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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, 2010
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

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

II

I

I

III

I

PART I	I		I
Item 1.	I	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS	I	1
Item 2.	I	OFFER STATISTICS AND EXPECTED TIMETABLE	I	1
Item 3.	I	KEY INFORMATION	I	1
I	I	Selected Financial Information	I	1
I	I	Selected Operating Information	I	3
I	I	Exchange Rates	I	5
I	I	Risk Factors	I	5
Item 4.	I	INFORMATION ON THE COMPANY	I	22
I	I	History and Development of the Company	I	22
I	I	Business Overview	I	26
I	I	Exploration & Production	I	26
I	I	Gas & Power	I	54
I	I	Refining & Marketing	I	68
I	I	Engineering & Construction	I	76
I	I	Petrochemicals	I	78
I	I	Corporate and Other activities	I	80
I	I	Research and Development	I	81
I	I	Insurance	I	86
I	I	Environmental Matters	I	87
I	I	Regulation of Eni’s Businesses	I	93
I	I	Property, Plant and Equipment	I	102
I	I	Organizational Structure	I	102
Item 4A.	I	UNRESOLVED STAFF COMMENTS	I	102
Item 5.	I	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	I	102
I	I	Executive Summary	I	102
I	I	Critical Accounting Estimates	I	104
I	I	2008-2010 Group Results of Operations	I	108
I	I	Liquidity and Capital Resources	I	119
I	I	Recent Developments	I	126
I	I	Outlook	I	127
Item 6.	I	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	I	134
I	I	Directors and Senior Management	I	134
I	I	Compensation	I	138
I	I	Board Practices	I	146
I	I	Employees	I	151
I	I	Share Ownership	I	152
Item 7.	I	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	I	153
I	I	Major Shareholders	I	153
I	I	Related Party Transactions	I	153
Item 8.	I	FINANCIAL INFORMATION	I	154
I	I	Consolidated Statements and Other Financial Information	I	154
I	I	Significant Changes	I	154
Item 9.	I	THE OFFER AND THE LISTING	I	154
I	I	Offer and Listing Details	I	154
I	I	Markets	I	156
Item 10.	I	ADDITIONAL INFORMATION	I	157
I	I	Memorandum and Articles of Association	I	157
I	I	Material Contracts	I	163
I	I	Exchange Controls	I	163
I	I	Taxation	I	163
I	I	Documents on Display	I	167
Item 11.	I	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	I	168
Item 12.	I	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	I	169
12A.	I	Debt Securities	I	169
12B.	I	Warrants and Rights	I	169
12C.	I	Other Securities	I	169
12D.	I	American Depositary Shares	I	169
II	I	I	I	I
PART II	I	I	I	I
Item 13.	I	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	I	171
Item 14.	I	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	I	I
Item 15.	I	CONTROLS AND PROCEDURES	I	171
Item 16.	I	I	I	II
16A.	I	Board of Statutory Auditors Financial Expert	I	172
16B.	I	Code of Ethics	I	172
16C.	I	Principal Accountant Fees and Services	I	172
16D.	I	Exemptions from the Listing Standards for Audit Committees	I	173
16E.	I	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	I	173
16F.	I	Change in Registrant’s Certifying Accountant	I	174
16G.	I	Significant Differences in Corporate Governance Practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual	I	II
II	I	I	I	II
PART III	I	I	I	II
Item 17.	I	FINANCIAL STATEMENTS	I	177
Item 18.	I	FINANCIAL STATEMENTS	I	177
Item 19.	I	EXHIBITS	I	177

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

 

CERTAIN DEFINED TERMS

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

 

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

The Consolidated Financial Statements of Eni, included in this annual report, have been prepared in accordance with International Financial Reporting Standards (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.it. Below is a selection of the most frequently used terms.

Financial terms
Leverage		A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including non-controlling interest. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure which in the case of the Company refers to IFRS, see "Item 5 – Financial Condition".
Net borrowings		Eni evaluates its financial condition by reference to "net borrowings", which is a non-GAAP measure. Eni calculates net borrowings as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure which in the case of the Company refers to IFRS, see "Item 5 – Financial Condition".
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.
Conversion index		Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation.
Deep waters		Waters deeper than 200 meters.
Development		Drilling and other post-exploration activities aimed at the production of oil and gas.

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

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		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 current Italian regulation, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.
Take-or-pay		Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
Upstream/Downstream		The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.

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ABBREVIATIONS

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

 

CONVERSION TABLE

 

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(*)

In this Annual Report on Form 20-F, the Company presents oil and gas production volumes and reserves expressed in barrels of oil-equivalent whereby natural gas volumes are converted on the base of an equivalency. In 2010, Eni updated the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent. This update reflected changes in Eni’s gas properties that took place in recent years and was assessed by collecting data on the heating power of gas in all Eni’s 230 gas fields on stream at the end of 2009. The effect of this update on production expressed in BOE was 26 KBOE/d for the full year 2010 and on the initial reserves balances as of January 1, 2010 amounted to 106 mmBOE. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depletion charges. Other oil companies may use different conversion rates.

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PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

 

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

 

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB). The tables below show Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2006, 2007, 2008, 2009 and 2010. 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,

	2006		2007		2008		2009		2010

CONSOLIDATED PROFIT AND LOSS STATEMENT DATA
Net sales from operations		86,105			87,204			108,082			83,227			98,523
Operating profit by segment (1)
Exploration & Production		15,580			13,433			16,239			9,120			13,866
Gas & Power		3,802			4,465			4,030			3,687			2,896
Refining & Marketing		319			686			(988	)		(102	)		149
Petrochemicals		172			100			(845	)		(675	)		(86	)
Engineering & Construction		505			837			1,045			881			1,302
Other activities (2)		(622	)		(444	)		(466	)		(436	)		(1,384	)
Corporate and financial companies (2)		(296	)		(312	)		(623	)		(420	)		(361	)
Impact of unrealized intragroup profit elimination (3)		(133	)		(26	)		125						(271	)
Operating profit		19,327			18,739			18,517			12,055			16,111
Net profit attributable to Eni		9,217			10,011			8,825			4,367			6,318
Data per ordinary share (euro) (4)
Operating profit:
- basic		5.23			5.11			5.09			3.33			4.45
- diluted		5.22			5.11			5.09			3.33			4.45
Net profit attributable to Eni basic and diluted		2.49			2.73			2.43			1.21			1.74
Data per ADR ($) (4) (5)
Operating profit:
- basic		13.13			14.01			14.97			9.27			11.81
- diluted		13.12			14.00			14.97			9.27			11.81
Net profit attributable to Eni basic and diluted		6.26			7.48			7.14			3.36			4.62

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	As of December 31,

	2006		2007		2008		2009		2010

CONSOLIDATED BALANCE SHEET DATA
Total assets		88,312		101,460		116,673		117,529		131,860
Short-term and long-term debt		11,699		19,830		20,837		24,800		27,783
Capital stock issued		4,005		4,005		4,005		4,005		4,005
Non-controlling interest		2,170		2,439		4,074		3,978		4,522
Shareholders’ equity - Eni share		39,029		40,428		44,436		46,073		51,206
Capital expenditures		7,833		10,593		14,562		13,695		13,870
Weighted average number of ordinary shares outstanding (fully diluted - shares million)		3,701		3,668		3,639		3,622		3,622
Dividend per share (euro)		1.25		1.30		1.30		1.00		1.00
Dividend per ADR ($) (4)		3.24		3.74		3.72		2.91		2.64

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(1)	i	From 2009, gains and losses on non-hedging commodity derivative instruments, including both fair value re-measurement and gains and losses on 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)	i	From 2010 certain environmental provisions incurred by the Parent Company Eni SpA due to inter-company guarantees on behalf of Syndial have been reported within the segment reporting unit "Other activities". Data for the years 2008 and 2009 have been restated by increasing the operating loss of the "Other activities" segment by euro 120 million and euro 54 million, respectively. Prior-year data have not been restated.
(3)	i	This item mainly pertained to intra-group sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of the end of the period.
(4)	i	Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2010 is based on the proposal of Eni’s management which is submitted to approval of the Annual General Shareholders’ Meeting scheduled on April 29 and May 5, 2011 on first and second calls, respectively.
(5)	i	Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S. $ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2006 through 2009 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively. The dividend for 2010 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (euro 1 per ADR) at the Noon Buying Rate recorded on the payment date on September 30, 2010, while the balance of euro 1 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2010. The balance dividend for 2010 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 26, 2011 to holders of Eni shares, being the ex-dividend date May 23, while ADRs holders will be paid late in May 2011.

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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, 2006, 2007, 2008, 2009 and 2010. 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. In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. In 2010, Eni updated the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent. This update reflected changes in Eni’s gas properties that took place in recent years and was assessed by collecting data on the heating power of gas in all Eni’s 230 gas fields on stream at the end of 2009. The effect of this update on production expressed in boe was 26 KBOE/d for the full year 2010 and on the initial reserves balances as of January 1, 2010 amounted to 106 mmBOE. Prior-year converted amounts were not restated. Other per-boe indicators were only marginally affected by the update (e.g. realization prices, costs per boe) and also negligible was the impact on depletion charges. Other oil companies may use different conversion rates.

	Year ended December 31,

	2006		2007		2008		2009		2010

Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)		3,457		3,127		3,243		3,377		3,415
of which developed		2,126		1,953		2,009		2,001		1,951
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)		24		142		142		86		208
of which developed		18		26		33		34		52
Proved reserves of natural gas of consolidated subsidiariesat period end (BCF)		16,897		16,549		17,214		16,262		16,198
of which developed		10,949		10,967		11,138		11,650		10,965
Proved reserves of natural gas of equity-accounted entities at period end (BCF)		68		3,022		3,015		1,588		1,684
of which developed		48		428		420		234		246
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end (1)		6,400		6,010		6,242		6,209		6,332
of which developed		4,032		3,862		3,948		4,030		3,926
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end (a)		36		668		666		362		511
of which developed		27		101		107		74		96
Reserve replacement ratio (2)		38		38		136		95		104
Average daily production of liquids (KBBL/d)		1,079		1,020		1,026		1,007		997
Average daily production of natural gas available for sale (mmCF/d) (3)		3,679		3,819		4,143		4,074		4,222
Average daily production of hydrocarbonsavailable for sale (KBOE/d) (3)		1,720		1,684		1,748		1,716		1,757
Hydrocarbon production sold (mmBOE)		625.1		611.4		632.0		622.8		638.0
Oil and gas production costs per BOE (4)		5.79		6.90		7.65		7.41		8.89
Profit per barrel of oil equivalent (5)		15.03		14.19		16.00		8.14		11.91

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(a)		Proved gas reserve of equity-accounted entities mainly pertained to three Russian companies that were jointly purchased with the Italian partner Enel in 2007 (Eni’s interest in the venture being 60%). In 2009 following the divestment of a 51% interest to Gazprom upon exercise of a call option arrangement, Eni’s interest in the venture decreased to 29.4%.
(1)	i	Includes approximately 754, 749, 746, 769 and 767 BCF of natural gas held in storage in Italy as of December 31, 2006, 2007, 2008, 2009 and 2010, 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)	i	Natural gas production volumes exclude gas consumed in operations (286, 296, 281, 300 and 318 mmCF/d in 2006, 2007, 2008, 2009 and 2010, respectively).
(4)		Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment including also royalties) prepared in accordance with IFRS divided by production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in "Item 18 – Notes to the Consolidated Financial Statements".
(5)		Expressed in U.S. dollars. Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in "Item 18 – Notes to the Consolidated Financial Statements" for a calculation of results of operations from oil and gas producing activities.

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Selected Operating Information continued

	Year ended December 31,

	2006		2007		2008		2009		2010

Sales of natural gas to third parties (5)		79.63		78.75		83.69		83.79		75.81
Natural gas consumed by Eni (5)		6.13		6.08		5.63		5.81		6.19
Sales of natural gas of affiliates (Eni’s share) (5)		7.65		8.74		8.91		7.95		9.41
Total sales and own consumption of natural gas of the Gas & Power segment (5)		93.41		93.57		98.23		97.55		91.41
E&P natural gas sales in Europe and in the Gulf of Mexico (5)		4.69		5.39		6.00		6.17		5.65
Worldwide natural gas sales (5)		98.10		98.96		104.23		103.72		97.06
Transport of natural gas for third parties in Italy (5)		30.90		30.89		33.84		37.32		47.87
Length of natural gas transport network in Italy at period end (6)		30.9		31.1		31.5		31.5		31.6
Electricity sold (7)		31.03		33.19		29.93		33.96		39.54
Refinery throughputs (8)		36.27		37.15		35.84		34.55		34.80
Balanced capacity of wholly-owned refineries (9)		534		544		544		554		564
Retail sales (in Italy and rest of Europe) (8)		12.48		11.80		12.03		12.02		11.73
Number of service stations at period end (in Italy and rest of Europe)		6,294		6,441		5,956		5,986		6,167
Average throughput per service station (in Italy and rest of Europe) (10)		2,470		2,486		2,502		2,477		2,353
Petrochemical production (8)		7.07		8.80		7.37		6.52		7.22
Engineering & Construction order backlog at period end (11)		13,191		15,390		19,105		18,730		20,505
Employees at period end (units)		72,850		75,125		78,094		77,718		79,941

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(6)	i	Expressed in BCM.
(7)	i	Expressed in thousand kilometers.
(8)	i	Expressed in TWh.
(9)	i	Expressed in mmtonnes.
(10)	i	Expressed in KBBL/d.
(11)	i	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,
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
2010		1.46		1.19		1.33		1.34

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(1)

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

 

	High		Low		At period end

(U.S. dollars per euro)

October 2010		1.41		1.37		1.39
November 2010		1.42		1.30		1.30
December 2010		1.34		1.31		1.34
January 2011		1.34		1.29		1.34
February 2011		1.38		1.34		1.35
March 2011		1.42		1.38		1.42

Fluctuations in the exchange rate between the euro and the U.S. dollar affect the dollar equivalent of the euro price of the Shares on the Mercato Telematico Azionario (Electronic Share Market or "MTA") and the U.S. dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the U.S. dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on March 31, 2011 was $1.42 per euro 1.00.

 

Risk Factors

Competition

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

Eni faces strong competition in each of its business segments.

•		In the Exploration & Production business, Eni faces competition from both international oil companies and state-owned oil companies for obtaining exploration and development rights, and developing and applying new technologies to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage 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, to apply and develop new technologies, and to control cost increases, its growth prospects and future results of operations and cash flows may be adversely affected.
•		In its natural gas business, Eni faces increasingly strong competition on both the Italian market and the European market driven by moderate growth prospects for demand over the short and medium-term, in the face of large gas availability on the marketplace. The latter was driven by material investments to expand

 

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		import capacity to Europe via pipeline which have been made by a number of operators, including Eni, in recent years. Also large availability of LNG on a worldwide scale has found an outlet at the European continental hubs driving the development of highly liquid spot gas markets. LNG availability was fuelled by the ramp-up of important upstream projects worldwide (new treatment trains in Qatar, Yemen and Russia) and commercial development of non-conventional gas resources in the USA which have reduced dependence on LNG imports. As natural gas is a commodity, gas oversupplies have caused suppliers to compete more aggressively on pricing thus pressuring gas margins in the whole sector. Management believes that a better balance between demand and supply on the European market will not be achieved until 2014 at the earliest. The described trends may 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.
•		Eni also faces competition from large, well-established European utilities and other international oil and gas companies in growing its market share and acquiring or retaining clients. A number of large clients, particularly electricity producers, in both the domestic market and other European markets have entered the wholesale market of natural gas by directly purchasing gas from producers and reselling it to wholesale or retail markets. At the same time, a number of national gas producers from countries with large gas reserves are planning to sell natural gas directly to final clients, which would threaten the market position of companies like Eni which resell gas purchased from producing countries to final customers. These developments may increase the level of competition in both the Italian and other European markets for natural gas and reduce Eni’s operating profit and cash flows.
•		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 that increasing competition due to the weak GDP growth expected in Italy and Europe over the next one to two years will cause 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 oil field services, construction and engineering industries is primarily based on technical expertise, quality and number of services and availability of technologically advanced facilities (for example, vessels for offshore construction). Lower oil prices could result in lower margins and lower demand for oil services.

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

 

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.

Eni’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the crude oil and natural gas industry. The Company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. As recent events in the Gulf of Mexico have shown, exploration and production carries certain inherent risks, especially deep water drilling. Accidents at a single well can lead to loss of life, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operation and prospects of the Group. Eni has implemented and maintains a system of policies, procedures and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. Nonetheless,

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in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks. Eni maintains insurance coverage that include coverage for physical damage to our assets, third party liability, workers’ compensation, pollution and other damage to the environment and other coverage. Our insurance is subject to caps, exclusion and limitation, and there is no assurance that such coverage will adequately protect us against liabilities from all potential consequences and damages. In light of the accident at the Macondo well in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher retentions. Also, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production interests, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production.

 

Exploratory drilling efforts may be unsuccessful

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. 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. Eni plans to explore for oil and gas offshore; a number of projects are planned in deep and ultra-deep waters or at deep drilling depths, where operations are more difficult and costly than in other areas. Deep water operations generally require a significant amount of time before commercial production of reserves can commence, increasing both the operational and financial risks associated with these activities. The Company plans to conduct risky exploration projects offshore the Gulf of Mexico, Egypt, Angola, Italy, Australia, Nigeria and Norway. In 2010, the Company invested approximately euro 1 billion in executing exploration projects and it plans to spend approximately euro 0.9 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.

 

The oil and gas industry may face increased regulation both in the USA and elsewhere that could increase the cost of regulatory compliance and may require changes to our drilling operations and exploration and development plans and may lead to higher royalties and taxes

The recent incident at the BP-operated Macondo well in the Gulf of Mexico is likely to result in more stringent regulation of oil and gas activities in the U.S. and elsewhere, particularly relating to environmental and health and safety protection controls and oversight of drilling operations, as well as access to new drilling areas. The U.S. Government had imposed a six-month moratorium, which was suspended in October 2010, on certain offshore drilling activities. The moratorium forced Eni’s management to reschedule certain projects and caused delays in linking a few wells to production facilities, which had a negligible impact on the Company’s production for the year. In addition, the Group incurred operating costs related to inactivity or redeployment of certain drilling rigs which were booked before the moratorium. During the first months of 2011, Eni expects to resume the operations that had been previously authorized and then suspended following the moratorium. Planned activities for which authorizations have still to be granted may be rescheduled due to uncertainties in the timing of obtaining the necessary authorizations from the U.S. Authorities. Similar actions have been taken by governments elsewhere in the world. The European Parliament has increased regulations in the area of environmental protection in the field of hydrocarbon extraction and Italian Authorities have passed legislation that would introduce certain restrictions to activities for exploring and producing hydrocarbons. These new regulations and legislation, as well as evolving practices, could increase the cost of compliance and may require changes to our drilling operations and exploration and development plans and may lead to higher royalties and taxes.

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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 producing 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:

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 actual returns of development projects. 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 material cost overruns and a substantial delay in the scheduling of production start-up at the Kashagan field, where development is ongoing. Those negative trends were driven by a number of factors including depreciation of the U.S. dollar versus the euro and other currencies; cost escalation of goods and services required to execute the project; an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; design changes to enhance the operability and safety standards of the offshore facilities. The partners of the venture are currently discussing an update of the expenditures and time schedule to complete the Phase 1 which were included in the development plan approved in 2008 by the relevant Kazakh Authorities. The Consortium continues to target the achievement of first commercial oil production by end of 2012. However, the timely delivery of Phase 1 depends on a number of factors which are presently under review.

See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the Kashagan project.

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

 

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.

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In addition to being a function of production, revisions and new discoveries, the Company’s reserve replacement is also affected by the entitlement mechanism in its Production Sharing Agreements ("PSAs") and similar contractual schemes. In accordance 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 2010, the Company’s reserve replacement was negatively affected by lower entitlements in its PSAs for an estimated amount of 80 mmBOE, which however did not impair the Company’s ability to fully replace reserves produced in the year. Due to ongoing trends in crude oil prices, the Company expects a risk of lower production and reserve entitlement relating to its PSA contracts to occur in 2011. See "Item 4 – Business Overview – Exploration & Production" and "Item 5 – Management’s Expectations of Operations". Future oil and gas production is dependent on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiation with countries and other owners of known reserves and acquisitions. 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. Lower crude oil prices have an adverse impact on Eni’s results of operations and cash flow. Eni generally does not hedge 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:

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.

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:

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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

The oil and gas industry is subject to the payment of royalties and income taxes which tend to be higher than those payable in many other commercial activities. In addition, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. As a result of those trends, management estimates that the tax rate applicable to the Company’s oil and gas operations is materially higher than the Italian statutory tax rate of 38%. In 2010, management estimates that the tax rate of the Company’s Exploration & Production segment was approximately 60%.

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

 

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, 2010, 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 2010, 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:

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

 

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

In recent months, several North African and Middle Eastern oil producing countries have experienced and continue to experience an extreme level of political instability that has resulted in changes in governments, unrest and violence and consequential economic disruptions. Further material changes are likely but largely unpredictable. Such instability is affecting, in particular, Libya. In 2010, approximately 15% of Eni’s production originated from Libya and a material amount of Eni’s proved reserves were located in Libya. Following suspension of activities at several of Eni’s producing sites in Libya and the closure of the GreenStream pipeline transporting gas from Libya to Italy, Eni’s production in Libya as of end of March 2011, was flowing at a rate ranging from 70 to 75 KBOE/d compared to an expected level for 2011 of approximately 280 KBOE/d. Production is continuing to decline. Closure of the GreenStream pipeline has also been impacting our gas sales in the Gas & Power Division. The majority of Eni’s employees in Libya have left the country. Due to the outbreak of political unrest in Libya, in February and March 2011, the US, the UN, the EU and several countries implemented certain sanctions in relation to Libya. Future developments in Libya, which we are currently unable to predict, may have a material adverse effect on Eni’s financial condition, results of operations and Libyan assets. Please see Item 4 for additional details of our operations in Libya and the impact of recent developments on our operations.

 

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 USA that target Iran and persons who have certain dealings with Iran may lead to the imposition of sanctions on any persons doing business in Iran or with Iranian counterparties.

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

CISADA also adopted measures designed to reduce the President’s discretion in enforcement under the ISA, including a requirement for the President to undertake an investigation upon being presented with credible evidence that a person is engaged in sanctionable activity. CISADA also added to the ISA provisions that an investigation need not be initiated, and may be terminated once begun, if the President certifies in writing to the U.S. Congress that the person whose activities in Iran were the basis for the investigation is no longer engaging in those activities or has taken significant steps toward stopping the activities, and that the President has received reliable assurances that the person will not knowingly engage in any sanctionable activity in the future. The President also may waive sanctions, subject to certain conditions and limitations.

The USA maintains broad and comprehensive economic sanctions targeting Iran that are administrated by the U.S. Treasury Department’s Office of Foreign Assets Control ("OFAC sanctions"). These sanctions generally restrict the dealings of U.S. citizens and persons subject to the jurisdiction of the USA. In addition, we are aware of initiatives by certain U.S. states and U.S. institutional investors, such as pension funds, to adopt or consider adopting

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laws, regulations or policies requiring divestment from, or reporting of interests in, companies that do business with countries designated as states sponsoring terrorism. CISADA specifically authorized certain state and local Iran-related divestment initiatives. If our operations in Iran are determined to fall within the scope of divestment laws or policies, sales resulting from such divestment laws and policies, if significant, could have an adverse effect on our share price. Even if our activities in and with respect to Iran do not subject us to sanctions or divestment, companies with investments in the oil and gas sectors in Iran may suffer reputational harm as a result of increased international scrutiny.

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

Eni Exploration & Production Division has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the National Iranian Oil Co (NIOC) between 1999 and 2001, and no other exploration and development contracts have been entered into since then. Under such Service Contracts, Eni has carried out development operations in respect of certain oil fields, and is entitled to recovery of expenditures made, as well as a service fee. The service contracts do not provide for payments to be made by Eni, as contractor, to the Iranian Government (e.g. leasing fees, bonuses, significant amounts of local taxes); all material future cash flows relate to the payment to Eni of its dues. All projects mentioned above have been completed or substantially completed; the last one, the Darquain project, is in the process of final commissioning and is being handed over to the NIOC. Eni Exploration & Production projects in Iran are currently in the cost recovery phase. Therefore, Eni has ceased making any further investment in the country and is not planning to make additional capital expenditures in Iran in any year subsequent to 2010. Eni’s other significant involvement in Iran is that, from time to time, Eni may purchase Iranian-origin crude oil. Eni has no involvement in Iran’s refined petroleum sector, and does not export refined petroleum to Iran. In addition, we have occasionally entered into licensing agreement with certain Iranian counterparties for the supply of technologies in the petrochemical sector. In 2010, Eni’s production in Iran averaged 21 KBOE/d, representing approximately 1% of the Eni Group’s total production for the year. Eni’s entitlement in 2010 represented less than 10% of the overall production from the oil and gas fields that we have developed in Iran. Eni does not believe that the results from its Iranian activities have or will have a material impact on the Eni Group’s results.

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

With respect to segments other than Exploration & Production, our Refining & Marketing segment has historically purchased amounts of Iranian crude oil under a term contract with the NIOC and on a spot basis. We purchased 1.42 mmtonnes, 980 ktonnes and 1.63 mmtonnes in 2008, 2009 and 2010, respectively. We paid NIOC $953 million in 2008, $419 million in 2009 and $888 million in 2010 for those purchases.

In addition in the three-year period 2008-2010 we purchased crude oil from international traders and oil companies who, based on bills of loading and shipping documentation available to us, we believe purchased the crude oil from Iranian companies. Purchases were mainly on spot basis. In 2008, we purchased 1.3 mmtonnes of crude oil amounting to $830 million; in 2009, we purchased 278 ktonnes of crude oil amounting to $147 million and in 2010, we purchased 2.09 mmtonnes of crude oil amounting to $1.1 billion.

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

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

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

We purchased 329 ktonnes, 241 ktonnes and 321 ktonnes in 2008, 2009 and 2010, respectively. We paid Syrian Petrol Company $227 million in 2008, $92 million in 2009 and $163 million in 2010 for those purchases.

In 2008, we also purchased 184 ktonnes of crude oil amounting to $73 million and in 2010 we purchased 115 ktonnes of crude oil amounting to $59 million, in each case from international traders who, based on bills of loading and shipping documentation available to us, we believe purchased those raw materials from Syrian companies.

Other than as described above, Eni is not currently investing in the country, and it has no contractual arrangements in place to invest in the country. However, we have recently been exploring investment opportunities in Syria.

 

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 substantial operating losses in both 2009 and 2008 of euro 675 million and euro 845 million, respectively. However, results in 2010 improved substantially and operating loss diminished to euro 86 million due to demand recovery, cost efficiencies and better unit margins, while the overall profitability was impaired by higher oil-based feedstock costs. Looking forward, management expects that while any strengthening in the global recovery may benefit demand for our products, continuing increases in the cost of oil represent a risk to the profitability of the Company’s petrochemicals operation as it may be difficult transferring higher feedstock costs to end-prices of products due to the high level of competition in the industry and the commoditized nature of many of Eni’s products.

 

Risks in the Company Gas & Power business segment

i) Risks associated with the Trading Environment and Competition in the Industry

In 2010, the Company’s results of operations and cash flow were negatively affected by lower sales volumes and reduced unit margins due to increasing competitive pressures arising from large gas availability on the marketplace. We expect continuing competitive pressures and oversupply to affect our results in 2011 and beyond

In 2010, gas demand in Italy and Europe rebounded from the depressed levels registered in the previous year, growing by 6% and 4%, respectively. Consumption volumes, however, remained below the pre-crisis levels seen in 2007. The Eni gas business failed to benefit from demand growth in 2010 as sales volumes declined by 6.4% from 2009 with Italy posting the largest decrease, with direct sales to customers down by 14.4% and sales to importers to Italy down by 19.5% driven by rising competitive pressures which also dragged down unit selling margins on gas sales in Italy. The Company’s results in its European markets business unit were affected by lowering average gas selling margins as gas spot prices at continental hubs were dragged down by large availability of LNG and competitive pressures. While spot prices have increasingly been adopted as contractual benchmarks in selling formulae outside Italy, the Company’s cost of supplies remained linked to trends in oil prices as provided by its long-term contractual arrangements to purchase gas from suppliers. As a result the Company’s unit margins outside Italy fell sharply in 2010. Management believes that those trends will continue weighing on the gas business’ future results of operations and cash flows over the next three years.

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A recovery in profitability of the Company’s marketing business depends heavily on the management’s assumption to be able to renegotiate better contractual terms within the Company’s long-term gas supply contracts

The industrial and financial forecasts for the next four-year plan of the gas business as well as the amount of the impairment loss recognized in 2010 Consolidated Financial Statements both take into consideration management assumptions that the Company’s long-term gas purchase contracts will be renegotiated at better economic terms for Eni, so as to restore the competitiveness of the Company’s cost position in the current depressed scenario for the gas sector. The renegotiation of revised contractual terms, including any price revisions and contractual flexibility, is established by such contractual clauses whereby parties are held to bring the contract back to the economic equilibrium in case of significant changes in the market environment, like the ones that have been occurring since the second half 2008. In the course of 2010, Eni has finalized a number of important contractual renegotiations by obtaining improved economic conditions for supplies and wider contractual flexibility with a benefit to its commercial programs. A number of renegotiations have been commenced or are due to commence in the upcoming months involving all the Company’s main suppliers of gas based on long-term contracts. Should the outcome of those renegotiations fall short of management’s expectations and absent a solid recovery in fundamentals of the gas sector, management believes that future results of operations and cash flows of the Company’s gas business will be negatively affected with further consequences in terms of recoverability of the carrying amounts of the gas business assets. In 2010 Consolidated Financial Statements, the Company recorded an impairment loss of euro 425 million related to its goodwill in the European gas business; for further information see "Item 5 – Operating and Financial Review and Prospects – Group Results of Operations".

 

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

Management estimates that long-term demand growth will achieve an average rate of 1.7% and 1.1% in Italy and Europe, respectively, until 2020. Those estimates have been revised down from previous management projections to factor in the expected impacts associated with a number of ongoing trends:

•		uncertainties and volatility in the current macroeconomic cycle;
•		growing adoption of consumption patterns and life-style characterized by wider sensitivity to energy efficiency;
•		EU policies intend to reducing GHG emissions and promoting renewable energy source. For further information about the Company’s outlook for gas demand see "Item 4 – Gas & Power".

The projected moderate dynamics in demand development will not be sufficient to balance current oversupplies on the marketplace over the next three years according to management’s estimates. Gas oversupplies have been increasing in recent years as new, large investments to upgrade import pipelines to Europe have come online from Russia, Libya and Algeria, and large availability of LNG on a worldwide scale has found an outlet at the European continental hubs driving the development of very liquid spot gas markets. Also, certain Eni’s competitors are currently assessing the economic feasibility of new gas import infrastructures, targeting 5-10 BCM of capacity expansion online from 2015-2016 according to management’s assumptions.

Management believes that a better balance between demand and supply will not be achieved until 2014, at the earliest. Those trends represent risks to the Company’s future results of operations and cash flows in its gas business.

 

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

In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing countries that supply the European gas markets. Those contracts have been ensuring approximately 80 BCM of gas availability from 2010 (including the Distrigas portfolio of supplies) with a residual life of approximately 19 years and a pricing mechanism indexed to the price of crude oil and its derivatives (gasoil, fuel oil, etc.). The contracts provide take-or-pay clauses whereby the Company is required to collect minimum pre-determined volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, applied to uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. Amounts of cash pre-payments and time schedules for collecting pre-paid gas vary from contract to contract. Generally, cash pre-payments are calculated on the basis of the energy prices current in the year 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

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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 current in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations.

Management believes that the current outlook for moderate gas demand growth and large gas availability on the marketplace, the possible evolution of sector-specific regulation, as well as the de-coupling between trends in gas prices indexed to oil versus gas benchmark prices at spot markets, represent risks factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts.

In 2009 and 2010, Eni incurred the take-or-pay clause as the Company collected lower volumes than its minimum take obligations in each of those years accumulating deferred costs for an amount of euro 1.44 billion as of December 31, 2010. The Company’s ability to recover those pre-paid volumes within contractual terms will depend in future years on a number of factors, including the possible evolution of the market environment and the competitiveness of Eni’s cost position, with this latter being influenced by the Company’s ability to renegotiate better contractual terms of its long-term purchase contracts (see paragraph above).

In case 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.

For further information on the Company’s take-or-pay contracts see "Item 4 – Gas & Power – Purchases".

 

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

Over the medium-term, Eni plans to increase its natural gas sales in Europe leveraging on its natural gas availability under take-or-pay purchase contracts, availability of transport rights and storage capacity, and widespread commercial presence in Europe which benefited from synergies from integrating the Belgian gas operator Distrigas acquired 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 natural gas market in Italy is highly regulated in order to favor the opening of the market and development of competition

In 2010, the regulated period for gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 expired. Those thresholds defined maximum allowed limits of gas volumes (imported or domestically produced) input into the national transport network and marketed to final customers, applicable to each operator.

That system of antitrust thresholds was replaced with a mechanism of market shares enacted by Legislative Decree No. 130 of August 13, 2010. The Decree introduced a 40% ceiling to the wholesale market share of each Italian gas operator. This ceiling can be raised to 55.9% in case an operator commits itself to building new storage capacity in Italy for a total of 4 BCM within five years. The new capacity shall be allocated to industrial and power generation customers. In case of breaching the mandatory thresholds, an operator is obliged to execute gas release measures at regulated prices. Eni plans to build new storage capacity and, in the meantime, intends to adopt measures and bear the associated expenses to make 50% of that planned capacity available to requesting customers (for further information see "Operating Review of the Gas & Power Division – Paragraph Regulation"). Eni believes that this new gas regulation will increase competitiveness in the wholesale natural gas market in Italy.

Further material aspects regarding the Italian gas sector regulations are regulated access to infrastructures (transport backbones, storage fields, distribution networks and LNG terminals), the unbundling of activities relating to infrastructures within vertically-integrated group companies, from July 1, 2008 (as defined by Decision No. 11/2007 and updated by Resolution No. 253/2007 of the Authority for Electricity and Gas). Also the Italian Authority for Electricity and Gas is entrusted with certain powers in the matters of setting tariffs for transport, distribution, storage and re-gasification services, as well as in approving specific codes for each regulated activity,

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monitoring natural gas prices and setting pricing mechanisms for supplies to residential users consuming less than 200,000 CM/y. See next paragraph.

 

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 for Electricity and Gas on these matters may limit the ability of Eni to pass an increase in the cost of the raw material onto final consumers of natural gas. The indexation mechanism set by the Authority for Electricity and Gas with Resolution No. 64/2009 basically provides that the cost of the raw material in pricing formulae to the residential sector be indexed to movements in a basket of hydrocarbons. In 2010, the Authority for Electricity and Gas with Resolution ARG/gas 89/10 amended that indexation mechanism and established a fixed reduction of 7.5% of the raw material cost component in the final price of supplies to residential users be applied in the thermal year October 1, 2010-September 30, 2011. This resolution will negatively affect Eni’s future results of operations and cash flows, considering the negative impact on unit margins in sales to residential customers. Administrative appeals against the Authority’s resolution, which have been filed by many operators including Eni, might possibly impact that matter.

Management cannot exclude the possibility that in the future the Authority for Electricity and Gas could implement further measures in this matter which may negatively affect Eni results of operations and liquidity.

 

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 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 party to 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 may off-take daily volumes in excess of 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. Eni believes that Decision No. 137/2002 is in contrast with the rationale of the European regulatory framework on the gas market as provided in European Directive No. 2003/55/EC. 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 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 fulfilling its minimum take contract obligations. See "Item 5 – Outlook".

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A number of mandatory gas release measures and other administrative measures have been recently implemented in Italy resulting in a negative impact on Eni’s results of operations and liquidity. It is possible 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 2007, Eni agreed to adhere to a gas release program involving 4 BCM which were disposed of in a two-year period (from October 1, 2007 to September 30, 2009). For thermal year 2009/2010 Italian Law No. 99/2009 obliged Eni to dispose 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, only 1.1 BCM were awarded out of the planned 5 BCM. The price set by the Ministry was 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 the Company may be obliged to implement new gas release programs. As a consequence, future results and cash flows could be negatively affected.

In 2010, a national trading platform was implemented where gas importers must trade volumes of gas corresponding to a legal obligation on part of Italian importers and producers. Under those provisions, importers from extra-EU countries are required to supply a set percentage of imported volumes in a given thermal year and to trade them at the national trading platform on a spot basis. Fulfillment of that obligation is a condition for the importer to be permitted to import gas from extra-EU countries. Also royalties in-kind owed to the Italian State on gas production are to be traded on that trading platform. The new trading platform is expected to develop a spot market for natural gas in Italy.

 

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.

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 infrastructures 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 rescheduled in a 24-month deadline following enactment of the decree from the Italian Prime Minister. Currently, Eni is unable to predict any development of this matter.

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 status of Italian natural gas market, targeting the overall level of competition, 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. Both the Authority for Electricity and Gas and the Antitrust Authority believe that the vertical integration of Eni in the supply, transport, distribution, storage and marketing of gas may hamper development of a competitive gas market 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 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 relating ongoing antitrust proceedings or new proceedings that may possibly arise. 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 34 to the Consolidated Financial Statements for a full description of Eni’s main pending antitrust proceedings.

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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. In 2009, new regulations were enacted in Italy relating to monitoring the route of waste from production up to its disposal/recycling, also prosecuting any unlawful conducts. The Company anticipates that it will incur operating costs to comply with this new regulation in 2011 when the new system of monitoring waste becomes fully-operational. 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 latter topic see "Item 4 – Environmental Regulations".

 

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

Risks of environmental, health and safety incidences and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management’s beliefs that Eni adopts high operational standards to ensure safety of its operations and to protect the environment and health of people and employees, it is possible that incidents like blow-outs, oil spills, contaminations and similar events could occur that would result in damage to the environment, employees and communities. 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. The Company is particularly exposed to the risk of environmental liabilities in Italy where the vast majority of the Group industrial installations are localized and also due to the circumstance that the Group engaged in a number of industrial activities in past years that were subsequently divested, closed, liquidated or shut down. At those industrial sites Eni has commenced in recent years a number of remedial plans to restore and clean-up proprietary or concession areas that were contaminated and polluted by the Group’s industrial activities in previous years. Notwithstanding the Group claimed that it cannot be held liable for such past contaminations as permitted by applicable regulations in case of declaration rendered by a guiltless owner – particularly regulations that enacted into Italian legislation the Directive No. 2004/35/EC – a number of civil and administrative proceedings have arisen relating to both the environmental damage and

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administrative prescriptions on how to perform individual cleaning-up project. In 2010, Eni proposed a global transaction to the Italian Ministry for the Environment related to nine sites of national interest where the Group has been performing clean-up activities in order to define the scope of work of each clean-up project and settle all pending administrative and civil litigation. To account for this proposal, the Group accrued a pre-tax risk provision amounting to euro 1.1 billion in its 2010 Consolidated Financial Statements.

Remedial actions with respect to other Company’s sites 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.

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 likelihood of as yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavorable developments in ongoing litigation on the environmental status of certain Company’s site where a number of public administrations and the Italian Ministry for the Environment act as plaintiffs; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of future environmental restoration and remediation programs are often inherently difficult to estimate.

 

Legal Proceedings

Eni is party to a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of the balance sheet date to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to amounts already accrued in connection with pending legal proceedings due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to the circumstance that they are often inherently difficult to estimate. See disclosure of pending litigation in Note 34 to the Consolidated Financial Statements.

 

Risks related to Changes in the Price of Oil, Natural Gas, Refined Products and Chemicals

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

 

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

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

 

The favorable impact of higher oil prices on Eni’s results of operations may be offset in part by 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 movements in oil prices.

In the Gas & Power segment, increases in the oil price represent a risk to the Company as gas supplies are mainly indexed to the cost of oil and certain refined products, while selling prices, particularly outside Italy, are increasingly linked to certain market benchmarks quoted at continental hubs. In the current trading environment,

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spot prices at those hubs are particularly depressed due to oversupply conditions. In addition, the Italian Authority for Electricity and Gas may limit the ability of the Company to pass cost increases linked to higher oil prices onto selling prices in supplies to residential customers and small businesses as the Italian Authority for Electricity and Gas regulates the indexation mechanism of the raw material cost in selling formulae to those customers. See the paragraph "Risks in the Company’s gas business" above for more information.

In addition, in light of changes in the European gas market environment, Eni has recently adopted new risk management policies. These policies contemplate the use of derivative contracts to mitigate the exposure of Eni’s future cash flows to future changes in gas prices; such exposure had been exacerbated in recent years by the fact that spot prices at European gas hubs have ceased to track the oil prices to which Eni’s long-term supply contracts are linked. These policies also contemplate the use of derivative contracts for speculative purposes whereby Eni will seek to profit from opportunities available in the gas market based, among other things, on its expectations regarding future prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. All derivative contracts that are not entered into for hedging purposes in accordance with IFRS will be accounted through profit and loss, resulting in higher volatility of the gas business’ operating profit. Please see "Item 5 – Financial Review – Outlook" and "Item 11 – Quantitative and Qualitative Disclosures About Market Risk".

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

 

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

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. The prices of refined products depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. Furthermore, Eni’s realized margins are also affected by relative price movements of heavy crude qualities versus light crude qualities, taking into account the ability of Eni’s refineries to process complex crudes that represent a cost advantage when market prices of heavy crudes are relatively cheaper than the marker Brent price. In 2010, Eni’s refining margins were unprofitable as the high cost of oil was only partially transferred to final prices of fuels at the pump pressured by weak demand, high worldwide and regional inventory levels and excess refining capacity. Management does not expect any significant recovery in industry fundamentals over the next four-year industrial plan. The sector as a whole will continue to suffer from weak demand and excess capacity, while the cost of oil feedstock may continue rising and price differentials may remain compressed. In this context, management expects that the Company’s refining margins will remain at below break-even levels in 2011 and possibly beyond.

 

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

Eni’s margins on petrochemical products are affected by trends in demand for petrochemical products and movements in crude oil prices to which purchase costs of petroleum-based feedstock are indexed. Given the commoditized nature of Eni petrochemical products, it is difficult for the Company to transfer higher purchase costs for oil-based feedstock to selling prices to customers. Rising oil-based feedstock costs will continue to negatively affect Eni’s results of operations and liquidity in this business segment in 2011.

 

Risks from Acquisitions

Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or companies in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – 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 may incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets we acquire. If the integration and financial risks connected to acquisitions materialize, our financial performance may be adversely affected.

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Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones. In recent years, the Group has experienced a higher than normal level of counterparty failure due to the severity of the economic and financial downturn. In our 2010 Consolidated Financial Statements, we accrued an allowance against doubtful accounts amounting to euro 201 million, mainly relating the Gas & Power business. Management believes that the Gas & Power business is particularly exposed to credit risks due to its large and diversified customer base which include a large number of middle and small businesses and retail customers where impacts of the economic and financial downturn were particularly severe.

 

Exchange Rates

Movements in the exchange rate of the euro against the U.S. dollar can have a material impact on Eni’s results of operations. Prices of oil, natural gas and refined products generally are denominated in, or linked to, U.S. dollars, while a significant portion of Eni’s expenses are denominated in euros. Similarly, prices of Eni’s petrochemical products are generally denominated in, or linked to, the euro, whereas expenses in the Petrochemical segment are denominated both in euros and U.S. dollars. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses. The Exploration & Production segment is particularly affected by movements in the U.S. dollar versus the euro exchange rates as the U.S. dollar is the functional currency of a large part of its foreign subsidiaries and therefore movements in the U.S. dollar versus the euro exchange rate affect year-on-year comparability of results of operations.

 

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

 

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, availability of new informative elements, variations in economic conditions such as prices, costs, other significant factors including evolution in technologies, industrial practices and standards (e.g. removal technologies) and the final outcome of legal, environmental or regulatory proceedings. See "Item 5 – Critical Accounting Estimates".

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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 exploration and production, gas marketing operations, management of gas infrastructures, power generation, petrochemicals, oil field services and engineering industries. Eni has operations in 79 countries and 79,941 employees as of December 31, 2010.

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

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

Internet address: www.eni.com.

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

Eni’s principal segments of operations are described below.

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations in 43 countries, including Italy, the UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the USA, Kazakhstan, Iraq, Russia, Venezuela and Australia. In 2010, Eni produced 1,757 KBOE/d on an available for-sale basis. As of December 31, 2010, Eni’s total proved reserves of subsidiaries stood at 6,332 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 511 mmBOE. In 2010, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 29,497 million and operating profit of euro 13,866 million.

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, managing gas infrastructures for transport, distribution, storage, re-gasification, and LNG supply and marketing. This segment also includes the activity of power generation that is ancillary to the marketing of electricity. In 2010, Eni’s worldwide sales of natural gas amounted to 97.06 BCM, including 5.65 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the USA. Sales in Italy amounted to 34.29 BCM, while sales in European markets were 54.52 BCM that included 8.44 BCM of gas sold to certain importers to Italy.

Through Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,600-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 Northern European 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 1,330 municipalities through a low pressure network consisting of approximately 50,307 kilometers of pipelines as of December 31, 2010. 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, Ferrara and Bolgiano with a total installed capacity of 5.3 GW as of December 31, 2010. In 2010, sales of power totaled 39.54 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 the USA. In 2010, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 29,576 million and operating profit of euro 2,896 million.

Eni’s Refining & Marketing segment engages in crude oil supply, refining and marketing of petroleum products mainly in Italy and in the rest of Europe, as well as crude oil and trading and shipping products. In 2010, processed volumes of crude oil and other feedstock amounted to 34.80 mmtonnes and sales of refined products were 46.80 mmtonnes, of which 27.01 mmtonnes were in Italy. Retail sales of refined product at operated service stations amounted to 11.73 mmtonnes including Italy and the rest of Europe. In 2010, Eni’s retail market share in Italy through its "eni" and "Agip" branded network of service stations was 30.4%. In 2010, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 43,190 million and operating profit of euro 149 million.

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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 2010, Eni sold 6.1 mmtonnes of petrochemical products. In 2010, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 6,141 million and an operating net loss of euro 86 million.

Eni engages in oil field services, construction and engineering activities through its partially-owned subsidiary Saipem and subsidiaries of Saipem (Eni’s interest being 42.92%). Saipem provides a full range of engineering, drilling and construction services to the oil and gas industry and downstream refining and petrochemicals sectors, mainly in the field of performing large EPC (Engineering, Procurement and Construction) contracts offshore and onshore for the construction and installation of fixed platforms, subsea pipelaying and floating production systems and onshore industrial complexes. In 2010, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 10,581 million and operating profit of euro 1,302 million.

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

 

Strategy

Eni’s strategy is to expand the Company’s principal businesses over both the medium and the long-term, with improving profitability. Specifically, the Company is planning for:

In executing this strategy, management intends to pursue integration opportunities among and within businesses and 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 53.3 billion to support continuing organic growth in its businesses, mainly Exploration & Production. In 2011, Eni intends to invest approximately euro 14 billion, an amount roughly in line with 2010. Eni plans to fund those capital expenditure projects mainly by means of cash flows provided by operating activities. Capital projects will be assessed and implemented in accordance with strict financial criteria. Management intends to progressively reduce the ratio of net borrowings to shareholders’ equity leveraging on projected cash flows from operations at our Brent scenario of $70 a barrel flat in the next four years and planned divestments amounting to euro 2 billion in 2011. This target includes expected cash outflows to remunerate Eni’s shareholders through a progressive dividend policy. In 2010 management plans to distribute a dividend of euro 1 a share subject to approval from the General Shareholders Meeting scheduled on May 5, 2011. In subsequent years, management plans to increase dividends in line with OECD inflation. This dividend policy is based on the Company’s planning assumptions for Brent prices and other assumptions (see "Item 5 – Outlook" and "Item 3 – Risk Factors").

Further details on each business segment strategy are discussed throughout this Item 4. For a description of risks and uncertainties associated with the Company’s outlook, including any possible impact associated with ongoing political instability and war in Libya, and the capital expenditure program see "Item 5 – Outlook" and "Item 3 – Risk Factors".

In the next four-year period, Eni plans to spend euro 1.1 billion for technological research and innovation activities. Management believes that technological leadership is a key driver of the Company’s competitive

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advantages in the long-term. Eni concentrates most of its efforts in upstream projects focused on maximizing the recovery rate of hydrocarbons from reservoirs, optimizing drilling and well performance, exploiting unconventional oil and gas resources and improving exploration performance. Projects in the refining sector target the development of advanced fuels, that allow higher engine performance with minimum environmental impact, and the increase in valuable products yields from refining heavy and sour crude qualities (in particular the Eni Slurry Technology (EST) project). In the petrochemical sector, efforts are focused on developing high value added elastomers and polymers. We also intend to enhance our long-term options to contribute to sustainable development by progressing our capabilities in renewable sources of energy, particularly in the field of solar and photovoltaic energy, carbon capture and sequestration, clean fuels, operations safety and integrity in upstream, and environmental clean-up and remediation.

 

Significant Business and Portfolio Developments

The significant business and portfolio developments that occurred in 2010 and to date in 2011 were the following:

•		From February 22, 2011, liquids and natural gas production at a number of fields in Libya and supplies through the GreenStream pipeline have been halted as a result of ongoing political instability and unrest in the Country. Facilities have not suffered any damage and such standstills do not affect Eni’s ability to ensure natural gas supplies to its customers. Eni is technically able to resume gas production at or near previous level once the situation stabilizes. The overall impact of the political instability and conflict in Libya on Eni’s results of operations and cash flows will depend on how long such tensions will last as well as on their outcome, which management is currently unable to predict. Eni’s oil and natural gas production as of end of March 2011, was flowing at a rate ranging from 70 to 75 KBBL/d, down from the expected level of approximately 280 KBBL/d. Production is continuing to decline. Current production mainly consists of gas that is entirely delivered to local power generation plant. For further discussion on risks and management outlook on the Libyan situation see "Item 3 – Risk Factors – Political Considerations" and "Item 5 – Outlook".
•		In November 2010, Eni and the Venezuelan State Company PDVSA established a joint venture in charge of developing the Junín 5 oil field, located in the Orinoco Oil Belt. Management believes that the field contains important volumes of resources, mainly heavy oil. The two partners plan to achieve first oil by 2013.
•		In 2010, appraisal activities were performed in the gas discovery of Perla located in the Cardón IV Block, in the shallow water of the Gulf of Venezuela. Based on the assessment made, management believes that Perla contains significant amount of gas reserves. The initiative is conducted through a 50/50 joint venture with another international oil. The two partners are planning for starting production in 2013.
•		At the beginning of the fourth quarter 2010, Eni achieved project milestones at the Zubair oil field in Iraq by increasing production by more than 10% above the initial production rate of approximately 180 KBBL/d. Increasing production above that level means that Eni has begun the cost recovery for its work on the field by booking its share of production, including receiving a remuneration fee for every extra barrel of oil produced above the 10% target. Eni, with a 32.8% share, is leading the consortium in charge of redeveloping the Zubair field over a 20-year period, targeting a production plateau of 1.2 mmBBL/d in the next six years.
•		In October 2010, with a view to rationalizing its upstream portfolio, Eni divested its subsidiary Società Padana Energia to Gas Plus. The divested subsidiary includes exploration leases and concessions for developing and producing oil and natural gas in Northern Italy. For further details, see "Exploration & Production – Italy", below.
•		In May 2010, Eni signed a preliminary agreement with an affiliate of Petrobras for the divestment of its 100% interest in Gas Brasiliano Distribuidora, a company that markets and distributes gas in an area of the S. Paulo State, Brazil. The completion of the transaction is subject to approval of the relevant Brazilian Authorities. The expected cash consideration amounts to $250 million.
•		In April 2010, Eni sold to NOC (Libyan National Oil Corp) a 25% stake in the share capital and the control of GreenStream BV, the company owning and managing the gas pipeline for importing to Italy natural gas produced in Libya.
•		Procedures for divesting Eni’s interests in the German TENP, the Swiss Transitgas and the Austrian TAG gas transport pipelines and carrier companies are progressing and the Company targets to finalize the divestiture in 2011. The divestment program has been agreed upon with the European Commission as remedial actions to settle an antitrust proceeding without the ascertainment of any illicit behavior and consequently without imposition of any fines or sanctions on the Company. The proceeding was started by the Commission in the year 2006 to investigate allegedly anti-competitive behavior ascribed to Eni in the natural gas market. The commitments have been ratified as of September 29, 2010.

In addition, in 2010 and up to date in 2011 Eni closed the following transactions:

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•		In March 2011, Eni signed a Memorandum of Understanding with the Minister of Ecology and Natural Resources in Ukraine. The agreement provides for a joint study to cooperate in conventional and unconventional oil and gas resources and evaluate upstream initiatives.
•		In January 2011, Eni was awarded rights to explore retaining operatorship of offshore Block 35 in Angola, with a 30% interest. The agreement foresees drilling 2 wells and 3D seismic surveys to be carried out in the first 5 years of exploration. This deal is subject to the approval of the relevant authorities.
•		In January 2011, Eni signed a Memorandum of Understanding with PetroChina to promote common opportunities to jointly expand operations in research and development of conventional and unconventional hydrocarbons in China and outside China, particularly in Africa. In addition, PetroChina is evaluating to purchase an interest in certain of Eni’s assets.
•		In December 2010, Eni acquired Minsk Energy Resources which operates 3 exploration licenses in the Polish Baltic Basin. Management believes that the acquired acreage may contain unconventional gas resources. Drilling operations are expected to start in the second half of 2011.
•		In December 2010, Eni acquired a controlling interest in Altergaz, a company marketing natural gas in France to retail and middle market clients, as the other partners of the company exercised a put option on a 15% stake.
•		In November 2010, Eni signed with the Government of Ecuador new terms for the service contract for the Villano oil field, due to expire in 2023. Under the new agreement, the operated area is enlarged to include the Oglan oil discovery, which is planned to be developed in synergy with existing facilities.

•		In October 2010, Eni was awarded operatorship of offshore Block 1 and Block 2 (Eni 100%) in the Dahomey Basin in the Gulf of Guinea as part of its agreements with the Government of Togo to develop the country’s offshore mineral resources.
•		In August 2010, Eni signed an agreement with UK-based Surestream Petroleum to acquire a 55% stake and operatorship in the Ndunda Block located in the Democratic Republic of Congo. The agreement has been sanctioned by the relevant authorities.
•		In January 2010, Eni finalized an acquisition of downstream activities in Austria, including a retail network, wholesale activities, as well as commercial assets in the aviation business and related logistic and storage activities.

In 2010, capital expenditures amounted to euro 13,870 million, of which 87% related to Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 8,578 million) deployed mainly in Egypt, Kazakhstan, Congo, the USA and Algeria, and exploration projects (euro 1,012 million) carried out mainly in Angola, Nigeria, the USA, Indonesia and Norway; (ii) the development and upgrading of Eni’s natural gas transport and distribution network in Italy (euro 842 million and euro 328 million, respectively) as well as development and increase of storage capacity (euro 250 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 692 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,552 million). There were no significant acquisitions in the year.

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 USA, Egypt, Congo, Italy and Angola, and exploration projects (euro 1,228 million) carried out mainly in the USA, 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 USA, 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

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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 in Italy, 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 in Belgium; (ii) the completion of the acquisition of Burren Energy Plc in the UK; (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 a LNG project in Angola.

 

BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 43 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the USA, Kazakhstan, Russia, Algeria, Australia, Venezuela and Iraq. In 2010, Eni average daily production amounted to 1,757 KBOE/d on an available for-sale basis. As of December 31, 2010, Eni’s total proved reserves amounted to 6,843 mmBOE; proved reserves of subsidiaries stood at 6,332 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 511 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 compound average growth rate in our production in excess of 3% in the next 2011-2014 four-year period, targeting a production plateau above 2.05 mmBOE/d by 2014. Those targets are based on our long-term Brent price assumptions of 70 $/BBL. The production outlook for 2011 is uncertain due to ongoing political instability and unrest in Libya. Following suspension of activities at several of Eni’s producing sites in Libya and the closure of a pipeline transporting gas from Libya to Italy, Eni’s production in Libya as of end of March 2011, was flowing at a rate ranging from 70 to 75 KBOE/d compared to an expected level for 2011 of approximately 280 KBOE/d. Production is continuing to decline. Future developments in Libya, which we are currently unable to predict, may have a material adverse effect on Eni’s production targets. However, in our planning assumptions to 2014 we assumed that the Libyan production would resume flowing at its normal rate at some point in the future. For further information on this issue as well as certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices see "Item 5 – Outlook" and "Item 3 – Risk Factors".

Management plans to achieve the target of production growth to 2014 via organic developments, leveraging on the planned start-ups of a number of fields and material expenditures to support current production levels at our producing fields. We project that new fields start-ups will add approximately 630 KBOE/d to the Company’s production level by 2014. Main production start-ups are planned in Angola, Norway, Russia, Kazakhstan, Algeria and Venezuela. We have a good level of visibility on those new projects as most of them have been already sanctioned.

The second leg of our growth strategy is to maximize the production recovery rate at our current fields by counteracting natural field depletion. To achieve this, we plan to execute infilling and work-over activities, apply our advanced recovery technologies and reservoir management capabilities.

In exploration activities, Eni plans to perform the major part of exploration projects in well-established areas of presence targeting to extend the plateau of producing fields. Those areas include Egypt, Pakistan, Nigeria, Congo and the Gulf of Mexico where availability of production facilities will enable the Company to readily put in production discovered reserves. Other projects will be executed offshore of West Africa, Venezuela and in deepwater plays in the Gulf of Mexico where the Company believes to have the necessary know-how and skills to discover new reserves. A third layer of exploration projects is planned to be executed in high risk/high reward areas including Mozambique, Togo, Ghana and offshore Australia and East Timor where the Company believes important resources can be discovered. Eni expects to purchase new exploration permits and to divest or exit marginal or non-strategic areas.

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Eni intends to focus on reserve replacement in order to ensure the medium to long-term sustainability of the business. Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight cost control and reducing the time span which is necessary to put reserves in production. We expect that costs to develop and operate fields will increase in the next years due to sector-specific inflation, and growing complexity of new projects. We plan to counteract those cost increases by leveraging on cost efficiencies associated with: (i) increasing the scale of our operations as we concentrate our resources on fields of greater dimensions than in the past where we plan to achieve economies of scale; (ii) expanding the scope of operated production. We believe that is a key driver of profitability as operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; and (iii) applying our technologies which we believe can reduce drilling and completion costs.

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.

Management plans to invest approximately euro 39.1 billion to explore for and develop new reserves over the next four years. Exploration projects will account for approximately euro 3.6 billion. Approximately euro 1.8 billion will be spent to build transportation infrastructures and LNG projects through equity-accounted entities. For the year 2011, management plans to spend euro 9.8 billion in reserves development and exploration projects.

 

Disclosure of Reserves

Overview

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

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

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the 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 exercises rigorous control over the process of booking proved reserves, through a centralized model of reserve governance. The Reserves Department of the Exploration & Production Division is entrusted with the task of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.

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

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditures, operating expenses and costs related to asset retirement obligations; (ii) the Petroleum Engineering Department at the head office verifies the production profiles of such properties where significant changes have occurred; (iii) geographic area managers at the head office verify estimates carried out by business unit managers; (iv) the Planning and Control Department provides the economic evaluation of reserves; (v) the Reserve Department, through the Division Reserves Evaluators (DRE), provides independent reviews of fairness and correctness of classifications carried out by the abovementioned 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 fulfills the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards established by the Society of Petroleum Engineers.

 

Reserves independent evaluation

Since 1991, Eni has requested independent oil engineering companies to carry out an independent evaluation² of part of its proved reserves on a rotational basis. Management believes that those engineering firms are qualified and experienced on the marketplace. The description of qualifications of the persons primarily responsible for the reserve audit is included in the third party audit report³. In the preparation of their reports, 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 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’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided. In 2010, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of 28% of Eni’s total proved reserves at December 31, 2010⁴, confirming, as in previous years, the reasonableness of Eni internal evaluation⁵.

In the 2008-2010 three-year period, 78% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2010 the principal Eni properties not subjected to independent evaluation in the last three years were Karachaganak (Kazakhstan), Samburgskoye and Yaro-Yakhinskoye (Russia).

 

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, 2010, 2009 and 2008. Reserves data for 2010 and 2009 are based on the un-weighted 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 is based on the last day price of the Company’s fiscal year in accordance with then applicable rules.

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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 reserves

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
Year ended Dec. 31, 2010 (a)		724		601		2,096		1,133		1,126		295		230		127		6,332		511		6,843
Developed		554		405		1,215		812		543		139		141		117		3,926		96		4,022
Undeveloped		170		196		881		321		583		156		89		10		2,406		415		2,821

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(a)

In 2010, Eni has updated the natural gas conversion factor. See page vi for further information.

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 reserves

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
Year ended Dec. 31, 2010		248		349		978		750		788		139		134		29		3,415		208		3,623
Developed		183		207		656		533		251		39		62		20		1,951		52		2,003
Undeveloped		65		142		322		217		537		100		72		9		1,464		156		1,620

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 reserves

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
Year ended Dec. 31, 2010		2,644		1,401		6,207		2,127		1,874		871		530		544		16,198		1,684		17,882
Developed		2,061		1,103		3,100		1,550		1,621		560		431		539		10,965		246		11,211
Undeveloped		583		298		3,107		577		253		311		99		5		5,233		1,438		6,671

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 683 mmBOE as of December 31, 2010 (674 and 679 mmBOE as of December 31, 2009 and 2008, respectively). Said volumes are not included in reserves volumes shown in the table herein.

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Activity of the year

	Subsidiaries		Equity-accounted entities

	2008		2009		2010		2008		2009		2010

Additions to proved reserves		882			605			776			6			(296	)		158
of which purchases and sales of reserves-in-place		32			25			(12	)					(314	)
Production for the year		(650	)		(638	)		(653	)		(8	)		(8	)		(9	)

	Subsidiaries and equity-accounted entities

	2008		2009		2010

Proved reserves replacement ratio of subsidiaries and equity-accounted entities		135		96		125

Eni’s proved reserves of subsidiaries as of December 31, 2010 totaled 6,332 mmBOE (oil and condensates 3,415 mmBBL; natural gas 16,198 BCF) representing an increase of 123 mmBOE, or 2%, from December 31, 2009. Additions to proved reserves booked in 2010 were 776 mmBOE (including the impact of gas conversion factor update equal to 97 mmBOE) and derived from: (i) revisions of previous estimates were 661 mmBOE mainly reported in Libya, Nigeria, Egypt, Iraq and Italy; (ii) extensions, discoveries and other factors were 125 mmBOE, with major increase booked in the UK and Algeria; and (iii) improved recovery were 2 mmBOE. The unfavorable effect of higher oil price on reserve entitlements in certain PSAs and service contracts (down 80 mmBOE) resulted from higher oil prices compared to year ago (the Brent price used in the reserve estimation process was $79 per barrel in 2010 compared to $59.9 per barrel in 2009). Higher oil prices also resulted in upward revisions associated with improved economics of marginal productions.

In 2010, sales of mineral-in-place resulted mainly from the divestment of wholly-owned subsidiary Società Padana Energia to Gas Plus, which held exploration, development and production properties in Northern Italy.

As of December 31, 2010 Eni’s share of proved reserves of equity-accounted entities amounted to 511 mmBOE, an increase of 149 mmBOE, or 41.2%, compared to December 31, 2009, with an increase mainly reported in Venezuela.

The current SEC rules allow the use of reliable technology 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 "reliable technologies".

Proved developed reserves of subsidiaries as of December 31, 2010 amounted to 3,926 mmBOE (1,951 mmBBL of liquids and 10,965 BCF of natural gas) representing 62% of total estimated proved reserves (65% and 63% as of December 31, 2009 and 2008, respectively).

The reserve replacement ratio for Eni’s subsidiaries and equity-accounted entities was 125% in 2010 (96% in 2009 and 135% in 2008). The ratio did not include the impact associated with adoption of a new conversion factor of natural gas to barrel-of-oil equivalent on the initial balances of proved reserves as of January 1, 2010 as management believes that that change did not pertain to the Company’s reserve performance for the year. 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 ability to sustain its growth perspective. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, as well as changes in oil and gas prices, political risks and geological and other environmental risks. Specifically, in recent years Eni’s reserves replacement ratio has been affected by the impact of higher 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

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end amounts of Eni’s proved reserves, the lower the number of barrels necessary to cover the same amount of expenditures. In 2010, this trend resulted in a lower amount of booked reserves associated with the Company’s PSAs as the average oil price used in reserve computation was 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 10.3 years as of December 31, 2010 which included reserves of both subsidiaries and equity-accounted entities.

 

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2010 totaled 2,821 mmBOE. At year end, liquids proved undeveloped reserves amounted to 1,620 mmBBL, mainly concentrated in Africa and Kazakhstan. Natural gas proved undeveloped reserves accounted for 6,671 BCF, mainly located in Africa and Russia.

In 2010, total proved undeveloped reserves increased by 354 mmBOE. The principal reasons for the increase are revisions and new projects sanction, mainly in Libya, Venezuela and Iraq.

During 2010, Eni converted approximately 295 mmBOE of proved undeveloped reserves to proved developed reserves. The main reclassification to proved developed were related to development activities, revisions and production start-up of the following fields/projects: Cerro Falcone (Italy), M’Boundi (Congo), Wafa (Libya), Bhit and Sawan (Pakistan), Morvin (Norway), Tuna and Hapy (Egypt) and Karachaganak (Kazakhstan).

In 2010, capital expenditures amounted to approximately euro 1.7 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.

The Company estimates that approximately 0.9 BBOE of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (0.6 BBOE) where development activities are progressing and start-up production is targeted by the end of 2012. For more details regarding this project please refer to part 1, Item 4, page 46, where the project is disclosed. See also our discussion under the "Risk Factors" section about risks associated with oil and gas development projects on page 6; (ii) certain Libyan gas fields where development activities and production start-up is dependent upon fulfilling contractual delivery obligations under a long-term gas supply agreement; and (iii) other minor projects where development activities are progressing.

 

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 1,852 BCF from producing properties located in Australia, Egypt, India, Indonesia, Libya, Nigeria, Norway, Pakistan, Tunisia and the UK.

The temporary shut down of the GreenStream pipeline due to ongoing political instability and unrest in Libya will not materially impair the Company’s ability to fulfill its contractual delivery commitments with third parties as the Company can make use of its gas availability from various sources to meet those commitments.

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 68% of outstanding delivery commitments in the next three years.

Eni has met all contractual delivery commitments as of December 31, 2010.

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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 2010, oil and natural gas production available for sale averaged 1,757 KBOE/d. Production for the year expressed in barrel-of-oil equivalent was calculated assuming a natural gas conversion factor which was updated to 5,550 CF of gas equaling 1 barrel of oil. On a comparable basis, i.e. when excluding the effect of the update gas conversion factor, production showed an increase of 0.9% for the full year. Production growth was driven by additions from new field start-ups, particularly the Zubair field (Eni’s interest 32.8%) in Iraq, and production ramp-ups at fields which were started-up in 2009 (for a total increase of 40 KBOE/d). These increases were offset in part by mature field declines. Lower entitlements in the Company’s PSA due to higher oil prices, as well as lower gas uplifts in Libya as a result of oversupply conditions in the European market were partly offset by lower OPEC restrictions resulting in a net negative impact of approximately 7 KBOE/d. The share of oil and natural gas produced outside Italy was 90% (90% in 2009).

Liquids production (997 KBBL/d) decreased by 10 KBBL/d from 2009 (down 1%). The impact of mature field declines was partly offset by organic growth and production start-ups achieved in particular in Nigeria, due to the ramp-up of the Oyo project (Eni’s interest 40%), in Italy as a result of the ramp-up of the Val d’Agri enhanced development project (Eni’s interest 60.77%), in Tunisia due to the production start-up/ramp-up of the Baraka and Maamoura projects (Eni operator with a 49% interest) as well as Zubair in Iraq.

Natural gas production (4,222 mmCF/d) increased by 148 mmCF/d from 2009 (up 3.6%). The main increases were registered in Nigeria, due to projects start-up in the Block OML 28 (Eni’s interest 5%), in Australia, due to ramp-up of the Blacktip project (Eni’s interest 100%), in Congo, due to ramp-up of the M’Boundi gas project (Eni operator with an 83% interest) in Egypt, due to start-up of the Tuna field (Eni operator with a 50% interest), in Italy, due to the start-up of the Annamaria field (Eni operator with an 90% interest) and in India, due to organic growth of PY-1 project (Eni’s interest 47.18%). These increases were offset in part by mature field declines.

Oil and gas production sold amounted to 638 mmBOE. The 24.5 mmBOE difference over production (662.5 mmBOE for the year ended December 31, 2010) reflected volumes of natural gas consumed in operations (20.9 mmBOE).

Approximately 58% of liquids production sold (361.3 mmBBL) was destined to Eni’s Refining & Marketing Division (of which 18% was processed in Eni’s refinery); about 28% of natural gas production sold (1,536 BCF) was destined to Eni’s Gas & Power Division.

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

2008		68		140		338		289		69		49		63		10		1,026
2009		56		133		292		312		70		57		79		8		1,007
2010		61		121		301		321		65		48		71		9		997

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(1)

Data includes Eni’s share of production of affiliates and joint venture accounted for under the equity method of accounting amounting to 19, 17 and 14 KBBL/d in 2010, 2009 and 2008, respectively.

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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

2008		725		588		1,661		204		227		396		304		38		4,143
2009		630		608		1,503		213		241		417		416		46		4,074
2010		648		517		1,559		365		221		436		385		91		4,222

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(1)		Data includes Eni’s share of production of affiliates and joint venture accounted for under the equity method of accounting amounting to 27, 29 and 26 mmCF/d in 2010, 2009 and 2008, respectively.
(2)		It excludes production volumes of natural gas consumed in operations. Said volumes were 318, 300 and 281 mmCF/d in 2010, 2009 and 2008, 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 105 KBOE/d, 97 KBOE/d and 93 KBOE/d in 2010, 2009 and 2008, 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 provided. Unit prices and production costs are disclosed separately for subsidiaries and equity-accounted entities. The average production cost does not include any ad valorem or severance taxes.

AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION

($)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

Americas

Australia and Oceania

Total consolidated subsidiaries

Equity- accounted entities

2008 Oil and condensate, per BBL		84.87		71.90		85.38		91.58		79.06		75.29		88.88		82.80		84.31		56.04
Natural gas, per KCF		13.06		10.55		7.15		1.50		0.53		5.05		8.81		9.59		7.99		11.91
Average production cost, per BOE		9.40		8.67		3.62		15.33		5.86		3.63		8.48		8.50		7.65		18.97
2009 Oil and condensate, per BBL		56.02		56.46		56.42		59.75		52.34		55.34		55.66		50.40		57.02		44.43
Natural gas, per KCF		9.01		7.06		5.79		1.66		0.45		4.09		4.05		8.14		5.62		6.81
Average production cost, per BOE		9.69		8.28		3.99		13.19		5.20		3.44		7.39		9.56		7.41		13.72
2010 Oil and condensate, per BBL		72.19		67.26		70.96		78.23		66.74		75.20		72.84		73.00		72.95		58.86
Natural gas, per KCF		8.71		7.40		6.87		1.87		0.49		4.35		4.70		7.40		6.01		8.73
Average production cost, per BOE		9.42		9.42		5.63		15.19		6.40		5.62		8.15		9.75		8.89		17.45

Drilling and other exploratory and development activities

In 2010, a total of 47 new exploratory wells were drilled (23.8 of which represented Eni’s share), which includes drilled exploratory wells that have been suspended pending further evaluation, as compared to 69 exploratory wells drilled in 2009 (37.6 of which represented Eni’s share) and 111 exploratory wells drilled in 2008 (58.4 of which represented Eni’s share).

Overall commercial success rate was 41% (39% net to Eni) as compared to 41.9% (43.6% net to Eni) and 36.5% (43.4% net to Eni) in 2009 and 2008, respectively.

In 2010, a total of 399 development wells were drilled (178 of which represented Eni’s share) as compared to 418 development wells drilled in 2009 (175.1 of which represented Eni’s share) and 366 development wells drilled in 2008 (155.1 of which represented Eni’s share). The drilling of 122 development wells (43 of which represented Eni’s share) is currently underway.

