ENI - 20-F annual report

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

		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2009
OR
		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____ to _____
OR
		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report

Commission file number: 1-14090
Eni SpA
(Exact name of Registrant as specified in its charter)
Republic of Italy
(Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei - 00144 Roma - Italy
(Address of principal executive offices)
Alessandro Bernini
Eni SpA
1, piazza Ezio Vanoni
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52041730 - Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
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Securities registered or to be registered pursuant to Section 12(b) of the Act.

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

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

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

CERTAIN DEFINED TERMS

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

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

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

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

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

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

STATEMENTS REGARDING COMPETITIVE POSITION

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

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GLOSSARY

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

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ABBREVIATIONS

CONVERSION TABLE

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PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB). The tables below show Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2005, 2006, 2007, 2008 and 2009. The selected historical financial data presented herein are derived from Eni’s Consolidated Financial Statements included in Item 18.

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

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Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2005, 2006, 2007, 2008 and 2009. Data on production of oil and natural gas and hydrocarbon production sold includes Eni’s share of production of affiliates and joint ventures accounted for under the equity or cost method of accounting.

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Selected Operating Information continued

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Exchange Rates

The following tables set forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board).

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

Risk Factors

Competition

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

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

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

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

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

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Exploratory drilling efforts may not be successful

Drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be unsuccessful as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or fires, blow-outs and various forms of accidents, marine risks such as collisions and adverse weather conditions and shortages or delays in the delivery of equipment. Exploring or drilling in offshore areas, particularly in deep waters, is generally more complex and riskier than in onshore areas; the same is true for exploratory activity in remote areas or in challenging environmental conditions such as those we are experiencing in the Caspian region or Alaska. In addition, we may fail to secure a market for the quantities of oil and gas that are discovered, for example because there is no economic or practicable means to transport such quantities to the final market. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and liquidity. Because Eni plans to invest significant capital expenditures in executing high risk exploration projects, it is likely that Eni will incur significant exploration and dry hole expenses in future years. High risk exploration projects include projects executed in deep and ultra-deep offshore and in new areas where the Company lacks installed production facilities. Particularly, Eni plans to explore for oil and gas offshore, frequently in deep waters or at deep drilling depths, where operations are more difficult and costly than on land or at shallower depths and in shallower waters. Deep water operations generally require a significant amount of time between a discovery and the time that Eni can produce and market the oil or gas, increasing both the operational and financial risks associated with these activities. The Company plans to conduct risky exploration projects offshore in the Gulf of Mexico, Libya, Angola, Nigeria, Norway and Indonesia. In 2009, the Company invested euro 1.23 billion in executing exploration projects and it plans to spend approximately euro 1.17 billion per annum on average over the next four years.

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

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

Eni is involved in a number of development projects for the production of hydrocarbon reserves. Certain projects are planned to develop reserves in high risk areas, particularly offshore and in remote and hostile environments. Eni’s future results of operations and liquidity rely upon its ability to develop and operate major projects as planned. Key factors that may affect the economics of these projects include:

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

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

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

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

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

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

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

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

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

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

Uncertainties in Estimates of Oil and Natural Gas Reserves

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

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

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

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

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the tax regimes of any country in which Eni conducts its oil and gas operations, regardless of the level of stability of the political and legislative framework in each country. See "Political considerations" below. In recent years, developments in the regulatory framework, mainly regarding tax issues, have been implemented or announced also in EU countries and in North America. In 2008, Italy enacted new tax rules that increased the statutory tax rate applicable to energy companies with annual turnover in excess of euro 25 million by 5.5%, thus reversing a reduction in the statutory tax rate of the same amount that was enacted the previous year. In 2009, the above mentioned 5.5% supplemental tax rate was increased by another percentage point to 6.5% thus bringing the Italian statutory tax-rate to 34%. Also in 2009, the Italian Parliament enacted a supplemental tax rate of 4% that has to be applied to profit before income taxes reported by the parent company Eni SpA associated with a treaty between Italy and Libya. This tax rate increased tax payables by approximately euro 239 million for the full year 2009.

