Item 4. INFORMATION ON THE COMPANY

History and Development of the Company

Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, electricity generation, petrochemicals, oilfield services and engineering industries. Eni has operations in about 70 countries and 75,862 employees as of December 31, 2007.

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

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

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

Internet address: www.eni.it.

The name of the agent of Eni in the United States is Viscusi Enzo, 666 Fifth Ave., New York, NY 10103.

Eni’s principal segments of operations are described below.

Eni’s Exploration & Production segment involves oil and natural gas exploration and field development and production, as well as LNG operations in 36 countries, including Italy, the UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the U.S., Kazakhstan, Russia and Australia. In 2007, Eni’s production of oil and natural gas amounted to 1,684 KBOE/d on an available-for-sale basis. As of December 31, 2007, Eni’s proved reserves of subsidiaries stood at 6,010 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 668 mmBOE. In 2007, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 27,278 million and operating profit of euro 13,788 million.

Eni’s Gas & Power segment involves supply, transport, distribution and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets. In 2007, Eni’s worldwide sales of natural gas amounted to 98.96 BCM, including 5.39 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S.. Sales in Italy amounted to 56.13 BCM, while sales in European markets were 35.02 BCM that included 10.67 BCM of gas sold to certain importers to Italy. Through its 50.04 per cent-owned subsidiary Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,081-kilometer long, while outside Italy Eni holds capacity entitlements on a network of European pipelines extending for approximately 5,000 kilometers made up of high pressure pipelines to import gas from Russia, Algeria, Libya and North Europe production basins to European markets. Eni, through its 100 percent-owned

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subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,318 municipalities through a low pressure network consisting of approximately 48,750 kilometers of pipelines as of December 31, 2007. Eni produces electricity and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of approximately 4.9 GW as of December 31, 2007. In 2007, sales of electricity totaled 33.19 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 2007, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 27,633 million and operating profit of euro 4,127 million.

Eni’s Refining & Marketing segment involves refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2007, processed volumes of crude oil and other feedstock amounted to 37.15 mmtonnes and sales of refined products were 50.15 mmtonnes, of which 28.05 mmtonnes in Italy. Retail sales of refined product at operated service stations amounted to 12.65 mmtonnes including Italy and the rest of Europe. In 2007, Eni’s retail market share in Italy through its Agip-branded network of service stations was 29.2%. In 2007, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 36,401 million and operating profit of euro 729 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 2007, Eni sold 5.5 mmtonnes of petrochemical products. In 2007, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 6,934 million and an operating profit of euro 74 million.

Eni’s oilfield services, construction and engineering activities are conducted through its 43 per cent-owned subsidiary Saipem and Saipem’s controlled entities. Activities involve offshore construction, particularly fixed platform installation, subsea 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 2007, Eni’s Engineering & Construction segment reported net sales from operations (including intragroup sales) of euro 8,678 million and operating profit of euro 837 million.

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

Strategy

Eni’s strategy is to grow the Company’s main businesses over both the medium and the long-term, with improving profitability. This strategy is designed to create long-term shareholder’s value particularly through significant dividend distributions. Over the next four-years, Eni plans to execute a capital expenditure program amounting to euro 49.8 billion to support organic growth. Eni plans to fund this capital expenditure program by means of cash flows provided by operating activities. Over the next four-years, the Company expects to distribute to its shareholders annual amounts of dividends in line with the current level in real terms (See "Item 8 – Dividends"). Eni plans to allocate cash flows provided by operating activities in excess of capital expenditures and dividend payments to continue its program of share repurchases, while at the same time maintaining a strong balance sheet. See "Item 5 – Management Expectations of Operations".

Eni’s strategy in its Exploration & Production operations is to grow production leveraging on development of assets in its portfolio and the integration of the assets acquired in 2007, including Burren Energy Plc that was acquired in January 2008. Eni plans to achieve a production growth rate of 4.5% on average over the 2008-2011 period, under Eni’s Brent price scenario of 64 U.S. dollar per barrel in 2008, decreasing to 55 U.S. dollar per barrel in 2011 (See "Item 5 – Management Expectations of Operations"). High oil prices represent a risk to the achievement of the Company’s planned production target due to Eni’s exposure to PSAs whereby higher oil prices result in lower production entitlements. On May 14, 2008 Brent price was 121.14 U.S. dollar per barrel. For a description of Eni’s production volume sensitivity to oil prices see "Item 5 – Management Expectations of Operations". Management will continue to evaluate opportunities to increase production through acquisitions. Eni intends to pay special attention to reserve replacement in order to secure the medium to long-term sustainability of its business.

In its Gas & Power activities, Eni intends to grow natural gas sales in the international market, preserve the profitability of the Italian marketing business, effectively manage regulated businesses, and develop a global LNG business. Eni targets worldwide gas sales of 110 BCM in 2011, including E&P sales in the North Sea and the U.S.. In particular, Eni plans to achieve an annual average growth rate of 9% in international sales in the four-year period 2008 to 2011. Eni plans to grow its international sales mainly: (i) in Europe, where Eni expects to expand sales in those markets where its presence is already established – i.e. the Iberian Peninsula, Germany, Turkey, France and the UK – leveraging on the Company’s competitive advantages given by gas availability, access to infrastructures and long-term relationships with the most important producing countries (mainly Russia, Algeria and Libya); and (ii) in the U.S. where Eni plans to grow sales by leveraging on a number of LNG projects that are currently being

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

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

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

In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.7 billion to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing ongoing programs focused on reducing costs to find and recover hydrocarbons, developing clean fuels, upgrading heavy crudes (in particular the EST project), monetizing natural gas through projects such as high pressure high distance gas transmission (TAP) and Gas to Liquids (GTL), and protecting the environment by investing in the fields of renewable sources of energy and reduction of GHG emissions.

Significant business and Portfolio Developments

The significant business and portfolio developments that occurred in 2007 and to date in 2008 were the following:

In addition, in 2007 Eni closed the following transactions:

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Recent developments are described below.

In 2007, capital expenditures amounted to euro 10.6 billion, of which 84.7% related to the Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 4,788 million) deployed predominantly in Kazakhstan, Egypt, Angola, Italy and Congo, and exploration projects (euro 1,659 million) particularly in the Gulf of Mexico, Egypt, Norway, Nigeria and Brazil; (ii) development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 886 million) as well as upgrading of natural gas import pipelines to Italy (euro 253 million); (iii) the ongoing construction of combined cycle power plants (euro 175 million); (iv) projects designed to upgrade the conversion capacity and flexibility of Eni’s refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, and to build and upgrade service stations (totaling euro 979 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,410 million).

