UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Form 20-F

		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, 20089
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
20097 Milano
(Milano) - Italy
Tel +39 02 52041730
- Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
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Securities registered or to be registered pursuant to Section 12(b) of the Act.

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark 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 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).

TABLE OF CONTENTS

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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"Item 5 – Operating and Financial Review and Prospects”Prospects" and "Item 11 – Qualitative and Quantitative Disclosures about Market Risk" contain forward-looking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the "SEC"). In addition, Eni’s senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as ‘expects’, ‘anticipates’, ‘targets’, ‘goals’, ‘projects’, ‘intends’, ‘plans’, ‘believes’, ‘seeks’, ‘estimates’, variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni’s actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled "Risk Factors" and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni’s expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.

CERTAIN DEFINED TERMS

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

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

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

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

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

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

STATEMENTS REGARDING COMPETITIVE POSITION

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

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GLOSSARY

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

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ABBREVIATIONS

CONVERSION TABLE

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PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

Item 3. KEY INFORMATION

Selected Financial InformationInformation

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB). The tables below show Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2004, 2005, 2006, 2007, 2008 and 2008.2009. The selected historical financial data for the years ended December 31, 2004, 2005, 2006, 2007 and 2008presented herein are derived from Eni’s Consolidated Financial Statements included in Item 18.

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

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Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2004, 2005, 2006, 2007, 2008 and 2008.2009. Data on production of oil and natural gas and hydrocarbon production sold includes Eni’s share of production of affiliates and joint ventures accounted for under the equity or cost method of accounting.

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Selected Operating Information continued

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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).

Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on May 4, 2009April 9, 2010 was $1.34$1.35 per euro 1.00.

Risk Factors

Competition

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

Eni encountersfaces competition from other oil and natural gas companies in all areas of its operations.

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

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

The exploration and production of oil and natural gas requires high levels of capital expenditures and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil and natural gas fields. The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production interests, the imposition of specific drilling and other work obligations, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. The oil and gas industry is subject to the payment of royalties and income taxes which tend to be higher than those payable in many other commercial activities.

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Exploratory drilling efforts may not be successful

Drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be unsuccessful as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or fires, blow-outs and various forms of accidents, marine risks such as collisions and adverse weather conditions and shortages or delays in the delivery of equipment. Exploring or drilling in offshore areas, particularly in deep waters, is generally more complex and riskier than in onshore areas; the same is true for exploratory activity in remote areas or in challenging environmental conditions such as those we are experiencing in the Caspian region or Alaska. In addition, we may fail to secure a market for the quantities of oil and gas that are discovered, for example because there is no economic or practicable means to transport such quantities to the final market. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and liquidity. Because Eni plans to invest significant capital expenditures in executing high risk exploration projects, it is likely that Eni will incur significant exploration and dry hole expenses in future years. High risk exploration projects include projects executed in deep and ultra-deep offshore and in new areas where the Company lacks installed production facilities. In particularParticularly, Eni plans to explore for oil and gas offshore, frequently in deep waterwaters or at deep drilling depths, where

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operations are more difficult and costly than on land or at shallower depths and in shallower waters. Deep water operations generally require a significant amount of time between a discovery and the time that Eni can produce and market the oil or gas, increasing both the operational and financial risks associated with these activities. In the case of theThe Company plans to conduct risky exploration projects are conductedoffshore in the deep offshore of the Gulf of Mexico, Australia, Brazil, the Barents Sea, India,Libya, Angola, Nigeria, Norway and offshore Ireland.Indonesia. In 2009, managementthe Company invested euro 1.23 billion in executing exploration projects and it plans to spend significant amounts of exploration expenditures in these areas that may result in significant dry hole expenses.approximately euro 1.17 billion per annum on average over the next four years.

Furthermore, shortage of deep water rigs and failure to find additional commercial reserves could reduce future production of oil and natural gas which is highly dependent on the rate of success of exploratory activity.

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

Eni is involved in a number of development projects for the production of hydrocarbon reserves. Certain projects are planned to develop reserves principally offshore.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:

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Furthermore, deep waters and other hostile environments, where the majority of Eni’s planned and existing development projects are located, can exacerbate these problems. Delays and differences between scheduled and actual timing of critical events, as well as cost overruns may adversely affect completion, the total amount of expenditures to be incurred and start upstart-up of production from such projects and, consequently, actual returns. Finally, developing and marketing hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commercial potential, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return for such long-lead-time projects are exposed to the volatility of oil and gas prices which may be substantially lower with respect to prices assumed when the investment decision was actually made, leading to lower rates of return. For example, we have experienced increased budgeted expenditures and a substantial delay in the scheduling of production start upstart-up at the Kashagan field, where development is ongoing. Moreover, in July 2007 these matters triggered a dispute withSpecifically, based on the new plan that was sanctioned by relevant Kazakh authorities. On October 31,Authorities in 2008, all the international partnersCompany increased estimated expenditures to develop the phase 1 of the project andfrom an original amount of U.S. $10.3 billion (Eni’s interest being at the Kazakh authorities agreed upontime 18.52%) – subject to adjustment to take into account cost inflation up to 2007 – to a new contractual and governance framework of the Kashagan project, settling the dispute. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the agreement. In conjunction with the finalization of the agreements, parties also sanctioned the revised expenditure budget of phase-one, amounting to U.S. $32.2 billion (excluding general and administrative expenses), of which U.S. $25.4 billion related to the original scope of work of phase 1 (including tranches 1 and 2), with the remaining part planned to be spent to execute tranche 3 and build certain exporting facilities. First oil is expected late in 2012.. Eni will fund those investments in proportion to its participating interest of 16.81%. TheFirst oil is expected late in 2012 based on the new plan, while the original development plan that was filed with Kazakh Authorities in 2004 forecast expenditures of U.S. $10.3 billion (Eni’s interest being at the time 18.52%) to execute tranches 1&2 (to be adjusted to take into account cost inflation up to 2007) and first oil in 2008. The change in production start-up and the relevant cost increase over the original budget were driven by:by a number of factors including depreciation of the U.S. dollar versus the euro and other currencies; cost price escalation of goods and services required to execute the project; an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; design changes to enhance the operability and safety standards of the offshore facilities. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the Kashagan project.

7In 2009, we experienced significant cost overruns to develop our operated Blacktip project, offshore Australia, leading us to record an impairment charge of euro 153 million to take into account the reduced project profitability.