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

Political Considerations

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

Substantial portions of Eni’s hydrocarbon reserves are located in countries outside the EU and North America, some of which may be politically or economically less stable than EU or North American countries. As of December 31, 2009, approximately 80% of Eni’s proved hydrocarbon reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2009, approximately 60% of Eni’s supplies of natural gas came from such countries. See "Item 4 – Gas & Power – Natural Gas Supplies". Adverse political, social and economic developments in any of those countries may affect Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. Particularly Eni faces risks in connection with the following issues:

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

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

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

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

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

Under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA contemplates sanctions to be imposed by the President of the United States against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 10 years. Management may decide to invest amounts in excess of $20 million per year in the country in the future. No sanctions have been imposed to date on Eni’s activities in the country. Eni’s current activities in Iran are primarily limited to carrying out residual activities relating to certain buy-back contracts it entered into in 2000 and 2001. Specifically, activities are progressing to hand over operatorship of the Darquain oilfield to the local partners as development activities were concluded at this field in 2009. Darquain remained the sole activity operated by Eni in the Country. Regarding another project that was handed over in past years, Eni’s involvement consists essentially in being reimbursed for its past investments. In 2009, Eni’s production in Iran was 35 KBOE/d, approximately 2% of the Group’s total production. Eni does not believe that its activities in Iran have a material impact on the Group’s results.

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

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

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand in response to economic cycles, with consequential effects on prices and profitability exacerbated by the highly competitive environment of this industry. Eni’s petrochemical operations have been in the past and may be adversely affected in the future by worldwide economic slowdowns, intense competitive pressures and excess installed production capacity. Furthermore, Eni’s petrochemical operations face increasing competition from Asian companies and national oil companies’ petrochemical divisions which can leverage on long-term competitive advantages in terms of lower operating costs and feedstock purchase costs. Particularly, Eni’s petrochemical operations are located mainly in Italy and Western Europe where the regulatory framework and public environmental sensitivity are generally more stringent than in other countries, especially Far East countries, resulting in higher operating costs of our petrochemical operation compared to the Company’s Asiatic competitors due to the need to comply with applicable laws and regulations in environmental and other related matters. Additionally, our petrochemical operations lack sufficient scale and competitiveness in a number of sites. Due to weak industry fundamentals, intense competitive pressures and high feedstock costs, our petrochemicals operations incurred operating losses in both 2009 and 2008 of euro 675 million and euro 845 million, respectively. Results were also affected by the recognition of impairment losses amounting to euro 121 million and euro 278 million respectively as recoverable amounts of certain petrochemicals plants were

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lower than their carrying amounts due to deteriorating profitability prospects on the back of lowered expectations for industry fundamentals and unfavorable trends in the trading environment. Management does not expect any significant recovery in industry fundamentals and the trading environment for 2010, making it likely that further operating losses will be incurred.

Risks in the Company Gas & Power business segment

i) Market risks

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

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

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

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

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

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

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

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

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

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

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

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

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

Over the medium-term, Eni plans to increase its natural gas sales in Europe leveraging on its natural gas availability under take-or-pay purchase contracts it has entered into with major natural gas producing countries (namely Russia, Algeria, Libya, Norway and the Netherlands) and synergies from the acquisition of the Belgian gas operator Distrigas that was completed in 2009. Should Eni fail to increase natural gas sales in Europe as planned due to poor strategy execution or competition, Eni’s future growth prospects, results of operations and cash flows might be adversely affected also taking account that Eni might be unable to fulfill its contractual obligations to purchase certain minimum amounts of natural gas based on its take-or-pay purchase contracts currently in force.

ii) Risks associated with sector-specific regulations in Italy

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Also in 2003, Law No. 290 was enacted in Italy which prohibits Eni from holding an interest higher than 20% in undertakings owning natural gas transport infrastructure in Italy (Eni currently holds a 52.54% interest in Snam Rete Gas). A decree is expected to be enacted by the Italian Prime Minister to establish the relevant provisions to implement this mandatory disposal. The deadline for the disposal, which was initially scheduled for December 31, 2008, is to be re-scheduled in a 24-month deadline following enactment of the decree from the Italian Prime Minister. Currently, Eni is unable to predict a deadline for this disposal.

