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Selected Operating Information

The tabletables below setsset 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, 2001, 2002, 2003, 2004, 2005.2005, 2006 and 2007. Data on proved reserves, production of oil and natural gas and hydrocarbon production sold includes Eni’s share of reserves and 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 tabletables sets 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 ADSsADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADSsADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on June 12, 2006May 14, 2008 was $1.26$1.55 per euro 1.00.

Risk Factors

Competition

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

In the Exploration & Production business, Eni encounters 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 evolutionCompany’s growth prospects, future results of the regulatory framework, which lags behind that of other major European countries.operations and cash flows.

Eni also faces significant competition from certain international operators in the oilfield services, construction and engineering industries. Such competition is primarily on the basis of technical expertise, quality and number of services and availability of technologically advanced facilities (for example vessels for offshore construction).

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 expenditureexpenditures and entails particular economic risks and opportunities.risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil orand natural gas fields. The production of oil and natural gas is highly regulated and is subject to interventionconditions 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 excise duties,income taxes which tend to be higher than those payable in respect of many other commercial activities.

Exploratory drilling efforts may not be successful

Drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be unsuccessful as a result of a variety of factors, including among others, 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 other adverse weather conditions and shortages or delays in the delivery of equipment. Exploring or drilling in offshore areas, in particularparticularly in deep water,waters, is generally more complex and riskier than in onshore areas; sothe same is true for exploratory activity in remote areas or in challenging environmental conditions such as those we are experiencing in the case ofCaspian region or Alaska. Specifically, in the Caspian Region or Alaska.

these complex environmental conditions resulted in higher drilling expenses as discussed under "Item 4 – Exploration & Production – Caspian Area". Failure in the activity of explorationto discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and financial condition.liquidity. Because of the percentage of Eni’sEni plans to invest significant capital plans devoted to higherexpenditures in executing high risk exploratoryexploration projects, it is likely that Eni will continue to experienceincur significant exploration and dry hole expenses. High risk exploration projects include projects executed in deep and ultra-deep offshore and in new areas where the Company lacks installed production facilities. In particular Eni plans to explore for oil and gas offshore, oftenfrequently in deep water or at deep drilling depths, where operations are more difficult and costly than on land or at shallower

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depths and in shallower waters. Deep water operations generally require a significant amount of time between a discovery and the time that Eni can produce and market the oil or gas, increasing both the operational and financial risks associated with these activities. In the case of the Company, risky exploration projects are conducted in the deep offshore of the Gulf of Mexico, Australia, Brazil, the Barents Sea, India, and offshore Ireland. In 2008, management plans to spend significant amounts of exploration expenditures in these areas that may result in significant dry hole expenses.

In addition, lack of necessary equipmentsessential equipment such as a shortage of deep water rigs could further delay operations or increase exploration costs, thus increasing both operational and financial risks.

In addition, Furthermore, failure in findingto find additional commercial reserves could dampenreduce 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 numerousseveral development projects for the production of hydrocarbon reserves, principally offshore. Eni’s future results of operations rely upon its ability to develop and operate major projects as planned. Key factors that may affect the economics of thosethese projects include:

Furthermore, deep waterwaters 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 estimatedscheduled and actual timing of critical events, as well as cost overruns may adversely affect completion, the completiontotal amount of expenditures to be incurred and start-upstart up of production from such projects and, consequently, actual returns. Finally, developing and market hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involving an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commerciality, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return for such long-lead-time projects are exposed to the actual returnsvolatility of oil and gas prices which may be substantially lower with respect to prices assumed when the investment decision was actually made, leading to lower rates of return. For example, we have experienced increased budgeted expenditures and a substantial delay in the scheduling of production start up on such projects.the Kashagan field, where development is ongoing. Moreover, in July 2007 these matters triggered a dispute with the relevant Kazakh authorities. In January 2008, the Kazakh authorities and the partners of the consortium North Caspian Sea Production Sharing Agreement (NCSPSA), which conducts operations at the Kashagan field, reached a settlement of this dispute. The parties have agreed, among others, to the following terms: (i) the proportional dilution of the participating interests of all the international members of the Kashagan consortium, allowing the national Kazakh company KazMunayGas’ stake to increase matching that of the four major shareholders at 16.81%, effective January 1, 2008. The Kazakh partner will pay to the other co-venturers an aggregate amount of U.S. $1.78 billion; (ii) a value transfer package to be implemented through changes to the terms of the NCSPSA, the amount of which will vary in proportion to future levels of oil prices. Eni will contribute to the value transfer package according to its new participating interest in the project. See "Item 4 – Business Overview – Exploration & Production". If the Company is unable to develop and operate major projects as planned, it may have a material adverse effect on our results of operations and liquidity.

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Inability in replacingto replace oil and natural gas reserves could adversely impact results of operations and earningsfinancial condition

Eni’s results of operations and earningsfinancial condition are substantially dependent on ourits ability to develop and sell oil and natural gas. Unless we arethe Company is able to replace produced oil and natural gas, ourits reserves will decline. Eni’s proved reserves of subsidiaries declined by 6.1% in 2007 and by 5.8% in 2006. In addition, Eni’s reserve replacement ratio was 38% in both 2007 and 2006, and 43% in 2005, meaning that the Company replaced less reserves than those produced. These reductions were greatly impacted by lower reserves entitlements in the Company’s Production Sharing Agreements and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of a field’s reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to cover the same amount of expenditures. See "Item 4 – Business Overview – Exploration & Production". Future oil and gas production areis dependent on the company’sCompany’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.operations and financial condition.

Lifting and development costs are increasingtrending up and this could reduce profit per BOE forin the oil industryExploration & Production segment

Profit marginsProfits per BOE in the oil industryExploration & Production segment are being affected by a steady rising trend in lifting and development costs as a result of the following:a number of industry-wide operating factors, including: (i) the increasingly high percentage of complex development projects in our portfolio (such as those in deep and ultra deep waters and in harsh environments) whichenvironments, such as with the Kashagan field). These projects in complex environments bear higher lifting and development costs as compared to development projects located onshore and in traditional environments; (ii) inflationary pressure affectingcontinuing increases in the purchase prices of raw materials and services in connectiondue to the worldwide economic recovery;sector-specific inflation; and (iii) lackan increasingly severe shortage of specialized resources (such as engineers and other valuable technicians) and critical equipment (such as drilling rigs) especially in remote areas.areas, leading to project delays and cost overruns. Eni’s management expects this rising trend ofin lifting and development costs to continue in the medium term and this could lead toforeseeable future, resulting in a reduction incontinuing pressure on our profit margins per BOE.

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

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

Crude oil and natural gas prices are subject to international supply and demand and other factors that are beyond Eni’s control. OPEC member countries control, production ofincluding among other things:

All these factors can affect the worldwideglobal balance between demand and supply offor oil and can exercise substantial influence on its price levels. International geopolitical tensions and political developments, including sanctions imposed on certain oil-producing countries on the basis of resolutions of the United Nations, can also affect world supply 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 tiedindexed to the prices of crude oil and certain crudes and refined petroleum products. Lower crude oil prices could have an adverse impact on Eni’s results of operations and cash flows from operations.

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

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Uncertainties in Estimates of Oil and Natural Gas Reserves

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

Many of these factors, assumptions and variables involved in estimating proved reserves are beyond Eni’s control and may prove to be incorrectchange over time.time and impact the estimates of oil and natural gas reserves. Accordingly, the estimated reserves could be materiallysignificantly different from the quantities of oil and natural gas that ultimately will be recovered. Additionally, any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s results of operations and financial condition.

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

In recent years, Eni has experienced adverse changes in tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. For example, in 2006 changes were enacted in the rate of taxes applicable to profit before taxation for upstream operations in the United Kingdom and in Algeria. As a result, in its 2006 profit and loss account Eni recorded an aggregate expense of euro 526 million for higher taxes payable and adjustments to deferred tax liabilities.