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

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

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

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

BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment involves oil and natural gas exploration and field development and production, as well as LNG operations, in 36 countries, including Italy, the UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the U.S., Kazakhstan, Russia and Australia. In 2007, Eni produced 1,684 KBOE/d on an available-for-sale basis. As of December 31, 2007, Eni’s proved reserves of subsidiaries stood at 6,010 mmBOE; Eni’ share of reserves of equity-accounted entities amounted to 668 mmBOE.

Eni’s strategy in its Exploration & Production operations is to increase production leveraging on the development of assets in portfolio and the integration of the assets acquired in 2007, including Burren Energy Plc that was acquired in January 2008. Eni plans to achieve a production growth rate of 4.5% on average over the 2008-2011 period, under certain trading environment assumptions (See "Item 5 – Management Expectations of Operations"). High oil prices represent a risk factor to the achievement of the Company’s planned production target due to Eni’s exposure to PSAs whereby higher oil prices result in lower production entitlements. On May 14, 2008, Brent price was 121.14 U.S. $/BL. A description of Eni’s production volume sensitivity to oil prices is disclosed under "Item 5 – Management Expectations of Operations". Future growth will be driven by the development of new projects located mainly in the key producing basins of North and West Africa and the Caspian region, and the contribution of long-life fields, including Kazakhstan, Libya, Congo, Nigeria and Italy. Management will continue to evaluate opportunities to increase production through the purchase of corporations or individual assets. Eni intends to pay special attention to reserve replacement in order to guarantee the medium-to long-term sustainability of its business. Eni intends to optimize its portfolio of development properties by focusing on areas where its presence is established, seeking new opportunities and divesting marginal assets. Eni also intends to develop its LNG business in order to monetize its large base of gas reserves mainly in North and West Africa.

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

Eni plans to improve profitability of its operations by implementing operating solutions with lower operating costs and exploiting synergies.

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

Oil and Natural Gas Reserves

Eni has always exercised rigorous control over the booking of proved reserves. The Reserve Department of the Exploration & Production segment, reporting directly to the General Manager, is entrusted with the task of continuously updating the Company’s guidelines concerning reserve evaluations and monitoring the periodic quantification process. Company guidelines follow Regulation S-X Rule 4-10 of the U.S. Securities and Exchange Commission (SEC) as well as, on specific issues not regulated by rules, the consolidated practice recognized by qualified reference institutions. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has certified their compliance with applicable SEC rules. D&M has also stated that the company guidelines regulate situations for which the SEC rules are less precise, providing a reasonable interpretation in line with the generally accepted practices in international markets. When participating in exploration and production activities operated by other entities, Eni also estimates its proved reserves on the basis of the above guidelines.

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

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation ² of its proved reserves on a rotational basis. Eni believes these independent evaluators to be experienced and qualified in the marketplace. In the preparation of their reports, these independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators. This information was used by Eni in determining its proved reserves and included log, directional surveys, core and PVT (Production Volume Temperature) analysis, maps, oil/gas/water monthly production/injection data of wells, reservoir, and field; field studies, reservoir studies; engineers comments relative to field performances, reservoir performances, development programs, work programs etc.; budget data for each field, long range development plans, future capital and operating costs, actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information to calculate NPV for the fields required to undertake an independent evaluation. Accordingly, Eni believes that the work performed by the independent evaluators is to be considered an evaluation of Eni’s proved reserves as opposed to a determination. We also note that the work performed in evaluating our reserves may not be the same work that the independent evaluators perform when evaluating other companies’ reserves. Notwithstanding the above, the fact that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support the management’s confidence that the Company’s booked reserves meet the regulatory definition of proved reserves and are reasonably certain to be produced in the future. Additionally, for those fields where a discrepancy arose, the Company has adopted the reserve estimate indicated by the independent evaluators whenever the latter was lower than the Company’s estimate. In any case, those differences were not significant.

In 2007, a total of 1.8 BBOE of proved reserves of subsidiaries have been evaluated, representing approximately 30% of Eni’s total proved reserves of subsidiaries at December 31, 2007. In the 2005-2007 three-year period, 64% of Eni’s total proved reserves of subsidiaries were subject to independent evaluations. As at December 31, 2007 the most important of Eni’s properties which were not subject to an independent evaluation were: Kashagan (Kazakhstan), Bayu Undan (Australia), Cerro Falcone and Monte Alpi-Monte Enoc (Italy). In 2007, Eni’s proved reserves purchased in Russia have also been evaluated as amounting to 617 mmBOE. These reserves related to the acquisition of a 60% interest in three equity-accounted Russian gas companies.

Eni’s proved reserves of subsidiaries at December 31, 2007 totaled 6,010 mmBOE (oil and condensates 3,127 mmBBL; natural gas 16,549 BCF) representing a decrease of 390 mmBOE, or 6.1%, from December 31, 2006. Additions to proved reserves booked by Eni’s subsidiaries in 2007 were 81 mmBOE deriving from: (i) extensions and discoveries (201 mmBOE), with major increases booked in Angola, Congo, Egypt, Kazakhstan, Tunisia and United States; and (ii) improved recovery (23 mmBOE) mainly in Algeria and Angola. These increases were offset in part by a negative balance of 143 mmBOE resulting from downward and upward revisions of previous estimates. Downward revisions of previous estimates mainly related to adverse price impacts in determining volume entitlements in Eni’s PSAs (down 348 mmBOE) resulting from higher year end oil prices (Brent price was $96.02 per barrel at December 31, 2007 compared to $58.925 per barrel at December 31, 2006). These negative revisions were recorded mainly in Kazakhstan, Libya and Angola, and were partly offset by upward revisions in Egypt, Italy, Nigeria and Norway. Acquisitions amounted to 156 mmBOE reflecting a contribution of purchased properties in the Gulf of Mexico and Congo. Due to risks inherent in the exploration and production business, a degree of uncertainty still exists as to whether these additions will actually be produced. See "Item 3 – Risks associated with exploration and production of oil and natural gas" and – "Uncertainties in estimates of oil and natural gas reserves". Proved reserves of Eni’s subsidiaries were determined based on Eni’s working interest of 18.52% in quantifying reserve entitlements of the Kashagan project as of December 31, 2007. As part of the agreements defined with the Kazakh Republic, the change of Eni’s interest to 16.81% in 2008 will determine a decrease of approximately 50 mmBBL in Eni’s estimated net proved reserves of the Kashagan field with respect to December 31, 2007 (information on the Kashagan agreements is provided below under the section "Caspian Area" on page 35).