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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

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
2010 Exploratory		0.5		2.8		17.4		7.0				3.8		6.3		1.4		39.2
Productive				1.7		9.3		2.3				1.0				1.0		15.3
Dry (a)		0.5		1.1		8.1		4.7				2.8		6.3		0.4		23.9
Development		24.9		3.1		44.6		30.5		1.8		43.5		28.1		1.5		178.0
Productive		23.9		2.9		44.3		28.0		1.8		41.7		27.6		1.5		171.7
Dry (a)		1.0		0.2		0.3		2.5				1.8		0.5				6.3

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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 in 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, 2010. 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, 2010 Exploratory (a)
Gross		6.0		19.0		11.0		52.0		13.0		22.0		13.0		1.0		137.0
Net		4.4		5.0		8.7		12.6		2.3		11.7		4.0		0.4		49.1
Development
Gross		4.0		18.0		18.0		23.0		8.0		11.0		40.0				122.0
Net		3.5		2.9		8.1		8.4		1.5		5.8		12.8				43.0

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(a)

Includes temporary suspended wells pending further evaluation.

 

Oil and gas properties, operations and acreage

As of December 31, 2010, Eni’s mineral right portfolio consisted of 1,176 exclusive or shared rights for exploration and development in 43 countries on five continents for a total acreage of 320,961 square kilometers net to Eni of which developed acreage was 41,386 square kilometers and undeveloped acreage was 279,575 square kilometers.

In 2010, changes in total net acreage mainly derived from: (i) new leases in Poland, Democratic Republic of Congo, Togo, Angola, Pakistan and Venezuela for a total acreage of approximately 13,000 square kilometers; (ii) the divestment of wholly-owned subsidiary Società Padana Energia and leases in Nigeria for a total acreage of

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approximately 1,500 square kilometers; (iii) the total relinquishment of mainly exploration leases in Pakistan, Australia, Congo, Italy, Egypt, Russia and East Timor, covering an undeveloped acreage in excess of 23,000 square kilometers; and (iv) the decrease in net acreage due to partial relinquishment or interest reduction in Mali and Indonesia for a total net acreage of approximately 15,000 square kilometers.

The table below provides certain information about the Company’s oil and gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2010. A gross acreage is one in which Eni owns a working interest.

	December 31, 2009		December 31, 2010

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		31,607		287		17,430		28,293		45,723		11,142		17,937		29,079
Italy		22,038		154		10,951		12,945		23,896		8,995		10,102		19,097
Rest of Europe		9,569		133		6,479		15,348		21,827		2,147		7,835		9,982
Croatia		987		2		1,975				1,975		987				987
Norway		3,412		49		2,276		5,956		8,232		338		2,080		2,418
Poland				3				1,968		1,968				1,968		1,968
United Kingdom		1,469		73		2,228		1,364		3,592		822		329		1,151
Other countries		3,701		6				6,060		6,060				3,458		3,458
AFRICA		158,749		274		68,350		211,830		280,180		20,153		132,518		152,671
North Africa		46,011		116		31,723		48,530		80,253		13,802		30,475		44,277
Algeria		17,244		38		2,177		17,433		19,610		730		16,514		17,244
Egypt		8,328		54		5,135		12,669		17,804		1,847		4,747		6,594
Libya		18,165		13		17,947		18,428		36,375		8,951		9,214		18,165
Tunisia		2,274		11		6,464				6,464		2,274				2,274
West Africa		60,524		152		36,627		86,076		122,703		6,351		49,830		56,181
Angola		3,393		68		4,532		15,569		20,101		589		3,931		4,520
Congo		8,188		25		1,900		9,680		11,580		1,044		5,030		6,074
Democratic Republic of Congo				1				1,118		1,118				615		615
Gabon		7,615		6				7,615		7,615				7,615		7,615
Ghana		1,086		2				2,300		2,300				1,086		1,086
Mali		31,668		1				32,458		32,458				21,640		21,640
Nigeria		8,574		47		30,195		11,144		41,339		4,718		3,721		8,439
Togo				2				6,192		6,192				6,192		6,192
Other countries		52,214		6				77,224		77,224				52,213		52,213
ASIA		125,641		78		18,825		191,203		210,028		6,352		106,393		112,745
Kazakhstan		880		6		324		4,609		4,933		105		775		880
Rest of Asia		124,761		72		18,501		186,594		205,095		6,247		105,618		111,865
China		18,322		10		138		18,256		18,394		22		18,210		18,232
East Timor		7,999		4				8,087		8,087				6,470		6,470
India		10,089		14		303		27,861		28,164		143		9,946		10,089
Indonesia		16,519		12		1,735		24,054		25,789		656		12,256		12,912
Iran		820		4		1,456				1,456		820				820
Iraq		640		1		1,950				1,950		640				640
Pakistan		18,201		18		9,122		17,224		26,346		2,708		8,639		11,347
Russia		2,323		4		3,597		1,529		5,126		1,058		449		1,507
Saudi Arabia		25,844		1				51,687		51,687				25,844		25,844
Turkmenistan		200		1		200				200		200				200
Yemen		20,560		2				23,296		23,296				20,560		20,560
Other countries		3,244		1				14,600		14,600				3,244		3,244
AMERICAS		11,523		522		4,659		17,356		22,015		3,063		8,124		11,187
Brazil		1,067		1				745		745				745		745
Ecuador		2,000		1		2,000				2,000		2,000				2,000
Trinidad and Tobago		66		1		382				382		66				66
USA		6,450		506		1,899		8,536		10,435		899		4,997		5,896
Venezuela		614		5		378		2,528		2,906		98		1,056		1,154
Other countries		1,326		8				5,547		5,547				1,326		1,326
AUSTRALIA AND OCEANIA		20,342		15		1,057		43,153		44,210		676		14,603		15,279
Australia		20,304		14		1,057		42,389		43,446		676		14,565		15,241
Other countries		38		1				764		764				38		38
Total		347,862		1,176		110,321		491,835		602,156		41,386		279,575		320,961

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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, 2010. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same bore hole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 8,153 (2,895.6 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 at Dec. 31, 2010 (a)
Oil wells
Gross		224.0		408.0		1,240.0		3,002.0		91.0		618.0		134.0		4.0		5,721.0
Net		184.4		63.1		601.1		515.3		29.6		383.8		63.6		2.6		1,843.5
Gas wells
Gross		525.0		206.0		131.0		505.0				762.0		289.0		14.0		2,432.0
Net		479.3		93.2		52.6		37.1				290.5		96.1		3.3		1,052.1

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(a)

Includes approximately 2,320 gross (700 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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The Adriatic Sea represents Eni’s main production area in Italy, accounting for 55% of Eni’s domestic production in 2010. Main operated fields are Barbara, Angela-Angelina, Porto Garibaldi, Cervia and Bonaccia (for an overall production of approximately 212 mmCF/d).

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 and is treated by the Viggiano oil center with an oil 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 2010, the Val d’Agri concession produced 88 KBOE/d (47 net to Eni) representing 26% 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 2010 accounted for 10% of Eni’s production in Italy.

In 2010, production was started-up at: (i) the Annamaria B production platform (Eni operator with a 90% interest), located at the border with Croatian territorial waters. During the course of the year the field reached its production plateau at approximately 40 mmCF/d; and (ii) the Bonaccia Est field flowing at the initial rate of approximately 36 mmCF/d. In 2010, development activities progressed at the Val d’Agri concession (Eni’s interest 60.77%) as wells at Cerro Falcone were connected to the oil treatment centre. Other activities were performed including: (i) optimization of producing fields by means of sidetrack and work over activities (Barbara, Annalisa and Azalea); (ii) sidetrack programs and facility upgrading in Val d’Agri; (iii) upgrading activities of compression plants and treatment facilities at the Crotone plants; and (iv) development activities at the Capparuccia, Tresauro and Guendalina fields. In the medium-term, management expects production in Italy to slightly increase due to the production ramp-up of the Val d’Agri fields and ongoing new field projects and continuing production optimization activities partly offset by mature fields decline and divested fields.

Rest of Europe Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the UK. In 2010, the Rest of Europe accounted for 12% of Eni’s total worldwide production of oil and natural gas. Croatia. Eni has been present in Croatia since 1996. In 2010, Eni’s production of natural gas averaged 42 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula. Exploration and production activities in Croatia are regulated by PSAs. The main producing gas fields are Annamaria B (start-up in 2010, as disclosed above), Ivana, Ika & Ida, Marica and Katarina are operated by Eni through a 50/50 joint operating company with the Croatian oil company INA. Norway. Eni has been operating in Norway since 1964. Eni’s activities are performed in the Norwegian

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Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 120 KBOE/d in 2010.

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 any given number of years with possible extensions.

Eni currently 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%), Yttergryta (Eni’s interest 9.8%), Norne (Eni’s interest 6.9%) and Urd (Eni’s interest 11.5%) which in 2010 accounted for 72% of Eni’s production in Norway. In 2010, production was started-up at the Morvin field (Eni’s interest 30%) as three wells of the development program were put into production. Production is expected to peak at 15 KBOE/d net to Eni in 2011 when the project is completed. Development activities progressed to put in production discovered reserves near the Aasgard field with the Marulk development plan (Eni operator with a 20% interest). Start-up is expected in 2012. 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 2010 produced approximately 34 KBOE/d net to Eni and accounted for 28% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension. Activities were performed during the year to maintain and optimize the production rate by means of infilling wells, the development of the South Area extension, upgrading of existing facilities and optimization of water injection.

Eni is currently performing exploration and development activities in the Barents Sea. Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest). The license expires in 2042. The project is progressing according to schedule. In 2010, EPC contracts have been awarded for building an FPSO unit that will be linked to an underwater production system, onshore facilities and an offshore supply system designed to reduce CO₂ emissions. Start-up is expected in 2013 while the production peak of 100 KBBL/d will be reached the following year.

Exploration activities yielded positive results in: (i) the Prospecting License 128 (Eni’s interest 11.5%) with the Fossekal oil discovery that will exploit synergies with the Norne (Eni’s interest 6.9%) production facilities; (ii) in the PL 473 license (Eni’s interest 29.4%) with the Flyndretind oil discovery; and (iii) the PL 532 (Eni’s interest 30%) with the Skrugard oil and gas discovery.

Poland. In December 2010, Eni acquired Minsk Energy Resources, which operates 3 licenses in the Polish Baltic Basin. Management believes that is a highly prospective shale gas play. Drilling operations are expected to start in the second half of 2011 with a total exploration commitment of 6 wells.

United Kingdom. Eni has been present in the UK since 1964. Eni’s activities are carried out in the British section of the North Sea, the Irish Sea and certain areas East and West of the Shetland Islands. In 2010, Eni’s net production of oil and gas averaged 87 KBOE/d.

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

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In 2010, Eni signed a Sale and Purchase Agreement to divest its 18% stake of the Blane producing field and completed the divestment of its entire working interest in the Laggan (Eni’s interest 20%) and Tormore (Eni’s interest 22.5%) pre-development fields. Production started-up in Burghley field (Eni’s interest 21.92%).

Eni holds interests in 13 production areas; in 1 of these Eni is operator. The main fields are Elgin/Franklin (Eni’s interest 21.87%), West Franklin (Eni’s interest 21.87%), Liverpool Bay (Eni’s interest 53.9%), J Block Area (Eni’s interest 33%), Andrew (Eni’s interest 16.21%), Farragon (Eni’s interest 30%), Flotta Catchment Area (Eni’s interest 20%) and MacCulloch (Eni’s interest 40%), which in 2010 accounted for 85% of Eni’s production in the UK.

Ongoing activities are aimed at optimizing production at the Elgin/Franklin field and infilling activity at the J-Block. In the fourth quarter of 2010, the following projects were sanctioned by partners and relevant authorities: (i) the development plan of the Jasmine discovery (Eni’s interest 33%). Engineering activities are currently ongoing and start-up is expected in 2012; and (ii) Phase 2 of the development program of the West Franklin field. This project comprises the construction of a production platform and the drilling of additional wells with production processed by Elgin/Franklin treatment plant.

Pre-development activities started in Kinnoull oil and gas discovery (Eni’s interest 16.67%) to be developed through Andrew field’s production facilities.

Exploration activity concerned the drilling of an appraisal well in Culzean gas discovery (Eni’s interest 16.95%), near the Elgin/Franklin producing field for assessing its possible development options.

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2010, North Africa accounted for 33% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2010, Eni’s oil and gas production averaged 74 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 403a/d (Eni’s interest up to 100%); (ii) Blocks 401a/402a

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(Eni’s interest 55%); (iii) Blocks 403 (Eni’s interest 50%) and 404a (Eni’s interest 12.25%); (iv) Blocks 208 (Eni’s interest 12.25%) and 405b (Eni’s interest 75%) with ongoing development activities; (v) Block 212 (Eni’s interest 22.38%) with discoveries already made; and (vi)  Blocks 316b, 319a and 321a (Eni operator with a 100% interest) in the Kerzaz area with ongoing exploration activities.

Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts. Production in Block 403a/d comes mainly from the HBN and Rom and satellite fields and represented approximately 23% of Eni’s production in Algeria in 2010. The main project underway is the integrated development of Rom and satellites reserves (Zea, Zek and Rec) following the mineral potential revaluation. The development plan has been approved by the relevant authorities. Current production is collected at the Rom Central Production Facility (CPF) and delivered to the treatment plant in Bir Rebaa North. An export pipeline has been completed and a new multiphase pumping system is under finalization in compliance with applicable country law to reduce gas flaring. Production in Blocks 401a/402a comes mainly from the Rod and satellite fields and accounted for approximately 23% of Eni’s production in Algeria in 2010. 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 17% of Eni’s production in Algeria in 2010. In Block 405b, the development activity relates to the MLE and CAFC integrated project. The final investment decision was sanctioned for both projects (MLE in 2009; CAFC in April 2010). The MLE development plan provides for the construction of a natural gas treatment plant with a capacity of 350 mmCF/d and of four export pipelines with linkage to the national grid system. These facilities will also receive gas from the CAFC field.

As of December 31, 2010, 61% of MLE project was completed. The CAFC project provides the construction of an oil treatment plant and will also benefit from synergies with existing MLE production facilities. As of December 31, 2010, 27% of CAFC project was completed. MLE and CAFC start-up are expected in 2011 and 2012, respectively, with a production plateau of approximately 33 KBOE/d net to Eni by 2014.

Block 208 is located South of Bir Rebaa. The El Merk project is progressing with the drilling activities and the construction of treatment facilities. 60% of the project scope was completed at year end. Production start-up is expected in 2012.

The new Algerian hydrocarbon Law No. 5 of 2007 introduced a higher tax burden for the national oil company Sonatrach which has requested to renegotiate the economic terms of certain PSAs in order to restore the initial economic equilibrium. Eni signed an agreement for Block 403 in this respect while agreements have not yet been reached for Blocks 401a/402a (Eni’s interest 55%) and Block 208 (Eni’s interest 12.25%).

In the medium-term, management expects to increase Eni’s production in Algeria to approximately 120 KBOE/d, reflecting the development and integration of the First Calgary acquired assets.

Egypt. Eni has been present in Egypt since 1954. In 2010, Eni’s share of production in this country amounting to 222 KBOE/d and accounted for 13% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily in Belayim field (Eni’s interest 100%) and 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 (Eni’s interest 100%), El Temsah (50% interest), Baltim (50% interest) and Ras el Barr (50% interest, non-operated) and all located in the offshore the Nile Delta. In 2010, production from these main concessions accounted for approximately 90% of Eni’s production in Egypt.

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

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In July 2010, Eni signed a Strategic Framework Agreement with the Egyptian Ministry of Petroleum for new upstream and downstream initiatives. The agreement provides for: (i) a joint study to evaluate a number of upstream activities in the Mediterranean Basin and outside Egypt, including Gabon and Iraq; and (ii) an initiative to secure rights for Eni to acquire gas transport capacity in the Arab Gas Pipeline system in compliance with existing intergovernmental agreements. In May 2010, Eni divested a 50% interest in the Ashrafi offshore field located in the Gulf of Suez. Eni will retain operatorship and a 50% interest. Production start-up was achieved from Tuna field (Eni operator with a 50% interest) through linkage to the El Gamil facility with a production plateau at approximately 70 mmCF/d net to Eni. Other development activities mainly regarded: (i) the basic engineering of the Belayim field for the upgrading of water injection facilities to recover remaining reserves; (ii) the second phase of the Denise field (Eni operator with a 50% interest); and (iii) the upgrading of the El Gamil plant by adding new compression capacity to support production. Through its affiliate Unión Fenosa Gas, Eni has an indirect interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.1 mmtonnes/y of LNG corresponding to approximately 268 BCF/y of

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feed gas. Eni is currently supplying 35 BCF/y for a 20-year period. Natural gas supplies derived from the Taurt and Denise fields with 17 KBOE/d net to Eni of feed gas.

Exploration activities yielded positive results in the: (i) Belayim concession (Eni’s interest 100%) with two discovery wells containing oil that were linked to existing facilities; (ii) El Qara North (Eni’s interest 75%) and Zaafaran East (Eni’s interest 75%) gas discoveries which were linked to the existing nearby facilities; (iii) Melehia development lease (Eni’s interest 56%) with the Jana and Arcadia oil discoveries. The latter was started-up in the second half of the year.

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 2010, Eni’s oil and gas production averaged 267 KBOE/d, the portion of liquids being 43%. Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contract areas. Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%). In the exploration phase, Eni is operator of four onshore blocks in the 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 licenses of Eni’s assets in Libya expire in 2042 and 2047 for oil and gas properties, respectively. From February 22, 2011, some liquids and natural gas production activities and the gas export through the GreenStream pipeline have been halted. Facilities have not suffered any damage and such standstill does not affect Eni’s ability to ensure natural gas supplies to its customers. Eni is technically able to resume gas production at or near previous level once the situation stabilizes. The overall impact of instability and conflict in Libya on Eni’s results in terms of operations and cash flows will depend on how long such political instability and unrest will last, which management is currently unable to predict. Eni’s production as of end of March 2011, was flowing at around 70-75 KBOE/d, down from the expected level of approximately 280 KBOE/d, and is made of gas which is totally delivered to local power generation plants. Production is continuing to decline..

Eni has limited investments planned in Libya over the course of the next two years, and no major project start-up are planned for the next four years.

Main development activities underway concerned the Western Libyan Gas Project (Eni’s interest 50%) for the monetization of gas reserves ratified in the strategic agreements between Eni and NOC. Activities were performed for maintaining in the future gas production profiles at the Wafa and Bahr Essalam fields through increasing compression capacity at the Wafa field and drilling additional wells at both fields. In 2010, volumes delivered through the GreenStream pipeline were 309 BCF. In addition, 53 BCF were sold on the Libyan market for power generation and approximately 7 BCF to feed the GreenStream compressor station.

Tunisia. Eni has been present in Tunisia since 1961. In 2010, Eni’s production amounted to 19 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.

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

In 2010, Eni signed new terms for the El Borma concession (Eni’s interest 50%), due to expire in 2043.

Development activities concerned the completion of the operated Baraka project and ramp-up of production at Maamoura field.

Optimization of production was carried out at the Adam, Djebel Grouz (Eni’s interest 50%), Oued Zar and El Borma fields.

In the medium-term, Eni expects production in Tunisia as a result of the development of recent offshore discoveries.

West Africa

Eni’s operations in West Africa are conducted mainly in Angola, Congo and Nigeria. In 2010, West Africa accounted for 22% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2010, Eni’s production averaged 113 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 3 (Eni’s interest ranging from 12% to 55%) in the offshore of the Congo Basin; (iii) Development Areas in the former Block 14 (Eni’s interest 20%) in the deep offshore West of Block 0; and (iv) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin. Eni also holds interests in other minor concessions, in particular 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, 15% 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 January 2011, Eni was awarded rights to explore and the operatorship of deep offshore Block 35, with a 30% interest. The agreement foresees drilling 2 wells to be carried out in the first 5 years of exploration. This deal is subject to the approval of the relevant authorities. West Hub is the main project underway in the Development Area of operated Block 15/06 (Eni’s interest 35%), with start-up expected in 2013 and peaking production at 22 KBBL/d net to Eni.

Within the activities for reducing gas flaring in Block 0, activity progressed at the Nemba field in Area B. The completion is expected in 2013 reducing flared gas by approximately 85%. Other ongoing projects include: (i) completion of linkage and treatment facilities at the Malongo plant; and (ii) installation of a second compression unit at the platform in the Nemba field in Area B. Flaring down of the Malongo area is still underway with completion 2011.

In the Development Areas of former Block 14, infilling activity was carried out at the Benguela-Belize/Lobito-Tomboco fields. Drilling of wells in Tombua-Landana field is ongoing as per field development plan.

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Main projects underway in the Development Areas of former Block 15 (Eni’s interest 20%) regarded: (i) the satellites of Kizomba Phase 1, with start-up expected before mid 2012 and peaking production at 100 KBBL/d (21 KBBL/d net to Eni) in 2013; and (ii) drilling activity at the Mondo and Saxi/Batuque fields to finalize their development plan. The subsea facility of the Gas Gathering project has been already completed. The project provides the construction of a pipeline collecting all the gas of the Kizomba, Mondo and Saxi/Batuque fields.

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 approximately 1.1 BCF/d of natural gas and production of 5.2 mmtonnes/y of LNG, condensates and LPG. The project has been sanctioned by relevant Angolan Authorities. It envisages the development of 10,594 BCF of gas in 30 years. Start-up is expected in the first quarter of 2012. LNG was originally expected to be delivered to the USA market at the re-gasification plant in Pascagoula, currently under construction, (Eni’s capacity amounting to approximately 205 BCF/y) in Mississippi. During the year, Eni signed a Memorandum of Understanding with the other project partners to assess possible further marketing opportunities. In 2010, the principal following activities were carried out: (i) engineering and procurement; (ii) linkage from offshore to onshore facilities; (iii) implementation of the construction of storage tanks for the processed products and onshore plant facilities; and (iv) fuel gas supplies from Block 15.

In addition, Eni is part of a second gas consortium with the national Angolan company and other partners that will explore further potential gas discoveries to support the feasibility of a second LNG train or marketing projects to deliver gas and associated liquids. Eni is technical advisor with a 20% interest.

Exploration activities yielded positive results in: (i) operated Block 15/06 (Eni’s interest 35%) with the appraisal wells of the Cinguvu (Cinguvu-1), Cabaça (Cabaça South East-2) and Mpungi (Mpungi 1 e 2) oil discoveries. The appraisal activities were completed ahead of schedule with commitments increasing the initial resource estimation to develop the East Hub and West Hub projects. In February 2010, the West Hub concept definition (FEED) was approved while the final investment decision was sanctioned at year end; (ii) Development Areas in former Block 14 (Eni’s interest 20%) with the Lucapa 6 appraisal oil well. Activities are underway for assessing its possible development opportunities following the area’s mineral potential revaluation; and (iii) Block 0 (Eni’s interest 9.8%) with the liquids and gas discovery located in the Vanza area.

In the medium-term, management expects to increase Eni’s production to approximately 190 KBBL/d reflecting contributions from ongoing development projects. Congo. Eni has been present in Congo since 1968. In 2010, production averaged 107 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 and 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, PEX and Likouala permits. In the exploration phase, Eni also holds interests in the Mer Très Profonde Sud deep offshore block (Eni’s interest 30%), the Noumbi onshore permit (Eni’s interest 37%) and the Marine XII offshore permit (Eni operator with a 65% interest). Exploration and production activities in Congo are regulated by Production Sharing Agreements. Production started-up at Zingali and Loufika (Eni operator with an 85% interest) onshore satellites of the M’Boundi field. Ongoing development activities concerned offshore fields with start-up expected in 2011-2012.

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Activities on the M’Boundi field (Eni operator with an 83% interest) moved forward with the application of advanced recovery techniques and a design to monetize associated gas within the activities aimed at reducing flared gas. 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 under construction potassium plant, owned by Canadian Company MAG Industries; (ii) the existing Djeno power plant (CED - Centrale Electrique du Djeno); and (iii) the recently built CEC Centrale Electrique du Congo power plant (Eni’s interest 20%). These facilities will also receive gas in the future from the offshore discoveries of the Marine XII permit. Development activities to build the CEC power plant moved forward as scheduled in the cooperation agreement signed by Eni and the Republic of Congo in 2007, with the start-up of the first and second turbo-generator.

Within the activities aimed to monetize gas reserves, the RIT project moved forward with the rehabilitation plan of the Pointe Noire-Brazzaville power grid. In 2010 the project DEPN - Phase 1 (Distribution Electrique à Pointe Noire) started-up in the town of Pointe Noire.

In the medium-term, management expects to increase Eni’s production in Congo due to the integration and development of recently acquired assets as well as projects underway, targeting a level in excess of 120 KBOE/d by 2014.

Democratic Republic of Congo. In August 2010, Eni acquired a 55% stake and operatorship in the Ndunda Block located in the Democratic Republic of Congo which may lead to future developments after exploration activities. At present no activities are conducted in this country.

Nigeria. Eni has been present in Nigeria since 1962. In 2010, Eni’s oil and gas production averaged 167 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 26 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 Blocks OML 60, 61, 62 and 63 (Eni operator with a 20% interest), within the activities aimed at supplying production of feed gas to the Bonny liquefaction plant (Eni’s interest 10.4%), the following development activities have been implemented: (i) the completion of basic engineering to increase capacity at the Obiafu/Obrikom plant; and (ii) the installation of a new treatment plant and transport facility aiming to 155 mmCF/d of feed gas for a 20-year period.

Exploration activity yielded positive results with the Tuomo 4 oil discovery (Eni’s interest 20%) and the development plan of the Tuomo gas field has been progressing with an early production through a linkage from Tuomo 4 well to the Ogbainbiry treatment plant. In 2010, a new compressor plant was started-up aiming to feed gas for the liquefaction trains 4 and 5, amounting to 311 mmCF/d (60 mmCF/d net to Eni).

In Block OML 61 flaring down of the Ebocha oil plant was completed.

In Block OML 28 (Eni’s interest 5%) within the integrated oil and natural gas project in the Gbaran-Ubie area, the first treatment unit started-up with first gas production. The Phase-2 is currently ongoing and start-up is expected in 2012. The development plan, currently ongoing, foresees for the construction of a Central Processing Facility (CPF) with treatment capacity of about 1 BCF/d of gas and 120 KBBL/day of liquids, the drilling of producing wells and the construction of a pipeline to carry the gas to the Bonny liquefaction plant.

The Forcados/Yokri oil and gas field (Eni’s interest 5%) is under development as part of the integrated associated gas gathering project aimed at supplying gas to the domestic market. First gas is expected in 2013 and project completion in 2015.

Eni holds a 10.4% interest in Nigeria LNG Ltd 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 on 6 trains. The seventh unit is being engineered as it is in the planning phase. When fully-operational, total capacity will amount to approximately 30 mmtonnes/y of

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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 Blocks OMLs 60, 61, 62 and 63. In 2010, total supplies were 1,870 mmCF/d (191 mmCF/d net to Eni corresponding to 34 KBOE/d). LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.

Eni holds a 17% interest of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal, 100 kilometers West of Bonny. This plant is expected to start operating in 2016 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 gathering 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). LNG will be delivered to the USA market mainly at the re-gasification plant in Cameron, in Louisiana. Eni’s capacity amounts to approximately 201 BCF/y. Front end engineering activities progressed. EPC tender exercise is ongoing. The final investment decision is envisaged in 2011.

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

Togo. In October 2010, Eni awarded operatorship of offshore Block 1 and Block 2 (Eni 100%) in the Dahomey Basin as part of its agreements with the Government of Togo to develop the country’s offshore mineral resources.

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 2010, Eni’s operations in Kazakhstan accounted for 6% of its total worldwide production of oil and natural gas.

Kashagan. Eni holds a 16.81% working interest in the NCSPSA. The NCSPSA defines terms and conditions for the exploration and development 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.

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Management believes this field contains a large amount of hydrocarbon resources which will eventually 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%.

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

The consortium is currently focused on completing Phase 1 and starting commercial oil production. Phase 1 completion as at December 2010 was around 80%, of which the completion of tranches 1 and 2 allowing the first production was around 90%.

The partners of the venture are currently discussing an update of the expenditures and time schedule to complete the Phase 1 which were included in the development plan approved in 2008 by the relevant Kazakh Authorities. The consortium continues to target the achievement of first commercial oil production by end of 2012. However, the timely delivery of Phase 1 depends on a number of factors which are presently under review.

The Phase 1 of the project targets an initial production capacity of 150 KBBL/d. In the 12-15 months following the start-up, the treatment plant and the compression facilities for gas re-injection will be started-up enabling an increase of the production capacity to 370 KBBL/d by 2014. A further increase of production capacity to 450 KBBL/d is expected as additional compression capacity for gas re-injection becomes available with the start-up of Phase 2 offshore facilities. Early engineering studies of Phase 2 are underway aiming at optimizing the development scheme.

Management believes that significant capital expenditures will be required in case the partners of the venture would sanction Phase 2 and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long time horizon and subsequently to the production start-up, management does not expect a material impact on the Company’s liquidity or its ability to fund these capital expenditures. In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production from Phase 2 and subsequent phases to the international markets.

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

As of December 31, 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, 2010, the aggregate costs incurred by Eni for the Kashagan project capitalized in the Consolidated Financial Statements amounted to $5.8 billion (euro 4.4 billion at the EUR/USD exchange rate of December 31, 2010). This capitalized amount included: (i) $4.5 billion relating to expenditures incurred by Eni for the development of the oil field; and (ii) $1.3 billion relating primarily to accrue finance charges and expenditures

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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 PSA lasting 40 years, until 2037. Eni and British Gas are co-operators of the venture both with a 32.5% interest. In 2010, production of the Karachaganak field averaged 228 KBBL/d of liquids (65 net to Eni) and 812 mmCF/d of natural gas (221 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 70% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 200 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. The remaining volumes of non-stabilized liquid production and associated gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg. The execution of the fourth treatment unit has been progressing towards completion and will enable to increase export of oil volumes to Western markets of currently non-stabilized liquids delivered to the Orenburg terminal. Phase 3 of the Karachaganak project targets to increase the development of gas and condensates reserves. The engineering activities identified a phased approach as the preferred development strategy with stage 1 of the project providing for the installation of gas producing and re-injection facilities to increase liquid production and gas sales in accordance with the foreseeable future market conditions. Technical and marketing discussion on Phase 3 with the relevant Kazakh Authorities are underway.

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

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 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.

Rest of Asia

In 2010, Eni’s operations in the rest of Asia accounted for 7% 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 2010 Eni’s production amounted to 7 KBOE/d.

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Exploration and production activities in China are regulated by Production Sharing Agreements. Hydrocarbons are produced from the offshore Blocks 16/08 and 16/19 through eight platforms connected to a FPSO. Natural gas production from the HZ21-1 field is delivered through a sealine to the Zhuhai Terminal and sold to the Chinese National Company CNOOC. Oil, which is sold into the domestic market, is mainly produced from HZ25-4 field (Eni’s interest 49%). Activity is operated by the CACT-Operating Group (Eni’s interest 16.33%). In January 2011, Eni signed a Memorandum of Understanding with the national oil company PetroChina to promote common opportunities to jointly expand operations in conventional and unconventional hydrocarbons in China and outside China. India. Eni has been present in India since 2005 and its activities are located in the offshore Cauvery Basin near the South-Eastern coast. In 2010, Eni’s production amounted to 7 KBOE/d. Production mainly comes from the PY-1 gas field which is part of the assets belonging to Hindustan Oil Exploration Co Ltd (Eni’s interest 47.18%) acquired within Burren acquisition. Gas production is sold to the local national oil company. Indonesia. Eni has been present in Indonesia since 2001. In 2010, Eni’s production mainly composed of gas, amounted to 16 KBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, the offshore Sumatra, and the offshore and onshore area of the West Timor; in total, Eni holds interest in 12 blocks. Exploration and production activities in Indonesia are regulated by PSAs. Eni is also involved in the ongoing study phase of joint development of the oil and gas discoveries in the Bukat permit (Eni operator with a 66.25% interest), the Muara Bakau permit (Eni operator with a 55% interest) and the five discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%). In 2010, the exploration activities related to the coal bed methane project were started in the Sanga Sanga PSC (Eni’s interest 37.8%). In case of commercial discovery, the project will exploit the synergy opportunities provided by the existing production and treatment facilities also including the Bontang LNG plant. Exploration activity yielded positive results in the Muara Bakau permit (Eni operator with a 55% interest), located offshore East Kalimantan, where the Jangkrik 2 and 3 appraisal wells significantly increased the initial reserve evaluations. Iran. Eni has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, these latter two projects

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being operated by another international oil company) entered into with the National Iranian Oil Co (NIOC) between 1999 and 2001, and no other exploration and development contracts have been entered into since then. All projects mentioned above have been completed or substantially completed; the last one, the Darquain project, is in the process of final commissioning and is being handed over to NIOC. Operatorship has already been transferred to a NIOC affiliate. When hand over of operations is completed, Eni’s involvements will essentially consist of being reimbursed for its past investments. In 2010, Eni’s production in Iran was 21 KBOE/d, approximately 1% of the Group’s worldwide production. Eni does not believe that its activities in Iran have a material impact on the Group’s results. See "Item 3 – Risk Factors – Political Consideration – Iran" for a full discussion of risks involved by our presence in Iran.

Iraq. In January 2010, Eni leading a consortium of partners including international companies and the national oil company Missan Oil signed a technical service contract to develop the Zubair oil field (Eni 32.8%) with the Iraqi South Oil Company, under a 20-year term with an option for further 5 years extension. The field was awarded to the Eni-led consortium following a successful first bid round and was offered under a competitive bid starting on June 30, 2009. The development of the project foresees to gradually increase production to a target plateau level of 1.2 mmBBL/d over the next six years. The contract provides the recovery of expenditures incurred from the incremental production of the field and the recognition of a remuneration fee once the production has been raised by 10% from its initial level of approximately 180 KBBL/d. Development provides for two phases: (i) Rehabilitation plan, approved in June 2010, aimed at improving the current production level and the knowledge of the reservoir; and (ii) Redevelopment plan allowing to reach the scheduled targets. In 2010 all the milestones planned for the initial phase of the project were achieved. In particular in September 2010, production was raised by more than 10% above the initial production rate allowing the consortium, based on the contact provision, to begin recovery of costs and recognition of remuneration fee. Therefore Eni starting from the last quarter of 2010 booked its equity production in relation to its share of cost recovery and remuneration.

Pakistan. Eni has been present in Pakistan since 2000. In 2010, Eni’s production averaged 58 KBOE/d and is mainly gas.

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

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 2010 accounted for 86% of Eni’s production in Pakistan.

Development activities concerned: (i) the Bhit field (Eni operator with a 40% interest) with the completion of a compressor plant and the drilling of new wells aimed at maintaining current production plateau; (ii) the Sawan field (Eni’s interest 23.68%) with a review of production facilities and reservoir to mitigate the current decline; and (iii) the Zamzama permit (Eni’s interest 17.75%) with the start-up of the Front End Compressor.

Exploration activity yielded positive results with the Latif North 1 appraisal well (Eni’s interest 33.33%) which started-up in 2010.

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

As part of the transaction to divest a 51% stake in Eni-Enel’s joint venture Llc SeverEnergia to Gazprom, based on the call option exercised by the Russian company in September 2009, Eni collected a second installment of the transaction by March 31, 2010. This amounted to euro 526 million ($710 million, approximately 75% of the total amount of the transaction).

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Ongoing activities mainly concerned the development of the Samburskoye gas field. Start-up is planned by 2012, targeting a production plateau of 150 KBOE/d.

Turkmenistan. Eni started its activities in Turkmenistan with the purchase of British company Burren Energy plc in 2008. Activities are mainly focused in the Western part of the country. In 2010 Eni’s production averaged 12 KBOE/d.

Exploration and production activities in Turkmenistan are regulated by PSAs.

Eni is operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receive, by mean of a swapping with the Turkmen Authorities, an equivalent amount of oil at the Okarem field, close to the South coast of Caspian Sea. Eni’s entitlement is sold FOB. Associated natural gas is used to own consumption and gas lift system. The remaining amount is delivered to Turkmenneft, via national grid.

America

In 2010, Eni’s operations in America area accounted for 8% of its total worldwide production of oil and natural gas.

Ecuador. Eni has been present in Ecuador since 1988 and activities are performed in Block 10 (Eni’s interest 100%) located in the Amazon forest. In 2010, Eni’s production averaged 11 KBBL/d.

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

Production derives from the Villano field and is carried out by means of a Central Production Facility linked by pipeline to the storage facility.

In November 2010, Eni signed with the Government of Ecuador new terms for the service contract for the Villano oil field, due to expire in 2023. Under the new agreement, the operated area is enlarged to include the Oglan oil discovery, with volumes in place of 300 mmBBL. In case of a successful appraisal campaign on Oglan, development will be carried out in synergy with existing facilities.

Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2010, Eni’s production averaged 64 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 USA, Spain and the Dominican Republic.

In 2010, the development plan of the Poinsettia, Bougainvillea and Heliconia fields in the North Coast Marine Area 1 Block (Eni’s interest 17.4%) was completed through the installation of a production platform on the Poinsettia field and the linkage to the Hibiscus treatment facility which was already upgraded. The new scheme platform was started-up in 2010.

USA. Eni has been present in the USA 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 2010, Eni’s oil and gas production is mainly derived from the Gulf of Mexico with an average of 108 KBOE/d.

Exploration and production activities in the USA are regulated by concessions.

Eni holds interests in 354 exploration and production blocks in the Gulf of Mexico of which 61% are operated by Eni.

The main fields operated by Eni are Allegheny, East Breaks and Morphet (Eni’s interest 100%), Longhorn-Leo, Devils Towers and Triton (Eni’s interest 75%) as well as King Kong (Eni’s interest 54%) and Pegasus (Eni’s interest 58%). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%), and Thunder Hawk (Eni’s interest 25%) fields.

Drilling activities in the Gulf of Mexico were impacted by the incident at the BP-operated Macondo well. The U.S. Government imposed a six-month moratorium on new offshore drilling activities that was suspended in

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October 2010. Through the end of 2010, development or drilling activities were still suspended, due to the delay in getting the relevant authorizations. For further information, see "Item 3 – Risk Factors".

In 2010, the development plan of the Alliance area (Eni’s interest 27.5%), in the Fort Worth Basin in Texas moved forward. This area, including gas shale reserves, was acquired in 2009 following a strategic alliance that Eni signed with Quicksilver Resources Inc. Production plateau at 10 KBOE/d net to Eni is expected in 2012.

Exploration activity yielded positive results with the oil and natural gas Hadrian West appraisal well, located in offshore Block KC 919 (Eni’s interest 25%), in the Gulf of Mexico.

Eni holds interests in 151 exploration and development blocks in Alaska, with interests ranging from 10 to 100% and for over half of these blocks, Eni is the operator.

Production is provided by the Oooguruk oil field (Eni’s interest 30%), in the Beaufort Sea and amounted to 10 KBBL/d (3 KBBL/d net to Eni) in 2010.

The main development activities concerned the Nikaitchuq operated field (Eni’s interest 100%), located in North Slope Basins offshore Alaska, with resources of 220 mmBBL. Production start-up was achieved at the end of January 2011. Peak production is expected at 28 KBBL/d.

Venezuela. Eni has been present in Venezuela since 1998. In 2010, Eni’s production averaged 10 KBBL/d.

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

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

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 more than 40 KBBL/d (approximately 11 net to Eni) is expected in 2012.

In June 2010, Eni was awarded gas exploration and development permits with a 40% interest in Punta Pescador and Gulfo de Paria Ovest, the latter coinciding with the Corocoro oil field area (Eni’s interest 26%). Commitment activities are under negotiation with the relevant authorities.

On January 26, 2010, Eni and 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. The two partners plan to achieve first oil by 2013 at an initial rate of 75 KBBL/d, targeting a long-term production plateau of 240 KBBL/d to be reached in 2018.

As part of the agreement, on November 22, 2010, Eni and PDVSA signed the contracts to set up two Empresas Mixtas (Eni’s interest 40%, PDVSA’s interest 60%) for the development of the Junin 5 field and the construction and operation of a refinery with a capacity of 350 KBBL/d that will allow also the treatment of intermediate streams from other PDVSA facilities. Eni, at the publication of the contract of incorporation of the Junin 5 project "Empresa Mixta" in December 2010 paid the first tranche of the bonus of $300 million; the balance of $346 million will be paid in additional tranches according to the achievement of milestones of the project.

Exploration activities yielded positive results with the successful appraisal campaign of the Perla gas field, located in the Cardon IV Block (Eni’s interest 50%) in the Gulf of Venezuela. This block is under a Concession Agreement for gas exploration and exploitation licensed and operated by a Venezuelan Joint Venture Company. PDVSA owns a 35% back-in-right to be exercised in the development phase, and at that time Eni will hold a 32.5% joint controlled interest in the company. Perla 2, 3 and 4 appraisal wells results exceeded the initial resource estimation by 50%. A Front End Engineering Design contracts related to offshore facility and transport infrastructure were assigned in 2010 targeting an early production phase of 300 mmCF/d with start-up in 2013. The early production phase includes the utilization of the already successfully drilled wells and the installation of four light offshore platforms linked, through a gas pipeline, to a Central Processing Facility (CPF) located onshore. The development of Perla is currently planned to continue with the full field phase, which includes additional producer wells and the CPF upgrade, to reach a plateau production of 1,200 mmCF/d.

Eni is also participating with a 19.5% interest in the Gulfo de Paria Centrale offshore exploration block, 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 2010, Australia and Oceania area accounted for 2% of Eni’s total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2000. In 2010, Eni’s production of oil and natural gas averaged 26 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 9 licenses (in 2 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 project is progressing according to schedule. Start-up is expected in 2011.

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 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".

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Gas & Power

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, managing gas infrastructures for transport, distribution, storage, re-gasification, and LNG supply and marketing. This segment also includes the activity of power generation that is ancillary to the marketing of electricity. In 2010, Eni’s worldwide sales of natural gas amounted to 97.06 BCM, including 5.65 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the USA. Sales in Italy amounted to 34.29 BCM, while sales in European markets were 54.52 BCM that included 8.44 BCM of gas sold to certain importers to Italy.

Gas transport, distribution and storage, as well as re-gasification of LNG in Italy are regulated activities as tariffs for the services rendered to gas operators and return on capital employed are set by an independent administrative body. For further description on those regulated activities see below.

 

Marketing of natural gas

The competitive landscape in the marketing of gas in the pan-European sector has changed dramatically from late 2008 to date. Gas demand across Europe was severely impacted by the economic downturn and has been struggling to recover to pre-crisis levels as the industrial activity is slowly progressing, particularly in Italy.

On the supply side, gas availability has considerably increased on the marketplace due to capacity upgrading at the major international pipelines which carry natural gas from producing countries to Europe, including the TAG line from Russia and the TTPC line from Algeria. Also large quantities of LNG have been directed towards Europe as a number of important upstream projects started operations worldwide, and the U.S. market has progressively reduced its LNG imports due to commercial exploitation of large gas reserves from non-conventional sources. Several LNG terminals and facilities which were recently finalized commenced to receive those surpluses of LNG in Europe. The build up of LNG supplies at the European hubs has driven down spot prices which have fallen below the level of gas prices based on oil-linked formulas. That trend has impaired the profitability of gas operators, including Eni, whose portfolio of supplies is mainly indexed to the cost of oil and certain refined products as provided in purchasing formulas of long-term take-or-pay contracts, while spot prices have increasingly become the benchmark in selling formulas, particularly outside Italy.

In 2010, our gas marketing operations reported significantly lower operating profit driven by lower sales in Italy due to mounting competitive pressures and compressed unit margins in sales outside Italy. Operating profit for the year in the gas marketing business decreased by 64% from a year ago and represented less than 5% of the Group’s consolidated operating profit for 2010. The short-term outlook for the European gas sector remains challenging. Weak underlying fundamentals and strong competitive pressures are expected to stay in place for some time. Risks still exist in the next couple of years that the Company may be unable to fulfill its minimum take obligations associated with its long-term gas purchase contracts providing take-or-pay clauses. For a description of those risks see "Item 3 – Risk Factors" and "Item 5 – Outlook". However, management expects that the European gas market will rebalance by the end of the 2011-2014 period due to a number of trends. In fact, it is expected that demand will continue to recover to pre-crisis level and be driven by economic expansion and increased consumption by the power generation sector. Production from European fields will continue to deplete, increasing the need for gas imports. Also, LNG oversupplies will be progressively absorbed due to increasing energy requirements in other parts of the world and limited new capacity additions in the Atlantic Basin. In such a scenario, Eni’s long-term supply contracts and access to transport and storage infrastructures will again become a competitive advantage.

Against this backdrop, management plans to improve results in its gas marketing operations which management expects to recover to 2009 profitability levels by 2014. We intend to renegotiate better economic terms and operating conditions in our long-term gas purchase contracts, so as to restore the competitiveness of the Company’s cost position in the current weak scenario for the gas sector. The renegotiation of revised contractual terms, including any price revisions and contractual flexibility, is established by such contractual clauses whereby parties are held to bring the contract back to the economic equilibrium in case of significant changes in the market environment, like the ones that have been occurring from the second half of 2008. In the course of 2010, Eni has finalized a number of important contractual renegotiations by obtaining improved economic conditions for supplies and wider contractual flexibility with a benefit to its commercial programs. A number of renegotiations have commenced or are due to commence in the near future involving all the Company’s main suppliers of gas based on long-term contracts. The Company targets to grow sales volumes at an average annual rate of 5% both in Europe and Italy over the plan period; particularly we plan:

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For a description of uncertainties and risks associated with this strategy including a discussion of the possible consequences of the Libyan political instability and conflict see "Item 3 – Risk Factors" and "Item 5 – Outlook".

In the next four-year period, management plans to invest euro 1.1 billion in marketing activities mainly directed to: (i) power plant upgrading, including building a new bio-mass power generation plant at Eni’s Porto Torres industrial site where a reconversion plan is underway; and (ii) increasing flexibility of generation facilities.

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

 

Demand outlook

In 2010, gas demand in Italy and Europe rebounded from the depressed levels registered in the previous year, growing by 6% and 4%, respectively. Consumption volumes however remained below the pre-crisis levels seen in 2007. Looking forward, management estimates that long-term gas demand growth will achieve an average rate of 1.7% and 1.1% in Italy and Europe, respectively, until 2020. Those projections imply a consumption level of approximately 590 BCM for the Europe as a whole by 2020; while in Italy a consumption level of approximately 97 BCM is projected at 2020.

Those estimates have been revised down from previous management projections to factor in the expected impacts associated with a number of ongoing trends:

Among positive drivers for demand growth, it is worth mentioning the growing adoption of natural gas to fuel thermoelectric production via combined cycles and the higher environmental compatibility of natural gas than other fossil fuels to produce energy.

 

Supply of natural gas

In 2010, Eni’s consolidated subsidiaries supplied 82.49 BCM of natural gas, representing a decrease of 6.16 BCM, or 6.9% from 2009 reflecting lower sales for the year.

Gas volumes supplied outside Italy (75.20 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 92% of total supplies, a decrease of 6.59 BCM, or 8.1%, from 2009, mainly reflecting a decline in natural gas sales. In 2010, lower volumes were purchased from: (i) Russia (down 7.73 BCM), where Eni reduced its off-takes in particular of volumes directed to Italy; (ii) the Netherlands (down 1.57 BCM); and (iii) Norway (down 1.17 BCM) also due to the impact of an accident that occurred at the import pipeline Transitgas in August 2010.

In 2010, increases were recorded in gas purchases from Algeria (up 2.41 BCM) and from the UK (up 1.8 BCM), as well as in LNG availability.

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Supplies in Italy (7.29 BCM) increased by 0.43 BCM from 2009, or 6.3%, also due to higher domestic production.

In 2010, main gas volumes from equity production derived from: (i) Italian gas fields (6.7 BCM); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2010, 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 (2.6 BCM); and (iv) other European areas (Croatia with 0.4 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 BCM representing 21% of total volumes available for sale.

In 2010, volumes input to storage deposits owned by Eni’s subsidiary Stoccaggi Gas Italia amounted to 0.20 BCM compared to withdrawals from storage deposit 1.25 BCM in 2009.

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

Natural gas supply		2008		2009		2010

(BCM)

Italy		8.00			6.86			7.29
Outside Italy		81.65			81.79			75.20
Russia		22.91			22.02			14.29
Algeria (including LNG)		19.22			13.82			16.23
Libya		9.87			9.14			9.36
the Netherlands		9.83			11.73			10.16
Norway		6.97			12.65			11.48
the United Kingdom		3.12			3.06			4.14
Hungary		2.84			0.63			0.66
Qatar (LNG)		0.71			2.91			2.90
Other supplies of natural gas		4.07			4.49			4.42
Other supplies of LNG		2.11			1.34			1.56
Total supplies of subsidiaries		89.65			88.65			82.49
Withdrawals from (input to) storage		(0.08	)		1.25			(0.20	)
Network losses, measurement differences and other changes		(0.25	)		(0.30	)		(0.11	)
Volumes available for sale of Eni’s subsidiaries		89.32			89.60			82.18
Volumes available for sale of Eni’s affiliates		8.91			7.95			9.23
E&P volumes		6.00			6.17			5.65
Total volumes available for sale		104.23			103.72			97.06

In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing countries that supply the European gas markets. These contracts have been ensuring approximately 80 BCM of gas availability from 2010 (including the Distrigas portfolio of supplies) with a residual life of approximately 19 years and a pricing mechanism indexed to the price of crude oil and its derivatives (gasoil, fuel oil, etc). The contracts provide take-or-pay clauses whereby the Company is required to collect minimum pre-determined volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, applied to uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. 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 current in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations.

Management believes that the current outlook for increasing competition pressures coupled with large gas availability on the marketplace, the possible evolution of sector-specific regulation, as well as the de-coupling between trends in gas prices indexed to oil versus gas benchmark prices at spot markets, represent risks factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts.

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Particularly, management expects that the Company will experience increasing exposure to the risk associated with growing adoption on the marketplace of selling formulas linked to spot prices which movements are independent of those of oil prices and refined products that drive supply costs in Eni’s take-or-pay contracts.

In the years 2009 and 2010, Eni incurred the take-or-pay clause as the Company collected lower volumes than its minimum take obligations in each of those years accumulating deferred costs for an amount of euro 1.44 billion as of December 31, 2010. The Company’s ability to recover those pre-paid volumes within contractual terms will depend in future years on a number of factors, including the possible evolution of the market environment and the competitiveness of Eni’s cost position. Ongoing political instability in Libya and the shut down of the GreenStream pipeline may possibly counteract those negative trends as the Company may be able to replace supplies from Libya with gas from its ample portfolio. The latter trend will evolve depending on how long such political instability and conflict will last and on their outcome which for the time being cannot be foreseen.

In case 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.

Based on management’s projections for sales volumes and unit margins for the four-year plan and subsequent years which incorporated expected trends in the European market fundamentals, and management’s assumptions to renegotiate better economic terms within the Company’s long-term gas purchase contracts, so as to restore the competitiveness of the Company’s cost position, the Company believes that in the long-term it will be in the position to recover volumes of gas which have been pre-paid in 2009 and 2010 due to the take-or-pay clause and also possible new volumes associated with the contractual clause due to the uncertainties and weak conditions in the gas market over the next two years. Even if financing associated with cash advances is factored in, the net present value associated with those long-term purchase 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.

For further information about this topic and risks associated with those obligations, see "Item 3 – Risk Factors" and "Item 5 – Outlook".

 

Marketing

Natural Gas Sales for the Year 2010

In 2010, worldwide natural gas sales were 97.06 BCM, down 6.66 BCM, or 6.4%, mainly due to unfavorable trends on the Italian market. Sales included Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and in the Gulf of Mexico.

Natural gas sales in Italy were 34.29 BCM (including own consumption and sales by affiliates) a decline of 5.75 BCM from 2009, or 14.4%, driven by increased competitive pressures and oversupply conditions on the marketplace, resulting in an estimated loss of ten percentage points in the Group market share in Italy. Particularly, lower sales were recorded in the power generation business (down 5.64 BCM), as clients opted to directly purchase gas on the marketplace. Lower sales to industrial customers (down 1.17 BCM) and wholesalers (down 1.08 BCM) were caused by increased competitive pressure fuelled by oversupply and weak demand. Sales on the Italian exchange for gas and spot market increased by 2.28 BCM, while sales volumes to the residential sector (6.39 BCM, up 0.09 BCM) were nearly unchanged. In addition, sales to importers in Italy were down by 2.04 BCM, or 19.5%, due to oversupply on the Italian market.

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 areas.

As of December 31, 2010, Eni’s customers in Italy totaled 6.88 million.

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Despite strong competitive pressures, sales on target markets in Europe showed a positive trend, increasing by approximately 1 BCM, or 2.5%, to 46.08 BCM. The main drivers behind the increase were organic growth achieved in France (up 1.18 BCM), Northern Europe (including the UK, up 0.91 BCM), Germany/Austria (up 0.31 BCM) and the Iberian Peninsula (up 0.30 BCM). Declines were recorded in Turkey (down 0.84 BCM), Belgium (down 0.80 BCM) and Hungary (down 0.22 BCM).

Sales to markets outside Europe (2.60 BCM) increased by 0.54 BCM, or 26.2%, from 2009.

E&P sales in Europe and in the USA (5.65 BCM) declined by 0.52 BCM.

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

Natural gas sales by entities		2008		2009		2010

(BCM)

Total sales of subsidiaries		89.32		89.60		82.00
Italy (including own consumption)		52.82		40.04		34.23
Rest of Europe		35.61		48.65		46.74
Outside Europe		0.89		0.91		1.03
Total sales of Eni’s affiliates (Eni’s share)		8.91		7.95		9.41
Italy		0.05		-		0.06
Rest of Europe		7.42		6.80		7.78
Outside Europe		1.44		1.15		1.57
Total sales of G&P		98.23		97.55		91.41
E&P in Europe and in the Gulf of Mexico (a)		6.00		6.17		5.65
Worldwide gas sales		104.23		103.72		97.06

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(a)

E&P sales include volumes marketed by the Exploration & Production Division in Europe (3.36, 2.57 and 2.33 BCM in 2008, 2009 and 2010, respectively) and in the Gulf of Mexico (2.64, 3.60 and 3.32 BCM in 2008, 2009 and 2010, respectively).

 

Natural gas sales by market		2008		2009		2010

(BCM)

ITALY		52.87		40.04		34.29
Wholesalers		7.52		5.92		4.84
Gas release		3.28		1.30		0.68
Italian gas exchange and spot markets		1.89		2.37		4.65
Industries		9.59		7.58		6.41
Medium-sized enterprises and services		1.05		1.08		1.09
Power generation		17.69		9.68		4.04
Residential		6.22		6.30		6.39
Own consumption		5.63		5.81		6.19
INTERNATIONAL SALES		51.36		63.68		62.77
Rest of Europe		43.03		55.45		54.52
Importers in Italy		11.25		10.48		8.44
European markets		31.78		44.97		46.08
Iberian Peninsula		7.44		6.81		7.11
Germany - Austria		5.29		5.36		5.67
Belgium		4.57		14.86		14.06
Hungary		2.82		2.58		2.36
Northern Europe		3.21		4.31		5.22
Turkey		4.93		4.79		3.95
France		2.66		4.91		6.09
Other		0.86		1.35		1.62
Extra European markets		2.33		2.06		2.60
E&P in Europe and in the Gulf of Mexico		6.00		6.17		5.65
WORLDWIDE GAS SALES		104.23		103.72		97.06

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Marketing of Electricity

As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, at industrial sites and on the Italian Exchange for electricity. Supplies of electricity include both own production volumes through gas-fired, combined-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 2010, the program for expanding the combined integrated offer of gas and power progressed in accordance with the Company’s expansion plans.

In 2010, electricity sales increased by 16.4% to 39.54 TWh, driven by a slight recovery in electricity demand and growth in the client base, in particular the retail market following intensive marketing campaigns, and mainly related to higher sales on open-markets (up 2.74 TWh) benefiting from higher trading and higher volumes traded on the Italian power exchange (up 2.43 TWh).

In 2010, electricity sales (39.54 TWh) were directed to the free market (70%), the Italian power exchange (18%), industrial sites (8%) and others (4%).

Power availability		2008		2009		2010

(TWh)

Power generation sold		23.33		24.09		25.63
Trading of electricity (a)		6.60		9.87		13.91
		29.93		33.96		39.54
Power sales by market
Free market		22.89		24.74		27.48
Italian Exchange for electricity		3.82		4.70		7.13
Industrial plants		2.71		2.92		3.21
Other (a)		0.51		1.60		1.72
		29.93		33.96		39.54

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(a)

Include positive and negative imbalances.

 

Planned Actions and Sales Target

(i) Italy

Over the next four years, management plans to increase sales and regain market share in Italy by leveraging on the competitiveness of the Company’s cost position, and the quality of its offer, including the offer of pricing formulas and services that are designed to suit the customers’ needs. The Company intends to deploy tailored solutions and customized contracts to retain clients in the business segment, and expand its customer base in the retail segment by means of new marketing initiatives, the bundling of a range of valuable services to commercial offer and wider geographic presence through an integrated network of agencies and stores. Based on those actions, management targets to expand sales volumes in Italy by 12 BCM within 2014 and to regain market share. In the last quarter of 2010, the adoption of a more volume-oriented approach led to an increase in Italian sales and market share by an estimated 7% and 1.5 percentage points, respectively, compared to a 38.3% market share and 9.8 BCM sales for the fourth quarter of the previous year.

 

(ii) European Markets

In Europe, the Company plans to increase sales volumes by 8 BCM by 2014 boosting direct sales in key European markets, particularly in France, Germany and Austria and maintaining its leadership position in the Benelux countries. To achieve these targets, management plans to leverage on the competitiveness of the Company’s cost position and new customized commercial offers, a multi-country approach and an integrated pan-European commercial platform.

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

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Benelux. Eni’s holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by the integration with Distrigas’ operations and its significant exposure to spot markets in Western Europe. In 2010, Distrigas sales were mainly directed to industrial companies, wholesalers and power generation and amounted to 14.87 BCM from 2009, down 0.85 BCM, or 5.4%, due to rising competition. The Company plans to maintain steady sales in this region over the plan period.

France. Eni sells natural gas to industrial clients, wholesalers and power generation as well as to the segments of retail and middle market. Eni is present in the French market through its direct commercial activities and through its subsidiary Altergaz, in which the Company acquired a controlling interest by increasing its share to 55.2% in December 2010. Altergaz supplies approximately 119,800 clients, of which 104,000 are residential customers (69,000 in 2009, of which 58,000 residentials). Furthermore, Eni holds a 34% interest in Gaz de Bordeaux SAS (with a 17% direct interest and a further 17% held by Altergaz) which is engaged in selling natural gas in the Municipality of Bordeaux. Eni plans to develop this partnership. Management plans to expand sales in France over the plan period growing volumes supplied to the business segments and increasing retail customers leveraging on the Altergaz integration. In 2010, sales in France amounted to 6.09 BCM (4.91 BCM in 2009), an increase of 1.18 BCM, or 24%, from a year ago.

Germany-Austria. Eni is present in the German natural gas market through its associate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 3.92 BCM in 2010 (1.96 BCM being Eni’s share), and through a direct marketing structure which sold in 2010 approximately 2.85 BCM in Germany and 1.09 BCM in Austria. Management plans to drive growth in direct sales leveraging on the quality of its commercial offer. In 2010, sales in Germany-Austria market amounted to 5.67 BCM, an increase of 0.31 BCM, or 5.8%, from a year ago.

Iberian Peninsula

Portugal. Eni operates on the Portuguese market through its affiliate Galp Energia (Eni’s interest 33.34%) which sold approximately 5.10 BCM in 2010 (1.70 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 2010, UFG gas sales in Europe amounted to 5.28 BCM (2.64 BCM Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) re-gasification plants (42.5% and 18.9%, respectively). In 2010, Eni sales in Spain amounted to 5.41 BCM representing a slight increase from a year ago. In 2010, total sales in the Iberian Peninsula amounted to 7.11 BCM, an increase of 0.30 BCM, or 4.4%, from a year ago.

Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2010, sales amounted to 3.95 BCM, a decrease of 0.84 BCM, or 17.5% 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). In 2010, sales amounted to 5.22 BCM, an increase of 21.1% from a year ago.

Deborah Gas Storage Project in the Hewett area, UK. Eni has progressed in developing the Gas Storage Project on the Deborah field within the Hewett area located in the Southern Gas Basin in the North Sea, near the Bacton terminal, UK. The Deborah Gas Storage Project is designed to provide the UK and North Western Europe markets with 4.6 BCM of working gas. Eni, the single owner of the project, completed the Front End Engineering Design ("FEED") after an appraisal well had been successfully drilled, and obtained most of the permits requested to sanction the project from the relevant national and local authorities. At the end of 2010, a Capacity Allocation Process aiming at selling long-term storage capacity was launched. A number of market players participated to the process and Eni Hewett, the Eni affiliate managing the project, ensured long-term contractual commitments to sell more than 20% of the capacity. Some of the participants to the capacity allocation process show interest in getting a participation in the investment as well. Based on that, Eni Hewett is currently managing a process to sell equity participation in the Deborah Gas Storage project and is progressing in bilateral discussions to sell further gas storage capacity. FID is expected to be taken by end of 2011/beginning 2012 based on the outcome of the equity sale process and discussions on capacity sales.

 

The LNG Business

Eni is present in all phases of the LNG business: liquefaction, shipping, re-gasification and sale through operated activities or interests in joint ventures and associates. Eni’s presence in the business is tied to the Company’s plans to develop its large gas reserve base in Africa and elsewhere in the world. The LNG business has been deeply impacted by the economic downturn of 2009 and structural modifications in the U.S. market where

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large availability of gas from unconventional sources have reduced the country’s dependence on gas imports via LNG.

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

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

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

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

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

USA

Cameron. The Cameron LNG terminal is situated 18 miles from the Gulf of Mexico along the Calcasieu Channel in Hackberry, Louisiana. The facility where Eni owns a capacity entitlement to treat LNG commenced operations in the third quarter of 2009. In consideration of a changed demand outlook for gas in the USA, on March 1, 2010, Eni renegotiated certain terms of the contract with the U.S. company Cameron LNG, owner of the facility, to farm out a share of the re-gasification capacity of the terminal. The new agreement provides that Eni is entitled to a daily send-out of 572,000 mmbtu (approximately 5.7 BCM/y) and a dedicated storage capacity of 160 KCM, giving Eni more flexibility in managing seasonal swings in gas demand. Furthermore, on March 3, 2011 Eni USA Gas Marketing Llc obtained from the American Department of Energy the authorization to export the LNG previously imported in the USA. This authorization will enhance operation flexibility, and will enable the company to exploit price differentials between American and European gas markets. Start-up of the Brass project (West Africa) to develop and liquefy gas reserves to fuel the Cameron plant is expected in 2016.

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

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

LNG sales		2008		2009		2010

(BCM)

G&P sales		8.4		9.8		11.2
Italy		0.3		0.1		0.2
Rest of Europe		7.0		8.9		9.8
Extra European markets		1.1		0.8		1.2
E&P sales		3.6		3.1		3.8
Liquefaction plants:
- Bontang (Indonesia)		0.7		0.8		0.7
- Point Fortin (Trinidad and Tobago)		0.5		0.5		0.6
- Bonny (Nigeria)		2.0		1.4		2.2
- Darwin (Australia)		0.4		0.4		0.3
		12.0		12.9		15.0

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Power Generation

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and in Bolgiano.

In 2010, power generation was 25.63 TWh, up 1.54 TWh, or 6.4% from 2009, mainly due to higher production in particular at the Brindisi and Livorno plant.

As of December 31, 2010, installed operational capacity was 5.3 GW (5.3 GW in 2009).

Power availability in 2010 was supported by the growth in electricity trading activity (up 4.04 TWh, or 40.9%) due to higher volumes traded on the Italian power exchange benefiting from lower purchase prices.

By 2014, Eni intends to complete its plan for expanding its power generation capacity, targeting an installed operational capacity of 5.7 GW⁶.

At full capacity in 2014, production is expected to amount to approximately 29.2 TWh, corresponding to approximately 7.9% 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 largest power producer in Italy.

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

The power generation development plan is underway and mainly refers to: (i) the revamping at the recently acquired Bolgiano plant (Eni 100%); (ii) the upgrading at Taranto plant (Eni 100%); and (iii) the construction of a new bio-mass power generation plant at Eni’s Porto Torres industrial site which is currently under remediation.

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 requires importers and producers of power from non renewable sources to input into the national power system a share of power produced from renewable sources set at 2% of power imported or produced from non renewable sources exceeding 100 GWh. Calculations are made on total amounts net of cogeneration 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 provides 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 for the Environment, has defined a 0.75% increase of this ratio for the periods from 2007 to 2010.

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.

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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		2008		2009		2010

Purchases
Natural gas		(mmCM)		4,530		4,790		5,154
Other fuels		(ktoe)		560		569		547
- of which steam cracking				131		82		103
Production
Electricity		(TWh)		23.33		24.09		25.63
Steam		(ktonnes)		10,584		10,048		10,983
Installed generation capacity		(GW)		4.9		5.3		5.3

 

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 lines which form the national transport network, gas underground storage deposits and related facilities, a re-gasification plant in Panigaglia and can rely on an extended system of local distribution networks. Eni is currently 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		105.0		75		7
Tarvisio-Sergnano-Minerbio		3		433		42/36, 34 e 48/56		119.2		58/75		3
Passo Gries-Mortara		1/2		177		48/34		64.8		55/75		1

i

i

i

i

i

i

i

i

i

i

i

i

i

Lines

Total length

Diameter

Transport capacity (2)

Transit capacity (3)

Compression stations

OUTSIDE ITALY

(units)

(km)

(inch)

(BCM/y)

(BCM/y)

(No.)

TENP (Bocholtz-Wallbach)		2 lines of km 500		1,000		36/38/40		22.9		15.5		4
Transitgas (Rodersdorf-Lostorf)		3 lines of km 165, 71 and 55		291		36/48		24.9		19.9		1
TAG (Baumgarten-Tarvisio)		3 lines of km 380		1,140		36/38/40/42		45.2		37.4		5
TTPC (Oued Saf Saf-Cap Bon)		2 lines of km 370		740		48		34.0		33.2		5
TMPC (Cap Bon-Mazara del Vallo)		5 lines of km 155		775		20/26		33.2		33.2
GreenStream (Mellitah-Gela)		1 line of km 520		520		32		8.0		8.0		1
Blue Stream (Beregovaya-Samsun)		2 lines of km 387		774		24		16.0		16.0		1

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(1)	i	Transport capacity refers to the capacity at the entry point connected to the import pipelines.
(2)	i	Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.
(3)	i	The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.

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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 invests in certain entities which own and operate those international pipelines, the pipeline owners, as well as in the entities which manage transportation rights, the carrier companies. For financial reporting purposes, such entities are either fully-consolidated or equity-accounted depending on the Company’s interest or agreements with other shareholders.

The structure of the Company’s interests in those entities may significantly change in the near future due to ongoing procedures for divesting Eni’s interests in the German TENP, the Swiss Transitgas and the Austrian TAG gas transport pipelines. The divestment is part of the commitments agreed upon by Eni and the European Commission to settle an antitrust proceeding related to alleged anti-competitive behavior in the natural gas market. In light of the strategic importance of the Austrian TAG pipeline to the supply of the Italian system, which transports gas from Russia to Italy, Eni negotiated a solution with the Commission which called for the transfer of its stake to an entity controlled by the Italian State. The Company expects to complete the divestment procedures within 2011. The prospected divestments will not affect Eni’s contractual gas transport rights.

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

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.

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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.

The South Stream pipeline will provide transport capacity of 63 BCM/y and is expected to be composed by two sections: (i) an offshore section crossing the Black Sea from the Russian coast at 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.

On June 18, 2010, Eni and Gazprom signed a Memorandum of Understanding to define terms and conditions for the French company EDF entering the South Stream project. As part of the agreement, EDF is expected to acquire an interest in the venture that is planning to build a new infrastructure to transport Russian gas across the Black Sea and Bulgaria to European markets.

Discussions among Eni, Gazprom and EdF in order to implement the latter’s accessions to the offshore section of the Project are ongoing.

 

Regulated businesses in Italy

Over the medium-term, management intends to sustain the Company’s strategies by a selective capital expenditure plan focused in particular on the regulated businesses in Italy with guaranteed returns. Specifically, in the next four-year period Eni plans to invest approximately euro 7.5 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) developing storage capacity by 4 BCM, according to government guidelines provided by Legislative Decree No. 130/2010 (for further information see below "Regulation of Eni’s Businesses – Gas & Power"), both through the development of new fields and the expansion of existing capacity; and (iii) upgrading and developing local distribution networks.

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.

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, the storage regulated capacity, also in accordance with the requirements of Legislative Decree No. 130/2010, 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 gas metering.

Eni, through Snam Rete Gas, operates the re-gasification terminal operating in Italy at Panigaglia (Liguria). At full capacity, this terminal can re-gasify 17,500 CM of LNG per day and input 3.5 BCM/y into the Italian transport network.

 

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 31,600 kilometers and comprises: (i) a national transport network extending over 8,894 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 22,786 kilometers, made up of smaller lines and allowing the transport of natural gas to large industrial complexes, power stations and local distribution

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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 diameters, 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 upgrades with the laying of a third line with a 48-inch diameter 583-kilometer long (of these 525 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 105 mmCM/d;
•		for natural gas imported from Libya (Gela delivery point):
		-		a 36-inch diameter 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 35 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 119 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:

		-		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 diameter 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 860 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 22 linkage and dispatching nodes and by 568 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 2010, volumes of natural gas input in the national grid (83.32 BCM) increasing by 6.42 BCM from 2009 due to higher gas deliveries due to a demand recovery. Eni transported 47.87 BCM of natural gas on behalf of third parties, up 10.55 BCM from 2009, or 28.3%.

Gas volumes transported (a)		2008		2009		2010

(BCM)

Eni		51.80		39.58		35.45
On behalf of third parties		33.84		37.32		47.87
		85.64		76.90		83.32

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(a)

Includes amounts destined to domestic storage.

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Transport capacity in Italy

		2009-2010 Thermal year		2010-2011 Thermal year

Entry points

Available capacity

Awarded capacity

Saturation

Available capacity

Awarded capacity

Saturation

(mmCM/d)

(mmCM/d)

(%)

(mmCM/d)

(mmCM/d)

(%)

Tarvisio		119.7		102.8		85.9		119.2		110.3		92.5
Mazara del Vallo		103.6		98.7		95.3		105.0		98.9		94.2
Passo Gries		64.9		59.0		90.9		64.8		55.0		84.9
Gela		33.0		32.9		99.7		35.2		34.3		97.4
Cavarzere (LNG)		26.4		21.0		79.5		26.4		24.6		93.2
Panigaglia (LNG)		13.0		7.2		55.4		13.0		7.2		55.4
Gorizia		4.8						4.8		0.5		10.4
		365.4		321.6		88.0		368.4		330.8		89.8

In 2010, the LNG terminal in Panigaglia (La Spezia) re-gasified 1.98 BCM of natural gas (1.32 BCM in 2009).

 

Distribution Activity

Distribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. The Company’s subsidiary Italgas and other subsidiaries operate in the distribution activity in Italy serving 1,330 municipalities through a low pressure network consisting of approximately 50,300 kilometers of pipelines supplying 5.8 million customers and distributing 8.15 BCM in 2010.

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 low risk and a steady cash generation profile.

Distribution activities are conducted under concession agreements whereby local public administrations award the service of gas distribution to companies. According to Legislative Decree No. 164/2000, the award of the service has to take place by a competitive bid process 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		2008		2009		2010

Volumes distributed:		(BCM)		7.63		7.73		8.15
- on behalf to Eni				6.33		6.26		6.30
- on behalf to third parties				1.30		1.47		1.85
Installed network		(km)		49,410		49,973		50,307
Active meters		(No. of users)		5,676,105		5,770,672		5,848,478
Municipalities served		(No.)		1,320		1,322		1,330

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

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 9.2 BCM.

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

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Storage		2008		2009		2010

Total storage capacity:		(BCM)		13.7		13.9		14.2
- of which strategic storage				5.1		5.0		5.0
- of which available storage				8.6		8.9		9.2
Available capacity:		(%)
- share utilized by Eni				39		30		29
- share utilized by third parties				61		70		71
Total offtake from (input to) storage:		(BCM)		11.57		16.52		15.59
- input to storage				6.30		7.81		8.00
- offtake from storage				5.27		8.71		7.59
Total customers		(No.)		48		56		60

In 2010, 8 BCM of gas were inputted to Company’s storage deposits (an increase of 0.19 BCM from 2009) while 7.59 BCM were supplied (down 1.12 BCM compared to 2009).

In 2010, storage capacity amounted to 14.2 BCM, of which 5 were destined to strategic storage.

The share of storage capacity used by third parties was 71% (70% in 2009).