See "Item 4 – Business Overview – Exploration & Production". IfIn the event the Company is unable to develop and operate major projects as planned, particularly if the Company fails to exercise tight control over costs and time schedules, it may have a materialcould incur significant impairment charges associated with costs overruns and project delays in future years with an adverse effect on our results of operations and liquidity.

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

Eni’s results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. Unless the Company is able to replace produced oil and natural gas, its reserves will decline. TheIn addition to being a function of production and new discoveries, the Company’s reserve replacement is also affected by the entitlement mechanism in its Production Sharing Agreements and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of a field’s reserves, the sale of which shouldis 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 determine year-end amounts ofestimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditures. TheIn 2009, the Company’s reserve replacement was negatively affected by reduced entitlements in its PSAs infor an estimated amount of 100 mmBOE, which was the years 2006 and 2007 when Eni’sprincipal factor leading to a reserve replacement ratio was 38% in both years, meaningof 95% for Eni’s subsidiaries (meaning that the Company replaced less reserves than those produced. Eni’s proved reserves of subsidiaries declined by 6.1% in 2007 and by 5.8% in 2006.produced). See "Item 4 – Business Overview – Exploration & Production". Future oil and gas production is dependent on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiation with countries and other owners of known reserves and acquisitions. An inability to replace reserves could adversely impact future production levels and growth prospects, thus negatively affecting Eni’s future results of operations and financial condition.

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

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

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

The exploration and production of oil and gas is a commodity business with a history of price volatility. The single largest variable that affects the Company’s results of operations and financial condition is crude oil prices. Eni generally does not hedge its exposure to variabilityfluctuations in future cash flows due to crude oil price movements. As a consequence, Eni’s profitability depends heavily on crude oil and natural gas prices.

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

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All these factors can affect the global balance between demand and supply for oil and prices of oil. Such factors can also affect the prices of natural gas because natural gas prices for the major part of our supplies are typically indexed to the prices of crude oil and certain refined petroleum products. Lower crude oil prices have an adverse impact on Eni’s results of operations and cash flowsflow. In 2009, the average price of the Brent barrel decreased by 36.6% compared to 2008 in dollar terms; gas prices experienced an even sharper decline driven by weak spot prices due to large gas availability on the marketplace. Spot prices of gas at the Henry Hub market, which is a highly liquid spot market in the U.S. declined by 55.4% in dollar terms. As a consequence of those trends in the market benchmarks, realized prices of the Company’s equity oil and gas decreased by 31.2% on average in dollar terms. Reduced prices negatively impacted the operating profit reported by the Exploration & Production segment which was down by 43.8%, or euro 7,119 million from operations.a year ago.

Furthermore, lower oil and gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flowsflow 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.

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Uncertainties in Estimates of Oil and Natural Gas Reserves

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

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

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

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

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the tax regimes of any country in which Eni conducts its oil and gas operations, regardless of the level of stability of the political and legislative framework in each country. See "Political considerations" below. In recent years, developments in the regulatory framework, mainly regarding tax issues, have been implemented or announced also in EU countries and in North America. In 2008, Italy enacted new tax rules that increased the statutory tax rate applicable to energy companies with annual turnover in excess of euro 25 million by 5.5 percentage points,5.5%, thus reversing a reduction in the statutory tax rate of the same amount that was enacted the previous year. EarlyIn 2009, the above mentioned 5.5% supplemental tax rate was increased by another percentage point to 6.5% thus bringing the Italian statutory tax-rate to 34%. Also in 2009, the Italian Parliament enacted a supplemental tax rate of 4% that has to be applied to profit before income taxes reported by the parent company Eni SpA associated with the Treatya treaty between Italy and Libya. This supplemental tax rate will entail increased tax payables amounting toby approximately euro 300239 million for the full year 2009.

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

Political Considerations

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

Substantial portions of Eni’s hydrocarbon reserves are located in countries outside the EU and North America, some of which may be politically or economically less stable than EU or North American countries. AtAs of December 31, 2008,2009, approximately 80% of Eni’s proved hydrocarbon reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2007,2009, approximately 70%60% of Eni’s supplies of natural gas came from such countries. See "Item 4 – Gas & Power – Natural Gas Supplies". Adverse political, social and economic developments in any of those countries may affect Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. Particularly Eni faces risks in connection with the following issues: (i) lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights; (ii) unfavorable developments in laws, regulations and contractual arrangements leading for example to expropriations or forced divestitures of assets and unilateral cancellation or modification of contractual terms. For example, in conjunction with the rescheduling of the Kashagan project in 2007, the Kazakh authorities opened a dispute against the international partners of the consortium operating the Kashagan development claiming failure on part of the consortium to fulfill certain contractual obligations. Subsequently, the Kazakh authorities and the international partners of the consortium have agreed on a new contractual framework of the project. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the agreement; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases (including retroactive claims); and (v) civil and social unrest leading to sabotages, acts of violence and incidents. For example, we have been

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

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

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

See "Item 4 – Exploration & Production – Oil and Natural Gas Reserves"; and "Item 5 – Recent Developments". While the occurrence of thesethose events is unpredictable, it is likely that the occurrence of such events could cause Eni to incur material losses or facility disruptions, by this way adversely impacting Eni’s results of operations and cash flows.

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

Eni is currently conducting oil and gas operations in Iran. The legislation and other regulations of the United States of America impose sanctions on this country and may lead to the imposition of sanctions on any persons doing business in this country or with Iranian counterparties.

Under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages thatcontemplates sanctions to be imposed by the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 910 years. Management expectsmay decide to continue investing in Iran yearlyinvest amounts in excess of that threshold$20 million per year in the foreseeablecountry in the future. No sanctions have been imposed to date on Eni’s activities in the country. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buy-back contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on2001. Specifically, activities are progressing to hand over operatorship of the Darquain oilfield to the local partners as development activities were concluded at this field in 2009. Darquain remained the sole activity operated by Eni in the Country. Regarding another project that was handed over in past years, Eni’s involvement consists essentially in being reimbursed for its past investments. In 2009, Eni’s production in Iran was 35 KBOE/d, approximately 2% of the Group’s total production. Eni does not believe that its activities in Iran have a material impact on the country.Group’s results.

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

We are aware of initiatives by certain U.S. states and U.S. institutional investors, such as pension funds, to adopt or consider adopting laws, regulations or policies requiring divestment from, or reporting of interests in, companies that do business with countries designated as states sponsoring terrorism. These policies could adversely impact or limit investment by certain investors in our securities.securities and so possibly impact adversely our share price.