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

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

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

Proved developed reserves of subsidiaries at December 31, 2007 amounted to 3,862 mmBOE (1,953 mmBBL of liquids and 10,967 BCF of natural gas), representing 64% of total estimated proved reserves (63% and 63% at December 31, 2006 and 2005, respectively).

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 676 mmBOE as of December 31, 2007 (583 and 604 mmBOE as of December 31, 2006 and 2005, respectively). Said volumes are not included in reserves volumes shown in the table herein.

The tables below set forth a geographical breakdown of Eni’s proved reserves and proved developed reserves of hydrocarbons, on a barrel of oil equivalent basis, for the periods indicated.

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Proved reserves

Eni’s proved reserves of hydrocarbons by geographic area

Eni’s proved reserves of liquids by geographic area

Eni’s proved reserves of natural gas by geographic area

Eni’s proved developed reserves of hydrocarbons by geographic area

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Eni’s proved developed reserves of liquids by geographic area

Eni’s proved developed reserves of natural gas by geographic area

Mineral Right Portfolio and Exploration Activity for the year

As of December 31, 2007, Eni’s mineral right portfolio consisted of 1,220 exclusive or shared rights for exploration and development in 36 countries on five continents, for a total net acreage of 394,490 square kilometers (385,219 at December 31, 2006). Of these, 37,642 square kilometers concerned production and development (48,273 at December 31, 2006). Outside Italy net acreage (373,826 square kilometers) increased by 11,103 square kilometers mainly due to the acquisition of assets in Angola, Congo, Russia and the Gulf of Mexico, as well as exploration property in Australia, India, Nigeria, Pakistan, the United Kingdom and Alaska. In Italy, net acreage (20,664 square kilometers) declined by 1,832 square kilometers due to releases.

A total of 81 new exploratory wells were drilled in 2007 (43.5 of which represented Eni’s share), as compared to 68 exploratory wells completed in 2006 (35.9 of which represented Eni’s share). In addition, 28 exploratory wells were in progress at year end. The overall commercial success rate was 40% (38% net to Eni) as compared to 43% (49% net to Eni) in 2006. In 2005, 52 exploratory wells were completed (21.8 of which represented Eni’s share), with an overall success rate of 39.3% in 2005 (the success rate of Eni’s share of exploratory wells was 47.4%).

Production

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 2007, oil and natural gas production available for sale averaged 1,684 KBOE/d (liquids 1,020 KBBL/d; natural gas 3,819 mmCF/d), a decrease of 36 KBOE/d, or 2.1%, compared to 2006 mainly due to disruptions in Nigeria due to continuing social unrest (down 25 KBOE/d), unplanned downtime and technical issues in the North Sea and mature field declines, particularly in Italy and the United Kingdom, as well as price impacts in certain PSAs. Production performance for the year was also impacted by Venezuela’s expropriation of the Dación oilfield

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assets which took place on April 1, 2006 (down 15 KBBL/d over 2006). These negative factors were offset in part by the contribution of acquired assets in the Gulf of Mexico and Congo (up 45 KBOE/d on annual average) and production increases in Libya, Egypt and Kazakhstan. Oil and natural gas production share outside Italy was 88% (as compared to 87% in 2006).

Production of liquids (1,020 KBBL/d) decreased by 59 KBBL/d, or 5.5%, compared to 2006. Production decreases were reported mainly in Nigeria, Venezuela and the United Kingdom due to the above-mentioned causes. The most significant increases were registered in: (i) the United States due to the contribution of purchased assets and the resumption of full activity at plants damaged by hurricanes in the second half 2005; (ii) Egypt, as a result of production ramp-up at the el Temsah fields; and (iii) Kazakhstan due to a better performance of the Karachaganak field.

Production of natural gas available for sale (3,819 mmCF/d) in 2007 increased over 2006 by 140 mmCF/d, or 3.8%, mainly in Libya, as a result of the build-up of the Western Libyan Gas Project; the Gulf of Mexico, due to the contribution of acquired assets; Norway, particularly at the Aasgard (Eni’s interest 14.81%) and Kristin (Eni’s interest 8.25%) fields. Gas production decreased due to mature field declines in Italy and the United Kingdom.

Oil and gas production sold in 2007 amounted to 611.4 mmBOE. Approximately 61% of liquids production sold (370.3 mmBBL) was destined to Eni’s Refining & Marketing segment; 37% of natural gas production sold (1,385 BCF) was destined to Eni’s Gas & Power segment.

The tables below set forth Eni’s production of liquids and natural gas on an available-for-sale basis for the periods indicated.

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 75 KBOE/d, 57 KBOE/d and 20.5 KBOE/d in 2007, 2006 and 2005, respectively.

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The table below sets forth certain information and operating data regarding Eni’s principal oil and natural gas interests as of December 31, 2007.

Principal oil and natural gas interests at December 31, 2007

Eni’s principal regions of operations are described below. In the discussion that follows references to hydrocarbon production are to be intended to hydrocarbon production available for sale.

Italy

Eni has been operating in Italy since 1926. In 2007, Eni’s oil and gas production amounted to 208 KBOE/d. Eni’s activities in Italy are deployed in the Adriatic Sea, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley. Eni’s exploration and development activities in Italy are regulated by concession contracts.

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The Adriatic Sea represents Eni’s main production area in Italy, accounting for 30% of Eni’s domestic production in 2007. Production is composed mainly of natural gas. Main operated fields are Barbara (155 mmCF/d net to Eni), Angela-Angelina (64 mmCF/d), Porto Garibaldi (57 mmCF/d) and Cervia (46 mmCF/d).

Eni is operator of the Val d’Agri concession (Eni’s interest 60.77%) in Basilicata Region, Southern Italy, resulting from the unitization of the Volturino and Grumento Nova concessions made in late 2005. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is fed by 22 production wells of the 47 foreseen by the sanctioned development plan and is supported by the Viggiano oil center with a treatment capacity of 104 KBBL/d. Oil produced is carried to Eni’s refinery in Taranto via a 136-kilometer long pipeline. In 2007, the Val d’Agri concession produced 106 KBOE/d (65 net to Eni) corresponding to 31% of Eni’s production in Italy.

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

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2007, North Africa accounted for 34% of Eni’s total worldwide production of oil and natural gas.