 

Capital Expenditures

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

 

Refining & Marketing

Eni’s Refining & Marketing segment engages in the supply of crude oil, refining and marketing of refined products, trading and shipping of crude oil and product 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 2010, the refining business was hit by a weak trading environment due to higher costs of oil-based feedstock that was not followed by a corresponding increase in product prices, pressured by weak demand, high inventories and excess refining capacity. In addition, the increased oil price triggered higher costs of energy utilities, which are typically indexed to it. However, those negative trends were more than offset by cost efficiencies, supply optimization, lower impairment and amortization charges and stable marketing results enabling the Company to achieve a significant improvement from the year-earlier results.

In the medium-term, management expects the trading environment in Europe to show limited improvements as demand for refined products will stagnate and excess capacity and high worldwide and regional inventory levels and product imbalances will persist on the marketplace. Although an overall reduction in refining capacity is expected. Management also warns against risks of further oil price increases.

To face expected negative trends in the refining scenario, Eni intends to focus on:

In marketing, management plans to improve results by leveraging on better services to customers at Eni’s network of service stations, growing its market share in selective European markets and expanding the contribution to results from non-oil activities.

In the 2011-2014 period, we plan to make capital expenditures amounting to euro 2.9 billion, in line with the previous plan, carefully selecting capital projects. Management plans to invest approximately euro 2 billion to upgrade the Company’s best refineries mainly by completing and starting-up the EST (Eni Slurry Technology)

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project at the Sannazzaro unit which will upgrade the conversion capacity of the refinery. In marketing, the Company intends to invest in retail network upgrading and rebranding and for developing non-oil activities.

As a result of all these actions, management believes that the Refining & Marketing segment will break-even in 2011 and then continue to improve profitability and cash generation, under the assumption that there will no improvement in the trading environment compared to 2010.

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 2010, a total of 68.25 mmtonnes of crude were purchased by the Refining & Marketing Division (67.40 mmtonnes in 2009), of which 30.14 mmtonnes from Eni’s Exploration & Production Division. Volumes amounting to 20.95 mmtonnes were purchased on the spot market, while 17.16 mmtonnes were purchased under long-term supply contracts with producing countries. Approximately 25% of crude purchased in 2010 came from Russia, 22% from West Africa, 12% from the North Sea, 12% from the Middle East, 11% from North Africa, 5% from Italy, and 13% from other areas.

In 2010, some 36.17 mmtonnes of crude purchased were marketed (up of approximately 60 ktonnes, or 0.2%, from 2009). In addition, 3.05 mmtonnes of intermediate products were purchased (2.92 mmtonnes in 2009) to be used as feedstock in conversion plants and 15.28 mmtonnes of refined products (13.98 mmtonnes in 2009) were purchased to be sold on markets outside Italy (10.72 mmtonnes) and on the domestic market (4.56 mmtonnes) as a complement to available production.

 

Refining

Against the backdrop of a weak outlook for refining margins, in the medium-term, management plans to improve profitability of the Company’s refining operations by focusing on operational efficiency through energy saving, streamlining logistics and fixed cost reductions. Integration actions of Eni’s refining system are expected to mainly target Gela and Taranto refineries enabling the Company to cut production of low value fuel oil and reduce supply costs. Management also intends to tightly control capital expenditure and selectively upgrade conversion capacity and flexibility of the best refineries.

As of December 31, 2010, Eni’s refining system had total refinery capacity (balanced with conversion capacity) of approximately 37.8 mmtonnes (equal to 757 KBBL/d) and a conversion index of 61%. 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 28.2 mmtonnes (equal to 564 KBBL/d), with a 65% conversion rate.

In 2010, refinery throughputs in Italy and outside Italy were 34.80 mmtonnes.

The Company plans to selectively upgrade its refining system by increasing complexity and flexibility at its best refineries. The main capital project will be the completion of a new conversion unit at the Sannazzaro refinery designed on the EST proprietary technology for converting the heavy barrel by almost eliminating residue from conversion processes. The start-up of this facility is confirmed to be 2012. Higher conversion capacity is expected to enable the Company to extract value from equity crude as well as capture opportunities of monetizing heavy crudes and non-conventional resources. Other projects will involve the enhancement of logistic infrastructures at the Taranto unit.

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The table below sets forth certain statistics regarding Eni’s refineries as of December 31, 2010.

Refining system in 2010

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		564		65		69		41		37		29		89		46		70		91
Italy
Sannazzaro		100		223		223		180		61		34		11				29		29				77		95
Gela		100		129		129		100		142		35				37						46		69		89
Taranto		100		120		120		120		72				30						38				78		78
Livorno		100		106		106		84		11														87		110
Porto Marghera		100		107		107		80		20										22				64		85
Partially owned refineries (3)				874		245		193		50		163		25				99		27				83		109
Italy
Milazzo		50		248		124		80		73		41		25				32						74		109
Germany
Vohburg/Neustadt (Bayernoil)		20		215		43		41		36		49						43						94		98
Schwedt		8.33		231		19		19		42		49								27				96		99
Czech Republic
Kralupy e Litvinov		32.4		180		59		53		30		24						24						79		87
Total refineries				1,559		930		757		61		232		66		37		128		116		46		73		93

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

 

Italy

Eni’s refining system in Italy is composed of five wholly owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Eni’s refineries in Italy have 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%. Management believes that this unit is among 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 and conversion capacity of this refinery allows it to process a wide range of feedstock. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genoa terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulfurization units. Conversion is obtained through a fluid catalytic cracker (FCC), two hydrocrackers (HdCK), with the last unit entered into operations in June 2009, which enable middle distillate conversion and a visbreaking thermal conversion unit with a gasification facility using the heavy residue from visbreaking (tar) to produce syn-gas to feed the nearby EniPower power plant at Ferrera Erbognone. Eni is developing 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 120 KBBL/d and a conversion index of 72%. This refinery can process a wide range of crude and other feedstock. It principally 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 desulfurization 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 2010 a total of 1.8 mmtonnes of this oil were processed). A new hydro-cracking unit with a capacity of 17 KBBL/d started production in 2010 expanding the conversion capacity of the refinery.

The Gela refinery has 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

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refinery is underway by means of an upgrade of its power plant, mainly through the revamping of its boilers, aimed at increasing profitability by exploiting the synergies deriving from the integration of refining and power generation.

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

The Porto Marghera refinery, with 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.

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, through its 33.34% interest in Galp, Eni participates 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 production.

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

Availability of refined products		2008		2009		2010

(mmtonnes)

ITALY
Refinery throughputs
At wholly-owned refineries		25.59			24.02			25.70
Less input on account of third parties		(1.37	)		(0.49	)		(0.50	)
At affiliates refineries		6.17			5,87			4.36
Refinery throughputs on own account		30.39			29,40			29.56
Consumption and losses		(1.61	)		(1.60	)		(1.69	)
Products available for sale		28.78			27.80			27.87
Purchases of refined products and change in inventories		2.56			3,73			4.24
Products transferred to operations outside Italy		(1.00	)		(0.96	)		(0.92	)
Consumption for power generation		(1.13	)		(1.00	)		(0.96	)
Sales of products		28.92			26.68			27.01
OUTSIDE ITALY
Refinery throughputs on own account		5.45			5.15			5.24
Consumption and losses		(0.25	)		(0.25	)		(0.24	)
Products available for sale		5.20			4.90			5.00
Purchases of finished products and change in inventories		15.14			10.12			10.61
Products transferred from Italian operations		1.42			3.89			4.18
Sales of products		21.76			18.91			19.79
Refinery throughputs on own account		35.84			34,55			34.80
of which: refinery throughputs of equity crude on own account		6.98			5,11			5.02
Total sales of refined products		50.68			45.59			46.80
Crude oil sales		26.00			36,11			36.17
TOTAL SALES		76.68			81.70			82.97

In 2010, refining throughputs were 34.80 mmtonnes, up 0.7% from 2009.

Volumes processed in Italy increased by approximately 160 ktonnes, or 0.5%, from 2009 mainly due to a better performance at the Livorno, Gela and Taranto plants as the trading environment improved from a year ago and

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optimization of refining cycles was implemented. In addition, higher volumes were processed due to the coming on stream of a new hydro-cracking unit in Taranto and lower planned standstills affected the partially-owned Milazzo refinery. These effects were partly offset by the termination of a process contract on the Saras third-party refinery (down 1,966 ktonnes). Eni’s refining throughputs outside Italy increased by 1.7% supported by higher refinery throughput in the Czech Republic as a consequence of increased margins and demand recovery.

Total throughputs in wholly-owned refineries were 25.70 mmtonnes, up by approximately 1.68 mmtonnes (or 7%) from 2009, reflecting an improved refinery utilization rate which reached 91%. This increase reflects feedstock integration in refinery cycles and improved throughput margins, in particular for lubricants.

Approximately 15.8% of volumes of processed crude was supplied by Eni’s Exploration & Production segment (16.3% in 2009) representing a 0.5 percentage point decrease from 2009, corresponding to a lower volume of approximately 90 ktonnes.

 

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) by sea through spot and long-term lease contracts of tanker ships; and (ii) on land through the ownership of a pipeline network extending approximately 1,447 kilometer-long. 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		2008		2009		2010

(mmtonnes)

Italy
Retail		8.81		9.03		8.63
Wholesale		11.15		9.56		9.45
		19.96		18.59		18.08
Petrochemicals		1.70		1.33		1.72
Other sales		7.26		6.76		7.21
Total		28.92		26.68		27.01
Outside Italy
Retail		3.22		2.99		3.10
Wholesale		4.50		4.07		4.30
		7.72		7.06		7.40
Other sales		12.52		11.85		12.39
Total		20.24		18.91		19.79
Iberian Peninsula (a)		1.52
of which:
Retail		0.64
Wholesale		0.88
TOTAL SALES		50.68		45.59		46.80

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(a)

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

In 2010, sales volumes of refined products (46.80 mmtonnes) were up of 1.21 mmtonnes from 2009, or 2.7%, mainly due to higher volumes sold to oil companies and traders in Italy and outside Italy.

 

Retail Sales in Italy

The re-branding of Eni’s service stations and the upgrading of Eni’s retail network progressed in 2010. In 2010, 463 service stations in Italy were re-branded to the "eni" brand, corresponding to approximately 10% of the retail network, with priority awarded to high throughput service stations with non-oil activities.

In marketing operations, Eni plans to strengthen its competitive positioning in Italy and to expand sales of fuels and non-oil products as well as expanding its share in the domestic retail market for fuels by 2014, up from 30.4% in 2010. To achieve those results, management intends to upgrade the network of service stations by starting-up new outlets with high service standards, improve the quality and range of services offered to the Company’s customers in order to boost customer retention, enhancing the offer of premium products, and develop non-oil activities under the "eni" brand.

A strong focus will be devoted to pursue high levels of operating efficiency.

In 2010, retail sales in Italy of 8.63 mmtonnes decreased by approximately 400 ktonnes, down 4.4% driven by lower demand which mainly impacted gasoline and, to a lesser extent gasoil, reflecting a decline in domestic fuel demand, as well as rising competitive pressure and price elasticity. Average throughput related to gasoline and gasoil (2,322 kliters) decreased by approximately 160 kliters from 2009. Eni’s retail market share for 2010 was 30.4%, down 1.1 percentage point from 2009 (31.5%).

At December 31, 2010, Eni’s retail network in Italy consisted of 4,542 service stations, 68 more than at December 31, 2009 (4,474 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (74 units), the opening of new service stations (11 units), partly offset by the closing of service stations with low throughput (13 units) and the release of 4 service stations under highway concession.

In 2010, also fuel sales of the Blu line – fuels with high performance and low environmental impact – recorded lower sales from 2009, reflecting weak domestic consumption. In particular, sales of BluDieselTech declined slightly down from 2009, approximately amounting to 573 ktonnes (689 mmliters), and represented 10.3% of gasoil sales on Eni’s retail network. At December 31, 2010, service stations marketing BluDieselTech totaled 4,071 units (4,104 at 2009 year end) covering approximately 90% of Eni’s network.

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Retail sales of BluSuper amounted to 70 ktonnes (approximately 94 mmliters), decreasing by approximately 12 ktonnes from 2009, and covered 2.6% of gasoline sales on Eni’s retail network (down 0.1% from a year ago). At December 31, 2010, service stations marketing BluSuper totaled 2,672 units (2,679 at December 31, 2009), covering approximately 59% of Eni’s network.

In February 2010, in replacement of the previous promotional campaign "You&Agip", Eni launched the new "you&eni" loyalty points program, which will last 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, 2010, the number of customers that actively used the card in the year amounted to approximately 5 million. The average number of cards active each month was approximately 2.8 million. Volumes of fuel marketed under this initiative represented approximately 40% of overall volumes marketed on Eni’s network.

In 2010, 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 sales against the backdrop of a weak demand and increased price elasticity.

 

Retail Sales in the Rest of Europe

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

In 2010, retail sales of refined products marketed in the rest of Europe (3.10 mmtonnes) were up 3.7% from 2009. The increase was driven by volume additions in Austria, reflecting the purchase of service stations, and by enhanced performance in Eastern Europe (particularly in Slovakia and Romania), as well as in Germany and France.

At December 31, 2010, Eni’s retail network in the rest of Europe consisted of 1,625 units, an increase of 113 units from December 31, 2009 (1,512 service stations). The network evolution was as follows: (i) positive balance of acquisitions/releases of lease concessions (19 units) with positive changes in Austria and Hungary; (ii) purchased 114 service stations; (iii) opened 5 new outlets; and (iv) 25 low throughput service stations were closed. Average throughput (2,441 kliters) slightly decreased from 2009 (2,461 kliters).

The key markets of Eni’s presence are: Austria with a 7% market share, Hungary with 11.9%, Czech Republic with 11.8%, Slovakia with 9.7%, Switzerland with 6.5% 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 1,146 service stations, of which 395 are in Germany and 173 in France, with a 71% 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.).

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 2010, sales volumes on wholesale markets in Italy (9.45 mmtonnes) were down by approximately 110 ktonnes from 2009, or 1.2%, mainly reflecting a decline in domestic consumption in particular of fuel oil by industrial customers. Eni’s wholesale market share for 2010 averaged 29.2%, up 1.6 percentage points from 2009 (27.6%).

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Sales on wholesale markets in the rest of Europe (3.88 mmtonnes) increased by approximately 220 ktonnes, or 6%, mainly in Austria, due to purchase of service stations, in France due to higher bitumen sales and in Germany, due to a large product availability and a recovery in consumption.

Supplies of feedstock to the petrochemical industry (1.72 mmtonnes) increased by approximately 390 ktonnes due to demand recovery.

Other sales (19.60 mmtonnes) increased by approximately 990 ktonnes, or 5.3%, mainly due to higher sales volumes to the cargo market and to oil companies.

Eni also markets jet fuel directly at 46 airports, of which 27 are in Italy. In 2010, 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 2010, marine fuel sales were 2.03 mmtonnes (1.97 mmtonnes in Italy).

 

LPG

In Italy, Eni is leader in LPG production, marketing and sale with 592 ktonnes sold for heating and automotive use equal to a 17.6% market share. An additional 217 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 2014.

 

Lubricants

Eni operates seven (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 2010, retail and wholesale sales in Italy amounted to 106 ktonnes with a 24.1% 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 120 ktonnes, of these about 60% were registered in Europe (mainly Spain, Germany, and France).

 

Oxygenates

Eni, through its subsidiary Ecofuel (Eni’s interest 100%), sells approximately 1.7 mmtonnes/y of oxygenates mainly ethers (approximately 6.5% of world demand) and methanol (approximately 1.1% of world demand). About 81% 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 19% 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.

Starting from March 1, 2010, Italian regulation on bio-fuels content has been changed from 3% to 3.5%. With the use of Bio-ETBE and FAME Eni covered the compliance within 98%. From January 1, 2011, the content increases to 4%. Eni expects to cover compliance in the same manner as in 2010.

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Capital Expenditures

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

 

Engineering & Construction

Eni engages in engineering, construction and drilling both offshore and onshore for the oil and gas industry through Saipem, a subsidiary listed on the Italian Stock Exchange (Eni’s interest is 43%), and Saipem’s controlled subsidiaries. Saipem boasts a strong competitive position in the market for services to the oil industry, particularly in executing large, complex EPC contracts for the construction of offshore and onshore facilities and systems to develop hydrocarbons reserves as well as LNG, refining and petrochemicals plants, pipeline layering and offshore and onshore drilling services. The Company owes its market position to technological and operational skills which we believe are acknowledged in the marketplace due to its capabilities to operate in frontier areas and complex ecosystems, efficiently and effectively managing large projects, engineering competencies and availability of technologically-advanced vessels and rigs which have been upgraded in recent years through a large capital expenditure plan. 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 efficiency in all business areas at the same time maintaining top execution and security standards, preserve competitive supply costs, optimize the utilization rate of the fleet, increase structure flexibility in order to mitigate the effects of negative business cycles as well as develop and promote a company culture that will permit identification and management of risks and business opportunities; (ii) to continue focusing on the more complex and difficult projects in the strategic segments of deepwater, FPSO, heavy crude and LNG (offshore and onshore, for the gas monetization) upgrading; (iii) to promote local content in terms of employment of local contractors and assets in strategic countries where large projects are carried out supporting the development of delocalized logistic hubs and construction yards when requested by clients in order to achieve a long-term consolidation of its market position in those countries; (iv) to leverage on the capacity to execute internally more phases of large projects on an EPC and EPIC basis, pursuing better control of costs and terms of execution adapting with flexibility to clients’ needs, thus expanding the Company’s value proposition; and (v) to complete the expansion and revamping program of its construction and drilling fleet in consideration of the future needs of the oil and gas industry, in order to confirm the Company’s leading position in the segment of complex projects with high profitability.

Saipem expects to invest approximately euro 2.4 billion over the next four years to complete the upgrading program of its fleet of vessels and rigs, further expanding the operational features, the dimension and the geographical reach and of its fleet as well as to support the activities related to the execution of projects in portfolio and the acquisition of new orders.

Orders acquired in 2010 amounted to euro 12,935 million, of these projects 94% are to be carried out outside Italy, while orders from Eni companies represented 7% of the total. Order backlog was euro 20,505 million as of December 31, 2010 (euro 18,730 million as of December 31, 2009). Projects to be carried out outside Italy represented 94% of the total order backlog, while orders from Eni companies amounted to 16% of the total.

		2008		2009		2010

Orders acquired		(euro million)		13,860		9,917		12,935
Offshore construction				4,381		5,089		4,600
Onshore construction				7,522		3,665		7,744
Offshore drilling				760		585		326
Onshore drilling				1,197		578		265
Originated by Eni companies		(%)		4		32		7
To be carried out outside Italy		(%)		94		79		94
Order backlog and breakdown by business		(euro million)		19,105		18,730		20,505
Offshore construction				4,682		5,430		5,544
Onshore construction				9,201		8,035		10,543
Offshore drilling				3,759		3,778		3,354
Onshore drilling				1,463		1,487		1,064
Originated by Eni companies		(%)		13		22		16
To be carried out outside Italy		(%)		98		93		94

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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 33 vessels and a large number of robotized vehicles able to perform advanced subsea operations. Its major vessels are: (i) the Saipem 7000 semisubmersible 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 pipelaying to a depth of 2,000 meters; (iii) the Castoro 6 semisubmersible 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 semisubmersible vessel used for large diameter underwater pipelaying. 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 order awarded in 2010 in offshore construction were: (i) the extension of Kashagan Trunklines contract on behalf of Agip KCO for the installation of the offshore facilities system relating to the experimental phase of the Kashagan field development program in Kazakhstan; (ii) the extension of Kashagan Piles and Flares contract on behalf of Agip KCO for the installation of the offshore facilities system relating to the experimental phase of the Kashagan field development program in Kazakhstan; (iii) an EPIC contract on behalf of Petrobras for the P55-SCR project, for risers and flowlines serving the semisubmersible platform P-55 to be installed in the Roncador field, offshore Brazil.

 

Onshore construction

In the onshore construction business, Saipem is one of the largest engineering and construction operators on turnkey contract base at a worldwide level in the oil and gas segment, especially through the acquisition of Snamprogetti. Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of 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 2010 in Onshore construction were: (i) the EPC contracts on behalf of Abu Dhabi Gas Development for the construction of a gas processing plant (with a treatment capacity of 1 BCF/d of gas), a sulfur recovery unit and the related transporting facilities as part of the Shah Gas development program in the United Arab Emirates; (ii) an EPC contract on behalf of Husky Oil for the realization of the Central Processing Facilities designed for a total of 60 KBBL/d of bitumen production for the first phase of the Sunrise Oil Sands project near Fort Murray, Alberta, Canada; and (iii) an EPC contract on behalf of Kharafi National for the construction of Early Production Facilities, which will have an oil and gas treatment capacity of 150 KBBL/d and a sulfur granulation plant, for the development of the Jurassic field located in Northern Kuwait.

 

Offshore drilling

Saipem is the only engineering and construction contractor that provides both offshore and onshore drilling services to oil companies. In the offshore drilling segment, Saipem mainly operates in West Africa, the North Sea,

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the Mediterranean Sea and the Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum depth of 9,200 meters. In order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-the-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments.

In particular, in the following years, Saipem intends to complete the building of: the Scarabeo 8 and 9, new generation semisubmersible platforms, that have been already rented to Eni through multi-year contracts. 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 15 vessels fully-equipped for its primary operations and some drilling plants installed on board of fixed offshore platforms. Its major vessels are: the Saipem 12000 and Saipem 10000, designed to explore and develop hydrocarbon reservoir operating in excess of 3,600 and 3,000 meters water depth, respectively in full dynamic positioning. In 2010 those vessels operated in West Africa and Far East. Other relevant vessels are Scarabeo 5 and 7, third and fourth generation semisubmersible rigs able to operate at depths of 1,900 and 1,500 meters of water, respectively. Average utilization of drilling vessels in 2010 stood at 100% (90% in 2009).

The most significant orders awarded in 2010 in Offshore drilling were: (i) a 15-month contract (plus additional options) for the use of the semisubmersible platform Scarabeo 3 in Congo and Nigeria on behalf of Addax Petroleum; (ii) a 36-month contract for the lease of the jack-up Perro Negro 5 in Saudi Arabia on behalf Saudi Aramco; and (iii) an extension until June 2013 for the lease of the semisubmersible platform Scarabeo 4 in Egypt on behalf of IEOC.

 

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 2010 stood at 94% (91% in 2009). The 86 rigs owned by Saipem at year end were located as follows: 28 in Venezuela, 19 in Peru, 8 in Saudi Arabia, 7 in Algeria, 6 in Colombia, 4 in Italy, 3 in Kazakhstan, 3 in Brazil, 3 in Ecuador, 2 in Ukraine, 2 in Congo and 1 Bolivia. Saipem also used rigs owned by third parties (6 in Peru and 2 in Kazakhstan) as well as rigs owned by the joint company Saipar.

The most significant orders awarded in 2010 in Onshore drilling were: (i) a contract on behalf on ExxonMobil Kazakhstan Inc. for the decommissioning and transportation of two rigs owned by the client already operated by Saipem. Saipem will also carry out conversion activities on one of the two rigs; (ii) a contract on behalf of Repexa in Peru for the lease of a rig with a contract duration of two years; and (iii) a contract on behalf of ConocoPhillips in Algeria for the lease of a rig with a contract duration of six months (plus an additional 18 months option).

 

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, cyclicality in demand, strong competitive pressures from operators with lower cost structure, 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

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prices adjust to higher oil prices. See "Item 3 – Risk Factors". In 2010, the Petrochemicals Division trimmed operating losses from 2009 by improving demand, better products margins and cost efficiencies. Management expects the outlook for 2011 will be shaping favorably to the Company as the world economy strengthens thus boosting worldwide demand for chemical commodities. However, risks will persist due to rising oil prices which could put pressure on unit margins of commodities. In light of this, management is planning for actions intended to strengthen the product mix of the Company by developing new products characterized by higher value added than the current portfolio, particularly in the businesses of elastomers, polyethylene and styrenics. Further measures will be dedicated to reduce operating costs and improve yields and plant efficiency in the production of basic ethylene which is the primary input for all downstream productions. To target those objectives, management plans to make capital expenditures amounting to euro 1 billion over the next four-year period which will be mainly directed to develop the product line in the elastomer and polyethylene businesses, plant upgrading and revamping at the Company’s cracking units as well as complying with all applicable regulations on environment, health and safety issues. In addition, the Company plans to develop an initiative to produce plastics from certain bio-components at the Porto Torres unit in Sardinia, Italy. Other initiatives will involve marketing activities with the aim of boosting margins by sales channels optimization, product portfolio rationalization, including elimination of unprofitable products, and revision of pricing policies. Also licensing activities will be pursued in order to expand contribution to results from licensing the Company’s technologies. Based on those planned actions, management expects to improve profitability and cash flow of the Company’s petrochemicals operations targeting to break-even in 2012 under the Company’s assumption relating trends in the prices of crude oil. See "Item 5 – Outlook".

In 2010, sales of petrochemical products (4,731 ktonnes) increased by 466 ktonnes (or 10.9%) from 2009 as a result of a recovery in demand from the depressed levels experienced a year-earlier.

Petrochemical production (7,220 ktonnes) increased by 699 ktonnes from 2009, or 10.7% in all business areas driven by the needs to ensure supplies to meet recovery in sales volumes in all Eni’s main plants. In addition, the year earlier the Company was forced to shut down production during the course of the year in order to avoid accumulating excess of finished products.

In 2010, nominal production capacity decreased by one percentage point from 2009 due to the closing of the styrene plant in Hythe. The average plant utilization rate, calculated on nominal capacity increased from 65.4% to 72.9% as a result of higher volumes produced, in particular in the Priolo, Brindisi and Porto Torres plants.

Average unit sale prices increased by 35.6% from the depressed levels registered in 2009. The most relevant increase was registered in the average price of olefins (up 48% on average) driven by higher costs for oil-based feedstock (the virgin naphtha prices increased by 41% from a year ago) as demands for basic chemicals increased at a fast pace and supplies were constrained. Average unit prices of styrene and polyethylene increased on average by 30%, while elastomers achieved lower increases.

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

	Year ended December 31,

		2008		2009		2010

(ktonnes)

Basic petrochemicals		5,110			4,350			4,860
Polymers		2,262			2,171			2,360
Total production		7,372			6,521			7,220
Consumption of monomers		(3,539	)		(2,701	)		(2,912	)
Purchases and change in inventories		851			445			423
		4,684			4,265			4,731

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

	Year ended December 31,

		2008		2009		2010

(euro million)

Basic petrochemicals		3,060		1,832		2,833
Polymers		2,961		2,185		3,126
Other revenues		282		186		182
Total revenues		6,303		4,203		6,141

 

Basic petrochemicals

Basic petrochemical revenues (euro 2,833 million) increased by euro 1,001 million (up 54.6%) from 2009 in all of the main business segments due to the steep increase in average unit prices (olefins up 48%; intermediates and aromatics up more than 30%) as a result of the pricing environment and higher volumes sold.

In particular, sales volumes of olefins increased by 17%, intermediates by 10%, while aromatics registered lower increases (up 8%) due to the decreases registered in xylene sales (down 5%).

Basic petrochemical production (4,860 ktonnes) increased by 510 ktonnes from 2009 (up 11.7%) due to the recovery in the demand for monomers.

 

Polymers

Polymer revenues (euro 3,126 million) increased by euro 941 million from 2009 (up 43.1%) as unit prices increased by 30% on average. Sales volumes increased on average by 8% (elastomers up 11%, styrene up 10%, polyethylene up 6%) due to positive trends in demand.

Polymers production (2,360 ktonnes) increased by 189 ktonnes from 2009 (up 8.7%) driven by a recovery in the main end-markets (automotive, construction and packaging).

Production volumes of elastomers and styrene increased on average by 10% from 2009 due to higher production of EPR, nytrilic rubbers, compact polystyrene and ABS. Polyethylene production registered a lower increase (up 7.7%) due to unplanned facility downtime at the Dunkerque plant.

 

Capital Expenditures

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

 

Corporate and Other activities

These activities include the following businesses:

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

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Seasonality

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

 

Research and Development

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

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

The reorganization of R&D structures that Eni started in 2006 was completed in 2010 with the help of some measures:

In 2010, Eni filed 88 patent applications (106 in 2009), 61 of these coming from Eni Divisions and Eni Corporate, 10 from Petrochemicals and 17 from the Engineering & Construction activities of Saipem. In particular, 8% of patents concerned refining processes, 49% were in the field of drilling and completion, geology/geophysics of fields and engineering, 8% concerned the environment and 35% concerned innovation on renewable energy sources. The efficacy and efficiency of intellectual property management and of know-how dissemination are monitored within the R&D performance assessment system. In 2010, a review of Eni’s patent portfolio was performed that ended with the decision to abandon obsolete and non profitable patents.

In 2010, Eni’s overall expenditure in R&D amounted to euro 221 million which were almost entirely expensed as incurred (euro 207 million in 2009 and euro 217 million in 2008).

At December 31, 2010, a total of 1,019 persons were employed in research and development activities (in line with 2009). Below, we describe the main results achieved in research and innovation for sustainability in 2010.

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In the next four-year period, Eni plans to spend euro 1.1 billion for technological research and innovation activities. Management believes that technological developments may ensure the Company a competitive advantages in the long-term.

A summary of the most relevant R&D results obtained during the year by each business segment and at a Corporation level is provided below.

 

Exploration & Production

Advanced exploration techniques
- Reverse Time Migration (RTM). Emerging technology for the processing of in depth seismic data aimed at reconstructing the image of highly complex underground areas. In 2010, the proprietary version has been successfully applied for the first time to an exploration project in Angola, allowing the identification of new oil bearing structures that were not visible with conventional tools.
- Basin simulation (e-simba^TM). This proprietary package contains about 20 integrated software items for assessing the amount and type of hydrocarbons potentially trapped. In 2010, some of the functions have been developed and applied in about 30 exploration projects in countries such as Venezuela, Ghana, Mozambique, Poland Australia, Angola and Congo, allowing a better probabilistic assessment of mineral potential.

Drilling and completion technologies
- Extended reach drilling. Proprietary technology and equipment (Eni continuous circulation device, e-cd^TM and aluminum rods) have been used to drill wells in China and Alaska. In China, costs were reduced by 50% as compared to earlier works.
- Innovative technologies to improve drilling safety. A portfolio of projects for increasing drilling safety reached an advanced stage with the in-field testing of special surface valves to be integrated in the proprietary equipment for an optimal drilling control (e-cd^TM). An innovative system for blow-out control within the well (downhole blow-out isolation packer) has also been tested. In 2010, Eni continued the development of the Dual ROV assisted top kill system that provides an efficient technique for blow-outs in deepwater wells. The system will be introduced in the sea in 2011.

Technologies for field characterization and increase in recovery rates
- Polymer enhanced water injection. The design phase has been completed for the implementation of the project of polymer enhanced water injection in a well in Egypt. The study results suggest an approximately 3% increase in the recovery factor.
- Bright Water Injection. This technology is based on an additive that is injected in the ground and selectively blocks the rock parts where water is present, thus potentially increasing the extraction of crude from mature fields. It has been applied in 2010 in two fields in North Africa with positive results and further applications in Congo are scheduled for 2011.
- Tar recovery from tar sands. A mixed water-solvent process for obtaining high recovery rates from tar sands (>90% in weight as compared to tar contained in sands) has been developed and applied to different types of sand. A concept design study has been completed for facilities in a pilot plant for the testing of in situ recovery techniques.
- EOR with acoustic stimulation. This process is based on sending sound waves into a field through a mechanical lifting system designed for this purpose. In 2010, field tests in Egypt were made in order to assess the potential of this well known but little tested technology in controlled conditions. Early results indicated a positive effect on oil production in the mature field where the test was made.

 

Refining & Marketing

Eni Slurry Technology (EST). The EST proprietary technology is an innovative process for hydro-conversion by means of a nanodispersed catalyst (slurry) and a peculiar process scheme to refine various kinds of heavy feedstock: residues from the distillation of heavy and extra-heavy crude (such as the ones from the Orinoco Belt in Venezuela) or non-conventional products such as tar sands, characterized by high contents of sulfur, nitrogen, metals, asphaltenes and other pollutants that are hard to manage in conventional refineries. EST does not produce by-products and completely converts feedstocks into distillates. In 2010, testing continued mainly directed to validating the technology from the point of view of the upgrading performance and plant management, and a customized basic on the Zuata crude was prepared. The first industrial plant with a 23 KBBL/d capacity is under construction at the Sannazzaro refinery, with start-up scheduled for 2012.

Hydrogen SCT-CPO (Short Contact Time - Catalytic Partial Oxidation). It is a reforming technology that can convert gaseous and liquid hydrocarbons (also derived from bio-mass) into synthetic gas (carbon monoxide and hydrogen). This technology can contribute to process intensification as it allows to produce synthetic gas and hydrogen using reactors up to 100 times smaller than those currently in use, with relevant savings. The development

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of this technology, that makes use of oxygen enriched air, has been completed and another version making use of pure oxygen is under development.

Nanomaterials. The use of structured nanomaterials is one of the key elements for innovation and intensification of processes. Projects are underway to study and enhance nanomaterials that could introduce radical improvements in conversion processes. The Dual Catalyst Slurry technology is based on nanocatalysts and its current tests could lead to breakthrough developments in EST, as it can increase productivity and quality of end products. The development of a bi-functional catalyst is underway that hydrogenates and desulphorates feesdtocks and increases the cracking rate and nitrogen removal. In the Flexible FCC (fluid catalytic cracking), new proprietary zeolite and zeolite-like materials have been developed for increasing the conversion of heavier fractions without increasing residues. This additive, associated to a new process scheme could change the gasoline/gasoil ratio in favor of the latter. In 2010, application testing continued and confirmed the results obtained so that scale up has started with the aim of finding the final formulation to be used in industrial reactors. This application is covered by a patent application.

 

Petrochemicals

Elastomers. A new grade of thermoplastic co-polymer has been industrially homologated to be used in adhesives with lower viscosity (remaining equal its adhesive/cohesive properties) leading to lower energy consumption in the formulation of the final adhesive. At a pilot scale, new hydrogenated styrene-butadiene co-polymers to be used as viscosity index improvers have been produced and are scheduled to be homologated by the reference customer. In the lab and pilot plant the advantage of using a new activator in the polymerization of terpolymers EPDM with vanadium based catalysts has been confirmed and provided higher yields, improved quality and lower consumption of chlorine in the production process.

Polyethylene. The production of two new grades of LLDPE (linear low density polyethylene) continued with wide distribution of molecular weight and therefore improved processability and retention of basic mechanic properties. In a gas phase plant a new grade of LLDPE for rotomolding application with exenes has been produced entailing a significant improvement of certain basic properties (such as resistance to chemicals). New formulas have been developed for HDPE (high density polyethylene) to be used in rotomolding applications in the field of phytochemicals.

Styrenic polymers. A new formula of ABS (acrylonitryl-butadiene-styrene polymer) grade from continuous mass has been developed for injection molding. This formula dramatically increases the mechanical properties of products adjusting their performance to products deriving from emulsions. This allows a relevant recovery in penetration into injection molding. After the first industrial campaign, customers expressed their satisfaction.

 

Engineering & Construction

Assets
Technological innovation on assets is pursued with the aim of improving sustainability, competition and reliability, and reducing the environmental impact of operations. In particular, in 2010 some of the projects underway reached the testing phase:

•		Equipment. New systems for the construction of coverage for soldering joints on board of pipelaying vessels, techniques for the remote control of anomalous deformations during the laying of pipes into the sea and some technologies complementary to excavation activities for critical operating scenarios have been validated. Studies were completed on technologies for the sustainability of construction of infrastructure in environmentally highly sensitive areas.
•		Vessels. Detailed development and implementation of the main technical systems and subsystems for production and laying of pipes on the new pipelaying vessel CastorOne continued.

Offshore
Activities were focused on programs dedicated to the continued improvement of innovative solutions for the development of oil and natural gas fields in the sea. Main activities concerned fields in frontier areas such as deep waters and the Arctic, monetization of offshore natural gas reserves by means of liquefaction technologies applied on floating plants (LNG offshore) and production from offshore renewable sources:

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Onshore
Activity is dedicated to process technologies and their know-how and to the application of the most modern and state-of-the-art technologies from third parties supporting our clients worldwide in the upstream, midstream and downstream areas in the various phases of completion from engineering to construction.

An overview of the main research projects developed during the year at the Corporate level is provided below.

 

Exploration & Production Division

Cube. To cope with events similar to that occurred at the Macondo well in the Gulf of Mexico and the failed attempt to collect the crude plume with a containing device, Eni prepared a device (in 1:4 proportion) for the collection and separation of gas from water and oil near the wellhead on the seabed and tested it in-house up to a flow of 10,000 BBL/d.

Development of reaction capacity to oil spills on the coast of the Barents Sea and sub-Arctic areas. The Norwegian project led by Eni achieved relevant results in 2010 in preparing an emergency plan for the Goliat field in the Barents Sea. Standards for testing disperdents and beach cleaners have been developed in order to use them in case of oil spills near the coast. These standards will be upheld by Norwegian law and later suggested at international level.

GHG program (Green House Gases). Activities are progressing part of the pilot project for injecting CO₂ in the Cortemaggiore gas storage site. Authorizations are pending to build and operate the plant.

Water management. This project promotes the application of innovative technologies for the treatment of reinjected waters. In 2010, the contract for the supply of a system for the removal of oil and solids from production waters in the Egyptian Desert has been awarded.

Organic Rankine Cycle (ORC) Technology for Energy Recovery. A feasibility study has been completed and the installation of Organic Fluid Cycle is underway in the gas powered Fano power station (3 MW) by recovering the thermal power dissipated by turbocompressors. This would represent the first application of the ORC technique to Eni’s Group.

Feeding pumps in desert areas with photovoltaic devices. A contract has been prepared and the engineering is underway for a the supply of photovoltaic systems to be applied onto diesel generators for feeding sucker rod pumps in desert areas in Egypt.

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Gas & Power Division

Transport of carbon dioxide by pipeline (TACC). This project is part of the program of long distance transport of gases under different pressures with the aim of developing standards, guidelines and recommendations for future applications in carbon capture and storage. In 2010, the technical part of the program was laid out as well as the participants in the joint industrial project. Eni will promote the creation of JIP action with other integrated gas companies, e.g. Gasunie and Statoil.

Monitoring of advanced gas transport systems (MAST and Dionisio project). Eni has developed proprietary technologies for the advanced monitoring of gas transport systems (pipelines and compression stations). In 2010, technologies have been successfully tested for the identification of structural defaults (MAST) that can generate criticalities in transport. The development of the Dionisio technology that is based on vibro-acoustic sensors for noticing intrusions and leaks along transport pipelines continued. A prototype monitoring system has been installed on the Chivasso-Aosta pipeline.

 

Refining & Marketing Division

Blu fuels and products. Eni has been working for years in R&D for advanced fuels and lubricants that aim at optimizing engine efficiency and reducing noxious emissions. In February 2010, the Lombardia Region and Eni signed an agreement for the distribution of "formula Milano" in 50 outlets. This is a type of BluDieselTech with: (i) a total aromatics content lower than 18% in weight, as compared to an average 25% currently on sale; (ii) a total polyaromatics content lower 3% in weight as compared to an average 8%; and (iii) cetane number >55 as compared to current standards providing for a minimum 51.

Biofuels. Eni developed the Ecofining™ technology in cooperation with UOP that allows for the conversion of vegetables into Green Diesel. In November 2010, the American Institute of Chemical Engineers (AICHE) awarded Eni and UOP the 2010 Sustainable Energy Award for the activities developed in this area. Aim of the Ecofining™ technology is the production of bio-fuel by means of an integrated refining process that allows for the hydrotreatment of the renewable portion (vegetable oil, exhausted oil, animal fat) and obtain a superior product in terms of heating value and cetane number than conventional bio-diesel (FAME).

Zero waste. Eni intends to develop a system for the disposal of industrial sludge alternative to landfills, possibly associated to thermal treatment in order to minimize waste. For the treatment of industrial, oily and biological waste generated by the oil industry a thermal process has been studied that allows for the gasification of sludge that is turned into an inert residue. A patent application has been filed on this project. Basic design has been completed of a pilot plant with a 50 kg/h capacity along with a feasibility study for an annual volume of 5,000 tonnes of sludge.

 

Polimeri Europa

Basic petrochemicals. Positive testing of catalytic oxidation of phenilcyclohexane on a pilot plant was performed as part of a study aiming at completing a proprietary process for the direct production of phenol and cyclohexanone, which uses benzene as sole feedstock, eliminating the production of acetone as by-product (a toxic and flammable fluid).

Elastomers. The first industrial production of new grades of SBR (styrene-butadiene rubber) has been completed with application to high performance (lower energy consumption and reduction in resistance to rolling) in tire materials. In the lab Eni developed a proprietary technology for new grades of elastomers for Tyre Green application (with lower emissions) with even better performance. ESBR and NBR rubber grades have been obtained at industrial level with low VOCs content.

Styrenic polymers. At the Mantova site, in the new patented technology plant for the expandable polystyrene production, the industrialization of expandable polystyrene was successfully completed through a continuous mass system with a 38 ktonnes/y capacity. The new products allow a 15% reduction in VOCs which are released in the atmosphere during transformation.

 

Eni Corporate

Photoactive materials. A Luminescent Solar Concentrator consists of a slab of transparent material (polymeric or glassy) doped with fluorescent molecules, patented by Eni, which work as microscopic light emitters. The emitted

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radiation is partially concentrated within the slab by total internal reflections and is waveguided toward its edges where PV cells are placed. LSCs allow for a substantial decrease in standard PV module costs by reducing the effective cell surface with respect to the absorbing surface. The positive results obtained at lab level allow the commencement of a pre-commercial phase.

Use of waste for energy production. At lab scale Eni developed a "liquefaction" process for the conversion of the organic waste into bio-oil with a nearly 42% yield (on dry weight) corresponding to an 80% energy recovery. This new technology has been patented and successfully applied to the organic fraction of solid urban waste (FORSU) and to sludge from waste purification plants.

Micro-organisms for bio-diesel. Purpose of the project is the use of micro-organisms (yeasts and bacteria) that accumulate lipids similar to those deriving from oil-bearing vegetables, that can easily be turned into bio-diesel. The raw material employed by these micro-organisms derives from the treatment of wood-cellulose bio-mass in order to not compete with food products. The identified yeasts have higher productivity than the traditional oil crops, including palm.

EKRT (ElectroKinetic Remediation Technology). It is a technology for environmental remediation applicable to mercury polluted soils. An electrolytic solution is circulated in order to dissolve the metallic part of mercury, separating it by means of electro kinesis. This process does not affect the inert portions of mercury and acts selectively only on the mobile portion of mercury, that is also its toxic portion.

 

Results derived from the Eni-MIT alliance

Oil spills in marine environment. The project derives from the discovery of an innovative material with great selective capacity for the absorption of oil dispersed in water. This could be a first step towards new systems for treating oil spills in marine environments.

Ultraflexible solar cell. One of the most relevant results obtained by the Solar Frontier Center: these cells made of a thin photoactive material covered by a layer of transparent plastic can be bent without breaking or reducing performance and this allows to cover irregular surfaces without using metal stilts.

Solar cells on paper. In this case the photoactive device is made on paper as a printed document. The innovative technique is the same used for producing cells on plastic and flexible substrata. A paper cell can be a low cost solution for application where the key aspect is not duration but fast installation and easy transport.

Photochemical splitting of water. Aim of this project is to devise processes for generating oxygen and hydrogen from water by means of biological agents using solar light. The main actors here are nanomaterials synthesized by exploiting the self-assembling capacity of viruses. With this technique we proceeded with the synthesis of new active materials that can be useful in promoting a sustainable generation of hydrogen from renewable sources.

Biofixation of CO₂. CO₂ in the sea is captured by living organisms that convert it into calcium carbonate that is a component of their shell. These biological systems have been successfully reproduced in the lab with the use of yeasts. This paves the way for exploiting CO₂ while producing calcium carbonate and other materials that are considered eco-friendly.

 

Insurance

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

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

Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses.

 

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:

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, and criteria for waste classification.

Decree No. 152/2006 was amended by four subsequent decrees: Legislative Decrees No. 284/2006, No. 4/2008, No. 128/2010 and No. 205/2010.

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Decree No. 4/2008 introduced important changes regarding SEA and EIA procedures, landfill, waste and remediation. The most important aspects of these regulations to Eni are those regulating permits for industrial activities, waste management, and remediation of polluted sites, water protection and environmental liability.

Decree No. 128/2010 introduced IPPC regulations and additional restricting emission limits for certain critical pollutants, in compliance with the IED directive. In relation to the accident occurred in the Gulf of Mexico, the Decree also introduced permit restrictions regarding offshore activities, in line with the European Parliament Resolution of October 7, 2010 on EU action on oil exploration and extraction in Europe. Eni is planning to reschedule certain offshore activities in the Mediterranean Sea and the North European Sea to take account of such developments.

Decree No. 205/2010 implemented the Directive No. 2008/98/EC about waste and adopted the new Special Waste Tracking System (SISTRI) aimed to track waste transfers at national level and to allow a real-time control by authorities. The full operability of the system, initially forecasted by July 2010, has been rescheduled to June 2011.

Decree No. 155/2010 adopted in the Italian law, the European prescriptions on ambient air quality, established by the Directive No. 2008/50/EC. Its main innovation is the definition of monitoring criteria and emission limits for fine particulate substances (PM 2.5), to be achieved by January 1, 2015.

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

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:

 

European Union

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

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Directive No. 2008/1/EC contains the new IPPC and rationalizes all existing regulations on this issue. 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 that are to be included in the European Pollutant Release and Transfer Register (E-PRTR). According to the E-PRTR, Eni installations shall report data on the Italian Register website, by the end of March of each year.

In 2010, Eni has completed 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 review 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 new proposal also introduces more robust monitoring and inspections on installations, the review of permit conditions and the reporting of compliance. The proposal reached the final reading phase on July 7, 2010 and the directive was formally adopted on October 25, 2010 and expected to be published by 2011. The directive defines more restricting emission limits to be observed by the end of 2012, although includes some derogation, as the TNP Transitional National Plan and the option Opt-Out for those installations that are going to shut down their operations by 2023. The member states must transpose the Directive into national legislation by 24 months from publication.

Moreover in September 2010, the European Commission started a public internet consultation on the Review of the Environmental Impact Assessment (EIA) Directive (Directive No. 85/337/EC on the assessment of the effects of certain public and private projects on the environment, as amended). The objective of this public consultation is to collect opinions on the overall view on the functioning and effectiveness of the EIA Directive and possible areas to be improved/amended. Eni participates to the consultation, answering the web-questionnaire.

On November 22, 2008, the new directive on waste (Directive No. 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 (No. 1991/689/EC) and on waste oils (No. 1975/439/EC). 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 particularly through 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.

The 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 promising results of the UN Conference of Cancun (December 2010) related to the definition of a Climate Agreement after 2012, have led the European Commission, on March 15, 2011, to present a Roadmap for transforming the European Union into the worldwide forerunner of low carbon economy by 2050. The Roadmap objective is cutting greenhouse gas emissions by 80-95% of 1990 levels within 2050, by implementing cost-effective measures aiming mostly at improving energy efficiency. The analysis takes into consideration costs and savings related to potential measures such as sectoral policies, national and regional low-carbon strategies and long-term investments. The Commission’s analysis shows that the global transition to a low carbon and resource-efficient economy will generate multiple benefits for the EU: energy importation costs savings, improvements in energy security and economy competitiveness.

Following the incident at the Macondo well in the Gulf of Mexico the U.S. Government and other governments have adopted or are likely to adopt more stringent regulations targeting safety and reliable oil and gas operations in the USA and elsewhere, particularly relating to environmental and health and safety protection controls and oversight of drilling operations, as well as access to new drilling areas. The U.S. Government imposed a moratorium on certain offshore drilling activities through November 30, 2010 (it was suspended in October), and similar actions may be taken by governments elsewhere in the world. Confirming this approach, Italian Authorities have passed legislation with Law Decree No. 128 on June 29, 2010 that introduces certain restrictions to activities for exploring and producing hydrocarbons; however existing projects for conducting oil and gas operation would not be affected. Eni and other operators in the industry have commenced discussions with the Italian Ministry for Economic Development and the Ministry for the Environment to clarify uncertainties in correctly interpreting and applying the new regulations.

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Also the European Parliament has increased its activities in the area of environmental protection in the field of hydrocarbon extraction. On October 7, 2010 the European Parliament approved a resolution on this issue and rejected a proposed moratorium on new oil platforms until global adoption of uniformly more stringent environmental protection laws. The resolution highlighted need for a single European system for prevention and response to intra-community oil spills which would entail amending three EU directives: Seveso II, the directive on environmental responsibility and VIA. The Italian Government confirmed its intention to harmonize Italian laws with European laws also according to the approved resolution. Adoption of stricter regulation both at national and European or international level and expected evolution in industrial practices could trigger cost increases to comply with new HSE standards which the Company might adopt either on a mandatory or voluntary basis. Also our exploration and development plans to produce hydrocarbons reserves and drilling programs could be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil and gas industry will likely increase compared to previous years. The assessments made by Eni’s management regarding the impacts on our operations following the Macondo well incident in the Gulf of Mexico and the rescheduling of certain projects due to the moratorium called by the U.S. Government caused delays in linking few wells to production facilities which had a negligible impact on the Company’s production for the year. In addition, the Group incurred operating costs related to inactivity or redeployment of certain drilling rigs which were booked before the moratorium. During the first months of 2011, Eni expects to resume the operations that had been previously authorized and suspended following the moratorium. Planned activities for which authorizations still have to be granted might be rescheduled due to uncertainties in the timing of obtaining the necessary authorizations from the U.S. Authorities. In order to achieve the highest security standards of our operations in the Gulf of Mexico, we entered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Fast Response System (HFRS) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.

 

HSE Activity for the Year 2010

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 2010, 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 271 (247 in 2009), of which 97 certifications according to the ISO 14001 standard, 9 certifications according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union) and 62 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

Environment. In 2010, Eni incurred total expenditures amounting to euro 1,151 million for the protection of environment, down 13% from 2009. Current environmental expenses decreased by approximately 13% from 2009, and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure decreased by 13% and mainly related to soil and subsoil protection, air emissions, energy efficiency and climate change. Eni expects to continue incurring amount of environmental expenditures and expenses in line with or above 2010 levels in future years.

Safety. Safety of our employees and contractors as well as of all people living in the area where activities and assets are located is important to our company. In 2010, there were no significant impacts resulting from new regulations on safety in the workplace. Eni’s business units focused on completing the important organizational changes required by new regulations enacted in 2008.

The improvement and dissemination of safety awareness through all levels of the Company’s organization continued in 2010; this is one of the foundations of Eni’s safety strategy, through a large communication campaign with the target of improving the conduct of workers in the specific field of safety at work. The campaign will be completed this year and will involve 35,000 workers and 25,000 contractors. At the end it will be possible to evaluate the effectiveness of the campaign.

From the end of 2009 and throughout 2010, a number of safety seminars involving the top and middle management of various Business Units have taken place, with the aim of sharing the experiences coming from the implementation of process safety audits in the downstream sector and asset integrity verification tools in the upstream sector. The process safety knowledge improvement effort is continuing with courses targeted at specific areas like functional safety and alarms management.

Results of efforts to achieve a better safety in all activities has brought an improvement of Eni injury frequency rate to 0.91 and of the injury severity rate to 0.03, both decreasing from 2009 and representing the best results ever.

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Costs incurred in 2010 to support the safety levels of operations and to comply with applicable rules and regulations were euro 283.5 million, down 45% from 2009. Eni expects to continue incurring amounts of expenses for safety which will be in line with or above 2010 levels in future years.

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

To protect the health and safety of its employees, Eni relies on a network of more than 300 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. The experience acquired in this field, have brought to the elaboration of Health Impact Assessment (HIA) and relative standards to be applied to all new projects of evaluation of working exposure in foreign environment.

In 2010, Eni incurred a total expense of euro 57.8 million, down 28.6% from 2009, 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 2010 levels in future years.

In 2010, Eni total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to euro 1,578 million, down 18% from 2009.

 

Managing GHG emissions and Implementation of the Kyoto Protocol

On February 16, 2005, the Kyoto Protocol entered into force along with commitments provided by Annex I to the Protocol which was ratified by the same parties who joined 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 No. 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. 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.

Eni is part to the ETS. 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 2.0 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 2010.

Moreover, Eni monitors the opportunities deriving 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

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program of greenhouse gas emissions reduction. In December 2003, during the Conference of Parties to the Kyoto Protocol – COP9 –, Eni and the Ministry for the Environment signed a Voluntary Agreement for using flexible mechanisms, promoting CDM and JI and contributing to the sustainable development of host countries.

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.

Management plans to target GHG emissions reduction 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 outlets for that gas. The elimination of flaring and the use of associated gas for the development of local economies enable sustainable development while reducing greenhouse gas emissions. The validation, where possible, of such projects as CDM and JI will provide emission credits and support the Company in achieving its GHG reduction targets in Italy, as set by the Kyoto Protocol. The flaring down project of Kwale Okpai in Nigeria was already registered as a CDM.

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 move forward completion of gas flaring reduction projects. In the period 2010-2013, a reduction in the trend of Eni total GHG emissions is foreseen due to the planned implementation of the abovementioned 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 650-750 million. Most of those projected expenses are expected to be incurred in the years 2013-2014, which correspond to the third Phase of Emission Trading. In fact, from 2013, full auctioning will be in force in power sector, while energy-intensive industries exposed to international competition will receive their allowances free of charge as benchmarked to the average performance of the 10% most efficient installations in a specific sector.

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. Eni is currently implementing Italy’s first CO₂ injection project in Cortemaggiore: its Environmental Impact Assessment procedure is in course of approval by the competent Ministries.

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.

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Regulation of Eni’s Businesses

Overview

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

 

Regulation of Exploration and Production Activities

Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil and gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See "Regulation of the Italian Hydrocarbons Industry" and "Environmental Matters" in this Item 4 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 USA which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area.

In Production Sharing Agreements (PSA), entitlements to production volumes are defined on the basis of contractual agreements drawn up with state oil companies which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (cost oil) and give entitlement to a portion of the production volumes exceeding volumes destined to cover costs incurred (profit oil).

A similar scheme to PSA applies to Service and "Buy-Back" contracts.

In general, Eni is required to pay income tax on income generated from production activities (whether under a license or 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

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production concession, in each case granted by the Ministry of Productive Activities through competitive auctions. The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State. The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and an additional five-year extension until the field depletes.

Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Law No. 99 of July 23, 2009 royalties are equal to 10% and 4%, respectively, for onshore and offshore production of oil and 10% and 7%, respectively, for onshore and offshore production of natural gas.

 

Gas & Power

Natural gas market in Italy

Legislative Decree No. 130 August 13, 2010 containing measures for increasing competition in the natural gas market and transferring the ensuing benefits to final customers according to Article 30, lines 6 and 7, of Law July 23, 2009, No. 99

In 2010, the regulated period for gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 expired. Those thresholds defined maximum allowed limits of gas volumes (imported or domestically produced) input into the national transport network and marketed to final customers, applicable to each operator.

Implementing the provisions of Law 99/2009, that system of antitrust thresholds was replaced with a mechanism of market shares enacted by Legislative Decree No. 130 of August 13, 2010 "New measures to improve competitiveness in the natural gas market and to ensure the transfer of economic benefits to final customers" approved by the Italian Council of Ministers. The Decree provides that antitrust ceilings be calculated with reference to the market share of each operator, taking into account the amount of natural gas input into the national network, purchases on spot markets, and sales to importers in Italy made at national network entry points. Consequently, market shares will not be lower than the amount input to the network. Operators in the natural gas market will have to comply with a maximum share of 40% of domestic consumption. A mechanism of gas release at regulated prices is provided in case an operator fails to comply with the mandatory ceilings on the market share. This ceiling can be raised to 55% in case an operator commits to building new storage capacity in Italy for a total of 4 BCM within five years. In this case, the operator is obliged: (i) to allow third parties (such as industrial customers, groups of companies, consortia of final customers and power generation customers) participate in the construction of storage infrastructure either by means of direct investment or long-term contracts for storage services; and (ii) bear the costs associated with giving to third parties 50% of the expected benefits of new capacities under conditions defined by the Ministry for Economic Development and the Authority for Electricity and Gas ("AEEG").

Eni is planning to make the necessary investments to increase storage capacity in Italy so as to benefit from a higher allowed market share.

The Decree introduces measures for increasing competition in the natural gas market aiming at transferring the ensuing benefits to final customers, increasing storage capacity, supporting the security of supplies and enhancing flexibility in the gas system. To achieve this target, compensation to municipalities interested by the construction of new storage fields has been provided.

Eni’s management is monitoring this area and evaluating any possible financial or economic impact associated with the proposed measures and their regulatory evolution. Management also believes that this new gas regulation will increase competition in the wholesale natural gas market in Italy resulting in further margin pressures.

 

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

This law provides for:

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Law No. 290/2003

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 rescheduled 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 any evolution of this matter.

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 Eni. Management believes that this decree may impact Eni in case the Company makes plans to divest the whole or a portion of its interest in Snam Rete Gas. Eni’s interest in Snam Rete Gas will also be affected by the due steps that Italian institutions have been implementing to enact Directive No. 2009/73/EC in Italian laws. See below.

 

Regulations aimed at increasing competition in the Italian wholesale segment of natural gas

In order to implement measures defined by the Italian Government to face the economic downturn, a number of administrative provisions relating to the so-called gas release measures have been enacted in an effort by Italian administrative Authorities to boost the level of competition and liquidity of the Italian gas market. Those measures have strongly affected Eni’s marketing activity in Italy. Legislative Decree No. 78/2009 obliged Eni to make a gas release 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 AEEG (Eni considering this point discriminatory, filed a claim with 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, also based on indications of the Authority for Electricity and Gas, Eni believes that it is possible that the Company will be forced to implement additional gas release measures.

 

Negotiation Platform for gas trading

In compliance with the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry for Economic Development published a Decree that implements a trading platform for natural gas starting from May 10, 2010 aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform are entrusted to an independent operator, the GME (Gestore del Mercato Elettrico). On this platform are traded volumes of gas corresponding to the legal obligations on part of Italian importers and producers as per Law Decree No. 7/2007. Under these provisions, importers from non-European countries were expected to supply given amounts of gas (from 5% to 10% of total gas import) to the virtual exchange in order to receive permission to import, as well as volumes corresponding to royalties due by owners of mineral rights to the Italian state (and to Basilicata and Calabria Regions). Eni was required to offer at that platform about 200 mmCM related to the residual obligation for volumes imported in thermal year October 1, 2008-September 30, 2009, and to the offer obligation for the October 1, 2009-September 30, 2010 thermal year, as well as approximately 215 mmCM related to royalties due for 2009 full year. Operators, also non-importers, are allowed to negotiate additional gas volumes over the compulsory amounts on the platform according to the supply rules determined by the AEEG. Since December 2010, the GME is also trader’s counterparty in transactions on the spot market for natural gas (divided into day-ahead market and intraday market).

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Natural gas prices

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

Furthermore, the AEEG 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 AEEG 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.

 

Change in the criteria for determining and upgrading tariffs applied to residential customers: Resolution ARG/gas 89/2010

On June 18, 2010, the AEEG published a resolution ARG/gas 89/2010, applied to the October 1, 2010-September 30, 2011 thermal year, providing for a 7.5% reduction in the raw material cost component of those supplies in determining tariffs for residential users consuming less than 200,000 CM/y. Considering that the new calculation does not cover the supply costs of an efficient portfolio of long-term contracts and considering the relevant impact on its consolidated accounts deriving from this new resolution, Eni’s management has appealed against the ARG/gas 89/2010 resolution. This appeal is part of an ongoing administrative litigation which follows the partial annulment of AEEG Resolution No. 79/2007, pronounced by the Administrative Court of Lombardy in November 2010, with reference to the mechanism of indexation of the cost of raw material supplies to residential customers.

 

Directive No. 2009/73/EC of the European Parliament and Council on common regulations for the internal natural gas market

On July 13, 2009, European Directive No. 2009/73/EC on the regulation of the internal natural gas market was issued. Member states are expected to implement it in their legislation by March 3, 2011, and to choose one of two options for guaranteeing the independence of transport companies.

The two options provided are:

On March 3, 2010, the Italian Council of Ministers presented a draft legislative decree to implement Directive No. 2009/73/EC. Among the possible options, the decree provides for the adoption of the ITO model by Snam Rete Gas by March 3, 2012.

 

Fully-Regulated Businesses in the Italian Gas Market

Transport

Transport tariffs. The AEEG set transport criteria companies have to apply in determining natural gas transport and dispatching tariffs on national and regional transport 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.

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Criteria established by the AEEG 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 transport 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 pre-tax rate of return (WACC) on the Regulatory Asset Base (RAB) has been set equal to 6.4% in real terms.

The new tariff structure confirms recognition in tariff of expenditures incurred for network upgrading, providing for a higher remuneration than WACC, in a measure ranging from one to three percentage points of additional remuneration in relation to the nature of expenditures and for a period of 5 to 15 years.

Depreciation charges of gas transport infrastructures (gas pipelines) are determined on a 50-year 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 factor in 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 on the basis of operating costs recognized in tariff and amounts to approximately 15% of revenue cap.

With Resolution ARG/gas 218/2010, the AEEG also recognized to Snam Rete Gas a total amount of euro 54.9 million as settlement of additional costs incurred from October 1, 2008 to December 31, 2009 relating to the purchase of fuel gas for compression stations.

Network Code. From 2003, Snam Rete Gas Network Code is in force, regulating entitlements of transport capacity, obligations on part of both the transporter and the customer and the procedures through which customers can resell capacity to other users. Transport capacity at entry points to the national gas pipeline network (point of interconnection with import gas lines) is entitled on an annual basis with duration of up to five thermal years. Capacity products with duration shorter than one year are also available.

The Network Code, approved by the AEEG with Resolution No. 75 of July 1, 2003, is based on the criteria set by the same Regulator with Resolution No. 137/2002. This resolution 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 party to take-or-pay purchase 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 entitlements. The ability of Eni to collect gas volumes exceeding average daily volumes as provided by its take-or-pay purchase contracts represents an important operational flexibility that the Company uses to satisfy demand peaks. In planning its commercial flows, the Company normally assumes to fully utilize its contractual flexibility and to obtain the necessary capacity entitlements at the entry points to the national transport network. Eni believes that Resolution No. 137/2002 is in contrast with the rationale of the European regulatory framework on the gas market as provided in Directive No. 2003/55/EC. Based on that belief, the Company has opened an administrative procedure to repeal it before an administrative court which has recently confirmed in part Eni’s position. An upper grade court also confirmed the Company’s position. Specifically, the Administrative 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 Administrative 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 so as to impair Eni’s marketing plans.

 

Re-gasification

Re-gasification tariffs. The AEEG has set the criteria regulating the tariffs for the use of LNG terminals in the 3^rd regulatory period (October 2008-September 2012) with its 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,

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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.

Resolution ARG/gas 92/2008 also established that the allocation of reference revenues between re-gasification capacity and the commodity component is fixed at 90:10 (compared to 80:20 ratio in the second regulated period).

Re-gasification Code. From 2007 GNL Italia Re-gasification Code is in force, defining rules and regulations for the operation and management of the re-gasification plant of Panigaglia in North-West Italy. The Code, approved with the Resolution VIS 8/2009, is based on the criteria for access to LNG re-gasification services set by the same Regulator with Resolution No. 167/2005 (August 1, 2005) in accordance with Legislative Decree No. 164/2000. The decision also defines criteria for the allocation of re-gasification 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 re-gasified 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 AEEG 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 AEEG to each operator for covering costs borne.

In previous years, revenues were determined by applying tariffs set by the AEEG 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. 164/2000. 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 AEEG 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

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peak supplies and the need to incentive capital expenditure for upgrading the storage system; and (vii) the AEEG 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 August 3, 2010, the AEEG with Resolution No. 119/2010 published the criteria for determining storage tariffs for the 2011-2014 regulated period.

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

In the years following the first year of the new 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.

Storage Code. From November 1, 2006 Stoccaggi Gas Italia (Stogit) Storage Code is in force.

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 AEEG 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 for 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 for 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.

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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. 164/2000.

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 for Economic Development determines quantities and usage criteria of such reserves. As of December 31, 2010, Eni held approximately 177 BCF of strategic reserves of natural gas (177 BCF at year end 2009).

 

Refining and Marketing of Petroleum Products

Refining. Under Legislative Decree No. 112 of March 31, 1998, 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 Decree No. 112 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.

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

Law No. 96 of June 4, 2010 requires the government to follow some principles and criteria in drafting the legislative decree that shall implement, by December 31, 2012, Directive No. 2009/119/EC (imposing an obligation

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on member states to maintain minimum stocks of crude oil and/or petroleum products), in particular: (a) keep a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks; and (b) provide for the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development – with the mandatory participation of entities who have imported oil or petroleum products – that should be in charge of: (i) the holding and transport of specific stocks of products, (ii) the stocktaking, (iii) the statistics on emergency, specific and commercial stocks; and, eventually, (iv) the provision of a storage and transportation service of emergency and commercial stocks in favour of sellers of petroleum products to final clients not vertically integrated in the oil chain.

As of December 31, 2010, Eni owned 6.5 mmtonnes of oil products inventories, of which 4.2 mmtonnes as "compulsory stocks", 1.7 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, 2010) were held in term of crude oil (33%), light and medium distillates (46%), fuel oil (16%) and other products (5%) and they were located throughout the Italian territory both in refineries (78%) and in storage sites (22%).

 

Competition

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

National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest.

Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the "EEA Agreement"), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority.

In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the "Italian Antitrust Law"). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers.

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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, 2010, there were 270 fully-consolidated subsidiaries and 76 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 2010".

 

 

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 and "Item 3 – Risk Factors".

 

Executive Summary

Eni reported net profit of euro 6,318 million for the year ended December 31, 2010, representing an increase of 44.7% from 2009. That amount represented net profit attributable to Eni’s shareholders.

The Group operating profit for the year ended December 31, 2010 amounted to euro 16,111 million, up 33.6% from 2009 mainly related to: (i) a positive operating performance reported by the Exploration & Production segment, reflecting higher oil realizations in U.S. dollar terms (up 27.8%), and the depreciation of the euro against the U.S. dollar (down 4.7%); (ii) higher results of the Engineering & Construction Division which were driven by revenue growth and increased profitability of acquired orders; and (iii) improved operating results recorded by both the downstream refining and petrochemical businesses thanks to a more favorable trading environment. In contrast, the Gas & Power Division reported sharply lower results due to lower unit margins on sales outside Italy and volumes losses in the Italian market reflecting increased competitive pressures and oversupply conditions in the gas market. Results of the Gas & Power Division were also hit by an impairment charge amounting to euro 426 million relating to goodwill due to a reduced profitability outlook for the European gas marketing business.

Operating profit benefited from the recognition of an inventory holding gain amounting to euro 881 million (euro 345 million in 2009), reflecting the impact of rising prices of crude oil and products on year end valuation of inventories according to the average cost method of inventory accounting. Those gains were partly offset by higher environmental provisions as the Company recorded a charge amounting to euro 1,109 million to account for a proposal of a global environmental settlement with the Italian Ministry for the Environment. The proposed settlement is intended to define the Company’s commitments to perform clean-up and remediation activities at certain Italian sites and settle all pending civil and administrative litigation on the issue of environmental damage. See "Significant Transactions" below for a full description of the proposed transactions.

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Group results for the year also benefited from higher profits reported by non-consolidated entities that are accounted for under the equity or the cost method (up euro 587 million).

Net cash provided by operating activities amounted to euro 14,694 million for the year ended December 31, 2010 and benefited from a cash inflow from transferring certain account receivables without recourse to factoring institutions, amounting to euro 1,279 million due in 2011. These inflows were balanced by outflows for pre-payments to the Company’s suppliers of gas under long-term contracts upon triggering the take-or-pay clause (euro 1,238 million). Net cash provided by operating activities, together with cash proceeds from divestments amounting to euro 1,113 million, were used to fund part of the cash outflows relating to capital expenditures totaling euro 13,870 million and dividend payments to Eni’s shareholders amounting to euro 3,622 million. Dividends paid to non-controlling interests amounted to euro 514 million, mainly relating to Saipem and Snam Rete Gas.

As of December 31, 2010 net borrowings amounted to euro 26,119 million, an increase of euro 3,064 million from December 31, 2009.

In 2010, oil and natural gas production available for sale averaged 1,757 KBOE/d. Production for the year expressed in barrel-of-oil equivalent was computed assuming a natural gas conversion factor which was updated to 5,550 cubic feet of gas equals 1 barrel of oil. See disclosure in a footnote to the "Conversion Table" on page vi. On a comparable basis, i.e. when excluding the effect of updating the gas conversion factor, production showed an increase of 0.9% for the full year. Production growth was driven by additions from new field start-ups, particularly the Zubair field (Eni’s interest 32.8%) in Iraq (for a total increase of 40 KBOE/d). These increases were offset in part by mature field declines.

Worldwide gas sales in 2010 amounted to 97.06 BCM, down 6.4% from 2009 due to lower volumes supplied to the Italian market (down 5.75 BCM, or 14.4%) against the backdrop of stronger competitive pressures and oversupply on the marketplace which also hit sales to importers of natural gas in Italy (down 2.04 BCM or 19.5%). These declines were partly offset by higher volumes achieved in a number of European markets driven by growth in France, Northern Europe (including the UK), Germany/Austria and the Iberian Peninsula, while sales decreased in Turkey, Belgium and Hungary.

In 2010, capital expenditures amounted to euro 13,870 million (euro 13,695 million in 2009) and related mainly to:

During the 2010-2014 four-year period, Eni expects to invest approximately euro 53.3 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

		2008		2009		2010

Average price of Brent dated crude oil in U.S. dollars (1)		96.99		61.51		79.47
Average price of Brent dated crude oil in euro (2)		65.93		44.16		59.89
Average EUR/USD exchange rate (3)		1.471		1.393		1.327
Average European refining margin in U.S. dollars (4)		6.49		3.13		2.66
Euribor - three month euro rate % (3)		4.6		1.2		0.8

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

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

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

In 2010, Eni’s results were driven by higher oil realizations driven by rising Brent prices which were up 29.2% from 2009. Results also benefited from the depreciation of the euro versus the U.S. dollar, down by 4.7%, which improved the operating results reported by Eni’s subsidiaries whose functional currency is the U.S. dollar. Unit margins in the marketing of gas outside Italy were hit by lower price differentials between spot prices for gas recorded in European continental hubs, as those prices have become the benchmark in contractual selling formulae in Europe, and the Company’s purchase costs of gas which have remained mainly indexed to the cost of oil and certain refined products. Eni’s realized refining margins in U.S. dollar terms remained at unprofitable levels as the Brent benchmark refining margin for the year was down 0.47 $/BBL, or 15% from 2009. That trend reflected higher oil-feedstock costs which were only partially transferred to prices of refined products at the pump pressured by weak underlying fundamentals (slow demand, excess capacity, high inventory levels). Nonetheless, Eni’s realized margins posted a slight improvement from the depressed levels of the year-earlier due to wider price differential between sour and sweet crude qualities and higher relative prices of middle distillates compared to heating oil, which benefited Eni’s complex refineries. Petrochemical product margins also improved from the prior year as high oil-based feedstock costs were at least partially offset by higher chemicals commodity prices on the back of a recovery in demand.

 

Key Consolidated Financial Data

		2008		2009		2010

(euro million)

Net sales from operations				108,082		83,227		98,523
Operating profit (1)				18,517		12,055		16,111
Net profit attributable to Eni				8,825		4,367		6,318
Net cash provided by operating activities				21,801		11,136		14,694
Capital expenditures				14,562		13,695		13,870
Acquisitions of investments and businesses (2)				4,305		2,323		443
Shareholders’ equity including non-controlling interest at year end				48,510		50,051		55,728
Net borrowings at year end (2)				18,376		23,055		26,119
Net profit attributable to Eni basic and diluted		(euro per share)		2.43		1.21		1.74
Dividend per share		(euro per share)		1.30		1.00		1.00
Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) (3)				0.38		0.46		0.47

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(1)		From year 2009, the Company accounts for 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 as issued by IASB. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated

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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 oil field 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 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 "Item 18 – Note 20 to the Consolidated Financial Statements") 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 cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate related to the activity involved.

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For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. Oil, natural gas and petroleum product prices (and to prices from 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. 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.

