20-F 1 u46369e20vf.htm FORM 20-F e20vf
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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549


Form 20-F

(Mark One)

REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g)
OF THE SECURITIES EXCHANGE ACT OF 1934

OR

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             .

Commission file number: 1-14090

Eni SpA
(Exact name of Registrant as specified in its charter)

Republic of Italy
(Jurisdiction of Incorporation of Organization)

Piazzale Enrico Mattei 1, 00144 Rome, Italy
(Address of principal executive offices)


 


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     Securities registered or to be registered pursuant to Section 12(b) of the Act:

     Shares, nominal value euro 1 each, listed on the New York Stock Exchange not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the New York Stock Exchange.

     American Depositary Shares, each representing the right to receive five Shares, listed on the New York Stock Exchange.

     


     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 each   4,001,814,026

     Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:   Yes o    No o

     Indicate by check mark which financial statement Item the Registrant has elected to follow:

Item 17 o     Item 18 o

 


CERTAIN DEFINED TERMS
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
STATEMENTS REGARDING COMPETITIVE POSITION
GLOSSARY
CONVERSION TABLE
PART I
Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
Item 3. KEY INFORMATION
Selected Financial Information
Selected Operating Information
Exchange Rates
Risk Factors
Item 4. INFORMATION ON THE COMPANY
History and Development of the Company
BUSINESS OVERVIEW
Exploration & Production
Refining & Marketing
Petrochemicals
Oilfield Services and Engineering
Other Activities
Research and Development
Insurance
Environmental Matters
Regulation of Eni’s businesses
Property, Plant and Equipment
Organizational Structure
Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
Critical Accounting Policies
Background and Recent Developments
Principles of Consolidation
Results of Operations
Liquidity and Capital Resources
Management Expectations of Operations
Summary of Significant Differences Between Italian GAAP and U.S. GAAP
Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
Directors and Senior Management
Compensation
Board Practices
Employees
Share Ownership
Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
Major Shareholders
Related Party Transactions
Item 8. FINANCIAL INFORMATION
Consolidated Statements and Other Financial Information
Significant Changes
Item 9. THE OFFER AND THE LISTING
Offer and Listing Details
Markets
Item 10. ADDITIONAL INFORMATION
Memorandum and Articles of Association
Material Contracts
Exchange Controls
Taxation
Documents on Display
Item 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES OF MARKET RISK
Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
PART II
Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
Item 15. CONTROLS AND PROCEDURES
Item 16. [RESERVED]
PART III
Item 17. FINANCIAL STATEMENTS
Item 18. FINANCIAL STATEMENTS
Item 19. EXHIBITS
Exhibit 1
Exhibit 7
Exhibit 8
Exhibit 10.1


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TABLE OF CONTENTS

                 
            Page
           
Certain Defined Terms
        i  
Presentation of Financial and Other Information
        i  
Statements Regarding Competitive Position
        i  
Glossary
            iii  
Conversion Table
        v  
PART I
               
Item 1.
  IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS (*)     1  
Item 2.
  OFFER STATISTICS AND EXPECTED TIMETABLE (*)     1  
Item 3.
  KEY INFORMATION     1  
 
  Selected Financial Information     1  
 
  Selected Operating Information     3  
 
  Exchange Rates     4  
 
  Risk Factors     4  
Item 4.
  INFORMATION ON THE COMPANY     9  
 
  History and Development of the Company     9  
 
  Business Overview     12  
 
  Exploration & Production     12  
 
  Gas & Power     23  
 
  Refining & Marketing     32  
 
  Petrochemicals     39  
 
  Oilfield Services and Engineering     41  
 
  Other Activities     45  
 
  Research and Development     45  
 
  Insurance     47  
 
  Environmental Matters     47  
 
  Regulation of Eni’s businesses     49  
 
  Property, Plant and Equipment     57  
 
  Organizational Structure     58  
Item 5.
  OPERATING AND FINANCIAL REVIEW AND PROSPECTS     59  
 
  Critical Accounting Policies     59  
 
  Background and Recent Developments     61  
 
  Principles of Consolidation     63  

 


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            Page
           
 
  Results of Operations     64  
 
  Liquidity and Capital Resources     75  
 
  Management Expectations of Operations     80  
 
  Summary of Significant Differences     83  
 
  Between Italian GAAP and U.S. GAAP        
Item 6.
  DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES     84  
 
  Directors and Senior Management Compensation     84  
 
  Board Practices     89  
 
  Employees     93  
 
  Share Ownership     94  
Item 7.
  MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS     95  
 
  Major Shareholders     95  
 
  Related Party Transactions     95  
Item 8.
  FINANCIAL INFORMATION     95  
 
  Consolidated Statements and Other Financial Information     95  
 
  Significant Changes     96  
Item 9.
  THE OFFER AND THE LISTING     96  
 
  Offer and Listing Details     96  
 
  Markets     98  
Item 10.
  ADDITIONAL INFORMATION     98  
 
  Memorandum and Articles of Association     98  
 
  Material Contracts     105  
 
  Exchange Controls     105  
 
  Taxation     105  
 
  Documents on Display     109  
Item 11.
  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK     110  
Item 12.
  DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES     112  

 


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            Page
           
PART II
               
Item 13.
  DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES     112  
Item 14.
  MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS        
 
      112  
Item 15.
  CONTROLS AND PROCEDURES     112  
Item 16.
  RESERVED     112  
PART III
               
Item 17.
  FINANCIAL STATEMENTS (**)     113  
Item 18.
  FINANCIAL STATEMENTS (**)     113  
Item 19.
  EXHIBITS     113  


    (*) Omitted pursuant to General Instructions for Form 20-F.
 
    (**) The Registrant has responded to Item 18 in lieu of responding to Item 17.

     Certain disclosures contained herein including, without limitation, information appearing in «Item 4. Information on the Company», and in particular «Item 4 — Exploration & Production», «Item 5. Operating and Financial Review and Prospects» and «Item 11. Quantitative and Qualitative Disclosures of 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

CERTAIN DEFINED TERMS

     In this Form 20-F, the term «Eni» refers to 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 «Certain Oil and Gas Terms» and «Conversion Table».

 


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management objectives, trends in results of operations, margins, costs, return on equity, 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 Report 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 term «Eni» refers to 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 «Certain Oil and Gas Terms» and «Conversion Table».

 

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

     Unless otherwise indicated, the financial information contained herein has been prepared in accordance with Eni Group accounting policies which are in accordance with principles prescribed by Italian law and supplemented by the accounting principles issued by the Consiglio Nazionale dei Dottori Commercialisti e dei Ragionieri or, in the absence thereof and if applicable, the International Accounting Standards Board (collectively, «Italian GAAP»). For further details see Note 2 to the Consolidated Financial Statements as described in Note 27 to the Consolidated Financial Statements, Italian GAAP differ in certain significant respects from accounting principles generally accepted in the United States («U.S. GAAP»). Unless otherwise indicated,

 


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any reference herein to «Consolidated Financial Statements» is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein.

     Starting from 1999, Eni published its Consolidated Financial Statements in euro; prior to 1999 Eni published its Consolidated Financial Statements in Italian lire. As of January 1, 1999, the lira became a sub-unit of the euro which is now the official currency of Italy. The euro/lira exchange rate was irrevocably fixed on December 31, 1998, at lire 1936.27 per euro. Eni Consolidated Financial Statement for years prior to 1999 have been translated into euro for a better comparison of data. See «Item 3 — Selected Consolidated Financial Data». 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 «E» are to the currency of the European Monetary Union.

     Market share estimates contained in this document are based on management estimates unless otherwise indicated.

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.

GLOSSARY

     A glossary of financial and oil and gas terms is available on Eni’s web page at the address www.eni.it/english/notizie/mediateca/glossario_eni.html. Below is a selection of the most frequently used terms.

     
   Financial Terms    
Leverage   It is a measure of a company’s debt, calculated as the ratio between net borrowings and shareholders’ equity, including minority interests.
     
Net borrowings   Eni evaluates its financial condition by reference to «net borrowings», which it calculates as total debt less: cash and cash equivalent securities not related to operations, non-operating financing receivables, and other items, net. Non-operating financing receivables consists of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow.

 


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    Securities not related to operations consist primarily of government and corporate securities.
     
Roace   Return On Average Capital Employed, is the return on average capital invested, calculated as the ratio between: (i) net income before minority interests, plus net financial charges on net borrowings, on a post-tax basis using a deemed tax rate equal to the Italian statutory tax rate; and (ii) net average capital employed. Capital employed is defined as the sum of shareholders’ equity, minority interest and net borrowings. Expressed as a percentage.
     
Business terms    
     
Associated gas   Natural gas, occurring in the form of a gas cap, overlying an oil zone, contained in the reservoir’s crude oil gas
     
Average reserve life index   Ratio between the amount of reserves at the end of the year and total production for the year
     
Barrel   Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons.
     
Boe   Barrel of Oil Equivalent. It is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a coefficient equal to 0.0061 in the case of gas produced outside Italy and 0.0063 in the case of gas produced in Italy due to their different calorific values.
     
Concession contracts   Contracts currently applied mainly in Western countries regulating relationships between States and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive on mining activities and for this reason it acquires a right on hydrocarbons extracted, against the payment of royalties on production and taxes on oil revenues to the State.
     
Condensates   These are light hydrocarbons produced along with gas, that condense to a liquid state at surface temperature and pressure.
     
Conversion capacity   Maximum amount of heavy fractions that can be processed in certain dedicated facilities of a refinery to obtain finished products.
     
Deep waters   Waters deeper than 200 meters.
     
Development   Drilling and other post-exploration activities aimed at the production of oil and gas.
     
EPC   Engineering, Procurement, Construction.

 


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EPIC   Engineering, Procurement, Installation, Construction.
     
Exploration   Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis, and well drilling.
     
Infilling wells   Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
     
FPSO   Floating Production Storage and Offloading System.
     
LNG   Liquefied Natural Gas obtained through the cooling of natural gas to minus 160° C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed and consumed. One ton of LNG corresponds to 1,400 cubic meters of gas.
     
LPG   Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
     
Margin   The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemicals products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.
     
Mineral Storage   According to Legislative Decree No. 164/2000, these are volumes required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. The purpose is to ensure production flexibility as required by long-term purchase contracts as well as to cover technical risks associated with production.
     
Modulation Storage   According to Legislative Decree No. 164/2000, these are volumes required for meeting hourly, daily and seasonal swings of demand.
     
Network Code   A Code containing norms and regulations for access to, management and operation of natural gas pipelines.
     
Over/Under lifting   Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts different from the agreed ones determine temporary Over/Under lifting situations.

 


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Primary balanced refining
capacity
  Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.
     
Production Sharing
Agreement («PSA»)
  Contract in use in African, Middle Eastern, Far Eastern and Latin American countries, regulating relationships between States and oil companies with regards to the exploration and production of hydrocarbons. The mining concession is assigned to the national oil company jointly with the foreign oil company who has exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: «cost oil» is used to recover costs borne by the contractor, «profit oil» is divided between contractor and national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions may vary from one country to the other.
     
Proved reserves   Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved reserves include: (i) proved developed reserves: amounts of hydrocarbons that are expected to be retrieved through existing wells, facilities and operating methods; (ii) non developed proved reserves: amounts of hydrocarbons that are expected to be retrieved following new drilling, facilities and operating methods. On these amounts the company has already defined a clear development expenditure program which is an expression of the company’s determination.
     
Ship-or-pay   Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.

 


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Strategic Storage   According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.
     
Take-or-pay   Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of the gas set in the contract also in case it is not collected by the purchaser. The purchaser has the option of collecting the gas paid and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
     
Upstream/Downstream   The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil sector that are downstream of exploration and production activities.

ABBREVIATIONS

     
BCF   = billion cubic feet
BOE   = barrel of oil equivalent
mm/BBL   = million barrels
KBBL/d   = thousand barrels per day
mmCF/d   = million cubic feet per day

CONVERSION TABLE

         
1 acre   = 0.405 hectares    
1 barrel   = 42 U.S. gallons    
1 barrel of oil equivalent   = 1 barrel of crude oil   = 5,600 cubic feet of natural gas in Italy(1)
= 5,800 cubic feet of natural gas outside Italy(1)
1 barrel of crude oil per day   = approximately 50 tonnes of crude oil per year    
1 cubic meter of natural gas   = 35.3147 cubic feet of natural gas    

 


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1 cubic meter of natural gas   = approximately 0.0063 barrels of oil equivalent in Italy(1)    
    = approximately 0.0061 barrels of oil equivalent outside Italy(1)    
1 kilometer   = approximately 0.62 miles    
1 short ton   = 0.907 tonnes   = 2,000 pounds
1 long ton   = 1.016 tonnes   = 2,240 pounds
1 tonne   = 1 metric ton   = 1,000 kilograms
= approximately 2,205 pounds
1 tonne of crude oil   = 1 metric ton of crude oil   = approximately 7.3 barrels of crude oil (assuming an API gravity of 34 degrees)


(1)   The conversion factors for Eni’s natural gas in Italy and outside Italy differ due to the different product characteristics of such varieties of natural gas.

 


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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

     Financial information shown below has been extracted or derived from the audited consolidated financial statements of Eni. Starting from 1999, Eni publishes its consolidated financial statements in euro and has translated all lire amounts relating to consolidated financial statements for the year 1998 at the fixed official exchange rate of lire 1,936.27 = 1 euro. Although these statements depict the same trends as would have been shown had they been presented in lire, they may not be directly comparable to the financial statements of other companies that have also been restated in euro. Prior to the adoption of the euro, the currencies of other countries fluctuated against the lira, but as the euro did not exist prior to January 1, 1999, actual historical exchange rates for the euro are not available. A comparison of Eni’s financial statements for the year 1998 and those of other companies that historically used a reporting currency other than the lira that takes into account actual fluctuations in exchange rates could give a different impression than a comparison of Eni’s financial statements for the year 1998 and those of that company translated into euro.

                                           
      Years ended December 31,
     
      1998   1999   2000   2001   2002
     
 
 
 
 
      (million except number of shares and per share and per ADS data)
CONSOLIDATED INCOME STATEMENT DATA
                                       
Amounts in accordance with Italian GAAP:
                                       
Net sales from operations (1)
    28,341       31,008       47,938       48,925       47,922  

 


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      Years ended December 31,
     
      1998   1999   2000   2001   2002
     
 
 
 
 
      (million 5 except number of shares and per share and per ADS data)
Operating income:
                                       
 
Exploration & Production
    594       2,834       6,603       5,984       5,175  
 
Gas & Power (2)
    2,513       2,580       3,178       3,672       3,244  
 
Refining & Marketing
    730       478       986       985       321  
 
Petrochemicals
          (362 )     4       (332 )     (347 )
 
Oilfield Services and Engineering
    198       149       144       255       298  
 
Other activities
    (168 )     (199 )     (143 )     (168 )     (189 )
 
Activities to be divested
    (57 )                        
Operating income
    3,810       5,480       10,772       10,396       8,502  
Income before extraordinary items and income taxes (3)
    4,165       5,579       10,869       9,921       8,378  
Net income (2) (4)
    2,328       2,857       5,771       7,751       4,593  
Data per ordinary share (5) (5):
                                       
Operating income
    0.96       1.36       2.70       2.66       2.22  
Income before extraordinary items and income taxes
    1.04       1.40       2.72       2.54       2.19  
Net income
    0.58       0.71       1.44       1.98       1.20  
Data per ADS ($) (5):
                                       
Operating income
    5.57       6.92       12.66       11.83       11.65  
Income before extraordinary items and income taxes (3)
    6.09       7.04       12.77       11.39       11.48  
Net income
    3.40       3.61       6.79       8.82       6.29  
Amounts in accordance with U.S. GAAP (5) (6):
                                       
Net sales from operations
    25,587       28,369       45,488       45,848       43,632  
Operating income (7)
    3,409       4,880       9,819       8,853       7,861  
Income before extraordinary items and income taxes (3)
    3,617       4,912       10,067       10,330       8,350  
Net income
    2,064       2,873       5,758       6,317       5,292  
Data per ordinary share (5) (5):
                                       
Operating income
    0.82       1.18       2.42       2.21       2.00  
Income before extraordinary items and income taxes (3)
    0.90       1.22       2.52       2.64       2.18  
Net income Basic
    0.52       0.72       1.44       1.62       1.38  
                    Diluted
    0.52       0.72       1.44       1.62       1.38  
Data per ADS ($) (5):
                                       
Operating income
    4.77       5.96       11.36       9.83       10.49  
Income before extraordinary items and income taxes (3)
    5.29       6.20       11.83       11.76       11.44  
Net income Basic
    3.02       3.63       6.77       7.19       7.25  
                    Diluted
    3.02       3.63       6.77       7.19       7.25  

 


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    As of December 31,        
   
    1998   1999   2000   2001   2002
   
 
 
 
 
    (million 5 except number of shares)
CONSOLIDATED BALANCE SHEET DATA
                                       
Amounts in accordance with Italian GAAP:
                                       
Total assets, net
    41,336       46,197       56,363       62,736       65,808  
Short-term and long-term debt
    9,465       9,551       11,044       12,819       15,420  
Capital stock issued
    4,132       4,133       4,133       4,001       4,002  
Amounts in accordance with U.S. GAAP:
                                       
Total assets, net
    42,562       47,612       57,257       64,976       66,122  
Short-term and long-term debt
    9,367       9,389       10,810       12,379       15,320  
Capital stock issued
    4,132       4,133       4,133       4,001       4,002  
Other Financial Information
                             
Capital expenditure
    5,152       5,483       5,431       6,577       8,048  
Investments (including net borrowings of acquired companies)
    413       114       4,384       4,664       1,366  
Weighted average number outstanding of ordinary shares (shares million)
    4,001       4,001       3,994       3,910       3,826  
Dividend per share(E)
    0.310       0.362       0.424       0.750       0.750  
Dividend per ADS($) (8)
    1.61       1.70       1.81       3.71       3.93  


(1)   Eni is a party to certain Production Sharing Agreements (PSAs) whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint-venture partners which are state-owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA-related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production. Without this specific provision in its PSAs, Eni would otherwise be entitled to the sale proceeds of this portion of oil and gas production withheld. Starting in 1999, in order to be consistent with international practices, Eni began classifying the value of production equivalent to such taxes as revenues and the associated taxes in the appropriate income tax account. This had the effect of increasing revenues and income taxes by euro 203 million in 1999, as well as oil and gas reserves. Prior year amounts have not been reclassified since the effect of this change on net income is immaterial. See «Item 4—Information on the Company—Exploration & Production—Oil and Natural Gas Reserves—Note 1 on page 14».
 