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand in response to economic cycles, with consequential effects on prices and profitability exacerbated by the highly competitive environment of this industry. Eni’s petrochemical operations have been in the past and may be adversely affected in the future by worldwide economic slowdowns, intense competitive pressures and excess installed production capacity. Furthermore, Eni’s petrochemical operations face increasing competition from AsiaticAsian companies and national oil companies’ petrochemical divisions which can leverage on certain long-term competitive advantages in terms of lower operating costs and feedstock purchase costs. In particular,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. In 2008Additionally, 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 postedincurred operating losses in both 2009 and 2008 of euro 822675 million due to sharply higher feed-stock costs inand euro 845 million, respectively. Results were also affected by the first halfrecognition of the year and lower product volumes and margins in the second half due to the current economic downturn and related asset impairments. Impairmentimpairment losses were recorded amounting to euro 121 million and euro 278 million respectively as the recoverable amounts of certain petrochemicals plants were

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lower than their carrying amounts due to deteriorating profitability prospects on the back of lowered expectations for industry fundamentals and unfavorable trends in the trading environment. As

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the downturn is expected to continue for the full year 2009, we doManagement does not projectexpect any significant improvementrecovery in our petrochemicals business profitability.industry fundamentals and the trading environment for 2010, making it likely that further operating losses will be incurred.

LiberalizationRisks in the Company Gas & Power business segment

i) Market risks

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

Legislative Decree No. 164/2000 opened upIn 2009 European gas demand was severely impacted by the economic downturn, as a fall in both producing activities and demand for electricity reduced gas consumption. European gas demand decreased by 7.4% from 2008, excluding seasonal effects. The Italian naturalmarket was particularly hit by the downturn as demand fell by approximately 9 BCM from 2008, down 10%, and almost 10 BCM from the pre-crisis levels seen in 2007, down 12%, excluding seasonal effects. At the same time, new gas supplies entered the market as several operators, including Eni, completed plans to competition asupgrade gas import pipelines from January 1, 2003.gas producing countries or projects to build new facilities to import gas to Europe via LNG carriers. In particular, Eni finalized plans to upgrade the import capacity of its two main pipelines from Russia and Algeria increasing capacity by an overall amount of 13 BCM/y (the gas pipelines TAG and TTPC), with new capacity entirely sold to third parties. A new LNG terminal with a capacity of 8 BCM/y commenced operations late in 2009, operated by a consortium of competitors. As a result, all customers in Italy are free to choose their supplier of natural gas. The decree, among other things, introduced rules which have a significant impactgas availability on Eni’s activity, as the Company is present in all the phases of the natural gas chain:

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

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

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

Since the inceptionoversupply. Accordingly, Eni’s results of the liberalization process in the Italian natural gas market, Eni has been experiencingmarketing business, sales volumes and average gas selling margins¹ were driven down by rising competition and weak demand both in its naturalItaly and Europe. Large gas business leading to lower selling margins due to the entry of new competitors into the market. Certain competitors of Eni are supplied byavailability on other European markets also prevented the Company itself, generally on the basisfrom disposing of long-term contracts. In fact, in order to comply with the above mentioned regulatory thresholds relating to volumes supplied through the national transport network and sales volumes in Italy, Eni sold part of its gas availability underby selling it on European markets. This situation was exacerbated by lower gas consumption in the U.S. driven by the economic downturn and recent developments in extracting gas by unconventional sources. As a result of these trends, large amounts of LNG were re-directed towards Europe. The condition of oversupply on the European market is signaled by the circumstance that gas spot prices no longer appear correlated to trends in oil prices. This trend has resulted in Eni being less competitive as its take-or-pay supply contractscosts are based on the price formulas of long-term supply agreements which link the price of gas to third parties importing said volumesthe price of oil.

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

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

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

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

future years.

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Despite the fact that an increasing portion of natural gas volumes purchased by Eni under its take-or-pay contracts is planned to be marketed outside Italy, management believes that unfavorableCurrent, negative trends in gas demands and supplies may impair the Italian demand and supply for natural gas on both the short and the longer-term, also dueCompany’s ability to the reaching of full operation at new supply infrastructures, and the evolution of Italian regulations of the natural gas sector, represent risk factors to the fulfillment of Eni’sfulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts

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

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

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

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

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

If Eni fails to off-take the contractual minimum amounts, it will be exposed to a price risk, because the purchase price Eni will ultimately be required to pay is based on prices prevailing after the date on which the off-take obligation arose. In addition, Eni is subject to the risk of not being able to dispose of pre-paid volumes. The Company also expects to incur financing costs to pay cash advances corresponding to contractual minimum amounts. As a result, the Company’s selling margins, results of operations and cash flows mightflow may be adverselynegatively affected.

Eni is committed to increasing natural gas sales in Europe. If Eni fails to achieve this target, future growth prospects may be adversely affected. Furthermore, Eni may be unable to fulfill its minimum take obligations under its take-or-pay purchase contracts and this could adversely impact results of operations and liquidity

Over the medium-term, Eni plans to increase its natural gas sales in Europe leveraging on its natural gas availability under take-or-pay purchase contracts it has entered into with major natural gas producing countries (namely Russia, Algeria, Libya, Norway and the Netherlands) and synergies from the acquisition of the Belgian gas operator Distrigas that was completed in 2008.2009. Should Eni fail to increase natural gas sales in Europe as planned due to poor strategy execution or competition, Eni’s future growth prospects, results of operations and cash flows might be adversely affected also taking account that Eni might be unable to fulfill its contractual obligations to purchase certain minimum amounts of natural gas based on its take-or-pay purchase contracts currently in force.

ii) Risks associated with sector-specific regulations in Italy

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

Legislative Decree No. 164/2000 opened the Italian natural gas market to competition, impacting on Eni’s activities, as the company is engaged in all the phases of the natural gas chain. The opening to competition was achieved through the enactment of certain antitrust thresholds on volumes input into the national transport network and on volumes sold to final customers. Specifically, these antitrust thresholds are effective until December 31, 2010 and prescribe that: (i) operators transmit a volume of imported or domestically produced gas into the national

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transport network which shall not be higher than a predetermined share of Italian final consumption. This share was 75% of total final consumption in the first year of regulation, decreasing by 2 percentage points per year to achieve a 61% threshold in terms of final consumption by 2009; and (ii) operators are forbidden from marketing gas volumes to final customers in excess of 50% of overall volumes marketed to final customers. Compliance with these ceilings is verified annually by comparing actual average shares reached by any operator in a given three-year period for both volumes input and volumes marketed to customers to average shares permitted by the law for the same period. Actual shares are computed net of losses (in the case of sales) and volumes of natural gas consumed in own operations. Based on a bill passed by the Italian upper house, Eni expects that these antitrust thresholds will be renewed when they expire in 2010.