Algeria . Eni has been present in Algeria since 1981. In 2007, Eni’s oil production in Algeria averaged 85 KBOE/d. Operating activities are located in the Bir Rebaa area in the South-Eastern desert and include the following exploration and production blocks: (a) Blocks 403 a/d (Eni’s interest 100%); (b) Blocks 401a/402a (Eni’s interest 55%); (c) Blocks 403 (Eni’s interest 50%) and 404a (Eni’s interest 12.25%); and (d) Blocks 212 (Eni’s interest 22.38%) and 208 (Eni’s interest 12.25%).

Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.

Production in Block 403a/d is supplied mainly by the HBN and Rom and satellite fields and accounted for approximately 23% of Eni’s production in Algeria in 2007. The main project underway is the Rom Integrated project, designed to develop the reserves of the Rom Main (Eni’s interest 100%), ZEA (Eni’s interest 75%) and Rom Nord fields. The project provides for the construction of a new oil treatment plant with a capacity of 32 KBBL/d. First oil is expected in 2011.

Production in Blocks 401a/402a is supplied mainly by the Rod and satellite fields and accounted for approximately 22% of Eni’s production in Algeria in 2007. Infilling activities are being performed in order to maintain the current production plateau.

The main fields in Block 403 are BRN, BRW and BRSW and accounted for approximately 14% of Eni’s production in Algeria in 2007. Extensive exploration activity is being performed. In October 2007, Eni and the Algerian state company Sonatrach signed an agreement for the renewal of the development and production concession on this block.

Block 208 is located South of Bir Rebaa. The El Merk Synergy plan for the development of this block in conjunction with the development of adjoining blocks operated by other companies is the main project underway in Algeria. The project scheme provides for the construction of a Central Production Facility. Start-up is expected after 2011. In 2007, basic engineering work was completed.

In 2006, Sonatrach requested international oil companies, including Eni, to renegotiate the economic terms of certain PSAs in light of certain changes enacted in the tax regime applicable to oil activities. Although tax terms applicable to existing PSAs partied by international oil companies have not been modified, Sonatrach asserts that it is currently bearing higher taxation on behalf of foreign oil companies. On this basis, Sonatrach intends to renegotiate the economic terms of those PSAs, particularly Blocks 401a/402a (Eni’s interest 55%), 404 (Eni’s interest 12.25%) and 208 (Eni’s interest 12.25%), in order to restore the initial economics of such contracts. At present, management is not able to foresee the final outcome of such renegotiations.

In the medium term, management expects production in Algeria to decline slightly due to mature fields decline.

Egypt. Eni has been present in Egypt since 1954. In 2007, Eni’s share of production in this country amounting to 231 KBOE/d and accounted for 14% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Belayim concession (Eni’s interest 100%) offshore in the Gulf of Suez. Gas production mainly comes from the operated or participated concession of North Port Said (former Port Fouad, Eni’s interest 100%), Baltim (50% interest), Ras el Barr (50% interest, non-operated) and el Temsah (50% interest) offshore the Nile Delta. In 2007, production from these concessions also including a portion of liquids accounted for 90% of Eni’s production in Egypt.

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

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In October 2007, Eni signed a major petroleum agreement with NOC, the Libyan National Oil Corporation. The agreement provides the extension of Eni’s mineral rights in Libya until 2042 and 2047 for oil and gas properties respectively, and the launch of large projects in gas monetization and exploration. This agreement will enable Eni to efficiently develop its long-life producing fields over a long time frame by applying its advanced techniques for maximizing the recoverability of hydrocarbons. The projects defined by the agreement regard: (i) overhauling the exploration activities in high-potential areas where Eni is already present; (ii) monetizing additional and substantial gas reserves through the upgrading of the GreenStream export pipeline, achieving an additional transport capacity of 106 BCF/y and the construction of a new LNG plant near Mellitah designed to produce 177 BCF/y, equivalent of LNG to be marketed worldwide. Under this agreement, the properties owned by Eni have been grouped into six contract areas (onshore and offshore) regulated according to Production Sharing Agreements. Onshore, the following areas have been identified: (i) Area A, including the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 and the NC 125 field (Eni’s interest 50%); (iii) Area E, with Block NC 174 (Eni’s interest 33.3%); and (iv) Area F, with Block 118 (Eni’s interest 50%). Offshore areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D, with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%).

Main discoveries for the year were achieved in: (a) offshore Block NC41 (Eni’s interest 100%), where the U1-NC41 discovery well showed the presence of oil and natural gas at a depth of over 2,600 meters; and (b) onshore concession 82 (Eni’s interest 50%), where the YY1-82 discovery well showed the presence of oil at a depth of about 5,000 meters.

In the medium term, management expects to increase Eni’s production in Libya owing to the expected ramp-up of new mineral structures near the Western Libyan Gas Project fields, despite mature field declines.

Tunisia. Eni has been present in Tunisia since 1961. In 2007, Eni’s production amounted to 15 KBOE/d. Eni’s activities are located mainly in the Mediterranean offshore facing Hammamet and in the Southern desert areas.

Exploration and production in this country are regulated by concessions and Production Sharing Agreements.

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Production mainly comes from the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks. In 2007, the development of Maamoura offshore field was sanctioned. Production is expected to start in 2009 and flow at 7 KBOE/d.

Main discoveries in 2007 were achieved in: (i) the Adam concession, where the Karma-1 and Ikhil-1 exploration wells found oil and the Nadir-1 exploration well showed the presence of gas. The three wells were linked to existing production facilities; (ii) the Bordi el Khadra permit, where the Nakhil 1 exploration well showed an oil formation and was linked to existing production facilities; and (iii) the Larich concession, where the Larich SW-1 exploration well showed the presence of oil and gas.

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

West Africa

Eni’s operations in West Africa are conducted in Angola, Congo and Nigeria. In 2007, West Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2007, Eni’s production averaged 132 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

In December 2007, Eni finalized another agreement to be part of a second gas consortium which will evaluate existing gas discoveries and explore further potential in the Angolan offshore to support the feasibility of a second LNG train. Eni is technical operator, with a 20% interest.

Development activities at the Landana and Tombua oil fields in offshore Block 14 progressed, achieving early production at the Landana field which was linked to existing facilities at Benguela/Belize. Production is expected to peak in 2009 at 130 KBBL/d (23 net to Eni).

Development of the Banzala oil field in Block 0 in Cabinda moved forward with the installation of the two scheduled production platforms, which had been previously started up in June 2007 and in January 2008, respectively. Production is expected to peak in 2009 at 27 KBBL/d (3 KBBL/d net to Eni).