Management believes that adverse changes are always possible in the tax regimes of any country in which Eni conducts its oil and gas operations, regardless of the level of stability of the political and legislative framework in each country. These adverse changes would translate into negative impacts on Eni’s future results leadingof operations and cash flows. Furthermore, the marginal tax rate in the oil and gas industry tends in the long-term to change in correlation with the price of crude oil which could make it difficult for Eni to translate higher oil prices into increased depreciation, depletion and amortization charges and/or impairment charges, which would reduce earnings and shareholders’ equity.
net profit.

Political Considerations

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

Substantial portions of Eni’s hydrocarbon reserves are located in countries outside the EU and North America, some of which may be politically or economically less stable than EU or North American countries. At December 31, 2005,2007, approximately 73%70% of Eni’s proved hydrocarbon reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supply comes from countries outside the EU and North America. In 2005,2007, approximately 60% of Eni’s supplies of natural gas came from such countries. See "Item 4 – Gas & Power – Natural Gas Supplies". Adverse political, social and economic developments in any such producing countryof those countries may affect Eni’s ability to continue operating in that country,an economic way, either temporarily or permanently, and affect Eni’s ability to access oil and gas reserves. In operating in politically unstable countriesParticularly Eni faces risks in connection with the following:following issues: (i) lack of well-established and reliable legal systems;systems and uncertainties surrounding enforcement of contractual rights; (ii) other politicalunfavorable developments in laws, regulations and laws and regulations (such as expropriationcontractual arrangements leading for example to expropriations or forced divestituredivestitures of assets and unilateral cancellation or modification of contract terms), for examplecontractual terms. A case in April 2006,point was the expropriation of Eni’s titles and mineral assets relating to an important oil field were transferred to the Venezuelan state oil companyDación oilfield in Venezuela which occurred in 2006, following itsthe unilateral cancellation of thea service contract regulating oil activities in this field by the field;Venezuelan state oil company. For a discussion on developments for this matter see "Item 4 – Exploration & Production – Venezuela"; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases (including retroactive claims); and (v) civil and social unrest forleading to sabotages, acts of violence and incidents. For example, in the first quarter of 2006 certain episodes of civil2007 we experienced continued social unrest in Nigeria causedleading to a number of disruptions at certain Eni oil producing facilities.facilities in the Country. As a consequence, our oil and gas production in the Country declined by an estimated amount of 25 KBOE/d from the previous year. In the first quarter of 2008, the Company has experienced a slow ramp up of production. See "Item 4 – Exploration & Production – Oil and Natural Gas Reserves"; and "Item 5 – Recent Developments". While the occurrence of these events is unpredictable, it is likely that the occurrence of such events could cause Eni to incur material losses or facility disruptions, by this way adversely impacting Eni’s results of operations and cash flows.

In August 1996,9

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 adoptedof 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 and Libya Sanctions Act (the "Sanctions Act"of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying Iran and Libyait the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction. On April 23, 2004destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States terminated the application of the Sanctions Actis authorized to Libya, with the remaining economic sanctions against Libya lifted on September 23, 2004. The Sanctions Act still applies to Iran and authorizes the President of the United States to imposestart an investigation aiming at possibly imposing sanctions from a six-sanction menu under certain circumstances against any person includingfound in particular to have knowingly made investments of U.S. $20 million or more in any foreign company, making investments in Iran, thustwelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. The Sanctions ActFurthermore, the ISA envisages that the President of the United States is scheduledbound to expireimpose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on August 5,June 6, 2006. Eni does not believe that enforcementcannot predict interpretations of, or the implementation policy of the Sanctions Act againstU.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 8 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buy-back contracts it wouldentered into in 2000 and 2001 and no sanctions have a material adverse effectever been imposed on its financial condition or results of operations. However,Eni’s activities in the country.

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

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

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand, with consequentconsequential effects on prices and profitability exacerbated by the highly competitive environment of thethis industry. Eni’s petrochemicalspetrochemical operations which are located mainly in Italy, have been in the past and may be adversely affected in the future be adversely affected by worldwide economic slowdowns and excess installed production capacity, as well as by economic slowdowns in many industrialized countries. The dislocation ofcapacity. Furthermore, Eni’s petrochemical activities to geographic areas like the Far Eastoperations face increasing competition from Asiatic companies and national oil producing countriescompanies’ petrochemical divisions which providecan leverage on certain long-term competitive advantages has weakened the competitivenessin terms of petrochemicals operations in industrialized countries, includinglower operating costs and feedstock purchase costs. In particular, Eni’s petrochemical operations. Petrochemical operations are located mainly in industrializedItaly and Western Europe where regulatory framework and public environmental sensitivity are generally more stringent than in other countries, are also less competitive than those locatedespecially Far East countries, resulting in higher operating costs of our petrochemical operation compared to the above-mentioned areasCompany’s Asiatic competitors due to stricter regulatory frameworksthe need to comply with applicable laws and growingregulations in environmental concerns which prevail in industrialized countries.
and other related matters.

Liberalization of the Italian Natural Gas Market

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

The new regulatory regime has the effect of limiting the sizeeffects and increasing competition will limit growth prospects and profitability of Eni’sour natural gas business in Italy.Italy as discussed below.

Eni’sEni has been experiencing significant pressure on its natural gas marginmargins¹ since the inception of the liberalization process in Italy may decrease permanently compared to historical levelsItaly. In addition, unfavorable trends in Italian demand and supply of gas could add further pressure

In order to meetSince the expected growthinception of the liberalization process in the Italian natural gas market, over the medium and long-term, Eni entered into long-term purchase contracts with producing countries that currently have a residual average term of approximately 15 years. Existing contracts, whichhas been experiencing rising competition in general contain take-or-pay clauses, will ensure total delivery of approximately 67.3 BCM/y ofits natural gas (Russia 28.5, Algeria 21.5,business leading to lower selling margins due to the Netherlands 9.8, Norway 6 and Nigeria 1.5)entry of new competitors into the market. Certain competitors of Eni are supplied by 2008. The above quantities are basedthe Company itself, generally on the annual contract quantitybasis of the relevant contract. The average annual minimum quantity that Eni is committed to purchase under its take-or-pay obligations is approximately 85% of said quantities.long-term contracts. In fact, in order to comply with the above mentioned regulatory thresholds relating to volumes input intosupplied through the national transport network and sales volumes in Italy, Eni signed multi-yearsold part of its gas availability under its take-or-pay supply contracts withto third party importers inparties importing said volumes to Italy and started implementing a strategy of increasing naturalmarketing them to Italian customers. For more information on Eni’s take-or-pay contracts, see "Item 4 – Gas & Power – Natural gas sales in the rest of Europe in order to sell outside Italy natural gas volumes available under its take-or pay contracts, exceeding mandatory thresholds. In prior years Eni sold the majority of its natural gas availability on the Italian market. This change in the sale mix is structural and is adversely affecting Eni’s results of operations. Further, managementpurchases".

Management expects Eni’s gas selling margins on natural gas in Italy to comeremain under pressure in the foreseeable future years due to the entry into the market of new competitors, including the impact of theconsidering Eni’s gas availability under its take-or-pay supply contracts, build-up of Eni’s supplies to the above mentioned competitors and possibly new competitors entering the Italian importers.market also in light of ongoing or planned capital projects intended 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 16 BCM/y in import capacity reaching full operation in 2009, of which 10 BCM are expected to come online in 2008 (3.3 BCM are already operating; 6.6 BCM are expected to come online by year end). 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, Eni expects a third party’s new LNG terminal with an 8 BCM/y capacity to commence operations by end of 2008.

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 in the long-term unfavorable trends in the Italian demand and supply for natural gas, also due to the possible implementation of all publicly announced plans for the construction of new supply infrastructures, and the evolution of Italian regulations of the natural gas sector, represent risk factors to the fulfillment of Eni’s obligations in connection with its take-or-pay supply contracts and may result in a downward pressure on gas selling margins. Based on the foregoing, Eni’s future results of operations and cash flows might be adversely affected.

EniEni’s growth prospects in Italy are limited by regulation

Due to the antitrust threshold on direct sales in Italy, management expects Eni’s natural gas sales in Italy to increase at a rate that cannotwill not exceed the growth rate of natural gas demand in Italy. Management believes this development might have a material adverse impact on Eni’s results of operations.