These antitrust thresholds enabled new competitors to enter the Italian gas market, resulting in declining selling margins on gas. In addition, certain competitors of Eni are supplied by the Company itself, generally on the basis of long-term contracts. This is a result of the fact that, in order to comply with the above mentioned regulatory thresholds relating to volumes supplied through the national transport network and sales volumes in Italy, Eni sold part of its gas availability under its take-or-pay supply contracts to third parties importing said volumes to Italy and marketing them to Italian customers.

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

The Authority for Electricity and Gas is entrusted with certain powers in the matters of natural gas pricing. Specifically, the Authority for Electricity and Gas holds a general surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users consuming less than 200,000 CM/y (qualified as non eligible customers as of December 31, 2002 as defined by Legislative Decree No. 164/2000) taking into account the public goal of containing the inflationary pressure due to rising energy costs. Accordingly, decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the cost of fuels onto final consumers of natural gas. Following a complex and lengthy administrative procedure started in 2004 and finalized in March 2007 with Resolution No. 79/2007, the Authority finally established a new indexation mechanism for updating the raw material cost component in supplies to residential and commercial users consuming less than 200,000 CM/y, establishing, among other things that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account of the new indexation mechanism of the raw material cost component. This indexation mechanism has been recently updated based on Resolution No. 64/2009 of the Authority, which provides that changes in a preset basket of hydrocarbons are transferred to the cost of the supply to those customers. Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons. The Company does not expect any material impact following enactment of Resolution No. 64/2009.

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

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

OverOther risk factors deriving from the medium-term, Eni has scheduled its import volumesregulatory framework are associated with the regulation of natural gas to Italy based on the assumption to use the purchase flexibility contractually provided by its take-or-pay purchase contracts during periods in which demand is expected to peak. These import programs are also based on the assumption that Eni will obtain the necessary transport capacity entitlements on the Italian transport network. However, Eni’s planning assumptions may be considered to be not fully in line with current rules regulating the access to the Italian gas transport infrastructures as provided fornetwork that is currently set by the Network Code currently in force which has been drafted in accordance with Decision No. 137 of July 17, 137/2002 of the Authority for Electricity and Gas. Such rules establish certainThe decision is fully incorporated into the network code presently in force as prepared by the system’s operator. The

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decision sets priority criteria for transport capacity entitlements at points where the Italian transport infrastructurenetwork connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, Eni’s gas volumes purchased underoperators that are holders of take-or-pay contracts, as in the case of Eni, are entitled to a priority in the allocation ofallocating available transport capacity for amounts not exceedingwithin the limit of average daily contractual volumes. Accordingly, Eni’s purchaseGas volumes exceeding average daily contractual volumes are not entitled to any priority and, in gaining access tocase of congestion at any entry points, they are entitled available capacity on a proportionate basis together with all pending requests for capacity assignments. Under its take-or-pay purchase contracts, Eni has the Italian transport infrastructures. The contractual flexibility represented by Eni’s right to upliftoff-take daily volumes larger than average daily contractual volumes under its take-or-pay purchase contractsvolumes. 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, underbased on current regulationregulations, available transport capacity would be entitled firstly to operators having a priority right, i.e. holders of take-or-pay contracts within the limits of average daily contractual volumes. Then any residual available transport capacity would be allocated in proportion to all pending capacity requests. However, in planning its commercial flows, the Company normally assumes to make full use of its contractual flexibility and to obtain all necessary capacity entitlements at the entry points to the national transport network. Those assumptions may be inconsistent with rules sets by Decision No. 137/2002 specifically with regard to priority criteria governing capacity entitlements. Eni considers Decision No. 137/2002 to be inconsistentillegitimate as it is, in Eni’s view, in contrast with the overall rationale of the European natural gas regulatory framework especially with reference to Directive 98/30/CE (superseded and replaced byon the gas market as provided in European Directive 03/55/CE) and Legislative Decree No. 164/2000, andCE. The Company based on that belief has openedcommenced an administrative procedure to repeal Decision No. 137/2002 before an administrative court.court which recently confirmed in part Eni’s position. An administrative appeals court also confirmed the Company’s position. Specifically, the Court stated that the purchase of the contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted priority in access to the network, also in case congestion occurs. At the moment, however, no case of congestion occurred at entry points to the Italian transport infrastructure such to impairing Eni’s marketing plans. Management cannot predict a final outcome of this proceeding. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power". Eni cannot rule out a negative outcome for this matter. However, management

Management also believes that Eni’s results of operations and cash flows could be adversely affected should a combination of market conditions in light of currentand regulatory constraints prevent Eni from selling its whole availability of natural gas purchased to fulfill its minimum take contract obligations (e.g. in case a congestion occurs at the entry points of the Italian transport infrastructure, Eni would be forced to uplift a smaller volume of gas than the minimum contractual take).obligations. See "Item 5 – Management Expectations of Operations".

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

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

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

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

Italian institutionaladministrative and governmental institutions and political forces are urging a higher degree of competition in the Italian natural gas market and this may produce significant developments in this area. A brief description follows of certain recently enacted laws and certain proceedings before the Authority for Electricity and Gas and the Italian Antitrust Authority in order to allow investors to gain some insight into the complexity of this

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

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

Also in 2003, Law No. 290 was enacted in Italy which prohibits Eni from holding an interest higher than 20% in undertakings owning natural gas transport infrastructure in Italy (Eni currently holds a 50.04%52.54% interest in Snam Rete Gas, which owns and manages approximately 97% of the Italian natural gas transport infrastructure)Gas). A decree is expected to be enacted by the Italian Prime Minister to establish the relevant provisions to implement this mandatory disposal. The deadline for the disposal, which was initially scheduled for December 31, 2008, is to be re-