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As part of Phase C of the development of reserves in the Kizomba deep offshore area, development activities of the Mondo and Saxi/Batuque fields in Block 15 are ongoing. A common development strategy is expected to be deployed in both projects, envisaging the installation of FPSO vessels. In January 2008, the Mondo field was started up. The Saxi/Batuque fields are expected to start-up in 2008. Peak production at 100 KBBL/d (18 net to Eni) is expected in 2008 and 2009, respectively. In September 2007, production started at the Marimba field by linking to existing facilities at Kizomba A. Production is expected to peak in 2008 at 39 KBBL/d (7 KBBL/d net to Eni).

Main oil discoveries were made in Block 14, with the Lucapa-1, Menongue-1 and Malange-1 wells and in Block 15/06 with the Sangos 1 discovery well.

In the medium term, management expects to increase Eni’s production to approximately 130 KBBL/d reflecting contributions from ongoing development projects, despite mature field declines.

Congo. Eni has been present in Congo since 1968 and its activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore. In 2007, production averaged 67 KBOE/d net to Eni.

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

Development activities of the acquired M’Boundi field moved forward with the revision of the production scheme and layout, as well designing activities regarding application of advanced recovery techniques and associated gas monetization. In particular, Eni signed an agreement with Congolese authorities for doubling the Djeno power plant and building a new power plant to be fired with associated gas produced at the M’Boundi field. These projects are expected to start-up in the second half of 2008 and by end of 2009, respectively.

Development activities at the Awa Paloukou (Eni’s interest 90%) and Ikalou-Ikalou Sud (Eni’s interest 100%) fields are underway. Production is expected to start in 2008, peaking at 13 KBOE/d net to Eni in 2009.

Main oil discoveries were made in Mer Très Profonde Sud permit (Eni’s interest 30%) with the Persée Nord Est-1 well, drilled at a depth between 2,700 and 3,500 meters, and the Cassiopea Est-1 well, drilled at a depth of 2,900 meters and which yielded 5,300 BBL/d in test production.

In the medium term, management expects to increase Eni’s production in Congo due to the contribution from recently acquired assets, targeting a level of 140 KBBL/d in 2011. Key growth drivers will be the integration and development of assets acquired from Maurel & Prom and Burren Energy in addition to projects underway.

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Nigeria. Eni has been present in Nigeria since 1962. In 2007, Eni’s oil and gas production averaged 119 KBOE/d located mainly in the onshore and offshore of the Niger Delta.

In the development /production phase Eni is operator of onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 50.19%), OMLs 120-121 (Eni’s interest 40%) and OML 118 (Eni’s interest 12.5%). Through SPDC JV oil joint venture, Eni also holds a 5% interest in 31 onshore blocks and a 12.86% interest in 5 conventional offshore blocks.

In the exploration phase Eni is operator of Oil Prospecting Leases (OPL) 244 (Eni’s interest 60%), OML 134 (former OPL 211 - Eni’s interest 50.19%) and onshore OML 135 (former OPL 219 - Eni’s interest 12.5%) and OPL 282 (Eni’s interest 90%).

In March 2007, Eni signed a Production Sharing Contract for the OPL 135 permit (Eni operator with a 48% interest) located in the Niger Delta. The arrangement with a 25-year term envisages an exploration stage with a five-year term and a subsequent development phase of oil and natural gas reserves located in the proximity of existing facilities and the Kwale/Okpai power station where Eni is operator.

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

The Forcados/Yokri oil and gas fields (Eni’s interest 5%) are currently under development offshore and onshore the Niger Delta. Development is expected to be completed in 2008 as part of an integrated project aiming at providing natural gas supplies to the Bonny liquefaction plant. Offshore production facilities have been installed. The onshore project provides for the upgrading of the Yokri and North/South Bank flowstations and the realization of a gas compressor plant.

Eni holds a 10.4% interest in the Bonny liquefaction plant located in the eastern Niger Delta, with a treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on 6 trains. The sixth train has been started in 2007. The seventh unit is being engineered with start-up expected in 2012. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 BCF/y. Natural gas supplies to the plant are provided under a gas supply

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agreement with a 20-year term from the SPDC joint venture and the NAOC JV of OMLs 60, 61, 62 and 63.When fully operational in 2008, supplies will total approximately 3,461 mmCF/d (268 net to Eni). In 2007, Eni’s supplies were 173 mmCF/d. LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas transport fleet, wholly-owned by Nigeria LNG Co.

Eni is operator with a 17% interest of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal. This plant is expected to start operating in 2012 with a treatment capacity of 10 mmtonnes/y of LNG corresponding to 618 BCF/y (approximately 64 net to Eni) of feed gas on 2 trains for twenty years. Supplies to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas fields in the OMLs 61 and 62 onshore blocks. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 2 mmtonnes/y of LNG capacity. The front end engineering is underway and the final investment decision is expected in the second half of 2008.

In the medium term, management expects to increase Eni’s production in Nigeria to approximately 200 KBOE/d, reflecting in particular the development of gas reserves.

North Sea

Eni’s operations in the North Sea area are conducted in Norway and United Kingdom. In 2007, the North Sea accounted for 15% of Eni’s total worldwide production of oil and natural gas.

Norway. Eni has been operating in Norway since 1964. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 134 KBBL/d in 2007.

Exploration and production activities in Norway are regulated by Production Licenses (PLs). According to a production license, the holder is entitled to perform seismic surveys and drilling and production activities for a few years with possible extensions.

Eni holds interests in six production areas in the Norwegian Sea. The main producing fields are Aasgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.12%), Mikkel (Eni’s interest 14.9%) and Norne (Eni’s interest 6.9%), which together accounted for 68% of Eni’s production in Norway. The main structures under development are located near Kristin, particularly Tyrihans (Eni’s interest 6.23%). Economic development of this field is expected to be achieved through synergies with the Kristin production facilities. Production is expected to start in 2009, when production of Kristin is expected to decline which will make spare capacity available to process production from Tyrihans.

Eni holds interest in four production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL018 which in 2007 produced 352 KBOE/d (44 net to Eni) and accounted for 32% of Eni’s production in Norway. Ongoing projects for Ekofisk aim at maintaining and optimizing production by means of infilling wells, the development of the Growth Area and upgrading of existing facilities.

Currently Eni is only performing exploration activities in Barents Sea. Operations in this area are focused on the appraisal of the mineral potential of the large Goliath discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest) aimed at its commercial development. The project is progressing in accordance with the program. The final investment decision is expected in 2008. Critical equipment (rigs) to develop the field has already been booked.

In 2007, Eni sold a 30% stake of the Prospecting License 259 (Eni’s interest 70%) and the whole interest of the Prospecting License 256.