Eni is committed to increasing natural gas sales in Europe. If Eni fails to grow natural gas sales in Europe as planned,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 also to absorbleveraging on its natural gas availability under take-or-pay contracts.purchase contracts it has entered into with major natural gas producing countries (namely Russia, Algeria, Libya, Norway and the Netherlands). 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 maymight be unable to sell all the volumesfulfill its contractual obligations to purchase certain minimum amounts of natural gas purchased underbased on its take-or-pay purchase contracts and this could adversely impact results of operations.currently in force.

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

Over the next few years,medium term, Eni plans tohas scheduled its import certain volumes of natural gas usingto Italy based on the highestassumption to use the purchase flexibility ascontractually provided for by its take-or-pay purchase contracts.contracts during periods in which

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demand is expected to peak. These import programs are also based on the assumption that Eni also assumes that it will be entitled toobtain the necessary transport capacity on the Italian transport infrastructure.network. However, EniEni’s planning assumptions are inconsistent with current rules regulating the access to the Italian transport infrastructureinfrastructures as provided for by the Network Code currently in force which has been drafted underin accordance with Decision No. 137 of July 17, 2002 of the Authority for Electricity and Gas. Such rules establishedestablish certain priority criteria for the entitlement to transport capacity of natural gasentitlements at points where the Italian transport infrastructure connects with international transport networksimport pipelines (the so-called entry points to the Italian transport system). In particular current rules establish thatSpecifically, Eni’s gas volumes purchased under take-or-pay contracts entered into before 1998, as in the case of Eni, have the rightare entitled to a priority in the entitlement toallocation of available transport capacity equal tofor amounts not exceeding average daily contractual volumes. There is therefore no guaranteed access priority forAccordingly, Eni’s contractedpurchase volumes exceeding average daily contractual volumes. In fact, take-or-pay contracts entered intovolumes are not entitled to any priority in gaining access to the Italian transport infrastructures. The contractual flexibility represented by Eni before 1998 envisage Eni’s right to offtakeuplift daily volumes larger than the average daily contractual volume; this contractual flexibility provided by the difference between the maximum daily volume Eni is allowed tovolumes under its take-or-pay purchase and the average daily contractual volumecontracts is used when demand peaks, usually during the winter.wintertime. In the event of congestion occurs at entry points natural gas volumes not receiving priority are entitled to the Italian transport network, under current regulation available transport capacity would be entitled firstly to operators having a priority right, i.e. holders of take-or-pay contracts within the limits of average daily contractual volumes. Then any residual available transport capacity would be allocated in proportion with requests from operators.to all pending capacity requests. Eni considers Decision No. 137/2002 to be inconsistent with the overall rationale of the European natural gas legislativeregulatory framework, especially with reference to Directive 98/30/CE (superseded and replaced by Directive 03/55/CE) and Legislative Decree No. 164/2000, and is challenginghas opened an administrative procedure to repeal Decision No. 137/2002 before the competentan administrative courts.court. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power". However, Eni cannot rule out a negative outcome infor this matter. Accordingly,However, management believes that Eni’s results of operations and cash flows could be adversely affected should market conditions and/orin light of current regulatory constraints prevent Eni from selling its whole availability of natural gas purchased to fulfill take-or payits minimum take contract obligations (i.e.,(e.g. in case a congestion occurs at the entry points of the Italian transport infrastructure, whichEni would force Enibe forced to offtakeuplift a smaller volume of gas than the minimum contractual off take). See "Item 5 – Management Expectations of Operations".

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

Eni cannot predict future developmentsItalian institutional and political forces are urging a higher degree of competition in the regulation of the Italian natural gas market. Also an institutional debate is ongoing in Italy regarding the liberalization of the natural gas market and this may produce significant developments onin this matter.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 ofinto the complexity of this matter. For a full discussion of laws and procedures described herein see "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power ".Power".

In 2003, Law No. 290 was enacted which prohibits Eni from holding an interest higher than 20% in undertakings owning natural gas transport infrastructure in Italy (Eni currently holds a 50.07%50.04% interest in Snam Rete Gas, which owns and manages approximately 97% of the Italian natural gas transport infrastructure). A decree is expected to be enacted by the Italian Prime Minister to establish the relevant provisions to implement this mandatory disposal. The deadline for the disposal, which was initially scheduled for December 31, 2008, is to be re-scheduled in a 24-month term starting from the date in which this decree from the Italian Prime Minister becomes effective. Currently, Eni is unable to predict any deadline of this disposal.

On the basis of the findings 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") acknowledgedconcluded that the overall level of competition of the Italian natural gas market is unsatisfactory due to the dominant position held by Eni in many phases of the natural gas chain. According to both the Authority for Electricity and Gas and the Antitrust Authority, the vertical integration of Eni in the supply, transport and storage of gas has restricted the development of competition in Italy notwithstanding the antitrust ceilings introduced by Legislative Decree No. 164/2000. It was further stated that the price of natural gas in Italy (in particular for the industrial sector) is higher than in other European countries.

In October 2005,November 2006, the Authority for Electricity and Gas startedconcluded an inquiry concerning the competitive behavior of operators selling natural gas to residential and commercial customers withcustomers. This inquiry acknowledged that the aimretailing market for natural gas in Italy lacked a sufficient degree of definingcompetition due to current commercial practices and the existence of both entry and exit barriers. The Authority plans to implement measures to improve competition.competition in this market.

In February 2006,November 2007, the Italian Authority for Electricity and Gas and the Italian Antitrust Authority closedopened an inquiry concerning Eni’s competitive behavior concluding that Eni abused its dominant positionto gain insight into the functioning of the natural gas storage activity in Italy, particularly with regard to its decisionlack of investments by operators directed to suspend a plan for the upgrading of the import pipeline from Algeria and to unilaterally cancel certain contracts to sell the relevant transportexpand capacity to third parties. Contracts were signed earlystore natural gas in 2003 andItaly. Eni through its wholly-owned subsidiary Stogit Italia owns almost the relevant upgrade is expected to become effectiveentire storage capacity currently existing in 2007. The Antitrust Authority fined Eni by an amount of euro 290 million.Italy.

On May 5, 2006, the European Commission started an inquiry in order to verify an alleged abuse of dominant position on the part of Eni in violation of Article 82 of the EEC Treaty and Article 54 of the CES Agreement in the activities of international gas transport and wholesale and retail supply of gas.12

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 for management and cannot exclude negative impacts on Eni’s financial condition or results of operations in future years deriving from developments on these matters.

Eni believes an oversupplymatters on Eni’s future results of natural gas is likely to occur in the long-term (beyond 2009)

Eni plans to upgrade its natural gas import infrastructure from Algeriaoperations and Russia to Italy, with expected start-up in 2008 and late 2008/2009, respectively. Taking into account the build-up of supplies of natural gas from Libya through the Greeenstream gasline and of Eni’s fourth long term take-or-pay purchase contract from Russia, an additional import capacity of 883 BCF/y is expected to be available for the Italian natural gas market starting in 2009. A large portion of this expected import capacity has been or is planned to be awarded to third parties. In addition, certain operators in the Italian natural gas market have publicly announced plans to develop LNG terminals in Italy. Eni expects at least one new LNG terminal with a 283 BCF/y capacity to start operations by 2009 thus adding new import capacity to the Italian market. Management believes the pace of demand growth in the Italian natural gas market may not meet the expected increase in supplies of natural gas market starting in 2009 and beyond. If this projections materialize, a decrease in natural gas margins is likely to occur.cash flows.