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

OnIn recent years, both the basis of a joint inquiry conducted from 2003 through June 2004 on the Italian natural gas market, the Authority for Electricity and Gas and the Italian Antitrust Authority (the "Antitrust Authority") concluded thathave conducted several reviews and inquiries on the Italian natural gas market, targeting the overall level of competition of the Italian natural gas market, the degree of opening to competition of the residential sector, levels of entry-exit barriers, and other areas such as sub-investment in the storage sector. Virtually the entire storage capacity belong to Eni through its indirect interest in Stoccaggi Gas Italia SpA, which is unsatisfactory duewolly owned by Snam Rete Gas SpA. In 2009, the Italian Antitrust commenced an inquiry targeting the possible existence of entry barriers in the residential sector and alleged anti-competitive practices on the part of sellers which are integrated in the activity of gas distribution, including Eni and the subsidiary Italgas (which is wolly owned by Snam Rete Gas SpA). See Note 28 to the dominant position held by Eni in many phasesConsolidated Financial Statements for a full description of the natural gas chain. According to bothsuch proceeding. Both the Authority for Electricity and Gas and the Antitrust Authority both believe that the vertical integration of Eni in the supply, transport, distribution, storage and storagemarketing of gas has restrictedmay hamper the development of competition in Italy notwithstanding the antitrust ceilings introduced by Legislative Decree No. 164/2000. It was further stated that the price of natural gas in Italy (in particular for the industrial sector) is higher than in other European countries. In order to implement a Law Decree defined by the Italian Government to face the economic downturn, in March 2009 the Authority for Electricity and Gas proposed certain rules on the Italian gas market designed to increase competition. These rules provide that Eni supplies to the market preset amounts of natural gas at fixed prices. Implementation of these rules could materially and adversely affect the Company’s results of operations and cash flow.

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

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

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

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

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

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

For more information on these issues (particularly the Authority’s Decisions No. 248/2004, 134/2006 and 79/2007) see "Item 4 – Regulation – Gas & Power".

Antitrust and competition law

The Group’s activities are subject to antitrust and competition laws and regulations in many countries of operations, especially in Europe. In the years prior to 2008, Eni recorded significant loss provisions due to unfavorable developments in certain antitrust proceedings before the Italian Antitrust Authority, and the European

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Commission. It is possible that the Group may incur significant loss provisions in future years relative to ongoing antitrust proceedings or possible new proceedings. The Group is particularly exposed to this risk in its natural gas and refining and marketing activities due to its large presencethe fact that Eni is the incumbent operator in thesethose markets in Italy and in Europe.a large European gas player. See Note 2928 to the Consolidated Financial Statements for a full description of Eni’s main pending antitrust proceedings. Particularly, as a result ofOur main antitrust matter relates to an inquiry onongoing proceeding before the level ofEuropean Commission with respect to alleged anti-competitive practices designed to harm competition in the European natural gas market on March 9, 2009 the European Commission sent Eni a Statementin violation of Objections related to a proceeding under Article No. 82 of the EU Treaty and Article No. 54 of the SEE agreement with reference to anSEE. The proceeding involved Eni and other European players. Eni received a statement of objections from the European Commission which alleged unjustifiable refusalthat during the 2000-2005 period Eni was responsible for limiting the access of accessthird parties to the TAG and TENP/Transitgas gas pipelines that are interconnected withTAG, TENP and Transitgas, thus restricting gas availability in Italy. On February 4, 2010, Eni formally submitted the ItalianEuropean Commission a set of structural remedies relating certain international gas transport system through actions intendedpipelines. With prior agreement from its partners, Eni committed to "capacity hoarding, capacity degradation and strategic limitationdispose of investment" with the effect of "hindering the development of a real competitionits interests in the downstream marketGerman TENP, in the Swiss Transitgas and […] harmingin the consumers".Austrian TAG gas pipelines. The European Commission envisagesintends to submit these remedies to a market test. In case the possibleCommission approves those remedies upon conclusion of the market test, Eni will be in the position to settle the matter without imposition of aany fine and of structural remedies. or other remedial measures.

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

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Furthermore, based on the findings of antitrust proceedings, plaintiffs could seek payment to compensate for any alleged damages as a result of antitrust business practices on part of Eni. Both these risks could adversely affect the Group’s future results of operations and cash flows.

Environmental, Health and Safety Regulation

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

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, products and other activities. In particular,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 may also restrictregulate emissions of substances and pollutants, handling of hazardous materials and discharges to surface and subsurface water resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned by Eni. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Breach of environmental, health and safety laws exposes the Company’s employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for environment health or safety damage. Additionally, in the case of violation of certain rules regarding safety in the workplace, the Company can be liable as provided for by a general EU rule on businesses liability due to negligent or willful conduct on part of their employees as adopted in Italy with Law Decree No. 231/2001.

Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures to comply with environmental, health and safety laws and regulations, also taking into account possible future developments in environmental regulations in Italy and in other countries where Eni operates, particularly thecurrent and proposed fuel and product specifications, emission controls and implementation of increasingly strict measures decided at both international and country level to reduce greenhouse gas emissions. For more discussion about this topic see "Item 4 – Environmental regulations".

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

Risks of environmental, health and safety incidences and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management believesmanagement's belief that Eni adopts high operational standards to ensure safety of its operations and to protect the environment and health of people and employees, it is always possible that incidents like blow-outs, spillovers,spill-overs, contaminations and similar events could occur that would result in damage to the environment, employees and communities. In particular,Environmental laws also require the Company to remediate and clean-up the environmental impacts of prior disposals or releases of chemicals or petroleum substances and pollutants by the Company. Such contingent liabilities may exist for various sites that the Company disposed of, closed or shut-down in prior years where the Group products have been produced, processed, stored, distributed or sold, such as chemicals plants, mineral-metallurgic plants, refineries and other facilities. Particularly, Eni is performing a number of remedial actionsplans to restore and clean-up certain industrial sites that were contaminated by the Group’s industrial activities in previous years, mainly in Italy. Management expects further remedialRemedial actions are expected to be implementedcontinue in the foreseeable future, years. Theimpacting our liquidity as the Group has accrued risk provisions to cope with all existing environmental liabilities whereby both a legal or constructive obligation to perform a clean-up or other remedial actions is in place and the associated costs can be reasonably estimated. The accrued amount represents the management’s best estimates of future environmental expenses to be incurred. In 2009, the Company’s environmental provision increased by euro 280 million.

Notwithstanding this, management believes that it is possible that in the future Eni may incur significant environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the chance of as yet

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unknown contamination; (ii) the results of on-going surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated site; (iii) unfavorable

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developments in ongoing litigation on the environmental status of certain Company’s site where a number of public administrations and the Italian Ministry for environment act as plaintiffs; (iv) the possibility that new litigation might arise; and (v) the probability that new and stricter environmental laws might be implemented.implemented; and (vi) the circumstance that the extent and cost of future environmental restoration and remediation programs are often inherently difficult to estimate.