Main discoveries for 2007 were achieved in the: (i) Prospecting License 393 (Eni’s interest 30%), near the Goliath discovery, where the 7125/4-1 Nucula exploration well showed the presence of hydrocarbons at a depth between 800 and 1,450 meters; (ii) Prospecting License 122 (Eni’s interest 20%), the appraisal of the Marulk discovery increased the recognized mineral potential; (iii) Prospecting License 312 (Eni’s interest 17%), where the Gamma discovery well showed the presence of gas at a depth of 2,500 meters; and (iv) the Prospecting License 293 (Eni operator with a 45% interest) the Afrodite discovery well showed the presence of gas and condensates at a depth of 373 meters.

In the medium term, management expects to slightly increase Eni’s production in Norway, reflecting the planned development projects, partly offset by mature field declines.

The United Kingdom. Eni has been present in the United Kingdom since 1964. Eni’s activities are carried out in the British section of the North Sea, in the Irish Sea and in some areas East and West of the Shetland Islands. In 2007, Eni’s net production of oil and gas averaged 120 KBOE/d.

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

Caspian Area

In 2007, Eni’s operations in the Caspian Area accounted for 6% of its total worldwide production of oil and natural gas.

Kazakhstan-Kashagan. Eni has been present in Kazakhstan since 1992. Eni is the single operator of the North Caspian Sea Production Sharing Agreement (NCSPSA) with a participating interest equal to 18.52% as of December 31, 2007. The other partners of this initiative are Total, Shell and ExxonMobil, each with a participating interest currently of 18.52%, ConocoPhillips currently with 9.26%, and Inpex and KazMunayGas each currently with 8.33%. Each partner’s participating interest in the project will change according to the terms of the Memorandum of Understanding signed among the parties, including the Kazakh authorities, on January 14, 2008. Information on this agreement is included below. The change in participating interests will apply retroactively as of January 1, 2008.

The NCSPSA defines terms and conditions for the exploration and development activities to be performed in the area covered by the contract. The Kashagan field was discovered in the northern section of the contractual area in the year 2000. Management believes this field to contain a large amount of hydrocarbon resources.

As of December 31, 2007, Eni’s proved reserves booked for the Kashagan field amounted to 520 mmBOE, recording a decrease of 76 mmBOE with respect to 2006 mainly due to the impact of increased year-end oil prices on reserve entitlements in accordance with the PSA scheme. Proved reserves for the field as of December 31, 2007 were determined according to Eni’s then current participating interest of 18.52%. As part of the agreements defined with the Kazakh Republic, the change of Eni’s interest to 16.81% in 2008 will determine a decrease of approximately 50 mmBBL in Eni’s estimated net proved reserves of the Kashagan field with respect to December 31, 2007.

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As of December 31, 2006, Eni’s proved reserves booked for the Kashagan field amounted to 596 mmBOE, recording an increase of 107 mmBOE with respect to 2005 due to an extension of the proved area and project cost revision, offset in part by the impact of price revisions.

As of December 31, 2007, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $2.6 billion. This capitalized amount included: (i) $1.8 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $0.8 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre emption rights in previous years. The $2.6 billion amount was equivalent to euro 1.8 billion based on the 2007 year-end euro/U.S. dollar exchange rate. As of December 31, 2006 the aggregate costs incurred by Eni for the Kashagan project that were capitalized by Eni in its financial statements amounted to $1.9 billion, corresponding to euro 1.5 billion based on 2006 year-end exchange rates.

Costs borne by Eni to explore and develop this field are recovered in accordance with the mechanisms typically contemplated by a PSA scheme, which is widely used in the industry. In this type of contract the national oil company or State-owned entity assigns to the international oil company (the contractor) the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is generally divided into two portions: "cost oil" is used to recover costs borne by the contractor and "profit oil" is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Accordingly, recoverability of the expenditures is subject to approval from the relevant State-owned or controlled entity who is party to the agreement. Similarly, cost overruns are recovered to the extent they are sanctioned by the State-owned or controlled entity who is party to the agreement.

To date, costs incurred for the development of the Kashagan oilfield relate to scheduled works and in accordance to the budget duly approved by the Kazakhstan authorities, and are therefore recoverable subject to customary audit rights.

The development plan of the Kashagan field was originally sanctioned by the Kazakh authorities in February 2004, contemplating a three-phase development scheme including partial gas re-injection in the reservoir to enhance the recovery factor of the crude oil. The sanctioned plan budgeted expenditures amounting to U.S. $10.3 billion (in 2007 real terms) to develop phase-one, with a target production level of 300 KBBL/d. First oil was originally scheduled to be produced by the end of 2008. Eni was expected to fund these expenditures according to its participating interest in this project. On June 29, 2007, Eni, as operator, filed with the relevant Kazakh authorities amendments to the sanctioned development plan. These amendments rescheduled the production start-up to 2010 and estimated development expenditures for phase-one at U.S. $19 billion. The production delay and cost overruns were driven by a number of factors: 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 off-shore facilities.

In July 2007, the Kazakh authorities rejected the proposed amendments to the sanctioned development plan. In August 2007, the Government of the Kazakh Republic sent to the companies forming the NCSPSA consortium a notice of dispute alleging failure on part of the consortium to fulfil certain contractual obligations and violation of the Republic’s laws. Negotiations commenced with a view to settle this dispute.

On January 14, 2008, all parties to the NCSPSA consortium and the Kazakh authorities signed a memorandum of understanding for the amicable resolution of this dispute. The material terms of the agreement are: (i) the proportional dilution of the participating interest of all the international members of the Kashagan consortium, following which the stake held by the national Kazakh Company KazMunayGas and the stakes held by the other four major shareholders will each be equal to 16.81%. These changes will be effective January 1, 2008. The Kazakh partner will pay the other co-venturers an aggregate amount of U.S. $1.78 billion; (ii) a value transfer package to be implemented through changes to the terms of the NCSPSA, the amount of which will vary in proportion to future levels of oil prices. Eni is expected to contribute to the value transfer package in proportion to its new participating interest in the project; and (iii) an increased role of the Kazakh partner in operations and a new operating and governance model which will entail a greater involvement of the major international partners.

Although the project was not stopped during the negotiation process, its progress slowed down. The NCPSA consortium has presented to the Kazakh authorities a revised budget and schedule for the execution of the phase-one of the project, and the relevant discussions are currently ongoing.