 

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 provisions 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:

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Employee benefits

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including among others discount rates, expected rates of return on plan assets, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include 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 obligations and employee benefits, Eni accrues for all contingencies that are both probable and estimable. These other contingencies are primarily related to litigation and tax issues. Determining 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 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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2008-2010 Group Results of Operations

Overview of the Profit and Loss Account for Three Years Ended December 31, 2008, 2009 and 2010

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,

		2008		2009		2010

(euro million)

Net sales from operations		108,082			83,227			98,523
Other income and revenues (1)		728			1,118			956
Total revenues		108,810			84,345			99,479
Operating expenses		(80,354	)		(62,532	)		(73,920	)
Other operating (expense) income (2)		(124	)		55			131
Depreciation, depletion, amortization and impairments		(9,815	)		(9,813	)		(9,579	)
OPERATING PROFIT		18,517			12,055			16,111
Finance income (expense)		(640	)		(551	)		(727	)
Income (expense) from investments		1,373			569			1,156
PROFIT BEFORE INCOME TAXES		19,250			12,073			16,540
Income taxes		(9,692	)		(6,756	)		(9,157	)
NET PROFIT		9,558			5,317			7,383
Attributable to:
- Eni		8,825			4,367			6,318
- non-controlling interest		733			950			1,065

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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)		Beginning in 2009, the Company accounts for 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.

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,

		2008		2009		2010

(%)

Operating expenses		74.3		75.1		75.0
Depreciation, depletion, amortization and impairments		9.1		11.8		9.7
OPERATING PROFIT		17.1		14.5		16.4

2010 compared to 2009. Net profit attributable to Eni’s shareholders in 2010 was euro 6,318 million, an increase of euro 1,951 million from 2009, or 44.7%. This increase was driven by:

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These increases were partly offset by higher income taxes (up euro 2,401 million compared to 2009) mainly reflecting higher income taxes currently payable by subsidiaries in the Exploration & Production Division operating outside Italy due to higher taxable profit.

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:

 

Discontinued Operations

Discontinued operations in 2010, 2009 and 2008 were immaterial.

 

Analysis of the Line Items of the Profit and Loss Account

a) Total Revenues

Eni’s total revenues were euro 99,479 million, euro 84,345 million and euro 108,810 million for the year ended December 31, 2010, 2009 and 2008, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations amounted to euro 98,523 million, euro 83,227 million and euro 108,082 million for the year ended December 31, 2010, 2009 and 2008, respectively, and its other income and revenues totaled euro 956 million, euro 1,118 million and euro 728 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,

		2008		2009		2010

(euro million)

Exploration & Production (1)		33,042			23,801			29,497
Gas & Power (1)		37,062			30,447			29,576
Refining & Marketing (2)		45,017			31,769			43,190
Petrochemicals		6,303			4,203			6,141
Engineering & Construction		9,176			9,664			10,581
Other activities		185			88			105
Corporate and financial companies		1,331			1,280			1,386
Impact of unrealized intragroup profit elimination		75			(66	)		100
Consolidation adjustment (3)		(24,109	)		(17,959	)		(22,053	)
NET SALES FROM OPERATIONS		108,082			83,227			98,523

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2010 compared to 2009. Eni’s net sales from operations (revenues) for 2010 (euro 98,523 million) increased by euro 15,296 million from 2009, or 18.4% from 2009, primarily reflecting higher realizations on oil, refined products and natural gas in U.S. dollar terms and the positive impact of the depreciation of the euro against the U.S. dollar.

Revenues generated by the Exploration & Production Division (euro 29,497 million) increased by euro 5,696 million, or 23.9%, mainly due to higher realizations in U.S. dollar terms (oil up 27.8%; natural gas up 7.1%) and the depreciation of the euro versus the U.S. dollar. Eni’s average liquids realizations decreased by 1.33 $/BBL to 72.76 $/BBL due to the settlement of certain commodity derivatives relating to the sale of 28.5 mmBBL. The latter trend is going to continue in 2011 due to current trends in Brent oil prices.

Revenues generated by the Gas & Power Division (euro 29,576 million) decreased by euro 871 million (or 2.9%) due to lower sales volumes in Italy (down 5.75 BCM, or 14.4%), partly offset by the positive impact of a slight recovery in spot and oil-linked gas prices due to a less unfavorable pricing environment compared to 2009 which are reflected in Eni’s revenues. Increased sales volumes were also recorded in key European markets.

Revenues generated by the Refining & Marketing Division (euro 43,190 million) increased by euro 11,421 million (or 36%) reflecting higher selling prices of refined products.

Revenues generated by the Petrochemical Division (euro 6,141 million) increased by euro 1,938 million (up 46.1%) mainly reflecting higher average selling prices (up 35.6%) and a recovery in sales volumes (up 10.9%, mainly in the elastomers business area) following stronger demand on end-markets compared to the particularly weak trading environment of the previous year.

Revenues generated by the Engineering & Construction business (euro 10,581 million) increased by euro 917 million, or 9.5%, from 2009, as a result of increased activities in the onshore and drilling business units.

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, refined products and natural gas in U.S. dollar terms and lower sales volumes. These negatives were partly offset by the positive impact of the depreciation of the euro versus the U.S. 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 U.S. 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

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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 versus 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 versus the U.S. 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 and gas projects that were started during the upward phase of the oil cycle.

 

b) Operating Expenses

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

	Year ended December 31,

		2008		2009		2010

(euro million)

Purchases, services and other		76,350		58,351		69,135
Payroll and related costs		4,004		4,181		4,785
Operating expenses		80,354		62,532		73,920

2010 compared to 2009. Operating expenses for the year (euro 73,920 million) increased by euro 11,388 million from 2009, up 18.2%, reflecting primarily higher supply costs of purchased oil, gas and petrochemical feedstocks reflecting trends in the trading environment, the depreciation of the euro against the U.S. dollar, as well as higher operating expenses reported by the upstream activities.

Purchases, services and other costs include environmental and other risk provisions for an overall amount of euro 1,291 million mainly associated with an environmental provision recorded to account for a proposed global settlement on certain environmental issues (euro 1,109 million) filed with the Italian Ministry for the Environment, which is disclosed in the paragraph "Significant Transactions" below.

Payroll and related costs (euro 4,785 million) increased by euro 604 million, or 14.4%, 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 higher activity levels in the Engineering & Construction business), as well as increased provisions for redundancy incentives (euro 423 million in 2010) including a provision representing the charge to be borne by Eni as part of a personnel mobility program in Italy for the period 2010-2011. These increases were partly offset by a decrease in the average number of employees in Italy.

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 U.S. 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

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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.

 

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,

		2008		2009		2010

(euro million)

Exploration & Production (1)		6,678			6,789			6,928
Gas & Power		797			981			963
Refining & Marketing		430			408			333
Petrochemicals		116			83			83
Engineering & Construction		335			433			513
Other activities		4			2			2
Corporate and financial companies		76			83			79
Impact of unrealized intragroup profit elimination (2)		(14	)		(17	)		(20	)
Total depreciation, depletion and amortization		8,422			8,762			8,881
Impairments		1,393			1,051			698
		9,815			9,813			9,579

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(1)		Exploratory expenditures of euro 1,199 million, euro 1,551 million and euro 2,057 million are included in these amounts relative to the years 2010, 2009 and 2008, 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.

2010 compared to 2009. In 2010, depreciation, depletion and amortization charges amounted to euro 8,881 million, representing an increase of euro 119 million from 2009, or 1.4%. The Exploration & Production Division recorded higher charges (up euro 139 million) due to increased development activities as new fields were brought into production and higher expenditures were made in order to support production levels in producing fields. Those were partly offset by lower exploration expenditures. Also the Engineering & Construction business recorded higher charges (up euro 80 million) as new vessels and rigs were brought into operation. The decrease recorded in the Refining & Marketing Division reflected a review of the residual useful lives of refineries and related facilities, with an impact of euro 76 million. In doing so, the Company believes that it aligned with practices prevailing among integrated oil companies, particularly the European companies. In the Gas & Power Division, the impact of new investments entered into operation was offset by the revision of the useful lives of gas pipelines (from 40 to 50 years), as revised by the Authority for Electricity and Gas for tariff purposes, from January 1, 2010, with an impact of euro 31 million.

In 2010, impairment charges of euro 698 million mainly regarded an impairment charge of goodwill allocated to the European gas marketing cash generating unit in the Gas & Power Division. The impaired goodwill derived from the acquisition of the Belgian company Distrigas that was made in 2009. Management forecasts that weak demand growth and continuing oversupply will continue to weigh on the recovery of the European gas sector in the next few years. Rising competitive pressures will pressure unit margins on gas sales and reduce selling outlets. To factor in those trends, management revised downward with respect to past years, future projections for returns and cash flows of the Company’s gas business for the next four years. Particularly, the European market business unit is expected to be negatively affected by lowering marketing margins over the next four years. This reflects ongoing development of highly liquid spot markets for gas and the fact that spot prices have increasingly become the prevailing reference price for contractual formulas in supplies outside Italy whereas Eni’s purchase costs for gas are mainly indexed to the price of oil and refined products. Trends in spot prices as compared to those in oil-linked purchase costs have been de-coupling until recently resulting in negative spreads during the course of 2010; management expects that those negative trends will not re-couple until 2014 at the earliest. In the 2010 Consolidated Financial Statements, management recognized an impairment loss amounting to euro 426 million associated with goodwill of the European gas business unit considering weak 2010 results and a reduced outlook for profitability as discussed above. Impairment charges of oil and gas properties in the Exploration & Production Division were recorded for significantly lower amount than in the previous two years. Impairments were triggered by a changed

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pricing environment and downward reserve revisions which mainly pertained to gas properties in the USA with proved and unproved reserves. Minor impairment losses were recorded on assets impaired in previous reporting periods in the Refining & Marketing and Petrochemical Divisions as capital expenditures made in 2010 were completely written-off as Eni does not expect improving profitability in the underlying business units (For further information see "Item 18 – Consolidated Financial Statements – Note 14 – Tangible and Intangible assets").

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 U.S. dollar, rising development activities reflecting consolidation of acquired oil and 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.

 

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,

		2008		2009		2010

(euro million)

Exploration & Production (1)		16,239			9,120			13,866
Gas & Power (1)		4,030			3,687			2,896
Refining & Marketing		(988	)		(102	)		149
Petrochemicals		(845	)		(675	)		(86	)
Engineering & Construction		1,045			881			1,302
Other activities (2)		(466	)		(436	)		(1,384	)
Corporate and financial companies (2)		(623	)		(420	)		(361	)
Impact of unrealized intragroup profit elimination		125						(271	)
Operating profit (3)		18,517			12,055			16,111

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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 2010 certain environmental provisions incurred by the parent company Eni SpA due to inter-company guarantees on behalf of Syndial have been reported within the segment reporting unit "Other activities" rather than the segment "Corporate and financial companies". Data for the years 2008 and 2009 have been restated accordingly for the following amounts: euro 120 million and euro 54 million, respectively.
(3)		From 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.

 

 

 

 

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The table below sets forth operating profit or losses 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,

		2008		2009		2010

(%)

Exploration & Production		49.1			38.3			47.0
Gas & Power		10.9			12.1			9.8
Refining & Marketing		(2.2	)		(0.3	)		0.3
Petrochemicals		(13.4	)		(16.1	)		(1.4	)
Engineering & Construction		11.4			9.1			12.3
Other activities
Corporate and financial companies		(46.8	)		(32.8	)		(26.0	)
Group		17.1			14.5			16.4

Exploration & Production. Operating profit in 2010 amounted to euro 13,866 million, up euro 4,746 million from 2009, or 52%, due to higher liquids and gas realizations in U.S. dollar terms (up by 27.8% and 7.1%, respectively). The result also reflected: (i) a positive impact associated with the depreciation of the euro against the U.S. dollar, for an estimated amount of euro 400 million; (ii) the recognition of lower asset impairments; and (iii) lower exploration expenditures. These positives were partly offset by increased operating expenses and amortizations charges reflecting new fields entered into operation and activities to improve production rates in existing fields, and higher provisions for redundancy incentives (up euro 66 million).

In 2010, liquids and gas realizations increased on average by 18.6% in U.S. dollar terms, driven by higher oil prices for market benchmarks (Brent crude price increased by 29.2%) and, to a lower extent, higher gas prices which were up by 7.1% on average. Eni’s oil realizations increased on average by 27.8% driven by a favorable market environment. Eni’s average liquids realizations were negatively impacted for an amount of 1.33 $/BBL on average due to the settlement of certain commodity derivatives relating the sale of 28.5 mmBBL in the year at contractually fixed prices. This was part of a derivative transaction the Company entered into to hedge exposure to volability of future cash flows expected from the sale of a portion of the Company’s proved reserves for an original amount of approximately 125.7 mmBBL in the 2008-2011 period. As of December 31, 2010, the residual amount of that hedging transaction was 9 mmBBL.

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

	Full Year

		2008		2009		2010

Sales volumes		(mmBBL)		364.3			373.5			357.1
Sales volumes hedged by derivatives (cash flow hedge)				46.0			42.2			28.5
Total price per barrel, excluding derivatives		($/BBL)		88.17			56.98			74.09
Realized gains (losses) on derivatives				(4.13	)		(0.03	)		(1.33	)
Total average price per barrel				84.05			56.95			72.76

Operating profit in 2009 amounted to euro 9,120 million, down euro 7,119 million from 2008, or 43.8%, reflecting lower realizations in U.S. 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 U.S. 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.

In 2009, the impact of those cash flow hedges was immaterial as the increase in liquids realizations by 0.45 $/BBL as a result of the sale of 31.6 mmBBL at the hedged price recorded in the first nine months was absorbed by

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a reduction on average by 1.46 $/BBL 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.

Gas & Power. In 2010, the Gas & Power Division reported operating profit of euro 2,896 million, a decrease of euro 791 million from 2009, down 21.5%, due to a lower performance delivered by the Marketing business which was down by 63.7%. This was partly offset by a better performance achieved by the Italian regulated businesses (up by 12.7%). The negative performance in marketing operations was mainly due to: (i) increasing competitive pressures in Italy, due to oversupply conditions in the marketplace and sluggish demand growth, resulting in both sharply lower gas sales (down by 14.4% and 19.5% to Italian customers and Italian wholesalers importers, respectively) and price reductions to customers during the marketing campaign for the new thermal year beginning on October 1, 2010; (ii) outside Italy, the persistence of unprofitable differentials between oil-linked gas purchase costs provided in Eni’s long-term gas supply contracts and spot prices recorded at European hubs which have become a prevailing reference benchmark for selling prices; (iii) the impairment of goodwill attributed to the European marketing cash generating unit (euro 426 million), based on 2010 results and a reduced profitability outlook for this business; (iv) a negative change in 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; and (v) a reversal in trend of certain energy parameters to which gas purchase and selling prices are indexed, mainly in sales to residential users.

These negatives were partly offset by: (i) the recording of higher inventory holding gains due to the impact of rising gas prices on inventories stated at the weighted average cost of supplies or the net realizable value, whichever is lower; and (ii) a non-recurring gain amounting to euro 270 million related to the favorable settlement of an antitrust proceeding resulting in a provision accrued in previous reporting periods being reversed almost entirely to 2010 profit. The provision was originally accrued to take into account a resolution of the Italian Antitrust Authority, who charged Eni with anti-competitive behavior for having allegedly refused third party access to the pipeline for importing natural gas from Algeria.

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 USA. 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.

The table below sets forth break-down of operating profit by businesses in the Gas & Power Division:

	Year ended December 31,

		2008		2009		2010

(euro million)

Marketing		1,806		1,530		555
Regulated businesses in Italy		1,701		1,773		1,998
International transport		523		384		343
Operating profit of the Gas & Power Division		4,030		3,687		2,896

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Refining & Marketing. In 2010, the Refining & Marketing segment reported an operating profit of euro 149 million, compared to the prior-year loss of euro 102 million. The improvement reflected a less adverse refining scenario with Eni’s complex refineries helped by widening price differentials between sour and sweet crudes and better spreads of middle distillates to heating fuel. Refining margins still remained unprofitable as high oil feedstock prices were only partially transferred to final prices of refined products pressured by weak industry fundamentals. The Eni Refining business also benefited from cost efficiencies and various optimization measures in supply and refining activities, and integration of refinery cycles whereby the Gela refinery have begun processing heavy residues from Taranto throughputs thus enabling to reap cost savings and margins improvements. The Marketing business was affected by rapidly rising supply costs that were only partially transferred to prices at the pump, and lower retail sales in Italy. These negatives were partly offset by higher sales on European networks. Results of Refining & Marketing Division also benefited from the circumstance that in 2009 material impairment charges were recorded to align the carrying amounts of unprofitable refining and marketing assets to their projected recoverable amounts (down by euro 313 million).

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 absorb 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.

Petrochemicals. In 2010, the Petrochemical Division recorded a sharp reduction in its operating loss which was down by 87.3% from the year-earlier (from a loss of euro 675 million in 2009 to a loss of euro 86 million in 2010). This positive result reflected better market conditions and a recovery in demand which drove improved product margins and higher sales (up by 10.9% mainly in the elastomers business area). Profitability was also supported by cost efficiencies. An inventory holding gain amounting to euro 105 million was recognized (compared with a loss of euro 121 million in 2009) reflecting the impact of higher oil-based feedstock and commodity prices on year end valuation of inventories according to the average cost method of inventory accounting, as well as lower asset impairments (down by euro 69 million).

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%).

Engineering & Construction. Operating profit in 2010 amounted to euro 1,302 million, an increase of euro 421 million, or 47.8% compared to 2009. This increase was driven by a positive operating performance reported by the Onshore Construction and Offshore Drilling business areas reflecting higher activity levels and higher margins on the works performed. The utilization rate of the Perro Negro 6 jack-up and the semisubmersibles Scarabeo 3 and 4 increased. In addition, the comparison with 2009 benefited from the circumstance that in 2009 a charge amounting to euro 250 million was recorded to settle the TSKJ legal proceeding "Item 8 – Financial Information – Legal Proceedings" for further details.

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 34 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 impact of the charge, the segment reported an improved operating performance recorded in all business areas reflecting steady revenue

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growth and stable profitability as a result of the large number of oil and gas projects that were started during the upward phase of the oil cycle.

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 1,384 million for 2010, representing a sharply higher increase of euro 948 million compared to the loss recorded in 2009 (euro 436 million) mainly due to higher environmental provisions recorded to account for a proposed global transaction on certain environmental issues (euro 1,109 million) filed with the Italian Ministry for the Environment, which is disclosed in the paragraph "Significant Transactions" below.

Other activities reported an operating loss of euro 436 million for 2009, representing an improvement of euro 30 million, or 6.4%, compared to the loss recorded in 2008 (euro 466 million) mainly due to lower environmental charges.

Corporate and financial companies. These activities are mainly cost centers which comprise corporate activities and central treasury departments and financial and other subsidiaries that provide a range of financial and business support services to Group companies, including financing of Eni’s projects around the world, information technology, employee selection, training and retention, real estate and other general purposes services.

The aggregate Corporate and financial companies reported an operating loss of euro 361 million for 2010, representing a reduction of euro 59 million, compared to the loss recorded in 2009 (euro 420 million), mainly reflecting the implementation of cost efficiency measures.

The aggregate Corporate and financial companies reported an operating loss of euro 420 million for 2009, representing a reduction of euro 203 million, compared to the loss recorded in 2008 (euro 623 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.

 

e) Net Finance Expense

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

	Year ended December 31,

		2008		2009		2010

(euro million)

Gain (loss) on derivative financial instruments		(427	)		(4	)		(131	)
Exchange differences, net		206			(106	)		92
Interest income		87			33			18
Finance expense on short and long-term debt		(993	)		(753	)		(766	)
Finance expense due to the passage of time		(249	)		(218	)		(251	)
Income from equity instruments		241			163
Other finance income and expense, net		259			111			124
		(876	)		(774	)		(914	)
Finance expense capitalized		236			223			187
		(640	)		(551	)		(727	)

2010 compared to 2009. In 2010, net finance expense increased by euro 176 million to euro 727 million from 2009, mainly due to the circumstance that in 2009 a finance gain of euro 163 million was recorded under "Income from equity instruments" due to the contractual remuneration on the 20% interest in OAO Gazprom Neft, earned until such interest was divested on April 24, 2009. Higher losses were recognized in connection with fair value evaluation through profit and loss of certain derivative instruments on exchange rates (up euro 127 million) that did not meet all formal criteria to be designated as hedges under IFRS. Those losses were more than offset by net positive exchange rate differences (euro 198 million). The item "Exchange differences, net" includes a currency adjustment, amounting to euro 33 million, related to the loss provision accrued in the 2009 financial statements to take account of the TSKJ proceeding. Finance charges on finance debt were substantially in line with the previous

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year, as the impact associated with increased average net borrowings was offset by lower interest rates on both euro-denominated and U.S. dollar loans (down 0.4 percentage points the Euribor and the Libor rate).

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 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 U.S. 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.

 

f) Net Income from Investments

2010 compared to 2009. Net income from investments in 2010 was a net gain of euro 1,156 million and mainly related to: (i) Eni’s share of profit of entities accounted for with the equity method (euro 537 million), mainly in the Gas & Power and Exploration & Production Divisions; (ii) dividends received by entities accounted for at cost (euro 264 million), mainly relating to Nigeria LNG Ltd; and (iii) gains on disposal of interests (euro 332 million) related to the full divestment of Società Padana Energia (euro 169 million), a 25% stake in GreenStream (euro 93 million) including a gain from revaluing the residual interest in the venture, a 100% interest in the Belgian company Distri RE SA (euro 47 million) as well as a non-strategic interest of the Engineering & Construction Division (euro 17 million).

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.

 

g) Taxes

2010 compared to 2009. In 2010, income taxes amounted to euro 9,157 million, up euro 2,401 million from a year ago, or 35.5%, mainly reflecting higher income taxes currently payable by subsidiaries in the Exploration & Production Division operating outside Italy due to higher taxable profit.

The Group consolidated tax rate was lower compared to 2009, down from 56% to 55.4% (down 0.6 percentage points). This reduction was due to:

Those positive effects on the Group tax rate were partly offset by a higher percentage of taxable income reported by foreign subsidiaries in the Exploration & Production Division which bear a higher tax rate than the Group average tax rate.

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:

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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 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).

 

h) Non-controlling Interest

2010 compared to 2009. Net profit pertaining to non-controlling interest was euro 1,065 million, up from euro 950 million in 2009, and concerned primarily Snam Rete Gas SpA (euro 537 million) and Saipem SpA (euro 503 million).

2009 compared to 2008. Non-controlling 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).

 

Liquidity and Capital Resources

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

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

	Year ended December 31,

		2008		2009		2010

(euro million)

Net profit		9,558			5,317			7,383
Adjustments to reconcile net profit to net cash provided by operating activities:
- amortization and depreciation charges, impairment losses and other non monetary items		8,792			9,117			9,024
- net gains on disposal of assets		(219	)		(226	)		(552	)
- dividends, interest, taxes and other changes		9,399			6,843			9,368
Changes in working capital related to operations		4,489			(1,195	)		(1,720	)
Dividends received, taxes paid, interest (paid) received during the period		(10,218	)		(8,720	)		(8,809	)
Net cash provided by operating activities		21,801			11,136			14,694
Capital expenditures		(14,562	)		(13,695	)		(13,870	)
Investments and purchases of consolidated subsidiaries and businesses		(4,019	)		(2,323	)		(410	)
Disposals		979			3,595			1,113
Other cash flow related to investing activities (*)		644			101			202
Changes in short and long-term finance debt		980			3,841			2,272
Dividends paid and changes in non-controlling interests and reserves		(6,005	)		(2,956	)		(4,099	)
Effect of changes in consolidation and exchange differences		7			(30	)		39
Change in cash and cash equivalent for the year		(175	)		(331	)		(59	)
Cash and cash equivalent at the beginning of the year		2,114			1,939			1,608
Cash and cash equivalent at year end		1,939			1,608			1,549

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

	Year ended December 31,

		2008		2009		2010

(euro million)

Net cash provided from operating activities		21,801			11,136			14,694
Capital expenditures		(14,562	)		(13,695	)		(13,870	)
Acquisitions of investments and businesses		(4,019	)		(2,323	)		(410	)
Disposals		979			3,595			1,113
Other cash flow related to capital expenditures, investments and divestments		(267	)		(295	)		228
Net borrowings (1) of acquired companies		(286	)					(33	)
Net borrowings (1) of divested companies		181
Exchange differences on net borrowings and other changes		129			(141	)		(687	)
Dividends paid and changes in non-controlling interest and reserves		(6,005	)		(2,956	)		(4,099	)
Change in net borrowings (1)		(2,049	)		(4,679	)		(3,064	)
Net borrowings (1) at the beginning of the year		16,327			18,376			23,055
Net borrowings (1) at year end		18,376			23,055			26,119

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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.

 

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

In 2010, adjustments to reconcile net profit to net cash provided by operating activities mainly related to non-monetary charges and gains amounting to euro 9,024 million, which primarily regarded depreciation, depletion amortization and impairment charges of tangible and intangible assets (euro 9,579 million), gains on disposals of euro 552 million mainly relating to divestiture of certain interests as discussed under the caption "f) Net income from investments and properties in the Exploration & Production Division" and movements in net working capital. Adjustments to net profit also included income taxes (euro 9,157 million) and interest expenses (euro 571 million) accrued in the year as opposed to amounts actually paid.

Net profit for 2009 was adjusted to take into account non-monetary charges and gains amounting to euro 9,117 million, which primarily regarded depreciation, depletion amortization and impairment charges of tangible and intangible assets (euro 9,813 million), gains on disposals and movements in net working capital. Adjustments to net profit also included income taxes (euro 6,756 million) and interest expenses (euro 603 million) occurred in 2009 as opposed to amounts paid in the year.

 

a) Changes in Working Capital related to Operations

In 2010, changes in working capital absorbed cash flows amounting to a negative euro 1,720 million as a result of: (i) increasing oil, gas and petroleum products inventories (up euro 1,150 million) due to the impact of rising oil prices on inventories stated at the weighted average cost; and (ii) cash pre-payments amounting to euro 1,238 million made to the Company’s suppliers of gas under long-term gas supply contracts whereby the Company has the contractual obligation to lift minimum annual quantities of gas or, in case of failure, pre-pay the whole price or a portion of the price of those quantities as provided by the so-called take-or-pay clause. The Company recognized among its assets a deferred cost to account for those pre-paid volumes of gas. For further details on that asset see "Item 18 – Note 14 – Other non current assets – in Notes to the Consolidated Financial Statements".

These negatives were partly offset by an increased balance between trade payables and receivables also resulting by reduced trade receivables relating to the transfer of certain receivables without recourse to factoring institutions, amounting to euro 1,279 million due in 2011, increasing Group cash inflows.

In 2009, changes in working capital absorbed flows amounting to a negative euro 1,195 million as a result of a decreased balance between trade payables and receivables.

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b) Investing Activities

	Year ended December 31,

		2008		2009		2010

(euro million)

Exploration & Production		9,281			9,486			9,690
Gas & Power		2,058			1,686			1,685
Refining & Marketing		965			635			711
Petrochemicals		212			145			251
Engineering & Construction		2,027			1,630			1,552
Other activities		52			44			22
Corporate and financial companies		95			57			109
Impact of unrealized intragroup profit elimination		(128	)		12			(150	)
Capital expenditures		14,562			13,695			13,870
Acquisitions of investments and businesses		4,019			2,323			410
		18,581			16,018			14,280
Disposals		(979	)		(3,595	)		1,113
NET INVESTMENT		17,602			12,423			15,393

Capital expenditures totaled euro 13,870 million and euro 13,695 million in 2010 and 2009, respectively.

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

Acquisitions of investments and businesses totaled euro 410 million in 2010 and euro 2,323 million in 2009.

In 2010, disposals amounted to euro 1,113 million and mainly related to: (i) a second tranche of the divestment to Gazprom of a 51% stake in the joint venture OOO SeverEnergia by the shareholding company Artic Russia which is jointly participated by Eni and Enel (60% and 40% being their respective interests), following the exercise of a call option by the Russian company. The cash consideration of this second tranche was euro 526 million; (ii) divestment of non-strategic oil and gas properties in the Exploration & Production Division, for an overall amount of euro 456 million, including divestment of the entire stake in the subsidiary Società Padana Energia (euro 179 million); and (iii) the divestment of a 25% stake in GreenStream BV (euro 75 million).

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 and gas properties following agreements signed with Suez.

 

c) Dividends paid and Changes in Non-controlling Interests and Reserves

In 2010, dividends paid and changes in non-controlling interest and reserves (euro 4,099 million) mainly related to: (i) cash dividends to Eni shareholders (of which euro 1,811 million related to the balance for the dividend relating the fiscal year 2009 and euro 1,811 million as an interim dividend for fiscal year 2010); and (ii) the distribution of dividends to non-controlling interest by Snam Rete Gas SpA and Saipem SpA (euro 506 million) and other consolidated subsidiaries (euro 8 million).

In 2009, dividends paid and changes in non-controlling interest 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 non-controlling 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

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Eni’s reorganization of its regulated businesses in Italy. This transaction is outlined in "Item 4 – Significant business and portfolio developments for the year".

 

Financial Condition

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

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.

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,

		2008		2009		2010

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)		6,908			13,929		20,837			6,736			18,064		24,800			7,478			20,305		27,783
Cash and cash equivalents		(1,939	)				(1,939	)		(1,608	)				(1,608	)		(1,549	)				(1,549	)
Securities not related to operations		(185	)				(185	)		(64	)				(64	)		(109	)				(109	)
Non-operating financing receivables		(337	)				(337	)		(73	)				(73	)		(6	)				(6	)
Net borrowings		4,447			13,929		18,376			4,991			18,064		23,055			5,814			20,305		26,119

	As of December 31,

		2008		2009		2010

Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS		(euro million)		48,510			50,051			55,728
Ratio of total debt to total shareholders’ equity including non-controlling interest				0.43			0.50			0.50
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest				(0.05	)		(0.04	)		(0.03	)
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage)				0.38			0.46			0.47

At the end of 2010, net borrowings amounted to euro 26,119 million, representing a euro 3,064 million increase from 2009. This increase was mainly due to the large amount of capital expenditures made in the year, dividend payment to shareholders executed in the year and pre-payments to the Company’s suppliers of gas under long-term contracts upon triggering the take-or-pay clause. These outflows were only partially funded with cash flows from

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operations, divestments for the year and cash inflow from transferring certain account receivables without recourse to factoring institutions, amounting to euro 1,279 million due in 2011. As a result of an increased level of net borrowings, the Group leverage inched higher to 0.47 at December 31, 2010 from 0.46 as of end of 2009. The Group net equity increased due to net profit for the year and currency translation differences recorded in translating to euro amounts net equity of subsidiaries whose functional currency is the U.S. dollar due to the dollar revaluation in exchange rates recorded at year end (up by 7.3% due to the exchange rate recorded on December 31, 2010 at 1 euro = 1.336 US$ compared to 1 euro = 1.441 US$ at December 31, 2009).

Total debt of euro 27,783 million consisted of euro 7,478 million of short-term debt (including the portion of long-term debt due within 12 months equal to euro 963 million) and euro 20,305 million of long-term debt.

Total debt included bonds for euro 13,572 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to euro 192 million (including accrued interest and discount). Bonds issued in 2009 amounted to euro 2,614 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (79%), U.S. dollar (17%), pound sterling (2%) and 2% in other currencies.

At the end of 2009, net borrowings amounted to euro 23,055 million, representing an 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 24,800 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.

 

Short-term Debt

As of December 31, 2010, short-term debt of euro 7,478 million (including the portion of long-term debt due within twelve months) increased by euro 742 million over 2009. The weighted average interest rate of Eni’s short-term debt was 0.7% and 0.8% for the years ended December 31, 2010 and 2009, respectively.

At December 31, 2010 Eni had undrawn committed and uncommitted borrowing facilities amounting to euro 2,498 million and euro 7,860 million, respectively (euro 2,241 million and euro 9,533 million at December 31, 2009). These facilities bore interest rates reflecting prevailing financing conditions on the marketplace. Charges in unutilized facilities were not significant.

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.

 

Long-term Debt

As of December 31, 2010, long-term debt of euro 20,305 million increased by euro 2,241 million over 2009.

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 maintenance of a minimum level of credit rating. As of the balance sheet date, Eni was in compliance with those covenants. According to the agreements, should the Company fail to comply with maintenance of a minimum credit rating, new guarantees would be provided to be agreed upon with the European Investment Bank. At December 31, 2009 and 2010, the amount of short and long-term debt subject to restrictive covenants was euro 1,508 million and euro 1,685 million, respectively. During 2010, Saipem reimbursed financial debts conditioned to the maintenance of certain performance indicators (euro 75 million). Bonds of euro 13,572 million consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 10,678 million and other bonds for a total of euro 2,894 million.

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

 

Capital Expenditures by Segment

Exploration & Production. In 2010, capital expenditures of the Exploration & Production segment amounted to euro 9,690 million, representing an increase of euro 204 million, or 2.2%, from 2009 mainly due to the development of oil and gas reserves (euro 8,578 million). Significant expenditures were directed mainly outside Italy, in

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particular Egypt, Kazakhstan, Congo, the USA and Algeria. Development expenditures in Italy concerned well drilling program and facility upgrading in Val d’Agri as well as sidetrack and infilling activities in mature fields. About 97% of exploration expenditures that amounted to euro 1,012 million were directed outside Italy in particular to Angola, Nigeria, the USA, Indonesia and Norway. In Italy, exploration activities were directed mainly to the offshore of Sicily.

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, the USA, 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 USA, 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.

Gas & Power. In 2010, capital expenditures in the Gas & Power segment totaled euro 1,685 million and mainly related to: (i) developing and upgrading Eni’s transport network in Italy (euro 842 million); (ii) developing and upgrading Eni’s distribution network in Italy (euro 328 million); (iii) developing and upgrading Eni’s storage capacity in Italy (euro 250 million); (iv) completion of construction of the combined cycle power plants at the Ferrara site, upgrading and other initiatives to improve flexibility (euro 115 million); and (v) the upgrading plan of international pipelines (euro 17 million).

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).

Refining & Marketing. In 2010, capital expenditures in the Refining & Marketing Division amounted to euro 711 million and regarded mainly: (i) refining, supply and logistics in Italy (euro 446 million), with projects designed to improve the conversion rate and flexibility of refineries, in particular the Sannazzaro and Taranto refineries, as well as expenditures on health, safety and environmental upgrades; and (ii) upgrade of the refined product retail network in Italy and in the rest of Europe (euro 246 million). Expenditures on health, safety and the environment amounted to euro 143 million.

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.

Petrochemicals. In 2010, capital expenditures in the Petrochemical segment amounted to euro 251 million (euro 145 million in 2009) and regarded mainly plant upgrades (euro 116 million), up-keeping (euro 59 million), energy recovery (euro 45 million) and environmental protection, safety and environmental regulation compliance (euro 29 million).

In 2009, 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), up-keeping and rationalization (euro 20 million).

Engineering & Construction. In 2010, capital expenditures in the Engineering & Construction Division (euro 1,552 million) mainly regarded:

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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.

 

Recent Developments

Trading Environment

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

		Three months ended March 31,

		2010		2011

Average price of Brent dated crude oil in U.S. dollars (1)		76.24		104.97
Average price of Brent dated crude oil in euro (2)		55.09		76.73
Average EUR/USD exchange rate (3)		1.384		1.371
Average European refining margin in U.S. dollars (4)		2.40		1.74
EURIBOR - three month euro rate % (3)		0.6		1.0

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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.

 

Status of Our Libyan Operations

From February 22, 2011, liquids and natural gas production at a number of fields in Libya and supplies through the GreenStream pipeline have been halted as a result of ongoing political instability and conflict in the Country. Facilities have not suffered any damage and such standstills do not affect Eni’s ability to ensure natural gas supplies to its customers. Eni is technically able to resume gas production at or near previous levels once the situation stabilizes. The overall impact of the Libyan political instability and conflict on Eni’s results of operations and cash flows will depend on how long such situation will last as well as on their outcome, which management is currently unable to predict. Eni’s oil and natural gas production as of end March 2011, was flowing at a rate ranging from 70 to 75 KBBL/d, down from the expected level of approximately 280 KBBL/d. Production is continuing to decline. Current production mainly consists of gas that is entirely delivered to local power generation plants. For further discussion on risks and management outlook on the Libyan situation see “Item 3 – Risk Factors – Political Considerations” and “Item 5 – Outlook”.

 

Significant Transactions

In 2010, Eni committed to divest its interests in certain international gas pipelines to settle an antitrust proceeding before the European Commission concerning alleged anti-competitive behavior in the natural gas market ascribed to Eni. Eni was not charged with any illicit behavior and consequently no fines or sanctions were imposed. The Commission accepted Eni’s commitments as of September 29, 2010. Currently, procedures for the divestment of Eni’s interests in the German TENP, the Swiss Transitgas and the Austrian TAG gas transport pipelines and relevant carrier companies are progressing. 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. For further details on the matter see "Item 8 – Legal Proceedings".

In January 2011, the Parent Company Eni SpA also on behalf of other Group companies (including in particular Syndial) filed a proposal with the Italian Ministry for the Environment to enter into a global settlement related to nine sites of national interest (Priolo, Napoli Orientale, Brindisi, Pieve Vergonte, Cengio, Crotone, Mantova, Porto Torres and Gela) where the Group companies have started, as guiltless owners of a number of

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industrial areas, environmental restoration and clean-up activities. The proposal includes a definition of a number of pending proceedings relating to clean-up issues and environmental damage. The framework of the transaction proposal includes: (i) a global environmental transaction as per Article 2 of Law Decree No. 208/2008 (related to the Pieve Vergonte, Cengio, Crotone, Mantova, Porto Torres and Gela sites); (ii) certain environmental framework agreements that have already been signed by relevant administrative bodies and which interested businesses may adhere to (related to the Priolo, Brindisi and Napoli Orientale sites); and (iii) the settlement of a civil lawsuit regarding environmental damage at the Pieve Vergonte site. Briefly, Eni and its subsidiaries through the proposal:

As a result of the filing of the proposal of global settlement following thorough and extended contacts with the public bodies, Eni took a charge amounting to euro 1,109 million to the environmental provision in its 2010 consolidated accounts, with a net effect on profit for 2010 full year of euro 783 million including the tax impact of the operation. The charge had no effect on the Group’s consolidated net borrowings at period end. In case of finalization of the global transaction, the payment of the accrued amount will be made progressively according to the agreements applicable to each site. A complex administrative procedure is going to start following the presentation of Eni’s proposal to the Ministry. That entity is responsible for drafting a framework transaction which will undergo technical review on the part of all interested administrative bodies including public and local authorities. Finally, the transaction signed by Eni is due to be ratified by the Italian Council of Ministers.

The Company’s Annual General Shareholders Meeting scheduled on April 29 and May 5, 2011, is due to approve the full-year dividend proposal. Eni expects to pay the balance of the dividend for fiscal year 2010 amounting to euro 0.50 per share in May 2011. Total cash out is estimated at euro 1.81 billion.

 

Outlook

Management expects that the global economic recovery will progressively strengthen across the year 2011. Nonetheless, the 2011 outlook is characterized by a certain degree of uncertainty and volatility also in light of ongoing political instability and conflict in Libya. Eni forecasts an upward trend for Brent crude oil prices supported by healthier global oil demand. For capital budgeting and planning purposes, Eni assumes an average Brent price of 70 $/BBL for the full year 2011. Management expects that the European gas market will remain weak as sluggish demand growth is insufficient to absorb current oversupplies. Refining margins are expected to remain unprofitable due to weak underlying fundamentals and high feedstock costs. Against this backdrop, management expectations about the main trends in the Company’s businesses for 2011 and beyond are disclosed below.

 

Exploration & Production

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Gas & Power

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Refining & Marketing

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Engineering & Construction

 

Petrochemicals

 

Capital Expenditure plans

Over the next four years, the Company plans to invest euro 53.3 billion in its businesses to support continued organic growth; approximately 73%, 14%, 5.4% and 4.5% of planned capital expenditures is expected be directed to the Exploration & Production, Gas & Power, Refining & Marketing and Engineering & Construction segments, respectively.

The main planned projects are as follows: (i) development of oil and gas reserves mainly in Iraq, Norway, Kazakhstan, Angola, Italy, Congo, Nigeria, Algeria and the USA; (ii) exploration projects to be executed mainly in the USA, Egypt, Angola, Italy, Australia, Nigeria and Norway; (iii) upgrading of national pipelines for transporting natural gas, as well as upgrading of Italian distribution networks and gas storage capacity; (iv) completion of the upgrading and new vessel construction program in the Engineering & Construction segment; (v) refinery upgrading, targeting an increase in conversion capacity mainly by completing the EST project at the Sannazzaro refinery; and (vi) upgrading of Eni’s networks of service stations for marketing petroleum products.

Eni’s capital expenditure program is expected to increase by approximately 1% compared to the previous industrial plan due to planned expenditures for developing new upstream projects, particularly those associated with reserves development in Iraq, and offshore Angola, the circumstance that the Company is forecasting steady trends in costs for materials and sector specific services in its upstream projects and the assumption of the U.S. dollar appreciation against the euro. Lower capital expenditures are associated with the completion of the plan for upgrading the fleet of vessels and offshore rigs of Saipem.

For the year 2011, management plans to make capital expenditures of approximately euro 14 billion which is broadly in line with 2010 (euro 13.87 billion were invested in 2010), and will mainly be directed to developing large fields and starting production at new important fields in the Exploration & Production Division, refinery upgrading related in particular to the realization of the EST project, completing the program of enhancing Saipem’s fleet of vessels and rigs, and upgrading the natural gas transport infrastructure.

Management expects to pursue strict capital discipline when assessing individual capital projects. Management assumed an oil price of 70 $/BBL flat in the next four-year period; longer-term management assumed an oil price of 70 $/BBL that is adjusted to take account of expected inflation from 2015 onwards. The internal rate of return of each project is compared to the relevant hurdle rate, differentiated by business segment and country of operation. These hurdle rates are calculated taking into account: (i) the weighted average cost of capital to the Group. In 2010 management assessed that the cost of capital to the Group decreased by 0.5 percentage points on average from the previous year reflecting a reduced market premium for the equity risk and a slight decrease in the cost of borrowings to Eni following expected trends in the main market benchmarks. Such trends were partially offset by increased market yields on assets risk-free due to a higher risk premium for Italy; (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.

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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 70 $/BBL for the years 2011-2014 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, 2011 was 104.97 $/BBL on average and it was 118.62 $/BBL as of April 1, 2011. Management plans for achieving a reduction in the ratio of net borrowings to total equity ("leverage") in 2011 compared to end of the year 2010 also taking into account the planned divestment of assets for an amount of euro 2 billion. Looking forward, management intends to seek to progressively reduce this ratio to below 40% by the end of the plan period leveraging on future cash flow from operations.

For planning purposes, management assumed an average exchange rate of approximately 1.30 U.S. dollars per euro in the 2011-2014 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty. See "Item 3 – Risk Factors".

 

Dividend policy

In the next four-year period management intends to pursue a progressive dividend policy. Management plans to pay euro 1.00 a share dividend for 2010 subject to approval from the General Shareholders’ Meeting scheduled on May 5, 2011. Of this, euro 0.50 per share was paid in September 2010 as an interim dividend with the balance of euro 0.50 per share expected to be paid late in May 2011. For the year 2011, management plans to start growing the dividend in line with OECD inflation. This dividend policy is based on management’s planning assumptions for oil prices at 70 $/BBL flat in the 2011-2014 period. If management assumptions on oil prices were to change, management may revise the dividend and reset the basis for progressive dividend increases. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year.

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

 

Off-Balance Sheet Arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in Note 34 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

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has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in Note 34 to the Consolidated Financial Statements.

 

Contractual Obligations

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

	Maturity year

	Total		2011		2012		2013		2014		2015		2016 and thereafter

(euro million)

Total debt		29,415		8,609		3,859		2,559		2,027		2,863		9,498
Long-term finance debt		21,268		963		3,583		2,485		2,009		2,815		9,413
Short-term finance debt		6,515		6,515
Fair value of derivative instruments		1,632		1,131		276		74		18		48		85
Interest on finance debt		4,835		720		712		654		563		460		1,726
Guarantees to banks		339		339
Non-cancelable operating lease obligations (1)		4,053		1,023		863		587		517		311		752
Decommissioning liabilities (2)		12,726		44		60		116		362		146		11,998
Environmental liabilities (3)		2,014		338		307		261		263		184		661
Purchase obligations (4)		259,914		16,891		15,425		15,896		15,970		15,734		179,998
Natural gas to be purchased in connection with take-or-pay contracts (5)		246,889		15,708		14,403		14,961		15,004		14,788		172,025
Natural gas to be transported in connection with ship-or-pay contracts (5)		8,363		794		708		646		668		655		4,892
Other take-or-pay and ship-or-pay obligations		1,979		169		160		165		175		168		1,142
Other purchase obligations (6)		2,683		220		154		124		123		123		1,939
Other obligations (7)		149		4		4		4		4		4		129
of which:
- Memorandum of intent relating to Val d’Agri		149		4		4		4		4		4		129
TOTAL		313,445		27,968		21,230		20,077		19,706		19,702		204,762

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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)	i	Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(3)		Environmental liabilities do not include the environmental charge amounting to euro 1,109 million for the proposal to the Ministry for the Environment to enter into a global transaction related to nine sites of national interest because the dates of payment cannot be reasonably estimated.
(4)	i	Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(5)		Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See "Item 4 – Gas & Power – Natural Gas Purchases" and "Item 3 – Risk Factors – Liberalization of the Italian Natural Gas Market" for a discussion of nature and importance of Eni’s take-or-pay contracts and the related risks from the evolving regulatory environment that could negatively impact Eni’s results.
(6)	i	Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the USA.
(7)	i	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, 2010. 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. Major projects are authorized by the Company’s Board of Directors, each of those projects generally entails expenditures in excess of euro 300 million.

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	Total		2011		2012		2013		2014		2015 and thereafter

Committed on major projects		25,616		5,443		5,606		2,867		3,304		8,396
Other committed projects		24,982		7,210		4,700		4,253		2,802		6,017
TOTAL		50,598		12,653		10,306		7,120		6,106		14,413

 

Liquidity Risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. For a description of how the Company manages the liquidity risk see "Item 18 – Note 34 to the Consolidated Financial Statements".

At December 31, 2010, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 10,358 million, of which euro 2,498 million were committed, and long-term committed unused borrowing facilities of euro 4,901 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 about euro 10.4 million were drawn as of December 31, 2010.

The Group has debt ratings of A+ and A-1 respectively for long (outlook stable) and short-term debt assigned by Standard & Poor’s and Aa3 and P-1 (outlook stable) assigned by Moody’s.

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. For a description of how the Company manages the Credit risk see "Item 18 – Note 34 to the Consolidated Financial Statements". For information about credit losses in 2010 and the allowance for doubtful accounts see "Item 18 – Note 9 to the Consolidated Financial Statements".

 

Market Risk

In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro versus other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see "Item 18 – Note 34 to the Consolidated Financial Statements".

 

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 2011:

Name		Position		Year elected or appointed		Age
Roberto Poli		Chairman		2002		73
Paolo Scaroni		CEO		2005		65
Alberto Clô		Director		1999		64
Paolo Andrea Colombo		Director		2008		51
Paolo Marchioni		Director		2008		42
Marco Reboa		Director		2005		56
Mario Resca		Director		2002		66
Pierluigi Scibetta		Director		2005		52
Francesco Taranto		Director		2008		71

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 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 for Economic Development, may appoint another member of the Board of Directors, without voting rights, in addition to those appointed by the Shareholders’ Meeting. On the occasion of the last Board appointment, the Minister of Economy and Finance opted not to exercise that power.

Roberto Poli Born in 1938. He has been Chairman of the Board of Eni SpA since May 2002. He is Chairman of Poli e Associati SpA, a consultancy firm for corporate finance, extraordinary operations, company acquisitions and restructurings. He is currently Director of Mondadori SpA, Fininvest SpA, Coesia SpA, Maire Tecnimont SpA and Perennius Capital Partners SGR SpA. From 1966 to 1998 he was professor of corporate finance at the Università Cattolica del Sacro Cuore, in Milan. He was an advisor for extraordinary finance operations for some of Italy’s leading industrial groups. He was Chairman of Rizzoli-Corriere della Sera SpA and Publitalia SpA. In June 2008 he was decorated as Cavaliere del Lavoro.

Paolo Scaroni Born in 1946. He has been Chief Executive Officer of Eni since June 2005. He is currently Director of Assicurazioni Generali, Non-Executive Deputy Chairman of the London Stock Exchange Group, Director of Veolia Environnement. He is also member of the Board of Overseers of Columbia Business School, in New York, and Director of Fondazione Teatro alla Scala. After graduating in Economics and Business at the Luigi Bocconi University, in Milan, in 1969, he worked for three years at Chevron, and obtained an MBA from Columbia University, in New York, and continued his career at McKinsey. In 1973 he joined Saint Gobain, where he held a series of managerial positions in Italy and abroad, until his appointment as Head of the Glass Division in Paris in 1984. From 1985 to 1996 he was Deputy Chairman and Chief Executive Officer of Techint. In 1996 he moved to the UK and was Chief Executive Officer of Pilkington until May 2002. From May 2002 to May 2005 he was Chief Executive Officer and Chief Operating Officer of Enel. From 2005 to July 2006 he was Chairman of Alliance Unichem. In May 2004 he was decorated as Cavaliere del Lavoro. In November 2007 he was decorated as Officer of the Légion d’honneur.

Alberto Clô Born in 1947. He has been a Director of Eni SpA since June 1999. He is currently Director of Atlantia SpA, Italcementi SpA, De Longhi SpA and IREN SpA. He graduated in Political Sciences at the University of Bologna, where he is currently professor of Industrial Economics and of Public Services Economics. In 1980 he founded the magazine "Energia" of which he is the editor. He is the author of many books and more than 100 essays and articles on industrial and energy economics and contributes to a number of newspapers and business magazines. In 1995 and 1996 he was Minister of Industry and ad interim Minister of Foreign Trade and also President of the Council of Industry and Energy Ministers of the European Union during the six-month Italian presidency. In 1996 he was decorated as Cavaliere di Gran Croce of the Republic of Italy.

Paolo Andrea Colombo Born in 1960. He has been a Director of Eni SpA since June 2008. After graduating in Business Administration in 1984 at the Luigi Bocconi University, in Milan, he qualified as a professional accountant

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and auditor in 1985. He is Lecturer in the Accounting Department at the Luigi Bocconi University, in Milan. He is founder partner of Borghesi Colombo & Associati, a consultancy firm specialized in corporate finance – including taxation and business consultancy in the context of extraordinary operations – as well as strategic and corporate governance consultancy. He is Director of Mediaset SpA and Ceresio SIM, Chairman of the Statutory Board of Aviva Vita SpA and GE Capital Interbanca SpA, Statutory Auditor of A. Moratti Sapa, Humanitas Mirasole SpA and Credit Agricole Assicurazioni Italia Holding SpA. He was effective Statutory Auditor of Eni SpA from May 2002 to May 2005, and he was Chairman of the Board of Statutory Auditors from May 2005 to May 2008.

Paolo Marchioni Born in 1969. He has been a Director of Eni SpA since June 2008. He is a qualified lawyer specializing in penal and administrative law, counselor in Supreme Court and superior jurisdictions. He acts as a consultant to government agencies and business organizations on business, corporate, administrative and local government law. He was Mayor of Baveno (Verbania) from April 1995 to June 2004 and Chairman of the Assembly of Mayors of Con.Ser.Vco from September 1995 to June 1999. Until June 2004 he was a member of the Assembly of Mayors of the Asl 14 health authority, the steering committee of the Verbania health district, the Assembly of Mayors of the Valle Ossola Waste Water Consortium, the Assembly of Mayors of the Verbania social services consortium. From April 2005 to January 2008 he was a member of Stresa city council. From October 2001 to April 2004 he was Director of C.i.m SpA of Novara (merchandise interport center) and from December 2002 to December 2005 Director and executive committee member of Finpiemonte SpA. From June 2005 to June 2008 he was Director of Consip. He has been Vice-president of Provincia del Verbano-Cusio-Ossola and provincial councilor in charge of budgeting, property, legal affairs and production activities since June 2009. He has been Chairman of the Board of Directors of Finpiemonte partecipazioni SpA since August 2010.

Marco Reboa Born in 1955. He has been a Director of Eni SpA since May 2005. He graduated in Business Administration at the Luigi Bocconi University, in Milan. He is a professional accountant and auditor. He is Professor at the Faculty of Law at the Carlo Cattaneo University - LIUC, in Castellanza, and author of many publications on corporate governance, economic evaluations and budget. He is the editor of "Rivista dei Dottori Commercialisti" and he is a professional advisor in Milan. He is a Director of Luxottica Group SpA and Interpump Group SpA. He is Chairman of the Board of Statutory Auditors of Mediobanca SpA. He is Statutory Auditor of Gruppo Lactalis Italia SpA, Egidio Galbani SpA and Big Srl.

Mario Resca Born in 1945. He has been Director of Eni SpA since May 2002. In 2008 he was appointed General Director of Italian Heritage and Antiquities in the Ministry of Cultural Heritage and Activities. He is Chairman of Confimprese. He is a Director of Mondadori SpA. He graduated in Economics at the Luigi Bocconi University, in Milan. After graduating he joined Chase Manhattan Bank. In 1974 he was appointed Manager of Saifi Finanziaria (Fiat Group) and from 1976 to 1991 he was a partner of Egon Zehnder. In this period he was Director of Lancôme Italia and of companies belonging to the RCS Corriere della Sera Group and the Versace Group. From 1995 to 2007 he was Chairman and Chief Executive Officer of McDonald’s Italia. He was also Chairman of Sambonet SpA and Kenwood Italia SpA, a founding partner of Eric Salmon & Partners and Chairman of the American Chamber of Commerce. He was decorated as Cavaliere del Lavoro in June 2002.

Pierluigi Scibetta Born in 1959. He has been a Director of Eni SpA since May 2005. He graduated in Economics at the University La Sapienza, in Rome. He is a professional accountant and auditor and 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 ISPESL, Nucleco SpA, FN SpA and AGITEC SpA; he was also Deputy Special 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. He is Chairman of Watch Structure of Gestore dei Mercati Energetici SpA.

Francesco Taranto Born in 1940. He has been a Director of Eni SpA since June 2008. He is currently a Director of Cassa di Risparmio di Firenze SpA. He began working in 1959, in a stock brokerage in Milan; from 1965 to 1982 he worked at Banco di Napoli as Deputy Manager of the stock market and securities department. He held a series of managerial positions in the asset management field, notably he was Manager of securities funds at Eurogest from 1982 to 1984, and General Manager of Interbancaria Gestioni from 1984 to 1987. After moving to the Prime group (1987 to 2000), he was Chief Executive Officer of the parent company for a long period. He was also a member of the steering council of Assogestioni and of the corporate governance committee for listed companies formed by Borsa Italiana. He was a Director of Enel from October 2000 to June 2008.

 

Senior Management

The table below sets forth the composition of Eni’s Senior Management, until December 31, 2010. 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.

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Name		Management position		Year first appointed to current position		Total number of year of service at Eni		Age
Paolo Scaroni		General Manager of Eni		2005		6		65
Claudio Descalzi		Exploration & Production Chief Operating Officer		2008		30		56
Domenico Dispenza		Gas & Power Chief Operating Officer		2005		37		65
Angelo Fanelli (*)		Refining & Marketing Chief Operating Officer		2010		30		59
Alessandro Bernini		Chief Financial Officer		2008		15		51
Salvatore Sardo		Chief Corporate Operations Officer		2008		6		59
Massimo Mantovani		General Counsel Legal Affairs Senior Executive Vice President		2006		18		48
Rita Marino (**)		Internal Audit Senior Executive Vice President		2008		6		47
Leonardo Maugeri (***)		Strategies and Development (****) Senior Executive Vice President		2000		16		46
Umberto Vergine (*****)		Studies and Researches (****) Senior Executive Vice President		2010		27		54
Stefano Lucchini		Public Affairs and Communication Senior Executive Vice President		2005		6		49
Roberto Ulissi		Company Secretary Corporate Affairs and Governance Senior Executive Vice President		2006		5		49
Raffaella Leone		Executive Assistant to the CEO		2005		6		49

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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 Committee⁷, 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 Milan in 1955. He graduated in Physics in 1979 at the University of Milan. He continued his studies with specialist courses in Petroleum Engineering in France and in the US. He joined the 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. Since July 30, 2008 he has been Eni SpA. Chief Operating Officer of the Exploration & Production Division.

Domenico Dispenza Born in Trieste in 1946. He has a degree in Aeronautical Engineering at the Politecnico of Milan. In 1973 he completed a Master’s degree in Advanced Technology at Sogesta in Urbino. Since January 2006 he has been Chief Operating Officer of Eni’s Gas & Power Division. He started 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

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Negotiator for Gas Sales and Purchase Agreement. From 1991 to 1999 he was Director of Gas Supplies. On June 30, 1999 he was appointed CEO 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. Domenico Dispenza is currently: CEO of Blue Stream Pipeline Company BV, Member of the Board of Eni Trading & Shipping SpA, Member of the Board of the Eni Foundation, Member of the Board of UNI and Member of the Executive Committee of Eurogas.

Angelo Fanelli Born in Rome in 1952. He has a degree in Mechanical Engineering at the University La Sapienza in Rome. After gaining experience at other companies, he joined the Eni Group in 1981, and in the first seven years held "field" positions in the Extra-network and Network markets as Technical Assistant, Lubricants and Sales Promoter on the Motorway Network. From 1988 to 1993 he was Head of the Bologna and Florence sales areas. From 1994 to 2004 he held a number of positions in the Network sector. He was appointed Head of Road Network Management, Head of the Ordinary Network and subsequently Head of Business Network Italy and Head of the Agip Road Transport Division, before becoming Head of Retail Business at the R&M Division. From 2003 to 2004 he was Chairman and Managing Director of AgipRete SpA. In 2004 he was appointed Commercial Director Italy, a job he held until 2005 when he took up the position of Head of Logistics at the Genoa headquarters. In 2006 he was appointed Commercial Director (Executive Vice President) of the Refining & Marketing. Since 2008 he has been a member of the board of Europia in Brussels. On April 6, 2010 he was appointed Chief Operating Officer of Eni SpA – Refining & Marketing.

Alessandro Bernini Born in 1960 in Borgonuovo Val Tidone, in the Province of Piacenza, Italy. He started his career in 1979 at Neutra Revisioni SaS, based in Milan, first as Junior Accountant in the Auditing Activities Department then as Accountant in Charge. In 1981, he joined Ernst & Young becoming thereafter Senior, Supervisor and Manager. On January 1, 1995 he was appointed Partner of the Company and Chartered Accountant Manager for the Areas of Piacenza, Parma and Cremona and Technical Manager for the branch based in Brescia. In the same period he was also engaged as a lecturer for post graduate master’s degree courses at the universities of Pavia and Parma. On the September 1, 1996 he joined the Eni Group as Administration Department Manager for Saipem SpA. In 2006 he was appointed Group Chief Financial Officer for Saipem SpA. He has covered executive managerial roles in many important companies of the Saipem Group. From August 1, 2008 he is Chief Financial Officer of the Eni Group.

Massimo Mantovani Born in Milan in 1963. He has a degree in Law and a Master in Law (LLM) at the University of London. He is registered to practice law in Italy and in England as solicitor. For about 5 years he worked for a number of law firms in Milan and London before joining the legal department of Snam SpA in 1993. In October 2005 he was appointed Legal Affairs Senior Executive Vice President of Eni SpA after being legal director of the Gas & Power Division of Eni. Since 2005 he has been a member of the Board of Directors of Snam Rete Gas SpA and is a member of the Eni Watch Structure of Eni SpA.

Rita Marino Born in 1964. She has been Chief Internal Auditor since July 2005 and Officer in charge of internal control since March 2007, and is a member of the Eni Watch Structure and Secretary of the Eni Internal Control Committee⁸. After gaduating in Economics and Business in 1987 at the 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 acquired extensive experience in the merger and acquisition activity, managing several 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.

Marco Petracchini Born in Rome in 1964. He graduated cum laude in Economics at the University La Sapienza in 1989, in Rome. After graduation, he was hired by Esso Italiana where he held a number of positions in the IT, finance and auditing sectors. He joined Eni in 1999, where he was rapidly promoted to the Internal Audit Department. Since January 2011 he has been Eni’s Executive Vice President of the Internal Audit Department Officer in charge of internal control function. He is also a member of the Control Body and Secretary of the Internal Control Committee of Eni SpA. He holds international qualifications, including that of Certified Internal Auditor (CIA), awarded by the Institute of Internal Auditors with which he also gained an honorable mention, and Certified Fraud Examiner (CFE), awarded by the Association of Certified Fraud Examiners.

Stefano Lucchini Born in Rome in 1962. He has a degree in Economics at the LUISS University in Rome. His first job was 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 (where he oversaw the company’s IPO) and subsequently as the group’s head of external relations. He has also been the head of external relations for Confindustria, the Italian employers’ federation. In June 2002 he was appointed

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head of external relations for the Banca Intesa Group. Since July 2005 he has been Senior Executive Vice President of Public Affairs and Communication Department for the Eni Group. He teaches at the Advanced School of Journalism at the Catholic University of Milan, for which he is also a member of the evaluation committee. He has been a member of the Board of Directors of AGI (the second Italian newswire company) since 2005. He is also a Commendatore della Repubblica Italiana and a Silver Medallist of the Italian Red Cross. 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. He is a Member of the Advisory Board MBA Program LUISS and a Member of the Committee of Guarantors for the celebrations of the 150^th Anniversary of Italian Unification. He is a visiting fellow of Oxford University and President of the Benedict XVI pro Matrimonio et Familia Foundation.

Umberto Vergine Born in Milan in 1957. He is a Chartered Civil Engineer from Politecnico of Milan and joined Eni in 1984. Having began his career as a petroleum engineer, he worked in Norway, Angola and Libya, and then as Production Manager in the Crema District in Italy until 1993. He has previously covered various leading positions overseas, managing different exploration and production projects for Eni’s companies. Between 1996 and 2001 he was District Manager of Agip UK in Aberdeen, District General Manager of Nigerian Agip Oil Co in Port Harcourt and General Manager of Petrobel Company in Egypt. In 2001, after the acquisition, he was Managing Director of Lasmo Venezuela in Caracas and at the end of 2002, he was appointed Managing Director of Ieoc in Cairo. Returned to Italy in 2004, before his current position, he held in Eni’s Exploration and Production Division the responsibilities of Senior Vice President for North Sea, Americas, Russia, Far East and Pacific, Senior Vice President of Technologies & Services, and Executive Vice President for South Europe, Central Asia, Far East and Pacific. Since April 2010 he has been of Senior Executive Vice President of Studies and Researches.

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 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 Rome in 1962. He is a lawyer. After several years as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of 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 Governing Council of the Bank of Italy. He was also a member of numerous Italian and European commissions representing the Ministry of Economy and Finance, including, at a national level, the Commission for the Reform of Corporate Law and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of banking law at the University of Cassino. He is a Grande Ufficiale della Repubblica Italiana. Since 2006 he has been Corporate Affairs and Governance Senior Executive Vice President at Eni and a member of the board of Eni International BV. He also holds the office of Company Secretary of Eni.

Raffaella Leone In Eni since 2005, she is the Executive Assistant to the CEO of Eni. She is President of Servizi Aerei SpA, Vice President of Eni Foundation, a 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.

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CHAIRMAN
The compensation of the Chairman of the Board of Directors has been resolved by Eni’s Shareholders’ Meeting and includes:

With regard to the powers delegated to the Chairman, the Board of Directors determined further compensation, as follows:

Compensation of the Chairman also includes an insurance against death or permanent inability caused by injury or sickness in the exercise of his duties or under certain other circumstances as stipulated collectively for all managers of Italian companies producing goods and services. In particular, a specific insurance policy has been underwritten which guarantees euro 500,000 to survivors.

 

CEO
Compensation for the CEO has been resolved by the Board of Directors of Eni in connection with his position both as CEO and as General Manager of the parent company Eni SpA.

As General Manager of Eni SpA, his terms of employment are regulated by the "Contratto collettivo nazionale di lavoro per i dirigenti di aziende produttrici di beni e servizi" (the Italian national collective contract for managers of companies producing goods and services), as well as by any internal agreement stipulated by the representatives of managers and Eni SpA.

The CEO compensation includes the following items:

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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:

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The Board of Directors in the meeting of June 11, 2008, reasserting its previous decision of 2006, 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:

With the exception of the CEO as described above, none of the Directors of Eni has service contracts with the Company or any of its subsidiaries providing for benefits upon termination of employment.

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Pursuant to Article 78 of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, including the latest Decision DEM/11012984 of February 24, 2011, the table below reports individual remuneration earned in 2010 by each member of the Board of Directors, Statutory Auditors and Division Chief Operating Officers. The overall amount earned by other managers with strategic responsibilities is reported too. Following the mentioned Consob Decision, the table reports the total amount of emoluments accrued in the 2010 financial statements, with separate evidence of amounts accrued in 2010 and yet to be paid and amount accrued in previous reporting periods which have been paid in 2010.

Name

Position

Term of office

Expiry date of the position (a)

Emoluments for service at Eni SpA

Committees membership emoluments

Non-monetary benefits

Bonuses and other incentives

Salaries and other remuneration

Emoluments accrued in 2010, total

Emoluments accrued in 2010, yet to be paid, total

Emoluments accrued in previous years paid in 2010, total

Emoluments paid in 2010, total

								(euro thousand)

Board of Directors
Roberto Poli		Chairman		01.01-12.31		04.2011		765							336						1,101						1,101
Paolo Scaroni		CEO and General Manager		01.01-12.31		04.2011		430	(b)				3		2,955	(c)		1,032			4,420						4,420
Alberto Clô		Director		01.01-12.31		04.2011		115			45										160		23		45		182
Paolo Andrea Colombo		Director		01.01-12.31		04.2011		115			36										151				94		245
Paolo Marchioni		Director		01.01-12.31		04.2011		115			20										135		39		49		145
Marco Reboa		Director		01.01-12.31		04.2011		115			45										160		160		160		160
Mario Resca		Director		01.01-12.31		04.2011		115			45										160		23		45		182
Pierluigi Scibetta		Director		01.01-12.31		04.2011		115			36										151				94		245
Francesco Taranto		Director		01.01-12.31		04.2011		115			36										151		18		36		169
Board of Statutory Auditors
Ugo Marinelli		Chairman		01.01-12.31		04.2011		115													115		57		57		115
Roberto Ferranti		Auditor		01.01-12.31		04.2011		80	(d)												80		40		40		80
Luigi Mandolesi		Auditor		01.01-12.31		04.2011		80													80		40		40		80
Tiziano Onesti		Auditor		01.01-12.31		04.2011		80										39	(e)		119		79		79		119
Giorgio Silva		Auditor		01.01-12.31		04.2011		80													80		40		80		120
Chief Operating Officers
Claudio Descalzi		Exploration & Production		01.01-12.31									2		886	(f)		1,267	(g)		2,155						2,155
Domenico Dispenza		Gas & Power		01.01-12.31									1		836	(h)		759			1,596						1,596
Angelo Caridi		Refining & Marketing		01.01-04.05											374			176	(i)		550						550
Angelo Fanelli		Refining & Marketing		04.06-12.31									1		116	(j)		376	(k)		493						493
Other managers with strategic responsibilities (l)													13		4,127	(m)		4,182			8,322						8,322
								2,435			263		20		9,630			7,831			20,179		519		819		20,479

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well as indemnities paid upon termination of the employment contract are reported within such column. Emoluments paid for positions held on the Board of Statutory Auditors in Eni’s subsidiaries are also reported.

Total compensation accrued in the year 2010 pertaining to all of board members amounted to euro 9.7 million; it amounted to euro 469,000 in the case of the Statutory Auditors. Such amounts include, in addition to each item of emolument reported in the table above, amounts accrued in the year for pension benefits, social security contributions and other elements of the remuneration associated with roles performed, which represent a cost for the Company.

For the year ended December 31, 2010, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, Chief Operating Officers and other managers with strategic responsibilities amounted to euro 33 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2010. The break-down is as follows:

	2010
	(euro million)

Fees and salaries		20
Post employment benefits		1
Other long-term benefits		10
Fair value stock grants/options		2
		33

The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay. As of December 31, 2010, 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 Chief Operating Officers of Eni’s Divisions and Eni’s senior managers, was euro 1,763 thousand.

The break-down of this amount is presented in the table below:

Name	(euro thousand)

Paolo Scaroni		CEO and General Manager of Eni		171
Claudio Descalzi		Chief Operating Officer of the E&P Division		312
Domenico Dispenza		Chief Operating Officer of the G&P Division		437
Angelo Fanelli		Chief Operating Officer of the R&M Division		225
Senior managers (a)				618
				1,763

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(a)

No. 8 managers.

 

Deferred Monetary Incentive

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% subject to achievement of a preset level of profitability in terms of EBITDA achieved in the reference three-year period as approved by the Board of Directors. The recipient or his/her heirs will preserve the right to participate in this scheme in definite measure with reference to the time period which elapses between grant and the possible occurrence of any of the following events: (i) termination of the employment contract by mutual consent; (ii) death of the recipient; (iii) loss of control by Eni SpA of the subsidiary where the recipient is employed; and (iv) divestment to a non-controlled entity of the subsidiary or the business where the recipient is employed. In case of unilateral termination of the employment contract, the right to the incentive expires. The following table sets out the basic bonus awarded in the year 2010 to the CEO and to the Chief Operating Officers of Eni’s Divisions, and the total amount awarded to the Company’s managers with strategic responsibilities.

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Name	Deferred bonus awarded
	(euro thousand)

Paolo Scaroni		CEO and General Manager of Eni		787
Claudio Descalzi		Chief Operating Officer of the E&P Division		275
Domenico Dispenza		Chief Operating Officer of the G&P Division		281
Angelo Fanelli		Chief Operating Officer of the R&M Division		194
Other managers with strategic responsibilities (a)				1,223

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(a)

No. 9 managers.

 

Long-term Monetary Incentive

Eni’s Board of Directors approved a new long-term monetary incentive scheme addressed to critical managerial resources in order to support achievement of better returns than those of the Company’s main competitors over the long-term. Managers involved in this scheme are in positions which are directly linked to the Company’ results or are otherwise of strategic interest to the Company. The scheme was intended to replace a stock-based compensation plan that was discontinued in 2009.

This plan provides for award of a base incentive to be paid after a vesting period of three years. The amount that will be actually paid is a percentage ranging from 0 to 130% of the base amount, and is subject to achievement of a performance parameter represented by a measure of Adjusted Net Profit + Depletion, Depreciation & Amortization (DD&A) recorded in the 2010-2012 three-year period as benchmarked to the performance achieved by a panel of the largest international oil companies by market capitalization. The recipient or his/her heirs will preserve the right to participate in this scheme in definite measure with reference to the time period which elapses between grant and the possible occurrence of any of the following events: (i) termination of the employment contract by mutual consent; (ii) death of the recipient; (iii) loss of control by Eni SpA of the subsidiary where the recipient is employed; and (iv) divestment to a non-controlled entity of the subsidiary or the business where the recipient is employed. In case of unilateral termination of the employment contract, the right to the incentive expires. A similar scheme was approved for the CEO and General Manager. In case of termination of his employment contract before the end of the vesting period, the incentive will still be paid when it vests on the basis of the assessment of the performance achieved in the reference three-year period. The following table sets out the bonuses awarded in 2010 to the CEO, the Chief Operating Officers of Eni’s Divisions, and the total amount awarded to the Company’s managers with strategic responsibilities.

Name	Long-term incentive awarded
	(euro thousand)

Paolo Scaroni		CEO and General Manager of Eni		2,501
Claudio Descalzi		Chief Operating Officer of the E&P Division		347
Domenico Dispenza		Chief Operating Officer of the G&P Division
Angelo Fanelli		Chief Operating Officer of the R&M Division		244
Other managers with strategic responsibilities (a)				1,597

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(a)

No. 9 managers.

 

Stock Options

At December 31, 2010, a total of 15,737,120 options were outstanding for the purchase of an equal amount of Eni ordinary shares with a nominal value of euro 1.00 at an average strike price of euro 23.005. The Company discontinued any stock-based compensation scheme in 2009; as such, options outstanding as of the end of the year pertained to stock options schemes adopted in previous reporting periods.

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The following table shows the evolution of stock option activity in 2009 and 2010.

	2009		2010

	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		23,557,425		23.540		16.556		19,482,330		23.576		17.811
New options granted
Options exercised in the period		2,000		13.743		16.207		88,500		14.941		16.048
Options cancelled in the period		4,073,095		23.374		14.866		3,656,710		26.242		16.918
Options outstanding as of December 31		19,482,330		23.576		17.811		15,737,120		23.005		16.398
of which exercisable as of December 31		7,298,155		21.843		17.811		8,896,125		23.362		16.398

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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 grant; (ii) the date of the recording in the securities account of the managers to whom the options have been granted; and (iii) the date of the unilateral termination of employment for rights cancelled). The market share price of grants outstanding as of the beginning and the end of the year, is the price recorded as of December 31.