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

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

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

Antitrust and competition law

The Group’s activities are subject to antitrust and competition laws and regulations in many countries of operations, especially in Europe. In the years prior to 2008, Eni recorded significant loss provisions due to unfavorable developments in certain antitrust proceedings before the Italian Antitrust Authority, and the European Commission. It is possible that the Group may incur significant loss provisions in future years relative to ongoing antitrust proceedings or possible new proceedings. The Group is particularly exposed to this risk in its natural gas and refining and marketing activities due to the fact that Eni is the incumbent operator in those markets in Italy and a large European gas player. See Note 28 to the Consolidated Financial Statements for a full description of Eni’s main pending antitrust proceedings. Our main antitrust matter relates to an ongoing proceeding before the European Commission with respect to alleged anti-competitive practices designed to harm competition in the European gas market in violation of Article No. 82 of the EU Treaty and Article No. 54 of the SEE. The proceeding involved Eni and other European players. Eni received a statement of objections from the European Commission which alleged that during the 2000-2005 period Eni was responsible for limiting the access of third parties to the gas pipelines TAG, TENP and Transitgas, thus restricting gas availability in Italy. On February 4, 2010, Eni formally submitted the European Commission a set of structural remedies relating certain international gas pipelines. With prior agreement from its partners, Eni committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines. The European Commission intends to submit these remedies to a market test. In case the Commission approves those remedies upon conclusion of the market test, Eni will be in the position to settle the matter without imposition of any fine or other remedial measures.

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

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

Environmental, Health and Safety Regulation

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

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

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

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

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

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

Notwithstanding this, management believes that it is possible that in the future Eni may incur significant environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the chance of as yet unknown contamination; (ii) the results of on-going surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated site; (iii) unfavorable

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

Legal Proceedings

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

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

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

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

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

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

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

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

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

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

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

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

Risks from Acquisitions

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

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. Credit risks arise from both commercial partners and financial ones. Although the Group has not experienced in the past material non-performance from its counterparties, due to the severity of the current economic and financial crisis it is possible that we may experience a higher than normal level of counterparty failure. In our consolidated financial statements for the year 2008, we accrued an allowance against doubtful accounts amounting to euro 251 million more than doubling the allowance made a year earlier. In 2009 Consolidated Financial Statements we made a further allowance for doubtful accounts amounting to euro 260 million, mainly relating to the Gas & Power business. Management believes that the Gas & Power business is particularly exposed to the ongoing impacts of the economic and financial crisis due to its large and diversified customer base which include a large number of middle and small businesses and retail customers.

Exchange Rates

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

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

Risks deriving from Eni’s Exposure to Weather Conditions

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

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

Interest Rates

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

Critical Accounting Estimates

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

Item 4. INFORMATION ON THE COMPANY

History and Development of the Company

Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, power generation, petrochemicals, oilfield services and engineering industries. Eni has operations in 77 countries and 78,417 employees as of December 31, 2009.

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

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

• San Donato Milanese (Milan), Via Emilia, 1; and
• San Donato Milanese (Milan), Piazza Ezio Vanoni, 1.

Internet address: www.eni.com.

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

Eni’s principal segments of operations are described below.

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

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

Through Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,531-kilometer long, while outside Italy Eni holds capacity entitlements on a network of European pipelines extending for approximately 4,400 kilometers made up of high pressure pipelines to import gas from Russia, Algeria, Libya and North Europe production basins to European markets. Snam Rete Gas, through its 100 percent-owned subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,322 municipalities through a low pressure network consisting of approximately 49,973 kilometers of pipelines as of December 31, 2009. Snam Rete Gas, through its wholly-owned subsidiary Stoccaggi Gas Italia operates in natural gas storage activities in Italy through eight storage fields. Eni produces power and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of 5.3 GW as of December 31, 2009. In 2009, sales of power totaled 33.96 TWh. Eni operates a re-gasification terminal in Italy and holds indirect interest or capacity entitlements in a number of LNG facilities in Europe, Egypt and in certain projects under construction in the U.S. In 2009, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 30,447 million and operating profit of euro 3,687 million.