(2)   Legislative Decree No. 164 dated May 23, 2000, requires Eni to unbundle its transmission and distribution activities from other businesses in the Natural Gas segment. In connection with such decree, Eni arranged for an independent appraisal of its transmission and distribution assets which resulted in estimates of the useful lives of such assets (40 years for pipelines and 50 for distribution networks). Such useful lives have also been confirmed by various reports issued by the Italian Authority for Electricity and Gas.

 


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    Effective January 1, 2000, assets related to transmission and distribution activities are now depreciated based on the useful lives established by the aforementioned appraisal and no longer on the basis of useful lives established by the Ministry of Economy and Finance based on technical studies conducted for homogeneous industries (10 and 8% for pipelines and distribution networks, respectively). This lower rate of depreciation resulted in an increase in operating income amounting to euro 663 million, an increase in income before minority interest amounting to euro 396 million and an increase in net income amounting to euro 312 million. Also note that effective from January 2002, the new Gas & Power division is responsible for Eni’s natural gas and electricity generation activities. For comparability, results of operations and financial data of the Natural Gas and Electricity Generation segments, which were reported separately until year 2001, have been aggregated.
 
(3)   Extraordinary income (expense) is as defined under Italian GAAP. These items would not qualify as extraordinary under U.S. GAAP. See Notes 27 and 28 to the Consolidated Financial Statements.
 
(4)   Net income for 1998 includes a deferred tax asset attributable to the effect of initial application of a new accounting standard related to income taxes amounting to euro 60 million.
 
(5)   Euro per Share or dollars per American Depositary Share (ADS), as the case may be. Eni Shareholders’ Meeting held on June 1, 2001 resolved to convert the nominal value of Eni Shares into euro by applying the fixed exchange rate of 1936.27 lire per euro; reduce the resulting nominal value of each share from euro 0.516 to euro 0.5; group two shares of nominal value euro 0.5 into one share with nominal value of 1 euro. The conversion, due to EU requirements, was effective from June 18, 2001. Starting from the same date, each ADS represents five Eni Shares. Consequently, all earnings per Share and earnings per ADS amounts in this selected financial data corresponding to prior periods have been restated to reflect the 2 for 1 reverse stock split. Earnings per share is calculated by dividing net income by the weighted-average number of shares issued and outstanding during the year, excluding treasury shares. In order to compare earnings per share to previous years, the number of shares issued through stock grants made in 2000, 2001 and 2002 has been added to the number of shares outstanding in previous years. The dilutive effect of potential ordinary shares when converted into ordinary shares on earnings per share is not material. At present, only shares assigned for no consideration are considered, as the conditions have not yet been met for the stock options to be exercised. See «Note 29 to the Consolidated Financial Statements — Stock Compensation». Data per ADS were translated at the Noon Buying Rate of December 31 for each year presented ($1.0485 = E1.00 at December 31, 2002). On June 20, 2003, the Noon Buying Rate was U.S. dollars 1.1616 = euro 1.00.
 
(6)   For information concerning certain differences between Italian GAAP and U.S. GAAP as applied to the Consolidated Financial Statements included elsewhere herein, see Notes 27 and 28 to the Consolidated Financial Statements.
 
(7)   See Note 28 to the Consolidated Financial Statements for details of operating income under U.S. GAAP by business segment for the last three years.
 
(8)   Except for year 2002, data have been translated into U.S. dollars using for each year presented the noon buying rate of the payment date.

 


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Selected Operating Information

     The table below sets 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, for the years ended and at December 31, 1998, 1999, 2000, 2001 and 2002. Such estimates of proved reserves have been prepared in accordance with Statement of Financial Accounting Standards No. 69 («SFAS 69»). See the unaudited supplemental oil and gas information on Note No. 29 to the Consolidated Financial Statements.

                                           
      Year ended at December 31,
     
      1998   1999   2000   2001   2002
     
 
 
 
 
Proved reserves at period end of:
                                       
 
oil (mm/BBL)
    2,881       3,137       3,422       3,948       3,783  
 
natural gas (BCF)
    13,515       13,665       14,772       17,072       18,629  
Proved reserves of hydrocarbons in mm/BOE at period end (1)
    5,255       5,534       6,008       6,929       7,030  
Finding and development costs per barrel of oil equivalent (three-year average) (2)
    5.16       5.43       5.35       6.28       6.78  
Reserve replacement ratio (3) (three-year average)
    183       174       173       226       204  
Reserve life index (4)
    13.4       14.0       14.0       13.7       13.2  
Average daily production of:
                                       
 
oil (KBBL/d)
    653       674       748       857       921  
 
natural gas (mmCF/d) (5)
    2,176       2,209       2,493       2,827       3,015  
Average daily production of hydrocarbons in KBOE/d (5)
    1,038       1,064       1,187       1,353       1,449  
Oil and gas production costs per barrel of oil equivalent (6)
    3.56       3.64       3.61       3.85       3.83  
Profit per barrel of oil equivalent (7)
    0.13       4.11       7.86       5.48       5.08  
Natural gas sales of primary distribution in Italy (8)
    55.69       60.24       59.92       58.89       52.56  
Natural gas sales of primary distribution in Europe (8)
                1.33       3.07       8.20  
Third-party transport of natural gas in Italy (8)
    6.07       6.90       9.45       11.41       19.11  
Length of natural gas distribution network in Italy at period end (9)
    28.7       29.0       29.1       29.6       29.8  
Electricity production sold (10)
                    4,766       4,987       5,004  
Refined products production (11)
    40.10       38.31       38.89       37.78       35.55  
Standard capacity of wholly-owned refineries (12)
    664       664       664       664       504  
Capacity utilization of wholly-owned refineries (13)
    103       96       99       97       99  
Service stations at period end (in Italy and outside Italy)
    12,984       12,489       12,085       11,707       10,762  

 


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      Year ended at December 31,
     
      1998   1999   2000   2001   2002
     
 
 
 
 
Average throughput per service station (14)
    1,512       1,543       1,555       1,621       1,674  
Petrochemicals production (15)
    8.29       8.30       8.53       7.83       9.58  
Oilfield services and engineering order backlog at period end (16)
    4,934       4,439       6,638       6,937       10,065  
Employees at period end (units)
    78,906       72,023       69,969       70,948       80,655  


(1)   Includes approximately 782, 756, 783, 728 and 779 BCF of natural gas held in storage in Italy at December 31, 1998, 1999, 2000, 2001 and 2002 respectively. See «Item 4. Information on the Company-Exploration and Production-Storage». For 1999 data see «Item 4. Information on the Company-Exploration & Production-Oil and Natural Gas reserves-Note 1 on page 14».
 
(2)   Consists of (i) the sum of costs incurred in respect of (a) acquisitions of unproved property and (b) exploration and development activities, divided by (ii) the increase in proved reserves attributable to (a) revisions of previous estimates, (b) improved recovery and (c) extensions and discoveries, in each case prepared in accordance with SFAS 69. In 2001 and 2002, excluding the purchase cost of unproved property of Lasmo, as well as cost incurred in connection with Iranian buy-back contract in year 2002, the indicator is 5.33 and 5.67 USD/boe respectively. See the unaudited supplemental oil and gas information in Note No. 29 to the Consolidated Financial Statements. Expressed in dollars.
 
(3)   Consists of (i) the increase in proved reserves attributable to (a) purchases of minerals in place, (b) revisions of previous estimates, (c) improved recovery and (d) extensions and discoveries, divided by (ii) production during the year as set forth in the reserve tables, in each case prepared in accordance with SFAS 69. See the unaudited supplemental oil and gas information in Note No. 29 to the Consolidated Financial Statements. Expressed as a percentage.
 
(4)   Consists of proved reserves at year-end divided by production during the year as set forth in the reserve tables, in each case presented in accordance with SFAS 69. See the unaudited supplemental oil and gas information in Note No. 29 to the Consolidated Financial Statements. Expressed on a yearly basis.
 
(5)   Natural gas production volumes exclude gas consumed in operations (94 mmCF/d and 132 mmCF/d in 2001 and 2002, respectively). See also «Item 4. Information on the Company-Exploration and Production-Production-Note 1 and 3 on page 16».
 
(6)   Consists of production costs (costs incurred to operate and maintain wells and field equipment) prepared in accordance with SFAS 69 divided by actual production net of production volumes of natural gas consumed in operations. See the unaudited supplemental oil and gas information in Note No. 29 to the Consolidated Financial Statements. Expressed in dollars.
 
(7)   Results of operations from oil and gas producing activities, divided by actual sold production, in each case prepared in accordance with SFAS 69. See the unaudited supplemental oil and gas information in Note No. 29 to the Consolidated Financial Statements. for a calculation of results of operations from oil and gas producing activities. Expressed in dollars.
 
(8)   Billions of cubic meters.
 
(9)   Thousands of kilometers.
 
(10)   Gigawatthour.
 
(11)   Millions of tons.
 
(12)   Thousands barrels/day.
 
(13)   Production as a percentage of capacity taking into account scheduled plant shutdowns.

 


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(14)   Thousands of liters per day.
 
(15)   Millions of tons.
 
(16)   The sum of the order backlog of Saipem SpA and Snamprogetti SpA, expressed in millions of euro.

Exchange Rates

     Italy is one of the eleven member states of the European Monetary Union that entered the single European currency which became effective on January 1, 1999; the other countries are Austria, Belgium, Finland, France, Germany, Ireland, Luxembourg, the Netherlands, Portugal and Spain. Greece entered the single European currency on January 1, 2001. The official fixing rate of the lira versus the euro is 1,936.27 lire per euro.

     The following table sets forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board). Exchange rates for the year 1998 are derived dividing the official fixing rate of the lira versus the euro by the Noon Buying Rates of the lira versus the U.S. dollar.

                                 
                            At
    High   Low   Average(1)   Period End
   
 
 
 
    U.S. dollars per euro
Year ended December 31
                               
1998
    1.06       1.22       1.11       1.17  
1999
    1.18       1.00       1.06       1.01  
2000
    1.03       0.83       0.92       0.94  
2001
    0.95       0.84       0.90       0.89  
2002
    1.05       0.86       0.95       1.05  


(1)   Average of the Noon Buying Rates for the last business day of each month in the period.
                         
                    At
    High   Low   Period End
   
 
 
    U.S. dollars per euro
December 2002
    1.0485       0.9927       1.0485  
January 2003
    1.0861       1.0361       1.0739  
February 2003
    1.0875       1.0708       1.0779  
March 2003
    1.1062       1.0545       1.0900  

 


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                    At
    High   Low   Period End
   
 
 
    U.S. dollars per euro
April 2003
    1.1180       1.0621       1.1180  
May 2003
    1.1853       1.1200       1.1766  
June 2003 (through June 20, 2003)
    1.1870       1.1616       1.1616  

     Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on Telematico and the dollar price of the ADSs on the NYSE. Cash dividends related to fiscal year 2002 will be paid by Eni SpA in euro in 2003 and exchange rate fluctuations will also affect the dollar amounts received by owners of ADSs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on June 20, 2003 was U.S. dollars 1.1616 = euro 1.00.

Risk Factors

     Competition

     There is strong competition worldwide, both within the oil industry and with other industries, in supplying energy to the industrial, commercial and residential energy markets. A number of Eni’s competitors have merged or may have the intention to merge and so lead to possibly stronger competition from competitors with greater financial resources. In its Exploration & Production business, particularly outside Italy, Eni encounters competition from other major international oil companies for exploration and development rights. In its natural gas business, Eni encounters increasingly strong competition from both national and international natural gas suppliers, also following the impact of the liberalization of the Italian natural gas market introduced by Legislative Decree No. 164/2000 which provides for, among other things, the opening of the entire Italian market to competition by 2003, limits to the size of gas companies relative to the market and third parties access to transport infrastructure. In its electricity business, Eni competes with other producers from Italy or outside Italy which sell electricity on the Italian market. In addition an uncertain regulatory framework and delays in the authorization process for the construction of new power plants on the part of public administrations prevent operators, amongst which Eni, from fully deploying their growth plans in the electricity business according to scheduled time. Eni faces competition from several major international oil companies in its refinery and refined product marketing businesses. In the retail market, Eni competes with third parties both in Italy and outside Italy (including major international oil companies, companies owned by oil producing nations and local operators) to obtain concessions to establish and operate service stations. Once established, Eni’s service stations compete primarily on the basis of services and availability of non-petroleum products. In Italy plans for the upgrading and efficiency improvement of a service station network can advance only in accordance with the evolution of the regulatory framework, which lags behind that of other major European countries. Eni also faces significant competition from certain international operators in the oilfield services contracting and engineering industries. Such competition is primarily on the basis of technical expertise, quality

 


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and number of services, availability of technologically advanced facilities (for example vessels, drilling plants etc.) and price.

     Cyclicality of Petrochemical Industry

     The petrochemical industry is subject to cyclical fluctuations in supply and demand, with consequent effects on prices and profitability exacerbated by the highly competitive environment of the industry. Eni’s petrochemicals operations, which are located mainly in Italy with certain plants located also outside Italy, have been in the past and may in the future be adversely affected by worldwide excess installed production capacity, as well as by economic slowdowns in many industrialized countries. The dislocation of petrochemical activities to geographical areas like the Far East and oil producing countries which provides long term competitive advantages has weakened the competitiveness of petrochemicals operations in industrialized countries, amongst which Eni’s own petrochemical operations. Petrochemicals operations in industrialized countries are also less competitive than those in the above-mentioned areas due to stricter regulatory frameworks and growing environmental concerns which prevail in industrialized countries.

     Political and Economic Considerations

     The production of oil and natural gas requires high levels of capital expenditure and entails particular economic risks and opportunities. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil or natural gas fields.

     The production of oil and natural gas is highly regulated and is subject to intervention 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. In addition, the oil and gas industry is subject to the payment of royalties and excise duties, which tend to be higher than those payable in respect of many other commercial activities.