Decisions of the Authority for Electricity and Gas inon 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 reference selling tariffs in thefor supply of natural gas to residential and commercial segmentsusers taking into account, among other things, the public interest goal of containing the inflationary pressure due to a rise inrising energy costs. The decisions of the Authority for Electricity and Gas on these matters may limit the ability of Eni to pass an increase in the purchase cost of fuelsnatural gas on to the final consumersconsumers. Specifically, upon finalization of a complex lengthy administrative procedure started in 2004 and closed in March 2007, the Authority: (i) set the raw material cost component in supplies to residential users consuming less than 200,000 CM/y for the period from January 1, 2005 to June 30, 2006 – at the same time imposing to Italian natural gas. Ingas importers (including Eni) to renegotiate supply contracts with resellers to residential users in order to take account of the impact of these new amounts; and (ii) confirmed the indexation mechanism for updating the raw material cost component in supplies to above mentioned users in force from July 1, 2006, establishing in particular with Decision No. 248/2004 the Authority for Electricity and Gas established, among other things: (i) that an increase in case the international price of Brent crude oil isdecrease below the 20 dollars per barrel threshold or exceed the 35 dollars per barrel threshold the corresponding variations of the raw material cost are only partially transferred on to residential and commercial users of natural gasgas. Management cannot exclude the possibility that in case international pricesthe future the Authority could implement similar measures that may negatively affect Eni results of Brent crude oil exceedoperations and liquidity. For more information on this issue (particularly the 35 dollars per barrel threshold;Authority’s Decisions No. 248/2004, 134/2006 and (ii) that79/2007) 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 2007, Eni accrued significant provisions amounting to euro 130 million against pending antitrust proceedings before the European Commission. In previous years, Eni also recorded significant loss provisions against antitrust proceedings before the Italian natural gas importers – including Eni – must renegotiate supply contracts to wholesalers in order to take account of the reduction of the price of natural gas sold to residential and commercial users. A proceeding has commenced betweenAntitrust Authority, the Authority for Electricity and Gas and Eni, which appealed Decision No. 248/2004the European Commission. It is possible that the Group may incur significant loss provisions in future years relative to an administrative court.

Eni’s management expects a negative outcome ofongoing antitrust proceedings or possible new proceedings. The Group is particularly exposed to this matter. Eni has accrued a material provisionrisk in its 2005natural gas and refining and marketing activities due to its large presence in these markets in Italy and in Europe. See Note 28 to the Consolidated Financial Statements in orderfor a full description of Eni’s main ongoing antitrust proceedings.

Furthermore, based on the findings of antitrust proceedings, plaintiffs could seek payment to reflectcompensate for any alleged damages as a result of antitrust business practices on part of Eni. Both these risks could adversely affect the risks associated with this matter. In 2006 management expects Eni’sGroup’s future results of operations to be adversely impacted by a material amount in light of the high Brent crude oil prices, in the event Decision 248/2004 is implemented in its original form. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power" and "Item 5 – Financial Review and Prospects".
cash flows.

Environmental, Health and Safety Regulation

Eni may incur material operating costsexpenses and liabilitiesexpenditures in relation to compliance with applicable environmental, regulationshealth and future environmental developmentssafety 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, including legislation that implements international conventions or protocols.activities. In particular, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, as well as refining, petrochemicals and other Group operations, limit or prohibit drilling activities onin 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 pollution resulting from oil, natural gas, refining, petrochemical and petrochemicalother Group’s operations.

These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemicalspetrochemical plants, refineries, pipeline systems and other facilities that Eni owns.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. Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Some riskManagement expects that the Group will continue to incur significant amounts of operating expenses and expenditures to comply with environmental, health and safety laws and regulations, also taking into account possible future developments in environmental regulations in Italy and in other countries where Eni operates, particularly the implementation of increasingly strict measures decided at both international and country level to reduce greenhouse gas emissions.

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

Risks of environmental, costshealth and safety incidences and liabilities isare inherent in certainmany of Eni’s operations and productsproducts. Notwithstanding management’s belief that Eni adopts high standards to ensure safety of its operations, it is always possible that incidents like blow-outs, spillovers, contaminations and similar events could occur that would result in damage to the environment, workers and communities. In particular, Eni and there can be no assurance that material costs and liabilities will not be incurred.

Although management, considering theis performing a number of remedial actions already taken with the insurance policies to cover environmental risks and the provision for risks accrued, does not currently expect any material adverse effect on Eni’s Consolidated Financial Statementsrestore certain industrial sites which were contaminated as a result of its compliancethe Group’s activities in previous years. Management expects other remedial actions to be implemented in future years. The Group has accrued risk provisions to cope with suchall 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 taking into account the probability that new and stricter environmental laws might be implemented and regulations, there are risksthird parties’ claims. Notwithstanding this, management believes that it is possible that in the future Eni may incur significant costsenvironmental expenses and liabilities in future yearsaddition to the amounts already accrued due to: (i) the chance of as yet unknown contamination; (ii) future developments in environmental regulation; (iii) 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; and other possible effects deriving from the implementation of Decree No. 471/1999 of the Ministry of Environment; (iv) the possible effects deriving from the implementation of certain enacted regulations such as the ones deriving from Decree No. 367 of the Ministry of Environment published in January 8, 2004, regarding the fixing of new quality standards for aquatic environment in relation to dangerous substances, and those deriving from the application of European directive 2004/35/EC concerning environmental responsibility for prevention and reclamation of environmental damage; and (v)(iii) the possibility ofthat new litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.
might arise.

Legal Proceedings

Eni is a party to a number of civil actions and administrative proceedings arising in the ordinary course of the business. Although Eni’s management does not currently expect a material adverse effect on Eni’s financial position and results of operations on the basis of information availableIn addition to date and taking account of existing provisions Eni’s management cannot rule outaccrued as of the balance sheet date to account for ongoing proceedings, it is possible that in future years Eni may incur materialsignificant 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) errors in the estimateunderestimation of probable future losses.

Risks deriving from changesrelated to Changes in oil pricesthe Price of Oil, Natural Gas, Refined Products and in natural gas, refined and petrochemical products prices and marginsChemicals

Operating results in certain of Eni’s businesses, particularly the Exploration & Production, Refining & Marketing, Gas & Power and Petrochemical segments are affected by changes in the price of crude oil and by their impactmovements in crude oil prices on prices and margins of natural gas and 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 offor produced oil prices is generally immediate. HoweverFurthermore, Eni’s average realizationrealizations for produced oil differsdiffer from the price of Brent crude marker crude Brentprimarily due primarily to the circumstance that Eni’s production slate, which also includes heavy crudes,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 crudes,crude qualities, hence higher market price).

The favorable impact of higher oil prices on Eni’s results of operations may be offset by the different trends ofin margins infor Eni’s downstream businesses

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

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In the Refining & Marketing and Petrochemical businesses a time lag exists between movements in oil prices and movements in the prices and margins of natural gas and refined and petrochemical products. In particular, trends of natural gas margins in Eni’s natural gas business tend to mitigate the impact of changes in oil prices on Eni’s operating results due to different movements in prices of certain energy parameters to which natural gas purchase and sale prices are contractually indexed in different proportions and as measured over different reference periods.finished products.

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

The results of operations of Eni’s Refining & Marketing segment are substantially affected by changes in European refining margins which reflect changes in relative prices of crude oil and refined products. Generally,products as outlined above. Furthermore, Eni’s realized margins are also affected by relative price movements of heavy crude qualities vs. light crude qualities. In 2007, Eni’s refining margins declined significantly compared to 2006 due to a time lag existsweak trading environment exacerbated by the circumstances that price differentials between changesheavy crudes and light ones narrowed sharply resulting in oil prices and movementsa substantial reduction in refined products prices.the profitability of complex throughputs.

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

Eni’s margins on petrochemical products margins are affected by trends in demand for petrochemical products and changes in oil prices which influence changes in costpurchase costs of petroleum-based feedstock. Generally, an increase in oil price determines a decrease inGiven 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 2007, the profitability of Eni’s petrochemical segment was significantly affected by lower selling margins in the short-term. Prolonged weakness of the European economy as well as Eni’s own structural weaknesses have prevented Eni’s Petrochemical segment from returning to profitability in recent yearsfor commodity petrochemical products due to the inabilityhigher purchase costs for oil-based feedstock that were not fully transferred to transfer increasesselling prices of oil-based feedstocks into selling prices. Due to industry conditionsproducts. Management’s outlook for 2008 is also challenging, and weak economic growth in Europe, management does not expect any significant and durable improvement in Petrochemicals segment profitability over the foreseeable future.
trading environment from 2007 and possibly a further contraction in margins on petrochemical products.