Pursuant to Article 78 of Consob Decision No. 11971 of May 14, 1999, and to its subsequent modifications, the following table sets out the stock options awarded to the CEO, the Chief Operating Officers of Eni’s Divisions and to other managers with strategic responsibilities. As any stock-based compensation scheme was discontinued by the Company in 2009, options pertained to grants made in previous reporting periods ante 2009. The table shows also stock options of Directors who held a position in 2010 for a fraction of the year.

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						Other managers with strategic responsilities (a)
		Paolo Scaroni (b)		Claudio Descalzi		Domenico Dispenza				Angelo Caridi (c)				Angelo Fanelli (d)
Options outstanding at the beginning of the period:
- number of option		2,226,570		223,720		315,075	142,000	(e)		150,500	107,300			114,685		1,524,375	36,000	(g)
- average exercise price	(euro)	23.875		24.173		24.357	4.399			22.534	21.588			24.138		23.777	26.521
- average maturity in months		45		46		46	42			53	36			46		46	43
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											100,025	(f)					30,600	(g)
- average exercise price	(euro)										21.229						26.521
- average market price at date of exercise	(euro)										26.683						28.614
Options expired during the period:
- number of options		332,340		40,890		63,800				72,000	7,275	(f)		20,590		239,540	5,400	(g)
Options outstanding at the end of the period:
- number of options		1,894,230		182,830		251,275	142,000			78,500				94,095		1,284,835
- average exercise price	(euro)	23.247		23.439		23.571	4.399			22.528				23.413		23.092
- average maturity in months		33		34		35	30			19				35		35

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The recipient or his/her heirs will preserve the right to participate in these schemes in definite measure with reference to the time period which elapses between award and the possible occurrence of any of the following events: (i) termination of the employment contract by mutual consent; (ii) death of the recipient; (iii) loss of control by Eni SpA of the subsidiary where the recipient is employed; and (iv) divestment to a non-controlled entity of the subsidiary or the business where the recipient is employed. In case of unilateral termination of the employment contract, the abovementioned stock option rights expires.

 

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 core 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 of them 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. In a resolution dated June 11, 2008, the Board appointed Paolo Scaroni as CEO and General Manager entrusting him with the widest powers for the ordinary and extraordinary administration of the Company, while exclusively reserving the most important strategic, operational and organizational powers in addition to those that cannot be delegated by law.

In particular, 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 transactions⁹; 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 March 10, 2011 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

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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, at its meeting on March 10, 2011, 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 Italiana. The composition, role and functioning of these committees are governed by their relative regulations which are approved by the Board, in compliance with the criteria outlined in the Eni Code.

The committees required by the Code (Internal Control Committee and Compensation Committee) are composed of not less than three members and, in any case, fewer than the majority of members of the Board. The committees are currently composed of non-executive Directors, all of whom are 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. The Chairman of the Board of Statutory Auditors or a Statutory Auditor appointed by him may participate in Committee meetings. Non-members may also participate in committee meetings upon explicit invitation and with reference to specific topics on the agenda of the day. Minutes of all committee meetings are drafted by the respective secretaries. Committees’ meetings are summarized by the respective secretaries. The current members of the committees have been 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 Board of Directors regarding the remuneration payable to Directors with proxies and to the members of the Board’s committees 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. It performs the tasks assigned by the Management System Guideline on "Transactions involving interests of Directors and Statutory Auditors and transactions with related parties", adopted in November 2010 by the Board of Directors pursuant to Consob regulation of March 12, 2010.

During 2010, the Compensation Committee met six times, with a 100% attendance rate, and made proposals regarding: (i) Eni’s 2009 results and 2010 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 2009; (iii) the criteria of the remuneration policy for executives with strategic responsibilities; (iv) establishment of the 2010 Long-Term Monetary Incentive Plan for the CEO, to replace and compensate for the Eni Stock Option Plan; (v) implementation of the 2010 Long-Term Monetary Incentive Plan, to replace the Stock Option Plan, for critical managerial resources; and (vi) 2010 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.

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The Internal Control Committee, established within Eni in 1994, is entrusted with providing consulting and advisory services to the Board of Directors as regards the internal control system. It is exclusively made up of non-executive and independent Directors who possess the necessary skills for the tasks they are required to perform¹⁰.

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.

The periodic reports for the Board of Directors are drafted by the Committee by taking into account the opinions expressed – in their respective periodic reports – by the Officer in charge of preparing financial reports, the Officer in charge of Internal Control, the Eni Watch Structure and, in general, on the basis of the evidence acquired in carrying out its activities. In particular, the Internal Control Committee performs the following activities:

 

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 members) who shall comply with specific independence, expertise and integrity requirements.

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The members of the Board of Statutory Auditors were elected by the Ordinary Shareholders’ Meeting held on June 10, 2008 for a three financial year term, until the Shareholders’ Meeting approval of Eni’s 2010 Financial Statements.

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 of correct administration, the adequacy of the Company’s organizational structure for matters within the scope of the Board itself, the adequacy of the internal control system and of the administrative-accounting system, as well as the reliability of the latter in correctly representing the Company’s transactions; (iii) the arrangements for implementing the corporate governance rules provided for in the Code of Borsa Italiana to which the Company adheres; and (iv) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.

Moreover, under Article 19 of Legislative Decree No. 39/2010, the Board shall perform the functions assigned to it as "audit committee and internal auditing". In this capacity, the Board supervises (a) the financial reporting process, (b) the effectiveness of internal control systems, internal audit, if applicable, and risk management, (c) the audit of annual accounts and consolidated accounts, and (d) the independence of auditors or audit firms, particularly as regards the provision of non-audit services.

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 addition, pursuant to Article 19, paragraph 1, letters c) and d) of the Legislative Decree No. 39/2010, it monitors auditing activities and, also in compliance with the provisions of Article 10.C.5. of Eni Code, the independence of the Audit firm, the compliance of the latter with all applicable regulatory provisions as well as the nature and size of non-auditing services provided to Eni Group, either directly or through companies within Audit firm’s 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 allowed 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 Audit Committee as provided for by SEC rules are as follows:

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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 injuction, 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 Structure¹¹. 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 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 Senior Executive Vice President of Legal Affairs, the Executive Vice President of Human Resources and Organization and the Senior Executive Vice President of Internal Audit Department of the Company (or their direct reports).

 

Audit firm

The auditing of the Company’s accounts is entrusted, as per current legislation, to an independent audit firm whose appointment falls under the competency of the Shareholders’ Meeting, upon the Board of Statutory Auditors opinion.

In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit firm issues a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the USA. Moreover, the Audit firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting.

For the most part, the subsidiaries’ financial statements are subject to auditing by Eni’s Audit firm. Moreover, Eni’s Audit firm, for the purpose of issuing an opinion on the consolidated financial statements, assumes the responsibility for the auditing activities performed by other audit firms with respect to subsidiaries’ financial statements, which represent altogether an irrelevant part of the company’s assets and consolidated turnover.

Upon the Board of Statutory Auditors’ opinion, the Shareholders’ Meeting of April 29, 2010 appointed Reconta Ernst & Young SpA for the financial years 2010-2018.

 

Court of Auditors ("Corte dei conti")

The financial management of Eni is monitored by the Court of Auditors (Italian "Corte dei conti") in order to protect public finances. This activity has been carried out by the Court Judge, Raffaele Squitieri (whose substitute is

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Amedeo Federici), appointed on October 28, 2009. The Court Judge attends the meetings of the Board of Directors, of the Board of Statutory Auditors and of the Internal Control Committee.

 

Employees

As of December 31, 2010, Eni had a total of 79,941 employees, an increase of 2,223 employees, or 2.9% from December 31, 2009, which reflects an increase of 3,334 employees hired and working outside Italy and a decrease of 1,111 employees hired in Italy.

Employees hired in Italy were 33,974 (42.5% of all Group employees). During the year 2,439 persons left their job at Eni, of these 1,842 had an open-end contract and 597 a fixed-term contract. Declines were registered in all business segments due to efficiency actions.

The process of improvement in the quality mix of employees continued in 2010 with the hiring of 1,516 persons, of which 703 had fixed-term contracts. A total of 813 persons were hired with open-ended and apprenticeship contracts, most of them with university qualifications (412 persons) and 355 persons with a high school diploma.

Employees hired and working outside Italy were 45,967 (57.5% of all Group employees), an increase of 3,334 persons, mainly in the Engineering & Construction segment due to new contracts, in France in the Gas & Power segment (Altergaz) and in Austria in the Refining & Marketing segment.

Employees at year end		2008		2009		2010

(units)

Exploration & Production		10,236		10,271		10,276
Gas & Power		11,692		11,404		11,245
Refining & Marketing		8,327		8,166		8,022
Petrochemicals		6,274		6,068		5,972
Engineering & Construction		35,629		35,969		38,826
Other activities		1,070		968		939
Corporate and financial companies		4,866		4,872		4,661
		78,094		77,718		79,941

 

 

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The table below sets forth Eni’s employees as of December 31, 2008, 2009 and 2010 in Italy and outside Italy:

		2008		2009		2010

(units)

Exploration & Production	Italy		4,054		3,883		3,906
	Outside Italy		6,182		6,388		6,370
			10,236		10,271		10,276
Gas & Power	Italy		9,029		8,842		8,652
	Outside Italy		2,663		2,562		2,593
			11,692		11,404		11,245
Refining & Marketing	Italy		6,609		6,467		6,162
	Outside Italy		1,718		1,699		1,860
			8,327		8,166		8,022
Petrochemicals	Italy		5,224		5,045		4,903
	Outside Italy		1,050		1,023		1,069
			6,274		6,068		5,972
Engineering & Construction	Italy		5,420		5,174		4,915
	Outside Italy		30,209		30,795		33,911
			35,629		35,969		38,826
Other activities	Italy		1,070		968		939
	Outside Italy		-		-		-
			1,070		968		939
Corporate and financial companies	Italy		4,717		4,706		4,497
	Outside Italy		149		166		164
			4,866		4,872		4,661
Total	Italy		36,123		35,085		33,974
Total	Outside Italy		41,971		42,633		45,967
			78,094		77,718		79,941
of which senior managers			1,594		1,562		1,574

 

Share Ownership

As of February 28, 2011, the cumulative number of shares owned by Eni’s directors, statutory auditors and senior managers, including the three Chief Operating Officers, was 239,189 less than 0.1% of Eni’s share capital outstanding as of the same data. Eni issues only ordinary shares, each bearing one-vote right; therefore shares held by those persons have no different voting rights. The break-down of share ownership for each of those persons is provided below.

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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 Fanelli		Chief Operating Officer of the R&M Division		30,800		4,095
Board of Statutory Auditors				1,000
Senior managers				24,219		1,025,560

 

Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

As of March 21, 2011, 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		157,552,137		3.93
Cassa Depositi e Prestiti (a)		1,056,179,478		26.37

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The following mutual funds reported to hold more than 2% of Eni’s share capital: (i) Capital Research and Management for a total number of shares corresponding to 2.01% of Eni’s ordinary share capital on July 10, 2009; and (ii) Blackrock Investment Inc for a total number of shares corresponding to 2.68% of Eni’s ordinary share capital on May 20, 2010.

The Ministry of Economy and Finance, in agreement with the Ministry for 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 21, 2011 there were 35,091,381 ADRs, each representing two Eni ordinary shares outstanding corresponding to approximately 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 as other companies owned or controlled by the Italian Government. All such transactions are conducted on an arm’s length basis and in the interest of Eni companies.

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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 42 to the Consolidated Financial Statements.

 

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 34 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 70 $/BBL flat over the next four years, management plans to grow the dividend in line with OECD inflation from 2011. If management assumptions on oil prices were to change, management may revise the dividend and reset the basis for progressive dividend increases.

Management intends to propose to the Annual Shareholders’ Meeting scheduled on May 5, 2011, the distribution of a dividend of euro 1.00 per share for fiscal year 2010, of which euro 0.50 was already paid as interim dividend in September 2010. Total cash outlay for the 2010 dividend is expected at approximately euro 3.6 billion (including the euro 1.8 billion already paid in September 2010) 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 2010 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 (Electronic Share Market or "MTA"). MTA, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA ("Borsa

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Italiana"). Eni’s American Depositary Receipts ("ADRs"), each representing two Shares, are listed on the New York Stock Exchange. The ratio has changed from one ADR per five Shares to one ADR per two Shares, effective January 10, 2006.

The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs on the New York Stock Exchange, respectively. 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.

	MTA		New York Stock Exchange

	High		Low		High		Low

(euro per share)

(U.S. $ per ADR)

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
2010		18.560		14.610		53.890		35.370
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
2010
First quarter		18.560		16.010		53.890		43.950
Second quarter		17.800		14.610		48.550		35.370
Third quarter		16.590		14.710		43.870		36.970
Fourth quarter		16.670		15.350		46.950		40.320
2011
First quarter
January 2011		17.720		16.420		48.820		43.990
February 2011		18.420		17.080		50.300		46.680
March 2011 (through March 21, 2011)		17.950		16.520		49.770		45.380

JPMorgan Chase Bank NA (the "Depositary") functions as depositary bank issuing ADRs pursuant to a deposit agreement (the "Deposit Agreement") among Eni, the Depositary and the beneficial owners ("Beneficial Owners") and registered holders from time to time of ADRs issued hereunder.

As of March 21, 2011 there were 35,091,381 ADRs outstanding, representing 70,182,762 ordinary shares or approximately 2% of all Eni’s shares outstanding, held by 115 holders of record (including the Depository Trust Company) in the United States of America, 113 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 USA or elsewhere.

The Shares are included in the FTSE MIB Index (the "FTSE MIB"), the primary benchmark index for the Italian stock market. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on MTA and 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. The Shares are the first largest component of the FTSE MIB, with a weighting of approximately 15.1%, as established by FTSE after the quarterly rebalancing for FTSE MIB effective March 21, 2011.

Trading in the MTA is allowed in any quantity of the Shares as well as other financial instruments. Where necessary, Borsa Italiana may specify a minimum lot for each financial instrument. Since March 28, 2000, a three-day rolling cash settlement has been applied to all trades of equity securities in Italy, instead of the previous five-day settlement. In addition, future and option contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the Italian Securitized Derivatives Market ("SeDeX"). IDEM facilitates the

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trading of future and option contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic regulated market where it is possible to trade securitized derivatives (covered warrants and certificates).

Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an "official price", calculated as the weighted average price of the total volume of each security traded in the market during the session, and a "reference price", calculated as the closing-auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective December 20, 2010: (i) ± 5.0% (or such other amount established by Borsa Italiana in the "Guide to the Parameters" for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price shall be the previous day’s reference price, in the opening auction, or the auction price, in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the "Guide to the Parameters") with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time.

 

Markets

The Commissione Nazionale per le Società e la Borsa (the National Commission for Companies and the Stock Exchange or "Consob"), is the public authority responsible for regulating and supervising the Italian securities markets to ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of London Stock Exchange Group, following the merger effective October 1, 2007, is a joint stock company authorized by Consob to operate regulated markets in Italy; it is responsible for the organization and management of the Italian stock exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of responsibility for supervision (Consob and the Bank of Italy) from that of market management (Borsa Italiana). Main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading and the surveillance of the markets.

According to Consob Regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which are MTA (shares, convertible bonds, pre-emptive rights, warrants and Funds), 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. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments – in the system and in accordance with non-discretionary rules – in a way that results in a contract. A Systematic Internaliser is an investment firm or a bank which deals on own account by executing client orders outside a Regulated Market or a MTF. Outside Regulated Markets, block trading is also permitted for orders that meet certain minimum size requirements and must be notified to Consob and Borsa Italiana.

According to Legislative Decree No. 58 of February 24, 1998 ("Decree No. 58"), the Consolidated Law on Financial Intermediation, the provision of investment services and activities to the public on a professional basis is reserved to banks and investment firms ("authorized persons"). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct.

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 registered head office of the Company is located in Rome, Italy, and the Company has two secondary registered offices in San Donato Milanese (Milan).

The full text of Eni’s By-laws is attached as an exhibit to this annual report (last amended on June 3, 2010). 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 field of chemicals, nuclear fuels, geothermal, renewable energy sources and energy in general, 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 similar purposes, comparable or complementary to its own or those of its subsidiaries or affiliates, either in Italy or abroad, and it may provide collateral and/or personal guarantees for both its own and third-party commitments.

 

Directors’ issues

The Eni’s 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.

If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one among its members.

The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on the matters regarding major strategic, operational and organizational decisions.

According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman for researching and promoting integrated projects and international agreements of strategic significance.

The Board of Directors may at any time withdraw the powers delegated hereon, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to simultaneously appoint another Chief Executive Officer. The Board of Directors, upon proposal of the Chairman and in agreement with the Chief Executive Officer, may delegate powers for single acts or classes of acts to other among its members.

According with Eni’s By-laws, the quorum for meeting of the Board shall be the majority of the Directors in office who are entitled to vote. Resolutions shall be adopted by an absolute majority of the Directors present who are entitled to vote; in case of a tie, the vote of the person chairing the meeting shall be decisive.

 

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 Board of Directors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with Consob Regulation on March 12, 2010, and taking also into account recommendations established by Eni Code, the Board of Directors – on November 18, 2010 – approved unanimously the Management System Guidelines (MSG) "Operations with the interests of

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directors and statutory auditors and transactions with related parties", which will apply from January 1, 2011. These procedures, that replace the previous similar guidelines, received the prior favorable opinion, expressed unanimously, of the Internal Control Committee, composed entirely of independent directors under the Corporate Governance Code of Borsa Italiana SpA and in accordance with Consob Regulation, to detail the abovementioned disclosure obligations (extending them to the Statutory Auditors). MSG specifies commitments of monitoring, evaluation and motivation related to the preliminary phase and completion of a transaction with a subject of interest of directors or statutory auditors. In this regard, both in the preliminary and deliberation phase, is requested a detailed and documented examination of the reason of the operation, highlighting the interest of company in its completion and the convenience and fairness of underlying terms. 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). In any case, if the operation is under the responsibility of the Board of Directors of Eni, it is provided for a non-binding opinion from the Internal Control Committee. 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.

 

Compensation

Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian civil law, while compensation of Directors invested with particular tasks in accordance with the By-laws (such as the Board Chairman and the CEO), or for participation in Board Committees, shall be determined by the Board of Directors, upon proposal of the Compensation Committee after consultation with the Board of Statutory Auditors (for more details about compensation policy in 2010, see "Item 6 – Compensation").

 

Borrowing powers

Borrowing powers 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 to both 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 SpA" (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.

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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), Eni’s By-laws provide a voting list system. In particular, pursuant to Article 17 of the By-laws and according to the applicable law, lists may be presented both by shareholders, either individually or jointly with others, representing at least 1% of the share capital, or the different percentage fixed by Consob (the public authority responsible for regulating the Italian securities market) in its regulation, or by the Board of Directors. Each shareholder may present or contribute towards presenting, and vote for, a single list.

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 shareholders’ rights it 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 by applicable law and Eni’s By-laws, in "ordinary" or "extraordinary" form. Resolutions of ordinary and extraordinary Shareholders’ Meetings in first, second or third call must be approved with the quorum and voting majorities provided for by the law in each case. The Board of Directors may, if it is deemed necessary, determine that both the ordinary and the extraordinary Shareholders’ Meeting shall be called for only one date, with the quorum and voting majorities provided for by the law.

Shareholders’ Meetings are usually held at the Company’s registered office, unless otherwise resolved by the Board of Directors, provided however they are held in Italy.

A Shareholders’ Meeting shall be called by notice published on the Company’s website, as well as in the ways specified by Consob in its regulation, within the legal terms and in accordance with current law. The call notice, which content is defined by the law and Eni’s By-laws, contains all the information to attend and to vote at the meeting including, information on proxy voting and vote by mail (the information is also available on the Company’s website). In the same manner and within the same deadline for publishing the notice calling the meeting, unless otherwise specified by the regulations, the Board of Directors issues a report on the meeting’s agenda.

An ordinary Shareholders’ Meeting is called at least once a year, within 180 days of the end of the Company financial year (on December 31), to approve the financial statements, as the Company is required to draw up consolidated financial statements.

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The right to attend the Shareholders’ Meeting applies to those on behalf of whom the intermediary – authorized pursuant to applicable regulations – has sent to the Company, upon request of the person entitled to the right, the statement certifying the ownership of the relative right, at the end of the seventh trading day prior to the date of the Shareholders’ Meeting on first or single call. Credit and debit records entered on accounts after this deadline shall not be considered for the purpose of legitimizing the exercise of voting rights at the Shareholders’ Meeting. The statement made by the authorized intermediary must be received by the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting on first or single call, or other deadline fixed by Consob regulation issued in agreement with the Bank of Italy. The right to attend and to vote at the Shareholders’ Meeting still remains even if the statement is received by the Company after the deadline indicated above, as long as it is received by the opening of the Shareholders’ Meeting. Those who are entitled to vote may appoint a representative in the Shareholders’ Meeting according to law, by means of a written proxy (or in electronic form when this is provided for in specific regulations) and in the ways set forth therein. In this latter case, electronic notification of the proxy may be carried out by using a special section of the Company’s Website, in the ways indicated in the notice calling the meeting. In order to simplify the casting of vote by proxy issued by shareholders who are employees of the Company or of 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 legal representatives of said associations. The right to vote may also be exercised by mail according to specific laws and regulations. If envisaged in the notice calling the meeting, those persons entitled to vote may attend the Shareholders’ Meeting through telecommunication means, and exercise their right to vote by electronic means, in accordance with the law, the specific regulatory provisions and the meeting Regulations. The Company may designate a representative for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the proposals on the agenda in the ways provided by the law and the regulatory provisions, by the end of the second trading day preceding the date set for the Shareholders’ Meeting on first or single call. The proxy is not valid for proposals on which no voting instructions have been provided.

The Chairman of the meeting ensures the regularity of proxies and, in general, the right to attend the meeting.

Shareholders’ 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/her opinion on the items on the agenda.

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 into 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 people to hold shares or vote other than the limitations described below (which are equally applicable to residents and non-residents in Italy).

In accordance with Article 6 of the By-laws, and applying the special rules pursuant to Article 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 participate in profits, relative to any shareholding that exceeds the limit.

Pursuant to Article 32 of the By-laws and the abovementioned provision of law, shareholdings owned by the Ministry of 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 for 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.

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These special powers are briefly the following:

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.

The special powers shall be exercisable with regard to significant and binding cases of general interest (public order, public security, public health and defense) in an appropriate way and measure and proportionally to the safeguarding of these interests, even by means of necessary time limits, without prejudice to compliance with the national and European principles, and in particular with the non-discrimination principle.

The Italian Prime Ministerial Decree of May 20, 2010, after some decisions of the European Court of Justice, repealed paragraph 2 of first article of Prime Ministerial Decree of June 10, 2004, related to the specific circumstances in which the special powers may be exercised.

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 such any 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 Finance¹² and Consob Regulation¹³, any direct or indirect

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holding in the voting shares of a listed issuer in excess of 2%¹⁴, 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 abovementioned 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 abovementioned 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 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 in the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights 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 abovementioned 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.

Moreover, under the Italian Civil Code (Article 2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed a fifth of the capital of the parent company – if the latter is a listed company – taking into account for this purpose the shares held by the same parent company or its subsidiaries.

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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 Authority¹⁵. 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 in Italy may effect any investments, divestments and other transactions that entail a transfer of assets to or from Italy, subject only to the reporting, record-keeping and disclosure requirements described below. In particular, residents of Italy may hold foreign currency and foreign securities of any kind, within and outside Italy, while non-residents may invest in Italian securities without restriction and may export from Italy cash, instruments of credit or payment and securities, whether in foreign currency or euro, representing interest, dividends, other asset distributions and the proceeds of dispositions.

Updated reporting and record-keeping requirements are contained in the Italian legislation which implements an EU directive regarding the free movement of capital. Such legislation requires that transfers into or out of Italy of cash or securities in excess of euro 12.5 thousand be reported in writing to the 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.

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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 2010 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.

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 USA 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 USA 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.

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Where the Beneficial Owner has not provided the abovementioned 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 the USA 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:

Gains realized by non-residents from non substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax.

On the contrary, gains realized by non-residents from substantial interest even in listed companies are deemed to be realized in Italy and consequently they are subject to the capital gains tax.

However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the USA 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 abovementioned 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.

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If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding euro 1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place.

 

United States Taxation

The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not purport to address all material tax consequences of the ownership of Shares or ADSs. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, investors that actually or constructively own 10% or more of Eni SpA’s Shares, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose "functional currency" is not the U.S. dollar.

This summary is based on the tax laws of the USA (including the Internal Revenue Code of 1986, as amended, (the "Code"), its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof, and which are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs.

If a partnership holds the Shares or ADSs, the USA federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the USA federal income tax treatment of an investment in the Shares or ADSs.

As used in this section, the term "U.S. Holder" means a beneficial owner of Shares or ADSs who or that is: (i) a citizen or resident of the USA; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the USA is able to exercise primary supervision over the administration of the trust and one or more USA persons have the authority to control all substantial decisions of the trust.

The discussion does not address any aspects of USA 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 USA and Italy with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits.

In general, and taking into account the earlier assumptions, for the U.S. federal income tax purposes, U.S. Holders who own ADSs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADSs and ADSs for Shares generally will not be subject to the U.S. federal income tax.

 

Dividends

Subject to the passive foreign investment company, or PFIC, rules discussed below, distributions paid on the shares generally will be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends-received deduction generally allowed to corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian tax Authorities. If you are a non-corporate U.S. Holder, dividends paid to you in taxable years beginning before January 1, 2013 that constitute qualified dividend income will be taxable to you at a maximum tax rate of 15% provided that you hold the Shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends we pay with respect to the Shares or ADSs generally will be qualified dividend income. The amount of the dividend distribution that you must

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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 USA 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 USA federal income tax liability. See "Italian Taxation – Income Tax" above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the shares will be income from sources outside the USA 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 ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency its U.S. dollar equivalent, determined at the spot rate on the date of disposition). Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non-corporate U.S. Holder that is recognized in taxable years beginning before January 1, 2013 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 ADSs should not be treated as stock of a PFIC for USA federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, unless a U.S. holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, if you are a U.S. holder, you would be treated as if you had realized such gain and certain "excess distributions" ratably over your holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, your Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during your holding period in your Shares or ADSs. Dividends that you receive from Eni SpA will not be eligible for the 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, USA.

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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 U.S. dollar reduces the Group’s results from operations and liquidity, and vice versa.

Due to a changed competitive environment in the European gas market and also considering the development of highly liquid spot markets for gas and volatile gas margins, management adopted in 2010 new risk management policies and instruments to safeguard the value of the Company’s assets in the gas value chain and to seek to profit from market and trading opportunities. These new policies and instrument will be fully implemented in 2011. As part of its new risk management strategy, the Company plans to enter into commodity derivatives transactions targeting different objectives.

(i)		On one hand, management plans to enter commodity derivative transactions to hedge the risk of variability in future cash flows on already contracted or highly probable future sales exposed to commodity risk depending on the circumstance that costs of supplies may be indexed to different market and oil benchmarks compared to the indexing of selling prices. Management plans to implement tight correlation between such commodity derivatives transactions and underlying physical contracts in order to account for those derivatives in accordance with hedging accounting in compliance with IAS 39, where possible;
(ii)		on the other hand, management plans to enter purchase/sale commodity contracts in both commodity and financial markets for speculative purposes in order to alter the risk profile associated with a portfolio of gas contracts (purchase contracts, transport entitlements, storage capacity) or leverage any price differences in the marketplace, seeking to increase margins on existing assets in case of favourable trends in the commodity pricing environment or seeking a potential profit based on expectations of future prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. Those derivatives will be accounted for through profit and loss, resulting in higher volatility in the gas business’ operating profit.

The Company may also enters into commodity derivatives from time to time, to hedge 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.

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.

Please refer to Note 34 to the Consolidated Financial Statements for a qualitative and quantitative discussion of the Company’s exposure to market risks.

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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, Eni’s securities are traded in the form of ADSs (American Depositary Shares) which are listed on the New York Stock Exchange. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. Eni’s ADRs are issued, cancelled and exchanged at the office of JP Morgan Chase Bank of New York, 1 Chase Manhattan Plaza, Floor 58, New York, NY, 10005-1401, as depositary (the "Depositary") under the Deposit Agreement between Eni, the Depositary and the holders of ADRs.

JP Morgan Chase Bank is also the transfer agent for Eni’s ADRs, and its principal office is 161 North Concord Exchange, South St Paul, MN, 55075.

BNP Paribas is the custodian (the "Custodian") on behalf of the holders of Eni’s 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 Chase Bank as Depositary and Transfer agent.

 

Fees and payments made by the Depositary to the issuer

The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the New York Stock Exchange. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.

For the year 2010, as agreed in the Deposit Agreement and subsequent amendments, the Depositary will reimburse to Eni up to U.S. $900,000 in connection with abovementioned expenditures.

 

Expenses waived or paid directly to third parties by the Depositary

There are no agreements whereby the Depositary has agreed to waive Eni 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, 2010.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, has been audited by Reconta Ernst & Young SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 of this Annual Report on Form 20-F.

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Changes in Internal Control over Financial Reporting

There have not been changes in the Company’s internal control over financial reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Item 16A. Board of Statutory Auditors Financial Expert

Eni’s Board of Statutory Auditors has determined that 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

Reconta Ernst & Young SpA has served as Eni’s principal independent public auditor for fiscal year 2010 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F.

PricewaterhouseCoopers SpA has served as Eni’s principal independent public auditor for fiscal years 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 to its public auditors Reconta Ernst & Young SpA and PricewaterhouseCoopers SpA and their respective member firms, for the years ended December 31, 2010, 2009 and 2008, respectively:

	Year ended December 31,

		2008		2009		2010

(euro thousand)

Audit fees		27,962		30,748		21,113
Audit-related fees		152		276		183
Tax fees		46		51		166
All other fees		1		-		-
Total		28,161		31,075		21,462

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Audit Fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting.

Audit Related Fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit Fees in this Item. The fees disclosed in this category mainly include audits of pension and benefit plans, merger and acquisition due diligence, audit and consultancy services rendered in connection with acquisition deals, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards.

Tax Fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities.

All Other Fees include products and services provided by the principal accountant, other than the services reported in Audit Fees, Audit-Related Fees and Tax Fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations.

 

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 2010, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (c) of Rule 2-01 of Regulation S-X.

 

Item 16D. Exemptions from the Listing Standards for Audit Committees

Making use of the exemption provided by Rule 10A-3(c)(3) for non-U.S. private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, is performing the functions required by the SEC rules and the Sarbanes-Oxley Act to be performed by the audit committees of non-U.S. companies listed on the NYSE (see "Item 6 – Board of Statutory Auditors" above).

 

Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The Issuer and its affiliated purchasers have not executed any purchase of equity securities of the Issuer from 2009 as of the date of the 20-F filing for the year ended December 31, 2010. All relevant authorizations previously granted by the General Shareholders’ Meeting to the Company management to execute any purchase of equity securities have expired. As of December 31, 2010, Eni’s treasury shares in portfolio amounted to No. 382,952,240 (nominal value euro 1 each) corresponding to 9.56% of share capital of Eni, for a total book value of euro 6,756 million. The decrease of No. 88,507 shares held in treasury from December 31, 2009 (No. 382,952,240 shares)

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consisted of No. 7 shares granted to shareholders of the former Snam SpA and to the sale of No. 88,500 shares following the 2002 and 2003 stock option plans.

 

Item 16F. Change in Registrant’s Certifying Accountant

Not applicable.

 

Item 16G. Significant Differences in Corporate Governance Practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual

Corporate governance. Eni’s governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted.

This model differs from the U.S. one-tier model 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 Corporate Governance Code promoted by Borsa Italiana (hereafter Borsa Italiana Code), which Eni has adopted.

 

Independent Directors

NYSE standards. Under NYSE standards U.S. listed companies’ Boards shall have a majority of independent directors. A director qualifies as independent when the Board 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 specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he/she is an employee of the issuer or a partner of the auditor).
In addition, a director cannot be considered independent in the three-year "cooling-off" period following the termination of any relationship that compromised a director’s independence.
Eni standards. In Italy, the Consolidated Law on Finance states that at least one member, or two members if the Board is composed by more than seven members, shall 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, with its directors or with the companies in the same group of the issuer that could influence his or her judgment.
Eni’s By-laws increases the number of independent directors provided by the law 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; independence is defined as not being currently or recently involved in any commercial relationship – either directly or indirectly – with the issuer or other parties associated with the issuer and which may influence his/her independent judgment.
In accordance with Eni’s By-laws, the Board of Directors, after its appointment by the Shareholders’ Meeting and periodically, evaluates the 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

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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 on a regularly basis in the absence of 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 2010, 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. U.S. listed companies shall 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 allowed 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").
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 shall have a nominating/corporate governance committee (or equivalent body) composed entirely of independent directors that is 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 Ethics – 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

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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 abovementioned 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, 2010 and 2009	F-4
Consolidated profit and loss account for the years ended December 31, 2010, 2009 and 2008	F-5
Consolidated Statements of comprehensive income for the years ended December 31, 2010, 2009 and 2008	F-6
Consolidated Statements of changes in shareholder’s equity for the years ended December 31, 2010, 2009 and 2008	F-7
Consolidated Statement of cash flows for the years ended December 31, 2010, 2009 and 2008	F-10
Notes to the Consolidated Financial Statements	F-12

 

 

Item 19. EXHIBITS

1. By-laws of Eni SpA

8. List of subsidiaries

11. Code of Ethics

Certifications:

12.1. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
12.2. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act

13.1. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
13.2. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)

15.a(i) Report of DeGolyer and MacNaughton
15.a(ii) Report of Ryder Scott Co

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Shareholders of Eni S.p.A

We have audited the accompanying consolidated balance sheet of Eni S.p.A as of December 31, 2010 and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders' equity and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eni S.p.A at December 31, 2010, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eni S.p.A’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 7, 2011 expressed an unqualified opinion thereon.

/s/ Reconta Ernst & Young S.p.A.

Rome, Italy
April 7, 2011

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Shareholders of Eni S.p.A

We have audited Eni S.p.A’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Eni S.p.A management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting on page 171. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Eni S.p.A maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Eni S.p.A as of December 31, 2010 and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders' equity and cash flows for the year then ended and our report dated April 7, 2011 expressed an unqualified opinion thereon.

/s/ Reconta Ernst & Young S.p.A.

Rome, Italy.
April 7, 2011

F-2

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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 consolidated balance sheet as of December 31, 2009 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 for each of the two years in the period ended December 31, 2009 present fairly, in all material respects, the financial position of Eni SpA and its subsidiaries at December 31, 2009, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

 

PricewaterhouseCoopers SpA

Rome, Italy
April 26, 2010

 

 

 

 

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CONSOLIDATED BALANCE SHEET
(euro million)

		Dec. 31, 2009		Dec. 31, 2010

		Note		Total amount		of which with related parties		Total amount		of which with related parties

ASSETS
Current assets
Cash and cash equivalents		(7)		1,608					1,549
Other financial assets held for trading or available for sale		(8)		348					382
Trade and other receivables		(9)		20,348			1,355		23,636			1,356
Inventories		(10)		5,495					6,589
Current tax assets		(11)		753					467
Other current tax assets		(12)		1,270					938
Other current assets		(13)		1,307			9		1,350			9
				31,129					34,911
Non-current assets
Property, plant and equipment		(14)		59,765					67,404
Inventory - compulsory stock		(15)		1,736					2,024
Intangible assets		(16)		11,469					11,172
Equity-accounted investments		(17)		5,828					5,668
Other investments		(17)		416					422
Other financial assets		(18)		1,148			438		1,523			668
Deferred tax assets		(19)		3,558					4,864
Other non-current receivables		(20)		1,938			40		3,355			16
				85,858					96,432
Assets held for sale		(31)		542					517
TOTAL ASSETS				117,529					131,860
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		(21)		3,545			147		6,515			127
Current portion of long-term debt		(26)		3,191					963
Trade and other payables		(22)		19,174			1,241		22,575			1,297
Income taxes payable		(23)		1,291					1,515
Other taxes payable		(24)		1,431					1,659
Other current liabilities		(25)		1,856			5		1,620			5
				30,488					34,847
Non-current liabilities
Long-term debt		(26)		18,064					20,305
Provisions for contingencies		(27)		10,319					11,792
Provisions for employee benefits		(28)		944					1,032
Deferred tax liabilities		(29)		4,907					5,924
Other non-current liabilities		(30)		2,480			49		2,194			45
				36,714					41,247
Liabilities directly associated with assets held for sale		(31)		276					38
TOTAL LIABILITIES				67,478					76,132
SHAREHOLDERS’ EQUITY		(32)
Non-controlling interest				3,978					4,522
Eni shareholders’ equity
Share capital				4,005					4,005
Reserves				46,269					49,450
Treasury shares				(6,757	)				(6,756	)
Interim dividend				(1,811	)				(1,811	)
Net profit				4,367					6,318
Total Eni shareholders’ equity				46,073					51,206
TOTAL SHAREHOLDERS’ EQUITY				50,051					55,728
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY				117,529					131,860

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(euro million except as otherwise stated)

		2008		2009		2010

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		(35)		108,082			5,048			83,227			3,300			98,523			3,274
Other income and revenues				728			39			1,118			26			956			58
				108,810						84,345						99,479
OPERATING EXPENSES		(36)
Purchases, services and other				76,350			6,298			58,351			4,999			69,135			5,825
- of which non-recurring charge (income)				(21	)					250						(246	)
Payroll and related costs				4,004						4,181						4,785
OTHER OPERATING (EXPENSE) INCOME				(124	)		58			55			44			131			41
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS				9,815						9,813						9,579
OPERATING PROFIT				18,517						12,055						16,111
FINANCE INCOME (EXPENSE)		(37)
Finance income				7,985			42			5,950			27			6,117			41
Finance expense				(8,198	)		(17	)		(6,497	)		(4	)		(6,713	)
Derivative financial instruments				(427	)					(4	)					(131	)
				(640	)					(551	)					(727	)
INCOME (EXPENSE) FROM INVESTMENTS		(38)
Share of profit (loss) of equity-accounted investments				640						393						537
Other gain (loss) from investments				733						176						619
				1,373						569						1,156
PROFIT BEFORE INCOME TAXES				19,250						12,073						16,540
Income taxes		(39)		(9,692	)					(6,756	)					(9,157	)
Net profit				9,558						5,317						7,383
Attributable to:
- Eni				8,825						4,367						6,318
- Non-controlling interest		(32)		733						950						1,065
				9,558						5,317						7,383
Earnings per share attributable to Eni (euro per share)		(40)
Basic				2.43						1.21						1.74
Diluted				2.43						1.21						1.74

 

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(euro million)

		Note		2008		2009		2010

Net profit				9,558			5,317			7,383
Other items of comprehensive income
Foreign currency translation differences				1,077			(869	)		2,169
Change in the fair value of cash flow hedging derivatives		(32)		1,969			(481	)		443
Change in the fair value of available-for-sale securities		(32)		3			1			(9	)
Share of "Other comprehensive income" on equity-accounted entities							2			(10	)
Taxation		(32)		(767	)		202			(175	)
				2,282			(1,145	)		2,418
Total comprehensive income				11,840			4,172			9,801
Attributable to:
- Eni				11,148			3,245			8,699
- Non-controlling interest				692			927			1,102
				11,840			4,172			9,801

 

 

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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

Non-controlling 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
Other items of comprehensive income
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 avaible-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 non-controlling interest																																						20			20
Allocation of 2007 net profit																										5,261						(5,261	)
Share 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 non-controlling interest)																	(1,495	)																	(1,495	)					(1,495	)
Non-controlling 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		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

Non-controlling interest

Total shareholders’ equity

Balance at December 31, 2008		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
Other items of comprehensive income
Change in the fair value of cash flow hedge derivatives net of the tax effect											(279	)																							(279	)					(279	)
Change in the fair value of available-for-sale securities net of the tax effect														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 2008 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 non-controlling interest																																						1,560			1,560
Allocation of 2008 net profit																										4,111						(4,111	)
Put option granted to Publigaz SCRL (the Distrigas NV non-controlling interest)																	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	)
Non-controlling 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																										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		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 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

Non-controlling interest

Total shareholders’ equity

Balance at December 31, 2009 (Note 32)		4,005			959			6,757			(439	)		5			1,492			(1,665	)		(6,757	)		39,160			(1,811	)		4,367			46,073			3,978			50,051
Net profit for the year																																6,318			6,318			1,065			7,383
Gains (losses) recognized directly in equity
Change in the fair value of cash flow hedge derivatives net of the tax effect (Note 32)											267																								267						267
Change in the fair value of available-for-sale securitiesnet of the tax effect (Note 32)														(8	)																				(8	)					(8	)
Share of "Other comprehensive income" on equity-accounted entities																	(5	)																	(5	)		(5	)		(10	)
Foreign currency translation differences											(2	)								2,204						(75	)								2,127			42			2,169
											265			(8	)		(5	)		2,204						(75	)								2,381			37			2,418
Total recognized income and (expense) for the year											265			(8	)		(5	)		2,204						(75	)					6,318			8,699			1,102			9,801
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.50 per share in settlement of 2009 interim dividend of euro 0.50 per share)																													1,811			(3,622	)		(1,811	)					(1,811	)
Interim dividend distribution of Eni SpA (euro 0.50 per share)																													(1,811	)					(1,811	)					(1,811	)
Dividend distribution of other companies																																						(514	)		(514	)
Allocation of 2009 net profit																										745						(745	)
Effect related to the purchase of Italgas SpA and Stoccaggi Gas SpA by Snam Rete Gas SpA																	56																		56			(56	)
Treasury shares sold following the exercise of stock options by Eni managers								(1	)														1			1									1						1
Treasury shares sold following the exercise of stock options by Saipem and Snam Rete Gas managers																										10									10			27			37
Non-controlling interest recognized following the acquisition of the control stake in the share capital of Altergaz SA																																						7			7
Non-controlling interest excluded following the divestment of the control stake in the share capital of GreenStream BV																																						(37	)		(37	)
								(1	)								56						1			756						(4,367	)		(3,555	)		(573	)		(4,128	)
Other changes in shareholders’ equity
Cost related to stock options																										7									7						7
Stock option expired																										(6	)								(6	)					(6	)
Stock warrants on Altergaz SA																	(25	)																	(25	)					(25	)
Other changes																										13									13			15			28
																	(25	)								14									(11	)		15			4
Balance at December 31, 2010 (Note 32)		4,005			959			6,756			(174	)		(3	)		1,518			539			(6,756	)		39,855			(1,811	)		6,318			51,206			4,522			55,728

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CONSOLIDATED STATEMENT OF CASH FLOWS
(euro million)

		Note		2008		2009		2010

Net profit of the year				9,558			5,317			7,383
Adjustments to reconcile net profit to net cash provided by operating activities
Depreciation, depletion and amortization		(36)		8,422			8,762			8,881
Impairments of tangible and intangible assets, net		(36)		1,393			1,051			698
Share of profit (loss) of equity-accounted investments		(38)		(640	)		(393	)		(537	)
Gain on disposal of assets, net				(219	)		(226	)		(552	)
Dividend income		(38)		(510	)		(164	)		(264	)
Interest income				(592	)		(352	)		(96	)
Interest expense				809			603			571
Income taxes		(39)		9,692			6,756			9,157
Other changes				(375	)		(319	)		(39	)
Changes in working capital:
- inventories				546			52			(1,150	)
- trade receivables				(479	)		1,431			(1,918	)
- trade payables				1,171			(2,559	)		2,770
- provisions for contingencies				387			517			588
- other assets and liabilities				2,864			(636	)		(2,010	)
Cash flow from changes in working capital				4,489			(1,195	)		(1,720	)
Net change in the provisions for employee benefits				(8	)		16			21
Dividends received				1,150			576			799
Interest received				266			594			126
Interest paid				(852	)		(583	)		(600	)
Income taxes paid, net of tax receivables received				(10,782	)		(9,307	)		(9,134	)
Net cash provided by operating activities				21,801			11,136			14,694
- of which with related parties		(42)		(62	)		(1,188	)		(1,749	)
Investing activities:
- tangible assets		(14)		(12,082	)		(12,032	)		(12,308	)
- intangible assets		(16)		(2,480	)		(1,663	)		(1,562	)
- consolidated subsidiaries and businesses				(3,634	)		(25	)		(143	)
- investments		(17)		(385	)		(230	)		(267	)
- securities				(152	)		(2	)		(50	)
- financing receivables				(710	)		(972	)		(866	)
- change in payables and receivables in relation to investing activities and capitalized depreciation				367			(97	)		261
Cash flow from investing activities				(19,076	)		(15,021	)		(14,935	)
Disposals:
- tangible assets				318			111			272
- intangible assets				2			265			57
- consolidated subsidiaries and businesses				149						215
- investments				510			3,219			569
- securities				145			164			14
- financing receivables				1,293			861			841
- change in payables and receivables in relation to disposals				(299	)		147			2
Cash flow from disposals				2,118			4,767			1,970
Net cash used in investing activities				(16,958	)		(10,254	)		(12,965	)
- of which with related parties		(42)		(1,598	)		(1,262	)		(1,626	)

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CONSOLIDATED STATEMENT OF CASH FLOWS continued
(euro million)

		Note		2008		2009		2010

Proceeds from long-term debt				3,774			8,774			2,953
Repayments of long-term debt				(2,104	)		(2,044	)		(3,327	)
Increase (decrease) in short-term debt				(690	)		(2,889	)		2,646
				980			3,841			2,272
Net capital contributions by non-controlling interest				20			1,551
Net acquisition of treasury shares different from Eni SpA				(50	)		9			37
Acquisition of additional interests in consolidated subsidiaries							(2,068	)
Dividends paid to Eni’s shareholders				(4,910	)		(4,166	)		(3,622	)
Dividends paid to non-controlling interest				(297	)		(350	)		(514	)
Net purchase of treasury shares				(768	)
Net cash used in financing activities				(5,025	)		(1,183	)		(1,827	)
- of which with related parties		(42)		14			(14	)		(23	)
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)				(1	)
Effect of exchange rate changes on cash and cash equivalents and other changes				8			(30	)		39
Net cash flow for the year				(175	)		(331	)		(59	)
Cash and cash equivalents - beginning of year		(7)		2,114			1,939			1,608
Cash and cash equivalents - end of year		(7)		1,939			1,608			1,549

 

 

 

 

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Notes to the Consolidated Financial Statements

1 Basis of presentation

The Consolidated Financial Statements of Eni Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (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 agreement and buy-back contracts. The Consolidated Financial Statements have been prepared on a historical cost basis, taking into account where appropriate of any value adjustments, except for certain items that under IFRS must be recognized at fair value as described in the summary of significant accounting policies paragraph.

The Consolidated Financial Statements include the statutory accounts of Eni SpA and the accounts of subsidiaries where the company holds the right to directly or indirectly exercise control, determine financial and management decisions and obtain economic and financial benefits. For entities acting as sole-operator in the management of oil and gas contracts on behalf of companies participating in a joint venture, the activities are financed proportionately based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenues and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized proportionally directly in the financial statements of the companies involved. The exclusion from consolidation of some subsidiaries, which are not material either individually or overall, has not produced significant¹ economic and financial effects on the Consolidated Financial Statements. These interests are accounted for as described below under the item "Financial fixed assets".

Subsidiaries’ financial statements are audited by the independent auditors who examine and certify also the information required for the preparation of the Consolidated Financial Statements. The 2010 Consolidated Financial Statements approved by Eni’s Board of Directors on March 10, 2011 were audited by the independent auditor Reconta Ernst & Young SpA. The independent auditor of Eni SpA, as the main auditor is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other independent auditors, it takes the responsibility of their work. Amounts in the financial statements and in the notes are expressed in millions of euros (euro million).

 

2 Principles of consolidation

Interest in consolidated companies
Assets and liabilities, revenues and expenses related to fully consolidated subsidiaries are wholly incorporated in the Consolidated Financial Statements; the book value of interests in these subsidiaries is eliminated against the corresponding share of the shareholders’ equity by attributing to each of the balance sheet items its fair value at the acquisition date. When acquired, the net equity of controlled subsidiaries is initially recognized at fair value. The excess of the purchase price of an acquired entity over the total fair value assigned to assets acquired and liabilities assumed is recognized as goodwill; negative goodwill is recognized in the profit and loss account.

Equity and net profit of non-controlling interests are included in specific lines of equity and profit and loss account. If the partial control is acquired, this share of equity is determined using the proportionate share of the fair value of assets and liabilities, excluding any related goodwill, at the time when control is acquired (partial goodwill); as an alternative, it is allowed the recognition of the entire amount of goodwill deriving from the acquisition, taking into account therefore also the portion attributable to the non-controlling interests (full goodwill method); on this regard, the non-controlling interests are measured at their total fair value which therefore includes the goodwill attributable to them². The method of measuring goodwill (partial goodwill or full goodwill) is selective for each business combination.

The purchase of additional ownership interests in subsidiaries from non-controlling interests is recognized in equity and represents the excess of the amount paid over the carrying value of the non-controlling interests acquired; similarly, are recognized in equity the effects associated with the sale of non-controlling interests in consolidated subsidiaries without loss of control.

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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, that represents the Group’s functional currency, 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 "Non-controlling interest" for the portion related to non-controlling interests’ share. Cumulative exchange rate differences are charged to the profit and loss account when the entity disposes the entire interest in a foreign operation or at the loss of control of a foreign subsidiary. On the partial disposal, without losing control, the proportionate share of cumulative amount of exchange differences related to the disposed interest is recognized in equity to non-controlling interests. Financial statements of foreign subsidiaries which are translated into 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 use the euro. The main foreign exchange rates used to translate the financial statements adopting a different functional currency are indicated below:

(currency amount for euro 1)	Annual average exchange rate 2008		Exchange rate at Dec. 31, 2008		Annual average exchange rate 2009		Exchange rate at Dec. 31, 2009		Annual average exchange rate 2010		Exchange rate at Dec. 31, 2010

U.S. Dollar		1.47		1.39		1.39		1.44		1.33		1.34
Pound Sterling		0.80		0.95		0.89		0.89		0.86		0.86
Norwegian Krone		8.22		9.75		8.73		8.30		8.00		7.80
Australian Dollar		1.74		2.03		1.77		1.60		1.44		1.31
Hungarian Forint		251.51		266.70		280.33		270.42		275.48		277.95

 

3 Summary of significant accounting policies

The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below.

Current assets
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)"³ 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.

Available-for-sale financial assets include financial assets other than derivative financial instruments, loans and receivables, held for trading financial assets and held-to-maturity financial assets.

The fair value of financial instruments is determined by market quotations or, in their absence, it is estimated adopting suitable financial valuation models which take into account all the factors adopted by market operators and prices obtained in similar recent transactions in the market.

Interests and dividends on 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

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delivery of the asset within the time frame generally established by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date.

Receivables are measured at amortized cost (see item "Financial fixed assets" below).

Transferred financial assets are derecognized when the contractual rights to receive the cash flows of the financial assets are transferred together with the risks and rewards of the ownership.

Inventories, including compulsory stocks and excluding 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. Inventories of natural gas which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell.

The cost for inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted-average cost method on a three-month basis, or monthly, when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost for inventories of the 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 recognized immediately as an expense when it is probable that total contract costs will exceed total contract revenues. 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 "Other payables" or, after the settlement, to "Cash and Cash equivalents". The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually delivered – the related cost is included in the determination of the weighted-average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to collect gas that was previously uncollected within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, measured adopting the same criteria described for inventories.

Hedging instruments are described in the section "Derivative Instruments".

 

Non-current assets

Property, plant and equipment⁴
Tangible assets, including investment properties, are recognized using the cost model and stated at their purchase or self-construction cost including any costs directly attributable to bringing the asset into operation. In addition, when a substantial period of time is required to make the asset ready for use, the purchase price or self-construction cost includes the borrowing costs incurred that could have otherwise been saved had the investment not been made.

In the case of a present obligation for the dismantling and removal of assets and the restoration of sites, the carrying value includes, with a corresponding entry to a specific provision, the estimated (discounted) costs to be incurred at the moment the asset is retired. Changes in estimate of the carrying amounts of provisions due to the passage of time and changes in discount rates are recognized under "Provisions for contingencies"⁵.

Property, plant and equipment is not revalued for financial reporting purposes.

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Assets carried under financial leasing or concerning arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset are recognized at fair value, net of taxes due from the lessor or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt payable to the lessor is recognized as a financial liability. These assets are depreciated using the criteria described below. When the renewal is not reasonably certain, leased assets are depreciated over the shorter of the lease term 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 life⁶ which is an estimate of the period over which the assets will be used by the company. When tangible assets are composed of more than one significant element with different useful lives, each component is depreciated separately. The amount to be depreciated is the book value less the estimated net realizable value at the end of the useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when purchased with a building. Tangible assets held for sale are not depreciated (see item "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 to be included in the discount rate is 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 risk compared with Eni, specific WACC rates have been defined (for Gas & Power segment on the basis of a sample of companies operating in the same segment; for Engineering & Construction segment on the basis of the market quotation); WACC used for impairments in the Gas & Power segment is adjusted to take into consideration the risk premium of the specific country of the activity while WACC used for impairments in the Engineering & Construction segment is not adjusted for country risk as most of the company assets are not located in a specific country. For the regulated activities, the discount rate used for the measurement of the value in use is equal to the rate return defined by the Regulator. For the other segments, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the realizable value of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called "cash-generating unit". When the reasons for their impairment cease to exist, Eni makes a reversal that is recognized in 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

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asset arises from contractual or legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or as an integral part of other assets. An entity controls an asset if it has the power to obtain the future economic benefits generated by the underlying asset and to restrict the access of others to those cash flows.

Intangible assets are initially stated at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes.

Intangible assets with a definite useful life are amortized systematically over their useful life estimated as the period over which the assets will be used by the company; the amount to be amortized and the recoverability of the carrying amount are verified in accordance with the criteria described in the section "Property, plant and equipment".

Goodwill and other intangible assets with an indefinite useful life are not amortized. The recoverability of their carrying value is reviewed at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Goodwill is tested for impairment at the level of the smallest aggregate on which the company, directly or indirectly, evaluates the return on the capital expenditure to which goodwill relates. When the carrying amount of the cash-generating unit, including goodwill allocated thereto, exceeds the cash-generating unit’s recoverable amount⁷, 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 reversed⁸.

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 concerning the development, financing, operation and maintenance of infrastructures under concession, in which: (i) the grantor controls or regulates what services the operator must provide with the infrastructure, and at what price; and (ii) the grantor controls – by the ownership, beneficial entitlement or otherwise – any significant residual interest in the infrastructure at the end of the concession arrangement.

According to the agreements, the operator has the right to operate the infrastructure, controlled by the grantor, in order to provide the public service⁹.

 

Exploration and production activities^{10 11}

Acquisition of mineral rights
Costs associated with the acquisition of mineral rights are capitalized in connection with the assets acquired (such as exploratory potential, probable and possible reserves and proved reserves). When the acquisition is related to a set of exploratory potential and reserves, the cost is allocated to the different assets acquired on the basis of the value of the relevant discounted cash flows. Expenditure for the exploratory potential, represented by the costs for the acquisition of the exploration permits and for the extension of existing permits, is recognized under "Intangible assets" and is amortized on a straight-line basis over the period of the exploration as contractually established. If the exploration is abandoned, the residual expenditure is charged to the profit and loss account. Acquisition costs for proved reserves and for possible and probable reserves are recognized in the balance sheet as assets. Costs associated with proved reserves are amortized on a UOP basis, as detailed in the section "Development", considering both developed and undeveloped reserves. Expenditures associated with possible and probable reserves

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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 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 company’s technologies and financing (cost oil) and the company’s share of production volumes not destined to cost recovery (profit oil). Revenues from the sale of the production entitlements against both cost oil and profit oil are accounted for on an accrual basis whilst exploration, development and production costs are accounted for according to the policies mentioned above. The company’s share of production volumes and reserves representing the profit oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on the behalf of the company. As a consequence the company has to recognise at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense.

Retirement
Costs expected to be incurred with respect to the retirement of a well, including costs associated with removal of production facilities, dismantlement and site restoration, are capitalized and amortized on a UOP basis, consistent with the policy described under "Property, plant and equipment".

 

Grants
Grants related to assets are recorded as a reduction of purchase price or production cost of the related assets when there is reasonable assurance that all the required conditions attached to them, agreed upon with government entities, have been met.

Grants not related to capital expenditure are recognized in the profit and loss account.

 

Financial fixed assets

Investments
Investments in subsidiaries excluded from consolidation, jointly controlled entities and associates are accounted for using the equity method¹². 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".

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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 market and fair value cannot be reasonably determined, investments are accounted for at cost, adjusted for impairment losses; impairment losses may not be reversed¹³.

The risk deriving from losses exceeding shareholders’ equity is recognized in a specific provision to the extent the parent company is required to fulfill legal or implicit obligations towards the subsidiary or to cover its losses.

Receivables and financial assets to be held to maturity
Receivables and financial assets to be held to maturity are stated at cost represented by the fair value of the initial exchanged amount adjusted to take into account direct external costs related to the transaction (e.g. fees of agents or consultants, etc.). The initial carrying value is then adjusted to take into account capital repayments, devaluations and amortization of the difference between the reimbursement value and the initial carrying value. Amortization is carried out on the basis of the effective 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 excess charges. 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 measured at amortized cost (see item "Financial fixed assets" above).

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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 into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognized as "Financial income (expense)".

When the liability regards a tangible asset (e.g. site restoration and abandonment), the provision is stated with a corresponding entry to the asset to which it refers. Charges to the profit and loss account are made with the amortization process.

Costs that the company expects to bear in order to carry out restructuring plans are recognized when the company formally defines the plan and the interested parties have developed the reasonable expectation that the restructuring will happen.

Provisions are periodically updated to show the variations of estimates of costs, production times and actuarial rates. The estimated revisions to the provisions are recognized in the same profit and loss account item that had previously held the provision, or, when the liability regards tangible assets (i.e. site restoration and abandonment) with a corresponding entry to the assets to which they refer.

In the notes to the Consolidated Financial Statements, the following potential liabilities are described: (i) possible, but not probable obligations deriving from past events, whose existence will be confirmed only when one or more future events beyond the company’s control occur; and (ii) current obligations deriving from past events whose amount cannot be reasonably estimated or whose fulfillment will probably not result in an outflow of resources embodying economic benefits.

 

Employee benefits
Post-employment benefit plans, including constructive obligations, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. In the first case, the company’s obligation, which consists of making payments to the State or a trust or a fund, is determined on the basis of contributions due. The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits.

The actuarial gains and losses of defined benefit plans are recognized pro-rata on service, in the profit and loss account using the corridor method, if and to the extent that net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period exceed the greater of 10% of the present value of the defined benefit obligation or 10% of the fair value of the plan assets, over the expected average remaining working lives of the employees participating in the plan. Such actuarial gains and losses derive from changes in the actuarial assumptions used or from a change in the conditions of the plan. Obligations for long-term benefits are determined by adopting actuarial assumptions. The effect of changes in actuarial assumptions or a change in the characteristics of the benefit 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.

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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 the associated revenue can be reliably measured. In particular, revenues are recognized for the sale of:

Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer.

Revenues from crude oil and natural gas production from properties in which Eni has an interest together with other producers are recognized on the basis of Eni’s net working interest in those properties (entitlement method). Differences between Eni’s net working interest volume and actual production volumes are recognized at current prices at year end.

Income related to partially rendered services is recognized in the measurement of accrued income if the stage of completion can be reliably determined and there is no significant uncertainty as to the collectability of the amount and the related costs. When the outcome of the transaction cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable.

Revenues accrued during the year related to construction contracts are recognized on the basis of contractual revenues with reference to the stage of completion of a contract measured on the cost-to-cost basis. For service concession arrangements (see item "Intangible assets" above) in which customers fees do not provide a reliable distinction between the compensation for construction/update of the infrastructure and the compensation for operating it and in the absence of external benchmarks, revenues recognized during the construction phase are limited to the amount of the costs incurred.

Additional revenues, derived from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them. Tangible assets, different from an infrastructure used in service concession arrangements, transferred from customers (or constructed using cash transferred from customers) and used to connect them to a network to supply goods and services, are recognized at their fair value as an offset to revenues. When more than one separately identifiable service is provided (for example, connection to a network and supply of goods) the entity shall assess for which one service it receives the transferred asset from the customer and it shall consistently recognize a revenue when the connection is delivered or over the lesser period between the length of the supply and the useful life of the transferred asset.

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 recorded as intangible assets net of any negative difference between the amount of emissions and the quotas assigned. Revenues related to emission quotas are recognized when they are realized for the related sale. In case of sale, if applicable, the acquired emission rights are considered as the first to be sold. Monetary receivables granted as a substitution of emission rights awarded free of charge are recognized as an offset to item "Other income" of the profit and loss account.

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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 period¹⁴. The fair value of stock options is determined using valuation techniques which consider conditions related to the exercise of options, current share prices, expected volatility and the risk-free interest rate. The fair value of stock options is recorded as a charge to "Other reserves".

The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalized, are included in the profit and loss account.

 

Exchange rate differences
Revenues and costs associated with transactions in currencies other than the functional currency are translated into the functional currency by applying the exchange rate at the date of the transaction.

Monetary assets and liabilities denominated in currencies other than functional currency are converted by applying the year end exchange rate and the effect is stated in the profit and loss account. Non-monetary assets and liabilities denominated in currencies other than the functional currency valued at cost are translated at the initial exchange rate. Non-monetary 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.

Relating to the temporary differences associated with investments in subsidiaries, associates and jointly controlled entities, the related deferred tax liabilities are not recognized if the investor is able to control the timing of reversal of the temporary differences and it is probable that the temporary difference will not reverse in the foreseeable future.

Deferred tax assets and liabilities are included in non-current assets and liabilities and are offset at a single entity level if related to offsettable taxes. The balance of the offset, if positive, is recognized in the item "Deferred tax assets"; if negative, in the item "Deferred tax liabilities". When the results of transactions are recognized directly in shareholders’ equity, current taxes, deferred tax assets and liabilities are also charged to the shareholders’ equity.

 

Derivatives
Derivatives, including embedded derivatives which are separated from the host contract, are assets and liabilities recognized at their fair value which is estimated by using the criteria described in the section "Current assets". When there is objective evidence that an impairment loss has occurred for reasons different from fair value decreases (see "Current assets" paragraph) derivative are recognized net of the allowance for impairment losses.

Derivatives are designated as hedging instruments when the relationship between the derivative and the hedged item is formally documented and the hedge is highly effective and regularly reviewed. When hedging instruments cover the risk of variation of the fair value of the hedged item (fair value hedge, e.g. hedging of the variability on the

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fair value of fixed interest rate assets/liabilities) the derivatives are stated at fair value and the effects charged to the profit and loss account. Hedged items are consistently adjusted to reflect the variability of fair value associated with the hedged risk. When derivatives hedge the cash flow variation risk of the hedged item (cash flow hedge, e.g. hedging the variability on the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), changes in the fair value of the derivatives, considered effective are initially stated in equity and then recognized in the profit and loss account consistent with the economic effects produced by the hedged transaction. The changes in the fair value of derivatives that do not meet the conditions required to qualify for hedge accounting are 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).

 

Financial statements¹⁵
Assets and liabilities on the balance sheet are classified as current¹⁶ and non-current. Items on the profit and loss account are presented by nature¹⁷.

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.

 

4 Changes in accounting principles
There are no changes in accounting principles to those applied in 2009.

 

5 Use of accounting estimates
The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting 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

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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 are classified as proved undeveloped. Volumes are subsequently reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings occur at the point of first oil or gas production.

Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.

In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production-sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural as that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion expenses and impairment expense. Depreciation rates on oil and gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, depletion and amortization expense. Conversely, a decrease in estimated proved developed reserves increases depreciation, depletion and amortization expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is to be carried out. The larger the volume of estimated reserves, the lower the likelihood of asset impairment.

 

Impairment of assets
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 Note 20) 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 cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate related to the activity involved.

For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. Oil, natural gas and petroleum product prices (and prices from products which

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are derived there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, 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.

 

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 for the 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.

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Employee benefits
Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including among others discount rates, expected rates of return on plan assets, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include 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 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. Additional income is derived from a change in the scope of work is included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them.

 

6 Recent accounting principles

Accounting standards and interpretations issued by IASB /IFRIC and endorsed by EU
By Commission Regulation No. 632/2010 of July 19, 2010 the revised IAS 24 "Related Party Disclosures" has been endorsed. The standard: (i) enhances the definition of a related party requiring new cases; and (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.

By Commission Regulation No. 662/2010 of July 23, 2010 IFRIC 19 "Extinguishing Financial Liabilities with Equity Instruments" (hereinafter IFRIC 19) has been endorsed. The interpretation defines the accounting treatment to adopt when a financial liability is settled by issuing equity instruments to the creditor (debt for equity swaps).

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In particular, 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 instruments 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).

By Commission Regulation No. 149/2011 of February 18, 2011, "Improvements to IFRSs" have been endorsed. The document includes only changes to the existing standards and interpretation with a technical and editorial nature. The provisions come into effect starting from 2011.

 

Accounting standards and interpretations issued by IASB/IFRIC and not yet been endorsed by EU
On November 12, 2009 IASB issued IFRS 9 "Financial Instruments" which changes recognition and measurement criteria 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; and (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. In addition, on October 28, 2010 the IASB added to IFRS 9 the requirements on the accounting for financial liabilities. In particular, new provisions require, inter alia, that if a financial liability is measured at fair value through profit or loss, subsequent changes in the fair value attributable to changes in the own credit risk shall be presented in the other comprehensive income; the component related to own credit risk is recognized in profit and loss account if the treatment of the changes in own credit risk would create or enlarge an accounting mismatch. IFRS 9 provisions shall be applied for annual periods beginning on or after January 1, 2013.

On October 7, 2010 the IASB issued Amendment to IFRS 7 "Disclosures - Transfers of financial assets", that provides supplementary disclosures on financial instruments, with reference to transfers of financial assets, to describe any risks that may remain with the entity that transferred the assets. The amendments also require additional disclosures if a disproportionate amount of transfer transactions are undertaken around the end of a reporting period. New provisions shall be applied for annual periods beginning on or after July 1, 2011 (for Eni: 2012 financial statements).

Eni is currently reviewing these new IFRS and interpretations to determine the likely impact on the Group’s results.

 

 

 

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Current assets

7 Cash and cash equivalents
Cash and cash equivalents of euro 1,549 million (euro 1,608 million at December 31, 2009) included financing receivables originally due within 90 days for euro 339 million (euro 450 million at December 31, 2009). The latter were related to amounts on deposit with financial institutions accessible only on a 48-hour notice.

The average maturity of financing receivables due within 90 days was 30 days and the effective interest rate amounted to 0.6%.

8 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, 2009		Dec. 31, 2010

Securities held for operating purposes
Listed Italian treasury bonds		113		48
Listed securities issued by foreign financial institutions		171		219
Non-quoted securities				6
		284		273
Securities held for non-operating purposes
Listed Italian treasury bonds		49		87
Listed securities issued by Italian and foreign financial institutions		14		22
Non-quoted securities		1
		64		109
Total securities		348		382

Securities of euro 382 million (euro 348 million at December 31, 2009) were available-for-sale securities. At December 31, 2009 and December 31, 2010, 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, 2009		Changes recognized in the reserves of shareholders' equity		Value at Dec. 31, 2010

Fair value		6			(9	)		(3	)
Deferred tax liabilities		(1	)		1
Other reserves of shareholders’ equity		5			(8	)		(3	)

Securities held for operating purposes of euro 273 million (euro 284 million at December 31, 2009) were designed to provide coverage of technical provisions of the Group’s insurance company Eni Insurance Ltd for euro 267 million (euro 284 million at December 31, 2009).

The fair value of securities was determined by reference to quoted market prices.

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9 Trade and other receivables
Trade and other receivables were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Trade receivables		14,916		17,221
Financing receivables:
- for operating purposes - short-term		339		436
- for operating purposes - current portion of long-term receivables		113		220
- for non-operating purposes		73		6
		525		662
Other receivables:
- from disposals		82		86
- other		4,825		5,667
		4,907		5,753
		20,348		23,636

Receivables are stated net of the allowance for impairment losses of euro 1,524 million (euro 1,647 million at December 31, 2009):

(euro million)		Value at Dec. 31, 2009		Additions		Deductions		Other changes		Value at Dec. 31, 2010

Trade receivables		942		201		(191	)		10			962
Financing receivables		6										6
Other receivables		699		21		(67	)		(97	)		556
		1,647		222		(258	)		(87	)		1,524

During the course of 2010, Eni transferred without notification to factoring institutions certain trade receivables without recourse due in 2011 for euro 1,279 million. The receivables sold related to the Refining & Marketing segment (euro 910 million) and to the Gas & Power segment (euro 369 million). Following contractual arrangements, Eni collects those receivables sold and, within limits of collected amounts, transfers the amounts received to the factors.

The increase in trade receivables of euro 2,305 million primarily related to the Gas & Power segment (euro 1,360 million), of which euro 112 million related to the outstanding amount of certain receivables associated with pre-payments received upon triggering the take-or-pay clause in gas sales contracts. Other increases related to the Refining & Marketing segment (euro 330 million) and to the Engineering & Construction segment (euro 309 million).

Trade and other receivables were as follows:

		Dec. 31, 2009		Dec. 31, 2010

(euro million)

Trade receivables

Other receivables

Total

Trade receivables

Other receivables

Total

Neither impaired nor past due		11,557		3,004		14,561		14,122		4,451		18,573
Impaired (net of the valuation allowance)		1,037		58		1,095		1,142		51		1,193
Not impaired and past due in the following periods:
- within 90 days		1,168		772		1,940		1,291		74		1,365
- 3 to 6 months		503		56		559		196		56		252
- 6 to 12 months		294		439		733		177		663		840
- over 12 months		357		578		935		293		458		751
		2,322		1,845		4,167		1,957		1,251		3,208
		14,916		4,907		19,823		17,221		5,753		22,974

Trade receivables not impaired and past due primarily pertained to high-credit-quality public administrations and other highly-reliable counterparties for oil, natural gas and chemical products supplies.

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Additions to allowances for impairment losses of trade receivables of euro 201 million (euro 260 million in 2009) primarily related to the Gas & Power (euro 136 million) and the Refining & Marketing segments (euro 31 million). Deductions to allowances for impairment losses amounted to euro 191 million (euro 15 million at December 31, 2009) and were recorded on the write-down of trade receivables (euro 101 million) and collection of previously impaired receivables (euro 90 million). Deductions in the Gas & Power segment were euro 99 million; in the Exploration & Production segment they were euro 41 million.

Trade receivables included guarantees for work in progress for euro 70 million (euro 168 million at December 31, 2009).

Trade receivables in currencies other than euro amounted to euro 5,069 million.

Other receivables for euro 482 million (euro 461 million at December 31, 2009) associated with cost recovery in the Exploration & Production segment are currently undergoing arbitration procedure.

Receivables for financing operating activities of euro 656 million (euro 452 million at December 31, 2009) included euro 470 million due from unconsolidated subsidiaries, joint ventures and associates (euro 245 million at December 31, 2009), euro 159 million cash deposit to provide coverage of Eni Insurance Ltd technical provisions (euro 179 million at December 31, 2009) and receivables for financial leasing for euro 19 million (the same amount as of December 31, 2009). More information about receivables for financial leasing is included in the Note 18 – Other financial assets.

Receivables for financing non-operating activities amounted to euro 6 million (euro 73 million at December 31, 2009) related to restricted deposits of the Engineering & Construction segment (euro 67 million at December 31, 2009).

Financing receivables in currencies other than euro amounted to euro 458 million.

Other receivables were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Accounts receivable from:
- joint venture operators in exploration and production		2,372		3,017
- Italian non-financial government entities		457		457
- insurance companies		194		131
		3,023		3,605
Prepayments for services		860		1,085
Receivables relating to factoring arrangements		156		190
Other receivables		868		873
		4,907		5,753

Receivables deriving from factoring arrangements of euro 190 million (euro 156 million at December 31, 2009) were related to Serfactoring SpA and consisted primarily of advances for factoring arrangements with recourse and receivables for factoring arrangements without recourse.

Other receivables in currencies other than euro amounted to euro 3,837 million.

Receivables with related parties are described in Note 42 – Transactions with related parties.

Because of the short-term maturity of trade receivables, the fair value approximated their carrying amount.