Legal Proceedings

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

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

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

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

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

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

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

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

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

The resultsResults of operations of the Eni’s Refining & Marketing segment are substantially affected by changes in European refining margins which reflect changes in relative prices of crude oil and refined products as outlined above. The prices of refined products in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. Furthermore, Eni’s realized margins are also affected by relative price movements of heavy crude qualities vs. light crude qualities, taking into account the ability of Eni’s refineries to process complex crudes that representrepresents a cost advantage when market prices of heavy crudes are relatively cheaper than the marker Brent price. In 2009, Eni expects thatrefining margins decreased substantially due to the rapid recovery in oil prices which the Company was unable to transfer on to final prices of refined products due to weak demand, for productshigh worldwide and regional inventory levels and excess refining capacity. Also, Eni’s results of operation in its refining segment were affected by narrowing price differentialsdifferential between heavy and light crudes onescrude qualities resulting in poor margins on complex throughputs. Management does not expect any significant recovery in industry fundamentals in 2010. The sector as a whole will negatively affectcontinue to suffer from weak demand and excess capacity, while the performancecost of Eni’soil feedstock is seen rising and price differentials to remain compressed. In this context, management expects that the Company refining operations.margins will remain at below break-even levels.

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

Eni’s margins on petrochemical products are affected by trends in demand for petrochemical products and changes in oil prices which influence changes in purchase costs of petroleum-based feedstock. Given the commoditized nature of Eni petrochemical products, it is difficult for the Company to transfer higher purchase costs for oil-based feedstock to selling prices to customers. In 2008,2009, the profitability of Eni’s petrochemical segment was significantly affected by lower selling margins for commodity petrochemical products due to higherhigh purchase costs for oil-based feedstock that were not fully transferred to selling prices of products, in the first half of the year and, subsequently byas well as weak demand for petrochemical products.and competitive pressures. These negative factors also triggered asset impairments. Management’s outlook for 2009 is also2010 remains challenging, as industry fundamentals are not expected to improve substantially. Weak demand, competition, and management does not expect any significant improvementhigh oil-based feedstock costs will continue to negatively affect Eni’s results of operations and liquidity in the trading environment from 2008 and possibly a further contraction in margins on petrochemical products.this business segment.

Risks from Acquisitions

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

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. Credit risks arise from both commercial partners and financial ones. Although the Group has nevernot experienced in the past material non-performance from its counterparties, due to the severity of the current economic and financial crisis it is possible that we may experience a higher than normal level of counterparty failure. In our consolidated financial statements for the year 2008, we accrued an allowance against doubtful accounts amounting to euro 251 million more than doubling the allowance made a year earlier. In 2009 Consolidated Financial Statements we made a further allowance for doubtful accounts amounting to euro 260 million, mainly relating to the Gas & Power business. Management believes that the Gas & Power business is particularly exposed to the ongoing impacts of the economic and financial crisis due to its large and diversified customer base which include a large number of middle and small businesses and retail customers.

Exchange Rates

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

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products are generally denominated in, or linked to, the euro, whereas expenses in the Petrochemical segment are denominated both in euros and U.S. dollars. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in dollar-denominated expenses. The Exploration & Production segment is particularly affected by movements in the U.S. dollar vs. the euro exchange rates. In 2008, Eni’s operating profit in this business segment has been impacted by an estimated amount of euro 1.2 billion due to a 7.3% depreciation of the U.S. dollar versus the euro. This trend reversed in 2009 resulting in an addition to reported operating profit which was estimated in euro 500 million.

Risks deriving from Eni’s Exposure to Weather Conditions

Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products; in colder years, demand is higher. Accordingly, the results of operations of the Gas & Power segment and, to a lesser extent, the Refining & Marketing segment, as well as the comparability of results over different periods may be affected by such changes in weather conditions.

Furthermore, our operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to our operations and consequent loss or damage of properties and facilities.

Interest Rates

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

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Critical Accounting Estimates

The preparation of financial statements requires management to make certain accounting estimates that are characterized by a high degree of uncertainty, complexity and judgment. These estimates affect the reported amount of the Company’s assets and liabilities, as well as the reported amount of the Company’s income and expenses for a given period. Although management believes these estimates to represent the best outcome of the estimation process, actual results could differ from such estimates, due to, among other things, the following factors: uncertainty, lack or limited availability of information; the availability of new informative elements, variations in economic conditions such as prices, significant factors (e.g. removal technologies and costs) and the final outcome of legal, environmental or regulatory proceedings. See "Item 5 – Critical Accounting Estimates".

Item 4. INFORMATION ON THE COMPANY

History and Development of the Company

Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, electricitypower generation, petrochemicals, oilfield services and engineering industries. Eni has operations in about 7077 countries and 78,88078,417 employees as of December 31, 2008.2009.

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

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

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

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

Internet address: www.eni.it.www.eni.com.

The name of the agent of Eni in the United States is De Luca Vincenzo, 485 Madison Ave.,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 3940 countries, including Italy, the UK, Norway, Libya, Egypt, Norway, the UK, Angola, Nigeria, Congo, the U.S., Kazakhstan, Russia Algeria, Pakistan and Australia. In 2008, Eni’s production of oil and natural gas amounted to 1,7482009, Eni produced 1,716 KBOE/d on an available-for-saleavailable for-sale basis. As of December 31, 2008,2009, Eni’s total proved reserves of subsidiaries stood at 6,2426,209 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 666362 mmBOE. In 2008,2009, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 33,31823,801 million and operating profit of euro 16,4159,120 million.

Eni’s Gas & Power segment engages in supply, transport, distribution, storage, re-gasification and marketing of natural gas, as well as ofelectricity and LNG. This segment also includes the activity of power generation that enables Eniis ancillary to extract further value from gas, diversifying its commercial outlets.the marketing of electricity. In 2008,2009, Eni’s worldwide sales of natural gas amounted to 104.23103.72 BCM, including 6.006.17 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S. Sales in Italy amounted to 52.8740.04 BCM, while sales in European markets were 43.0355.45 BCM that included 11.2510.48 BCM of gas sold to certain importers to Italy. SalesIn 2009, following the reorganization of the regulated businesses the parent company Eni SpA concluded the sale of the entire share capital of its fully-owned subsidiaries Italgas SpA and Stoccaggi Gas Italia SpA to markets outside Europe amounted to 2.33 BCM. Through its 50.0352.54 per cent-owned subsidiary Snam Rete Gas.