     Crude oil prices are subject to international supply and demand and other factors that are beyond Eni’s control. OPEC member countries control production of a significant portion of the worldwide supply of oil and can exercise substantial influence over its price levels. International geopolitical tensions and political developments, including sanctions imposed on certain oil-producing countries on the basis of resolutions of the United Nations, can also affect world supply and prices of oil. Such factors can also affect the prices of natural gas because such prices are typically tied to the prices of certain refined petroleum products. Higher crude oil prices have a favourable impact on Eni’s results of operations and lower crude oil gives an adverse impact.

 


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     Substantial portions of Eni’s hydrocarbons reserves are located in countries outside the EU and North America, certain of which may be politically or economically less stable than EU or North American countries. At December 31, 2002, approximately 69% of Eni’s proved hydrocarbons reserves were located in such countries. See «Item 4 — Exploration & Production — Oil and Natural Gas Reserves». Similarly, a substantial portion of Eni’s natural gas supply comes from countries outside the EU and North America. In 2002, approximately 29% of Eni’s domestic supply of natural gas came from such countries. See «Item 4 — Gas & Power — Natural Gas Supplies». In August 1996, the United States adopted the Iran and Libya Sanctions Act (the «Sanctions Act»). The Sanctions Act requires the President of the United States to impose certain enumerated sanctions under certain circumstances on companies which engage in trade with or investment activities in Libya. Under the Sanctions Act, sanctions against Libya are expected to be applied until the President of the United States decides that Libya has complied with UN resolutions No. 731 of 1992 and No. 883 of 1993. Recent signs of a new Libyan attitude to the solution of existing controversies have led the UN to suspend Resolutions No. 731 and 883. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government with respect to the Sanctions Act. However, Eni does not believe that the Sanctions Act will have a material adverse effect on its financial condition or results of operations. For a description of Eni’s operations in Libya and Iran see «Item 4 — Information on the Company — Exploration and Production — North Africa and Rest of the World.»

     Liberalization of the Italian Natural Gas Market

     Legislative Decree n. 164 dated May 23, 2000 introduced rules for the liberalization of the Italian natural gas market which management believes will have a significant impact on Eni’s activity, as the company is present in all the phases of the natural gas chain. The decree, among other things, establishes:

    opening of the entire market to competition by 2003; this means that by then all customers are free to chose their supplier of natural gas;
 
    until December 31, 2010 antitrust thresholds to operators calculated as a percentage share of national consumption set as follows: (i) effective January 1, 2002 75% for imported or domestically produced natural gas volumes input in the national transport network and destined to sales; this percentage is to decrease by 2 percentage points per year until it reaches 61% in 2009; (ii) effective January 1, 2003 50% for sales to final customers. These ceilings are calculated on a three-year base net of losses (in the case of sales) and own consumption;
 
    the Authority for Electricity and Gas determines criteria for transport, dispatching, storage, use of LNG terminals and tariffs for natural gas for distribution by means of local networks;
 
    third parties are allowed to access infrastructure according to set conditions.

     In order to meet the medium and long-term demand of natural gas in particular of the Italian market, Eni entered into long-term purchase contracts with producing countries that currently have a residual average term of approximately 17 years. Existing contracts, which in general contain take-or-pay clauses, will ensure a total of about

 


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66 billion cubic meters of natural gas per year (Russia 28.5, Algeria 21.5, Netherlands 10 and Norway 6) by 2008. The above quantities are based on the annual contract quantity of the relevant contract. The average annual minimum quantity is approximately 85% of said quantities. In order to comply with the above mentioned regulatory thresholds relating to volumes input to the national transport network, Eni signed multi-annual contracts with third party importers to sell natural gas volumes exceeding said thresholds outside of the Italian territory; in prior years these volumes were imported into Italy and sold to Italian consumers by Eni. This change in the sale mix is structural and will adversely affect Eni’s results of operations. Further, management expects Eni’s margins on natural gas in Italy to come under pressure in future years due to the entry into the market of new competitors including the above mentioned third parties which purchase natural gas from Eni outside the Italian territory and resell it to Italian customers. Finally due to the antitrust threshold on direct sales in Italy, management expects Eni’s natural gas sales in Italy to increase at a rate that cannot exceed the growth rate of natural gas demand in Italy. Management believes all these developments might have a material adverse impact on Eni’s results of operations.

     To date Eni’s natural gas supply contracts have not entailed the application of take-or-pay clauses. Natural gas imports for the next few years have been programmed based on the highest flexibility allowed by longterm supply contracts, assuming that access capacity to the Italian network will be available in accordance with said flexibility. However, this assumption may be inconsistent with the current network code as established by the Authority for Electricity and Gas with decision No. 137 of July 17, 2002, in implementation of article 24, line 5 of Legislative Decree No. 164/2000. Decision No. 137 established priority criteria for the entitlement of transmission capacity at entry points from international networks into the domestic network. Entitlement periods can last no longer than five years. In particular it recognises priority access to take-or-pay contracts entered into before 1998, within the limit of the average daily contractual quantity. There is therefore no guaranteed access priority for the whole contractual flexibility. In fact, take-or-pay contracts entered by Eni before 1998 envisage Eni’s right to withdraw daily amounts larger than the average daily contractual amount; this contractual flexibility provided by the difference between the maximum daily amount Eni is entitled to and the average contractual daily amount is used in particular in winter. In the event of congestion at entry points, natural gas volumes not receiving a priority are assigned available transmission capacity on a pro-rata basis. Decision No. 137 establishes a transitional regime according to which for thermal year 2002-2003 access priority is granted also for two thirds of the difference between maximum contractual daily amounts and average daily amounts. For the thermal year 2003-2004, priority will be granted for only one third of that difference. On November 6, 2002 Eni filed a claim with the Regional Administrative Court of Lombardia requesting the annulment of decision No.137/2002 as Eni considers this decision non consistent with the overall rationale of the European natural gas framework, especially with reference to Directive 98/30/CE and Legislative Decree No. 164/2000. In case of an unfavourable outcome of this matter, management believes that Eni’s results of operations could be negatively affected should market conditions prevent Eni from selling its whole availability of natural gas under take-or pay contract obligations. See »Item 5—Management Expectations of Operations».

     On November 21, 2002 the Italian Antitrust Authority concluded the inquiry started on request of Blugas SpA concerning Eni’s alleged violation of competition rules, and acquitted Eni for the specific case of Blugas (deriving from the fact that in the spring-summer of 2001 Eni partially accepted Blugas’s request to access the network) but judged that Eni had abused of commanding position for having given, with the aim of respecting binding market thresholds, priority access to Italian purchasers with which Eni had entered supply contracts with volumes bought out of Italy supplied at entry points into the Italian network. The Antitrust Authority considers that these contracts infringe the rationale of article 19 of Legislative Decree No. 164/2000 which defines the limits for volumes to be input by a single operator into the national network. Given this infringing behavior and the lack of clarity of Italian regulations and Eni’s availability to increase the transmission capacity of gaslines outside Italy, the Antitrust Authority imposed on Eni a symbolic fine amounting to euro 1,000 and requested Eni to submit «a report indicating measures to be taken to eliminate infringing behaviors with specific attention to the upgrading of the transmission network or equivalent actions». Eni filed this report on March 6, 2003. On February 5, 2003 Eni filed a claim with the Regional Administrative Court of Lazio in Rome requesting the annulment of the measures taken by the Authority.

     Eni cannot predict the final outcome on this matter and future developments in the more general institutional debate ongoing on the liberalization of the natural gas market in Italy as confirmed by the joint official inquiry regarding the Italian gas market started in March 2003 by the Authority for electricity and gas and the Antitrust Authority with the aim of acquiring elements and information useful to define actions to improve competition. Management believes this is an area of concern and cannot exclude negative impacts on Eni’ s results of operations in future years.

     Environmental Regulation

     Together with other companies in the industries in which it operates, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, limit or prohibit drilling activities on certain protected areas, and impose criminal or civil liabilities for pollution resulting from oil, natural gas, refining and petrochemicals operations. These laws and regulations may also restrict air emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemicals plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the generation, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in particular operations and products of Eni, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. Although Eni, considering the

 


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actions already taken, the insurance policies to cover environmental risks and the provisions for risks accrued, does not currently expect any material adverse effect upon its results of operations and financial position as a result of its compliance with such laws and regulations, there can be no assurance that this will be the case due to: (i) the possibility of as yet unknown contamination; (ii) the results of the on-going surveys and the other possible effects of Decree No. 471/99 of the Ministry of Environment (which implements Legislative Decree No. 22/97, the “Ronchi Decree”); (iii) the possible effect of future environmental legislation and rules; (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

     Risks deriving from changes in oil prices and in natural gas, refined and petrochemical products prices and margins (1)

     Operating results in certain of Eni’s businesses, particularly the Exploration & Production, Refining & Marketing, Gas & Power and Petrochemical segments are affected by changes in the price of oil and by their impact on prices and margins of natural gas and refined and petrochemical products. Overall, higher oil prices have a net positive impact on Eni’s results of operations. The effect of higher oil prices on Eni’s average realized price of oil is generally immediate. However Eni’s average realized price for oil differs from the price of marker crude Brent due primarily to the circumstance that Eni’s production slate, including also heavy crudes, has a lower API gravity compared with Brent crude (when processed the latter allows for higher yields of valuable products compared to heavy crudes, hence higher market price). In addition changes in relative prices of Brent crude oil and heavy crudes cause changes in the results of operations of Eni’s Exploration & Production segment from one year to the year.

     A time lag exists between movements in oil prices and movements in the prices and margins of natural gas and refined and petrochemical products. In particular, the prices under natural gas purchase and sale contracts, which generally are for multiyear terms, are typically updated automatically by reference to the market prices of certain refined products and oil during a prior period, and therefore tend to mitigate the impact of changes in oil prices on Eni’s operating results. However, since Eni’s natural gas purchase and sale contracts are indexed to different refined products and types of oil, in different proportions and as measured over different reference periods, and are denominated in different currencies, Eni’s unit margins for natural gas may be significantly affected in the short term by variations in refined product and oil prices and exchange rates. In secondary distribution of natural gas, despite the passage of all customers from non eligible to eligible from January 1, 2003, the Authority for Electricity and Gas still establishes reference sale prices for non eligibile customers in order to allow for a gradual and regular transition to a free market, in accordance with the provisions of a Decree of the President of the Council of Ministers of October 31, 2002. In this segment, sale prices can be affected by Government regulations aimed at fighting inflation that limit the ability to transfer natural gas purchase costs onto the final sale price.

 


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     The results of operations of Eni’s Refining & Marketing segment are substantially affected by changes in European refining margins which reflect changes in relative prices of crude oil and refined products. Generally, a time lag exists between changes in oil prices and movements in refined products prices. In recent years the latter factor has more markedly influenced the trends in refining margins.

     Eni’s petrochemical products margins are affected by trends in demand and changes in oil prices which influence changes in cost of petroleum-based feedstock. Generally, an increase in oil price determines a decrease in petrochemical products margins on the short term. Prolonged weakness of international economy as well as Eni’s own structural weaknesses have prevented Eni’s Petrochemical segment from returning to profitability in recent years. Due to industry conditions and weak economic growth, management does not expect any significant improvement in petrochemicals segment profitability over the foreseeable future.

     Weather in Italy and Seasonality.

     Significant changes in weather conditions in Italy from year to year may cause variations in 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, may be affected by such variations in weather conditions. In addition, Eni’s results of operations reflect the seasonality in demand for natural gas and certain refined products used in residential space heating, the demand for which is typically highest in the first quarter of the year, which includes the coldest months, and lowest in the third quarter, which includes the warmest months.

     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 is denominated in euro. Similarly, prices of Eni’s petrochemical products generally are denominated in, or linked to, euro, whereas expenses in the Petrochemicals segment are denominated both in euro and U.S. dollars. Accordingly an appreciation of the U.S. dollar versus the euro generally has a positive effect on Eni results of operations, and vice-versa.

     Interest Rates.

     Interest on Eni’s debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, «EURIBOR» and the London Interbank Offered Rate, «LIBOR». As a consequence, movements in interest rates can have a material impact on Eni’s financial expense in respect of its net borrowings, which amounted to euro 11,141 million at December 31, 2002.

 


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     Uncertainties in Estimates of Oil and Natural Gas Reserves

     Numerous uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. Results of drilling, testing and production after the date of the estimate may require substantial upward and downward revision. In addition changes in oil and natural gas prices could have an effect on the quantities of Eni’s proved reserves because the estimates of reserves are based on prices and costs at the date when such estimates are made. In addition the reserves estimates are subject to revision as prices fluctuate due to the cost recovery feature under certain Production Sharing Agreements (PSA). Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered.

 


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Item 4.  INFORMATION ON THE COMPANY

History and Development of the Company

     Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, electricity generation, petrochemicals, oilfield services and engineering industries. Eni has operations in about 70 countries and 80,655 employees as of December 31, 2002.

     Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law 136 of February 10, 1953, was transformed into a joint stock company by Law Decree 333 of July 11, 1992 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 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, VAT number 00905811006, 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;
 
    San Donato Milanese (Milan), Piazza Ezio Vanoni, 1;
 
    Gela (Sicily), Strada Provinciale, 82.

     Internet address: www.eni.it

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

     Agip SpA was merged into Eni SpA effective as of January 1, 1997 to become Eni’s Exploration & Production division. Eni conducts its exploration and production activities through its Exploration & Production division and certain operating subsidiaries. Eni’s exploration, development and production activities commenced in 1926, when Agip was formed by the Government with a mandate to explore for and develop oil and natural gas. Exploration & Production operations are principally conducted in Italy, North Africa, West Africa, the North Sea and the Gulf of Mexico; it also operates in areas such as Latin America, Australia, the Middle and Far East and the Caspian Sea where Eni has recently entered. In 2002, Eni produced 1,449,000 BOE/d of hydrocarbons and, at December 31, 2002, it had estimated proved reserves of 7,030 mmBOE with a life index of 13.2 years. In 2002, Eni’s Exploration & Production segment had net sales from operations (including intersegment sales) of euro 12,877 million and operating income of euro 5,175 million.

     Snam SpA was merged into Eni SpA effective as of February 1, 2002 to become Eni’s Gas & Power division. Eni now conducts its natural gas and electricity generation activities through its Gas & Power division and certain operating subsidiaries. Eni natural gas supply, transmission and distribution activities commenced in the 1940s with the commercial sale of natural gas to industrial users in Northern Italy. In 2002, Eni’s primary distribution sales of natural gas totaled 52.56 billion cubic meters in Italy and 8.2 billion cubic meters in Europe. Primary distribution sales include sales to wholesalers, mainly local distribution companies, and large industrial and thermoelectric users which are supplied by a high and medium pressure gas pipeline network. Eni’s high and medium pressure gas pipeline network for primary distribution is about 30,000-kilometres long in Italy, while outside Italy Eni holds transmission rights on over 3,700 kilometers of high pressure pipelines. Effective on July 1, 2001 Eni’s natural gas transport network in Italy was conferred to Snam Rete Gas SpA. In December 2001 shares representing 40.24% of Snam Rete Gas capital were sold through an initial public offering with proceeds of euro 2.2 billion. Snam Rete Gas transports natural gas on behalf of Eni and third parties («shippers»); in 2002 transported volumes were 73.7 billion cubic meters, of which 19 billion on behalf of third parties. Eni operates directly in retail distribution (“secondary distribution”) of natural gas which includes almost exclusively sales made by local distribution companies to commercial and residential users through a low pressure gas pipeline network. Eni operates in secondary distribution in Italy through Italgas—the largest local distribution company in Italy—of wholly owned by Eni following the tender offer successfully closed in January 2003 and the subsequent squeeze-out of remaining minority shareholders. Eni also operates in secondary distribution activities outside Italy in Hungary through

 


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Tigaz, in Argentina through Distribuidora de Gas Cuyana and in Slovenia through Adriaplin. In 2002, Eni’s secondary distribution sales were 7.84 billion cubic meters in Italy and 3.79 billion cubic meters outside Italy. Eni’s secondary distribution network in Italy is over 46,000-kilometres long and over 30,000-kilometres long outside Italy.

     Eni conducts its electricity generation activities through Enipower SpA which owns and manages Eni’s power stations of Livorno, Taranto, Mantova, Ravenna and Brindisi with a total installed capacity of 1,000 megawatts and annual production sold of about 5,000 gigawatthour. Eni owns other minor power stations located in Eni’s petrochemical plants and refineries whose production is mainly for internal consumption. The accounts of these power stations are reported within Eni’s Refining & Marketing and Petrochemicals segment.