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10 Inventories
Inventories were as follows:

		Dec. 31, 2009		Dec. 31, 2010

(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		616		150				1,363		2,129		878		167				1,516		2,561
Products being processed and semi finished products		74		17				9		100		117		33				1		151
Work in progress						759				759						428				428
Finished products and goods		1,889		552				66		2,507		2,721		666				62		3,449
		2,579		719		759		1,438		5,495		3,716		866		428		1,579		6,589

Contract work in progress for euro 428 million (euro 759 million at December 31, 2009) are net of prepayments for euro 16 million (euro 13 million at December 31, 2009) within the limits of contractual considerations.

Changes in inventories and in provisions for impairments were as follows:

(euro million)

Value at the beginning of the year

Changes

Additions

Deductions

Changes in the scope of consolidation

Currency translation differences

Other changes

Value at the end of the year

Dec. 31, 2009
Gross value		6,779			(1,157	)								2			(35	)		9			5,598
Provisions for impairments		(697	)					(36	)		550						1			79			(103	)
Net value		6,082			(1,157	)		(36	)		550			2			(34	)		88			5,495
Dec. 31, 2010
Gross value		5,598			822									124			112			38			6,694
Provisions for impairments		(103	)					(16	)		23						(2	)		(7	)		(105	)
Net value		5,495			822			(16	)		23			124			110			31			6,589

Changes in the amount of euro 822 million essentially represented the Refining & Marketing segment (euro 817 million). Deductions in the amount of euro 23 million essentially represented the Petrochemical segment (euro 13 million). Changes in the scope of consolidation of euro 124 million essentially related to the inclusion of Altergaz SA following the acquisition of the control stake (euro 137 million) and the exclusion of GreenStream BV following the divestment of the control stake (euro 20 million).

11 Current tax assets
Current tax assets were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Italian subsidiaries		570		297
Foreign subsidiaries		183		170
		753		467

The decrease in other current tax assets of euro 286 million essentially related to receivables for interim tax payments made by Eni SpA in 2009, which exceeded the full-year tax payable, and were used, during 2010, to offset the payables of the year (euro 193 million).

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12 Other current tax assets
Other current tax assets were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

VAT		889		431
Excise and customs duties		119		192
Other taxes and duties		262		315
		1,270		938

The decrease in Valued Added Tax in the amount of euro 458 million essentially related to receivables for interim tax payments made by Eni SpA in 2009, which exceeded the full-year tax payable (euro 263 million).

13 Other current assets
Other current assets were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Fair value of non-hedging derivatives		698		626
Fair value of cash flow hedge derivatives		236		210
Other assets		373		514
		1,307		1,350

The fair value of derivative contracts which do not meet the criteria to be classified as hedges under IFRS was as follows:

		Dec. 31, 2009		Dec. 31, 2010

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Interest currency swap		2		113
Currency swap		64		1,855		1,117		123		1,357		4,411
Other		142		174		537		1		80		162
		208		2,142		1,654		124		1,437		4,573
Non-hedging derivatives on interest rate
Interest rate swap		1		133
Other		9		9
		10		142
Non-hedging derivatives on commodities
Over the counter		469		1,383		1,257		383		2,739		525
Future		10		234				33		418
Other		1				8		86				448
		480		1,617		1,265		502		3,157		973
		698		3,901		2,919		626		4,594		5,546

Fair value of the derivative contracts is determined using market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation methods used on the marketplace.

Fair values of non-hedging derivatives of euro 626 million (euro 698 million at December 31, 2009) essentially 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 or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.

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Fair value of cash flow hedge derivatives of euro 210 million (euro 236 million at December 31, 2009) essentially pertained to the Gas & Power segment (euro 209 million). These derivatives were designated to hedge surpluses or deficits of gas to achieve a proper balance in the gas portfolio. Other commodity derivatives were entered into to hedge variability in future cash flows on highly probable future sale transactions or on already contracted sales due to different movements in commodity prices as sales prices can be indexed to spot market benchmarks quoted on continental hub, whereas purchase costs are indexed to the price of oil and products. A similar scheme applies to exchange rate hedging derivatives.

Negative fair value of contracts expiring by 2011 is given in Note 25 – Other current liabilities; positive and negative fair value of contracts expiring beyond 2011 is given in Note 20 – Other non-current receivables and in Note 30 – Other non-current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are given in the Note 32 – Shareholders’ equity and in the Note 36 – Finance income (expense).

The nominal value of cash flow hedge derivatives for purchase and sale commitments was euro 1,145 million and euro 273 million, respectively.

Information on the hedged risks and the hedging policies is given in Note 34 – Guarantees, commitments and risks – Risk factors.

Other assets amounted to euro 514 million (euro 373 million at December 31, 2009) and included prepayments and accrued income for euro 155 million (euro 104 million at December 31, 2009), insurance premiums for euro 52 million (euro 18 million at December 31, 2009) and rentals for euro 20 million (euro 35 million at December 31, 2009).

Non-current assets

14 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 depreciation and impairments

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
Dec. 31, 2010
Land		618		3								18			4			22			665		693		28
Buildings		785		35		(94	)		(1	)		19			21			67			832		3,194		2,362
Plant and machinery		39,858		3,280		(6,755	)		(150	)		(652	)		1,721			5,689			42,991		108,464		65,473
Industrial and commercial equipment		787		115		(170	)								17			242			991		2,309		1,318
Other assets		543		143		(122	)					74			18			516			1,172		2,583		1,411
Tangible assets in progress and advances		17,174		8,732					(106	)		(58	)		833			(5,822	)		20,753		22,369		1,616
		59,765		12,308		(7,141	)		(257	)		(599	)		2,614			714			67,404		139,612		72,208

Capital expenditures of euro 12,308 million (euro 12,032 million at December 31, 2009) essentially related to the Exploration & Production segment (euro 8,622 million), the Engineering & Construction segment (euro 1,541 million), the Gas & Power segment (euro 1,251 million) and the Refining & Marketing segment (euro 704 million). Capital expenditures included capitalized finance expenses of euro 186 million (euro 221 million at December 31, 2009) essentially related to the Engineering & Construction segment (euro 66 million), the Exploration & Production segment (euro 57 million), the Gas & Power segment (euro 37 million) and the Refining & Marketing

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segment (euro 24 million). The interest rate used for the capitalization of finance expense ranged from 0.8% to 4.8% (1.9% and 3.7% at December 31, 2009).

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

The break-down by segment of impairments amounting to euro 257 million (euro 990 million at December 31, 2009) and the associated tax effect is provided below:

(euro million)		2009		2010

Impairment
Exploration & Production		576		123
Refining & Marketing		287		72
Petrochemicals		121		52
Other segments		6		10
		990		257
Tax effect
Exploration & Production		197		49
Refining & Marketing		108		28
Petrochemicals		33		15
Other segments		2		3
		340		95
Impairment net of the relevant tax effect
Exploration & Production		379		74
Refining & Marketing		179		44
Petrochemicals		88		37
Other segments		4		7
		650		162

In assessing whether impairment is required, the carrying value of an asset, item of property, plant and equipment, is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair value less costs to sell and value in use. Given the nature of Eni’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers are in 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. The Group’s main CGUs are: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields whereby technical, economic or contractual features make the underlying cash flows interdependent; (ii) in the Gas & Power segment, 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 Regulatory Authorities for the purpose of tariff settings. Other CGUs in the Gas & Power segment are gas carrier ships and plants for the production of electricity; (iii) in the Refining & Marketing segment, refining plants and commercial facilities relating to each distribution channels and by country (ordinary network, high-ways network, and wholesale activity); (iv) in the Petrochemical segment, production plants by business and related facilities; and (v) in the Engineering & Construction segment, the Business Units Offshore and Onshore constructions, Onshore drilling facilities and individual Rigs for Offshore operations. The recoverable amount is calculated by discounting the estimated cash flows deriving from the use of the CGU and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life. Recoverable amounts of the CGUs in the regulated businesses of gas transportation, distribution, storage and re-gasification equal their respective net borrowings recognized by Regulatory Authority, considering that the operating cost structure borne is recognized in the tariff regime set by Regulatory Authority (Regulatory Asset Base - RAB).

Cash flows are determined on the basis of the best information available at the moment of the assessment deriving: (i) for the first four years of the projection, from the Company’s four-year plan approved by the top management which provides information on expected oil and gas production volumes, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main

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macroeconomic variables, including inflation, nominal interest rates and exchange rates; (ii) for the subsequent years, considering management’s assumptions of long-term trends in the main macroeconomic variables (inflation rates, oil prices, etc.), cash flow projections are based on the following factors: (a) for the oil and gas CGUs, the residual life of the reserves and associated projections of operating costs and development expenditures; (b) for the CGUs of the Refining & Marketing segment, the economical and technical life of the plants and associated projections of operating costs, expenditures to support plant efficiency and refining and marketing margins; (c) for the CGUs of the Petrochemical segment, the economical and technical life of the plants and associated projections of expenditures to support plant efficiency, and normalized operating results plus depreciation (normalized EBITDA); (d) for the CGUs of the gas market and the Engineering & Construction segment, the perpetuity method of the last-year plan by using a nominal growth rate ranging from 0% to 2%; and (e) for the regulated businesses of gas transportation, distribution, storage and regasification, a terminal value equal to the regulatory asset base of the last-year plan; and (iii) the commodity prices have been assessed based on the forward prices prevailing in the marketplace as of the balance sheet date for the first four years of the cash flow projections and the long-term price assumptions adopted by the Company’s management for strategic planning purposes for the following years (see Note 3 – Summary of significant accounting policies).

Value-in-use is determined by discounting post-tax cash flows at the rate which corresponds for the Exploration & Production, Refining & Marketing and Petrochemical segments to the Company’s weighted average cost of capital, adjusted to consider risks specific to each country of activity (adjusted post-tax WACC). In 2010, the adjusted post-tax rates used for assessing value-in-use decreased by 0.5 percentage points on average from the previous year reflecting a reduced market premium for the equity risk and a slight decrease in the cost of borrowings to Eni following expected trends in the main market benchmarks. Such trends were partially offset by increased market yields on assets risk-free due to an higher risk premium for Italy. In 2010 the adjusted WACC used for impairment test purposes ranged from 8% to 13%.

Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

In 2010, the Exploration & Production segment recorded immaterial asset impairments, if individually considered, for a total amount of euro 123 million which primarily related to gas properties located in USA and Egypt as a result of a changed price environment and downward reserve revisions, particularly associated to unproved properties.

Other impairments were recorded in both the Refining & Marketing and the Petrochemical segments as expenditures made in the year were entirely written off due to lack of economic perspectives associated with the relevant CGUs which were totally impaired in previous reporting periods.

Foreign currency translation differences of euro 2,614 million were primarily related to translation of entities accounts denominated in U.S. dollar (euro 2,221 million).

Other changes of euro 714 million included the initial recognition and change in the estimated amount of the costs for dismantling and restoring oil sites and expenditures associated with certain social projects of the Exploration & Production segment for euro 556 million, of which euro 287 million related to the recognition of social projects by Eni North Africa BV and the reclassification from assets held for sale following the decision of the proposed buyer not to acquire the 100% stake in the share capital of Società Adriatica Idrocarburi SpA for euro 292 million. The book value of assets disposed of amounted to euro 95 million.

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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, 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
Dec. 31, 2010
Congo		1,164							(7	)		91			1,248
USA		882				(84	)		(150	)		70			718
Turkmenistan		649							(12	)		51			688
Algeria		452							(43	)		37			446
Other countries		231							(61	)		(9	)		161
		3,378				(84	)		(273	)		240			3,261

The accumulated provisions for impairments amounted to euro 5,680 million and euro 6,186 million at December 31, 2009 and 2010, respectively.

At December 31, 2010, Eni pledged property, plant and equipment for euro 28 million primarily as collateral against certain borrowings (the same amount as of December 31, 2009).

Government grants recorded as a decrease of property, plant and equipment amounted to euro 753 million (euro 642 million at December 31, 2009).

Assets acquired under financial lease agreements amounted to euro 27 million (euro 28 million at December 31, 2009), of which, euro 20 million related to FPSO ships used by the Exploration & Production segment to support oil production and treatment activities and euro 7 million related to service stations in the Refining & Marketing segment.

Contractual commitments related to the purchase of property, plant and equipment are included in Note 34 – Guarantees, commitments and risks – Liquidity risk.

Property, plant and equipment under concession arrangements are described in Note 34 – Guarantees, commitments and risks – Asset under concession arrangements.

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Property, plant and equipment by segment

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Property, plant and equipment, gross
Exploration & Production		71,189			85,494
Gas & Power		22,040			22,510
Refining & Marketing		13,378			14,177
Petrochemicals		5,174			5,226
Engineering & Construction		9,163			10,714
Other activities		1,592			1,614
Corporate and financial companies		373			372
Elimination of intra-group profits		(343	)		(495	)
		122,566			139,612
Accumulated depreciation, amortization and impairment losses
Exploration & Production		36,727			44,973
Gas & Power		8,262			8,634
Refining & Marketing		8,981			9,411
Petrochemicals		4,321			4,236
Engineering & Construction		2,858			3,292
Other activities		1,513			1,536
Corporate and financial companies		194			201
Elimination of intra-group profits		(55	)		(75	)
		62,801			72,208
Property, plant and equipment, net
Exploration & Production		34,462			40,521
Gas & Power		13,778			13,876
Refining & Marketing		4,397			4,766
Petrochemicals		853			990
Engineering & Construction		6,305			7,422
Other activities		79			78
Corporate and financial companies		179			171
Elimination of intra-group profits		(288	)		(420	)
		59,765			67,404

 

15 Inventory - compulsory stock
Inventory - compulsory stock was as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Crude oil and petroleum products		1,586		1,874
Natural gas		150		150
		1,736		2,024

Compulsory stock was primarily held by Italian companies (euro 1,724 million and euro 2,010 million at December 31, 2009 and 2010, respectively) in accordance with minimum stock requirements of oil, petrochemical products and natural gas set forth by applicable laws.

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16 Intangible assets
Intangible assets were as follows:

(euro million)

Net value at the beginning of the year

Investments

Amortization

Impairments

Changes 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, 2009
Intangible assets with finite useful lives
Exploration expenditures		971		1,273		(1,615	)							(20	)		22			631		2,259		1,628
Industrial patents and intellectual property rights		149		10		(85	)		(2	)							66			138		1,275		1,137
Concessions, licenses, trademarks and similar items		733		20		(153	)							1			70			671		2,403		1,732
Service concession arrangements		3,322		268		(121	)							17			(74	)		3,412		5,958		2,546
Intangible assets in progress and advances		580		83					(4	)				1			(79	)		581		584		3
Other intangible assets		1,733		9		(136	)							15			5			1,626		2,035		409
		7,488		1,663		(2,110	)		(6	)				14			10			7,059		14,514		7,455
Intangible assets with indefinite useful lives
Goodwill		3,531							(56	)		15		8			912			4,410
		11,019		1,663		(2,110	)		(62	)		15		22			922			11,469
Dec. 31, 2010
Intangible assets with finite useful lives
Exploration expenditures		631		1,038		(1,235	)					16		52			36			538		2,323		1,785
Industrial patents and intellectual property rights		138		38		(87	)										61			150		1,374		1,224
Concessions, licenses, trademarks and similar items		671		40		(160	)					6		1			17			575		2,410		1,835
Service concession arrangements		3,412		300		(134	)		(10	)				6			(12	)		3,562		6,205		2,643
Intangible assets in progress and advances		581		138					(1	)							(60	)		658		664		6
Other intangible assets		1,626		8		(128	)							9			(1	)		1,514		2,048		534
		7,059		1,562		(1,744	)		(11	)		22		68			41			6,997		15,024		8,027
Intangible assets with indefinite useful lives
Goodwill		4,410							(430	)		173		17			5			4,175
		11,469		1,562		(1,744	)		(441	)		195		85			46			11,172

Exploration expenditures of euro 538 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 upon expiration of terms or management’s decision to cease any exploration activities. Additions for the year included exploration drilling expenditures which were fully amortized as incurred for euro 1,009 million (euro 1,271 million at December 31, 2009).

Concessions, licenses, trademarks and similar items for euro 575 million primarily comprised transmission rights for natural gas imported from Algeria (euro 406 million) and concessions for mineral exploration (euro 121 million).

Service concession arrangements of euro 3,562 million primarily pertained to Italian gas distribution activity (euro 3,340 million and euro 3,492 million as of December 31, 2009 and 2010, respectively). Such activity is conducted in concession on the basis of municipal assignments, as the definition through relevant decrees of over-municipal minimum territorial reaches is still pending. At the expiration date of the concession, following the sale to a new operator of the gas distribution network, the outgoing operator is entitled to receive a reimbursement base on an industrial assessment of the relevant assets. Tariffs for the distribution service are defined by the Italian Authority for Electricity and Gas. Applicable regulations award concessions to distribution companies exclusively by means of competitive bid. Concessions are granted for a maximum term of 12 years. Government grants recorded as a decrease in the carrying amounts of service concession arrangements amounted to euro 729 million (euro 693 million as of December 31, 2009).

Other intangible assets with finite useful lives of euro 1,514 million primarily pertained to: (i) customer relationship and order backlog for euro 1,140 million (euro 1,244 million at December 31, 2009) recognized upon the business combination of Distrigas NV. These assets are amortized on the basis of the supply contract with the longest term (19 years) and the residual useful life of sale contracts (4 years); (ii) an option to develop offshore

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storage capacity for the commercial modulation of gas in the British North Sea which was recognized upon acquisition of Eni Hewett Ltd amounting to euro 241 million (euro 234 million at December 31, 2009). The asset impairment test confirmed recoverability of the book value; (iii) royalties for the use of licenses by Polimeri Europa SpA amounting to euro 64 million (euro 68 million at December 31, 2009); and (iv) estimated costs for Eni’s social responsibility projects in relation to oil development programs in Val d’Agri connected to mineral rights under concession for euro 35 million (euro 38 million at December 31, 2009) 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

Impairments of intangible assets with indefinite useful life (goodwill) of euro 430 million essentially pertained to the Gas & Power segment (euro 426 million), as described below. Change in the consolidation area of euro 173 million related to recognition of goodwill following the purchase price allocation in connection with the business combinations of Altergaz SA (euro 97 million) and Eni Mineralölhandel GmbH including its subsidiary Eni Marketing Austria GmbH (euro 76 million). More information is included in Note 33 – Other information – Main acquisitions.

The carrying amount of goodwill at the end of the year was euro 4,175 million (euro 4,410 million at December 31, 2009). The break-down by operating segment is as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Exploration & Production		249		262
Gas & Power		3,328		3,000
Refining & Marketing		84		164
Engineering & Construction		749		749
		4,410		4,175

Goodwill acquired through business combinations has been allocated to the cash-generating units ("CGUs") that are expected to benefit from the synergies of the acquisition. The CGUs of the Gas & Power segment are composed of such commercial business units whose cash flows are interdependent and therefore benefit from acquisition synergies. The recoverable amounts of the CGUs are determined by discounting the future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of their useful lives. Recoverable amounts of the CGUs in the regulated businesses of gas transportation, distribution, storage and re-gasification equal their respective regulatory asset base, considering that the operating cost structure borne is recognized in the tariff regime set by Regulatory Authority (RAB - Regulatory Asset Base).

Cash flows are determined on the basis of the best information available at the moment of the assessment deriving: (i) for the first four years of the projection, from the Company’s four-year plan approved by the top management which provides information on expected oil and gas production volumes, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates; (ii) for the subsequent years, considering management’s assumptions of long-term trends in the main macroeconomic variables (inflation rates, oil prices, etc.), cash flow projections are based on the following factors: (a) for the oil and gas CGUs, the residual life of the reserves and associated projections of operating costs and development expenditures; (b) for the CGUs of the Refining & Marketing segment, the economical and technical life of the plants and associated projections of operating costs, expenditures to support plant efficiency and refining and marketing margins; (c) for the CGUs of the gas market and the Engineering & Construction segment, the perpetuity method of the last-year plan by using a nominal growth rate ranging from 0% to 2%; and (d) for CGU of the regulated businesses of gas transportation - Italy, distribution, storage and re-gasification, a terminal value equal to the regulatory asset base of the last-year plan; and (iii) the commodity prices have been assessed based on the forward prices prevailing in the marketplace as of the balance sheet date for the first four years of the cash flow projections and the long-term price

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assumptions adopted by the Company’s management for strategic planning purposes for the following years (see Note 3 – Summary of significant accounting policies).

Value-in-use is determined by discounting post-tax cash flows at the rate which corresponds: (i) for the Exploration & Production and Refining & Marketing segments to the Company’s weighted average cost of capital, adjusted to consider risks specific to each country of activity (adjusted post-tax WACC). In 2010, the adjusted post-tax rates used for assessing value-in-use decreased by 0.5 percentage points on average from the previous year reflecting a reduced market premium for the equity risk and a slight decrease in the cost of borrowings to Eni following expected trends in the main market benchmarks. Such trends were partially offset by increased market yields on assets risk-free due to an higher risk premium for Italy. In 2010 the adjusted WACC used for impairment test purposes ranged from 8% to 13%; (ii) the impairment test rate for the Gas & Power segment was estimated on the basis of a sample of comparable companies in the utility industry. The impairment test rate for the Engineering & Construction segment was derived from market data. Rates used in the Gas & Power segment were adjusted to take into consideration risks specific to each country of activity, while rates used in the Engineering & Construction segment did not reflect any country risks as most of the company assets are not permanently located in a specific country. Rates for the Gas & Power segment ranged from 7% to 8%, unchanged from the previous year as the decrease observed in the equity risks for gas companies was lower than the oil sector and was completely absorbed by the impact of rising yields on assets risk-free. In the Engineering & Construction segment, the discount rate was 9%, an increase of 0.5 percentage points from the previous year due to an higher equity risk and higher rates of risk-free assets; and (iii) for the regulated activities in the Italian natural gas sector, the discount rates were assumed to be equal to the rates of return defined by the Italian Authority for Electricity and Gas.

Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

Goodwill has been allocated to the following CGUs:

Gas & Power segment

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Domestic gas market		766		767
Foreign gas market		2,247		1,918
- of which European market (Distrigas)		2,148		1,722
Domestic natural gas transportation network		305		305
Other		10		10
		3,328		3,000

Goodwill allocated to the CGU domestic gas market primarily pertained to goodwill recognized upon the buy-out of Italgas SpA minorities in 2003 through a public offering (euro 706 million). The relevant CGU is engaged in supplying gas to residential customers and small businesses. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of that CGU, including the allocated goodwill.

Goodwill allocated to the CGU European market pertained to goodwill recognized upon allocating the purchase price of the Distrigas business combination in 2009. The CGU comprises Distrigas marketing activities and those activities managed directly or indirectly by the Gas & Power division of the parent company Eni SpA, which includes marketing activities in Europe including France, Germany, Benelux, the UK, Switzerland and Austria. Those business units jointly benefited from the business combination synergies. In performing the impairment review of the recoverability of the CGU carrying amount at the balance sheet date, management recognized an impairment loss amounting to euro 426 million considering weak 2010 results and a reduced outlook for profitability.

The key assumptions adopted for determining future cash flow projections of both the CGUs Italian market and European market included marketing margins, forecast sales volumes, the discount rate and the growth rates adopted to determine the terminal value. Information on these drivers was derived from the four-year plan approved by the Company’s top management that was revised downwards with respect to past years future projections for returns and cash flows of the Company’s gas business, particularly the European market, due to expectations for weak demand and supply fundamentals, rising competitive pressures and increased commercial risk. The European market is expected to be negatively affected by lowering marketing margins over the next four years. This reflects ongoing development of very liquid spot markets for gas and the circumstance that spot prices have increasingly become the prevailing reference price for contractual formulae in supplies outside Italy whereas Eni’s purchase costs for gas are

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mainly indexed to the price of oil and refined products. Trends in spot prices as compared to those in oil-linked purchase costs have been de-coupling until recently resulting in negative spreads during the course of 2010; management expects that those negative trends will re-couple in 2014 at the earliest. Compared to the previous year exercise of four-year financial projections, management is now assuming that the CGU European market will be affected by the following negative factors: (i) an average reduction of 47% in unit marketing margins that will be earned on future gas sales relating to determination of value in use of that CGU; (ii) an average reduction of 7% in planned sales volumes; and (iii) the discount rate and the growth rate are unchanged from previous assumptions. The industrial and financial forecasts for the next four-year plan of the gas business as well as the amount of the impairment loss recognized in 2010 consolidated accounts both take into consideration management assumptions to renegotiate better economic terms within the Company’s long-term gas purchase contracts, so as to restore the competitiveness of the Company’s cost position in the current depressed scenario for the gas sector. The renegotiation of revised contractual terms, including any price revisions and contractual flexibility, is established by such contractual clauses whereby parties are held to bring the contract back to the economic equilibrium in case of significant changes in the market environment, like the ones that have occurred since from the second half 2008. In the course of 2010, Eni has finalized a number of important contractual renegotiations by obtaining improved economic conditions for supplies and wider contractual flexibility with a benefit to its commercial programs. A number of renegotiations have been commenced or are due to commence in the near future involving all the Company’s main suppliers of gas based on long-term contracts. Should the outcome of those renegotiations fall short of management’s expectations and absent a solid recovery in fundamentals of the gas sector, management believes that future results of operations and cash flows of the Company’s gas business will be negatively affected with further consequences in terms of recoverability of the carrying amounts of the CGU European market.

The terminal value of the CGUs was estimated based on the perpetuity method of the last year of the plan assuming a long-term nominal growth rate equal to zero and 1.6% for the CGU Italian market and the CGU European market, respectively. Value in use of the CGU European market was assessed by discounting the associated post-tax cash flows at a post-tax rate of 7.5% that corresponds to the pre-tax rate of 9.3% (7.5% and 10%, respectively in the previous year). Value in use of the CGU Italian market was assessed by discounting the associated post-tax cash flows at a post-tax rate of 7% that corresponds to the pre-tax rate of 11.7% (7% and 11.9%, respectively in the previous year).

The excess of the recoverable amount of the CGU domestic gas market over its carrying amount including the allocated portion of goodwill (headroom) amounting to euro 344 million would be reduced to zero under each of the following alternative hypothesis: (i) a decrease of 26% on average in the projected commercial margins; (ii) a decrease of 26% on average in the projected sales volumes; (iii) an increase of 2.8 percentage points in the discount rate; and (iv) a negative nominal growth rate of 3.5%. The recoverable amount of the CGU and the relevant sensitivity analysis were calculated solely on the basis of retail margins, thus excluding wholesale and business client margins (industrial, thermoelectric and others).

Goodwill allocated to the domestic natural gas transportation network CGU was recognized alongside the repurchase of own shares by Snam Rete Gas SpA and equals the difference between the purchase cost over the carrying amount of the corresponding share of net 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 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, 2009		Dec. 31, 2010

Offshore constructions		416		415
Onshore constructions		317		318
Other		16		16
		749		749

The segment goodwill of euro 749 million was mainly recognized following the acquisition of Bouygues Offshore SA, now Saipem SA (euro 711 million) and allocated to the CGUs Offshore and Onshore. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amounts of both those CGUs, including the allocated portions of goodwill.

The key assumptions adopted for assessing the recoverable amounts of those two CGUs which exceed their respective carrying amounts related to operating results, the discount rate and the growth rates adopted to determine

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the terminal value. Information on those drivers has been collected from the four-year plan approved by the Company’s top management, while the terminal value was estimated by using a perpetual nominal growth rate of 2% applied to the cash flow of the last year in the four-year plan. Value in use of both CGUs was assessed by discounting the associated post-tax cash flows at a post-tax rate of 9% (8.5% in 2009) which corresponds to the pre-tax rate of 11.8% and 13% for the Offshore business unit and the Onshore one respectively (10.8% and 12.3%, respectively in the previous year). The headroom of the Offshore business unit of euro 4,338 million would be reduced to zero under each of the following alternative changes in the above mentioned assumptions: (i) a decrease of 55% in the operating result of the four-year plan; (ii) an increase of about 9 percentage points of the discount rate; and (iii) negative real growth rate.

Changes in each of the assumptions that would cause the headroom of the Onshore business unit 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 with goodwill amounting to euro 262 million, management believes that there are no reasonably possible changes in the pricing environment and production/cost profiles that would cause the headroom of the relevant CGUs to be reduced to zero. Goodwill mainly refers to the portion of the purchase price that was not allocated to proved or unproved mineral interests of the business combinations Lasmo, Burren Energy (Congo) and First Calgary (Algeria) executed in previous reporting periods; and (ii) in the Refining & Marketing segment goodwill amounted to euro 164 million at the balance sheet date. Goodwill amounting to euro 66 million pertained to retail networks in the Czech Republic, Hungary and Slovakia which were purchased in 2008, for which the growth expectations improved in respect of the previous year following to a demand recovery and a better marketing position. Goodwill amounting to euro 76 million represented the allocation of the purchase price of a business combination involving a service station in Austria which was acquired in August 2010.

17 Investments

Investments accounted for using the equity method
Equity-accounted investments were as follows:

(euro million)

Value at the beginning of the year

Acquisitions and subscriptions

Sales and reimbursements

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, 2009
Investments in unconsolidated entities controlled by Eni		177		1		(14	)		42		(4	)		(8	)		(3	)		26			217
Joint ventures		3,257		25		(111	)		478		(81	)		(254	)		(54	)		67			3,327
Associates		2,037		200		(24	)		173		(156	)		(122	)		(31	)		207			2,284
		5,471		226		(149	)		693		(241	)		(384	)		(88	)		300			5,828
Dec. 31, 2010
Investments in unconsolidated entities controlled by Eni		217		32		(3	)		75		(18	)		(38	)		9			(18	)		256
Joint ventures		3,327		44		(526	)		379		(124	)		(312	)		124			(177	)		2,735
Associates		2,284		187		(33	)		263		(7	)		(130	)		81			32			2,677
		5,828		263		(562	)		717		(149	)		(480	)		214			(163	)		5,668

Acquisitions and subscriptions for euro 263 million related to the subscription of capital increase, of which euro 183 million related to Angola LNG Ltd.

Sales and reimbursements of equity-accounted investments of euro 562 million mainly pertained to the capital reimbursement of Artic Russia BV (euro 526 million) following the divestment of a 51% stake in the Eni-Enel joint venture OOO "SeverEnergia" as Gazprom exercised a call option on September 23, 2009. On March 31, 2010, Eni collected a second installment of the transaction amounting to euro 526 million (as converted at the EUR/USD exchange rate of 1.35 as of the transaction date, corresponding to approximately $710 million).

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Share of profit of equity-accounted investments and the decrease following the distribution of the dividends pertained to the following companies:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

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		116		64		33.34			147		55		33.34
Unión Fenosa Gas SA		108		138		50.00			116		126		50.00
Trans Austria Gasleitung GmbH		84		22		89.00			98		67		89.00
United Gas Derivatives Co		24		40		24.55	(*)		47		44		24.55	(*)
Eni BTC Ltd		35				100.00			37		35		100.00
Blue Stream Pipeline Co BV		33				50.00			36				50.00
Other investments		293		120					236		153
		693		384					717		480

(*)		Equity ratio 33.33.

Share of losses of equity-accounted investments of euro 149 million primarily related to CARDÓN IV SA (euro 40 million) and Super Octanos CA (euro 36 million).

Other changes of euro 163 million included: (i) reclassification to assets held for sale of the carrying amounts relating Trans Austria Gasleitung GmbH (euro 203 million), Transitgas AG (euro 40 million) and Trans Europa Naturgas Pipeline Gesellschaft mbH & Co KG (euro 8 million). More information is included in Note 31 – Assets held for sale and liabilities directly associated with assets held for sale; (ii) the exclusion from joint ventures and the inclusion in the scope of consolidation following the acquisition of the controlling interest of Altergaz SA (euro 67 million); and (iii) as an increase the exclusion from the scope of consolidation and the inclusion in equity-accounted investments of GreenStream BV (euro 149 million) following the sale of 25% of its share capital.

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The following table sets out the net carrying amount relating to equity-accounted investments:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

		Net carrying amount		Eni’s interest %		Net carrying amount		Eni’s interest %

Investments in unconsolidated entities controlled by Eni:
- Eni BTC Ltd		93		100.00			104		100.00
- Eni BBI Ltd		3		100.00			28		100.00
- other investments (1)		121					124
		217					256
Joint ventures:
- Unión Fenosa Gas SA		473		50.00			468		50.00
- Artic Russia BV		918		60.00			445		60.00
- Blue Stream Pipeline Co BV		371		50.00			435		50.00
- EnBW Eni Verwaltungsgesellschaft mbH		284		50.00			285		50.00
- Azienda Energia e Servizi Torino SpA		170		49.00			172		49.00
- Eteria Parohis Aeriou Thessalonikis AE		161		49.00			160		49.00
- Toscana Energia SpA		143		49.38			155		48.13
- GreenStream BV							147		50.00
- Raffineria di Milazzo ScpA		128		50.00			128		50.00
- Unimar Llc		72		50.00			74		50.00
- Supermetanol CA		80		34.51			66		34.51
- Eteria Parohis Aeriou Thessalias AE		43		49.00			43		49.00
- Starstroi Llc		31		50.00			19		50.00
- Trans Austria Gasleitung GmbH		170		89.00
- Super Octanos CA		66		49.00
- Transitgas AG		33		46.00
- Altergaz SA		28		41.62
- other investments (1)		156					138
		3,327					2,735
Associates:
- Galp Energia SGPS SA		914		33.34			1,005		33.34
- Angola LNG Ltd		612		13.60			841		13.60
- PetroSucre SA		176		26.00			198		26.00
- Ceska Rafinerska AS		184		32.44			189		32.44
- United Gas Derivatives Co		84		24.55	(2)		94		24.55	(2)
- Fertilizantes Nitrogenados de Oriente CEC		68		20.00			68		20.00
- ACAM Gas SpA		47		49.00			48		49.00
- Termica Milazzo Srl		23		40.00			40		40.00
- Distribuidora de Gas del Centro SA		29		31.35			32		31.35
- Gaz de Bordeaux SAS		13		17.00			27		34.00
- other investments (1)		134					135
		2,284					2,677
		5,828					5,668

(1)		Each individual amount included herein did not exceed euro 25 million.
(2)		Equity ratio 33.33.

Carrying amounts of investments in unconsolidated entities, including entities controlled by Eni, joint ventures and associates, comprised differences between the purchase price of relevant shareholdings and the corresponding Eni’s share in the net equity of each entities amounting to euro 511 million, of which euro 347 million referred to goodwill. Such differences primarily related to Unión Fenosa Gas SA (euro 195 million of goodwill), EnBW - Eni Verwaltungsgesellschaft mbH (euro 181 million, of which euro 18 million of goodwill) and Galp Energia SGPS SA (euro 106 million of goodwill).

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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		14.34		3,965

The table below sets out the provisions for losses included in the provisions for contingencies of euro 124 million (euro 170 million at December 31, 2009), primarily related to the following equity-accounted investments:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Industria Siciliana Acido Fosforico - ISAF - SpA (under liquidation)		64		59
Southern Gas Constructors Ltd		13		31
Charville - Consultores e Serviços Lda		21		12
Other investments		72		22
		170		124

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, 2009
Investments in unconsolidated entities controlled by Eni		30				(1	)		15			44		55		11
Associates		4							4			8		8
Other investments		376		4		(7	)		(9	)		364		371		7
		410		4		(8	)		10			416		434		18
Dec. 31, 2010
Investments in unconsolidated entities controlled by Eni		44				2			(17	)		29		29
Associates		8				1			1			10		18		8
Other investments		364		4		16			(1	)		383		390		7
		416		4		19			(17	)		422		437		15

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.

The net carrying amount of other investments of euro 422 million (euro 416 million at December 31, 2009) was related to the following entities:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

		Net carrying amount		Eni’s interest %		Net carrying amount		Eni’s interest %

Investments in unconsolidated entities controlled by Eni (*)		44				29
Associates		8				10
Other investments:
- Interconnector (UK) Ltd		134		16.06		136		16.07
- Nigeria LNG Ltd		82		10.40		89		10.40
- Darwin LNG Pty Ltd		78		10.99		79		10.99
- other (*)		70				79
		364				383
		416				422

(*)		Each individual amount included herein did not exceed euro 25 million.

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Provisions for losses related to other investments, included within the provisions for contingencies, amounted to euro 76 million (euro 41 million at December 31, 2009) and were primarily in relation to the following entities:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Eni BB Ltd				28
Burren Energy Shipping & Transportation (Samara) Ltd		25		25
Caspian Pipeline Consortium R - Closed Joint Stock Co		15		19
Other investments		1		4
		41		76

Other information about investments
The following table summarizes key financial data of unconsolidated entities controlled by Eni, joint ventures and associates prepared in accordance with accounting policies adopted in the preparation of Eni’s Consolidated Financial Statements and reflecting Eni’s interest in such entities:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Unconsolidated entities controlled by Eni

Joint ventures

Associates

Unconsolidated entities controlled by Eni

Joint ventures

Associates

Total assets		2,215			6,981		4,218		2,383			5,711		5,087
Total liabilities		2,081			3,721		1,929		2,193			3,022		2,410
Net sales from operations		65			3,936		5,718		113			3,497		5,134
Operating profit		(48	)		564		141		(9	)		434		323
Net profit		(9	)		474		101		32			252		225

The total assets and liabilities of unconsolidated controlled entities of euro 2,383 million and euro 2,193 million, respectively (euro 2,215 million and euro 2,081 million at December 31, 2009) pertained to entities acting as sole-operator in the management of oil and gas contracts for euro 2,172 million and euro 2,054 million (euro 1,873 million and euro 1,860 million at December 31, 2009). The residual amount pertained to not significant entities. More information is included in Note 1 – Basis of presentation.

 

18 Other financial assets
Other financing receivables were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Receivables for financing operating activities		1,112		1,488
Securities held for operating purposes		36		35
		1,148		1,523

Receivables for financing operating activities are presented net of the allowance for impairment losses of euro 32 million (euro 29 million at December 31, 2009).

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Operating financing receivables of euro 1,488 million (euro 1,112 million at December 31, 2009) primarily pertained to loans made by the Exploration & Production segment (euro 716 million), Gas & Power segment (euro 559 million) and Refining & Marketing segment (euro 96 million) to certain equity-accounted or cost-accounted entities which executed capital projects on behalf of Eni’s Group companies. Financing receivables due from unconsolidated subsidiaries, joint ventures and associates amounted to euro 656 million. Receivables for financial leasing amounted to euro 78 million (euro 97 million at December 31, 2009) and pertained to the disposal of the Belgian gas network by Finpipe GIE. The following table shows principal receivable by maturity date, which was obtained by summing future lease payment receivables discounted at the effective interest rate, interests and the nominal value of future lease receivables:

(euro million)		Maturity range

		Within 12 months		Between one and five years		Total

Principal receivable		19		78		97
Interests		6		10		16
Undiscounted value of future lease payments		25		88		113

Receivables with a maturity date within one year is shown in current assets in the item trade receivables for operating purposes - current portion of long-term receivables in the Note 9 – Trade and other receivables.

Receivables for financing operating activities in currencies other than euro amounted to euro 1,128 million (euro 716 million at December 31, 2009).

Receivables for financing operating activities due beyond five years amounted to euro 823 million (euro 460 million at December 31, 2009).

Securities of euro 35 million (euro 36 million at December 31, 2009), designated as held-to-maturity investments, are listed securities, issued by the Italian Government (euro 20 million) and by foreign governments (euro 15 million).

Securities with a maturity beyond five years amounted to euro 21 million.

Fair value of receivables for financing operating activities amounted to euro 1,534 million. 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 0.8% to 4.1% (1.0% and 4.5% at December 31, 2009). The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in Note 42 – Transactions with related parties.

19 Deferred tax assets
Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for euro 3,421 million (euro 3,764 million at December 31, 2009).

(euro million)

Value at Dec. 31, 2009

Additions

Deductions

Currency translation differences

Other changes

Value at Dec. 31, 2010

		3,558		1,612		(1,066	)		224		536		4,864

Deferred tax assets are described in Note 29 – Deferred tax liabilities.

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20 Other non-current receivables
The following table provides an analysis of other non-current receivables:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Tax receivables from:
- Italian tax authorities
. income tax		18		14
. interest on tax credits		55		65
		73		79
- foreign tax authorities		39		106
		112		185
Other receivables:
- in relation to disposals		710		800
- other non-current receivables		215		224
		925		1,024
Fair value of non-hedging derivatives		339		420
Fair value of cash flow hedge derivative instruments		129		102
Other asset		433		1,624
		1,938		3,355

Other receivables amounting to euro 800 million related to the divestment of certain assets which occurred in prior periods, including: (i) a receivable of euro 474 million recognized in 2008 upon the agreement signed with the Republic of Venezuela whereby Eni would receive cash compensation for the expropriated Dación oilfield to be collected in seven annual installments with accrual of interests. Following an agreement achieved, future installments can be paid in kind through equivalent collections of hydrocarbons. The 2009 installment of euro 71 million ($104 million) was collected in kind. The Company achieved new agreements for future installments that will be paid in kind through equivalent collections of hydrocarbons during 2011; and (ii) a receivable of euro 313 million related to the divestment of the interest of 1.71% in the Kashagan project to the local partner KazMunaiGas on the basis of the agreements defined with the international partners of the North Caspian Sea PSA and the Kashagan government, which are effective starting from January 1, 2008. The reimbursement of the receivable is provided for in three annual installments starting from the date of the production beginning.

The fair value of derivative contracts which do not meet the criteria to be classified as hedges under IFRS was as follows:

		Dec. 31, 2009		Dec. 31, 2010

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Interest Currency Swap		112		458		197		171		714		95
Currency swap		7		333		33		11		83		99
Other
		119		791		230		182		797		194
Non-hedging derivatives on interest rate
Interest rate swap		46		677		563		83		691		3,615
		46		677		563		83		691		3,615
Non-hedging derivatives on commodities
Over the counter		172		540		659		134		1,578		119
Future		2		37
Other								21				54
		174		577		659		155		1,578		173
		339		2,045		1,452		420		3,066		3,982

Fair value of the derivative contracts is determined using market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation methods generally accepted in the marketplace.

Fair values of non-hedging derivatives of euro 420 million (euro 339 million at December 31, 2009) essentially consisted of derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because

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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 of euro 102 million (euro 129 million at December 31, 2009) referred to the Gas & Power segment. Further information on cash flow hedge derivatives is given in Note 13 – Other current assets. Fair value related to the contracts expiring beyond 2011 is given in Note 30 – Other non-current liabilities; fair value related to the contracts expiring in 2011 is indicated in Note 13 – Other assets and in Note 25 – Other current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are given in Note 32 – Shareholders’ equity and in Note 36 – Operating expenses.

Nominal value of cash flow hedge derivatives for purchase and sale commitments was euro 775 million and euro 145 million, respectively.

Information on the hedged risks and the hedging policies is given in Note 34 – Guarantees, commitments – Risk factors.

Other asset of euro 1,624 million (euro 433 million at December 31, 2009) included prepayments amounting to euro 1,436 million that were made to gas suppliers upon triggering the take-or-pay clause provided by the relevant long-term arrangement. In accordance to those arrangements, the Company is contractually required to off-take minimum annual quantities of gas, or in case of failure is held to pay the whole price or a fraction for the uncollected volumes up to the minimum annual quantity. The Company is entitled to collect the pre-paid volumes in future years alongside the contract execution and for its entire duration or a shorter term as the case may be. The carrying amounts of those deferred costs, which are substantially equivalent to a receivable in-kind, are stated at the purchase cost or the net realizable value, whichever is lower. Prior-years impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. In future years, management plans to recover the prepaid volumes by regaining market share and expanding its sales volumes in the European gas market leveraging on strengthening the Company’s market leadership and consolidating its customer base in the Italian market through effective marketing actions in both the retail market and the industrial and thermoelectric sector. Those action plans coupled with perspectives of steady long-term demand growth until 2020 will enable the Company to absorb volumes pre-paid during the market downturn. The industrial and financial forecasts for the next four-year plan of the gas business and beyond took into consideration management’s assumptions to renegotiate better economic terms within the Company’s long-term gas purchase contracts, so as to restore the competitiveness of the Company’s cost position in the current depressed scenario for the gas sector. The renegotiation of revised contractual terms, including any price revisions and contractual flexibility, is established by such contractual clauses whereby parties are held to bring the contract back to the economic equilibrium in case of significant changes in the market environment, like the ones that have occurred since the second half 2008. In the course of 2010, Eni has finalized a number of important contractual renegotiations by obtaining improved economic conditions for supplies and wider contractual flexibility with a benefit to its commercial programs. A number of renegotiations have commenced or are due to commence in the near future involving all the Company’s main suppliers of gas based on long-term contracts. Should the outcome of those renegotiations fall short of management’s expectations and absent a solid recovery in fundamentals of the gas sector, management believes that future results of operations and cash flows of the Company’s gas business will be negatively affected.

Current liabilities

21 Short-term debt
Short-term debt was as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Banks		683		1,950
Commercial papers		2,718		4,244
Other financial institutions		144		321
		3,545		6,515

Short-term debt increased by euro 2,970 million primarily due to the balance of repayments and new proceeds (euro 2,646 million) and currency translation differences (euro 326 million). Commercial papers of euro 4,244

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million (euro 2,718 million at December 31, 2009) were mainly issued by the financial companies Eni Coordination Center SA (euro 2,655 million) and Eni Finance USA Inc (euro 1,589 million).

Short-term debt per currency is shown in the table below:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Euro		1,143		2,919
U.S. dollar		2,321		3,403
Other currencies		81		193
		3,545		6,515

In 2010, the weighted average interest rate on short-term debt was 0.7% (0.8% in 2009).

At December 31, 2010 Eni had undrawn committed and uncommitted borrowing facilities amounting to euro 2,498 million and euro 7,860 million, respectively (euro 2,241 million and euro 9,533 million at December 31, 2009). Those facilities bore interest rates reflecting prevailing conditions on the marketplace. Charges for unutilized facilities were immaterial.

22 Trade and other payables
Trade and other payables were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Trade payables		10,078		13,111
Advances		3,230		3,139
Other payables:
- related to capital expenditures		1,541		1,856
- others		4,325		4,469
		5,866		6,325
		19,174		22,575

The increase of euro 3,033 million in trade payables was primarily related to the Refining & Marketing segment (euro 1,398 million), the Gas & Power segment (euro 1,072 million) and the Exploration & Production segment (euro 372 million).

Advances of euro 3,139 million (euro 3,230 million at December 31, 2009) pertained to prepayments on contract work in progress for euro 1,539 million, advances on contract work in progress for euro 1,042 million (euro 1,469 million and euro 1,121 million at December 31, 2009, respectively) and other advances for euro 558 million (euro 640 million at December 31, 2009). Advances on contract work in progress were in respect of the Engineering & Construction segment. Other advances included advances amounting to euro 251 million due to gas customers who off-took lower quantities of gas than the contractual minimum quantity for the year (the contractual year or the calendar one as the case may be) as provided by the relevant long-term sale arrangement, thus triggering the take-or-pay clause.

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Other payables were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Payables due to:
- joint venture operators in exploration and production activities		2,305		2,382
- suppliers in relation to investing activities		809		1,224
- non-financial government entities		661		628
- employees		451		571
- social security entities		292		261
		4,518		5,066
Other payables		1,348		1,259
		5,866		6,325

Other payables of euro 1,259 million (euro 1,348 million at December 31, 2009) included payables due to gas suppliers for euro 214 million (euro 282 million at December 31, 2009) associated to the take-or-pay obligations. In the calendar year or thermal year ending December 31, 2010, the Company was unable to off-take the minimum annual quantities of gas provided by the relevant purchase agreements thus triggering the take-or-pay clause. Further information is provided in Note 20 – Other non-current assets.

Payables with related parties are described in Note 42 – Transactions with related parties.

The fair value of trade and other payables did not differ significantly from their carrying amounts considering the short-term maturity of trade payables.

23 Income taxes payable
Income taxes payable were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Italian subsidiaries		363		300
Foreign subsidiaries		928		1,215
		1,291		1,515

Income taxes payable by Italian subsidiaries were affected by a positive effect of the fair value valuation of cash flow hedging derivatives (euro 87 million). Further information is provided in Note 25 – Other current liabilities.

24 Other taxes payable
Other taxes payable were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Excise and customs duties		832		930
Other taxes and duties		599		729
		1,431		1,659

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25 Other current liabilities
Other current liabilities were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Fair value of non-hedging derivatives		691		656
Fair value of cash flow hedge derivatives		680		475
Other liabilities		485		489
		1,856		1,620

Fair value of non-hedging derivative contracts was as follows:

		Dec. 31, 2009		Dec. 31, 2010

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Currency swap		113		3,044		2,487		162		4,776		1,582
Interest currency swap		8		113				18		116
Other		135		107		684		1		141		29
		256		3,264		3,171		181		5,033		1,611
Non-hedging derivatives on interest rate
Interest rate swap		15				816		11		25		1,504
		15				816		11		25		1,504
Non-hedging derivatives on commodities
Over the counter		415		1,244		549		354		430		2,277
Future		2				54		10				161
Other		3		2				100				442
		420		1,246		603		464		430		2,880
		691		4,510		4,590		656		5,488		5,995

Fair value of derivative contracts was determined by using market quotations given by primary info-providers, or, absent market information, on the basis of valuation models generally accepted in the marketplace.

Fair values of non-hedging derivatives of euro 656 million (euro 691 million at December 31, 2009) mainly pertained to derivative contracts that did 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 475 million (euro 680 million at December 31, 2009) and pertained to the Gas & Power segment for euro 244 million and the Exploration & Production segment for euro 231 million (euro 311 million and euro 369 million at December 31, 2009, respectively). Fair value pertaining to the Gas & Power segment pertained to derivatives that were designated to hedge surpluses or deficits of gas to achieve a proper balance in the gas portfolio and hedge the exchange rate and commodity risk exposure as described in Note 13 – Other current assets. Fair value pertaining to the Exploration & Production segment pertained to future sale agreements of proved oil reserves due in 2011. Those derivatives were entered into to hedge exposure to variability in future cash flows deriving from the sale in the 2008-2011 period of approximately 2% of Eni’s proved reserves as of December 31, 2006, corresponding to 125.7 mmBBL, decreasing to 9 mmBBL as of December 31, 2010 due to transactions settled. Fair value of contracts expiring by 2010 is given in Note 13 – Other current assets; fair value of contracts expiring beyond 2010 is given in Note 30 – Other non-current liabilities and in Note 20 – Other non-current assets. The effects of the evaluation at fair value of cash flow hedge derivatives are given in the Note 32 – Shareholders’ equity and in the Note 36 – Operating expenses.

The nominal value of cash flow hedge derivatives referred to purchase and sale commitments for euro 1,805 million and euro 849 million, respectively (euro 1,882 million and euro 272 million at December 31, 2009, respectively).

Information on the hedged risks and the hedging policies is given in Note 34 – Guarantees, commitments and risks – Risk factors.

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Non-current liabilities

26 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		2009		2010		Current maturity 2011		2012		2013		2014		2015		After		Total

Banks		2011-2029		9,056		7,224		499		3,460		824		623		550		1,268		6,725
Ordinary bonds		2011-2040		11,687		13,572		410		46		1,603		1,333		2,212		7,968		13,162
Other financial institutions		2011-2021		512		472		54		77		58		53		53		177		418
				21,255		21,268		963		3,583		2,485		2,009		2,815		9,413		20,305

Long-term debt, including the current portion of long-term debt, of euro 21,268 million (euro 21,255 million at December 31, 2009) increased by euro 13 million. Changes included net payments for euro 374 million and, as increase, currency translation differences arose from the translation of financial statements denominated in currencies other than euro and translation differences arising on debt taken on by euro-reporting subsidiaries denominated in foreign currency which are translated into euros at year-end exchange rates of euro 172 million.

Debt from banks of euro 7,224 million related to committed borrowing facilities for euro 1,812 million.

Debt from other financial institutions of euro 472 million (euro 512 million at December 31, 2009) included euro 17 million of finance lease transactions (euro 24 million at December 31, 2009).

Eni entered into long-term borrowing facilities with the European Investment Bank which were subject to the maintenance of certain performance indicators based on Eni’s consolidated financial statements or the maintenance of a minimum level of credit rating. As of the balance sheet date, Eni was in compliance with those covenants. According to the agreements, should the Company fail to comply with maintenance of a minimum credit rating, new guarantees would be provided to be agreed upon with the European Investment Bank. At December 31, 2009 and 2010, the amount of short and long-term debt subject to restrictive covenants was euro 1,508 million and euro 1,685 million, respectively. A possible non-compliance with those covenants would be immaterial to the Company’s ability to finance its operations. Eni is in compliance with the covenants contained in its financing arrangements. During 2010, Saipem repaid financial debt which was subject to certain performance indicators (euro 75 million).

Bonds of euro 13,572 million consisted of bonds issued within the Euro Medium Term Notes Program for a total of euro 10,678 million and other bonds for a total of euro 2,894 million.

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The following table analyses bonds per issuing entity, maturity date, interest rate and currency as at December 31, 2010:

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		60			1,560		EUR				2016				5.000
- Eni SpA		1,500		45			1,545		EUR				2013				4.625
- Eni SpA		1,500		8			1,508		EUR				2019				4.125
- Eni SpA		1,250		67			1,317		EUR				2014				5.875
- Eni SpA		1,250		(3	)		1,247		EUR				2017				4.750
- Eni SpA		1,000		17			1,017		EUR				2020				4.000
- Eni SpA		1,000		(3	)		997		EUR				2018				3.500
- Eni Coordination Center SA		523		9			532		GBP		2011		2019		5.000		6.125
- Eni Coordination Center SA		423		3			426		YEN		2012		2037		1.150		2.810
- Eni Coordination Center SA		250		8			258		EUR		2017		2028		3.750		5.600
- Eni Coordination Center SA		191		5			196		USD		2013		2015		4.450		4.800
- Eni Coordination Center SA		41					41		EUR		2011		2015				variable
- Eni Coordination Center SA		34					34		USD				2013				variable
		10,462		216			10,678
Other bonds:
- Eni SpA		1,000		8			1,008		EUR				2015				4.000
- Eni SpA		1,000		(11	)		989		EUR				2015				variable
- Eni SpA		337					337		USD				2020				4.150
- Eni SpA		262		1			263		USD				2040				5.700
- Eni USA Inc		299		(3	)		296		USD				2027				7.300
- Eni UK Holding Plc		1					1		GBP				2013				variable
		2,899		(5	)		2,894
		13,361		211			13,572

As at December 31, 2010 bonds maturing within 18 months (euro 192 million) were issued by Eni Coordination Center SA. During 2010, Eni SpA issued bonds for euro 2,614 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, 2009 (euro million)		Average rate (%)		Dec. 31, 2010 (euro million)		Average rate (%)

Euro		19,345		3.9		18,895		3.5
U.S. dollar		779		3.9		1,415		5.7
British pound		742		5.2		527		5.5
Japanese yen		348		2.0		426		2.0
Other currencies		41		3.0		5		6.8
		21,255				21,268

At December 31, 2010 Eni had undrawn committed long-term borrowing facilities of euro 4,901 million (euro 2,850 million at December 31, 2009). Those facilities bore interest rates reflecting prevailing conditions on the marketplace. Charges for unutilized facilities were immaterial.

Fair value of long-term debt, including the current portion of long-term debt amounted to euro 22,607 million (euro 22,320 million at December 31, 2009) and consisted of the following:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Ordinary bonds		12,618		14,790
Banks		9,152		7,306
Other financial institutions		550		511
		22,320		22,607

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Fair value was calculated by discounting the expected future cash flows at rates ranging from 0.8% to 4.1% (1.0% and 4.5% at December 31, 2009).

At December 31, 2010 Eni did not pledge restricted deposits as collateral against its borrowings.

 

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

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Current

Non-current

Total

Current

Non-current

Total

A.	Cash and cash equivalents		1,608				1,608		1,549				1,549
B.	Available-for-sale securities		64				64		109				109
C.	Liquidity (A+B)		1,672				1,672		1,658				1,658
D.	Financing receivables		73				73		6				6
E.	Short-term debt towards banks		683				683		1,950				1,950
F.	Long-term debt towards banks		2,028		7,028		9,056		499		6,725		7,224
G.	Bonds		1,111		10,576		11,687		410		13,162		13,572
H.	Short-term debt towards related parties		147				147		127				127
I.	Other short-term debt		2,715				2,715		4,438				4,438
L.	Other long-term debt		52		460		512		54		418		472
M.	Total borrowings (E+F+G+H+I+L)		6,736		18,064		24,800		7,478		20,305		27,783
N.	Net borrowings (M-C-D)		4,991		18,064		23,055		5,814		20,305		26,119

Available-for-sale securities of euro 109 million (euro 64 million at December 31, 2009) 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 308 million (euro 320 million at December 31, 2009), of which euro 267 million (euro 284 million at December 31, 2009) were held to provide coverage of technical reserves for Eni’s insurance company, Eni Insurance Ltd.

Financing receivables of euro 6 million (euro 73 million at December 31, 2009) were held for non-operating purposes. Not included in the calculation above were financing receivables held for operating purposes amounting to euro 656 million (euro 452 million at December 31, 2009), of which euro 470 million (euro 245 million at December 31, 2009) were in respect of financing granted to unconsolidated entities which executed capital projects and investments on behalf of Eni’s Group companies and an euro 159 million cash deposit (euro 179 million at December 31, 2009) to provide coverage of Eni Insurance Ltd technical reserves.

 

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27 Provisions for contingencies
Provisions for contingencies were as follows:

(euro million)

Value at Dec. 31, 2009

Additions

Initial recognition and changes in estimates

Accretion discount

Reversal of utilized provisions

Reversal of unutilized provisions

Other changes

Value at Dec. 31, 2010

Provision for site restoration, abandonment and social projects		4,828				558		238		(175	)		(26	)		318			5,741
Provision for environmental risks		1,936		1,376				10		(203	)		(24	)		9			3,104
Provision for legal and other proceedings		1,168		125						(297	)		(310	)		6			692
Loss adjustments and actuarial provisions for Eni’s insurance companies		514		32						(149	)					1			398
Provision for taxes		296		100						(45	)		(1	)		7			357
Provision for the supply of goods		353		135				2		(106	)		(96	)					288
Provision for redundancy incentives		23		184						(4	)		(1	)					202
Provision for losses on investments		211		72									(14	)		(69	)		200
Provision for onerous contracts		90		70						(58	)					6			108
Provision for OIL insurance cover		79		14						(7	)		(9	)		2			79
Other (*)		821		207				1		(240	)		(108	)		(58	)		623
		10,319		2,315		558		251		(1,284	)		(589	)		222			11,792

(*)		Each individual amount included herein does not exceed euro 50 million.

Provision for site restoration and abandonment and social projects amounted to euro 5,741 million of which euro 5,373 million related to the discounted 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. The increase in the provision for the year amounted to euro 558 million and was primarily due to changes of estimated expenditures and the initial recognition in the estimates of future costs made by Nigerian Agip Oil Co Ltd (euro 125 million) and Eni Petroleum Co Inc (euro 117 million) and the recognition of social projects by Eni North Africa BV (euro 287 million). Also an amount of euro 238 million was recognized through profit and loss as accretion charge for the period. The discount rates adopted ranged from 2.1% to 8.9% (from 1.9% to 8.8% at December 31, 2009). Other increases of euro 318 million included currency translation differences (euro 190 million) and reclassification of the provision held by Società Adriatica Idrocarburi SpA (euro 137 million) from assets held for sale following the decision of the proposed buyer not to acquire the 100% stake. Management estimates that main expenditures associated with site restoration and abandonment operations will be incurred over a 25-year period starting from 2018.

Provision for environmental risks of euro 3,104 million primarily related to the estimated future costs of environmental cleaning-up and remediation in accordance with applicable laws and regulations. Also the provision included the estimated costs of environmental cleaning-up and restoring areas owned or held in concession by the Company, part of its industrial sites which were divested, shut-down or liquidated in previous reporting periods. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to perform certain cleaning-up and restoration projects and reliable cost estimation is available. Based on this latter assumption, the Company recorded an environmental charge amounting to euro 1,109 million to account for its proposal for a global transaction with the Italian Ministry for the Environment, whereby the Company pledged to execute certain environmental projects relating nine sites of national interest (Priolo, Napoli Orientale, Brindisi, Pieve Vergonte, Cengio, Crotone, Mantova, Porto Torres and Gela). At those sites, the Group companies have started, as guiltless owners of a number of industrial areas, environmental restoration and clean up activities. The proposal also contemplates the settlement of a number of pending proceedings relating to clean up issues and environmental damage. More information about that issue is reported in "Item 5 – Operating and Financial Review and Prospects – Significant Transactions". At December 31, 2010 provisions for environmental risks were primarily related to Syndial SpA (euro 2,465 million) and to the Refining & Marketing segment (euro 455 million).

Provision for legal and other proceedings of euro 692 million primarily included charges expected on failure to perform certain contractual obligations and estimated future losses on pending litigation including legal, antitrust and administrative matters. These provisions are stated on the basis of Eni’s best estimate of the expected probable liability and primarily related to the Gas & Power segment (euro 238 million) and Syndial SpA (euro 225 million). Reversal of utilized provisions of euro 297 million included the payment related the settlement of the TSKJ matter with U.S. Authorities (euro 250 million). The matter is fully disclosed in Note 34 – Guarantees, commitments and risks – Legal Proceedings. Reversal of unutilized provisions of euro 310 million included the favorable outcome of

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an antitrust proceeding of 2003 resulting in an amount significantly lower than the amount that was originally accrued on the base of a resolution by the Italian Antitrust Authority, who in a previous reporting period charged Eni with anti-competitive behavior for having allegedly refused third party access to a pipeline for importing natural gas from Algeria to Italy (euro 270 million).

Loss adjustments and actuarial provisions for Eni’s insurance companies of euro 398 million represented the liabilities towards third parties accrued for claims on insurance policies underwritten by Eni’s insurance company, Eni Insurance Ltd. In relation to such liability, Eni recorded in the assets of the balance sheet receivables for euro 98 million towards insurance companies for reinsurance contracts.

Provision for taxes of euro 357 million primarily included charges for unsettled tax claims in connection with uncertain applications of the tax regulation for foreign subsidiaries of the Exploration & Production segment (euro 240 million) and of the Engineering & Construction segment (euro 55 million).

Provision for the supply of goods in the amount of euro 288 million include the estimated costs of the supply contracts of Eni SpA.

Provision for redundancy incentives of euro 202 million primarily referred to the charge to be borne by Eni as part of a personnel mobility program in Italy for the period 2010-2011 in compliance with Law No. 223/1991.

Provision for losses on investments of euro 200 million was made with respect to losses from investments in entities incurred to date, where the losses exceeded the carrying amount of the investments.

Provision for onerous contracts of euro 108 million related to contracts for which the termination or execution costs exceed the relevant benefits.

Provision for OIL insurance cover of euro 79 million included 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.

28 Provisions for employee benefits
Provisions for employee benefits were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

TFR		445		423
Foreign pension plans		204		295
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans		107		108
Other benefits		188		206
		944		1,032

Provisions for indemnities upon termination of employment primarily related to the provisions accrued by Italian companies for employee termination indemnities ("TFR"), determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code.

The indemnity is paid upon retirement as a lump sum payment the amount of which corresponds to the total of the provisions accrued during the 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 before January 1, 2007 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.

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Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria and in Germany. Benefits under these plans consisted of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to retirement.

Group companies provide healthcare benefits to retired managers. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the company.

Other benefits primarily consisted of a deferred cash incentive plans, the long-term incentive plan and Jubilee awards. The provisions for the deferred cash incentive plans are assessed based on the estimated remuneration related to the probability of the company reaching planned targets that will be paid to managers reaching individual performance goals. The long-term incentive plan replaces the previous stock option assignments and provides for an incentive to be paid after a period of three years in an amount connected with the variation of a performance indicator. Jubilee awards are benefits due following the attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration.

The value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

	Foreign pension plans

(euro million)

TFR

Gross liability

Plan assets

FISDE and other foreign medical plans

Other benefits

Total

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
2010
Current value of benefit liabilities and plan assets at beginning of year		447			1,146			(500	)		115			188			1,396
Current cost					42						2			50			94
Interest cost		22			36						6			6			70
Amendments					9												9
Expected return on plan assets								(20	)								(20	)
Employee contributions					1			(30	)								(29	)
Actuarial gains/losses		8			(22	)		(4	)		4			6			(8	)
Benefits paid		(42	)		(28	)		9			(7	)		(45	)		(113	)
Curtailments and settlements					(113	)		115									2
Currency translation differences and other changes		(2	)		38			(38	)					1			(1	)
Current value of benefit liabilities and plan assets at end of year		433			1,109			(468	)		120			206			1,400

Other benefits of euro 206 million (euro 188 million at December 31, 2009) primarily concerned the deferred monetary incentive plan for euro 126 million (euro 119 million at December 31, 2009), jubilee awards for euro 59 million (euro 52 million at December 31, 2009) and the long-term incentive plan for euro 2 million.

Curtailments and settlements of foreign pension plans concerned a sale to third parties of obligations related to the pension plan and the relevant plan assets of Eni Lasmo Plc for euro 115 million with a net effect equal to zero.

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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, 2009

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2010

Present value of benefit obligations with plan assets								935			874
Present value of plan assets								(500	)		(468	)
Net present value of benefit obligations with plan assets								435			406
Present value of benefit obligations without plan assets		447			433			211			235			115			120			188		206
Actuarial gains (losses) not recognized		(2	)		(10	)		(442	)		(273	)		(6	)		(9	)
Past service cost not recognized											(73	)		(2	)		(3	)
Net liabilities recognized in provisions for employee benefits		445			423			204			295			107			108			188		206

The net liability for foreign employee pension plans of euro 295 million (euro 204 million at December 31, 2009) included the liabilities related to joint ventures operating in exploration and production activities for euro 62 million and euro 121 million at December 31, 2009 and 2010, respectively. A receivable of an amount equivalent to such liability was recorded.

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

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
2010
Current cost				42			2		50			94
Interest cost		22		36			6		6			70
Expected return on plan assets				(20	)							(20	)
Amortization of actuarial gains (losses)				8					7			15
Effect of curtailments and settlements				5								5
		22		71			8		63			164

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The main actuarial assumptions used in the evaluation of post-retirement benefit obligations at year-end and in the estimate of costs expected for 2011 were as follows:

(%)		TFR		Foreign pension plans		FISDE and other foreign medical plans		Other benefits

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
2010
Discount rate		4.8		2.7-14.0		4.8		1.8-4.8
Expected return rate on plan assets				3.5-14.0
Rate of compensation increase		3.0		2.0-14.0
Rate of price inflation		2.0		0.8-13.0		2.0		2.0

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		13.0		6.4-7.4
Bonds		36.4		1.8-14.0
Real estate		2.0		6.4
Other		48.6		0.5-14.0
Total		100.0

The effective return of the plan assets amounted to euro 24 million (nil at December 31, 2009).

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 to defined benefit plans for 2011 amounted to euro 125 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

2009
Impact on net benefit obligation		(7	)		4			3		2
Impact on plan assets					(16	)
2010
Impact on net benefit obligation		(1	)		(31	)		1		4
Impact on plan assets					3

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29 Deferred tax liabilities
Deferred tax liabilities were recognized net of offsettable deferred tax assets for euro 3,421 million (euro 3,764 million at December 31, 2009).

(euro million)

Value at Dec. 31, 2009

Additions

Deductions

Currency translation differences

Other changes

Value at Dec. 31, 2010

		4,907		691		(717	)		451		592		5,924

Deferred tax assets and liabilities consisted of the following:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Deferred tax liabilities		8,671			9,345
Deferred tax assets available for offset		(3,764	)		(3,421	)
		4,907			5,924
Deferred tax assets not available for offset		(3,558	)		(4,864	)
		1,349			1,060

The most significant temporary differences giving rise to net deferred tax liabilities were as follows:

(euro million)

Value at Dec. 31, 2009

Additions

Deductions

Currency translation differences

Other changes

Value at Dec. 31, 2010

Deferred tax liabilities:
- accelerated tax depreciation		5,172			520			(264	)		310			(40	)		5,698
- difference between the fair value and the carrying amount of assets acquired following business combinations		1,174			9			(59	)		87			(2	)		1,209
- site restoration and abandonment (tangible assets)		549			4			(91	)		29			(51	)		440
- capitalized interest expense		159			1			(11	)					(3	)		146
- application of the weighted average cost method in evaluation of inventories		61			16			(1	)					98			174
- other		1,556			141			(291	)		25			247			1,678
		8,671			691			(717	)		451			249			9,345
Deferred tax assets:
- site restoration and abandonment (provisions for contingencies)		(1,485	)		(86	)		32			(59	)		43			(1,555	)
- accruals for impairment losses and provisions for contingencies		(1,390	)		(630	)		316			(1	)		(12	)		(1,717	)
- depreciation and amortization		(1,186	)		(355	)		70			(78	)		49			(1,500	)
- unrealized intercompany profits		(1,062	)		(21	)		86			(12	)		101			(908	)
- assets revaluation as per Laws No. 342/2000 and No. 448/2001		(677	)					38						2			(637	)
- carry-forward tax losses		(174	)		(169	)		148			(24	)		(19	)		(238	)
- other		(1,348	)		(351	)		376			(50	)		(357	)		(1,730	)
		(7,322	)		(1,612	)		1,066			(224	)		(193	)		(8,285	)
Net deferred tax liabilities		1,349			(921	)		349			227			56			1,060

Deferred tax assets are recognized for deductible temporary differences to the extent that is probable that sufficient taxable profit will be available against which part or all of the deductible temporary differences can be utilized.

Net deferred tax liabilities of euro 1,060 million included the recognition of the deferred tax effect against equity on the fair value evaluation of derivatives designated as cash flow hedge for euro 14 million. Further information on cash flow hedge derivatives is given in Note 25 – Other current liabilities.

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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 generally allow the carry-forward of tax losses over a period longer than the five subsequent years, and in many cases, indefinitely. The tax rate applied to determine the portion of carry-forwards tax losses to be utilized equaled to: (i) an average rate of 34.0%, for Italian companies that are not included in the tax consolidation; (ii) a rate of 6.5%, equal to the additional IRES provided for energy companies that are included in the tax consolidation; and (iii) an average rate of 30.9%, for foreign companies.

Carry-forward tax losses of euro 1,298 million can be used in the following periods:

(euro million)		Italian subsidiaries		Foreign subsidiaries

2011				30
2012		2
2013				58
2014		90
2015		54
Beyond 2015				78
Without limit		6		980
		152		1,146

Carry-forward tax losses for which is probable the offsetting against future taxable profit amounted to euro 837 million and were in respect of Italian subsidiaries for euro 152 million and of foreign subsidiaries for euro 685 million. Deferred tax assets recognized on these losses amounted to euro 26 million and euro 212 million, respectively.

30 Other non-current liabilities
Other non-current liabilities were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Fair value of non-hedging derivatives		372		344
Fair value of cash flow hedge derivatives		436		157
Current income tax liabilities		52		40
Other payables		54		67
Other liabilities		1,566		1,586
		2,480		2,194

Fair value of derivative contracts was determined by using market quotations given by primary info-providers, or, in lack of market information, on the basis of generally accepted methods for financial valuations.

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Fair value of non-hedging derivatives was as follows:

		Dec. 31, 2009		Dec. 31, 2010

(euro million)

Fair value

Purchase commitments

Sale commitments

Fair value

Purchase commitments

Sale commitments

Non-hedging derivatives on exchange rate
Currency swap		10		296		94		1		48		17
Interest currency swap		23		394				16		228		117
		33		690		94		17		276		134
Non-hedging derivatives on interest rate
Interest rate swap		137		41		4,030		147		16		2,999
		137		41		4,030		147		16		2,999
Non-hedging derivatives on commodities
Over the counter		199		850		219		155		521		541
Future		1		12
Other		2				9		25				72
		202		862		228		180		521		613
		372		1,593		4,352		344		813		3,746

Fair value of non-hedging derivatives of euro 344 million (euro 372 million at December 31, 2009) essentially 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 157 million (euro 436 million at December 31, 2009) pertained to the Gas & Power segment (euro 275 million at December 31, 2009) and were designated to hedge surpluses or deficits of gas to achieve a proper balance in gas portfolio. Fair value of contracts expiring beyond 2011 is given in Note 20 – Other non-current receivables; fair value of contracts expiring by 2011 is given in Note 25 – Other current liabilities and in Note 13 – Other current assets. The effects of the evaluation at the fair value of cash flow hedge derivatives are given in Note 32 – Shareholders’ equity and in Note 36 – Operating expenses.

The nominal value of these derivatives referred to purchase and sale commitments for euro 383 million and euro 612 million, respectively (euro 1,544 million and euro 129 million at December 31, 2009).