The magnitude of the reserves base, the results of the first four tests conducted on development wells and the subsurface studies completed to date support expectations for a full field production plateau of 1.5 mmBBL/d, which represents a 25% increase above the original plateau as presented in the 2004 development plan. An independent reserve evaluation performed by a petroleum engineer (Ryder Scott Petroleum Consultants) fully supports the target production plateau of the Kashagan field. The achievement of the full field production plateau will require a material

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amount of expenditures in addition to the development expenditures needed to complete the execution of phase-one. However, taking into account that future development expenditures will be incurred over a long time horizon, management does not expect any material impact on the company’s liquidity or its ability to fund these capital expenditures.

In addition to the expenses incurred for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets, for which various options are currently under consideration by the consortium. These include: (i) the use of existing infrastructure, such as the Caspian Pipeline Consortium pipeline (Eni’s interest 2%) and the Atyrau-Samara pipeline, both of which are expected to undergo a capacity expansion; and (ii) the construction of a new transportation system. In this respect, it is worth mentioning the project aimed at building a line connecting the onshore Bolashak production center with the Baku-Tbilisi-Cehyan pipeline (where Eni holds an interest of 5% corresponding to the right to transport 50 KBBL/d).

Kazakhstan-Karachaganak. Located in West onshore Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by Production Sharing Agreement lasting 40 years, until 2037. Eni is co-operator of the venture with 32.5% interest.

In 2007, production from this field averaged 234 KBBL/d of liquids and 743 mmCF/d of natural gas, being 70 KBBL/d and 238 mmCF/d Eni’s share, respectively. This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. This scheme enables to increase the recovery of liquids. Approximately two-thirds of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of 150 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni's interest 2%) and the Atyrau-Samara pipeline. The remaining third of non-stabilized liquid production and volumes of associated gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg. The plant treatment capacity is being upgraded which will enable to increase exported volumes by 56 KBBL/d from 2009.

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In August 2007, Eni signed an agreement to purchase a 30% interest in four exploration blocks in the Exmouth Plateau area in Australia. The four blocks are located at a maximum water depth of 2,000 meters. Eni’s equity interest will increase by 10% after at least one exploration well is drilled. Eni will be the operator during the development phase.

In September 2007, Eni acquired a 40% interest and the operatorship of the JPDA 06-105 exploration permit, located in the international offshore cooperation zone between East Timor and Australia. Two oil discoveries are located in this permit. The exploration plan provides the drilling of a well in 2008.

Exploration and production activities in Australia are regulated by concessions, while in the cooperation zone between East Timor and Australia (JPDA) they are regulated by PSAs.

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

China. Eni has been present in China since 1984. In 2007, Eni’s production amounted to 8 KBOE/d. Activities are located in the South China Sea.

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

Production derives mainly from offshore blocks 16/08 and 16/09 operated by the CACTOG consortium (Eni’s interest 16.33%). Oil production, destined to the domestic market, derives mainly from the HZ26-1 field (Eni’s interest 16.33%) through fixed platforms, one of them underwater, linked to an underwater transport facility to the Zhuhai treatment plant. Ongoing development activities concerned mainly the HZ25-3/1 field with expected start-up in 2009.

Croatia. Eni has been present in Croatia since 1999. In 2007, Eni’s net production of natural gas averaged 51 mmCF/d. Activities are deployed in the Adriatic offshore facing the city of Pula.

Exploration and production activities in Croatia are regulated by PSA.

The main producing gas fields are Ivana, Ika & Ida, Marica and Katerina which operated by Eni through a 50/50 joint venture with the national Croatian oil company.

Development activities of the Annamaria, Irina and Ana/Vesna discoveries are ongoing. A common project is expected to be deployed in all of them, envisaging the installation of production platforms which shall be linked to existing facilities. Start-up is expected in 2009.

India. Eni has been present in India since 2005 and is performing exploration activities in onshore Block RJONN-2003/1 (Eni’s interest 34%) and offshore Blocks AN-DWN-2003/2 (Eni’s interest 40%) and MNDWN 2002/1 (Eni’s interest 34%).

The exploration program for Block RJ-ONN-2003/1, located in the desert of Rajastan, provides drilling of four wells in the first four years of the license. Any hydrocarbons discovered will be sold locally.

The exploration program for Block AN-DWN-2003/2 near the Andaman Islands provides drilling of three wells in the first four years of the license. In 2007, activity concerned the acquisition of seismic data in order to plan the exploration and drilling activity.

Indonesia. Eni has been present in Indonesia since 2000. Eni’s production amounted to 17 KBOE/d, mainly gas, in 2007. Activities are concentrated in the western offshore and onshore of Borneo and offshore Sumatra.

Exploration and production activities in Indonesia are regulated by PSAs.

Production consists mainly of gas and derives from the Sanga Sanga permit (Eni’s interest 37.81%) with seven production fields. This gas is treated at the Bontang liquefaction plant, the largest in the world, and is exported to the Japanese, South Korean and Taiwanese markets. Ongoing activities aim at maintaining the current production plateau by means of infilling wells and the optimization of existing ones.

In January 2007, Eni and Pertamina signed a Memorandum of Understanding aimed at identifying joint development opportunities for exploration and development activities.

Main ongoing projects include the joint development of the five discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%). Production will be treated at the Bontang LNG plant. The project has not yet been sanctioned by authorities.

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Exploration activity was successful with the Tulip East offshore discovery (Eni’s interest 100%), and an appraisal well of the Aster field (Eni’s interest 66.25%) was drilled and yielded 5 KBOE/d in test production.

Iran. Eni has been present in Iran since 1957. In 2007, production net to Eni averaged 26 KBOE/d. Eni’s activities are concentrated in the offshore of the Persian Gulf and onshore.

Exploration and production activities in Iran are regulated by buy-back contracts.

The main producing fields are South Pars phases 4 and 5 in the offshore of the Persian Gulf and Darquain located onshore which accounted for 88% of Eni’s production in Iran in 2007. Eni also holds interests in the Dorood field (Eni’s interest 45%).

The main ongoing project regards the Darquain field operated by Eni with a 60% interest. Upgrading activities are underway by means of drilling additional wells, increasing capacity of the existing treatment plant and gas-injection. These actions aim at increasing production from the present 50 KBBL/d to over 160 KBBL/d (14 net to Eni) by 2009.

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. Particularly, under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages that the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under, ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 8 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buy-back contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on Eni’s activities in the country. It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation.

Pakistan. Eni has been present in Pakistan since 2000. In 2007, production net to Eni averaged 50 KBOE/d, mainly gas.

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

Eni’s main permits are Bhit (Eni operator with a 40% interest), Sawan (23.68%) and Zamzama (17.75%), which in 2007 accounted for 90% of Eni’s production in Pakistan.