     In 2002, Eni’s Gas & Power segment had net sales from operations (including intersegment sales) of euro 15,297 million and operating income of euro 3,244 million.

     AgipPetroli SpA was merged into Eni SpA effective January 1, 2003 to become Eni’s Refining & Marketing division. Eni now conducts its refining and marketing activities through the Refining & Marketing division and certain operating subsidiaries. Activities commenced in the 1930s, when Eni initiated the development of the industrial and retail markets for refined products in Italy. Eni’s refining and marketing activities are located primarily in Italy, Europe and Latin America. Eni has the largest retail market share of refined products retail in Italy, equal to 37.5% of such market; its brands are Agip and IP. In 2002, sales of refined products totaled 52 million tons, of which 33 million in Italy. Eni’s total processing capacity of wholly-owned refineries amounted to 504,000 barrels per day at December 31, 2002. In 2002, Eni’s Refining & Marketing division had net sales from operations (including intersegment sales) of euro 21,546 million and operating income of euro 321 million.

     Eni’s petrochemical activities commenced in the 1950s, when it began production of basic petrochemicals at its Ravenna industrial complex. Through Polimeri Europa SpA and EniChem SpA (now Syndial SpA) and their subsidiaries, Eni operates in olefins and aromatics, basic intermediate products, chlorine derivatives, polyethylene, polystyrenes and elastomers. Eni’s petrochemical operations are concentrated in Italy and in Western Europe. In 2002, Eni sold 6.3 million tons of petrochemical products. In 2002, Eni’s Petrochemicals segment had net sales from operations (including intersegment sales) of euro 4,781 million and an operating loss of euro 347 million.

     Eni’s oilfield services and engineering activities commenced in the late 1950s. Through Saipem SpA (a 43% owned subsidiary) and its subsidiaries, Eni operates in offshore construction, in particular subsea pipe laying and floating production systems. Eni owns and operates a fleet of world class marine service vessels, able to drill wells 10,000 meters deep in water depths of up to 3,000 meters and to lay pipelines up to 60 inches in diameter in water depths up to 2,150 meters. Through Snamprogetti SpA (a wholly owned subsidiary) and its subsidiaries Eni is a provider of engineering and project management services to the oil and petrochemical industries. In 2002, Eni’s Oilfield Services and Engineering segment had net sales from operations (including intersegment sales) of euro 4,546 million and operating income of euro 298 million.

     Strategy

     Eni intends to maintain strong hydrocarbon production growth by developing existing projects and continuing its program of rationalisation of its mineral asset portfolio aimed at increasing its value by focusing on strategic areas with sound growth potential and exiting marginal ones. In gas activities Eni intends to increase sales in European markets and maintain sale levels in Italy by leveraging on expected natural gas demand growth, an effective marketing policy and the development of power generation capacity in its industrial plants.

     In the downstream oil segment Eni intends to reposition its activities by completing the upgrading of its distribution network in Italy and developing its presence in selected areas in Europe, where it can leverage on operating synergies and a well established brand.

     In oilfield services and engineering activities, Eni intends to concentrate its presence in the strategic segments of: (i) large projects for the development of offshore hydrocarbon reserves; (ii) construction of industrial complexes based on the application technologies for hydrocarbon production, treatment and transmission as well as the upgrading of natural gas and heavy crudes.

 


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     At the same time, Eni intends to reduce capital employed in non core businesses and to integrate its core activities in order to support international growth by means of integrated projects and improve its competitive positioning. Management plans to continue improving efficiency levels working on cost structure and capital expenditure processes.

     Strong attention will be devoted to R&D, which management believe to be the key factor for the future development of the oil industry. Eni intends to increase financial resources dedicated to this activity; in addition, management intends to focus resources on those strategic projects through which Eni believes to achieve competitive advantages in the medium to long term.

     Eni intends to pursue its growth strategy by implementing a four-year capital expenditure plan of euro 23 billion, about 80% of which in the Exploration & Production and Gas & Power segments. Management expects cash flow from operations to satisfy financial requirements related to new capital expenditure, the payment of dividends and the share buy-back program, while at the same time leaving enough resources to finance additional growth options in core activities.

     Recent developments

     The most significant events in the development of Eni occurred during 2002 and to date in 2003 were the following:

    Within its strategy of commercial policy integration and development of its natural gas segment also at international level, on November 25, 2002 Eni launched a public tender offer on all Italgas SpA ordinary shares outstanding not owned directly or indirectly by Eni, corresponding to approximately 56% of Italgas’ share capital. Eni offered a price of euro 13 per share, to be fully paid in cash. The public offering successfully closed on January 27, 2003 and Italgas shares were withdrawn from listing on the Italian Stock Exchange effective on February 7, 2003. Following the squeeze-out of the remaining minority shareholders, Eni now owns 100% of the share capital of Italgas. Total consideration paid pursuant to the tender offer amounted to approximately euro 2.5 billion;
 
    In March 2003 Eni completed the purchase of the Norwegian oil company Fortum Petroleum AS, which in 2002 produced 39 KBOE/d and held proved reserves of 159 mmBOE as of December 31, 2002. Total consideration plus financial debt acquired amounted to U.S. dollar 975 million. Management expects this acquisition to increase Eni’s hydrocarbon production in Norway in 2003 by approximately 40% from current level (94 KBOE/d);
 
    Eni is pursuing a program for the rationalization of its portfolio of mineral assets aimed at concentrating its activities in areas with significant growth potential where Eni is the operator: in 2002 Eni sold 16 interests in fields in the North Sea, Italy and Qatar, as well as exploration permits and other assets; total proceeds amounted to euro 390 million. At the same time Eni acquired interests in operated or partially held assets in Kazakhstan, the United Kingdom, Norway and Australia for a total consideration of euro 317 million;
 
    Within the North Caspian Sea PSA (of which Eni is single operator with a 16.67% interest) the importance of the Kashagan oil field discovery in the Kazakh offshore of the Caspian Sea was confirmed by the appraisal activities performed and underway in the area. According to the management, this field represents the most important discovery in the oil industry of the past thirty years;
 
    In Libya, within the development (of which Eni is operator with a 50% interest) of the natural gas, oil and condensates fields of Wafa in the NC-169 A onshore permit and of Bahr Essalam (former structure C) in the NC-41 offshore permit, EPIC/EPC contracts were awarded for the construction of hydrocarbon treatment plants, an offshore production platform and relevant infrastructure. Management expects production to start in 2004 at Wafa and in 2005 at Bahr Essalam. Natural gas produced from both fields is planned to be transmitted to Italy trough an underwater pipeline linking Mellitah on the Libyan coast to Gela in Sicily. Management expects the laying of the pipeline to start in the second half of 2003 and transport operations to start in 2005. Natural gas volumes are projected to reach 8 billion cubic meters per year (Eni’s share is 4 billion). Such volumes have already been booked by operators in the natural gas sector under long-term supply contracts. Eni’s share of the total capital expenditure for the whole project amounts to euro 3.8 billion; of which 3.2 billion for the upstream phase;

 


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    In Angola, in Block 15 (Eni’s interest 20%) development is ongoing of the oil fields discovered in the Kizomba area. This project is going to be carried out in phases. The first one, under completion, concerns the development of the Hungo and Chocalho fields; management expects production to start in 2004. For the purposes of the second phase, concerning the development of the Kissanje and Dikanza fields expected to start up in 2005, in January 2003 an FPSO vessel with a 250,000 KBBL/d treatment capacity and storage capacity of 2 million barrels was commissioned. Eni’s share of capital expenditure for the two phases amounts to U.S. dollar 1.29 billion;
 
    Eni and EnBW (Energie Baden-Württemberg AG, a German operator in electricity) acquired through a 50/50 German joint venture (EnBW-Eni Verwaltungsgesellschaft mbH) a 97.81% interest in GVS (Gasversorgung Süddeutschland GmbH), a regional operator in natural gas distribution in Germany GVS transports and sells approximately 7 billion cubic meters per year. The joint venture partners financed the transaction through a capital increase of about euro 178 million (Eni share is euro 89 million) as well as recourse to financial markets. The acquisition of GVS marks Eni’s entrance in a large natural gas market;
 
    Within its strategy of international expansion of gas activities, on March 14, 2003 Eni reached a final agreement with Spanish company Unión Fenosa SA for the purchase of a 50% interest in its subsidiary Unión Fenosa Gas. This transaction will be completed after the granting of authorizations by the relevant antitrust authorities; management expects Eni to pay euro 440 million as consideration. The transaction when finalised represents an important step in Eni’s strategy of international expansion and will strengthen Eni’s presence in the Spanish natural gas market, which management believes to have growth prospects and where Eni intends to increase its market share;
 
    The Blue Stream underwater pipeline linking Russia to Turkey through the Black Sea for the transportation of natural gas from Russia to the Turkish market was completed by the end of 2002. Commercial operations started in February 2003; management plans to supply the Turkish market with a maximum amount of 16 billion cubic meters of natural gas per year (Eni’s share is 8 billion cubic meters);
 
    Eni transferred its Priolo Refinery in Sicily to a newly established company in which Eni holds a minority stake (20%). Management plans to reduce progressively Eni’ refinery intake for its own account, targeting a reduction of 7.5 million tonnes per year by year 2006. Accordingly this transaction represents an important step in Eni’s strategy of downsizing its refining system, aimed at better balancing its own production with demand and at increasing supply flexibility;
 
    Eni continued its program for the restructuring of its distribution network in Italy, aimed at reaching European standards in terms of average throughput and services to customers. In 2002, Eni sold 246 service stations, closed down 549 service stations and upgraded its main network by building and purchasing about 150 owned and leased service stations. Average throughput in Italy increased by 3.9%. In 2003, management plans to sell further 330 service stations following agreements already finalized;
 
    Eni, through its subsidiary Saipem, purchased 100% of share capital of Bouygues Offshore through a public tender offer. Saipem offered a price of euro 60.08 per share, to be fully paid in cash. Total consideration amounted to euro 906 million (net of cash acquired for euro 100 million). The combination of Saipem’s construction capabilities supported by technologically advanced vessels and Bouygues Offshore’s engineering and project management expertise will strengthen Eni’s competitive position in the segment of large EPIC projects for the development of hydrocarbon fields.

     In 2002 Eni invested about euro 8 billion in new capital expenditure and financial investments. Capital expenditure (euro 6.6 billion) referred principally to the development of hydrocarbons reserves and exploration expenditure, the development and upgrade of Eni’s natural gas transport system, the expansion of power generation capacity, the maintenance of refineries as well as the upgrading of Eni’s network of service stations. Financial investments (euro 1.4 billion) referred in particular to the acquisition of 100% of Bouygues Offshore.

     In 2001 Eni invested about euro 11.3 billion in new capital expenditure and financial investments. Capital expenditures (euro 6.6 billion) referred principally to the development of hydrocarbons reserves and exploration expenditure, the development and upgrade of Eni’s natural gas transport system, the maintenance of refineries and petrochemicals plants as well as the upgrading of Eni’s network of service stations. Financial investments (euro 4.7 billion, including net borrowings) referred in particular to the completion of the acquisition of Lasmo for a total of euro 4,128 million (including net borrowings for about euro 970 million)

 


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and the purchase of 50% of Polimeri Europa — the remaining 50% already owned by Eni — (euro 204 million). Main divestment occurred in 2001 concerned: (i) 40.24% of share capital of Snam Rete Gas, a company indirectly wholly-owned by Eni, through means of an initial public offering and a private placement to foreign professional and institutional investors. The offering price was set at euro 2.8 per share with. Total consideration from the offering amounted to euro 2.2 billion in cash; (ii) 100% of share capital of Immobiliare Metanopoli, a wholly owned Eni’s subsidiary, as well as other Eni’s real estate for total consideration of euro 754 million in cash; (iii) the polyurethane business to Dow Chemical for a consideration of euro 428 million, of which euro 128 million in cash, euro 204 million corresponding to a 50% interest in Polimeri Europa (of which Eni already owns 50%) and euro 96 million of royalty rights for the use of Dow proprietary technology.

     In 2000, Eni invested about euro 9.8 billion in new capital expenditures and financial investments. Capital expenditure in 2000 (euro 5.4 billion) referred principally to the development of hydrocarbon reserves, exploration expenditure, the acquisition of proved and unproved reserves of hydrocarbons, the development and upgrade of Eni’s natural gas transport system, the maintenance of refineries and petrochemicals plants as well as the upgrading of Eni’s network of service stations. Financial investments (euro 4.4 billion, including net borrowings) referred in particular to the purchase of 28% of the share capital of Lasmo Plc as a result of a Public Offering launched by Eni on December 31, 2000 (euro 1,225 million), the acquisition of British-Borneo for euro 1,263 million (847 are net borrowings) and of 33.34% of Galp (euro 964 million).

BUSINESS OVERVIEW

Exploration & Production

     Eni operates in the exploration and production of hydrocarbons in Italy, North Africa, West Africa, the North Sea and the Gulf of Mexico. It also operates in areas with great development potential such as Latin America, Australia, the Middle and Far East and the Caspian Sea.

     In 2002, Eni’s Exploration & Production segment had net sales from operations (including intersegment sales) of euro 12,877 million and operating income of euro 5,175 million.

     Eni is pursuing an aggressive production growth strategy aimed at achieving a daily production target in excess of 1.8 million boe by 2006, which corresponds to an annual increase of approximately 6% over the next four years. Management plans to increase production by developing in areas where Eni has a consolidated presence and through the start-up of important projects in Libya, the deep offshore of West Africa, Iran and Kazakhstan. Eni intends to continue the rationalization of its asset portfolio, started after the purchase of British-Borneo Plc and Lasmo Plc, in order to increase its value by focusing on strategic areas with the highest growth potential and exiting marginal areas with limited growth prospects. Management plans to concentrate exploration expenditure in areas with high mineral potential, capable of providing the highest returns. In 2002, beside the successful continuation of exploration activities in the Caspian Sea, Eni made discoveries in Italy, Egypt, Angola and Nigeria. Eni will continue to improve its performance by searching for operating solutions aimed at reducing operating costs and increasing synergies.

     Oil and Natural Gas Reserves

     Eni’s proved reserves of hydrocarbons at December 31, 2002 totaled 7,030 mmBOE (oil and condensates 3,783 mmBBL; natural gas 18,629 BCF), increasing by 101 million boe over 2001, due to: (i) new discoveries and extensions (338 mmBOE), in particular in Nigeria, Kazakhstan, Australia and Italy; (ii) revisions of previous estimates (337 mmBOE), in particular in Kazakhstan, Angola and Nigeria; (iii) acquisitions (39 mmBOE), in particular interests in fields in the British and Norwegian sections of the North Sea and Australia; (iv) improved recovery (15 mmBOE) in particular in Algeria. Increases in proved reserves were offset in part by production for the year and the sale of interests in fields in Italy, Qatar and the British section of the North Sea (96 mmBOE). The increase in proved reserves allowed to replace 119% of production; this average was 129% without taking into account the effect of rationalizations. The average reserve life index is 13.2 years (13.7 in 2001).

 


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     Proved developed reserves at December 31, 2002, amounted to 3,703 mmBOE (2,241 mmBBL of oil and condensates and 8,354 BCF of natural gas) representing 53% of total estimated proved reserves (54% and 50% at December 31, 2001 and 2000, respectively).

     The table below sets forth a geographical breakdown of Eni’s estimated proved reserves of hydrocarbons, on a barrel of oil equivalent basis, for the periods indicated.

                                         
    Year ended December 31,
   
    1998   1999 (1)   2000   2001   2002
   
 
 
 
 
    (mmBOE)
Italy
    1,574       1,477       1,389       1,315       1,199  
North Africa
    1,686       1,849       1,929       2,122       2,033  
West Africa
    910       1,067       1,093       1,136       1,287  
North Sea
    666       646       700       879       825  
Rest of World
    419       495       897       1,477       1,686  
     
     
     
     
     
 
Total
    5,255       5,534       6,008       6,929       7,030  
     
     
     
     
     
 


(1)   Eni is a party to certain Production Sharing Agreements (PSAs) whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint-venture partners which are state-owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA-related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production. Without this specific provision in its PSAs, Eni would otherwise be entitled to the sale proceeds of this portion of oil and gas production withheld. Starting in 1999, in order to be consistent with international practices, Eni began classifying the tax oil withheld directly by its joint-venture partners which are State-owned entities as an increase of revenues and income taxes (in prior years such taxes were settled against revenues with respect to such Agreements). This had the effect of increasing revenues and income taxes by euro 203 million in 1999, as well as oil and gas reserves. Prior year amounts have not been reclassified since the effect of this change on net income is not significant. The application of this new presentation resulted in an increase of 46,000 boe/day (41,000 barrels/day of oil; 29 mmCF/d of natural gas) in hydrocarbon production and of 398 million boe in proved reserves (222 million barrels of oil; 1,021 BCF of natural gas) in 1999.