Through Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,474-kilometer31,531-kilometer long, while outside Italy Eni holds capacity entitlements on a network of European pipelines extending for approximately 4,400 kilometers made up of high pressure pipelines to import gas from Russia, Algeria, Libya and North Europe production basins to European markets. Eni,Snam Rete Gas, through its 100 percent-owned subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,3201,322 municipalities through a low pressure network consisting of approximately 49,40049,973 kilometers of pipelines as of December 31, 2008.2009. Snam Rete Gas, through its wholly-owned subsidiary Stoccaggi Gas Italia operates in natural gas storage activities in Italy through eight storage fields. Eni produces electricitypower and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of 4.95.3 GW as of December 31, 2008.2009. In 2008,2009, sales of electricitypower totaled 29.9333.96 TWh. Eni operates a re-gasification terminal in Italy and holds indirect interest or capacity entitlements in a number of LNG facilities in

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Europe, Egypt and in certain projects under construction in the U.S. In 2008,2009, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 36,93630,447 million and operating profit of euro 3,9333,687 million.

Eni’s Refining & Marketing segment engages in refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2008,2009, processed volumes of crude oil and other feedstock amounted to 35.8434.55 mmtonnes and sales of refined products were 50.6845.59 mmtonnes, of which 28.9226.68 mmtonnes in Italy. Retail sales of refined product at operated service stations amounted to 12.6712.02 mmtonnes including Italy and the rest of Europe. In 2008,2009, Eni’s retail market share in Italy through its Agip-branded network of service stations was 30.6%31.5%. In 2008,2009, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 45,08331,769 million and operating net loss of euro 1,023102 million.

Eni’s petrochemical activities include production of olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s petrochemical operations are concentrated in Italy and Western Europe. In 2008,2009, Eni sold 4.74.3 mmtonnes of petrochemical products. In 2008,2009, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 6,3034,203 million and an operating net loss of euro 822675 million.

Eni’s oilfield services, construction and engineering activities are conducted through its 42.91 per cent-owned subsidiary Saipem and Saipem’s controlled entities. Activities involve offshore construction, particularly fixed platform installation, sub-sea pipe laying and floating production systems and onshore construction. Offshore and onshore drilling services and engineering and project management services are also provided to the oil and gas, refining and petrochemical industries. In 2008,2009, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 9,1769,664 million and operating profit of euro 1,045881 million.

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

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Strategy

Eni’s strategy is to grow the Company’s main businesses over both the medium and the long-term, with improving profitability. This strategy has remained unchanged in spite of the current2009 economic downturn and an uncertain outlookperspectives for the global energy demand. Specifically, the Company is planning for:

In executing this strategy, management intends to preserve a solid capital structure targeting an optimal mix between net borrowingspursue integration opportunities among businesses and shareholders’ equity. By this means, management expectswithin them and to maintain the Company’s current credit rating.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 48.852.8 billion to support continuing organic growth.growth in its businesses. In 2010, Eni plans to invest approximately euro 14 billion, an amount roughly in line with 2009. Eni plans to fund thisthose capital expenditure program mostlyplans mainly by means of cash flows provided by operating activities. Capital projects will be assessed and implemented in accordance with tight financial criteria. Those will be the levers whereby the Company intends to preserve a solid capital structure targeting an optimal mix between net borrowings and shareholders’ equity. The Company intends to remunerate its shareholders through significanta progressive dividend distributions so aspolicy. In 2010 management plans to ensuredistribute a dividend in line with 2009. In subsequent years, dividends are planned to its shareholders competitivebe increased in line with OECD inflation. This dividend yields (measured aspolicy is based on the ratioCompany’s planning assumptions of dividend to the share price recorded on averageBrent oil prices at $65 per barrel flat in the monthnext four years and other assumptions (see “Item 5 – Management’s Expectations of DecemberOperations” and “Item 3 – Risk Factors”).

Further details on the Italian stock exchange). Management intends to support the Company’s profitability by focusing on cost reduction initiatives, including a number of actions that will be implemented in order to benefit from the expected reduction in purchase costs for oilfield materials, equipment and services in the Exploration and Production segment.each business segment strategy are discussed throughout this item. For a description of risks and uncertainties associated with the Company’s outlook and the capital expenditure program See "Item 5 – Management’s Expectations of Operations".

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

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

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

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

In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.11.4 billion in the next four years to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing ongoing programs focused on reducing costs to find and recover hydrocarbons, developing clean fuels, upgrading heavy crude (in particular the EST project), monetizing natural gas through projects such as high pressure high distance gas transmission (TAP) and Gas to Liquids (GTL), and protecting the environment by investing in the fields of renewable sources of energy and reduction of GHG emissions.

Significant businessBusiness and Portfolio Developments

The significant business and portfolio developments that occurred in 20082009 and to date in 20092010 were the following:

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In addition, in 2008 Eni completed the following transactions:

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Recent developments are described below.

In addition, in 2009 Eni closed the following transactions:

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

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

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

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

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

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

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BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 3940 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the U.S., Kazakhstan, Russia, Algeria, PakistanAustralia, Venezuela and Australia.Iraq. In 2008,2009, Eni produced 1,7481,716 KBOE/d on an available for-sale basis. As of December 31, 2008,2009, Eni’s total proved reserves amounted to 6,571 mmBOE; proved reserves of subsidiaries stood at 6,2426,209 mmBOE; Eni’Eni’s share of reserves of equity-accounted entities amounted to 666362 mmBOE.

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Eni’s strategy in its Exploration & Production operations is to increasepursue profitable production growth leveraging on the Company’s portfolio of assets and pipeline of development of its asset portfolio. Eni plansprojects. We plan to achieve a production growth rate of 3.5%higher than 2.5% on average over the 2009-2012 period, under2010-2013 periods, targeting a production level in excess of 2 mmBOE/d based on our long-term Brent price assumptions of 65 $/BBL and certain other trading environment assumptions (See "Item 5 – Management’s Expectations of Operations"). A descriptionincluding an indication of Eni’s production volume sensitivity to oil prices iswhich are disclosed under "Item 5 – Management’s Expectations of Operations".