Information on the hedged risks and the hedging policies is shown in Note 34 – Guarantees, commitments and risks – Risk factors.

The group’s liability for current income taxes of euro 40 million (euro 52 million at December 31, 2009) was due as special tax (with a rate lower than the statutory tax rate), relating to the option to increase the deductible tax bases of certain tangible and other assets to their carrying amounts as permitted by the 2008 Budget Law.

Other liabilities of euro 1,586 million (euro 1,566 million at December 31, 2009) included advances received by Suez following the long-term supplying of natural gas and electricity of euro 1,353 million (euro 1,455 million at December 31, 2009).

31 Assets held for sale and liabilities directly associated with assets held for sale
In 2010, non-current assets held for sale and liabilities directly associated with non-current assets held for sale of euro 517 million and euro 38 million pertained to the Gas & Power segment and related to: (i) Gas Brasiliano Distribuidora SA, a company that markets and distributes gas in an area of the São Paulo state, Brazil, for which Eni signed a preliminary agreement with an affiliate of Petrobras. The completion of the transaction is subject to approval of the relevant Brazilian authorities; (ii) Eni’s interests in gas transport pipelines from North Europe and Russia – Trans Europa Naturgas Pipeline Gesellschaft mbH & Co KG, Trans Europa Naturgas Pipeline Verwaltungs GmbH, Transitgas AG and Trans Austria Gasleitung GmbH – as well as assets and liabilities essentially related to marketing activities of gas transportation capacity of the consolidated companies Eni Gas Transport Deutschland SpA and Eni Gas Transport International SA. The divestment is part of the commitments presented by Eni to the European Commission to settle an antitrust proceeding related to alleged anti-competitive behavior in the natural gas

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market ascribed to Eni without the ascertainment of any illicit behavior and consequently without imposition of any fines or sanctions. The Commission accepted Eni’s commitments as of September 29, 2010. The completion of the transactions is expected in the first half of 2011.

In 2009, 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.

Società Padana Energia SpA and Distri RE SA have been sold during 2010. Società Adriatica Idrocarburi SpA has been reclassified from assets held for sale following the decision of the proposed buyer not to acquire its 100% stake.

32 Shareholders’ equity

Non-controlling interest
Profit attributable to non-controlling interest and the non-controlling interest in consolidated subsidiaries related to:

(euro million)		Net profit		Shareholders’ equity

		2009		2010		Dec. 31, 2009		Dec. 31, 2010

Saipem SpA		567		503		2,005		2,406
Snam Rete Gas SpA		369		537		1,568		1,705
Hindustan Oil Exploration Co Ltd		1				123		146
Tigáz Zrt		8		13		72		83
Others		5		12		210		182
		950		1,065		3,978		4,522

Eni shareholders’ equity
Eni’s net equity at December 31 was as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Share capital		4,005			4,005
Legal reserve		959			959
Reserve for treasury shares		6,757			6,756
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect		(439	)		(174	)
Reserve related to the fair value of available-for-sale securities net of the tax effect		5			(3	)
Other reserves		1,492			1,518
Cumulative currency translation differences		(1,665	)		539
Treasury shares		(6,757	)		(6,756	)
Retained earnings		39,160			39,855
Interim dividend		(1,811	)		(1,811	)
Net profit for the period		4,367			6,318
		46,073			51,206

Share capital
At December 31, 2010 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, 2009).

On April 29, 2010 Eni’s Shareholders’ Meeting declared a dividend distribution of euro 0.50 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2009 dividend of euro 1.00 per

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share, of which euro 0.50 per share paid as interim dividend. The balance was payable on May 27, 2010 to shareholders on the register on May 24, 2010.

 

Legal reserve
This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.

 

Reserve for treasury shares
The reserve for treasury shares represents the reserve destined to purchase own shares in accordance with the decisions of Eni’s Shareholders’ Meetings. The amount of euro 6,756 million (euro 6,757 million at December 31, 2009) included treasury shares purchased.

 

Reserve for available-for-sale securities and cash flow hedging derivatives, net of the related tax effect
The valuation at fair value of available-for-sale securities and cash flow hedging derivatives, net of the related tax effect, consisted of the following:

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	)
Changes of the year 2010		(9	)		1			(8	)		47			(33	)		14			38			(32	)		6
Foreign currency translation differences											(4	)		2			(2	)		(4	)		2			(2	)
Amount recognized in the profit and loss account											396			(143	)		253			396			(143	)		253
Reserve as of December 31, 2010		(3	)					(3	)		(275	)		101			(174	)		(278	)		101			(177	)

 

Other reserves
Other reserves amounted to euro 1,518 million (euro 1,492 million at December 31, 2009) and included:

•		a reserve of euro 1,142 million represented an increase in Eni’s shareholders’ equity associated with a business combination under common control which took place in 2009, whereby the parent company Eni SpA divested the subsidiaries Italgas SpA and Stogit SpA to Snam Rete Gas SpA with a corresponding decrease in the non-controlling interest (euro 1,086 million at December 31, 2009);
•		a reserve of euro 247 million related to the increase of Eni’s shareholders’ equity as a control to non-controlling 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, 2009);
•		a reserve of euro 157 million deriving from Eni SpA’s equity (same amount as of December 31, 2009);
•		a negative reserve of euro 25 million for stock warrants of Altergaz SA owned by its shareholder Eni G&P France BV;
•		a negative reserve of euro 3 million referred to the share of "Other comprehensive income" on equity-accounted entities (positive for euro 2 million at December 31, 2009).

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Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

 

Treasury shares
A total of 382,863,733 ordinary shares (382,952,240 at December 31, 2009) with nominal value of euro 1 each, were held in treasury, for a total cost of euro 6,756 million (euro 6,757 million at December 31, 2009). During the year 2010 the term established by Eni’s Shareholders’ Meetings for the purchase has expired. 15,737,120 treasury shares (19,482,330 at December 31, 2009) at a cost of euro 328 million (euro 414 million at December 31, 2009) were available for 2003-2005¹⁸ and 2006-2008 stock option plans.

The decrease of 3,745,210 shares consisted of the following:

		Stock option

Number of shares at December 31, 2009		19,482,330
Rights exercised		(88,500	)
Rights cancelled		(3,656,710	)
		(3,745,210	)
Number of shares at December 31, 2010		15,737,120

At December 31, 2010 options outstanding were 15,737,120 shares. Options refer to the 2003 stock plan for 213,400 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 22.514 per share, to the 2006 stock plan for 2,307,935 shares with weighted average exercise price of euro 23.121 per share, to the 2007 stock plan for 2,431,560 shares with weighted average exercise price of euro 27.451 per share and to the 2008 stock plan for 6,831,125 shares with an exercise price of euro 22.540 per share.

Information about commitments related to stock option plans is included in Note 36 – Operating expenses.

 

Interim dividend
Interim dividend for the year 2010 amounted of euro 1,811 million corresponding to euro 0.50 per share, as decided by the Board of Directors on September 9, 2010 in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 23, 2010.

 

Distributable reserve
At December 31, 2010 Eni shareholders’ equity included distributable reserves of euro 46,200 million.

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Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity

		Net profit		Shareholders’ equity

(euro million)		2009		2010		Dec. 31, 2009		Dec. 31, 2010

As recorded in Eni SpA’s Financial Statements		5,061			6,179			32,144			34,724
Excess of net equity in individual accounts of consolidated subsidiaries over their corresponding carrying amounts in the statutory accounts of the parent company		158			1,297			17,464			20,122
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity		(213	)		(574	)		5,068			4,732
- elimination of tax adjustments and compliance with Group account policies		(113	)		389			(1,062	)		(667	)
- elimination of unrealized intercompany profits		117			14			(4,582	)		(4,601	)
- deferred taxation		378			100			1,175			1,410
- other adjustments		(71	)		(22	)		(156	)		8
		5,317			7,383			50,051			55,728
Non-controlling interest		(950	)		(1,065	)		(3,978	)		(4,522	)
As recorded in Consolidated Financial Statements		4,367			6,318			46,073			51,206

 

33 Other information

Main acquisitions

Altergaz SA
In December 2010, Eni increased its shareholding in Altergaz SA, a company marketing natural gas in France to retail and middle market clients, as founding partners of the company exercised a put option on a 15% stake. Eni took control of the entity. Allocation of the purchase cost amounting to euro 106 million, to assets and liabilities was made on a preliminary basis. The purchase cost included the price paid to the partners exercising the put right for euro 39 million and the fair value of stake already held by Eni before the change of control amounting to euro 67 million.

Eni Mineralölhandel GmbH
On August 1, 2010, Eni acquired in Austria the company Eni Mineralölhandel GmbH that operates, through its 100%controlled company Eni Marketing Austria GmbH, in downstream activities including a retail network of 135 service stations, wholesale activities (with 36 additional retail service stations owned by third parties) as well as commercial assets in the aviation business and related logistic and storage activities. The allocation of the total cost of euro 113 million to assets and liabilities was closed as of the balance sheet date.

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The allocation of the purchase costs of the business combinations made during the 2010 year consisted of the following:

(euro million)		Altergaz SA		Eni Mineralölhandel GmbH

		Carrying value		Fair value		Carrying value		Fair value

Current assets		308			308			81		81
Property, plant and equipment		1			1			22		42
Intangible assets		4			4
Goodwill					97					76
Investments		13			13			3		3
Other non-current assets								5		25
Assets acquired		326			423			111		227
Current liabilities		315			315			90		95
Deferred tax liabilities		(7	)		(7	)		5		5
Provisions for contingencies		2			2			3		4
Other non-current liabilities								10		10
Liabilities acquired		310			310			108		114
Non-controlling interest		7			7
Eni’s shareholders equity		9			106			3		113

Net sales from operations and the net loss for the year 2010 and from the date of the acquisition to December 31, 2010 consisted of the following:

(euro million)		Altergaz SA		Eni Mineralölhandel GmbH

		2010		From the date of the acquisition to December 31, 2010		2010		From the date of the acquisition to December 31, 2010

Net sales from operations		561						398			163
Net loss		(23	)					(46	)		(3	)

The amounts related to net sales and net loss represent the 100% share.

 

 

 

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Supplemental cash flow information

(euro million)				2008		2009		2010

Effect of investment of companies included in consolidationand businesses
Current assets		1,938			7			409
Non-current assets		7,442			47			316
Net borrowings (*)		1,543			4			13
Current and non-current liabilities		(3,598	)		(29	)		(457	)
Net effect of investments		7,325			29			281
Non-controlling interest		(1,261	)					(7	)
Fair value of investments held before the acquisition of control		(601	)					(76	)
Purchase price		5,463			29			198
less:
Cash and cash equivalents		(1,829	)		(4	)		(55	)
Cash flow on investments		3,634			25			143
Effect of disposal of consolidated subsidiaries and businesses
Current assets		277						82
Non-current assets		299						855
Net borrowings		(118	)					(267	)
Current and non-current liabilities		(270	)					(302	)
Net effect of disposals		188						368
Fair value of share capital held after the sale of control								(149	)
Gain on disposal		25						309
Non-controlling interest		(1	)					(46	)
Selling price		212						482
less:
Cash and cash equivalents		(63	)					(267	)
Cash flow on disposals		149						215

(*)		For a definition see paragraph "Information on net borrowings" above.

 

34 Guarantees, commitments and risks

Guarantees
Guarantees were as follows:

		Dec. 31, 2009		Dec. 31, 2010

(euro million)

Unsecured guarantees

Other guarantees

Total

Unsecured guarantees

Other guarantees

Total

Consolidated subsidiaries				9,863		9,863				10,853		10,853
Unconsolidated entities controlled by Eni				146		146				156		156
Joint ventures and associates		6,060		1,251		7,311		6,077		1,005		7,082
Others		5		266		271		5		261		266
		6,065		11,526		17,591		6,082		12,275		18,357

Other guarantees issued on behalf of consolidated subsidiaries of euro 10,853 million (euro 9,863 million at December 31, 2009) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for euro 7,309 million (euro 6,091 million at December 31, 2009), of which euro 5,427 million related to the Engineering & Construction segment (euro 4,936 million at December 31, 2009); (ii) VAT recoverable from tax authorities for euro 1,076 million (euro 1,171 million at December 31, 2009); and (iii) insurance risk for euro 387 million reinsured by Eni (euro 253 million at December 31, 2009). At December 31, 2010 the underlying commitment covered by such guarantees was euro 10,718 million (euro 9,783 million at December 31, 2009).

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Other guarantees issued on behalf of unconsolidated subsidiaries of euro 156 million (euro 146 million at December 31, 2009) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for euro 152 million (euro 141 million at December 31, 2009). At December 31, 2010, the underlying commitment covered by such guarantees was euro 81 million (euro 64 million at December 31, 2009).

Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of euro 7,082 million (euro 7,311 million at December 31, 2009) primarily concerned: (i) an unsecured guarantee of euro 6,054 million (euro 6,037 million at December 31, 2009) given by Eni SpA to Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project relating to the Milan-Bologna 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 for euro 792 million (euro 971 million at December 31, 2009), of which euro 648 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 692 million at December 31, 2009); and (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds for euro 113 million (euro 126 million at December 31, 2009). At December 31, 2010, the underlying commitment covered by such guarantees was euro 639 million (euro 814 million at December 31, 2009).

Unsecured and other guarantees given on behalf of third parties of euro 266 million (euro 271 million at December 31, 2009) consisted primarily of: (i) guarantees issued on behalf of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni 13.6%) as security against payment commitments of fees in connection with the re-gasification activity (euro 225 million). The expected commitment has been valued at euro 222 million (euro 206 million at December 31, 2009) and it has included in the off-balance sheet commitments of the following paragraph "Liquidity risk"; and (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit for euro 24 million on behalf of minor investments or companies sold (euro 23 million at December 31, 2009).

At December 31, 2010 the underlying commitment covered by such guarantees was euro 258 million (euro 266 million at December 31, 2009).

 

Commitments and risks
Commitments and risks were as follows:

(euro million)		Dec. 31, 2009		Dec. 31, 2010

Commitments		16,668		17,226
Risks		1,277		1,499
		17,945		18,725

Other commitments of euro 17,226 million (euro 16,668 million at December 31, 2009) were essentially related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to euro 10,654 million (euro 10,302 million at December 31, 2009); (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 in a period included between 2011-2031. The expected commitment has been valued at euro 4,031 million and it has included in the off-balance sheet commitments of 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 Pascagoula’s terminal (6 BCM/y) over a twenty-year period (2011-2031). The expected commitment has been valued at euro 1,239 million (euro 1,151 million at December 31, 2009) and it has included in the off-balance sheet commitments of 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) (6 BCM/y) over a twenty-year period (until 2029). The expected commitment has been valued at euro 1,018 million (euro 990 million at December 31, 2009) and it has included in the off-balance sheet commitments of the following paragraph "Liquidity risk"; (v) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest euro 149 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 150 million at December 31, 2009). The commitment has included in the off-balance sheet commitments of the following paragraph "Liquidity risk"; and (vi) a commitment entered into by Eni USA Gas

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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 113 million (euro 110 million at December 31, 2009) and it has included in the off-balance sheet commitments of the following paragraph "Liquidity risk".

Risks of euro 1,499 million (euro 1,277 million at December 31, 2009) primarily concerned potential risks associated with the value of assets of third parties under the custody of Eni for euro 1,202 million (euro 899 million at December 31, 2009) and contractual assurances given to acquirers of certain investments and businesses of Eni for euro 297 million (euro 378 million at December 31, 2009).

 

Non-quantifiable commitments
Under the convention signed on October 15, 1991 by Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana 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) the market risk deriving from exposure to fluctuations in interest rates, foreign currency exchange rates and commodity prices; (ii) the credit risk deriving from the possible default of a counterparty; and (iii) the liquidity risk deriving from the risk that suitable sources of funding for the Group’s operations may not be available.

Financial risks are managed in respect of guidelines defined by the parent company, targeting to align and coordinate Group companies’ policies on financial risks ("Eni Guidelines on Management and Control of Financial Risks").

In 2010, driven by a deep change in its relative market risk profile determined by structural changes in the market, Eni’s Gas & Power Division adopted new pricing and risk management strategies for actively managing economic margins, that have been approved by the Board of Directors on June 15, 2010. As a result of the implementation of these new activities, reviews of the principles included in the Guidelines are expected in 2011.

Market risk
Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department, Eni Coordination Center, Eni Finance USA and Banque Eni which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk and Eni Trading & Shipping which executes certain activities relating to commodity derivatives. In particular, Eni SpA and Eni Coordination Center manage subsidiaries’ financing requirements in and outside 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 negotiating emission trading certificates. The commodity risk is managed by each business unit with Eni Trading & Shipping executing 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 interest rates or exchange rates on a speculative basis.

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Commodity derivatives are entered into with the aim of:

a)		hedging of certain underlying commodity prices set in a contractual arrangement with a third party. Hedging derivatives can be entered also to hedge highly probable future transactions;
b)		effectively managing the economic margin (positioning). This consists of entering purchase/sale commodity contracts in both commodity and financial markets aiming at altering the risk profile associated with a portfolio of physical assets of each business unit in order to improve margins associated to those assets in case of favorable trends in the commodity pricing environment;
c)		arbitrage. It consists of entering purchase/sale commodity contracts in both commodity and financial markets, targeting the possibility of earning a profit (or reducing the logistical costs associated to owned assets) leveraging any price differences in the marketplace;
d)		proprietary trading. It consists in entering purchase/sale commodity contracts in both commodity and financial markets, targeting of earning an uncertain profit, should certain expectations fulfill about favorable trends in the commodity pricing environment.

In addition, commodity derivatives may also be included in origination activities. This activity takes place in wholesale markets and provides for structuring contracts by an originator in order to meet the specific requirements of an internal or external counterparty. According to the management strategy adopted, origination services can be asset based, when the originator replicates the contract contents with profiles and capacities of its own assets in the logic of natural hedging, or not asset based, when price and volume risk profiles can be managed under a trading/positioning logic or a hedging logic that is implemented on each leg of the contract.

The framework defined by Eni’s policies and guidelines prescribes that measurement and control of market risk be performed on the basis of maximum tolerable levels of risk exposure defined in terms of limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon, or in accordance with Value-at-Risk (VaR) techniques. Those techniques make a statistical assessment of the market risk associated with the Group’s activity, i.e., potential gain or loss in fair values, due to changes in market conditions taking account of the correlation existing among changes in fair value of existing instruments.

Eni’s finance departments define maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of Value at Risk, pooling Group companies risk positions. Eni’s calculation and measurement techniques for interest rate and foreign currency exchange rate risks are in accordance with established banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni’s Group companies minimize these kinds of market risks by transferring risk exposure to the parent company’s finance department.

With regard to the commodity risk, Eni’s policies and guidelines define rules to manage this risk with the objective of optimization of core activities and the pursuing of preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of Value at Risk and stop loss in connection with exposure deriving from commercial activities as well as exposure deriving from proprietary trading executed by the subsidiary Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business units. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools Group companies requests for negotiating commodity derivatives, ensuring execution services to Group companies, 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 and stop loss 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 strategic risk is the economic risk which is intrinsic to each business unit. This exposure to strategic risk is not managed through specific systematic activities due to a strategic decision made by the Company, except for extraordinary business or market conditions. Therefore, internal risk policies and guideline do not foresee any mandate to manage, or any maximum tolerable level of risk exposure. To date, exposure to the strategic risk is associated with plans for commercial development of proved and unproved oil and gas reserves, long-term gas supply contracts for the portion not balanced by in-place or highly probable sale contracts, refining margins and minimum compulsory stock. Any hedging activity of the strategic risk is the sole responsibility of Eni’s top management, due to the extraordinary conditions that may lead to such decision. This kind of transaction is not subject to specific risk limits for its nature, but is however subject to monitoring and assessment activities.

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The three different market risks, for which 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. Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and viceversa. 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 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 Value-at-Risk techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period.

Interest rate risk
Changes in interest rates affect the market value of financial assets and liabilities of the company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. Borrowing requirements of the Group’s companies are pooled by the Group’s central finance department in order to manage net positions and the funding of portfolio developments consistently with management’s plans while maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be accounted for under the hedge accounting method in accordance with IAS 39. Value at risk deriving from interest rate exposure is measured daily on the basis of a variance/covariance model, within 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 viceversa. 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, natural gas, refined products or electricity. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable evaluation techniques. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. Value at risk deriving from commodity exposure is measured daily on the basis of a historical simulation technique, within a 95% confidence level and a one-day holding period.

The following table shows amounts in terms of Value at Risk , recorded in 2010 (compared with 2009) relating to interest rate and exchange rate risks in the first section, and commodity risk in the second section. Value-at-Risk values are stated in U.S. dollars, the currency most widely used in oil products markets. The relevant increase reported by the Gas & Power Division derives from the circumstance that in the second half of 2010, Value at Risk has been calculated according to new assumptions on non contracted exposures (based on benchmark indices related to prices in European hubs) consistently with the new pricing and risk management model of the Gas & Power Division approved by Eni’s Board of Directors.

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(Exchange and Value at Risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

		2009		2010

(euro million)

High

Low

Average

At year end

High

Low

Average

At year end

Interest rate (1)		6.85		1.65		3.35		1.98		2.82		1.09		1.55		1.60
Exchange rate		1.22		0.07		0.35		0.31		0.99		0.13		0.50		0.51

(1)		Value at Risk deriving from interest rate exposure includes the new finance branch Eni Finance USA Inc operation, since February 2010.

(Value at Risk - historic simulation method; holding period: 1 day; confidence level: 95%)

		2009		2010

(U.S.$ million)

High

Low

Average

At year end

High

Low

Average

At year end

Area oil, products		37.51		4.74		17.65		6.64		46.08		4.40		23.53		10.49
Area Gas & Power (2)		51.62		28.01		40.97		38.26		101.62		40.06		61.76		43.30

(2)		Amounts relating to the Gas & Power business also include Tigáz contribution, since the beginning of 2010.

Credit risk
Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial units and Eni Adfin are responsible for managing credit risk arising in the normal course of the business. The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. Also credit litigation and receivable collection activities are assessed. Eni’s corporate units define directions and methods for quantifying and controlling customer’s reliability. With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into accounts the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance departments, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and Division, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterparty on a daily basis. 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. As of December 31, 2010, Eni had no 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 on the marketplace as to be unable to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt. The Group capital structure is set according to the Company’s industrial targets and within the limits established by the Company’s Board of Directors who are responsible for prescribing the maximum ratio of debt to total equity and minimum ratio of medium and long-term debt to total debt as well as fixed rate medium and long-term debt to total medium and long-term debt. In spite of ongoing tough credit market conditions resulting in higher spreads to borrowers, the Company has succeeded in maintaining access to a wide range of funding at competitive rates through the capital markets and banks. The actions implemented as part of Eni’s financial planning have enabled the Group to maintain access to the credit market particularly via the issue of commercial paper which is also targeted to increase the flexibility of funding facilities. In particular in 2010, Eni

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issued bonds addressed to institutional investors on the euro market (two emissions for euro 1 billion each) and to professional investors on the dollar market for $800 million. The above mentioned actions were aimed at ensuring availability of suitable sources of funding to fulfill short-term commitments and due obligations while also preserving the necessary financial flexibility to support the Group’s development plans. In doing so, the Group has pursued an efficient balance of finance debt in terms of maturity and composition leveraging on the structure of its lines of credit, particularly the committed ones. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements.

At December 31, 2010, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 10,358 million, of which euro 2,498 million were committed, and long-term committed unused borrowing facilities of euro 4,901 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 about euro 10.4 million were drawn as of December 31, 2010.

The Group has debt ratings of A+ and A-1 respectively for long (outlook stable) and short-term debt assigned by Standard & Poor’s and Aa3 and P-1 (outlook stable) assigned by Moody’s.

 

Finance debt repayments including expected payments for interest charges
The tables below summarize the Group main contractual obligations for finance debt repayments, including expected payments for interest charges.

Dec. 31, 2009		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

 

Dec. 31, 2010		Maturity year
(euro million)

		2011		2012		2013		2014		2015		2016 and thereafter		Total

Non-current debt		963		3,583		2,485		2,009		2,815		9,413		21,268
Current financial liabilities		6,515												6,515
Fair value of derivative instruments		1,131		276		74		18		48		85		1,632
		8,609		3,859		2,559		2,027		2,863		9,498		29,415
Interest on finance debt		720		712		654		563		460		1,726		4,835
Guarantees to banks		339												339

 

Trade and other payables
The tables below summarize the Group trade and other payables by maturity.

Dec. 31, 2009		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

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Dec. 31, 2010		Maturity year
(euro million)

		2011		2012-2015		2016 and thereafter		Total

Trade payables		13,111						13,111
Advances, other payables		9,464		29		38		9,531
		22,575		29		38		22,642

 

Expected payments by period under contractual obligations and commercial commitments
In addition to finance debt and trade payables presented in the financial statements, the Group has in place a number of contractual obligations arising in the normal course of the business. To meet these commitments, the Group will have to make payments to third parties. The Company’s main obligations are take-or-pay clauses in contracts of the Gas & Power segment, 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.

The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

(euro million)		Maturity year

		2011		2012		2013		2014		2015		2016 and thereafter		Total

Operating lease obligations (a)		1,023		863		587		517		311		752		4,053
Decommissioning liabilities (b)		44		60		116		362		146		11,998		12,726
Environmental liabilities (c)		338		307		261		263		184		661		2,014
Purchase obligations (d)		16,891		15,425		15,896		15,970		15,734		179,998		259,914
Gas
- Natural gas to be purchased in connection with take-or-pay contracts		15,708		14,403		14,961		15,004		14,788		172,025		246,889
- Natural gas to be transported in connection with ship-or-pay contracts		794		708		646		668		655		4,892		8,363
Other take-or-pay and ship-or-pay obligations		169		160		165		175		168		1,142		1,979
Other purchase obligations (e)		220		154		124		123		123		1,939		2,683
Other obligations		4		4		4		4		4		129		149
- Memorandum of intent relating Val d’Agri		4		4		4		4		4		129		149
		18,300		16,659		16,864		17,116		16,379		193,538		278,856

(a)		Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(b)		Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(c)		Environmental liabilities do not include the environmental charge amounting to euro 1,109 million for the proposal to the Italian Ministry for the Environment to enter into a global transaction related to nine sites of national interest because the dates of payment are not reasonably estimable.
(d)		Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(e)		Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S. (euro 2,479 million).

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Capital expenditure commitments
In the next four years Eni plans to make capital expenditures of euro 53 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects at December 31, 2010. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown.

		Maturity year

(euro million)		2011		2012		2013		2014		2015 and thereafter		Total

Committed on major projects		5,443		5,606		2,867		3,304		8,396		25,616
Other committed projects		7,210		4,700		4,253		2,802		6,017		24,982
		12,653		10,306		7,120		6,106		14,413		50,598
- of which: environmental expenditures on MATTM transaction		207		184		125		36		50		602

 

Other information about financial instruments
The carrying amount of financial instruments and relevant economic effect as of and for the years ended December 31, 2009 and 2010 consisted of the following:

		2009		2010

		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)		(26	)		45						46		(13	)
Held-to-maturity financial instruments
Securities (b)		36			1						35		1
Available-for-sale financial instruments
Securities (b)		348			13			1			382		9			(9	)
Receivables and payables and other assets/liabilities valued at amortized cost
Trade and receivables and other (c)		20,748			(361	)					23,998		(110	)
Financing receivables (b)		1,637			72						2,150		84
Trade payables and other (d)		19,228			(48	)					22,642		26
Financing payables (b)		24,800			(508	)					27,783		(535	)
Assets at fair value through profit or loss (fair value option)
Investments (b)					163
Net liabilities for hedging derivatives (e)		751			161			(636	)		320		(402	)		47

(a)		In the profit and loss account, incomes were recognized within "Other operating income (loss)" for euro 118 million (expenses for euro 49 million at December 31, 2009) and expenses within "Finance income (expense)" for euro 131 million (expenses for euro 4 million at December 31, 2009).
(b)	i	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 128 million (expenses for euro 427 million at December 31, 2009) (net impairments) 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 18 million (incomes for euro 66 million at December 31, 2009) (translation differences arising from euro-reporting subsidiaries denominated in foreign currency which are translated into euro at year-end exchange rates and valuation at amortized cost).
(d)		The effects were recognized in the profit and loss account within "Finance income (expense)" (translation differences arising from euro-reporting subsidiaries denominated in foreign currency which are translated into euro at year-end exchange rates).
(e)		Income or expense were recognized in the profit and loss account within "Net sales from operations" and "Purchase, services and other" for euro 414 million of expenses (incomes for euro 155 million at December 31, 2009) within "Finance income (expense)" for euro 13 million of incomes (incomes for euro 6 million at December 31, 2009) (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:

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a)		Level 1: quoted prices (unadjusted) in active markets for identical financial assets or liabilities;
b)		Level 2: measurements based on the basis of inputs, other than quoted prices above, which, for assets and liabilities that have to be measured, can be observable directly (e.g. prices) or indirectly (e.g. deriving from prices); and
c)		Level 3: inputs not based on observable market data.

Financial instruments measured at fair value in the balance sheet as of at December 31, 2010 were classified as follows: (i) level 1, "Other financial assets held for trading or available for sale" and "Non-hedging derivatives - Future"; and (ii) level 2, derivative instruments different from "Future" included in "Other current assets", "Other non-current assets", "Other current liabilities" and "Other non-current liabilities". During 2010 no transfers were done between the different hierarchy levels of fair value.

The table below summarizes the amount of financial instruments valued at fair value:

(euro million)				Note		Dec. 31, 2009		Dec. 31, 2010

Current assets
Other financial assets available for sale		(8	)		348		382
Non-hedging derivatives - Future		(13	)		10		33
Other non-hedging derivatives		(13	)		688		593
Cash flow hedge derivatives		(13	)		236		210
Non-current assets
Non-hedging derivatives - Future		(20	)		2
Other non-hedging derivatives		(20	)		337		420
Cash flow hedge derivatives		(20	)		129		102
Current liabilities
Non-hedging derivatives - Future		(25	)		2		10
Other non-hedging derivatives		(25	)		689		646
Cash flow hedge derivatives		(25	)		680		475
Non-current liabilities
Non-hedging derivatives - Future		(30	)		1
Other non-hedging derivatives		(30	)		371		344
Cash flow hedge derivatives		(30	)		436		157

 

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

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closing of the proceeding. A number of plaintiffs have been appealed against this decision. The hearing for the review of the appeal against the dismissal request was held on November 11, 2010. Basing on this hearing, the Judge for the Preliminary Hearings retained the decision. On February 14, 2011 the Judge for the Preliminary Hearings decided to accept the request of dismissal of the proceeding for all the defendants issued by the Public Prosecutor. The Judge also decided in favor of releasing the hydrocarbon fields and their restitution to the entitled entities.

(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 Hearings 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 with a ruling filed on April 29, 2010.

(iii) Alleged negligent fire in the refinery of Gela. In June 2002, in connection with a fire at the refinery of Gela, a criminal investigation began concerning alleged negligent fire, environmental crimes and crimes against natural beauty. First degree proceedings ended with an acquittal sentence. In November 2007, the Public Prosecutors of Gela and of Caltanissetta filed an appeal against this decision. 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 groundwater 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 groundwater in the area of the refinery. Eni is charged with 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 at the renewal of the debate phase. During the debate phases, indictment and defense witnesses were examined. Subsequently, the first technical appraiser of the defense was examined. On May 14, 2010, following the examination, the Court of Gela issued a sentence whereby on one side criminal accusation against the above mentioned employee was dismissed as a result of the statute of limitations, on the other side the defendant was condemned to the payment of legal costs and compensation to the plaintiffs. The amount of the compensation will be determined by a resolution of a Civil Court. The sentence was filed on June 3, 2010. The Company has filed an appeal with the Second Degree Court of Caltanissetta. In the first hearing the proceeding was postponed due to a lack of notification.

(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 sole plaintiff 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. In the hearing on February 26, 2010, the Judge accepted all the evidences filed by the counterparts. In the hearing of April 14, 2010 the Public Prosecutor commenced the review of the texts that continued in a number of subsequent hearings.

(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 the survey, the ground and the groundwater at the Priolo site should be considered polluted according to Law Decree No. 152/2006. This contamination was caused by a spill-over made in the period prior to 2001 and not subsequent to

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2005; the equipment still operating on the site represents another source of risk, in particular those owned by ISAB Srl (ERG). 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. The Public Prosecutor requested the dismissal of the proceeding. The decision of the Judge on the dismissal on the proceeding is still pending.

(vii) Fatal accident Truck Center Molfetta – Prosecuting body: Public Prosecutor of Trani. On March 3, 2008 in the Municipality of Molfetta a fatal accident occurred that caused the death of four workers assigned to the cleaning of a tank car owned by the company FS Logistica, part of the Italian Railways Group. The tank was used for the transportation of liquid sulfur produced by Eni in the Refinery of Taranto and destined to the client company Nuova Solmine. Consequently a criminal action commenced against certain employees of FS Logistica and of its broker "La Cinque Biotrans" and, under the provisions of Legislative Decree No. 231/2001, against the two above mentioned companies and the company responsible for the clean up of the tank car - Truck Center. On October 26, 2009 the First Degree Court concluded that both the above mentioned persons and the three companies were guilty. Additionally, the documentation related to the trial was forwarded to the Public Prosecutor of Trani in order to ascertain the eventual responsibilities of Eni and Nuova Solmine employees in relation to the fatal accident and also to the Public Prosecutors of Taranto and Grosseto (competent for Nuova Solmine) in order to ascertain eventual irregularities in the procedures of handling and transporting liquid sulfur. Following the sentence, the Public Prosecutor of Trani commenced an investigation against a number of employees of Nuova Solmine and an employee of Eni’s Refining & Marketing division, responsible for marketing liquefied sulfur. On April 14, 2010, the Judge for the Preliminary Hearings notified the Eni’s employee a request of extension of the preliminary investigations. On May 11, 2010, Eni SpA, eight employees of the company and a former employee were notified of the closing of the investigation into manslaughter, grievous bodily harm and illegal disposal of waste materials. A number of defendants filed defensive memoranda. The Public Prosecutor has removed three defendants and transmitted evidence to the Judge for the Preliminary investigations requesting to dismiss the proceeding. The Judge for the Preliminary Investigation accepted the above mentioned request. The Judge postponed the preliminary hearing for the positions not dismissed to February 23, 2011. In this hearing, the Judge scheduled the hearing for the eventual admittance as plaintiffs of the Puglia Region, the Municipality of Molfetta and a relative of one of the victims for April 19, 2011. On that occasion, the counterparts shall state the kind of procedure that they intend to adopt.

(viii) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria – Prosecuting body: Public Prosecutor of Castrovillari. On June 11, 2010 the Company received a notification of a judicial measure for the preventive seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria, following a prior seizure of other areas in the same municipalities notified through a judicial measure in February 2010. The above mentioned decisions were the result of an investigation commenced after the damage of the HDPE covering the zinc ferrites generated in the industrial site of Pertusola Sud and, based on the Court’s conclusions, illegally stored in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria. The impounded areas are those where the above mentioned waste was stored. The proceeding is in the phase of the preliminary hearings. The circumstances object of investigation are the same considered in the criminal action concluded in 2008 with an acquittal sentence for one of the defendants while the Judge dismissed the accusation for all the other defendants as a result of the statute of limitations. In this case the accusation is of omitted clean up. Syndial SpA gave the availability for the removal of the waste materials, the related operations are still pending.

 

SYNDIAL SPA
(ix) 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 crops. 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 filed a number of exceptions on the admissibility in acting as plaintiffs of the counterpart; the Judge addressed the question in a hearing in February 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 marine fauna 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 Vinyls and Sasol Italy SpA stand trial. The proceeding continues for the constitution as defendants of the said part. In the hearing of October 18, 2010, then postponed to

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November 6, 2010, the legal defense filed the exception of lack of territorial competence of the Judges of the Court of Sassari as part potentially injured by the alleged crime. In the hearing of January 31, 2011, the Judge for the Preliminary Hearings rejected the above mentioned exceptions. Syndial defense submitted further preliminary issues related to the invalidity of the notice of conclusion of preliminary investigation. In a subsequent hearing, the Judge rejected all the exceptions on the invalidity of the notice of conclusion of preliminary investigation. In the following hearing held on February 15, 2011, Syndial issued a further exception on the inadmissibility of the use of investigation acts filed by the Public Minister after the deadline.

 

1.2 Civil and administrative proceeding

SYNDIAL SPA (FORMER ENICHEM SPA)
(i) Alleged pollution caused by the activity of the Mantova plant. In 1992, the Ministry for the 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 October 13, 2011. The Board of State Lawyers is confident on the positive closing of the transaction before this date, depending on the time necessary to the Ministry for completing its evaluation.

(ii) Summon before the Court of Venice for environmental damages allegedly caused to the lagoon of Venice by the Porto Marghera plants. On December 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. EVC Italia and the actual company, Vinyls Italia, 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 above mentioned 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 has been suspended until April 22, 2010 when the Province of Venice pursuant to Article 303 of the Italian Penal Code restarted the proceeding. The subsequent hearing for the resume of the proceeding took place on September 24, 2010. In that hearing the Judge decided to reschedule the hearing that will review the position of Vinyls Italia and the consultants appraisals filed by the parties. As the Judge resolved not to hear the consultants again, the hearing has been postponed to September 2011 to review the findings.

(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 to face charges of causing 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

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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 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 for the 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, assigned to another Judge, took place on April 13, 2010. During the hearing the Calabria Region required the revise of the independent appraiser report. The Judge rejected the request. As regards the ascertainment of the existence of a residual environmental damage not remedied by the clean up activities, the Board State of lawyers on behalf of the Ministry for the Environment requested an evaluation of the impact of the new regulation on the above mentioned damage. Syndial filed a document explaining the modification of the environmental damage regulation. The Judge scheduled the deadline for the filing of the counterparts’ objections to such document for September 16, 2010, and September 30, 2010 for the submission of Syndial reply. The findings related to the modification of the Environmental Damage regulation introduced by the Article 5-bis of the Law Decree No. 135/2009 submitted by all the parties will be discussed in the next hearing scheduled for November 17, 2010.
On September 15, 2010, the Calabria Region submitted a memorandum objecting to the documents filed by Syndial in the hearing of April 13, 2010. In September 30, 2010 Syndial filed a memorandum on the impact of the new Italian regulation about the environmental damage as per Law Decree No. 135/2009 on the proceeding. As a result of the discussions occurred between the parties, in the hearing held November 17, 2010 the Judge took under advisement the decision. With the act of December 21, 2010, the Judge deemed the acquired elements sufficient for the closing of the proceeding. The hearing for the final decision has been postponed to November 16, 2011 for the filing of the outcome.
However, discussions have been going on in order to arrange for a possible transaction of all environmental claims pending on this matter. In 2008 Eni’s subsidiary Syndial took charge of performing certain clean up activities and on December 5, 2008 presented a global project to clean up and remediate all interested areas. As for the approval procedure of the above mentioned 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 clean up activities. In the Annual Report 2008, 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

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has been only partially approved. The environmental provision made by the company is progressively employed in the execution of the clean up activities. 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. Syndial, the Province of Crotone and Council of Ministers filed their pleadings and subsequently the final statements of the case as well as memorandum of objections.
On January 20, 2011 the Appeal Court of Milan sentenced (Sentence 143/2011), fully accepting Syndial objections, the rejections of the claims made by the Council of Ministers, Ministry for the Environment, Delegated Commissioner for Calabria Region and Province of Crotone. The Appeal Court confirmed the invalidity of the entire proceeding accepting also an objection issued by Syndial on the inadmissibility of the request of fractionate damage that is already under examination by another Judge. The Appeal Court condemned the counterparts to reimburse the legal expenses sustained by Syndial.
The claims made in this first instance were substantially absorbed in the above mentioned two proceedings.

(iv) Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore – Prosecuting body: Ministry for 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 for 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 above mentioned technical legal advice, in concert with external consultants on accounting principles. In July 2009, Eni’s subsidiary Syndial filed an appeal against the above mentioned sentence, also requesting suspension of the sentence effectiveness. The Ministry for 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 for the Environment related to the determination of the quantification criteria for the monetary compensation of the environmental damage pursuant to the above mentioned Article 5-bis of the Law Decree No. 135/2009. The Board of State lawyers committed itself to not examine the sentence until the next hearing.
In the hearing of May 28, 2010, Syndial requested a further postponement still pending the above mentioned Decree of the Ministry for the Environment. The Board of State lawyers agreed to the request, justifying he postponement with the negotiation in place between the parties for the global solution of the proceeding, committing itself to not examine the sentence until the next hearing.
The Judge decided the postponement to October 29, 2010. In this hearing the Judge, since parties were still negotiating an environmental transaction, postponed the hearing to January 29, 2011. That hearing has been rescheduled to September 30, 2011 as discussions are ongoing.
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 for 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 above mentioned prescriptions that have been prescribed are the object of the Company opposition in the above mentioned proceeding. In case Syndial should be found guilty, it would incur remediation and clean up expenses, actually not quantifiable, that would be offset against any

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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 for the Environment joined the action and requested environmental damage payment – from a minimum of euro 53.5 million to a maximum of euro 93.3 million – to be broken down among the various companies that ran the plant in the past. 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 for the Environment. Both plaintiffs filed an appeal against this decision in June 2008 confirming the requests issued in the first judgment. 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. In this hearing the parties filed their pleadings and the Judge postponed the hearing for the final decision to October 6, 2011.

(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 above mentioned 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 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 objecting 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. In the hearing of October 21, 2010, the Court upheld the appeals filed by the counterparts while the filing of the Court’s decisions is still pending.
It must be noted that the Public Prosecutor of Siracusa commenced a criminal action against an unknown party in order to verify the effective contamination of the Augusta harbor and the connected risks on the execution on the

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clean up project proposed by the Ministry. The technical assessment disposed by the Public Prosecutor generated the following outcomes: (a) no public health risk in the Augusta harbor; (b) absence of any involvement on part of Eni companies in the contamination; and (c) drainages dangerousness. Based on those findings, the Public Prosecutor decided to dismiss the proceeding.

 

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 clawback 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. 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 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 ordering 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.
On September 28, 2010, the independent accounting consultant filed the determination of the charge pertaining to Serfactoring amounting to euro 48.98 million, net of the payment made by Federconsorzi to Agrifactoring. Syndial and Serfactoring submitted a written reply objecting to this conclusion. In the hearing of October 28, 2010, Eni’s companies requested the independent accounting consultant clarify the criteria of determination of the above mentioned charge. The Court approved the request and rescheduled the hearing to February 24, 2011, ordering the independent accounting consultant to submit a written report. In that hearing the consultants filed their reports and the hearing for the filing of the pleadings has been scheduled for April 28, 2011.
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. Eni accrued a provision with respect to this proceeding.

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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 (now RFI - Rete Ferroviaria Italiana 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 preliminary investigation of the arbitration procedure is still pending. On July 30, 2010, the independent consultants filed their finding that resulted partially favorable to the Company and in the subsequent hearings the counterparts filed their motion on preliminary issues and the related objections. In the next hearing of March 20, 2011, the independent consultants would fill further reports on the above mentioned issue.
The deadline for the submission of the arbitration determination has been scheduled for December 27, 2011.
On March 23, 2009, the Arbitration Committee determined the TAV right to extend the assessment made by the independent accounting consultant to the subcontractors appointed by the Consortium, the contractors, or assignees. Basing on the alleged invalidity of Arbitration Committee determination, on April 8, 2010, the Consortium notified to the counterparts the appeal to this decision requesting its suspension before the Appeal Court of Rome.
With regard to the project for the construction of a high-speed railway from Milan to Verona, in December 2004, CEPAV Due presented the final project, prepared in accordance with Law No. 443/2001 on the basis of the preliminary project approved by an Italian governmental Authority (CIPE). As concerns the arbitration procedure, 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 required 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 required 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. TAV filed with the Second Instance Court of Rome an appeal against the partial arbitration committee’s determination of January 2007. 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 rule on this matter. Subsequently, Law No. 133/2008 reestablished 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 continued in order to determinate the damages suffered by the Consortium even in the period prior to the revocation of the concession. An independent appraiser has been appointed in order to assess those damages. The arbitration proceeding is suspended, since the negotiations between the parties in order to sign the integration to the existing agreement and to settle the arbitration already closed and the pending one are underway. The deadline for the submission of the arbitration determination was 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 No. 1998/30/EC, this Court granted the suspension of the decision. The Authority did

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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, on March 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. 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. On September 29, 2010, the European Commission issued a decision whereby it resolved to accept Eni’s commitments and made them mandatory. The Commission acknowledged that its intervention was unwarranted and closed the proceeding. Eni is currently adopting all procedures to execute those commitments in accordance with such time schedule and criteria which have been agreed upon with the Commission (a non confidential version of the final agreements is available at the Company web site http://www.eni.com/it_IT/azienda/attività-strategie/gas-power/trasporto-gas/trasporto.shtml).

(iii) Trans Tunisian Pipeline Co Ltd (TTPC). In April 2006, Eni filed a claim before the Regional Administrative Court of Lazio against the decision of the Italian Antitrust Authority of February 15, 2006, stating that Eni’s behavior pertaining to implementations of plans for the upgrading of the TTPC pipeline for importing natural gas from Algeria represented an abuse of dominant position under Article 82 of the European Treaty and fined Eni. The initial fine amounted to euro 390 million and was reduced to euro 290 million in consideration of Eni’s commitment to perform actions favoring competition including the upgrade of the gasline. Eni accrued a provision with respect to this proceeding. With a decision filed on November 29, 2006, the Regional Administrative Court of Lazio partially accepted Eni’s claim, annulling such part of the Authority’s decision where the fine was quantified. 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.
On May 27, 2010, the Italian Antitrust Authority notified Eni the start of a proceeding aimed at reappraising the criteria that were applied in the initial determination of the fine amounting to euro 290 million, in accordance with a resolution of the Regional Administrative Court of Lazio made on February 15, 2006.
On December 20, 2010, the Council of State sentenced (Sentence No. 9306) to reform the original resolution of the Italian Antirust Authority of February 2006 as regards the quantification of the fine reducing it to euro 20,405,000. On January 4, 2011 Eni paid the reduced amount, since the procedure of the Italian Antitrust Authority to reappraise the amount of the fine was overruled by the decision of the Council of State on the same issue.

(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. On March 24, 2010, the Antitrust Authority published on its website the commitments of Italgas and other distribution companies involved in this inquiry, as foreseen by Article 14-ter of the Law No. 287/1990. These commitments were intended to remedy the alleged anti-competitive practices charged by the Authority, starting the market test phase. On September 8, 2010, the Italian Antirust Authority sentenced (Sentence No. 21530) to accept and make mandatory the remedies issued by Italgas. The proceeding was resolved without the ascertainment of the illicit behavior and without any fine to Eni and Italgas.

(v) Italian Antitrust Authority’s inquiry in the selling of bitumen. On May 27, 2010, the Italian Antitrust Authority started a preliminary investigation against Eni and other eight companies engaging in marketing bitumen for road by means of an agreement intended to hamper competition in this sector in Italy, in breach of Article 101 of Treaty on the Functioning of the European Union. The investigation is in the preliminary phase. The deadline for the finalization of the preliminary investigation has been scheduled for November 25, 2011.

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ENI SPA, POLIMERI EUROPA SPA AND SYNDIAL SPA
(vi) 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. The most important inquiry referred to BR and ESBR elastomers which was finalized on November 29, 2006, when 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 sentence for the appeal is still pending. Eni accrued a risk provision with respect to this proceeding.

 

3.2 Regulation

(i) Distribuidora de Gas Cuyana SA. Formal investigation of the agency entrusted with the regulations for the natural gas market in Argentina. Enargas started a formal investigation on some operators, among them Distribuidora de Gas Cuyana SA, a company controlled by Eni. Enargas stated that the company improperly applied conversion factors to volumes of natural gas invoiced to customers and requested the company to apply the conversion factors imposed by local regulations from the date of the default notification (March 31, 2004) without prejudice to any damage payment and fines that may be decided after closing the investigation. In April 2004, the company filed a defensive memorandum. On April 28, 2006, the company formally requested the acquisition of documents from Enargas in order to have access to the documents on which the allegations are based.

(ii) 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 impose administrative monetary penalties.
On May 5, 2010, the Authority communicated to the Company the results of the preliminary investigation: the Authority believes that the alleged violations have been committed and are still ongoing as of the date of the communication. In addition the Authority reaffirmed the need to issue an instruction to the Company to execute certain remedial actions as announced at the commencement of the investigation. Eni replied to the Authority that prior to the beginning of the preliminary investigation, in July 2009, the Company modified the layout of its invoices, which the Company believes to be fully compliant with transparency obligations set by the current regulation (providing also further information for an higher level of transparency for the client). The Company also believes that its invoice lay-out largely anticipates the new regulation on the issue of harmonization of invoices (Resolution 202/2009). Eni accrued a provision with respect to this proceeding even if the company considers to have demonstrated to have substantially complied with the applicable regulation. On October 11, 2010, the Authority for Electricity and Gas imposed (Sentence VIS 110/2010) a fine amounting to euro 350,000 of which: (i) euro 200,000 related to residential customers; and (ii) euro 150,000 related to non-residential customers connected in low voltage. Eni paid the sanction and filed a claim before the Regional Administrative Court against the sentence in order to defend its rights and interests.

(iii) Preliminary investigation of the Authority for Electricity and Gas on the billing of the tariff balance to final gas clients and periodicity of the billing. On May 25, 2010, the Authority for Electricity and Gas sentenced (Resolution VIS 36/2010) to commence a preliminary investigation against Eni in order to: (i) fine the Company for the alleged infringement of the Resolution 229/2001 (regulating the contractual conditions of gas sale to final clients through the network of local gas lines), Resolution 42/1999 (referred to the invoices transparency), Resolution 126/2004 (related to the code of commercial behavior for the gas sale) and the Integrated Text on the regulation of the quality of marketing services of electricity and gas (Resolution ARG/com 164/2008); and (ii) adoption of decisions aimed at break up behaviors prejudicial to clients rights. The resolution that sentenced the commencement of the proceeding includes also a number of injunctions as well as requests for information and documents that Eni provided to the Authority. Eni filed a claim before the Regional Administrative Court of Lombardia against the Resolution VIS 36/2010.
On November 10, 2010, the Authority for Electricity and Gas communicated to Eni the conclusions of the preliminary investigation confirming the alleged violations and subsequently authorizing the start of a proceeding.

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In the final hearing of the Authority authorized the Company to file a defensive memorandum and subsequently filed a claim before the Regional Administrative Court against the conclusion of the preliminary investigations. Eni accrued a risk provision with respect to this proceeding even if the company considers its motivations to be well grounded in the appeal proposed against the Authority for Electricity and Gas.

 

4. 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 Hearings requested all the parties that have not requested the plea-bargain to stand in trial, excluding certain defendants as a result of the statute of limitations. During the hearing on March 2, 2010, the Court confirmed the admission as plaintiffs of Eni SpA, EniPower SpA and Saipem SpA against the inquired parties under the provisions of Legislative Decree No. 231/2001. Further companies involved were identified as defendants. The proceeding continues with the examination of the witnesses.

(ii) Trading. An investigation is pending regarding two former Eni managers who were allegedly bribed by third parties in favor to 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 the Preliminary Hearings rejected most of the dismissal requests issued by the Public Prosecutor. Basing on the decision of the Judge for the Preliminary Hearings, the Public Prosecutor of Rome notified Eni, as injured part, the summon against two former managers of the company charged of aggravated fraud related to the relevant patrimonial damage caused to the injured part through the abuse of working relations and activities. The first hearing, scheduled for January 27, 2010, was postponed to March 30, 2010.
In the hearing of March 30, 2010 Eni was admitted as plaintiff against all the defendants. Subsequently the legal defense of one of the former managers opted for the "non-conditioned" plea-bargain. The Judge removed this position from the main proceeding postponing the related hearing to the same date of the principal one. In the hearing of June 23, 2010 related to the position of a former manager of Eni, the Public Prosecutor, made a request of acquittal coherently with the previous request of dismissal of that defendant. Eni legal defense asked the conviction of the defendant. After the debate, in the hearing of July 13, 2010, the Court acquitted that defendant. The Court would file the grounds of the judgment within the next 90 days. In the same date the main proceeding for the definition of the preliminary investigation requests was postponed to the hearing of February 9, 2011, and subsequently to May 24, 2011.

(iii) TSKJ Consortium Investigations by U.S., Italian, and Other Authorities. Snamprogetti Netherlands BV has a 25% participation in the TSKJ Consortium companies. The remaining participations are held in equal shares of 25% by KBR, Technip, and JGC. Beginning in 1994 the TSKJ Consortium was involved in the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti SpA, the holding company of Snamprogetti Netherlands BV, was a wholly owned subsidiary of Eni until February 2006, when an agreement was entered into for the sale of Snamprogetti to Saipem SpA and Snamprogetti was merged into Saipem

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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 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, have made investigations about alleged improper payments made by the TSKJ Consortium to certain Nigerian public officials.

The proceedings in the U.S.: in 2010 a settlement of the proceeding was entered into with the U.S. Authorities investigating the matter (the U.S. DoJ and the U.S. SEC) following long and complex discussions which commenced in 2009. In July 2010, Snamprogetti Netherlands BV entered into a deferred prosecution agreement with the DoJ. Pursuant to the agreement, the DoJ filed charges against Snamprogetti Netherlands BV including a count of conspiracy and violating certain provisions of the U.S. Foreign Corrupt Practices Act. Snamprogetti Netherlands BV agreed to pay a criminal penalty of $240 million.
If it satisfies the terms of the agreement, the charges against Snamprogetti Netherlands BV will be dismissed. Eni and Saipem agreed to guarantee the obligations of Snamprogetti Netherlands BV towards the DoJ, considering the contractual obligations assumed by Eni to indemnify Saipem as a part of the divestment of Snamprogetti. In July 2010, Eni and Snamprogetti Netherlands BV also entered into a consent order with the SEC, in which they consent to the filing of a complaint and the entry of a final judgment that alleges that Eni and Snamprogetti violated certain sections of the Securities Exchange Act of 1934. Under the consent order, Eni and Snamprogetti jointly agreed to pay disgorgement to the SEC in the amount of $125 million. Eni paid the agreed amounts in July 2010. Eni, Saipem, and Snamprogetti cooperated with the U.S. authorities’ investigations. In the agreements, the SEC and DoJ did not require the implementation of any independent compliance monitor. Since the conduct at issue, Eni, Saipem, and Snamprogetti Netherlands BV have made substantial enhancements to their anti-corruption compliance programs, which monitor Eni and its subsidiaries’ compliance systems. Eni and its subsidiaries are committed to continuous improvements to their internal compliance program and policies.

The proceedings in Nigeria: basing on the action commenced by the Nigerian Authorities, on December 10, 2010 Snamprogetti Netherlands BV agreed on a settlement with the Federal Government of Nigeria in order to resolve the investigation made on the activities of Snamprogetti Netherlands BV as member of the TSKJ Consortium. The Federal Government of Nigeria had previously commenced a legal action against the TSKJ Consortium and the four consortium companies, including Snamprogetti Netherlands BV. The company reached an agreement entailing the payment of a criminal fine amounting to $30 million and the reimbursement of $2.5 million for the legal expenditures of the Federal Government of Nigeria, thus concluding the legal proceeding. The Federal Government of Nigeria renounced to prosecute any criminal and civil action, in any jurisdiction, against Snamprogetti, the parent companies and the subsidiaries. In the agreement the Nigerian Authorities recognized that the alleged behaviors ended on June 15, 2004.

The proceedings in Italy: beginning in 2004, the TSKJ matter has prompted investigations by the Public Prosecutor’s office of Milan against unknown persons. Since March 10, 2009, the Company has received requests of exhibition of documents from the Public Prosecutor’s office of Milan. The events under investigation cover the 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 the 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 Corp 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.

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On November 17, 2009, 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 the Preliminary Investigation.
On February 9, 2010, 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 above mentioned decision of the Judge of Re-examination.
In the hearing of September 30, 2010, the Third Instance Court examined the appeal of the Public Prosecutor of Milan against the Judge of Re-examination decision of rejection of precautionary measures of disqualification. In this hearing the above mentioned Court accepted the claim of the Public Prosecutor and cancelled the decision of the Judge of Re-examination. The Court decided that the request of precautionary measures be admissible according to Law Decree No. 231/2001 even in the case of international corruption.
On January 24, 2011, Eni was notified the schedule of the hearing before the Re-examination Court of Milan for the debate on the request of precautionary measures issued by the Public Prosecutor of Milan basing on the decision of September 30, 2010 of the Third Instance Court.
On February 18, 2011, the Public Prosecutor of Milan, with respect to the guarantee payment amounting to euro 24,530,580, even in the interest of Saipem SpA, renounced to contest the decision of rejection of precautionary measures of disqualification for Eni SpA and Saipem SpA issued by the Judge for the Preliminary Hearings. In the hearing of February 22, 2011, the Re-Examination Court, taking note of the above mentioned renounce, declared inadmissible the appeal of the Public Prosecutor of Milan and closed the proceeding related to the request of precautionary measures of disqualification for Eni SpA and Saipem SpA.
On November 3, 2010, the defense of Saipem was notified the conclusion of the investigations relating to the proceeding pending before the Court of Milan through a deed by which the Court evidenced the alleged violations made by the five former Snamprogetti SpA (now Saipem SpA) and Saipem SpA being the parent company of Snamprogetti. The deed does not involve the Eni Group parent company Eni SpA. The charged crimes involve alleged corruptive events that have occurred in Nigeria after July 31, 2004. It is also stated the aggravating circumstance that Snamprogetti SpA reported a relevant profit (estimated at approximately $65 million). On December 3, 2010, the defense of Saipem was notified the opening of a proceeding with the first hearing scheduled for December 20, 2010. This first hearing that took place before the Judge for the Preliminary investigation of the Court of Milan was dedicated to the exposition of the motivations of the Public Prosecutor while the defenses exposed their point on January 12, 2011. At the end of this hearing the Public Prosecutor requested to replicate to defense motivations. In the hearing of January 26, 2011, the Public Prosecutor requested five former workers of Snamprogetti SpA (now Saipem) and Saipem SpA (as legal entity incorporating Snamprogetti) to stand trial.
It must be noted that the Board of Directors of Eni and Saipem in 2009 and 2010, respectively, approved new guidelines and anti-corruption policies regulating Eni and Saipem management of the business. The guidelines integrated anti-corruption policies of the Company, aligning them to the international best practices, optimizing the compliance system and granting the highest respect of Eni, Saipem and their workers of the Code of Ethics, 231 Model and national and international anti-corruption policies.

(iv) Gas metering. 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 Court of Milan. The order was also served upon five top managers of the Group companies in addition to third party companies and their top managers. The investigation alleges behavior which breaches Italian criminal law, starting from 2003, regarding the use of instruments for measuring gas, the related payments of excise duties and the billing of clients as well as relations with the Supervisory Authorities. The allegation regards, inter alia, the offense contemplated by Legislative Decree of June 8, 2001, No. 231, which establishes the liability of the legal entity for crimes committed by its employee in the interests of such legal entity, or to its advantage. Accordingly, notice of the commencement of investigations was served upon Eni Group companies (Eni, Snam Rete Gas and Italgas) as well as third party companies. On November 26, 2009, a notice of conclusion of the preliminary investigation was served to Eni’s Group companies whereby 12 Eni employees, also including former employees, are under investigation. The exceptions filed in the notice include: (i) violations pertaining to recognition and payment of the excise on natural gas amounting to euro 20.2 billion; (ii) violations or failure in submitting the annual statement of gas consumption and/or in the annual declarations to be filed with the Duty Authority or the Authority for Electricity and Gas; and (iii) a related obstacle which has been allegedly posed to the monitoring functions performed by the Authority for Electricity and Gas. On February 22, 2011, 12 Eni employees, also including former employees were notified the schedule of the preliminary hearing as part of the proceeding for which the notice of conclusion of the preliminary investigation was served on November 26, 2009. 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. On May 18, 2010, the Public Prosecutor of Milan requested the closing of the proceeding relating to a number of defendants, including a top manager for which the Public Prosecutor found no evidence supporting the indictment in an eventual proceeding. The request has been preceded by an act of removal of the archived judicial position from the main proceeding. As a result of a further dismissal of judicial position from the main proceeding, the Public Prosecutor of Milan notified to nine employees and former employees of Eni (in particular belonging to the Gas & Power division) the conclusion of the

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investigation related to the crime under the provisions of Article 40 (violations pertaining to recognition and payment of the excise on mineral oils) of Legislative Decree No. 504 of October 26, 1995. The companies were not notified the ending of the investigation because it excludes any charge of involving the administrative responsibility regulated by the Legislative Decree 231 of 2001. The deed also disputed certain violations pertaining to subtraction of taxable amounts and missed payments of excise taxes on natural gas amounting to euro 0.47 billion and euro 1.3 billion, respectively.
The preliminary hearing that actually does not involve legal entities has been scheduled for May 12, 2011.

(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. On April 2010, the above mentioned body has proposed an agreement on the matter that the counterparts are still evaluating. The Eni subsidiary is currently waiting for a measure from the judicial authority to dismiss the matter.

(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. On November 29, 2010, the Tributary Police of Milan requested to interview certain Eni managers in the field of the evolution on the management of contract assigned to Agip KCO to NCC and OIC consortia. Subsequently the Tributary Police convened two managers in order to interview them about the investigation commenced by the Public Prosecutor of Milan.

(vii) Algeria. On February 4, 2011, Eni received by the Public Prosecutor of Milan a notification requesting the collection of documents pursuant to Article 248 of the Penal Code. Through this decision, in relation to the crime of alleged international corruption, Eni SpA was requested to transmit: (i) the Saipem/Sonatrach contract signed on June 2009 related to the realization of the GK3 gas pipeline; and (ii) the GALSI/Saipem/Technip contract signed in July 2009 related to the engineering of the ground section of the gas pipeline. The notification has been forwarded to Saipem SpA since this matter is in its area of responsibility. The crime of international corruption regards, inter alia, the offense contemplated by Legislative Decree of June 8, 2001, No. 231. 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.

 

5. 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. On January 25, 2011, the Municipality notified to Eni an appeal to the Third

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Instance Court for the cancellation of the above mentioned sentence. 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.

 

ENI SPA and ENIADFIN SPA
(ii) Assessments for Padana Assicurazioni tax returns. In November and December 2010, the Italian Tax Authorities issued an assessment for Padana Assicurazioni tax returns for the year 2005 and a pre-assessment for years 2006 and 2007. The Tax Authorities have denied certain cost deductions and assessed a greater value for the going concern transferred to Eni Insurance Ltd in 2007. The total claim amounted to euro 148.5 million for taxes, penalties and interests. According to the guarantee issued in 2008, related to the sale of Padana Assicurazioni shares to Helvetia SV AG, this additional tax burden is to be charged to the seller companies: Eni SpA for 26.75% and its subsidiary Eni Adfin SpA for 73.25%. Based on those assessments, a risk provision has been accrued in the consolidated financial statements.

 

OUTSIDE ITALY
(iii) 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 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 ($0.3 million). These amounts are disputed and appeals have been submitted to the Higher Level Tax Authority. In March and October 2010, Kazakh Tax Authorities started the complex tax audits respectively for the year 2008 and 2009. On December 23, 2010, Agip Karachaganak BV Branch and Karachaganak Petroleum Operating BV Branch received Tax Audit Acts for the year 2005. The taxes assessed as reflected in 2005 Tax Audit Acts equal to US$ 207.4 million including penalties and administrative fines relating to CIT (US$ 205.9 million) and Withholding Tax and other taxes (US$ 1.5 million). All taxes assessed and penalties as well as administrative fines are subject to further appeal process at higher tax authority level in compliance with deadlines established in the tax and administrative legislation.
There is also 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.
In February 2011, Kazakh Authorities notified a claim also in relation to the 2007 cost recovery.
Parties are negotiating in order to settle the dispute.

(iv) 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.

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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 own portion of the realized productions (profit oil). With reference to natural gas storage in Italy, the activity is conducted on the basis of concessions with a duration that does not exceed 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, pending the decrees for the determination of minimum limits of over-municipal areas. 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. The law 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 "Item 3 – Risk Factors". In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s consolidated financial statements, taking account of ongoing remedial actions, existing insurance policies and the environmental risk provision accrued in the consolidated financial statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of the ongoing surveys and the other possible effects of statements required by Decree No. 471/1999 of the Ministry for the Environment; (iii) new developments in environmental regulation; (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

 

Emission trading
Legislative Decree No. 216 of April 4, 2006 implemented the Emission Trading Directive No. 2003/87/EC concerning greenhouse gas emissions and Directive No. 2004/101/EC concerning the use of carbon credits deriving from projects for the reduction of emissions based on the flexible mechanisms devised by the Kyoto Protocol. This European emission trading scheme has been in force since January 1, 2005, and on this matter, on November 27, 2008, the National Committee for Emissions Trading Scheme (Ministry for the Environment-Mse) published the Resolution 20/2008 defining emission permits for the 2008-2012 period. Eni was assigned permits corresponding to 126.4 million tonnes of carbon dioxide (of which, 25.8 in 2008, 25.8 in 2009, 25.3 in 2010, 25.0 in 2011, 24.5 in 2012) and in addition to approximately 2.0 million of permits expected to be assigned with respect to new plants in the five-year period 2008-2012. Emission quotas of new plants include only those physically assigned and recorded in the emissions registry. Emissions of carbon dioxide from Eni’s plants were lower than permits assigned in 2010. Against emissions of carbon dioxide amounted to approximately 25.5 million tonnes, emission permits amounting to 25.9 million tonnes were assigned, determining a 0.4 million tonnes surplus. In addition to such surplus, a 0.3 million tonnes of permits (as increase in the availability of Eni) are to be included following the contract of Virtual

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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 0.7 million tonnes.

35 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)		2008		2009		2010

Net sales from operations		107,777		83,519			98,864
Change in contract work in progress		305		(292	)		(341	)
		108,082		83,227			98,523

Net sales from operations were net of the following items:

(euro million)		2008		2009		2010

Excise taxes		13,142		12,122		11,785
Exchanges of oil sales (excluding excise taxes)		2,694		1,680		1,868
Services billed to joint venture partners		2,081		2,435		2,996
Sales to service station managers for sales billed to holders of credit cards		1,700		1,531		2,150
Exchanges of other products		83		55		79
		19,700		17,823		18,878

Net sales from operations of euro 98,864 million included revenues deriving from the construction and the development of the distribution network related to assets under concession agreements (euro 357 million).

Net sales from operations by business segment and geographic area of destination are presented in Note 41 – Information by business segment and geographic financial information.

 

Other income and revenues
Other income and revenues were as follows:

(euro million)		2008		2009		2010

Gains from sale of assets		48		306		266
Lease and rental income		98		100		84
Compensation for damages		15		54		47
Contract penalties and other trade revenues		23		31		52
Gains on price adjustments under overlifting/underlifting transactions		180		148		50
Other proceeds (*)		364		479		457
		728		1,118		956

(*)		Each individual amount included herein does not exceed euro 50 million.

Gains from sale of assets of euro 266 million related for euro 241 million to the Exploration & Production segment.

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36 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".

 

Purchase, services and other
Purchase, services and other included the following:

(euro million)		2008		2009		2010

Production costs - raw, ancillary and consumable materials and goods		58,662			40,311			48,261
Production costs - services		13,355			13,520			15,400
Operating leases and other		2,558			2,567			3,066
Net provisions for contingencies		884			1,055			1,407
Other expenses		1,660			1,527			1,309
		77,119			58,980			69,443
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(680	)		(576	)		(243	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(89	)		(53	)		(65	)
		76,350			58,351			69,135

Production costs-services included brokerage fees related to Engineering & Construction segment for euro 26 million (euro 155 million and euro 79 million in 2008 and 2009, respectively).

Costs incurred in connection with research and development activity recognized in profit and loss amounted to euro 221 million (euro 216 million and euro 207 million in 2008 and 2009, respectively) as they do not meet the requirements to be capitalized.

The item "Operating leases and other" included operating leases for euro 1,400 million (euro 957 million and euro 1,220 million in 2008 and 2009, respectively) and royalties on hydrocarbons extracted for euro 1,214 million (euro 871 million and euro 641 million in 2008 and 2009, respectively). Future minimum lease payments expected to be paid under non-cancelable operating leases were as follows:

(euro million)		2008		2009		2010

To be paid within 1 year		618		886		1,023
Between 2 and 5 years		2,585		2,335		2,278
Beyond 5 years		1,084		1,034		752
		4,287		4,255		4,053

Operating leases primarily concerned assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of Eni to pay dividends, use assets or to take on new borrowings.

Increases in provisions for contingencies net of reversal of unutilized provisions amounted to euro 1,407 million (euro 884 million and euro 1,055 million in 2008 and 2009, respectively) and mainly regarded environmental risks for euro 1,352 million (euro 360 million and euro 258 million in 2008 and 2009, respectively) as a result of the filing of the proposal to the Italian Ministry for the Environment for a global transaction on certain environmental issues. More information is included in Note 27 – Provisions for contingencies. Net reversal of provisions for legal proceedings amounted to euro 185 million (net provision of euro 55 million and euro 333 million in 2008 and 2009, respectively) as a result of a favorable outcome of an antitrust proceeding. More information is included in Note 27 – Provisions for contingencies.

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Payroll and related costs
Payroll and related costs were as follows:

(euro million)		2008		2009		2010

Wages and salaries		3,204			3,330			3,565
Social security contributions		694			706			714
Cost related to defined benefits plans and defined contributions plans		107			137			164
Other costs		282			342			600
		4,287			4,515			5,043
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(235	)		(280	)		(209	)
- capitalized direct costs associated with self-constructed assets - intangible assets		(48	)		(54	)		(49	)
		4,004			4,181			4,785

Average number of employees
The average number and break-down of employees by category of Eni’s subsidiaries were as follows:

(number)		2008		2009		2010

Senior managers		1,621		1,653		1,569
Junior managers		12,597		13,255		13,122
Employees		36,766		37,207		37,589
Workers		26,387		26,533		26,550
		77,371		78,648		78,830

The average number of employees was calculated as the average between the number of employees at the beginning and end of the period. The average number of senior managers included managers employed and operating in foreign countries, whose position is comparable to a senior manager status.

 

Stock-based compensation

Stock 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 of the Italian Civil Code. The following is the information about the residual plans of past periods.

At December 31, 2010, 15,737,120 options were outstanding for the purchase of 15,737,120 Eni ordinary shares (nominal value euro 1 each). The break-down of outstanding options was the following:

		Rights outstanding as of Dec. 31, 2010		Weighted-average strike price of the rights outstanding as of Dec. 31, 2010 (euro)

Stock option plan 2003		213,400		13.743
Stock option plan 2004		671,600		16.576
Stock option plan 2005		3,281,500		22.514
Stock option plan 2006		2,307,935		23.121
Stock option plan 2007		2,431,560		27.451
Stock option plan 2008		6,831,125		22.540
		15,737,120

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At December 31, 2010, the residual life of the plans at December 2003, 2004, 2005, 2006, 2007 and 2008 was 7 months, 1 year and 7 months, 2 years and 7 months, 1 year and 7 months, 2 years and 7 months and 3 years and 7 months, respectively.

The 2006-2008 stock option plan provides that options can be exercised after three years from the assignment (vesting period). The strike price is calculated as the arithmetic average of official prices registered on the Mercato Telematico Azionario operated by Borsa Italiana SpA in the month preceding the assignment.

In 2010, changes of stock option plans consisted of the carry-over of the previous plans. The following table summarizes these changes:

		2008		2009		2010

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		17,699,625			23.822		25.120		23,557,425			23.540		16.556		19,482,330			23.576		17.811
New rights granted		7,415,000			22.540		22.538
Rights exercised in the period		(582,100	)		17.054		24.328		(2,000	)		13.743		16.207		(88,500	)		14.941		16.048
Rights cancelled in the period		(975,100	)		24.931		19.942		(4,073,095	)		13.374		14.866		(3,656,710	)		26.242		16.918
Rights outstanding as of December 31		23,557,425			23.540		16.556		19,482,330			23.576		17.811		15,737,120			23.005		16.398
of which exercisable at December 31		5,184,250			21.263		16.556		7,298,155			21.843		17.811		8,896,125			23.362		16.398

The fair value of stock options granted during the years 2003, 2004 and 2005 was 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:

						2003		2004		2005		2006		2007		2008

Risk-free interest rate (%)		3.2		3.2		2.5		4.0		4.7		4.9
Expected life (years)		8		8		8		6		6		6
Expected volatility (%)		22.0		19.0		21.0		16.8		16.3		19.2
Expected dividends (%)		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 25 million and euro 12 million in 2008 and 2009, respectively).