     For additional information regarding Eni’s estimated proved reserves and proved developed reserves of crude oil and natural gas, see the unaudited supplemental oil and gas information on pages F-66 to F-73.

     Exploration and Development

     As of December 31, 2002, Eni’s portfolio of mineral rights consisted of 1,161 exclusive or shared rights for exploration and development in 37 countries on five continents, for a total net acreage of 281,682 square kilometers (317,283 at December 31, 2001). Of these, 41,578 square kilometers concerned production and development (41,841 at December 31, 2001). Net acreage decreased in Italy by 5,333 square kilometers, due to releases, and outside Italy by 30,268 square kilometers, due to releases in particular in Brazil, Pakistan, Egypt, Algeria and Guyana, and sales of mineral rights in Italy and Qatar. Increases were registered in Australia, Norway and Indonesia.

     A total of 120 new exploratory wells were drilled (52 of which represented Eni’s share), as compared to 110 exploratory wells completed in 2001 (47 of which represented Eni’s share).

     Overall success rate was 38.6% (39.1% of which represented Eni’s share) as compared to 36.5% (31.3% of which represented Eni’s share) in 2001.

     Exploration expenditure amounted to euro 902 million, of which 93% outside Italy, with a 19.2% increase over 2001. Outside Italy exploration concerned mainly the United States, Kazakhstan, Egypt, Angola, Russia and Brazil; in Italy mainly the deep waters of the Sicily Channel and areas in central-southern Italy.

     Capital expenditure for the purchase of mineral rights (euro 317 million) concerned primarily the purchase of: (i) a 2.39% interest in the North Caspian Sea PSA, where the Kashagan field is located (Eni is the single operator with a 16.67% interest in the PSA after the purchase) in Kazakhstan; (ii) a 5.6% interest in the Bayu Undan field (Eni’s interest 12.32% after the purchase) in Australia; (iii) an 11.3% interest in the T- Block fields (Eni is operator with an 88.7% share after the purchase) in the British section of the North Sea;

 


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(iv) a 7.9% interest in the Mikkel field in Norway; (v) an 8.9% interest in the Liverpool Bay fields (Eni’s interest is 53.9% after the purchase) in the Irish Sea.

     Expenditure for development and capital goods totaled euro 4,396 million, of which 89% outside Italy, an increase of 27.3% over 2001. Development expenditure outside Italy concerned fields in Nigeria, Iran, Libya, Kazakhstan, Angola, Venezuela and the United Kingdom. Development expenditure in Italy referred in particular to the continuation of construction of plant and infrastructure in the Val d’Agri. Total capital expenditure in 2002 amounted to euro 5,615 million, increasing by euro 1,339 million over 2001, up 31.3%.

     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 2002 hydrocarbon production amounted to 1,449 KBOE/d (oil and condensates 921 KBBL/d; natural gas 3,015 mmCF/d) increasing by 96 KBOE/d over 2001, up 7.1%, despite the 26 KBOE/d effect of production cuts decided by OPEC and the 8 KBOE/d effect of the rationalization of Eni’s mineral rights portfolio. The production increase was due to: (i) start-up of fields mainly in Algeria, the United States, Nigeria, Iran, Trinidad & Tobago and Pakistan; (ii) production increases recorded mainly in Algeria, Kazakhstan, the United States, Egypt, Norway, the United Kingdom, Italy and Congo. These increases were partly offset by the production decline of mature gas fields in Italy. The share of production outside Italy reached 78.5% (77.5% in 2001).

     Daily production of oil and condensates (921 KBBL/d) increased by 64 KBBL/d, up 7.5%, due to increases registered outside Italy (up 80 KBBL/d) in particular in: (i) Algeria, due to the start-up of the HBNSE/BKNE/RBK fields (Eni’s interest 12.25%) and the reaching of full production at the HBN field (Eni’s interest 34.63%); (ii) Kazakhstan, due to the fact that in the third quarter of 2001 production at the Karachaganak field (co-operated by Eni with a 32.5% interest) was suspended due to a fiscal dispute between Russia and Kazakhstan; (iii) Congo due to the start-up of the Foukanda and Mwafi fields (Eni is operator with a 65% interest) in the second half of 2001; (iv) the United Kingdom, due to the full operation of the Elgin/Franklin fields (Eni’s interest 21.87%). In Italy production increased by 17 KBBL/d due to the reaching of full operation of the Monte Alpi pipeline which transports oil produced in the Val d’Agri fields to Eni’s refinery in Taranto. These increases were partly offset by a 33 KBBL/d reduction outside Italy due mainly to production cuts decided by OPEC.

     Production of natural gas (3,015 mmCF/d) increased by 188 mmCF/d, up 6.7%, due to increases registered outside Italy (up 241 mmCF/d), in particular in Egypt, the United States (in connection with the start-up of the King Kong/Yosemite field — Eni’s interest 50%), Kazakhstan (due to the reasons mentioned above), the United Kingdom and Norway. These increases were offset in part by the production decline of mature fields (down 53 mmCF/d) in Italy, in particular the Porto Garibaldi/Agostino and Luna fields.

     Hydrocarbon production sold amounted to 523.1 million boe. The 5.8 million boe decrease over production was due essentially to lower withdrawals with respect to entitlements outside Italy (3.4 million boe) and to production volumes of natural gas input to storage (1.8 million boe). About 75% of oil and condensate production sold (333.4 million barrels) was transferred to the Refining & Marketing division (68% in 2001). About 44% of natural gas production sold (30.68 billion cubic meters) was transferred to the Gas & Power division (47% in 2001).

     The tables below set forth Eni’s production(1) of oil and condensates and natural gas for the periods indicated.

 


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Production of oil and condensates

                                         
    Year ended December 31,
   
    1998   1999   2000   2001   2002
   
 
 
 
 
                    (KBBL/d)                
Crude Oil and Condensates (2)
                                       
Italy
    100       88       76       69       86  
North Africa
    213       221       227       228       252  
West Africa
    194       202       213       219       222  
North Sea
    112       116       124       204       213  
Rest of the World
    34       47       108       137       148  
   Total
    653       674       748       857       921  

Natural gas production available for sale

                                         
    Year ended December 31,
   
    1998   1999   2000   2001   2002
   
 
 
 
 
                    (mmCF/d)                
Natural Gas (2) (3)
                                       
Italy
    1,648       1,511       1,438       1,313       1,260  
North Africa
    132       278       454       497       560  
West Africa
    14       21       67       82       87  
North Sea
    254       222       258       450       516  
Rest of the World
    128       177       276       485       592  
   Total
    2,176       2,209       2,493       2,827       3,015  


(1)   Production information set forth above differs from production as reported in the reserve tables in Note 29 to the Consolidated Financial Statements — Supplemental oil and gas information (unaudited) because yearly production presented in such reserve tables is based on estimates taken in November of each year and the information above sets forth actual production during the year. Furthermore, Eni’s production of natural gas reported in such reserve tables includes, in addition to sold production, production volumes of natural gas consumed in operations. Natural gas produced and reinjected into storage fields in Italy remains part of Eni’s reserves for each period.
 
(2)   For 1999 data see note 1 on page 13.
 
(3)   Natural gas production consumed in operations in countries where an alternative market exists is excluded from production. The effect was of 94 mmCF/d and 132 mmCF/d in 2001 and 2002, respectively.

     Storage

     Eni’s storage system in Italy is made up of a number of depleted fields used for the purposes of supply modulation in accordance with seasonal swings in demand (natural gas is stored in the summer and used in the winter), strategic reserve and mineral storage to ensure supply and to support domestic production. The present storage system is made up of 9 fields, 8 of which are located in northern Italy (one of them is not yet operational) and one in central Italy, on the basis of nine storage concessions vested by the Minister of Productive Activities.

     As provided for by article 21 of Legislative Decree No. 164/2000, which imposed the separation of storage activities from natural gas production and sale activities, on October 31, 2001 Eni SpA and Snam SpA contributed their storage business units to Stoccaggi Gas Italia SpA, a company established for this purpose in November 2000 and wholly owned by Eni SpA. This contribution concerned, among other assets, 749 BCF of natural gas, of which 378 BCF of so called working gas, that can be withdrawn without prejudice to general field performance, and 371 BCF representing the so called cushion gas necessary for allowing working gas volumes to be withdrawn.

     On February 27, 2002 the Italian Authority for Electricity and Gas (the «Authority») issued decision No. 26 containing the criteria for the determination of tariffs of natural gas storage for the first regulated period (from April 1, 2002 to March 31, 2006) and, retroactively, from June 21, 2000. With reference to these criteria, on March 18, 2002 Stoccaggi Gas Italia presented its suggested tariffs for supply modulation, mineral and strategic storage services for the first regulatory period. The Authority rejected Stoccaggi Gas Italia’s

 


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proposal and, in order to enact its decision No. 26, set storage tariffs for the thermal year 2002-2003 with its decision No. 49 of March 26, 2002. Stoccaggi Gas Italia currently applies the tariffs set by the Authority, and appealed both Authority decisions against the Regional Administrative Court of Lombardia in order to seek their repeal. The proceeding is still pending.

     In 2002, following optimization measures on existing fields that increased capacity by 13% (from 6.3 to 7.1 billion cubic meters), higher storage volumes have been made available for modulation services.

     The table below sets forth certain information and operating data regarding Eni’s principal oil and natural gas interests at and for the year ended December 31, 2002.

                                                                         
                                                                    % of Eni’s
                                    Number   Number                   Total Oil
            Number                   of   of   Production   Production   and
    Commencement   of   Net           producing   other   of   of   Natural Gas
    of operations   interests   acreage(1)   Type of fields   fields   fields(2)   Crude Oil(3)   Natural Gas(4)   Production
   
 
 
 
 
 
 
 
 
Italy
    1926       280       43,961     Onshore/Offshore     97       85       86       1,260       21.5  
North Africa
                                                                       
Algeria
    1981       27       6,527     Onshore     13       15       65             4.5  
Egypt
    1954       38       28,305     Onshore/Offshore     34       24       97       547       13.2  
Libya
    1959       7       21,268     Onshore/Offshore     8       10       79             5.5  
Tunisia
    1961       11       3,451     Onshore/Offshore     7       5       11       13       1.0  
 
            83       59,551               62       54       252       560       24.1  
West Africa
                                                                       
Angola
    1980       37       4,157     Offshore     34       32       62             4.3  
Congo
    1968       17       7,507     Offshore     16       8       75             5.2  
Gabon
    1981       4       11,297     Offshore     1             2             0.1  
Nigeria
    1962       55       8,385     Onshore/Offshore     118       130       83       87       6.8  
 
            113       31,346               169       170       222       87       16.4  
North Sea
                                                                       
Norway
    1964       30       2,768     Offshore     8       10       74       108       6.3  
The Netherlands
    2001       1       22     Offshore     2                   9       0.1  
United Kingdom
    1964       81       3,445     Offshore     46       25       139       399       14.4  
 
            112       6,235               56       35       213       516       20.8  
Rest of World
                                                                       
China
    1983       4       7,327     Onshore/Offshore     6       6       10             0.7  
Croatia
    1996       2       3,018     Offshore     1       6             32       0.3  
Ecuador
    1988       1       2,000     Onshore     1       1       22             1.5  
Indonesia
    2001       9       15,187     Onshore/Offshore     8       9       5       191       2.6  
Iran
    1957       4       423     Onshore/Offshore     1       3       3             0.2  
Kazakhstan
    1995       2       1,030     Onshore/Offshore     1       1       32       147       4.0  
Pakistan
    2000       11       8,193     Onshore     3       4             40       0.5  
Qatar (5)
    1992                                     5             0.3  
Trinidad & Tobago
    1970       2       621     Offshore     1       3             13       0.1  
United States
    1968       488       3,196     Offshore     15       5       29       169       4.0  

 


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                                                                    % of Eni’s
                                    Number   Number                   Total Oil
            Number                   of   of   Production   Production   and
    Commencement   of   Net           producing   other   of   of   Natural Gas
    of operations   interests   acreage(1)   Type of fields   fields   fields(2)   Crude Oil(3)   Natural Gas(4)   Production
   
 
 
 
 
 
 
 
 
Venezuela
    1998       2       630     Onshore/Offshore     6       1       42             2.9  
 
            525       41,625               43       39       148       592       17.3  
Other countries with only exploration activity
            48       98,964                     6                    
Outside Italy
            881       237,721               330       304       835       1,755       78.5  
 
           
     
             
     
     
     
     
 
Total
            1,161       281,682               427       389       921       3,015       100.0  
 
           
     
             
     
     
     
     
 


(1)   Square kilometers.
 
(2)   Includes non producing fields.
 
(3)   KBBL/d Includes condensates and natural gas liquids.
 
(4)   mmCF/d.
 
(5)   Assets in Qatar were sold effective from May 2002.

     Eni’s principal regions of operations are described below.

     Italy

     In 2002, Eni’s hydrocarbon production in Italy totaled 311,000 boe/day and represented 21.5% of Eni’s total production. Eni’s exploration and development interests in Italy are concentrated in the Po Valley, the Adriatic Sea, the Central Southern Apennines, Sicily and the Sicilian offshore.

     Production of oil in Italy totaled 86 KBBL/d. Eni’s three major fields, Val d’Agri in Southern Italy, Villafortuna in the Po Valley and Aquila in the southern Adriatic offshore, represented 72% of Eni’s total production in Italy. In particular, the Val d’Agri fields increased production from 12,000 barrels/day in 2001 to 37,000 in 2002, with a share of total production increasing from 18.6% in 2001 to 42.6% in 2002, due to the entry into full service of the Monte Alpi pipeline which carries oil from the Viggiano oil center to Eni’s Taranto refinery. Other oil fields are Rospo in the Adriatic Sea, Vega offshore southern Sicily, Gela and Ragusa in Sicily.

     Natural gas production totaled 1,26 mmCF/d and represented approximately 73% of Eni’s hydrocarbon production in Italy. Eni’s principal natural gas fields are located in the Adriatic Sea (Barbara, Porto Garibaldi/Agostino, Angela/Angelina, Cervia/Arianna and Bonaccia which collectively accounted for 47% of Eni’s natural gas production in Italy) and in the Ionian Sea (Luna, which accounted for 8.6%). In 2002 in the Adriatic offshore, the Calipso gas field started production with an output of approximately 4,000 boe/day.

     Within its asset rationalization program, Eni sold its 25% interest in the Gorgoglione concession in Basilicata, where the Tempa Rossa field is located. The achievement of full production of the Val d’Agri fields and the development of the recent oil discoveries at Miglianico in the central Apennines and of the Panda gas well in the deep offshore of Sicily will partly offset declines of mature gas fields.

     The achievement of full production of the Val d’Agri fields and the development of the recent oil discoveries at Miglianico in the central Apennines and of the Panda gas well in the deep offshore of Sicily will partly offset declines of mature gas fields.

     With regards to the Alto Adriatico Project, which contemplated the joint development of 15 offshore natural gas fields with proved reserves of 953 BCF, on December 3, 1999, the Ministry of the Environment, in agreement with the Veneto Region, issued a decree prohibiting the production of liquid or gaseous hydrocarbons in an area within 12 nautical miles from the coastline. The decree defined also the conditions for granting authorizations to exploit fields located beyond 12 nautical miles, from the test phase until the final exploitation phase. After the issue of this decree, natural gas reserves were reduced by the amount of proved

 


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reserves relating to the fields within the set limit (191 BCF), and the relevant assets were written off (21 million euro). Eni filed an extraordinary claim with the President of the Italian Republic against this decree. The claim was rejected. Currently the Italian Parliament is discussing a new law providing for the establishment of a technical Commission assessing exploitation feasability.

     North Africa

     Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2002, North Africa accounted for 24,1% of Eni’s total worldwide production of hydrocarbons.