Risks from Acquisitions

Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or corporations in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, in the current high oil price environment, 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.

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 euro.euros. Similarly, prices of Eni’s petrochemical products are generally denominated in, or linked to, the euro, whereas expenses in the PetrochemicalsPetrochemical segment are denominated both in euroeuros and U.S. dollars. Accordingly, a depreciation of the U.S. dollar versusagainst the euro generally has an adverse impact on Eni results of operations.
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 2007, Eni’s operating profit in this business segment declined by an estimated amount of euro 1.4 billion due to a 9.2% depreciation of the U.S. dollar versus the euro. Based on current trends in the U.S. dollar vs. the euro exchange rates, management expects the operating profit of the Exploration & Production segment to be negatively affected in 2008.

Risks deriving from Eni’s Exposure to Weather in Italy and SeasonalityConditions

Significant changes in weather conditions in Italy and in the rest of Europe from year to year may cause variations inaffect 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 variationschanges in weather conditions. In addition, Eni’s results2007, operating profit in the Gas & Power business was negatively affected by unusually mild winter weather resulting in lower gas sales from a year ago.

Furthermore, our operations, particularly offshore production of operations reflect the seasonality in demand foroil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to our operations and certain refined products used in residential space heating, the demand for which is typically highest in the first quarterconsequent loss or damage of the year, which includes the coldest months,properties and lowest in the third quarter, which includes the warmest months.
facilities.

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Interest Rates

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

Critical Accounting Estimates

The preparation of financial statements entailsrequires 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 critical accounting estimates are thoroughly applied and underlying amounts are fairly determined, management cannot rule out thatto represent the best outcome of the estimation process, actual outcomes mayresults could differ from such estimates, due to, among other things, the following factors: uncertainty, lack or limited availability of information; the availability of new informative elements, variations in economic conditions such as prices, significant factors (e.g., removal technologies and costs) and the final outcome of legal, environmental or regulatory proceedings. See "Item 5 – Critical Accounting Estimates".

Item 4. INFORMATION ON THE COMPANY

History and Development of the Company

Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, electricity generation, petrochemicals, oilfield services and engineering industries. Eni has operations in about 70 countries and 72,25875,862 employees as of December 31, 2005.2007.

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

Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821). Eni branches are located in:
• San Donato Milanese (Milan), Via Emilia, 1; and

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

Internet address: www.eni.it.

The name of the agent of Eni in the United States is Viscusi Enzo, 666 Fifth Ave., New York, NY 1010310103.

Eni’s principal segments of operations and subsidiaries are described below.

Eni conducts its exploration and production activities through its Exploration & Production Division and certain operating subsidiaries. Eni’s exploration, development and production activities commenced in 1926, when Agip SpA was established by the Italian Government with a mandate to explore for and develop oil and natural gas. Agip SpA was merged into Eni SpA effective as of January 1, 1997 to become Eni’s Exploration & Production Division.

Eni is engaged in exploration and production of hydrocarbons in Italy, North Africa, West Africa, the North Sea, the Gulf of Mexico, Australia, South America and areas with great development potential such as the Caspian Sea, the Middle and Far East, India and Alaska. In 2005, Eni’s hydrocarbon production available for sale averaged 1,693 KBOE/d and, at December 31, 2005, Eni’s estimated proved reserves totalled 6,837 mmBOE with a life index of 10.8 years. In 2005, Eni’s Exploration & Production segment hadinvolves oil and natural gas exploration and field development and production, as well as LNG operations in 36 countries, including Italy, the UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the U.S., Kazakhstan, Russia and Australia. In 2007, Eni’s production of oil and natural gas amounted to 1,684 KBOE/d on an available-for-sale basis. As of December 31, 2007, Eni’s proved reserves of subsidiaries stood at 6,010 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 668 mmBOE. In 2007, Eni’s Exploration & Production segment reported net sales from operations (including intersegmentinter-segment sales) of euro 22,47727,278 million and operating profit of euro 12,57413,788 million.

Eni conducts its natural gas and electricity generation activities through its Gas & Power Division and certain operating subsidiaries. Eni’s natural gas supply, transmission and distribution activities commenced in the 1940s with the commercial sale of natural gas to industrial users in Northern Italy. Snam SpA was merged into Eni SpA effective as of February 1, 2002 to become Eni’s Gas & Power Division.segment involves supply, transport, distribution and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets. In 2005,2007, Eni’s worldwide sales of natural gas amounted to third parties totalled 52.4798.96 BCM, including 5.39 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S.. Sales in Italy and 23.44amounted to 56.13 BCM, in the rest of Europe; Eni’s share of natural gas volumes sold by its affiliates totalled 8.53 BCM (of which 7.85 billion was sold in the rest of Europe). Natural gas volumes consumed in operations by Eni and Eni’s subsidiaries – mainly in electricity generation, refining and petrochemicals operations – totalled 5.54 BCM. Natural gaswhile sales in Italy include: (i) salesEuropean markets were 35.02 BCM that included 10.67 BCM of gas sold to wholesalers, mainly local companies selling natural gascertain importers to residential and commercial customers, and to large industrial and thermoelectric customers which are supplied by aItaly. Through its 50.04 per cent-owned subsidiary Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipeline network; and (ii) sales to residential and commercial customers which are supplied by a low pressure pipeline network. Eni’s high and medium pressure gas pipeline networkpipelines for natural gas transport that is about 30,700-kilometerapproximately 31,081-kilometer long, in Italy, while outside Italy Eni holds transmission rightscapacity entitlements on a network of European pipelines extending for approximately 5,000 kilometers made up of high pressure pipelines. Eni’s naturalpipelines to import gas transport network in Italy is ownedfrom Russia, Algeria, Libya and managed by Snam Rete Gas SpA. Snam Rete Gas is listed on the Italian Stock Exchange, Eni’s share being 50.07%. Snam Rete Gas transports natural gas on behalf of Eni and third parties ("shippers"); in 2005 its transported volumes were 85.10 BCM, of which 30.22 billion were on behalf of third parties.North Europe production basins to European markets. Eni, through its 100% 100 percent-owned

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subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,2821,318 municipalities through a low pressure network consisting of approximately 48,00048,750 kilometers of pipelines as of December 31, 2005.

2007. Eni conductsproduces electricity and steam at its electricity generation activities through its wholly-owned subsidiary EniPower SpA, which owns and manages Eni’s power stationsoperated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, and Ferrera Erbognone and Ferrara with a total installed capacity of approximately 4.5 gigawatt4.9 GW as of December 31, 2005.2007. In 2005, sold production2007, sales of electricity totalled 22.77 terawatthours.totaled 33.19 TWh. Eni owns other minor power stations locatedoperates a re-gasification terminal in Eni’s petrochemical plantsItaly and refineries whose production is mainly for internal consumption. The accountsholds indirect interest or capacity entitlements in a number of these power stations are reported within Eni’s Refining & MarketingLNG facilities in Europe, Egypt and Petrochemicals segments.

in certain projects under construction in the U.S.. In 2005,2007, Eni’s Gas & Power segment hadreported net sales from operations (including intersegmentinter-segment sales) of euro 22,96927,633 million and operating profit of euro 3,3214,127 million.

Eni conducts its refining and marketing activities through the Refining & Marketing Division and certain operating subsidiaries. Activities commenced in the 1930s, when Eni initiated the development of the industrial and retail markets for refined products in Italy. AgipPetroli SpA was merged into Eni SpA effective December 31, 2002 to become Eni’s Refining & Marketing Division. Eni’ssegment involves refining and marketing activities are located primarilyof petroleum products mainly in Italy and in the rest of Europe. In 2005,2007, processed volumes of crude oil and other feedstock amounted to 37.15 mmtonnes and sales of refined products were 50.15 mmtonnes, of which 28.05 mmtonnes in Italy. Retail sales of refined product at operated service stations amounted to 12.65 mmtonnes including Italy and the rest of Europe. In 2007, Eni’s retailingretail market share for refined products in Italy through its Agip-branded network of service stations was 29.7%29.2%. In 2005, Eni divested its wholly-owned subsidiary Italiana Petroli which is engaged in the retail marketing of refined products through a network consisting primarily of leased service stations, under the IP brand. In 2005, sales of refined products totalled 51.63 million tonnes, of which 30.29 million were in Italy. The balanced refining capacity of Eni’s wholly-owned refineries totalled 524 KBBL/d as of December 31, 2005. In 2005,2007, Eni’s Refining & Marketing segment hadreported net sales from operations (including intersegmentinter-segment sales) of euro 33,73236,401 million and operating profit of euro 1,857729 million.