In 2007, Eni and State oil company PPL signed an agreement providing for a swap of interests in the offshore Blocks M, N and C. Within this agreement, Eni holds 70% interest in the M and N blocks and 60% interest as operator in the C block.

In April 2008, upgrading facilities was completed at the Bhit gas field leading to the start-up of the satellite Badhra field.

Main discoveries for 2007 were achieved in: (a) the Gambat permit (Eni’s interest 30%) where the Tajjal 1 exploration well showed the presence of gas at a depth of 3,845 meters; (b) the Kadanwari permit (Eni operator with a 18.42% interest) where the Kadanwari 18 appraisal well confirmed the presence of gas at a depth of approximately 3,400 meters; and (c) the Latif permit (Eni’s interest 33.3%) where the Latif 1 exploration well discovered a hydrocarbon formation at a depth of 3,520 meters.

Russia. In April 2007, as part of Eni’s strategic alliance with Gazprom, Eni, through the partnership in SeverEnergia (60% Eni, 40% Enel), former EniNeftegaz, acquired assets of Lot 2 as part of the liquidation procedure of bankrupt Russian company Yukos. Eni’s share of cash consideration of this transaction amounted to euro 3.73 billion. Acquired assets included: (i) a 100% interest in three Russian companies (Eni’s share being 60%) operating in the exploration and development of natural gas reserves, OAO Arctic Gas Co, ZAO Urengoil Inc and OAO Neftegaztechnologia with proved reserves amounting to 617 mmBOE net to Eni, as well as certain minor assets that are expected to be sold or liquidated. Eni and Enel granted Gazprom a call option to purchase a 51% interest in these investments to be exercisable within two years from the purchase date. Should Gazprom exercise its call option, Eni’s interest would be diluted to approximately 30% and proved reserves that were booked in connection with the acquisition would be reduced by approximately 50%. These investments are accounted under

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the equity method as Eni jointly controls them based on agreed terms with the other partners. As these entities did not produce any revenue in the year, no significant loss or gain on equity evaluation was recorded in the profit or loss account; and (ii) a 20% interest in OAO Gazprom Neft which was purchased only by Eni. Eni granted Gazprom a call option on this 20% interest in OAO Gazprom Neft to be exercisable within two years from the purchase date. The strike price equals the purchase price plus a contractual remuneration on capital employed, less dividend distributed. This interest is classified as a current asset and assessed at fair value trough profit or loss as provided by the fair value option of IAS 39, considering that the call option is being assessed in the same way. The fair value of OAO Gazprom Neft is based on currently quoted market price as this company is listed at the London Stock exchange. As a result of this accounting treatment, a gain equal to the contractual remuneration of capital employed was recognized in 2007 profit and loss account (net gain of euro 188 million). See Item 5 for a more detailed discussion.

The three acquired gas companies are located in the Yamal Nenets region: (i) OAO Arctic Gas Co owns two exploration licenses, Sambugurskii and Yevo-Yahinskii including seven fields currently in the appraisal/development phase. Main fields are Sambugorskoye currently under development and production testing and Urengoiskoye; (ii) ZAO Urengoil Inc owns exploration and development licenses for the Yaro-Yakhinskoye gas and condensate field; and (iii) OAO Neftegaztechnologia owns the exploration and development license of the Severo-Chasselskoye field.

During 2007, certain activities were executed in order to set up the operational organization and take control of existing assets. An overall plan was assessed to complete and start acquired assets. Ongoing development activities moved forward bringing the wells to a sufficient level of safety and assessing resumption of construction of production and transportation facilities, as well as defining a seismographic activity. Finalization of the gas sale contracts is underway.

Saudi Arabia. Eni has been present in Saudi Arabia since 2004. Ongoing activities concern exploration of the so-called C area in order to discover and develop gas reserves. This license is located in the Rub al Khali basin at the border with Qatar and the United Arab Emirates. The exploration plan provides for the drilling of four wells in five years. In case of a commercial discovery, the contract will last 25 years with a possible extension to a maximum of 40 years. Any gas discovered will be sold locally for power generation and as feedstock for petrochemical plants. Condensates and NGL will be sold on international markets. Drilling of the second commitment exploratory well is underway.

United States. Eni has been present in the United States since 1966. Activities are performed in the conventional and deep offshore in the Gulf of Mexico and more recently onshore and offshore Alaska.

In 2007, Eni’s oil and gas production deriving only from the Gulf of Mexico averaged 68 KBOE/d, significantly growing from 2006 (up 114%) due to the acquisition of producing assets from Dominion Resources. This acquisition closed in July 2007 with an outlay of euro 3.5 billion. Acquired properties brought in an additional production of approximately 75 KBOE/d and proved reserves amounting to 123 mmBOE.

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

Eni holds interests in 400 exploration and production blocks in the Gulf of Mexico, 60% operated.

In October 2007, following an international bid procedure Eni was awarded 26 new exploration licenses in the Gulf of Mexico, covering a gross acreage of 606 square kilometers.

In March 2008, following an international bid procedure Eni was awarded 32 exploration leases. The subsequent development phase will leverage synergies relating to proximity of acquired acreage to existing operated facilities. Formal assignation is subject to approval by the relevant authorities.

The main fields operated by Eni with a 100% interest are Allegheny, East Breaks and Morphet as well as assets acquired from Dominion Resources including Devils Towers, Triton and Goldfinger (Eni operator with a 75% interest). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%), and King Kong (Eni operator with a 56% interest) fields.

Development of acquired assets in the year allowed the start-up of production at the San Jacinto (Eni is operator with a 53.3% interest), Q (Eni’s interest 50%) and Spiderman (Eni’s interest 36.7%) fields. Development of these fields was performed by installing underwater facilities to link to the Independence Hub platform. The production plateau of approximately 25 KBOE/d has been reached at the end of 2007. Main projects include the development of reserves at the Longhorn discovery (Eni’s interest 75%) trough installing production platform. Production is expected to start in 2009 peaking at 28 KBOE/d (approximately 19 net to Eni).

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In the medium term, management expects to increase Eni’s production reflecting the development and integration of assets acquired and the start-up of fields in Alaska.

Venezuela. Eni has been present in Venezuela since 1998.

In June 2007, Eni signed a memorandum of understanding with national state-owned company PDVSA which defines the terms for the transfer of the development activity of the Corocoro field in Venezuela to the new contractual regime of "empresa mixta". Eni will retain its 26% interest in this project. On December 5, 2007, the agreement was finalized. First oil was achieved in the first quarter of 2008. Production is expected to peak at 66 KBBL/d (17 KBBL/d net Eni).

In February 2008, Eni and the Venezuelan Authorities rea