     Algeria.   Eni has been present in Algeria since 1981. Its principal oil producing fields are located in the Bir Rebaa area in the south-eastern desert, where Eni is operator with a 49% interest. Production from these fields accounted for approximately 27% of Algeria’s annual production in 2002. In 2002 oil production reached full levels at the Hassi Berkine (HBN) field (Eni’s interest is 34.63%) and the fourth oil treatment line in the Hassi Berkine South oil center (HBNS, Eni’s interest is 12.25%) has started operations. These events allowed to increase Eni’s production by 29,000 barrels/day.

     According to management’s industrial plans, the expected start-up in late 2004 of production from the ROD and satellite fields (Eni’s share is 55%) and higher production from the HBN and HBNS fields will generate an increase in daily oil production net to Eni from the present level of 65,000 barrels/day to over 100,000 by 2006.

     Egypt.   Eni has been present in Egypt since 1954 and is the leading international operator. In 2002, fields operated by Eni accounted for 34% of Egypt’s total annual hydrocarbon production, which amounted to 410,000 boe/day (173,000 boe net to Eni). In 2002, oil and condensate production amounted to 97,000 barrels/day net to Eni and came mainly from the Eni operated Belayim and Ashrafi fields in the Gulf of Suez and from the Melehia field located in the Western Desert.

     In 2002, natural gas daily production amounted to 547 mmCF net to Eni. The main natural gas producing interests operated by Eni are concentrated in the Nile Delta, the Abu Madi and El Qar’a onshore fields and the El Temsah, Port Fouad, Darfeel and Baltim offshore fields. In 2002 the Akhen field was started up.

     Eni successfully drilled the new exploration well Tennin 1 in the East Delta Deep Marine permit (Eni is operator with a 50% interest) in the Mediterranean offshore, before the Nile Delta, about 80-kilometer north of Damietta. The well was drilled at water depth of approximately 300 meters, reaching a total depth of over 2,000 meters encountering a gas sand interval of about 60 meters. In test production the well yielded over 23 mmCF/d. A pre-feasibility study is underway for the development of the field. Management believes that this discovery is important both for the size of its reserves and for the possibility to send its production to the Unión Fenosa Gas liquefaction plant under construction at Damietta (See Item 4 — Gas & Power — Development projects).

     According to management’s industrial plans, in the medium term the increase in gas production, while offsetting the natural decline of mature oil producing fields, will allow to maintain the present level of about 190,000 boe/day.

     Libya.   Eni started operations in Libya in 1959 and is the leading international operator, with oil fields operated by Eni accounting for approximately 14% of Libya’s annual oil production. Eni’s principal producing interests are located in two areas: onshore in the Bu-Attifel field, where Eni is operator with a 50% interest, and offshore Tripoli in the Bouri field, where Eni is operator with a 30% interest.

     With a 50% interest Eni is operator in the development of the natural gas, oil and condensates fields of Wafa, in onshore permit NC-169 A located 520 kilometers south of Tripoli, and Bahr Essalam, in the NC-41 permit in the Mediterranean offshore located 110 kilometers north of Tripoli.

 


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     Contracts were awarded for the construction of centers for hydrocarbon treatment near Wafa and Mellitah on the Libyan coast, an offshore production platform and production and transport infrastructure including an underwater production system for a total value of euro 4.2 billion, of which 2.4 are Eni’s share.

     Development is ongoing at the Elephant oil field in the NC-174 permit where Eni is operator with a 33.34% interest. Production is expected to start in the first half of 2004 and to peak at 150,000 barrels/day (35,000 net to Eni) in 2007.

     According to management’s plans, the start-up of fields under development will lead to an increase in daily hydrocarbon production from the present level of 79,000 boe to approximately 260,000 in 2006.

     Tunisia.  Eni has been present in Tunisia since 1961; its main producing interests are in the El Borma oil field and in the oil and gas Hammouda and Oued Zar fields, operated by Eni, which owns a 50% interest therein.

     A new oil discovery was made with the Baraka South East 1 exploration well in the Tunisian offshore approximately 100-kilometers south-east of Tunis. The well was drilled in waters approximately 90 meters deep and reached a depth of over 2,300 meters. It yielded about 5,000 barrels/day of high quality oil in test production. This is the highest flow rate ever reached with a vertical well in the Tunisian offshore. Development studies are ongoing. In the onshore Borj el Kadra concession (Eni is operator with a 50% interest) in southern Tunisia a new oil discovery was obtained by the Adam 1 well, which is expected to start production in the second half of 2003.

     According to management’s plans, in the next four years hydrocarbon production in Tunisia is expected to decline slightly from the present level of 14,000 boe/day.

 


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     West Africa

     Eni’s operations in West Africa are conducted in Angola, Congo, Gabon and Nigeria. In 2002, West Africa accounted for 16.4% of Eni’s total worldwide production of hydrocarbons.

     Angola. Eni has been present in Angola since 1980. In 2002, Eni’s oil production amounted to 62,000 barrels/day. Eni’s main oil producing interests are the Takula, Nemba and Malongo fields located in Block 0 (Eni’s interest is 9.8%) and the Kuito field in the deep offshore Block 14 (Eni’s interest is 20%). Eni planned to develop the Benguela-Belize and Lobito-Tomboco oil fields in Block 14 as well as the Sanha condensate field in Block 0 (Cabinda B).

     Eni participates with a 20% interest in the deep offshore Block 15, where development of oil fields discovered in the Kizomba area has started. The fields under development are Hungo and Chocalho (Kizomba A) and Kissanje and Dikanza (Kizomba B); also the Xicomba field is under development.

     In Block 14 two offshore oil discoveries were made. The Gabela 1 well drilled at a water depth of over 320 meters, penetrating a 25-meter interval of oil-bearing porous rock yielded over 1,000 barrels of oil per day in test production. Geologic and engineering studies are planned in order to define the field’s reserves and the development scenario. The Negage 1 well drilled at a water depth of 1,444 meters encountering a 30 meter thick layer of oily sands at the depth of 2,990 meters yielded over 8,600 barrels/day during test production. The Tombua 3 well was also drilled with its sidetracks, all of which showed presence of hydrocarbons, maximum production was over 10,500 barrels of oil/day.

     In Block 15, a new oil discovery was made. The Reco-Reco 1 well drilled at a depth of 3,798 meters yielded about 3,000 barrels/day in test production. Still in Block 15, the Mondo 2 and Mavacola 2 wells were drilled. Mondo 2, drilled at a water depth of 748 meters allowed to discover a 93 meter thick layer of mineral rich sandstones at a depth of 2,200 meters.

     According to management’s plans, the start-up of fields under development will allow to double Eni’s 2002 production level from Angola’s operations (62,000 barrels/day) by 2006.

     Congo. Eni has been present in Congo since 1968 and is Congo’s second largest international oil producer, with oil fields operated by Eni accounting for approximately 35% of Congo’s total oil production in 2002. Eni’s principal oil producing interests operated in Congo are the Kitina (Eni’s interest is 37.75%), Foukanda, Mwafi, Zatchi and Djambala (Eni’s interest 65%) and Loango (Eni’s interest is 50%) fields located in the deep offshore facing Pointe Noire. Other fields are the Pointe Noire Grand Fond fields (Eni’s interest is 35%). In 2002, full production was reached at the Foukanda and Mwafi fields, which accounted for 20% of Eni’s production in Congo. The new thermoelectric power station at Djeno was inaugurated. The plant has a 25 megawatt capacity and is located near the hydrocarbon treatment terminal. It is fired with associated gas from

 


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the offshore fields of Foukanda, Kitina and Djambala. The project, which entails an investment of dollar 32 million (16 million is Eni’s share) was completed in 13 months by Eni and Chevron Texaco. It represents the first example of use and exploitation of associated gas otherwise flared in Congo.

     In Block Marine X, operated by Eni with a 90% interest, two appraisal wells were drilled, Awa Marine 2 and Paloukou Sud Marine 5. In the Loango concession, a seismic and reprocessing campaign was performed aimed at better evaluating the field’s potential and its nearby structures.

     According to management’s plans, in the next four years production from Eni’s operations is expected to decline slightly from the present level of 75 KBBL/d.

     Nigeria. Eni has been present in Nigeria since 1962. The fields operated by Eni accounted for approximately 8% of Nigeria’s oil production in 2002. Eni’s principal producing interests in Nigeria are in four onshore Blocks (OML 60, 61, 62 and 63) in the Niger Delta, where it acts as operator with a 20% interest, and in the offshore OML 116 Block (former OPL 472 Agbara) and OML 119 (former OPL 91) where it holds a 100% interest operated through service contracts. In December 2001, oil production started at the Okono oil field in Block OML 119 and in 2003 production is expected to start in the Okpoho oil field in the same Block. In 2006 production of the two fields is expected to peak at 16,000 barrels/day net to Eni. In April 2003, production started at the Abo Central offshore oil field located in Block OPL 316, operated by Eni with a 50.19% interest. The Bonga oil field, located in Block OML 118, where Eni holds a 12.5% interest, is currently being developed; production is expected to start in 2004.

     Eni also has a 5% interest in Nase, the largest oil joint venture in the country relating to hydrocarbon production from 43 onshore blocks.

     Eni holds a 10.4% share in the Nigeria LNG Company, a consortium managing the Bonny liquefaction plant for the treatment and export of LNG. The plant is made up of three treatment trains (the third one started operating in November 2002) with a total capacity of 402.5 BCF/year LNG. In 2002, the contracts for the fourth and fifth treatment trains were awarded and these will increase the plant’s overall capacity to 769.8 BCF/year. Work will be completed between the end of 2005 and early 2006. Eni’s share of gas reserves committed to the liquefaction plant amounts to 1,553.6 BCF.

     In the OML 118 deep offshore permit two appraisal wells were successfully drilled in the Bonga SW oil field at a water depth of about 1,300 meters that allowed for the start of the pre-feasibility study for the development of the field. The Bonga SW 2 well yielded 4,200 barrels/day up to a maximum of 11,000 barrels/day in test production. In the OPL 316 deep offshore permit while continuing the drilling of the ABO 4 development well, new deep levels were discovered. The feasibility study is underway, production from these new deep levels will entail synergies with the ABO field.

 


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     In December 2002 the EA field in the OML 79 permit (Eni’s interest 12.86%) started production at a rate of 40,000 boe/day (5,000 net to Eni). In the OML 63 onshore permit (Eni is operator with a 20% interest) the Obama Deep appraisal well, drilled at a depth of over 5,300 meters, met a level mineralized mainly with liquid hydrocarbons. The well yielded 4,170 barrels/day in test production and was completed and linked to the existing Pirigbene facilities.

     According to management’s plans, the reaching of full production at deep offshore Abo and Bonga fields and the increase in liquefied natural gas volumes treated at Bonny’s plant will lead to an increase in Eni’s production from Nigeria’s operations from the present level of 98,000 boe/day to over 180,000 boe/day by 2006.

     Mauritania. Eni holds a 35% interest in the area covered by A and B PSAs (Blocks 3, 4 and 5) in the deep offshore of Mauritania at a water depth from 200 to 2,600 meters. Within this area, Eni completed the appraisal campaign for the Chinguetti discovery (Eni’s interest is 35%) with the drilling of two appraisal wells and a new hydrocarbon discovery was also made with the Banda 1 exploration well.

     North Sea

     Eni’s operations in the North Sea area are conducted in Norway and the United Kingdom. In 2002, the North Sea accounted for 20.8% of Eni’s total worldwide production of hydrocarbons.

     Norway. Eni has operated in Norway since 1964. Eni’s principal producing interests in the North Sea are located in the Ekofisk field (12.39% interest) and in the Norwegian Sea in the Aasgard (7.9% interest) and Norne (6.9% interest) fields. In 2002, production of the Ekofisk, Aasgard and Norne fields accounted for 57% and 43% respectively of Eni’s production in Norway (62 and 38% in 2001).

     In March 2003, Eni concluded the purchase of Fortum Petroleum, the Norwegian subsidiary of the Finnish company Fortum Oy. The acquisition entailed a total investment of dollar 975 million (of which dollar 256 million were paid for its net equity and dollar 719 million for its net borrowings assumed).

     Fortum Petroleum’s main assets are located in the Norwegian section of the North Sea. In particular they consist of interests in the Aasgard (7%), Brage (12.26%) and Heidrun (5.12%) producing fields, in the Mikkel field (7% in addition to Eni’s preexisting 7.9% interest in the same field) and Goliath field (15% in addition to Eni’s preexisting 25% interest in the same field). The Mikkel field is currently being developed, while the Goliath field, which is operated by Eni, has not been developed yet. In addition, Fortum Petroleum holds interests in important gas transmission infrastructures such as Haltenpipe (5%), Heidrun Gas Export (5.12%) and Aasgard Transport (5%) linking the Aasgard and Heidrun fields to the Norwegian coast. The company also holds an interest in Franpipe (1.29%) and the related Dunkerque terminal (0.84%) in France and in Europipe II (3.66%) for natural gas transmission to the German coast.

 


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     At the end of 2002 Fortum Petroleum had proved reserves of approximately 159 million boe, half of which were natural gas. In 2002 its daily production amounted to 39,000 boe; in 2003, production is targeted to over 40,000 boe/day. This transaction is part of Eni’s growth strategy in the upstream sector by strengthening its presence in key areas and increasing interests in already held assets in order to generate operational synergies. According to management’s plans, the purchase of Fortum Petroleum and start-ups of fields under development will increase production from the present level of 92,000 boe/day to a peak of over 140,000 boe/day in 2006.

     United Kingdom.  Eni has been present in the United Kingdom since 1964. The main producing interests operated by Eni in the United Kingdom are located in the operated B-Block (average interest of 60%) and in the T-Block (which contains the Thelma, Tiffany and Tony fields), where Eni increased its interest from 77.48% to 88.78% following a purchase. Other important fields are those located in the Liverpool Bay (Hamilton, Lennox and Douglas), where Eni increased its interest from 45 to 53.9% after a purchase and the J-Block (33%), Hewett (27.35%), Ninian (12.94%), Magnus (5%), Thames (23.3%), McCulloch (40%) and Andrew (16.21%). Within the rationalization process of Eni’s asset portfolio following the purchase of British-Borneo and Lasmo, interests were sold in 11 marginal fields, as well as in other minor assets, such as transmission infrastructure, terminals and exploration licenses.

     According to management’s plans, production from United Kingdom operations is expected to decline in the next four years from the present level of 208,000 boe/day due to the average maturity of producing fields.

     Ireland.  Eni holds 3 exploration permits in the Atlantic offshore of Ireland at water depths ranging from 1,000 to 2,000 meters: permits 7/97 and 1/99 operated by Eni with a 100% interest and permit 2/94 (Eni’s interest 40%) where the Dooish well was successfully drilled at a water depth of 1,484 meters.

     Rest of the World

     In 2002, Eni’s operations in the rest of the world accounted for 17.3% of its total worldwide production of hydrocarbons.

     In Australia, Eni acquired two exploration permits WA-326-P, operated by Eni with a 100% interest, and WA-328-P, operated by Eni with a 66.7% interest. Eni will perform seismic surveys for 1,215 kilometers in the first permit and for 3,015 kilometers in the second permit. Eni was also awarded the WA-25-L production licence (where Eni is operator with a 65% interest) where the Woollybutt offshore oil field is located. Production at this field started in April 2003.

     In Azerbaijan, in January 2002 Eni signed with the national company Socar a sale and purchase agreement for the purchase of a 5% interest in the project for the construction of the Baku-Tblisi-Ceyhan pipeline. At present Eni’s interest concerns only the detailed engineering phase. The project envisages the construction of a 1,740-kilometer long pipeline for the transportation of oil from the Caspian Sea area to the Mediterranean by linking

 


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Baku to the Turkish port of Ceyhan through Georgia. The pipeline transport capacity is projected to be of one million barrels/day. Construction work started in September 2002. According to management’s plans, the pipeline is expected to start operating in 2005. In the Shakh Deniz Block (Eni’s interest 5%), an area of approximately 860 square kilometers, exploration contributed to the definition of the extension of the natural gas and condensates field. The development project for this field was approved and is in the starting phase after the conclusion of agreements with the national company Socar and the Turkish company Botas for the sale of natural gas produced.

     Brazil.   Eni holds interests in 4 exploration licenses (with shares from 20 to 100%) in two of which the second exploration phase has already started.

     China.   Eni has been present in China since 1983; it holds an exploration permit in the Qaidam basin, in the central western part of China where it signed a PSA with the national company CNPC, relating to a 7,000 square kilometer area.