Eni’s petrochemical activities commenced in the 1950s, when it beganinclude production of basic petrochemicals at its Ravenna industrial complex. Through Polimeri Europa SpA and its subsidiaries, Eni operates in olefins and aromatics, basic intermediate products, chlorine derivatives, polyethylene, polystyrenes, and elastomers. Eni’s petrochemical operations are concentrated in Italy and in Western Europe. In 2005,2007, Eni sold 5.4 million tonnes5.5 mmtonnes of petrochemical products. In 2005,2007, Eni’s PetrochemicalsPetrochemical segment hadreported net sales from operations (including intersegmentinter-segment sales) of euro 6,2556,934 million and an operating profit of euro 20274 million.

Eni’s oilfield services, construction and engineering activities commenced in the late 1950s. Throughare conducted through its 43 per cent-owned subsidiary Saipem SpA (a 43% owned subsidiary) and its subsidiaries, Eni operates inSaipem’s controlled entities. Activities involve offshore construction, in particularparticularly fixed platform installation, subsea pipe laying and floating production systems. Through Snamprogetti SpA (a wholly owned subsidiary)systems and its subsidiaries Eni is a provider ofonshore 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 2005,2007, Eni’s Oilfield Services,Engineering & Construction and Engineering segment hadreported net sales from operations (including intersegmentintragroup sales) of euro 5,7338,678 million and operating profit of euro 307837 million.

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

Strategy

Eni’s strategy is to grow the Company’s main businesses over both the medium and the long-term, with improving profitability. This strategy is designed to create long-term shareholder’s value particularly through significant dividend distributions. Over the next four-years, Eni plans to deployexecute a strategy of organic growth intended to sustain the group’s business over the long-term.

In the Exploration & Production activities, Eni plans to grow production of oil and natural gas through organic growth, targeting a production level of more than 2 mmBOE/d in 2009, which corresponds to a compound average growth rate of approximately 4% under certain trading environment assumptions (See "Item 5 – Management Expectations of Operations"). Eni plans to reach said production target by leveraging in particular on the contribution of recently completed large development projects and projects in the development phase in Angola, Libya, Nigeria, Egypt, Iran, Algeria and Kazakhstan. Management will continue to evaluate opportunities to increase production through the purchase of corporations or individual assets. Eni intends to pay special attention to reserve replacement in order to ensure the medium to long-term sustainability of its business. Eni intends to optimize its portfolio of development properties by focusing on areas where its presence is established, seeking for new opportunities and divesting marginal assets. Eni intends to develop its LNG business also through the purchase of interests in liquefaction plants in order to better exploit its natural gas reserves in North and West Africa. In exploration activities Eni intends to renew its portfolio of properties focusing on such areas where management believes a high mineral potential exists, on assets in areas where its presence is established (in particular Egypt, Nigeria, the United States, Italy and Norway) and to start exploration in newly acquired areas (in particular Alaska, Libya and India).

In the Gas & Power activities, Eni plans to grow natural gas sales in the rest of Europe and to develop its presence in the LNG business in order to compensate for lower growth opportunities on the domestic market due to the limits imposed on operators by the sector regulation and increasingly intense competition. In Italy, Eni plans to comply with regulatory limits on direct sales and input volumes to the national transport network by optimizing allocation of supplies between direct sales in Italy and in the rest of Europe and by using natural gas at its own electricity generation plants and, at the same time, leveraging on the expected consumption growth. In the medium term, management expects its natural gas sales in Italy to decline from the 58 BCM level recorded in 2005 as a consequence of increasing competition from third parties. Eni plans to implement a more attractive commercial offer than Eni’s competitors’ on the basis of the quality of services, pricing formulas including different indexation schemes to suit various customers’ purchasing profile and the integration of supply of gas and electricity. Management plans to grow natural gas sales on European markets by leveraging on the availability of Eni’s equity gas and on a diversified portfolio of supply contracts, an extensive gas pipeline network, which allows for the supply of natural gas from several sources, and long standing relationships with producing countries. Eni intends to strengthen its presence in markets where its presence is already established – such as the Iberian Peninsula, Germany and Turkey – and to develop sales in markets with significant growth and profitability prospects (in particular France and the United Kingdom).

In the Refining & Marketing activities, Eni intends to maximize returns from its existing assets. In the refining activity Eni plans to invest in new primary distillation capacity and in new conversion capacity to make its refining system flexible enough to obtain a higher yield of middle distillates and to achieve a greater vertical integration with its upstream activities. In marketing Eni aims to improve its competitive position in Italy and to increase sales in selected neighboring countries in the Rest of Europe.

Eni’s oilfield services construction and engineering activities play an essential role in contributing to technological innovations and in the implementation of world-scale projects thus supporting Eni’s growth process in the oil & gas business.

In technological research and innovation activities Eni plans to implement a relevant capital expenditure programmeprogram amounting to develop such technologies that management believes may ensure competitive advantages in the long-term and promote sustainableeuro 49.8 billion to support organic growth. Eni plans to continue developing existing programmes on clean fuels, sulphur and greenhouse gas management as well as projects such as the upgrading of heavy crudes (EST), high pressure gas transmission (TAP) and Gas to Liquids (GTL).

In pursuing this strategy Eni plans a capital expenditure programme amounting to euro 35.2 billion over the next four years. Eni plans to financefund this capital expenditure programmeprogram by using themeans of cash flows provided by operating activities. Over the next four year period,four-years, the Company expects to distribute to its shareholders a flowannual amounts of dividends in line with the current level of 2005 under certain assumptionsin real terms (See "Item 8 – Dividends"). Eni aimsplans to allocate cash flowflows provided by operating activities in excess of capital expenditureexpenditures and dividend requirementspayments to continue its programmeprogram of share buy-backrepurchases, while at the same time maintaining a strong balance sheet. See "Item 5 – Management Expectations of Operations".

Eni’s strategy in its Exploration & Production operations is to grow production leveraging on development of assets in its portfolio and the integration of the assets acquired in 2007, including Burren Energy Plc that was acquired in January 2008. Eni plans to achieve a production growth rate of 4.5% on average over the 2008-2011 period, under Eni’s Brent price scenario of 64 U.S. dollar per barrel in 2008, decreasing to 55 U.S. dollar per barrel in 2011 (See "Item 5 – Management Expectations of Operations"). High oil prices represent a risk to the achievement of the Company’s planned production target due to Eni’s exposure to PSAs whereby higher oil prices result in lower production entitlements. On May 14, 2008 Brent price was 121.14 U.S. dollar per barrel. For a description of Eni’s production volume sensitivity to oil prices see "Item 5 – Management Expectations of Operations". Management will continue to evaluate 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. Eni targets worldwide gas sales of 110 BCM in 2011, including E&P sales in the North Sea and the U.S.. In particular, Eni plans to achieve an annual average growth rate of 9% in international sales in the four-year period 2008 to 2011. Eni plans to grow its international sales mainly: (i) in Europe, where Eni expects to expand sales in those markets where its presence is already established – i.e. the Iberian Peninsula, Germany, Turkey, France and the UK – leveraging on the Company’s competitive advantages given by gas availability, access to infrastructures and long-term relationships with the most important producing countries (mainly Russia, Algeria and Libya); and (ii) in the U.S. where Eni plans to grow sales by leveraging on a number of LNG projects that are currently being

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executed. In Italy, Eni plans to implement a marketing plan aiming at preserving the profitability of its Italian operations against an expected increase in competition. Management forecasts sale volumes to remain stable compared to current levels. Eni intends to focus the most profitable customer segments, upgrade the commercial offer by tailoring pricing and services to customers’ specific needs and leverage the full potential of the combined supply of gas and electricity ("dual offer"). A strong focus will be devoted to reducing marketing expenses.