Future growth will be driven Management plans to achieve that target via organic developments, leveraging on the Company’s asset portfolio. We plan to achieve 75% of that production level by continuing production ramp-up at our existing fields and 25% by successfully starting to production 41 new fields that based on management estimates are forecast to add up to 560 KBOE/d to the developmentCompany’s production level by 2013. We have already sanctioned half of new projects locatedand expect to sanction a further 40% in a number of strategic oil2010. Management plans to maximize product contribution from existing fields, particularly those with long-life cycles, by applying its advanced recovery technologies, reservoir management capabilities and gas basins in the world, namely the Caspian Region, North and West Africa and the Gulf of Mexico. A high-quality portfolio geographically focused and resilient, with one of the lowest breakeven prices in the industry, high exposureimplementing actions to the most competitive giant projects and long-standing relationships with key host countries will enable any to deliver industry-leading growth even in current market conditions. Management will continue to evaluate opportunities to increase production through focused acquisitions. offset natural field depletion.

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

In exploration activities, Eni intends to concentrate resourcesexpenditures in well established areas of presence where availability of production facilities and existing competenciesknow-how and long-term relationships with host countriescompetencies will enable Enithe Company to readily put in production discovered reserves, reducing the time-to-market and capturing synergies.achieving cost efficiencies. Approximately 80%45% of planned capitalexploration expenditures will be directed to such core areas (located mainly in the United States, Libya, Angola, Nigeria, Norway, Egypt, Libya, Nigeria, Angola, Italy, NorwayCongo and Congo)Indonesia). Eni also plans to selectively pursue high risk/high reward opportunities arising from expansion in areas with high mineral potential.potential and to appraise the resource potential in recently entered areas like Gabon and Ghana. Eni expects to purchase new exploration permits and to divest or exit marginal or non strategic ones.areas.

In order to execute these strategies, Eni intendsManagement plans to invest approximately euro 32.637 billion on reserve developmentto explore for and field optimization as well as exploration projectsdevelop new reserves over the next four-year period;four years; approximately euro 1.80.5 billion of which will be spent to build transportation infrastructures and execute LNG projects through equity-accounted entities.

In 2009, oil and gas prices are expected to be significantly lower than 2008. In response Eni For the year 2010, management plans to improve profitability of its operations by implementing a number of initiatives designed to reduce costs to developspend euro 10.5 billion in reserves development and operate oil and gas fields by leveraging on the expected reduction in purchase costs of oilfield services, materials and equipment due to the economic downturn. Management has yet to commit a large amount of future development expenditures and plans to be able to benefit from ongoing downward trends in rates of oilfield services and purchase costs of goods and equipment. Additional cost control measures will address ongoing operations. The amount of planned capital expenditures for the years 2009-2012 already factors in the benefits associated with cost control. See "Item 3 – Risk Factors".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 natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions.

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

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

Reserves Governance

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

The ReserveReserves Department of the Exploration & Production segmentDivision is entrusted with the task of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines regardingon reserves evaluation. The department monitorsevaluation and classification and the periodic estimation process. Company guidelines follow Regulation S-X Rule 4-10internal procedures; and (iii) providing training of staff involved in the U.S. Securities and Exchange Commission (SEC) as well as on specific issues not regulated by the SEC rules, the established practice endorsed by qualified institutions on the marketplace. process of reserves estimation.

Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has certifiedaffirmed their compliance with applicablethe SEC rules.rules²; D&M has also stated that the Companycompany formal guidelines, regulate situations for which thewhenever SEC rules are less precise, providingdo not provide specific prescription, provide a reasonable interpretation in line with the generally accepted practices in international markets.the industry. When participating in exploration and production activities operated by otherothers entities, Eni also estimates its proved reserves on the basis of the above guidelines.

The process for evaluating reserves, as described in the internal procedure, involves: (i) business unit managersmanager (geographic units) and Local ReserveReserves Evaluators (LRE), who perform the evaluation and classification of reserves including estimates of production profiles, capital expenditures, operating costs and costs related to asset retirement obligations; (ii) geographic area managers at head offices checking evaluationsevaluation carried out by business unit managers; (iii) the Planning and (iii)Control Department which provides the economic evaluation of reserves; and (iv) the Reserve Department which, through Division Reserves Evaluators (DRE), provides independent reviews of the fairness and correctness of classifications carried out by businessthe above mentioned units and aggregates worldwide reserve data and performs an economic assessmentdata.

The head of reserves to calculate equity volumes. Moreover, 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 responsibility to ensureoil and gas industry and more than 10 years of experience specifically in evaluating reserves.

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

Reserves independent evaluation

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluationaudit²³ of its proved reserves on a rotationalrolling basis. Eni believes those independent evaluators to be experienced

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and qualifiedThe description of qualifications of the person primarily responsible for the reserve audit is included in the marketplace.third party audit report⁴. In the preparation of their reports, those independent evaluators relied,rely, without independent verification, upon information furnished by Eni with respect to property interest,interests, production, current costcosts of operationoperations and development, sale agreements, relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators. This information wasdata, equally used by

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Eni in determining its proved reserves and included log,internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir and field, reservoir studies;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, net present value (NPV), actual prices received fromapplicable to hydrocarbon sales, instructions on future prices,price adjustments required by applicable contractual arrangements and other pertinent information are provided. Accordingly, Eni believes that the work performed by theIn 2009, Ryder Scott Co and DeGolyer and MacNaughton provided an independent evaluators is to be considered an evaluation of Eni’s proved reserves carried out in parallel with the internal evaluation. The circumstance that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support management’s confidence that the company’s booked reserves meet the regulatory definition of proved reserves which are reasonably certain to be produced in the future. When the assessment of independent engineers is lower than internal evaluations, Eni revises its estimates based on information provided by independent evaluators. In any case, those differences were not significant.

In 2008, a total of 1.5 BBOE of proved reserves of subsidiaries have been evaluated, representing approximately 25%almost 28% of Eni’s total proved reserves as of subsidiaries at December 31, 2008. 2009⁵, confirming, as in previous years, the reasonableness of Eni’s internal evaluations⁶.

In the 2006-20082007-2009 three-year period, 76%86% of Eni’sEni total proved reserves of subsidiaries were subject to independent evaluations.evaluation. As atof December 31, 20082009 among the most important of Eni’sEni properties, the only property which werewas not subject to an independent evaluation were: Bourireview was Barbara (Italy).

Summary of proved oil and Bu Attifel (Libya), Barbara (Italy), M’Boundi (Congo)gas reserves

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

HYDROCARBONS