     Croatia.   Eni through a 50/50 joint venture with Ina, the State-owned Croatian company, operates the Ivana natural gas field, located in the Adriatic offshore. The field is operated through a main production platform, called Ivana A, installed in 1999, and three satellite platforms, Ivana B, D and E, installed between 2000 and 2001. In 2002 the development plan of other fields discovered in the area — Ika, Ida, Annamaria and Marica — was approved. Their development will entail the drilling of 18 directional wells, the construction and installation of 9 platforms at a water depth of 60 meters and the laying of underwater sealines for a total length of 120 kilometers. Total capital expenditure in the project is about euro 320 million. In April 2003 contracts for the construction of the first production platform were awarded. According to management’s plans, start-up of these four fields is expected in late 2004 and when fully operational will allow to increase production net to Eni from the present level of 5,000 boe/day to over 10,000 boe/day by 2005. In the same concession a new gas discovery was made with the Katarina 2 well.

     Ecuador.   The Villano oil field, operated by Eni with a 100% interest, is Eni’s first hydrocarbon producing field in Latin America. In 2002, this field produced 31,000 barrels/day (22,000 net to Eni). This production level is expected to increase in the next four years. Construction of the OCP pipeline (Eni interest is 7.51%) is underway. This new pipeline will add to the existent SOTE pipeline increasing transport capacity in Ecuador.

     Indonesia.   Eni is present in Indonesia following the acquisition of Lasmo since 2001. Its producing interests are located in the onshore area in east Kalimantan, regulated by the Sanga Sanga PSA (Eni’s interest is 38%) operated by Virginia Indonesia Company (VICO) in which Eni holds a 50% interest. This area produces mainly natural gas (about 80% of area’s total production). 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. Five wells were drilled in the fields of Ranggas, Gandang and Gendalo, in the Rapak and Ganal area (Eni interest is 20%) in the offshore east of Kalimantan. Three wells were drilled in the Ranggas oil and gas field, the R4 well flowed at a daily rate of more than 8,000 barrels of oil. The 2A well, drilled in the gas and condensates field of Gandang,

 


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confirmed the extension of the field. In the gas and condensates field of Gendalo, the G3 well, flowed at a daily rate of about 35,3 mmCF/d of gas and about 2,000 barrels/day of condensates. According to management’s industrial plans, Eni’s daily hydrocarbon production in the next four years is expected to remain at the present average level of 38,000 boe.

     In Iran, in 2002 the Dorood oil field (Eni’s interest is 38.25%) started production. This is Eni’s first producing asset in this country. Located in the offshore of the Persian Gulf, the field produced 3,000 barrels/day net to Eni in 2002 and is expected to peak at 14,000 barrels net to Eni in 2004 due to the expected start-up of 8 new producing wells in addition to the existing two.

     Within the development of phases 4 and 5 of the South Pars natural gas field in the Persian Gulf (Eni is operator with a 60% interest), a dollar 1.2 billion contract for the construction of four natural gas treatment plants with an overall capacity of 1,98 BCF/d of natural gas was awarded. Construction of the plants is expected to be completed by 2005. Production is expected to start in 2004. Eni is operator with a 60% interest of the onshore Darquain oil field, located about 50 kilometer north east of Abadan. Drilling and infrastructure construction are underway in order to start-up production in late 2003. In January 2003, the Balal field started production with an expected daily production of about 6,000 barrels in 2003.

     Kazakhstan. Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field with British Gas with a 32.5% interest. In 2002, production of oil and condensates from this field amounted to 32,000 barrels/day (net to Eni), production of natural gas amounted to 148 mmCF/d (net to Eni). The second development phase of this field, which is currently underway, is aimed at increasing daily production of liquids to 220,000 barrels/day (64,000 net to Eni) in 2004. The subsequent development phase of the field will concern expansion of natural gas sales.

     Eni is single operator of the North Caspian Sea PSA in the Kazakh offshore, where the Kashagan field is located. A consortium currently comprised of six international oil companies, amongst which Eni, is responsible for conducting exploration and development activities in the contractual area. Eni’s interest in the PSA is going to become 20.372% from an original 14.28% interest. The increase in Eni’s interest will follow the closing of two Sale and Purchase Agreements under which the consortium partners acquired a proportional share of the interests of BP and Statoil and subsequently of British Gas that left the project in 2001 and 2003, respectively. The contractual area is made up of 11 blocks covering a total of over 5,500 square kilometers at a water depth of 2 to 10 meters. This project, due to the mineral potential of existing structures and to the operating and technological challenges it poses, resulting from the shallow waters which are frozen for about six months a year, represents an extremely important industrial feat in the oil industry. Eni intends to apply the most advanced technologies and operational solutions in order to provide maximum environmental protection to the North Caspian area. Management plans the exploration campaign to last six years and to encompass the drilling of 6 exploration wells and the collection of seismic data. Six wells have been already drilled, the first two, KE-1 and KW-1 about 40 kilometers from one another, discovered a large reservoir in the Kashagan structure, approximately 75 kilometers

 


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south-east of Atyrau. The appraisal wells KE-2, KE-3, KE-4 and KE-5 confirmed the importance of the discovery. Three wells are currently being drilled, Kashagan South West 1 and Aktote 1 (exploration wells) and K-6 (appraisal well). On June 30, 2002 the consortium and the Kazakh authorities declared the commercial discovery of this field. At the end of 2002 the consortium filed the Kashagan development plan with the Kazakh authorities. The front-end engineering for the first development phase is currently underway.

     In a block near the Kashagan field within the same contractual area and under the same PSA, a new oil discovery was made in the Kalamkas structure. The Kalamkas-1 exploration well was drilled to a depth of 2,360 meters and yielded over 2,300 barrels/day in test production. Drilling was performed in very shallow and extremely environmentally sensitive waters.

     United States. Eni has been present in the United States since 1966 and holds several mineral rights in the Gulf of Mexico. Eni’s main producing fields are located offshore in the Grand Isle 102, Green Canyon 254-297 (where the Allegheny field is located, Eni’s interest is 100%) and Ewing Bank 921/964-5 (where the Morpeth field is located, Eni’s interest is 100%) concessions; other fields in which Eni holds interests are located in the Garden Banks 602/646 (where the Macaroni field is located, Eni’s interest is 34%), Mississippi Canyon 890-1/934-5 (where the Europa field is located, Eni’s interest is 32%) and Mississippi Canyon 194-5/150-1 (where the Cognac field is located, Eni’s interest is 16.5%) concessions.

     Eni holds a 25% interest in the Mississippi Canyon 538-9/582-3 concession where the Medusa oil and gas field is under development. Start-up is expected in 2003 with production peaking at 9,000 boe/day net to Eni by 2004.

     Eni holds a 50% interest in the Atwater Valley 63-4 concession where the appraisal phase of the Champlain oil field is ongoing and development is being studied.

     In the Green Canyon 472-3/516 Block (Eni’s interest is 50%), production started at the King Kong/Yosemite natural gas fields only thirteen months after the decision to develop these fields and eight months after the discovery of Yosemite, reaching a peak of 145 mmCF/d (69.6 mmCF/d net to Eni). The development of these two fields, operated by Eni, was obtained by drilling at a water depth of 1,170 meters three subsea wells tied back to the Allegheny platform (Eni’s interest 100%) located at a 25-kilometer distance. Expenditure net to Eni amounts to approximately dollar 90 million. In Green Canyon Block 562-3, the delimitation well K2 (operated by Eni with an 18.17% interest) was successfully drilled. Production is expected to start in 2004.

     According to management’s plans, the development of recently discovered fields will increase hydrocarbon production from the present level of 58 KBOE/d to a peak of over 70 KBOE/d in 2005.

     Venezuela. Eni is the operator with 100% of the Dacion oil field regulated by a service contract with a 20 year term. In 2002 production from this field amounted to 42 KBBL/d net to Eni. In addition Eni holds a 26% interest in the Corocoro oil field, located in the West Paria Gulf at the mouth of the Orinoco river. The field’s

 


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development project started in April 2002 and will progress through different phases. This field is expected to reach a production of 14 KBBL/d in the first phase.

     Pakistan. Eni has been present in Pakistan since 2000. Eni’s main natural gas producing field is Kadanwari (Eni’s interest is 18.42%) and Miano (Eni’s interest is 15.16%), the latter started production in 2002 at a level of 17.4 mmCF/d net to Eni. In January 2003 the Bhit field (operated by Eni with a 40% interest) was started up. According to management’s plans, in 2003 it will reach a production level of 272.6 mmCF/d (110.2 mmCF/d net to Eni) to be sold in Pakistan. Other natural gas fields are under development: Zamzama (Eni’s interest is 17.75%) and Sawan (Eni’s interest is 23.7%). Government authorized the development of the Zamzana natural gas field The development project is well underway and startup is expected in the fourth quarter of 2003.

     In August 2002, Eni signed a production contract agreement with a five-year term relating to the Khirtart Foldbelt area, within the Manchar exploration license (Eni is the operator with a 55% interest). The Khirtart Foldbelt area covers an area of 2,435 square kilometers.

     In the Middle Indus Basin, Eni obtained a 33.33% interest in the SW Miano (II) concession for a three-year term. Such concession covers an area of 1,238 square kilometers.

     According to management’s plan, production of natural gas is expected to increase in the next four years from the present level of 40.6 mmCF/d to over 232 mmCF/d in 2004.

     In Russia, Eni is the operator with a 50% interest of the Severo Astrakhansky license, covering an area of 1,800 square kilometers situated at the mouth of the Volga river, on the edges of the great pre-Caspian sedimentary basin. The area is crossed by the Caspian Pipeline Consortium oil pipeline, which started operations in 2002. Eni intends to continue exploration activities in the area.

Natural Gas

     Snam SpA was merged into Eni SpA effective as of February 1, 2002 to become Eni’s Gas & Power division. Eni now conducts its natural gas and electricity generation activities through its Gas & Power division and its subsidiaries. In 2002, Eni’s primary distribution natural gas sales totaled 52.56 billion cubic meters in Italy and 8.2 billion cubic meters in Europe. Primary distribution sales include sales to wholesalers, mainly local distribution companies, and large industrial and thermoelectric users which are supplied by a high and medium pressure gas pipeline network. Eni’s high and medium pressure gas pipeline network for primary distribution is about 30,000-kilometres long in Italy, while outside Italy Eni holds transport rights on over 3,700 kilometers of high pressure pipelines. Effective on July 1, 2001 Eni’s natural gas transport network in Italy was contributed to Snam Rete Gas SpA. In December 2001 shares representing 40.24% of the company’s capital were sold through a public offering with proceeds of euro 2.2 billion. Snam Rete Gas transports natural gas on behalf of Eni and third parties («shippers»); in 2002 transported volumes were 73.7 billion cubic meters,

 


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of which 19 billion on behalf of third parties. Eni is also active in retail distribution (“secondary distribution”) of natural gas, which includes almost exclusively sales made by local distribution companies to commercial and residential users through a low pressure gas pipeline network. Eni operates in secondary distribution in Italy through Italgas — the largest local natural gas distribution company in Italy — which is a wholly-owned subsidiary of Eni following the public tender offer successfully closed in January 2003. Eni also operates in secondary distribution outside Italy: in Hungary through Tigaz, in Argentina through Distribuidora de Gas Cuyana and in Slovenia through Adriaplin. In 2002, Eni’s secondary distribution sales were 7.84 billion cubic meters in Italy and 3.79 billion cubic meters outside Italy. Eni’s secondary distribution network in Italy is over 46,000-kilometres long and over 30,000-kilometres long outside Italy.

     Eni conducts its electricity generation activities through Enipower SpA which owns and manages Eni’s power stations of Livorno, Taranto, Mantova, Ravenna and Brindisi with a total installed capacity of 1,000 megawatts and annual production sold of about 5,000 gigawatthour. Eni owns other minor power stations located in Eni’s petrochemical plants and refineries whose production is mainly for internal consumption. The accounts of these power stations are reported within Eni’s Refining and Marketing and Petrochemicals segment.

     In 2002, Eni’s Gas & Power segment had net sales from operations (including intersegment sales) of euro 15,297 million and operating income of euro 3,244 million.

Strategy

     Eni is pursuing the development of international sales in order to compensate the lower growth opportunities in the domestic market, which are due to the limits imposed to operators by the applicable regulations. In Italy, Eni intends to maintain sales volumes within the limits permitted by the applicable regulation through the optimal allocation of supplies between direct sales in Italy and sales to operators in the natural gas sector as well as by using natural gas at its own electricity generation plants and, at the same time, leveraging on the expected demand growth, in particular for electricity generation. Eni’s commercial policy will aim at customer satisfaction by means of an efficient management of the customer portfolio, high flexibility in offers to customers and enhancement and integration of services provided.

     Outside Italy management plans to develop Eni’s presence in certain European gas markets, in particular in countries with interesting growth and profitability prospects (Iberian Peninsula, Turkey, Germany) where Eni can make optimal use of its diversified portfolio of supply contracts and its extensive gas pipeline network which allows the supply of natural gas from several sources. In 2002 Eni completed its entry into those markets by means of acquisitions and construction of infrastructure; in 2003 Eni started the operational and commercial phase of this plant. Eni also intends to search for market opportunities in order to sell the natural gas it produces in certain European areas and to expand its presence in LNG activities. Based on signed contracts and finalized transactions, Eni expects to increase significantly sales of natural gas outside Italy by 2006. Eni will also intensify its cost reduction actions especially in transport activities and in secondary distribution activities in Italy.

 


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

     Demand for Natural Gas in Italy

     With consumption amounting to about 70 billion cubic meters in 2002 (decreasing slightly over 2001), Italy is the third European market for natural gas after Great Britain and Germany.

     In 2002, about 20% of natural gas requirements were met through domestic production, while imports covered 80% of demand.

     In the next decade world consumption of natural gas is expected to increase, due to the continuous improvement in technologies applicable to all phases of natural gas production, the higher environmental compatibility of natural gas as compared to other hydrocarbons, expected demographic, economic and social developments and the steady increase in natural gas reserves. According to management’s own estimatees, Europe represents one of the areas with the highest development rate and the average increase is expected to be 2% per year.

     According to management’s own estimatees natural gas demand in Italy is expected to increase at higher rates than the European average and than the overall demand for energy in Italy. According to management’s own estimatees consumption is expected to reach about 90 billion cubic meters in 2010, corresponding to an annual average increase of over 3%. The share of natural gas on total domestic energy requirements is expected to reach nearly 40% in 2010.

     Management believes that most of this increase will concern natural gas used in electricity generation, because of the significant advantages of the use of natural gas in combined cycle generation plants, thanks to its lower investment cost, higher yields and reduced polluting emissions as compared to other fuels. Demand is expected to increase also from residential and commercial users, due to the further expansion of the natural gas distribution network in southern Italy and the increased use of natural gas for residential space heating in households and services. Many of the factors that may influence future trends in natural gas demand in coming years are, however, outside of management’s control; among these there are trends in the price of natural gas compared to other fuels, the development of the electricity sector, the economic growth, climate fluctuations, environmental laws and the continuing availability of natural gas imported from foreign countries. If the growth of the Italian natural gas market were to be lower than management’s expectations, Eni’s results of operations may not benefit from expected increase in volumes.

 


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     Natural Gas Purchases

     About 80% of the natural gas requirements of Eni’s Natural Gas segment are met by imports (mainly from Algeria, Russia and the Netherlands) under long-term supply contracts, and the balance by purchases of gas produced in Italy by Eni’s Exploration & Production division. In 2002, Eni’s Gas & Power division supplied 62.33 billion cubic meters of natural gas, in line with 2001. Volumes of natural gas from domestic production accounted for 20% of total supplies (23.3% in 2001) with a decrease of approximately 2 billion cubic meters over 2001.

     Natural gas volumes supplied outside Italy represented 79.7% of total supplies (76.6% in 2001) with an increase of 1.87 billion cubic meters over 2001, up 3.9%, in particular due to higher purchases from Norway (3.73 billion cubic meters) and the Netherlands (0.55 billion cubic meters). This is due to purchase contracts signed in 1997 with Norwegian and Dutch suppliers (targeting approximately 6 and 4 billion cubic meters/year, respectively) becoming operational in October 2001. Contracts with Norwegian suppliers became fully operational in 2002, while those with Dutch suppliers will reach full operation in 2003. These increases were offset in part by a decrease in supplies from Algeria (2.04 billion cubic meters) and Russia (0.89 billion cubic meters).