In its Refining & Marketing activities, Eni intends to improve profitability through the following steps. In its refining activities, Eni plans to implement a number of capital projects designed to upgrade its refineries with the aim of: (i) increasing conversion capacity so as to obtain a higher yield of middle distillates; (ii) enhancing flexibility in order to process low-quality crude that is typically discounted in the market-place; and (iii) reducing operating costs. In marketing, Eni intends to strengthen its leadership position in the Italian retail market by improving the quality of the offer through high standards of service, the marketing of premium fuels, tailored promotional initiatives to retain customers and advanced convenience formats. Eni will also continue to develop sales in a number of selected markets in the rest of Europe.

In its Engineering & Construction activities, Eni aims developing and expanding its geographical reach and technical characteristics of its world class fleet, by capturing opportunities arising from a growing market in drilling and oilfield services sectors. In order to achieve this, management plans to leverage on Eni’s strong position in faster growing markets and its consolidating relationships with major companies and National Oil Companies.

In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.7 billion to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing ongoing programs focused on reducing costs to find and recover hydrocarbons, developing clean fuels, upgrading heavy crudes (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.

KeySignificant business and Portfolio Developments

The most significant eventsbusiness and portfolio developments that occurred during 2005in 2007 and to date in 20062008 were the following:

In addition, in 2007 Eni closed the following transactions:

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Recent developments are described below.

In 2007, capital expenditures amounted to euro 10.6 billion, 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.

In 2006, capital expenditures amounted to euro 7.8 billion, of which 89.6% related to the Exploration & Production, Gas & Power and Refining & Marketing segments, and was primarily related to: (i) the development of oil and gas reserves (euro 3,629 million) in particular in Kazakhstan, Angola, Egypt and Italy, exploration projects (euro 1,348 million) particularly in Angola, Egypt, Norway, Nigeria, the Gulf of Mexico and Italy, including the acquisition of 152,000 square kilometers of new acreage (99% operated by Eni); (ii) upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 785 million); (iii) the ongoing construction of combined cycle power plants (euro 229 million); (iv) projects aimed at improving flexibility and yields of refineries (euro 376 million), including the start up of construction of a new hydrocracking unit at the Sannazzaro refinery, and upgrading the refined product distribution network in Italy and in the rest of Europe (euro 223 million); and (v) the construction of a new FPSO unit and upgrading of the fleet and logistic centers in the Engineering & Construction segment (euro 591 million).

In 2005, capital expenditureexpenditures amounted to euro 7.4 billion, of which 91% related to the Exploration & Production, Gas & Power and Refining & Marketing segments, and was primarily related to: (i) the development of oil and gas reserves (euro 3,952 million), in particular in Kazakhstan, Libya, Angola, Italy and Egypt, exploration

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projects (euro 656 million) and the purchase of proved and unproved property (euro 301 million); (ii) upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 825 million); (iii) the continuation of construction of combined cycle power plants (euro 239 million); (iv) actions for improving flexibility and yields of refineries, including the completion of construction of the tar gasification plant at the Sannazzaro refinery, and the upgrade of the refined product distribution network in Italy and in the rest of Europe (overall euro 656 million); and (v) upgrading of vessels and other equipment and facilities in Kazakhstan and West Africa in the Oilfieldoilfield services and construction business (euro 346 million).

In 2005 capital expenditure decreased by euro 85 billion over 2004, or 1.1%, due to a euro 299 billion reduction, or 20.6%, in the Gas

BUSINESS OVERVIEW

Exploration & Power business due principally to the completion of the Greenstream underwater pipeline project and the nearing to completion of the power generation development plan.Production

In 2004, capital expenditure amounted to euro 7.5 billion (of which 94% related to theEni’s Exploration & Production Gas & Powersegment involves oil and Refining & Marketing segments) and concerned: (i) development of hydrocarbon fields (euro 4,369 million) in particular in Libya, Iran, Angola, Italy, Kazakhstan, Egypt, Nigeria and Norway, and exploration (euro 499 million); (ii) upgrading of Eni’s natural gas transmission and distribution network in Italy (euro 721 million); (iii) the construction of the tar gasification plant at the Sannazzaro refinery, actions on refineries for the adjustment of automotive fuel characteristics to new European specifications and the upgrade of the refined product distribution network in Italy and in the rest of Europe (for a total of euro 669 million); and (iv) the continuation of construction of electricity generation plants (euro 451 million) and the completion of the Greenstream underwater pipeline project (euro 159 million).

BUSINESS OVERVIEW

Exploration & Production

Eni operates in the exploration and field development and production, of hydrocarbonsas well as LNG operations, in 36 countries, including Italy, North Africa, West Africa, the North Sea,UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the Gulf of Mexico, AustraliaU.S., Kazakhstan, Russia and South America. It also operates in areas such as the Caspian Sea, the Middle and Far East, India and Alaska where management believes a great mineral potential exists.Australia. In 2005,2007, Eni produced 1,6931,684 KBOE/d; asd on an available-for-sale basis. As of December 31, 2005,2007, Eni’s proved reserves totalled 6,837of subsidiaries stood at 6,010 mmBOE; Eni’ share of reserves of equity-accounted entities amounted to 668 mmBOE.

Eni’s strategy in its Exploration & Production operations is to increase production leveraging on the development of assets in portfolio and the integration of the assets acquired in 2007, including Burren Energy Plc that was acquired in January 2008. Eni plans to grow production of oil and natural through organic growth, targetingachieve a production level of more than 2 mmBOE/d in 2009 which corresponds to a compound average growth rate of approximately 4%4.5% on average over the 2008-2011 period, under certain trading environment assumptions (See "Item 5 – Management Expectations of Operations"). Eni plansHigh oil prices represent a risk factor to reach saidthe achievement of the Company’s planned production target due to Eni’s exposure to PSAs whereby higher oil prices result in lower production entitlements. On May 14, 2008, Brent price was 121.14 U.S. $/BL. A description of Eni’s production volume sensitivity to oil prices is disclosed under "Item 5 – Management Expectations of Operations". Future growth will be driven by leveragingthe development of new projects located mainly in particular onthe key producing basins of North and West Africa and the Caspian region, and the contribution of recently completed great development projectslong-life fields, including Kazakhstan, Libya, Congo, Nigeria and projects in the development phase in Angola, Libya, Nigeria, Egypt, Iran, Algeria and Kazakhstan.Italy. Management will continue to evaluate opportunities to increase production through the purchase of corporations or individual assets. Eni intends to pay special attention to reserve replacement in order to guarantee the medium tomedium-to long-term sustainability of its business. Eni intends to optimize its portfolio of development properties by focusing on areas where its presence is established, seeking for new opportunities and divesting marginal assets. Eni also intends to develop its LNG business also through the purchase of interests in liquefaction plants in order to better exploitmonetize its naturallarge base of gas reserves mainly in North and West Africa.

In exploration activities, Eni intends to renew its portfolioconcentrate resources in well established areas of properties focusing onpresence where availability of production facilities, existing competencies and long-term relationships with host countries will enable Eni to readily put in production discovered reserves, reducing the time-to-market and capturing synergies. Approximately 70% of planned capital expenditures will be directed to such core areas where management believes a high mineral potential exists, assets(located mainly in areas where its presence is already established (in particular Egypt, Nigeria, the United States, Egypt, Libya, Nigeria, Angola, Italy, Norway and Norway)Congo). Eni also plans to selectively pursue high risk/high reward opportunities arising from expansion in areas with high mineral potential. Eni expects to purchase new exploration permits and to start exploration in newly acquired areas (in particular Alaska, Libya and India).divest or exit marginal or non strategic ones.

Eni plans to improve profitability of its performanceoperations by searching forimplementing operating solutions with lower operating costs and exploiting synergies.

In order to execute these strategies, Eni intends to invest approximately euro 25.1 billion on reserve development and field optimization and euro 4.7 billion on exploration projects over the next four-year period. Further euro 3.7 billion will be spent to upgrade natural gas storage sites in Italy and to execute LNG and transport projects through equity-accounted entities.