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Compensation of key management personnel
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 personnel) in office at December 31 of each year amount to euro 25 million, euro 35 million and euro 33 million in 2008, 2009 and 2010, respectively, and consisted of the following:

(euro million)		2008		2009		2010

Wages and salaries		17		20		20
Post-employment benefits		1		1		1
Other long-term benefits		3		10		10
Stock grant/option		4		4		2
		25		35		33

 

Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to euro 6.4 million, euro 9.9 million and euro 9.7 million for 2008, 2009 and 2010, respectively. Compensation of Statutory Auditors amounted to euro 0.634 million, euro 0.475 million and euro 0.511 million in 2008, 2009 and 2010, respectively.

Compensation included emoluments and all other similar payments 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, even if not subjected to personal income tax.

 

Other operating income (loss)
Other operating income (loss) related to the recognition to the income statement of the effects related to the valuation at fair value of those derivatives on commodities which cannot be recognized according to the hedge accounting under IFRS as well as of the derivatives entered by the Gas & Power segment following the new pricing model (see Note 34 – Guarantees, commitments and risks – Risk factors for further information) for an active managing of margins (euro 7 million). Net gain on commodity derivatives of euro 131 million (losses for euro 124 million and incomes for euro 55 million in 2008 and 2009, respectively) included euro 13 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 and the Gas & Power segment (a gain of euro 7 million and euro 6 million in the 2008 and 2009, respectively).

 

Depreciation, depletion, amortization and impairments
Depreciation, depletion, amortization and impairments charges consisted of the following:

(euro million)		2008		2009		2010

Depreciation, depletion and amortization:
- tangible assets		5,994			6,658			7,141
- intangible assets		2,436			2,110			1,744
		8,430			8,768			8,885
Impairments:
- tangible assets		1,343			990			257
- intangible assets		53			62			441
		1,396			1,052			698
less:
- reversal of impairments - tangible assets		(2	)		(1	)
- reversal of impairments - intangible assets		(1	)
- capitalized direct costs associated with self-constructed
assets - tangible assets		(6	)		(4	)		(2	)
- capitalized direct costs associated with self-constructed
assets - intangible assets		(2	)		(2	)		(2	)
		9,815			9,813			9,579

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37 Finance income (expense)
Finance income (expense) consisted of the following:

(euro million)		2008		2009		2010

Finance income (expense)
Finance income		7,985			5,950			6,117
Finance expense		(8,198	)		(6,497	)		(6,713	)
		(213	)		(547	)		(596	)
Gain (loss) on derivative financial instruments		(427	)		(4	)		(131	)
		(640	)		(551	)		(727	)

Net finance income (expense) consisted of the following:

(euro million)		2008		2009		2010

Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(248	)		(423	)		(551	)
Interest due to banks and other financial institutions		(745	)		(330	)		(215	)
Interest from banks		87			33			18
Interest and other income on financing receivables and securities held for non-operating purposes		82			47			21
		(824	)		(673	)		(727	)
Exchange differences
Positive exchange differences		7,339			5,572			5,897
Negative exchange differences		(7,133	)		(5,678	)		(5,805	)
		206			(106	)		92
Other finance income (expense)
Capitalized finance expense		236			223			187
Income from equity instruments		241			163
Interest and other income on financing receivables and securities held for operating purposes		62			39			73
Interest on tax credits		37			4			2
Finance expense due to passage of time (accretion discount) (a)		(249	)		(218	)		(251	)
Other finance income		78			21			28
		405			232			39
		(213	)		(547	)		(596	)

The fair value gain (loss) on derivative financial instruments consisted of the following:

(euro million)		2008		2009		2010

Derivatives on exchange rate		(300	)		40			(111	)
Derivatives on interest rate		(127	)		(52	)		(39	)
Derivatives on commodities					8			19
		(427	)		(4	)		(131	)

Net loss from derivatives of euro 131 million (a net loss of euro 427 million and euro 4 million in 2008 and 2009, respectively) 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 entailed the recognition in profit or loss of negative currency translation differences on assets and liabilities denominated in currencies other than functional currency, as this effect cannot be offset by changes in the fair value of the related instruments.

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38 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)		2008		2009		2010

Share of profit of equity-accounted investments		761			693			717
Share of loss of equity-accounted investments		(105	)		(241	)		(149	)
Decreases (increases) in the provision for losses on investments		(16	)		(59	)		(31	)
		640			393			537

More information is provided in Note 17 – Investments.

 

Other gain (loss) from investments
Other gain (loss) from investments consisted of the following:

(euro million)		2008		2009		2010

Dividends		510			164			264
Gains on disposals		218			16			332
Losses on disposals		(1	)
Other income (expense), net		6			(4	)		23
		733			176			619

Dividends of euro 264 million essentially related to Nigeria LNG Ltd (euro 188 million) and Saudi European Petrochemical Company "IBN ZAHR" (euro 41 million).

Gains on disposals for 2010 of euro 332 million essentially referred to the divestment of the 100% interest in Società Padana Energia SpA (euro 169 million), a 25% stake in GreenStream BV (euro 93 million) and the 100% interest in Distri RE SA (euro 47 million). Gains on disposals for 2009 of euro 16 million primarily referred to a price revision related to the sale done in 2008 of Gaztransport et Technigaz SAS (euro 10 million). Gains on disposals for 2008 of euro 218 million primarily related to the sale of Gaztransport et Technigaz SAS (euro 185 million), Agip España SA (euro 15 million) and Padana Assicurazioni SpA (euro 10 million).

39 Income tax expense
Income tax expense consisted of the following:

(euro million)		2008		2009		2010

Current taxes:
- Italian subsidiaries		1,916			1,724			1,315
- foreign subsidiaries of the Exploration & Production segment		9,744			5,989			7,893
- foreign subsidiaries		426			483			521
		12,086			8,196			9,729
Net deferred taxes:
- Italian subsidiaries		(1,603	)		(534	)		(474	)
- foreign subsidiaries of the Exploration & Production segment		(827	)		(733	)		(97	)
- foreign subsidiaries		36			(173	)		(1	)
		(2,394	)		(1,440	)		(572	)
		9,692			6,756			9,157

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Current income taxes of euro 1,315 million were in respect of Ires and substitute tax (euro 1,077 million) and Irap (euro 224 million) for Italian subsidiaries and foreign taxes (euro 14 million).

The effective tax rate was 55.4% (50.3% and 56.0% in 2008 and 2009, respectively) compared with a statutory tax rate of 39.6% (38.2% and 40.1% in 2008 and 2009, respectively) and calculated by applying a 34.0%¹⁹ 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:

(%)		2008		2009		2010

Statutory tax rate		38.2			40.1		39.6
Items increasing (decreasing) statutory tax rate:
- higher foreign subsidiaries tax rate		15.2			13.3		15.0
- 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		0.7			0.2		0.8
		12.1			15.9		15.8
		50.3			56.0		55.4

The increase in the tax rate of foreign subsidiaries primarily related to a 16.1 percentage points increase in the Exploration & Production segment (17.1% and 16.1% in 2008 and 2009, respectively).

The impact pursuant to Law Decree No. 112/2008, 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 for euro 230 million following adjustments to the valorization criteria of revenues; (ii) a reduced deductibility in Italy of the cost of goods sold following the reduction in the gas volumes of inventories for 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 the weighted-average cost with respect to their tax base according to the last-in-first-out method (LIFO) (euro 528 million). In fact, pursuant to the Law Decree No. 112/2008 (become Law No. 133/2008), energy companies in Italy are required from 2008 to state inventories of hydrocarbons at the weighted-average cost for tax purposes as opposed to the previous LIFO evaluation and to recognize a one-off tax calculated by applying a special tax with a 16% rate on the difference between the two amounts. Accordingly, profit and loss benefited from the difference between utilization of deferred tax liabilities accrued on hydrocarbons inventories and the one-off tax (euro 229 million), for a total positive impact of euro 176 million, which consider previously applicable statutory tax rate (Ires) of 33% 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 profit and loss 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 of euro 173 million; and (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).

In 2010, permanent differences and other adjustments for 0.8 percentage points included: (i) as increase, the supplemental Ires pursuant to the Law No. 7 of February 6, 2009 (1.5 percentage points) and, as decrease, an untaxed income related to a favorable outcome of an antitrust proceeding (0.6 percentage points). For further information see in Note 27 – Provisions for contingencies. In 2009 permanent differences and other adjustments for 0.2 percentage points included: (ii) as increase, a charge amounting to euro 250 million related to the estimation of a fine for the TSKJ matter to the U.S. Authorities (for further information see Note 34 – Guarantees, commitments and risks); and (iii) as decrease, deferred tax assets accounted following an adjustment of the fiscal value to the carrying amount of oil and gas properties related to a reorganization of the Italian activities by paying a special tax and the partial deductibility of Irap of income taxes of previous years (euro 222 million).

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40 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 at December 31, 2008, 2009 and 2010, was 3,638,835,896, 3,622,405,852 and 3,622,454,738, respectively.

Diluted earnings per share is calculated by dividing net profit for the year attributable to Eni’s shareholders by the weighted average number of shares fully-diluted which includes issued and outstanding shares during the year, excluding treasury shares and including the number of shares that could be issued potentially in connection with stock-based compensation plans. At December 31, 2008, 2009 and 2010 the number of shares that could be issued potentially are related to stock options plans.

The average number of shares fully diluted used in the calculation of diluted earnings was 3,638,854,276, 3,622,438,937 and 3,622,469,713 for the years ending December 31, 2008, 2009 and 2010, respectively.

Reconciliation of the average number of shares used for the calculation for both basic and diluted earning per share was as follows:

		2008		2009		2010

Average number of shares used for the calculation of the basic earnings per share				3,638,835,896		3,622,405,852		3,622,454,738
Number of potential shares following stock option plans				18,380		33,085		14,975
Average number of shares used for the calculation of the diluted earnings per share				3,638,854,276		3,622,438,937		3,622,469,713
Eni’s net profit		(euro million)		8,825		4,367		6,318
Basic earning per share		(euro per share)		2.43		1.21		1.74
Diluted earning per share		(euro per share)		2.43		1.21		1.74

 

 

 

 

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41 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

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			(466	)		(623	)		125			18,517
Provisions for contingencies		154			238			190			2			36			219			45						884
Depreciation, amortization and impairments		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			1,846			1,572			(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			(436	)		(420	)					12,055
Provisions for contingencies		(2	)		277			154			1			311			172			142						1,055
Depreciation, amortization and impairments		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			1,868			1,461			(8	)		34,793
Unallocated liabilities																										32,685
Capital expenditures		9,486			1,686			635			145			1,630			44			57			12			13,695
2010
Net sales from operations (a)		29,497			29,576			43,190			6,141			10,581			105			1,386			100
Less: intersegment sales		(16,550	)		(833	)		(1,345	)		(243	)		(1,802	)		(25	)		(1,255	)
Net sales to customers		12,947			28,743			41,845			5,898			8,779			80			131			100			98,523
Operating profit		13,866			2,896			149			(86	)		1,302			(1,384	)		(361	)		(271	)		16,111
Provisions for contingencies		33			(58	)		199			2			35			1,146			50						1,407
Depreciation, amortization and impairments		7,051			1,399			409			135			516			10			79			(20	)		9,579
Share of profit (loss) of equity-accounted investments		92			388			68			1						(2	)		(10	)					537
Identifiable assets (b)		49,573			34,943			14,356			3,076			12,715			362			754			(917	)		114,862
Unallocated assets																										16,998
Equity-accounted investments		1,974			2,370			1,058			30			174			54			8						5,668
Identifiable liabilities (c)		12,330			10,048			6,197			874			5,760			2,898			1,307			(101	)		39,313
Unallocated liabilities																										36,819
Capital expenditures		9,690			1,685			711			251			1,552			22			109			(150	)		13,870

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Starting from 2010, environmental provisions incurred by Eni SpA following the effect of inter-company guarantees given on behalf of Syndial SpA are reported in the segment information within "Other activities". Prior periods information has been restated accordingly.

Inter-segment 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

Americas

Asia

Africa

Other areas

Total

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
2010
Identifiable assets (a)		45,342		16,322		5,091		6,837		12,459		27,322		1,489		114,862
Capital expenditures		3,044		1,710		724		1,156		1,941		5,083		212		13,870

Sales from operations by geographic area of destination

(euro million)		2008		2009		2010

Italy		42,843		27,950		47,802
Other European Union		29,341		24,331		21,125
Rest of Europe		7,125		5,213		4,172
Americas		7,218		7,080		6,282
Asia		8,916		8,208		5,785
Africa		12,331		10,174		13,068
Other areas		308		271		289
		108,082		83,227		98,523

42 Transactions with related parties
In the ordinary course of its business Eni enters into transactions regarding:

a)		the exchange of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries;
b)		the exchange of goods and provision of services with entities directly and indirectly owned or controlled by the Government;
c)		transactions with the Gruppo Cosmi related to Eni through a member of the Board of Directors related to certain acquisition of engineering, construction and maintenance services. Relevant transactions which were executed on an arm’s length basis, consisted of costs amounting to approximately euro 13 million, euro 21 million and euro 23 million in 2008, 2009 and 2010, respectively. At December 31, 2010 receivables for euro 1 million and payables for euro 8 million were outstanding (euro 4 million and euro 9 million at December 31, 2009, respectively); and
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. In 2010, transactions with Eni Foundation

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were not material; and (ii) Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level. Transactions with Enrico Mattei Foundation were not material.

Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities with the aim to develop solidarity, culture and research initiatives, on an arm’s length basis.

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 2008, 2009 and 2010, respectively, consisted of the following:

(euro million)		Dec. 31, 2008		2008

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Other

Goods

Services

Other

Other operating (expense) 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 (expense) 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

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(euro million)		Dec. 31, 2010		2010

Name

Receivables and other assets

Payables and other liabilities

Guarantees

Goods

Services

Other

Goods

Services

Other

Other operating (expense) income

Joint ventures and associates
ACAM Clienti SpA		14		2				1		5				56
Agiba Petroleum Co		2		5						95
Altergaz SA														262
Azienda Energia e Servizi Torino SpA		1		65						78						1
Bayernoil Raffineriegesellschaft mbH				32		1		19		51				2
Bernhard Rosa Inh. Ingeborg Plöchinger GmbH		7												50
Blue Stream Pipeline Co BV		13		14		37				152						2
Bronberger & Kessler undGilg & Schweiger GmbH		20												121
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		28		12		6,054				5						37
CEPAV (Consorzio Eni per l’Alta Velocità) Due		6		3		76				3						6
Gasversorgung Süddeutschland GmbH		3												62
GreenStream BV		4		13						95				1		2
Karachaganak Petroleum Operating BV		39		253				821		346		28		8		7
Kwanda Suporto Logistico Lda		51		1												17
Mellitah Oil & Gas BV		30		137						225						33
Petrobel Belayim Petroleum Co		8		34						714						3		2
Raffineria di Milazzo ScpA		21		20						266				157		7		1
Saipon Snc		2				53										29
Super Octanos CA				23				58						2
Supermetanol CA				13				57										1
Trans Austria Gasleitung GmbH		8		69				32		149				1		37
Transitgas AG				8						70
Unión Fenosa Gas SA		11				58								60				1
Other (*)		138		51		11		27		232		50		35		91		12
		406		755		6,290		1,015		2,486		78		817		272		17
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV		177		285				2		894		5				917		7
Eni BTC Ltd						152
Other (*)		22		22		3		4		48		2		5		23		4
		199		307		155		6		942		7		5		940		11
		605		1,062		6,445		1,021		3,428		85		822		1,212		28
Entities owned or controlled by the Government
Gruppo Enel		83		44				20		318		1		128		471
Gruppo Finmeccanica		44		44				50		37				22		9
GSE - Gestore Servizi Elettrici		94		104				466				81		462		16				3
Terna SpA		35		41				115		71		31		55		28		9		38
Other (*)		62		44						74		4		44		5		21
		318		277				651		500		117		711		529		30		41
		923		1,339		6,445		1,672		3,928		202		1,533		1,741		58		41

Most significant transactions with joint ventures, associates and non-consolidated subsidiaries concerned:

•		sale of natural gas to ACAM Clienti SpA, Altergaz SA and Gasversorgung Süddeutschland GmbH;
•		provisions of specialized services in upstream activities and Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Agip Kazakhstan North Caspian Operating Co NV, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co and, only for Karachaganak Petroleum Operating BV, purchase of oil products and to Agip Kazakhstan North Caspian Operating Co NV, provisions of services by the Engineering & Constuction segment; services charged to Eni’s associates are invoiced on the basis of incurred costs;
•		gas transportation and distribution services in behalf of Azienda Energia e Servizi Torino SpA;
•		payments of refining services to Bayernoil Raffineriegesellschaft mbH and Raffineria di Milazzo ScpA in relation to incurred costs;
•		supply of oil products to Bernhard Rosa Inh. Ingeborg Plöchinger GmbH, Bronberger & Kessler und Gilg & Schweiger GmbH and Raffineria di Milazzo ScpA on the basis of prices referred to the quotations on international markets of the main oil products, as they would be conducted on an arm’s length basis;

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•		acquisition of natural gas transport services outside Italy from Blue Stream Pipeline Co BV, GreenStream BV, Trans Austria Gasleitung GmbH and Transitgas AG, the issuing of guarantees on behalf of Blue Stream Pipeline Co BV and charges of fuel gas, used as drive gas, to Trans Austria Gasleitung GmbH;
•		transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Bologna with CEPAV (Consorzio Eni per l’Alta Velocità) Uno and related guarantees;
•		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;
•		planning, construction and technical assistance to Kwanda Suporto Logistico Lda;
•		acquisition of petrochemical products from Super Octanos CA and Supermetanol CA on the basis of prices referred to the quotations on international markets of the main products;
•		performance guarantees given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and sales of LNG; and
•		guarantees issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd.

Most significant transactions with entities owned or controlled by the Government concerned:

•		sale and transportation service of natural gas, the sale of fuel oil and the sale and purchase of electricity and the acquisition of electricity transmission service with Gruppo Enel;
•		a long-term contract for the maintenance of new 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; and
•		sale and purchase of electricity, the acquisition of domestic electricity transmission service and the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with Terna SpA.

Financing transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities directly and indirectly owned or controlled by the Government in the 2008, 2009 and 2010, respectively, consisted of the following:

(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

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(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

 

(euro million)		Dec. 31, 2010		2010

Name		Receivables		Payables		Guarantees		Charges		Gains

Joint ventures and associates
Artic Russia BV		104		3						1
Bayernoil Raffineriegesellschaft mbH		119
Blue Stream Pipeline Co BV				8		648				9
GreenStream BV		459		2						19
Raffineria di Milazzo ScpA						120
Trans Austria Gasleitung GmbH		144								6
Transmediterranean Pipeline Co Ltd		141								5
Other (*)		105		75		24
		1,072		88		792				40
Unconsolidated entities controlled by Eni
Other (*)		53		39		1				1
		53		39		1				1
		1,125		127		793				41

Most significant transactions with joint ventures, associates and non-consolidated subsidiaries concerned:

•		bank debt guarantee issued on behalf Blue Stream Pipeline Co BV and Raffineria di Milazzo ScpA;
•		financing loans and cash deposit at Eni’s financial companies on behalf of Artic Russia BV and a loan to Bayernoil Raffineriegesellschaft mbH for expenditures in refining plants; and
•		the financing of the Austrian section of the gasline from the Russian Federation to Italy and the construction of natural gas transmission facilities and transport services with Trans Austria Gasleitung GmbH, GreenStream BV 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, 2008		Dec. 31, 2009		Dec. 31, 2010

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Trade and other receivables		22,222		1,539		6.93		20,348		1,355		6.66		23,636		1,356		5.74
Other current assets		1,870		59		3.16		1,307		9		0.69		1,350		9		0.67
Other non-current financial assets		1,134		356		31.39		1,148		438		38.15		1,523		668		43.86
Other non-current assets		1,881		21		1.12		1,938		40		2.06		3,355		16		0.48
Current financial liabilities		6,359		153		2.41		3,545		147		4.15		6,515		127		1.95
Trade and other payables		20,515		1,253		6.11		19,174		1,241		6.47		22,575		1,297		5.75
Other liabilities		3,863		4		0.10		1,856		5		0.27		1,620		5		0.31
Long-term debt and current portion of long-term debt		14,478		9		0.06		21,255						21,268
Other non-current liabilities		3,102		53		1.71		2,480		49		1.98		2,194		45		2.05

The impact of transactions with related parties on the profit and loss account consisted of the following:

		2008		2009		2010

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Net sales from operations		108,082			5,048			4.67		83,227			3,300			3.97		98,523			3,274		3.32
Other income and revenues		728			39			5.36		1,118			26			2.33		956			58		6.07
Purchases, services and other		76,350			6,298			8.25		58,351			4,999			8.57		69,135			5,825		8.43
Other operating income (expense)		(124	)		58			..		55			44			80.00		131			41		31.30
Financial income		7,985			42			0.53		5,950			27			0.45		6,117			41		0.67
Financial expense		(8,198	)		(17	)		0.21		(6,497	)		(4	)		0.06		(6,713	)

Transactions with related parties concerned the ordinary course of Eni’s business and were mainly conducted at an arm’s length basis.

Main cash flows with related parties were as follows:

(euro million)		2008		2009		2010

Revenues and other income		5,087			3,326			3,332
Costs and other expenses		(6,298	)		(4,999	)		(5,825	)
Other operating income (loss)		58			44			41
Net change in trade and other receivables and liabilities		351			34			182
Dividends and net interests		740			407			521
Net cash provided from operating activities		(62	)		(1,188	)		(1,749	)
Capital expenditures in tangible and intangible assets		(2,022	)		(1,364	)		(1,764	)
Change in accounts payable in relation to investments		27			19			10
Change in financial receivables		397			83			128
Net cash used in investing activities		(1,598	)		(1,262	)		(1,626	)
Change in financial liabilities		14			(14	)		(23	)
Net cash used in financing activities		14			(14	)		(23	)
Total financial flows to related parties		(1,646	)		(2,464	)		(3,398	)

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The impact of cash flows with related parties consisted of the following:

		2008		2009		2010

(euro million)

Total

Related parties

Impact %

Total

Related parties

Impact %

Total

Related parties

Impact %

Cash provided from operating activities		21,801			(62	)		..		11,136			(1,188	)		..		14,694			(1,749	)		..
Cash used in investing activities		(16,958	)		(1,598	)		9.42		(10,254	)		(1,262	)		12.31		(12,965	)		(1,626	)		12.54
Cash used in financing activities		(5,025	)		14			..		(1,183	)		(14	)		1.18		(1,827	)		(23	)		1.26

43 Significant non-recurring events and operations
Non-recurring charge (income) consisted of the following:

(euro million)		2008		2009		2010

Transaction for the TSKJ matter					250		24
Fines sanctioned by Antitrust Authorities		(21	)				(270	)
		(21	)		250		(246	)

A non-recurring gain amounting to euro 270 million related to the favorable settlement of antitrust proceedings concerning alleged anti-competitive behavior attributed to Eni following an alleged unjustified refusal to grant access to the import pipeline from Algeria in 2003. This resulted in a significantly lower fine imposed than the one sanctioned by the Antitrust Authority in 2003. A charge of euro 24 million related to a fine of $30 million for the TSKJ matter following the agreement with the Federal Government of Nigeria for the settling of the legal proceeding (see Note 34 – Guarantees, commitments and risks – Legal Proceedings).

44 Positions or transactions deriving from atypical and/or unusual operations
In 2008, 2009 and in 2010 no transactions deriving from atypical and/or unusual operations were reported.

45 Subsequent events
From February 22, 2011, liquids and natural gas production at a number of fields in Libya and supplies through the GreenStream pipeline have been halted as a result ongoing political instability and conflict. Facilities have not suffered any damage and such standstills do not affect Eni’s ability to ensure natural gas supplies to its customers. Eni is technically able to resume gas production at or near previous level once the situation stabilizes. The overall impact of the political instability and conflict in Libya on Eni’s results of operations and cash flows will depend on how long such instability and conflict will last as well as on their final outcome, which management is currently unable to predict. Eni’s oil and natural gas production as of end of March 2011, was flowing at a rate ranging from 70 to 75 KBOE/d down from the expected level of approximately 280 KBOE/d. Production is continuing to decline. Current production mainly consists of gas that is entirely delivered to local power generation plant.

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Supplemental oil and gas information (unaudited)
The following information pursuant to "International Financial Reporting Standards" (IFRS) is presented in accordance with FASB Extractive Activities - Oil & Gas (Topic 932). Amounts related to minority interests are not significant.

Capitalized costs
Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates

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)		3,856			3,313			7,173			8,960			4,677			2,738			3,866			1,015			35,598			1,120
December 31, 2010
Proved mineral interests		10,576			10,616			14,051			17,057			1,989			5,552			6,617			1,674			68,132			927
Unproved mineral interests		32			320			570			2,006			39			1,561			1,979			42			6,549			469
Support equipment and facilities		270			33			1,391			716			70			21			53			6			2,560			16
Incomplete wells and other		909			584			2,069			1,089			4,644			107			1,444			84			10,930			668
Gross capitalized costs		11,787			11,553			18,081			20,868			6,742			7,241			10,093			1,806			88,171			2,080
Accumulated depreciation, depletion and amortization		(8,020	)		(7,771	)		(8,558	)		(11,067	)		(756	)		(4,699	)		(5,591	)		(522	)		(46,984	)		(592	)
Net capitalized costs (a) (b)		3,767			3,782			9,523			9,801			5,986			2,542			4,502			1,284			41,187			1,488

(a)		The amounts include net capitalized financial charges totaling euro 570 million in 2009 and euro 591 million in 2010.
(b)		The amounts do not include costs associated with exploration activities which are capitalized in order to reflect their investment nature and amortized in full when incurred. The "Successful Effort Method" application would have led to an increase in net capitalized costs of euro 3,690 million in 2009 and euro 3,410 million in 2010 for the consolidated companies and of euro 76 million in 2009 and euro 76 million in 2010 for joint ventures affiliates.

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Costs incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(euro million)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (1)

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
2010
Proved property acquisitions
Unproved property acquisition
Exploration		34		114		84		406		6		223		119		26		1,012		45
Development (a)		579		890		2,674		1,909		1,031		359		1,309		160		8,911		367
Total costs incurred		613		1,004		2,758		2,315		1,037		582		1,428		186		9,923		412

(1)		The amounts of joint ventures and affiliates as at December 31, 2009 and 2010 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2008 is reported at 60%).
(a)		Includes the abandonment costs of the assets for euro 628 million in 2008, euro 301 million in 2009 and euro 269 million in 2010.
(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

Rest of Asia

America

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (1)

2008
Revenues
Sales to consolidated entities		3,956			3,892			2,622			5,013			360			39			323			66			16,271
Sales to third parties		126			160			7,286			1,471			1,025			1,335			1,599			218			13,220			265
Total revenues		4,082			4,052			9,908			6,484			1,385			1,374			1,922			284			29,491			265
Operations costs		(260	)		(521	)		(528	)		(609	)		(157	)		(68	)		(233	)		(35	)		(2,411	)		(34	)
Production taxes		(195	)					(32	)		(616	)					(35	)								(878	)		(53	)
Exploration expenses		(135	)		(228	)		(406	)		(548	)		(16	)		(232	)		(435	)		(58	)		(2,058	)		(48	)
D.D. & A. and provision for abandonment (a)		(551	)		(829	)		(1,120	)		(1,115	)		(79	)		(823	)		(837	)		(35	)		(5,389	)		(84	)
Other income (expenses)		(420	)		(56	)		(934	)		(268	)		(270	)		(259	)		(6	)		(41	)		(2,254	)		(15	)
Pretax income from producing activities		2,521			2,418			6,888			3,328			863			(43	)		411			115			16,501			31
Income taxes		(924	)		(1,623	)		(4,170	)		(2,262	)		(302	)		(122	)		(214	)		(70	)		(9,687	)		(49	)
Results of operations from E&P activities (b)		1,597			795			2,718			1,066			561			(165	)		197			45			6,814			(18	)
2009
Revenues
Sales to consolidated entities		2,274			2,583			1,738			4,386			245			41			808			29			12,104
Sales to third parties					540			5,037			586			739			1,208			639			181			8,930			232
Total revenues		2,274			3,123			6,775			4,972			984			1,249			1,447			210			21,034			232
Operations costs		(271	)		(517	)		(553	)		(749	)		(153	)		(78	)		(273	)		(41	)		(2,635	)		(34	)
Production taxes		(148	)					(20	)		(445	)					(34	)								(647	)		(44	)
Exploration expenses		(40	)		(114	)		(319	)		(451	)		(20	)		(204	)		(341	)		(62	)		(1,551	)		(41	)
D.D. & A. and provision for abandonment (a)		(463	)		(921	)		(956	)		(1,502	)		(78	)		(535	)		(1,108	)		(186	)		(5,749	)		(76	)
Other income (expenses)		(125	)		(134	)		(471	)		(467	)		(186	)		(17	)		170			(47	)		(1,277	)		(41	)
Pretax income from producing activities		1,227			1,437			4,456			1,358			547			381			(105	)		(126	)		9,175			(4	)
Income taxes		(467	)		(833	)		(3,010	)		(1,042	)		(180	)		(67	)		(2	)		23			(5,578	)		(40	)
Results of operations from E&P activities (b) (c)		760			604			1,446			316			367			314			(107	)		(103	)		3,597			(44	)
2010
Revenues
Sales to consolidated entities		2,725			3,006			2,094			5,314			324			34			1,139			69			14,705
Sales to third parties					263			6,604			1,696			890			1,429			562			289			11,733			356
Total revenues		2,725			3,269			8,698			7,010			1,214			1,463			1,701			358			26,438			356
Operations costs		(278	)		(555	)		(593	)		(902	)		(184	)		(150	)		(292	)		(69	)		(3,023	)		(41	)
Production taxes		(184	)					(300	)		(700	)					(37	)								(1,221	)		(72	)
Exploration expenses		(35	)		(116	)		(85	)		(465	)		(6	)		(263	)		(204	)		(25	)		(1,199	)		(45	)
D.D. & A. and provision for abandonment (a)		(621	)		(615	)		(1,063	)		(1,739	)		(84	)		(696	)		(872	)		(84	)		(5,774	)		(72	)
Other income (expenses)		(560	)		254			(392	)		(219	)		(161	)		(138	)		(45	)		(25	)		(1,286	)		(59	)
Pretax income from producing activities		1,047			2,237			6,265			2,985			779			179			288			155			13,935			67
Income taxes		(382	)		(1,296	)		(4,037	)		(1,962	)		(291	)		(119	)		(154	)		(36	)		(8,277	)		(66	)
Results of operations from E&P activities (b) (c)		665			941			2,228			1,023			488			60			134			119			5,658			1

(1)		The amounts of joint ventures and affiliates as at December 31, 2009 and 2010 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2008 is reported at 60%).
(a)		Includes asset impairments amounting to euro 770 million in 2008, euro 576 million in 2009 and euro 123 million in 2010.
(b)		The "Successful Effort Method" application would have led to an increase of result of operations of euro 408 million in 2008, euro 320 million in 2009 and a decrease of euro 385 million in 2010 for the consolidated companies and any variation in 2008, an increase of euro 26 million in 2009 and a decrease of euro 5 million in 2010 for joint ventures and affiliates.
(c)		Amounts of 2009 and 2010 do not include results of operation related to the Italian gas storage activities, following restructuring of Eni’s regulated gas businesses in Italy now reported in Gas & Power segment.

Oil and natural gas reserves
Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932).

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of 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

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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 price²⁰ 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 evaluation²¹ 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 report²².

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.

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 2010 Ryder Scott Company and DeGolyer and MacNaughton²² provided an independent evaluation of almost 28% of Eni’s total proved reserves as of December 31, 2010²³ confirming, as in previous years, the reasonableness of Eni’s internal evaluations.

In the three-year period from 2008 to 2010, 78% of Eni’s total proved reserves were subject to independent evaluation.

As of December 31, 2010 the principal properties not subjected to independent evaluation in the last three years are Karachaganak (Kazakhstan), Samburgskoye and Yaro-Yakhinskoye (Russia).

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 54%, 57% and 55% of total proved reserves as of December 31, 2008, 2009 and 2010, respectively, on an oil-equivalent basis.

Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 2%, 2% and 3% of total proved reserves on an oil-equivalent basis as of December 31, 2008, 2009 and 2010, respectively.

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Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserve volumes associated with oil and gas deriving from such obligation represent 0.1%, 0.3% and 0.6% of total proved reserves as of December 31, 2008, 2009 and 2010, 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 evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.

The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2008, 2009 and 2010.

 

 

 

 

 

 

 

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Crude oil (including condensate and natural gas liquids)

(mmBBL)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan (1)

Rest of Asia

America

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

Total consolidated subsidiaries and total joint ventures and affiliates

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
Purchase of Minerals in Place
Revisions of Previous Estimates		38			17			178			75			(37	)		62			2						335						335
Improved Recovery								1			1															2			12			14
Extensions and Discoveries					25			13			22									1						61			117			178
Production		(23	)		(44	)		(108	)		(116	)		(24	)		(17	)		(22	)		(3	)		(357	)		(7	)		(364	)
Sales of Minerals in Place								(1	)		(2	)														(3	)					(3	)
Reserves at December 31, 2010		248			349			978			750			788			139			134			29			3,415			208			3,623
of which:
developed		183			207			656			533			251			39			62			20			1,951			52			2,003
undeveloped		65			142			322			217			537			100			72			9			1,464			156			1,620

(1)		Eni’s proved reserves of the Kashagan field are determined based on Eni share of 16.81% (2007 is reported at 18.52%).
(2)		Joint ventures and affiliates proved reserves as at December 31, 2009 and 2010 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

America

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (2)

Total consolidated subsidiaries and total joint ventures and affiliates

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
Purchase of Minerals in Place
Revisions of Previous Estimates		234			48			778			161			(179	)		211			41			(18	)		1,276			51			1,327
Improved Recovery
Extensions and Discoveries					177			146									4			5			22			354			58			412
Production		(246	)		(204	)		(609	)		(161	)		(86	)		(158	)		(145	)		(35	)		(1,644	)		(13	)		(1,657	)
Sales of Minerals in Place		(48	)					(2	)																	(50	)					(50	)
Reserves at December 31, 2010		2,644			1,401			6,207			2,127			1,874			871			530			544			16,198			1,684			17,882
of which:
developed		2,061			1,103			3,100			1,550			1,621			560			431			539			10,965			246			11,211
undeveloped		583			298			3,107			577			253			311			99			5			5,233			1,438			6,671

(1)		Eni’s proved reserves of the Kashagan field are determined based on Eni share of 16.81% (2007 is reported at 18.52%).
(2)		Joint ventures and affiliates proved reserves as of December 31, 2009 and 2010 include 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, 749, 746, 769 and 767 BCF of natural gas held in storage at December 31, 2007, 2008, 2009 and 2010, 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 year ended December 31, 2008 and the average prices during the years ended December 31, 2009 and 2010 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.

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The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor.

Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates.

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

The standardized measure of discounted future net cash flows by geographical area consists of the following:

(euro million)

Italy

Rest of Europe

North Africa

West Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total consolidated subsidiaries

Total joint ventures and affiliates (1)

Total consolidated subsidiaries and total joint ventures and affiliates

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
At December 31, 2010
Future cash inflows		30,047			27,973			86,728			45,790			41,053			9,701			8,546			3,846			253,684			11,504			265,188
Future production costs		(4,865	)		(7,201	)		(12,896	)		(13,605	)		(6,686	)		(3,201	)		(2,250	)		(611	)		(51,315	)		(3,997	)		(55,312	)
Future development and abandonment costs		(4,499	)		(6,491	)		(8,827	)		(5,310	)		(5,192	)		(3,489	)		(1,713	)		(221	)		(35,742	)		(2,230	)		(37,972	)
Future net inflow before income tax		20,683			14,281			65,005			26,875			29,175			3,011			4,583			3,014			166,627			5,277			171,904
Future income tax		(6,289	)		(9,562	)		(37,108	)		(14,468	)		(7,213	)		(872	)		(910	)		(805	)		(77,227	)		(2,554	)		(79,781	)
Future net cash flows		14,394			4,719			27,897			12,407			21,962			2,139			3,673			2,209			89,400			2,723			92,123
10% discount factor		(7,224	)		(1,608	)		(13,117	)		(3,884	)		(14,829	)		(419	)		(1,392	)		(850	)		(43,323	)		(1,640	)		(44,963	)
Standardized measure of discounted future net cash flows (a)		7,170			3,111			14,780			8,523			7,133			1,720			2,281			1,359			46,077			1,083			47,160

(1)		The amounts of joint ventures and affiliates as at December 31, 2009 and 2010 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2008 is reported at 60%).
(a)		Amounts of 2009 and 2010 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 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, 2008, 2009 and 2010, are as follows:

(euro million)		Total consolidated subsidiaries		Total joint ventures and affiliates		Total consolidated subsidiaries and joint ventures and affiliates

Standardized measure of discounted future net cash flows 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	)
Standardized measure of discounted future net cash flows 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
Standardized measure of discounted future net cash flows at December 31, 2009		31,500			257			31,757
Increase (Decrease):
- sales, net of production costs		(22,194	)		(243	)		(22,437	)
- net changes in sales and transfer prices, net of production costs		24,415			406			24,821
- extensions, discoveries and improved recovery, net of future production and development costs		1,926			1,409			3,335
- changes in estimated future development and abandonment costs		(6,464	)		(386	)		(6,850	)
- development costs incurred during the period that reduced future development costs		8,520			368			8,888
- revisions of quantity estimates		12,600			143			12,743
- accretion of discount		6,519			53			6,572
- net change in income taxes		(11,802	)		(1,115	)		(12,917	)
- purchase of reserves in-place
- sale of reserves in-place		(177	)					(177	)
- changes in production rates (timing) and other		1,234			191			1,425
Net increase (decrease)		14,577			826			15,403
Standardized measure of discounted future net cash flows at December 31, 2010		46,077			1,083			47,160

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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 7, 2011

 

 

 

 

 

 

 

 

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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 S.p.A." resulting from the transformation of Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953 is regulated by these By-laws.
1.2		The Company name may be written with an upper case or lower case initial.
ARTICLE 2
2.1		The registered head office of the Company is located in Rome, Italy and the Company has 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 - Corporate Purpose

ARTICLE 4
4.1		The corporate purpose is the direct and/or indirect management, by way of shareholdings in companies, agencies or businesses, of activities in the field of hydrocarbons and natural gases, 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, renewable energy sources and energy in general, in the sector of engineering and construction of industrial plants, in the mining sector, in the metallurgy sector, in the textile machinery sector, in the water sector, including derivation, drinking water, purification, distribution and reuse of waters; in the sector of environmental protection and treatment and disposal of waste, as well as in every other business activity that is instrumental, supplemental or complementary with the aforementioned activities.
		The Company also has the purpose of undertaking and managing the technical and financial co-ordination of subsidiaries and affiliated companies and the provision of financial assistance to them.
		The Company may undertake any transactions necessary or useful for the achievement of the corporate purpose; by way of example, it may initiate transactions involving real estate, moveable goods, trade and commerce, industry, finance and banking asset and liability transactions, and any action that is in any way connected with the corporate purposes 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 similar, comparable or complementary purposes 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 guarantees for its own and others’ obligations, especially performance bonds.

Part III - Capital - Shareholdings - Bonds

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d)

appointment of one Director with no voting rights. Should such an appointed Director cease to hold office, the Minister of Economy and Finance in agreement with the Minister of Economic Development will appoint a 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, that 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 fix the 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, without prejudice to the provisions of Article 2344 of the Civil Code.
ARTICLE 11
11.1		The Company may issue bonds, including convertible bonds and warrants, 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		An ordinary shareholders’ meeting is called at least once a year, within 180 days of the end of the Company financial year, to approve the financial statements, since the Company is required to draw up consolidated financial statements.
12.3		The Directors must call a shareholders’ meeting without delay when it is requested by shareholders representing at least one twentieth of the share capital. Calling a shareholders’ meeting upon request of shareholders cannot be made for the matters upon which, according to law, the shareholders’ meeting will resolve on the basis of a proposal of the Directors or on the basis of a project or report of the Board. The shareholders who request a meeting to be called must prepare a report on the proposals relating to the items to be discussed; the Board of Directors shall make the report available to the public, together with its own evaluations, if any, at the Company’s registered office, on the Company Website and in the other ways set forth in the Consob regulation, at the time the notice calling the meeting is published.
12.4		The Board of Directors shall make a report on the items on the agenda available to the public in the ways set out in the previous paragraph within the period of time for publication of the notice calling the shareholders’ meeting.
ARTICLE 13
13.1		A shareholders’ meeting shall be called by notice published on the Company Website, as well as in the ways specified by Consob in its regulation, within the legal terms and in accordance with current law.
		Shareholders who severally or jointly represent at least one fortieth of the Company share capital may ask for items to be added to the agenda by submitting a request within ten days of the publication of the notice calling the meeting, unless a different term is provided by the law, indicating the further proposed items in their request. Requests must be submitted in writing. Additions to the agenda cannot be made for the matters upon which, according to law, the shareholders’ meeting will resolve on the basis of a proposal of the Directors or on the basis of a project or report of the Directors different from the report on the items in the agenda. The Board of Directors gives notice of the allowed additions to the agenda in the same ways prescribed for the publication of the notice calling the meeting at least fifteen days before the date set for the shareholders’ meeting, unless a different term is prescribed by law. Within the period of time prescribed for submission of a request to add items to the agenda, the requesting shareholders shall provide to the Board of Directors a report on the matters they propose should be debated. The Board of Directors makes the report available to the public, together with its own evaluations, if any, at the same time as the publication of the notice of the additions to the agenda in the ways set out in Article 12.3 of these By-laws.
13.2		The legitimate attendance of the shareholders’ meetings and the exercise of voting rights is confirmed by a statement to the Company from the authorized intermediary, in compliance with intermediary accounting records,

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on behalf of the person with the voting right. The statement shall be issued by the intermediary on the basis of balances recorded at the end of the seventh trading day prior to the date of the shareholders’ meeting on first or single call. Credit and debit records entered on accounts after this deadline shall not be considered for the purpose of legitimising the exercise of voting rights at the shareholders’ meeting. The statement made by the authorized intermediary must reach the Company by the end of the third trading day prior to the date of the shareholders’ meeting on first or single call, or other deadline fixed by Consob regulation issued in agreement with the Bank of Italy. It remains implicit that the right to attend the meeting and vote shall be legitimate if the statements are received by the Company after the deadlines indicated above, provided they are received before the opening of the shareholders’ meeting on single call.

ARTICLE 14
14.1		Those persons who are entitled to vote may appoint a representative in the shareholders’ meeting according to law, by means of a written proxy or in electronic form when this is provided for in specific regulations and in the ways set forth therein. In this latter case, electronic notification of the proxy may be carried out by using a special section of the Company Website in the ways indicated in the notice calling the meeting. In order to simplify the casting of vote by proxy issued by shareholders who are employees of the Company or of 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 legal representatives of said associations.
14.2		The Chairman of the meeting has to assure the regularity of 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. If envisaged in the notice calling the meeting, those persons entitled to vote may attend the shareholders’ meeting through telecommunication equipment, and exercise their right to vote by electronic means, in accordance with the law, the regulatory provisions on this subject and with the meeting Regulations.
14.4		The shareholders’ meetings are disciplined by the shareholders’ meeting Regulations approved by the ordinary shareholders’ meeting.
14.5		The Company may designate a subject for each shareholders’ meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the proposals on the agenda in the ways provided by the law and the regulatory provisions, by the end of the second trading day preceding the date set for the shareholders’ meeting on first or single call. The proxy is not valid for proposals on which no voting instructions have been provided.
ARTICLE 15
15.1		The meeting is chaired by the Chairman of the Board of Directors, or in the event of his absence or impediment, by the Chief Executive Officer; in their absence, the meeting shall elect its own Chairman.
15.2		The Chairman of the meeting is assisted by a Secretary, who need not be a shareholder, to be designated by the 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 business transfer.
16.2		The ordinary and the extraordinary shareholders’ meeting are normally held after more than one call, as provided for in these By-laws; their resolutions in first, second or third call must be passed with the majorities requested by the law in each case. The Board of Directors may, if it is deemed necessary, determine that both the ordinary and the extraordinary shareholders’ meeting shall be held after a single call. In case of a single call the majorities required by law in this case shall apply.
16.3		The resolutions of the shareholders’ meeting, passed in accordance with the legal regulations and these By-laws, are binding on all shareholders, including those not present 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 6.2, letter d), of the By-laws.
17.2		The Directors are 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.

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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.
		The lists must be filed with the Company’s registered office by the twenty-fifth day before the date of the shareholders’ meeting on first or single call, called to resolve on the appointment of members of the Board of Directors, and made available to the public in the ways set forth in the law and in the Consob regulation at least twenty-one days before the date set for the shareholders’ meeting on first or single call. Each shareholder may, severally or jointly, submit and vote on a single list. Controlling subjects, controlled companies by them and those under joint control cannot submit or participate in the submission of other lists, nor can they vote on them, even through intermediaries or trustees, controlled here meaning those companies referred to in Article 93 of legislative decree No. 58 of February 24, 1998. Each candidate may stand on a single list, on penalty of non-electability. Only those shareholders who, severally or jointly, represent at least 1 per cent. of the share capital or the different extent fixed by Consob with its regulation shall have the right to submit lists. Ownership of the minimum share needed to submit lists shall be determined by having regard to the shares registered to the shareholder on the day on which the lists are filed with the Company. Related certification may also be submitted after the filing, provided submission is within the time limit fixed for the publication of the lists by the Company.
		At least one Director, if there are no more than five Directors, or at least three Directors if there are more than five, shall satisfy the independence requirements 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 satisfy the integrity requirements set forth by the applicable legislation.
		Together with the filing of each list, on penalty of inadmissibility, the curriculum of each candidate, statements of each candidate to accept his/her nomination and attest, in his/her own responsibility, that causes for his/her ineligibility and incompatibility are non existing and that he/she satisfies the aforementioned integrity and, if any, independence requirements, shall be filed.
		The appointed Directors shall communicate to the Company if they have lost the above mentioned independence and integrity requirements and if situations of ineligibility or incompatibility have arisen.
		The Board of Directors evaluates periodically the independence and the integrity of its members and if situations of ineligibility or incompatibility have arisen. If the integrity or independence requirements declared and set forth by the legislation in force are not satisfied or lapse for a Director or if situations of ineligibility or incompatibility have arisen, the Board of Directors shall declare the Director’s disqualification and resolve upon his/her substitution or shall invite him/her to rectify the situation of incompatibility within the term set by the Board itself, on penalty of his/her disqualification.
		Directors shall be elected in the following manner:

			a)		seven tenths of the Directors 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 Directors 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 submitted 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 or three 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 ordered in a decreasing numerical list. 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 Director elected or that has elected the least number of Directors. In the event that none of the lists has yet elected a Director or that all of them have elected the same number of Directors, 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 quotients, the entire shareholders’ meeting will vote again and the candidate elected will be the one who obtains a simple majority of the votes;
			c)		if the minimum number of independent Directors prescribed in these By-laws has not been elected after the application of the procedure described above, the quotient to be assigned to the candidates in each list shall be calculated using the system described at letter b); the independent candidates not yet drawn from the lists pursuant to letters a) and b) above, who have 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 fixed in these By-laws, the shareholders’ meeting shall resolve, with the majorities prescribed by the law, to replace the non-independent candidates who received the lowest quotients;
			d)		to appoint Directors for any reason not appointed pursuant to the aforementioned procedure, the shareholders’ meeting shall resolve, with the majorities prescribed by the law, in such a way as to ensure that the composition of the Board of Directors complies with the current legislation and the By-laws.
			The vote by list procedure shall apply only to the renewal of the entire Board of Directors.
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appointments. The mandates of Directors so elected will expire at the same time as those of the Directors already serving.

17.5		If during the term of office one or more Directors should no longer hold office, action will be taken in compliance with Article 2386 of the Civil Code with exception of the Director appointed pursuant to Article 6.2 letter d) of these By-laws. If a majority of Directors should cease to hold office, the whole Board will be considered to have resigned, and the Board must promptly call a shareholders’ meeting to appoint a new Board.
17.6		The Board may establish Board Committees which have consulting and proposing functions on specific subjects.
ARTICLE 18
18.1		If the shareholders’ meeting has not appointed a Chairman, the Board will elect one among its members. The Director appointed pursuant to Article 6.2, letter d) of the By-laws cannot be appointed as Chairman.
18.2		The Board, at the Chairman’s proposal, shall appoint a Secretary, who need not belong to the Company.
ARTICLE 19
19.1		The Board meets in the place indicated in the meeting notice whenever the Chairman or, in case of his absence or impediment, the Chief Executive Officer deems necessary, or when written application has been made by the majority of its members. The Board of Directors may also be convened pursuant to Article 28.4 of these By-laws. The Board of Directors’ meetings may be held by video or teleconference if each of the participants in the meetings can be identified and if each can follow and participate in the discussion of the topics dealt with in real time. 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 the period of notice may be shorter. The Board of Directors decides on how its meetings should be convened.
19.3		The Board of Directors must also be convened when so requested by at least two Directors or by one if the Board consists of three Director, to decide on a specific topic considered to be of particular importance, pertaining to the management of the Company, and said topic must be specified in the request.
ARTICLE 20
20.1		The Chairman of the Board or, in his absence, the oldest Director in attendance shall chair the meeting.
ARTICLE 21
21.1		For a Board meeting to be valid, a majority of serving Directors with voting rights must be present.
21.2		Resolutions shall be approved by majority of votes of the Directors with voting rights present; should votes be equal, the person who chairs the meeting shall have a casting vote.
ARTICLE 22
22.1		The resolutions of the Board of Directors 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 or her and countersigned by the Secretary.
ARTICLE 23
23.1		The Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, except for the acts that the law or these By-laws reserve for the shareholders’ meeting.
23.2		The Board of Directors shall deliberate on the following matters:

-		the merger and the proportional demerger of companies in which the Company owns shares or holdings representing at least 90 per cent. of the share capital;
-		the establishment and winding up of branches;
-		the amendment of the By-laws to comply with legal provisions.

23.3		The Board of Directors and the Chief Executive Officer shall promptly report to the Board of Statutory Auditors at least every three months and in any event at the time of the meetings of the Board of Directors, on the activity carried out and on the most significant economic, financial and capital transactions carried out by the Company and the companies it controls; in particular they shall report to the Board of Statutory Auditors those transactions in which they have an interest, on their own 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 6.2, letter d) of the By-laws, within the limits set forth in Article 2381 of the Civil Code; the Board may in addition delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may at any time withdraw the powers delegated hereon, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, upon the proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for single acts or categories of

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acts on other members of the Board of Directors with the exception of the Director appointed pursuant to Article 6.2, letter d) of these By-laws. The Chairman and the Chief Executive Officer, within the limits of the authority attributed to them, may delegate and empower Company employees or third parties to represent the Company for 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 determine the powers to be conferred on them, after they have been ascertained to fulfil the integrity requirements prescribed by the law. The Board of Directors shall periodically check the integrity of the General Managers. Failure to satisfy these requirements shall result in disqualification from the position.
		Upon proposal of the Chief Executive Officer, in agreement with the Chairman and with the favourable opinion of the Board of Statutory Auditors, the Board of Directors appoints the Manager responsible for the preparation of the financial reporting documents.
		The Manager responsible for the preparation of the financial reporting documents must be chosen from among those persons who, for at least three years, have carried out:

		a)		administration, control or senior management activities in companies listed on regulated stock exchanges in Italy or other European Union countries or other OECD countries with a share capital of no less than two million euro, or
		b)		audit activities in the companies indicated in letter a) above, or
		c)		professional activities or university teaching activities in the financial or accounting sectors, or
		d)		senior management functions in public or private bodies in the financial, accounting, or control sectors.

		The Board of Directors shall monitor that the Manager responsible for the preparation of the financial reporting documents has adequate powers and means to execute his/her tasks and that the administrative and accounting procedures are effectively respected
ARTICLE 25
25.1		Legal representation towards any judicial or administrative authority and towards third parties, and the Company signature, is vested in either the Chairman or the Chief Executive Officer.
ARTICLE 26
26.1		The Chairman and the members of the Board of Directors are entitled to remuneration to be determined by the ordinary shareholders’ meeting. Said resolution, once taken, shall remain valid for subsequent financial years until the shareholders’ meeting decides otherwise.
ARTICLE 27
27.1		The Chairman:

a)		represents the Company pursuant to Article 25.1;
b)		chairs the shareholders’ meeting pursuant to Article 15.1;
c)		calls and chairs meetings of the Board of Directors pursuant to Articles 19.1 and 20.1;
d)		checks that Board resolutions are implemented;
e)		exercises the powers delegated to him by the Board of Directors pursuant to Article 24.1.

Part VI - Board of Statutory Auditors

ARTICLE 28
28.1		The Board of Statutory Auditors consists of five effective members and two alternate members, chosen among persons who satisfy the professional and integrity requirements set forth by the Ministry of Justice Decree No. 162, of March 30, 2000.
		Pursuant to the aforementioned decree, the subjects closely connected to the business of the Company are: commercial law, business economics and corporate finance.
		Similarly, the sectors closely connected to 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.
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 the candidates are listed by progressive number.
		The procedures set forth in Article 17.3 and the provisions issued by Consob in its regulation shall apply to the submission, filing and publication of candidate lists.
		Lists shall be divided into two sections: the first concerns those candidates for appointment as effective Auditors and the second for the candidates for appointment as alternate Auditors. At least the first candidate in each section must be a chartered accountant and have carried out audit activities for no 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 standing Auditors and the other alternate Auditor will be appointed pursuant to Article 17.3, letter b) of the By-laws. The procedure described in said Article shall apply separately to each section of the other lists.

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		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.
		The vote by list procedure shall apply only in case of renewal of the entire Board of Statutory Auditors.
		Should an effective Auditor from the candidate list that received a majority of the votes expressed by the shareholders be replaced, the replacement shall be the alternate Auditor from the same list; should an effective Auditor from the other candidate lists be replaced, the replacement shall be the Alternate Auditor from those other lists.

28.3		Retiring Auditors may be re-elected.
28.4		Subject to prior communication to the Chairman of the Board of Directors, the Board of Statutory Auditors may call shareholders’ meetings and of the Board of Directors. The power to call the Board of Directors may be exercised individually by each member of the Board of Statutory Auditors; at least two effective Auditors are required to call shareholders’ meetings.
		The Board of Statutory Auditors’ meetings may be held by video or teleconference if each of the participants in the meetings can be identified and if each can follow and participate in the discussion of the topics dealt with in real time. 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 Company financial year ends on December 31 every year.
29.2		At the end of each financial year, the Board of Directors sees to the preparation of the Company financial statements in compliance with the law.
29.3		The Board of Directors may pay interim dividends to the shareholders during the financial year.
ARTICLE 30
30.1		Dividends not collected within five years of the day on which they become 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 resolve the manner of its 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 special laws on these matters shall apply.
32.2		Pursuant to Article 3, paragraph 2, of Decreelaw No. 332 of May 31, 1994, converted with amendments into Law No. 474 of July 30, 1994, Article 6.1, subsection six, of these By-laws does not apply to the shareholding owned by the Ministry of Economy and Finance, public bodies or entities they control.
ARTICLE 33
33.1		The Company retains all assets and liabilities held by the public law agency Ente Nazionale Idrocarburi before its transformation.

 

 

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EXHIBIT 8

List of Eni’s subsidiaries for year 2010

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
Eni Zubair SpA		Italy		100.00
Ieoc SpA		Italy		100.00
Società Adriatica Idrocarburi SpA		Italy		100.00
Società Ionica Gas SpA		Italy		100.00
Società Oleodotti Meridionali - SOM SpA		Italy		70.00
Società Petrolifera Italiana SpA		Italy		99.96
Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA		Italy		100.00
Agip Caspian Sea BV		Netherlands		100.00
Agip Energy and Natural Resources (Nigeria) Ltd		Nigeria		100.00
Agip Karachaganak BV		Netherlands		100.00
Agip Oil Ecuador BV		Netherlands		100.00
Burren Energy (Bermuda) Ltd		Bermuda		100.00
Burren Energy Congo Ltd		British Virgin Islands		100.00
Burren Energy (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 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
Eni Hewett Ltd		UK		100.00

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Table of Contents

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 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 Popodi Ltd		UK		100.00
Eni Rapak Ltd		UK		100.00
Eni Resources Ltd (in liquidation)		UK		100.00
Eni TNS Ltd		UK		100.00
Eni Togo BV		Netherlands		100.00
Eni Transportation Ltd		UK		100.00
Eni Trinidad and Tobago Ltd		Trinidad and Tobago		100.00
Eni TTO Ltd (in liquidation)		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		UK		100.00
First Calgary Petroleums LP		USA		100.00
First Calgary Petroleums Partner Co ULC		Canada		100.00
Hindustan Oil Exploration Co Ltd		India		47.18
Ieoc Exploration BV		Netherlands		100.00
Ieoc Production BV		Netherlands		100.00
Lasmo Sanga Sanga Ltd		Bermuda		100.00
Minsk Energy Resources Sp.Zo.o		Poland		100.00
Nigerian Agip Exploration Ltd		Nigeria		100.00
Nigerian Agip Oil Co Ltd		Nigeria		100.00
OOO ‘Eni Energhia’		Russia		100.00

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GAS & POWER
Acqua Campania SpA		Italy		31.97
Compagnia Napoletana di Illuminazione e Scaldamento col Gas SpA		Italy		55.39
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		55.56
LNG Shipping SpA		Italy		100.00
Snam Rete Gas SpA		Italy		55.56
Società EniPower Ferrara Srl		Italy		51.00
Società Italiana per il Gas pA		Italy		55.56
Stoccaggi Gas Italia SpA - Stogit SpA		Italy		55.56
Toscana Energia Clienti SpA		Italy		100.00
Travagliato Energia Srl		Italy		100.00
Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana		Slovenia		51.00
Altergaz SA		France		53.88
Distribuidora de Gas Cuyana SA		Argentina		45.60
Distrigas LNG Shipping SA		Belgium		100.00
Distrigas NV		Belgium		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
Inversora de Gas Cuyana SA		Argentina		76.00
Société de Service du Gazoduc Transtunisien SA - Sergaz SA		Tunisia		66.67
Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA		Tunisia		100.00
Tigáz-Dso Földgázelosztó kft		Hungary		50.08
Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság		Hungary		50.08
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 Centrosud SpA (former Fox Energy SpA)		Italy		100.00
Eni Fuel Nord SpA		Italy		100.00
Eni Rete oil&nonoil SpA		Italy		100.00
Eni Trading & Shipping SpA		Italy		100.00
Petrolig Srl		Italy		70.00
Petroven Srl		Italy		68.00
Raffineria di Gela SpA		Italy		100.00
Agip Lubricantes SA		Argentina		100.00
Agip Slovenija doo		Slovenia		100.00
Eni Austria GmbH (former Agip Austria GmbH)		Austria		100.00
Eni Austria Tankstellenbetrieb GmbH
(former Agip Austria Tankstellenbetrieb GmbH)		Austria		100.00
Eni Benelux BV		Netherlands		100.00
Eni Ceská Republika Sro (former Agip Ceská Republika Sro)		Czech Republic		100.00
Eni Deutschland GmbH (former Agip Deutschland GmbH)		Germany		100.00
Eni Ecuador SA		Ecuador		100.00
Eni France Sàrl		France		100.00
Eni Hungaria Zrt		Hungary		100.00
Eni Iberia SLU		Spain		100.00
Eni Marketing Austria GmbH		Austria		100.00
Eni Mineralölhandel GmbH		Austria		100.00

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Eni Oil Ceská Republika Sro		Czech Republic		100.00
Eni Oil Slovensko Spol Sro		Slovakia		100.00
Eni Romania Srl (former Agip Romania Srl)		Romania		100.00
Eni Schmiertechnik GmbH (former Agip Schmiertechnik GmbH)		Germany		100.00
Eni Slovensko Spol Sro		Slovakia		100.00
Eni Suisse SA		Switzerland		100.00
Eni Trading & Shipping BV		Netherlands		100.00
Eni Trading & Shipping Inc		USA		100.00
Eni USA R&M Co Inc (former American Agip Co 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
Saipem Energy Services SpA		Italy		43.29
Saipem SpA		Italy		43.29
Servizi Energia Italia SpA		Italy		43.29
SnamprogettiChiyoda SAS di Saipem SpA		Italy		43.25
Andromeda Consultoria Tecnica e Representações Ltda		Brazil		43.29
Boscongo SA		Congo		43.29
BOS Investment Ltd		UK		43.29
BOS - UIE Ltd		UK		43.29
Construction Saipem Canada Inc		Canada		43.29
Ersai Caspian Contractor Llc		Kazakhstan		21.65
ERS - Equipment Rental & Services BV		Netherlands		43.29
Global Petroprojects Services AG		Switzerland		43.29
Katran-K Llc		Russia		43.29
Moss Maritime AS		Norway		43.29
Moss Maritime Inc		USA		43.29
Moss Offshore AS		Norway		43.29
North Caspian Service Co		Kazakhstan		43.29
Petrex SA		Peru		43.29
Petromar Lda		Angola		30.30
PT Saipem Indonesia		Indonesia		43.29
Saigut SA De Cv		Mexico		43.29
Saimexicana SA De Cv		Mexico		43.29
Saipem America Inc		USA		43.29
Saipem Asia Sdn Bhd		Malaysia		43.29
Saipem (Beijing) Technical Services Co Ltd		China		43.29
Saipem Contracting Algerie SpA		Algeria		43.29
Saipem Contracting Netherlands BV		Netherlands		43.29
Saipem Contracting (Nigeria) Ltd		Nigeria		42.40
Saipem do Brasil Serviçõs de Petroleo Ltda		Brazil		43.29
Saipem Drilling Co Private Ltd		India		43.29
Saipem India Projects Ltd		India		43.29
Saipem International BV		Netherlands		43.29
Saipem Libya Limited Liability Company - SA.LI.CO. Llc		Libya		43.29
Saipem Ltd		UK		43.29
Saipem Luxembourg SA		Luxembourg		43.29
Saipem (Malaysia) Sdn Bhd		Malaysia		17.91
Saipem Maritime Asset Management Luxembourg Sàrl		Luxembourg		43.29
Saipem Mediteran Usluge doo		Croatia		43.29

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Saipem Misr for Petroleum Services SAE		Egypt		43.29
Saipem (Nigeria) Ltd		Nigeria		38.71
Saipem Perfurações e Construções Petrolíferas Unipessoal Lda		Portugal		43.29
Saipem (Portugal) Comércio Marítimo. Sociedade Unipessoal Lda		Portugal		43.29
Saipem (Portugal) - Gestão de Participações SGPS Sociedade Unipessoal SA		Portugal		43.29
Saipem SA		France		43.29
Saipem Services México SA De Cv		Mexico		43.29
Saipem Services SA		Belgium		43.29
Saipem Singapore Pte Ltd		Singapore		43.29
Saipem UK Ltd		UK		43.29
Saipem Ukraine Llc		Ukraine		43.29
Sajer Iraq Co for Petroleum Services Trading General Contracting & Transport Llc		Irak		25.97
SAS Port de Tanger		France		43.29
Saudi Arabian Saipem Ltd		Saudi Arabia		25.97
Sigurd Rück AG		Switzerland		43.29
Snamprogetti Canada Inc		Canada		43.29
Snamprogetti Engineering BV		Netherlands		43.29
Snamprogetti Ltd		UK		43.29
Snamprogetti Lummus Gas Ltd		Malta		42.86
Snamprogetti Netherlands BV		Netherlands		43.29
Snamprogetti Romania Srl		Romania		43.29
Snamprogetti Saudi Arabia Co Ltd Llc		Saudi Arabia		43.29
Société de Construction d'Oleoducs Snc (in liquidation)		France		43.29
Sofresid Engineering SA		France		43.29
Sofresid SA		France		43.29
Sonsub AS		Norway		43.29
Sonsub International Pty Ltd		Australia		43.29
Star Gulf FZ Co		United Arab Emirates		43.29
Varisal - Serviços de Consultadoria e Marketing Unipessoal Lda		Portugal		43.29
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		Italy		99.63
Eni Corporate University SpA		Italy		100.00
EniServizi SpA		Italy		100.00
Serfactoring SpA		Italy		48.82
Servizi Aerei SpA		Italy		100.00
Banque Eni SA		Belgium		100.00
Eni 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 7, 2011

 

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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 7, 2011

 

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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, 2010 (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 7, 2011

 

 

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, 2010 (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 7, 2011

 

 

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 17, 2011

 

 

 

Eni S.p.A.
E&P Division
Ms. Manuela Feudaroli
Vice President, Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

 

Dear Ms. Feudaroli:

Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved crude oil, condensate, liquefied petroleum gas (LPG), and natural gas reserves, as of December 31, 2010, of certain properties in Africa, Italy, and Rest of Europe owned by Eni S.p.A. (Eni). This evaluation was completed on March 17, 2011. Eni has represented that these properties account for 13 percent, on a net equivalent barrel basis, of Eni’s net proved reserves as of December 31, 2010, 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, 2010, 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, 2010. 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, condensate, LPG, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that

 

 

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information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Eni personnel, from Eni files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Eni with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

 

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

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

 

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and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of production licenses as appropriate.

 

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Reserves classifications used for our estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Eni has represented that its estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using known production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and 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

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operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in 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.

 

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(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(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

 

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application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

 

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil, Condensate, and LPG Prices

Eni has represented that the oil, condensate, and LPG prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A dated Brent oil price of 79.00 United States dollars (U.S.$) per barrel (U.S.$/bbl) was the resulting reference price. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average prices in this report were:

		Oil and Condensate (U.S.$/bbl)		LPG (U.S.$/bbl)

Africa		77.93		17.88
Italy		None		None
Rest of Europe		74.27		55.31
Average for Total		77.69		24.68

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

 

 

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within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. A significant quantity of the gas sold by Eni is subject to contract prices, and the range of such prices is varied. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average gas prices in this report in U.S.$/Mcf were:

		Gas (U.S.$/Mcf)

Africa		2.53
Italy		8.41
Rest of Europe		5.08
Average for Total		3.838

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.

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, 2010, 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 Africa, Italy, and Rest of Europe are based on the definitions of proved reserves of the SEC. Eni represents that its estimates of the net proved reserves attributable to these properties, which represent 13 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):

 

 

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In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932- 235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932- 235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

In comparing the detailed net proved reserves estimates prepared by us and by Eni, we have found differences, both positive and negative, resulting in an aggregate difference of less than 5 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Eni on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us.

 

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

	Submitted,
	/s/ DEGOLYER AND MACNAUGHTON
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

 

	/s/ LLOYD W. CADE, P.E.
	Lloyd W. Cade, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

 

 

 

 

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DEGOLYER AND MACNAUGHTON

 

 

 

 

CERTIFICATE of QUALIFICATION

I, Lloyd W. Cade Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.		That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Eni dated March 17, 2011, 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 28 years of experience in oil and gas reservoir studies and reserves evaluations.

 

 

 

SIGNED: March 17, 2011

 

 

 

	/s/ LLOYD W. CADE, P.E.
	Lloyd W. Cade, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

 

 

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EXHIBIT 15.a(ii)

 

Eni S.p.A.

 

 

Estimated

Future Reserves and Income

Attributable to Certain
Leasehold and Royalty Interests

 

 

 

 

SEC Parameters

 

 

As of

December 31, 2010

/s/HERMAN G. ACUÑA
————————————————————————————————
Herman G. Acuña, P.E.
TBPE License No. 92254
Managing Senior International Vice President

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580

[SEAL]

 

 

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

 

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February 14, 2011

 

Eni S.p.A.
E&P Division
Ms. Manuela Feudaroli
Vice President Reserves
Via Emilia 1
20097 San Donato Milanese
Milano, Italy

Dear Ms. Feudaroli:

At the request of Eni S.p.A. (Eni), Ryder Scott Company (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by Eni’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 31, 2011 and presented herein, was prepared for public disclosure by Eni in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Eni has indicated that the proved net reserves attributable to the properties that we reviewed account for 15 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following geographic locations:

• Africa
• Asia
• America

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as "the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities."

Based on our review, including the data, technical processes and interpretations presented by Eni, it is our opinion that the overall procedures and methodologies utilized by Eni in preparing their estimates of the proved reserves as of December 31, 2010 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Eni are, in the aggregate, reasonable within 5 percent of Ryder Scott’s estimates which is less than the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The conclusions discussed in this report, as of December 31, 2010, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month

 

 

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within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities audited by Ryder Scott.

 

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as an attachment to this report. The various proved reserve status categories are defined under the attachment entitled "Petroleum Reserves Definitions" in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The audited proved gas volumes included gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein.

Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Eni’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered."

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue

 

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to Eni for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Eni the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Eni’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Eni operates or has interests. Eni’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves audited herein were based upon a detailed study of the properties in which Eni owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

 

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities

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actually recovered are much more likely than not to be achieved." The SEC states that "probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy methods, the volumetric method, or a combination of performance and volumetric methods. These performance methods include, but may not be limited to, decline curve analysis and analogy which utilized extrapolations of historical production and pressure data available through December, 2010 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Eni and were considered sufficient for the purpose thereof. The volumetric method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by Eni that were available through December, 2010. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Eni has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Eni with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Eni. We consider the factual data used in this report appropriate and sufficient for the purpose of our investigations.

 

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In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to conduct the audit of reserves of the properties described herein. The proved reserves discussed herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC Regulations." In our opinion, the proved reserves reviewed in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

 

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Eni. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

 

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Eni furnished us with the above mentioned average prices in effect on December 31, 2010. Eni has assured us that these initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. The average dated Brent oil price of $79/Bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. The average realized prices provided by Eni and used in our evaluation are as follows:

 

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Geographic Area		Product		Average Realized Prices

Africa		Gas		$307.07/Mm3
		Oil & Condensate		$76.14/Bbl
Asia		Gas		$355.43/Mm3
		Oil & Condensate		$67.92/Bbl
America		Oil		$72.36/Bbl

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as "differentials." The differentials used in the preparation of this report were furnished to us by Eni. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Eni to determine these differentials.

 

Costs

Operating costs used in our evaluation were based on the operating expense reports of Eni and include only those costs directly applicable to the evaluated assets. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Eni. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the assets.

Development costs were furnished to us by Eni and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Eni were accepted without independent verification.

The proved developed and undeveloped reserves in this report have been incorporated herein in accordance with Eni’s plans to develop these reserves as of December 31, 2010. The implementation of Eni’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Eni’s management. As the result of our inquires during the course of preparing this report, Eni has informed us that the development activities included herein have been subjected to and received the internal approvals required by Eni’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Eni. Additionally, Eni has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Eni were held constant throughout the life of the properties.

 

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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 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. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

 

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Eni.

We have provided Eni with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Eni and the original signed report letter, the original signed report letter shall control and supersede the digital version.

 

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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

 

	Very truly yours,
	RYDER SCOTT COMPANY, L. P.
	TBPE Firm Registration No. F-1580
	/s/ HERMAN G. ACUÑA, P.E.
	Herman G. Acuña, P.E.
	TBPE License No. 92254
	Managing Senior Vice President-International
	[SEAL]
HGA/sm

 

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Professional Qualifications
Herman G. Acuña

The conclusions presented in this report for Eni properties located in Africa, Asia and America are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Herman G. Acuña was the primary technical person responsible for overseeing the independent estimation of the reserves, future production and income to render the audit conclusions of the report.

Mr. Acuña, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1997, is a Managing Senior International Vice President and serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Acuña served in a number of engineering positions with Exxon. For more information regarding Mr. Acuña’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com.

Mr. Acuña earned a Bachelor (Cum Laude) and a Masters (Magna Cum Laude) of Science degree in Petroleum Engineering from The University of Tulsa in 1987 and 1989 respectively. He is a registered Professional Engineer in the State of Texas, a member of the Association of International Petroleum Negotiators (AIPN) and the Society of Petroleum Engineers (SPE).

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Acuña fulfills. Mr. Acuña has attended formalized training and conferences including dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Acuña has recently taught various company reserves evaluation schools in Argentina, Bolivia, China, Denmark, 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 over 20 years of practical experience in petroleum engineering and the estimation and evaluation of petroleum reserves, Mr. Acuña has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

 

 

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the "Modernization of Oil and Gas Reporting; Final Rule" in the Federal Register of National Archives and Records Administration (NARA). The "Modernization of Oil and Gas Reporting; Final Rule" includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The "Modernization of Oil and Gas Reporting; Final Rule", including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the "SEC Regulations". The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).

Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

 

 

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Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

 

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a) (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

 

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §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

 

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(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.

 

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based: and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

 

 

 

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

 

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §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.

 

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Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In
Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.

In all cases. production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

 

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §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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