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

Eni’s petrochemical activities include production of olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s petrochemical operations are concentrated in Italy and Western Europe. In 2009, Eni sold 4.3 mmtonnes of petrochemical products. In 2009, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 4,203 million and an operating net loss of euro 675 million.

Eni’s oilfield services, construction and engineering activities are conducted through its 42.91 per cent-owned subsidiary Saipem and Saipem’s controlled entities. Activities involve offshore construction, particularly fixed platform installation, sub-sea pipe laying and floating production systems and onshore construction. Offshore and onshore drilling services and engineering and project management services are also provided to the oil and gas, refining and petrochemical industries. In 2009, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 9,664 million and operating profit of euro 881 million.

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

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Strategy

Eni’s strategy is to grow the Company’s main businesses over both the medium and the long-term, with improving profitability. This strategy has remained unchanged in spite of the 2009 economic downturn and uncertain perspectives for global energy demand. Specifically, the Company is planning for:

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

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

In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.4 billion to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing ongoing programs focused on reducing costs to find and recover hydrocarbons, developing clean fuels, upgrading heavy crude (in particular the EST project), monetizing natural gas through projects such as high pressure high distance gas transmission (TAP) and Gas to Liquids (GTL), and protecting the environment by investing in the fields of renewable sources of energy and reduction of GHG emissions.

Significant Business and Portfolio Developments

The significant business and portfolio developments that occurred in 2009 and to date in 2010 were the following:

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In addition, in 2009 Eni closed the following transactions:

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

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

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

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

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

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

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BUSINESS OVERVIEW

Exploration & Production

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

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

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

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

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

Disclosure of Reserves

Overview

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

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

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

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

Reserves Governance

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

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

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

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

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

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

Reserves independent evaluation

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent audit³of its proved reserves on a rolling basis. The description of qualifications of the person primarily responsible for the reserve audit is included in the third party audit report⁴. In the preparation of their reports, those independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interests, production, current costs of operations and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. This data, equally used by

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

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

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

Summary of proved oil and gas reserves

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

HYDROCARBONS

LIQUIDS

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NATURAL GAS

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

Activity of the year

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

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

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

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

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

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

The reserve replacement ratio for Eni’s subsidiaries was 95% in 2009 (136% in 2008 and 38% in 2007). The reserve replacement ratio was calculated by dividing additions to proved reserves by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities - Oil & Gas (Topic 932) (see the supplemental oil and gas information in the Consolidated Financial Statements). The reserve replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by reserve additions booked. Management considers the reserve replacement ratio to be an important indicator of the Company to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks. Specifically, in recent years Eni’s reserves replacement ratio has been affected by the impact of higher year-end oil prices on reserves entitlements in the Company’s Production Sharing Agreements (PSAs) and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of field reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to cover the same amount of expenditures. In 2009 this trend resulted in a lower amount of booked reserves associated with the Company’s PSAs as the oil price was averaged higher than the previous year. See "Item 3 – Risks associated with exploration and production of oil and natural gas" and – "Uncertainties in estimates of oil and natural gas reserves".

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

Proved undeveloped reserves

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

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

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

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

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

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

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

Delivery commitments

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

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

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

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

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

Oil and gas production, production prices and production costs

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

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

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

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

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

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

LIQUIDS PRODUCTION ⁽¹⁾

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

Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 97 KBOE/d, 93 KBOE/d and 75 KBOE/d in 2009, 2008 and 2007, respectively.

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

AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT

 

Drilling and other exploratory and development activities

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

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

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

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

NET EXPLORATION AND DEVELOPMENT DRILLING ACTIVITY

 

Present activities

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

DRILLING ACTIVITY IN PROGRESS

Oil and gas properties, operations and acreage

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

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

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

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