Oil and Natural Gas Reserves

Eni continues to exercisehas always exercised rigorous control over the booking of proved reserves. The Reserve Department of the Exploration & Production segment, reporting directly to the General Manager, is entrusted with the task of keepingcontinuously updating the Company’s guidelines concerning reserve classification criteria ("criteria") constantly updatedevaluations and of monitoring theirthe periodic process of estimate. The criteriaquantification process. Company guidelines follow Regulation S-X ruleRule 4-10 of the U.S. Securities and Exchange Commission (SEC) as well as, on specific issues not regulated by rules, the consolidated practice recognized by qualified reference institutions. The current criteria applied by EniCompany guidelines have been examinedreviewed by DeGolyer and MacNaughton (D&M), an independent oil engineerspetroleum engineering company, which confirmed that they are complianthas certified their compliance with theapplicable SEC rules. D&M has also stated that the criteriacompany guidelines regulate situations for which the SEC rules are less precise, providing a reasonable interpretation in line with the generally accepted practices in international markets. When participating in exploration and production activities operated by other entities, Eni also estimates its proved reserves on the basis of the mentioned criteria also when it participates in explorationabove guidelines.

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

Beginning inSince 1991, Eni has requested qualified independent petroleumoil engineering companies to carry out an independent evaluation² of its proved reserves on a rotationrotational basis. Eni believes these independent evaluators to be experienced and qualified in the marketplace. In particularthe preparation of their reports, these independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators. This information was used by Eni in 2005determining its proved reserves and included log, directional surveys, core and PVT (Production Volume Temperature) analysis, maps, oil/gas/water monthly production/injection data of wells, reservoir, and field; field studies, reservoir studies; engineers comments relative to field performances, reservoir performances, development programs, work programs etc.; budget data for each field, long range development plans, future capital and operating costs, actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information to calculate NPV for the fields required to undertake an independent evaluation. Accordingly, Eni believes that the work performed by the independent evaluators is to be considered an evaluation of Eni’s proved reserves as opposed to a determination. We also note that the work performed in evaluating our reserves may not be the same work that the independent evaluators perform when evaluating other companies’ reserves. Notwithstanding the above, the fact that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support the management’s confidence that the Company’s booked reserves meet the regulatory definition of proved reserves and are reasonably certain to be produced in the future. Additionally, for those fields where a discrepancy arose, the Company has adopted the reserve estimate indicated by the independent evaluators whenever the latter was lower than the Company’s estimate. In any case, those differences were not significant.

In 2007, a total of 1.641.8 BBOE of proved reserves or about 24%of subsidiaries have been evaluated, representing approximately 30% of Eni’s total proved reserves of subsidiaries at December 31, 2005, have been evaluated. The results of this independent evaluation confirmed Eni’s evaluations, as they did in past years.2007. In the 2003-2005 three year2005-2007 three-year period, independent evaluations concerned 84%64% of Eni’s total proved reserves;reserves of subsidiaries were subject to independent evaluations. As at December 31, 2007 the most important of Eni’s properties which were not subject to an independent evaluation were: Kashagan (Kazakhstan), Bayu Undan (Australia), Cerro Falcone and Monte Alpi-Monte Enoc (Italy). In 2007, Eni’s proved reserves purchased in particular evaluations concerned allRussia have also been evaluated as amounting to 617 mmBOE. These reserves related to the new development projects, including Kashagan, and most large-sized mature fields.acquisition of a 60% interest in three equity-accounted Russian gas companies.

Eni’s proved reserves of oil and natural gassubsidiaries at December 31, 2005 totalled 6,8372007 totaled 6,010 mmBOE (oil and condensates 3,7733,127 mmBBL; natural gas 17,59116,549 BCF) representing a decrease of 381390 mmBOE, or 5.3%6.1%, from December 31, 2004. The reserve replacement ratio was 40% in 2005; the average reserve replacement ratio for the last three years was 89%. The average reserve life index is 10.8 years (12.1 at December 31, 2004). The reserve replacement ratio was calculated dividing additions to proved reserves for year 2005 by total production, each as derived from the tables of changes in proved reserves prepared in accordance with SFAS No. 69 presented in Note 35 to the Consolidated Financial Statements. Management considers the reserve replacement ratio to be a key measure of the ability of the company to sustain its growth prospects. However, the ratio measures past performance and cannot be used to forecast the ability of management to replace produced reserve in future years.

Addition2006. Additions to proved reserves booked by Eni’s subsidiaries in 20052007 were 25381 mmBOE derived from :deriving from: (i) extensions and discoveries (156(201 mmBOE), with major increases booked in particularAngola, Congo, Egypt, Kazakhstan, Tunisia and United States; and (ii) improved recovery (23 mmBOE) mainly in Nigeria, Norway, KazakhstanAlgeria and Algeria; (ii)Angola. These increases were offset in part by a negative balance of 143 mmBOE resulting from downward and upward revisions of previous estimates. Downward revisions of previous estimates (down 98 mmBOE)mainly related to lower entitlementadverse price impacts in certain Production Sharing Agreements (PSAs)³ and buy-back contracts duedetermining volume entitlements in Eni’s PSAs (down 348 mmBOE) resulting from higher year end oil prices (Brent price was $96.02 per barrel at December 31, 2007 compared to higher oil prices$58.925 per barrel at December 31, 2006). These negative revisions were recorded mainly in Kazakhstan, Libya and Angola, and Libya; (iii) improved recovery (89 mmBOE),were partly offset by upward revisions in particularEgypt, Italy, Nigeria and Norway. Acquisitions amounted to 156 mmBOE reflecting a contribution of purchased properties in Algeria, Angolathe Gulf of Mexico and Kazakhstan; and (iv) purchase of proved property (106 mmBOE) in Kazakhstan, Australia, Italy and Angola. The increase offset in part the decline related to production for the year (634 mmBOE).Congo. Due to risks inherent in the exploration and production business, a degree of uncertainty still exists as to whether these additions will actually be produced. See "Item 3 – Risks associated with exploration and production of oil and natural gasgas" and – Uncertainties"Uncertainties in estimates of oil and natural gas reserves.reserves". Proved reserves of Eni’s subsidiaries were determined based on Eni’s working interest of 18.52% in quantifying reserve entitlements of the Kashagan project as of December 31, 2007. As part of the agreements defined with the Kazakh Republic, the change of Eni’s interest to 16.81% in 2008 will determine a decrease of approximately 50 mmBBL in Eni’s estimated net proved reserves of the Kashagan field with respect to December 31, 2007 (information on the Kashagan agreements is provided below under the section "Caspian Area" on page 35).

As of December 31, 2007 Eni’s share of proved reserves of equity-accounted entities amounted to 668 mmBOE. In 2007, proved reserves booked in connection with the acquisition of a 60% interest in three Russian gas companies amounted to 617 mmBOE. Gazprom was granted an option to acquire a 51% interest in those three gas companies. Should Gazprom exercise the call option, Eni’s interest would be diluted to approximately 30% and proved reserves that were booked in connection with the acquisition would be reduced by approximately 50%. Management believes that Gazprom will likely exercise its call option.

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The reserve replacement ratio for Eni’s subsidiaries was 38% in 2007 (38% in 2006 and 43% in 2005). The average reserve life index for Eni’s subsidiaries was 9.6 years at December 31, 2007. The reserve replacement ratio was calculated by dividing additions to proved reserves by total production, each as derived from the tables of changes in proved reserves prepared in accordance with SFAS No. 69 – See supplemental oil and gas information in Note 39 to the Consolidated Financial Statements. The reserve replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by reserve additions booked according with SEC criteria under Rule 4-10 of Regulation S-X. Management considers the reserve replacement ratio to be an important measure of the ability of the Company to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks. Specifically, in recent years Eni’s performance in replacing produced reserves has been affected by the impact of higher year-end oil prices on reserves entitlements in the Company’s Production Sharing Agreements (PSAs) and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of field reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to cover the same amount of expenditures.

The table below show Eni’s calculations of its reserve replacement ratios for the years ended December 31, 2005, 2006 and 2007.