     Eni is a party to import contracts with an average residual duration of about 17 years which generally include take or pay provisions and will provide a total of approximately 66 billion cubic meters of natural gas per year (28.5 from Russia, 21.5 from Algeria, 10 from the Netherlands, 6 from Norway) from 2008. Overall natural gas volumes under existing contracts amount to approximately 1,118 billion cubic meters.

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

                                           
      Year ended December 31,
     
      1998   1999   2000   2001   2002
     
 
 
 
 
      (billions of cubic meters)
Italy
    17.72       16.16       13.64       14.62       12.67  
Algeria
    16.83       20.40       21.56       18.39       16.35  
Algeria (LNG)
    1.99       2.06       2.01       1.79       1.92  
Russia
    16.69       19.09       21.03       19.51       18.62  
The Netherlands
    3.02       2.87       6.09       7.00       7.55  
Norway
                            1.10       4.83  
Qatar (LNG)
                                    0.24  
Other
                                    0.15  
 
Primary distribution
    56.25       60.58       64.33       62.41       62.33  

 


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Withdrawals (inputs) from (to) storage
    56.25       60.58       (2.43 )     0.13       (1.43 )
Internal consumption
    (0.56 )     (0.34 )     (0.65 )     (0.58 )     (0.14 )
 
Available volumes for primary distribution
    55.69       60.24       61.25       61.96       60.76  

     Natural Gas Sales in Italy and Europe

     Natural gas sales relating to primary distribution totaled 60.76 billion cubic meters, in 2002 with a decrease of 1.20 billion cubic meters, down 1.9%, over 2001, due to lower sales in Italy (6.33 billion cubic meters, down 10.7%), offset in part by higher sales in Europe (5.13 billion cubic meters, up 167.1%).

     In a increasingly competitive market, the decrease in natural gas sales in Italy was essentially due to a decline in sales to wholesalers (5.69 billion cubic meters, down 18.5% as compared to 2001) following the progressive alignment to ceilings set by Legislative Decree No. 164/2000, the concentration process ongoing in this segment and the mild weather of November and December 2002. Also sales to industrial customers declined (0.92 billion cubic meters, down 6.0% as compared to 2001) due to the weak economic situation and the interruption of interruptible supplies due to cold weather in early 2002. These declines were offset in part by increased sales to thermoelectric customers (0.28 billion cubic meters, up 2.2%) due to new supplies to power stations, whose effects were offset in part by lower sales following interruptions of supplies to customers with interruptible contracts.

     The increase in sales in Europe was due to the progressive coming on line of long-term supply contracts with operators of the natural gas market (Plurigas, Edison, Dalmine and Cir Energia) and the start of LNG supplies to the Spanish electric company Iberdrola (0.37 billion cubic meters) through a 15-year supplying contract of 1.2 billion cubic meters/year of LNG.

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

                                           
      1998   1999   2000   2001   2002
     
 
 
 
 
      (billion cubic meters)
Wholesalers
    29.49       30.85       30.26       30.83       25.14  
End users
    26.15       29.34       29.66       28.06       27.42  
 
— industrial users
    15.66       16.33       16.79       15.25       14.33  
 
— thermoelectric users
    10.47       13.01       12.87       12.81       13.09  
Italy
    55.64       60.19       59.92       58.89       52.56  
Europe
    0.05       0.05       1.33       3.07       8.20  

 


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      1998   1999   2000   2001   2002
     
 
 
 
 
      (billion cubic meters)
Sales in primary distribution
    55.69       60.24       61.25       61.96       60.76  
Sales in secondary distribution outside Italy
    2.73       2.67       3.48       3.91       3.79  
 
    58.42       62.91       64.73       65.87       64.55  

     The Italian natural gas market is made up of three main segments: residential and commercial, industrial and thermoelectric. Customers can be divided into two groups: final users consuming natural gas and wholesalers purchasing natural gas to sell it to other customers. According to the types of distribution, natural gas sales are divided into: (i) large distribution (primary distribution) which includes sales to wholesalers, mainly local distribution companies, and large customers, mainly industrial and thermoelectric customers; (ii) local distribution (secondary distribution) represented almost exclusively by sales made by local distribution companies to commercial and residential customers. From January 1, 2003, with the complete opening of the natural gas market, pursuant to Legislative Decree No. 164/2000, all customers are allowed to purchase natural gas at any source and to enter into contracts with transport companies operating in the national network and with distribution companies operating in local networks for the transport to the delivery points.

     In 2002 wholesalers, local distribution companies and automotive natural gas sellers sold approximately 31.8 billion cubic meters to final users (45% of total natural gas consumption), with a 3% decline over 2001. The market of local distribution companies includes residential and commercial users, large distribution and small enterprises located in urban areas, whose supplies are provided through low pressure urban pipeline networks. In Italy about 700 local distribution companies operate in over 5,700 municipalities with more than 16 million customers. These municipalities account for approximately 89% of total population in Italy. In 2002, Eni’s natural gas sales to local distribution companies and through these to residential and commercial users amounted to 25.1 billion cubic meters.

     In 2002 natural gas consumption by final users of primary distribution totaled 38.6 billion cubic meters (55% of total natural gas consumption), a 1.3% increase over 2001. Natural gas consumption in the industrial segment of primary distribution amounted to over 16 billion cubic meters (22% of total consumption), with a 1.2% decrease over 2001. In 2002, Eni’s sales of natural gas to industrial users amounted to 14.3 billion cubic meters.

     Natural gas consumption in the thermoelectric segment of primary distribution amounted to 22.6 billion cubic meters (32% of total consumption), with a 3.4% increase over 2001. This segment includes electricity producers and distributors (Enel SpA and some municipal utilities) and industrial producers of electricity. In 2002, Eni’s sales of natural gas to thermoelectric users amounted to 13.1 billion cubic meters.

 


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     Eni reorganized its activities by creating six new branches in Italy in order to react promptly and efficiently to market requirements, while paying increasing attention to customers’ needs and applying the home working model to all its sales personnel. The new marketing strategy is aimed at customer satisfaction, through the setting of a new commercial offer tailored to customers needs always in line with the rules and regulations introduced by Legislative Decree No. 164/2000. In particular the customized commercial offer includes a range of elements: from the standard to the modular profile which supplies an optimal mix of options, such as, for example, various price formulas and types of indexes aimed at controlling price volatility, availability of services and technical assistance. At present Eni provides its industrial customers with a wide range of high value added technical services on the use of natural gas in particular in co-generation and climatization. The main services provided in co-generation include: (i) studies on co-generation and technical testing of the solutions suggested in case of construction or upgrade of a co-generation plant; (ii) combustion analysis and energy control of existing plants for evaluating their proper use and efficiency; (iii) tests of compliance with safety regulations, environmental impact. A toll-free telephone line is available and in the Gas & Power section of Eni’s web site an area is dedicated to natural gas along with a mail box. Eni also started projects aimed at providing new services and offering them in innovative ways in particular as concerns direct relations to customers.

     Eni’s new commercial efforts were coupled with intense personnel training activity aimed at developing the new skills required by the market, at reinforcing direct relations with customers and supporting commercial units.

     Eni, through its subsidiary Italgas, is the Italian leader in the retail sale of natural gas to residential and commercial users, as well as small enterprises. In 2002, sales of natural gas in secondary distribution in Italy (7.84 billion cubic meters) decreased by 0.28 billion cubic meters, down 3.5% as compared to 2001, due mainly to mild weather, whose effects were offset in part by the approximately 119,000 units increase in the number of customers served (5.68 million as of December 31, 2002). Through Italgas Eni owns a low pressure urban network in Italy consisting of over 46,000 kilometers of pipelines at December 31, 2002, and serving 1,197 municipalities (1,186 at December 31, 2001), among which Rome, Naples, Turin, Florence and Venice with 5.68 million clients.

     Within its strategy of rationalization and development of its natural gas segment also at international level and in line with plans previously announced, Eni’s Board of Directors in its meeting of November 25, 2002, decided to launch a public tender offer on all Italgas SpA ordinary shares outstanding not owned directly or indirectly by Eni, corresponding to approximately 56% of Italgas’ capital. Eni offered a unit price of euro 13 per share, to be fully paid in cash and including a 25.7% premium over the weighted average of the last month is price for Italgas publicly traded shares and a 19.1% premium on the official price of the business day preceding the day of the announcement of the offer.

     The offer closed on January 27, 2003 with the purchase of 189,340,323 shares corresponding to 97.189% of the shares subject to the offer (194,817,383) and 54.326% of Italgas SpA’s share capital, represented by 348,523,506 shares. Payment of the price of shares tendered (euro 2,461 million) was effected on February 6, 2003. Italgas shares were withdrawn from Telematico on February 7, 2003.

 


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     Eni now owns a total of 342,546,446 Italgas shares, representing 98.285% of share capital. As the conditions provided for by article 111 of Legislative Decree No. 58 of February 24, 1998 met, with notice published on February 4, 2003, Eni declared its willingness to squeeze-out the minority share holders that did not tender their shares. Eni’s purchase right was exercised on March 25, 2003 without residual offering at the price of euro 13 set by an expert named by the President of the Court of Torino. Eni’s outlay is expected to amount to approximately euro 78 million.

     In order to implement the regulations contained in Legislative Decree No. 164/2000, Eni effected the separation of retail sales from its other activities in secondary distribution of natural gas; in particular Italgas SpA established Italgas Più SpA to which it contributed sales activities and customer management services. Italgas Più is now present on the market with a new and wider supply of services; in particular:

    a post-counter service for extraordinary and planned maintenance interventions on autonomous household heating systems, offered in two forms: «Assistenza Italgas Più» concerning the planned maintenance of heaters fired with any fuel that need to be periodically monitored and subjected to combustion analysis and «Pronto Assistenza» concerning fast interventions of skilled technicians for repairing damages or checking heaters and other parts of the heating plant;
 
    a service of energy management addressed mainly to public administrations, condominiums, the tertiary sector and industrial enterprises supplying heat instead of just natural gas, design of heating systems and consultancy services. This service provides immediate solutions to problems of management, design and upgrade of plants and frees customers from technical and organizational tasks as wells as from responsibilities and administrative tasks.

     Italgas Più also improved its marketing channels by adding to the traditional access point other specific channels:

    an integrated toll-free call center system (located in Turin, Rome, Florence, Naples, Chiavari) which customers can access for any information concerning services provided: payment of bills, information on consumption, requests for service and all related matters;
 
    a network of franchisors made up of 94 «shops» with flexible opening hours available to customers for any request concerning services provided. Italgas Più targets include the establishment of 460 franchised shops by 2005.

     The interactive web site www.italgaspiu.it represents a true online shop where customers can find all information concerning services provided, check their accounts, simulate consumption, change personal data and organize payments through their bank account.

     This business will be developed by entering new areas and promoting new services such as air conditioning and co-generation for small enterprises, in order to foster new forms of consumption.

 


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     Within its strategy of alliances with municipalities and with companies managing multiservices for local governments, Eni acquired, in partnership with Acea SpA, a 46.2% interest in Ages SpA, the municipal utilities company operating in Pisa. Eni’s expenditure amounted to euro 42 million.

     Outside Italy Eni is present in natural gas secondary distribution in:

    Hungary through Tigaz (Eni’s share 27.59%), the largest regional gas distribution company in the country, reaching 855 urban centers through a network of about 21,000 kilometers of pipelines, and serving about 1 million customers. In 2002, Tigaz sold 2.8 billion cubic meters of natural gas. In 2003 Tigaz finalized the purchase for approximately euro 80 million of 4 distribution companies active in the central-northern areas of Hungary supplying an aggregate of 150,000 customers and distributing 400 million cubic meters of natural gas;
 
    Argentina, through Distribuidora de Gas Cuyana SA (Eni’s share 20.05%), which operates in the urban area of Mendoza, serving about 360,000 customers through a network of about 8,900 kilometers of pipelines. In 2002, it handled 1.6 billion cubic meters of natural gas; about 0.9 were sold to end users, while the rest was transported on behalf of third parties;
 
    Slovenia, through Adriaplin Doo (Eni’s share 22.42%), which distributes natural gas to about 7,000 customers in 15 urban centers through a network of about 332 kilometers of pipelines. In 2002, it sold 30 million cubic meters.

     Transmission, Dispatching and Regasification Assets

     Transmission, dispatching and regasification activities in Italy are carried out by Snam Rete Gas SpA, a company listed on the Italian Stock Exchange and in which Eni holds a 59.76% interest. Eni’s primary transmission network was transfered to Snam Rete Gas in July 2001 pursuant to Legislative Decree No. 164/2000 concerning the Italian natural gas market, which provided for the legal separation of transmission and dispatching activities from all other activities in the natural gas segment, exclusive of the storage that, in any case, has to be subjected to accounting and management separation.

     The Italian natural gas transmission system is made up of a national network and a regional transmission network, as defined by the Decree of the Ministry of Industry (now the Ministry of Productive Activities) of December 22, 2000, which implements Legislative Decree 164/2000. These networks include pipelines, for a total length of about 31,200 kilometers, of which 29,795 kilometers are owned by Eni. The national network is composed of high pressure trunklines, mainly with a large diameter, which carry natural gas from the entry points to the system—import lines, storage sites and main national natural gas fields—to the linking points with the regional transmission network. The national network also includes some interregional lines reaching important local markets.

 


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     The regional transmission network is composed of the remaining lines and allows the transmission of natural gas to industrial user, power stations and local distribution companies of the various local areas served.

     At December 31, 2002 the national pipeline network owned by Eni extended for 7,943 kilometers. Underground pipelines have a maximum diameter of 48 inches and carry natural gas at a pressure of 24 to 75 bars. Underwater pipelines (the only one is the pipeline crossing the Messina Strait) have a diameter of 20 to 26 inches and carry natural gas at pressure equal to or higher than 115 bars.

     The major pipelines interconnected with import trunklines that are part of Eni’s national network are:

    for natural gas imported from Algeria:
two lines with a 48/42-inch(1) diameter, each approximately 1,500-kilometer long, including the smaller pipes that cross underwater the Messina strait, which link Mazara del Vallo (on the Southern coast of Sicily) to Minerbio (near Bologna). These lines are linked to the import pipelines that carry natural gas from Algeria through the Sicily Channel. The pipeline transmission capacity amounts to approximately 87 million cubic meters/day;
 
    for natural gas imported from Russia:
three lines with 48/42/36/34-inch(1) diameters extending for a total length of approximately 900 kilometers that are linked to the Austrian network in Tarvisio and cross the Po Valley reaching Sergnano (near Cremona) and Minerbio. The pipeline transmission capacity amounts to 84.4 million cubic meters/day;
 
    for natural gas imported from the Netherlands and Norway:
two 177-kilometer long lines, with a 48-inch diameter, extending from the Italian border at Passo Gries (Verbania), the point of connection with the Swiss network, to the node of Mortara, in the Po Valley. The pipeline transmission capacity amounts to 60.7 million cubic meters/day.

     As compared to 2001, in 2002 Eni’s national network increased by 47 kilometers. The national transmission network will be upgraded by means of:

    the laying of a third line with a 48-inch diameter over 264 kilometers (124 of which already operational as of December 2002) from Tarvisio (Udine) to Zimella (Verona) on the pipeline carrying natural gas imported from Russia and the upgrade of the Malborghetto station. Works are expected to be completed by 2007;
 
    the laying of a pipeline (66-kilometer long with a 36-inch diameter) from Gela to Enna (point of connection with the pipeline importing gas from Algeria) to allow the transmission of natural gas from Libya (up to 24 million cubic meters/day). This pipeline is expected to start operations in 2004;
 
    the laying a 70-kilometer long pipeline with a 30-inch diameter (39 already operating in 2002) from Pontremoli to Parma, with completion expected in 2004, to upgrade the connection of the Panigaglia LNG terminal with the national network and local markets.

 


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     Eni’s regional transmission network is composed of pipes with diameter smaller than the national lines’ one and extends for a total length of 21,852 kilometers. These pipes carry natural gas at pressures lower than 5 bars, between 5 and 24 bars and between 24 and 75 bars.

     As compared to 2001, in 2002 Eni’s regional network increased by 141 kilometers due to the construction of the Bolzano-Bressanone and Maenza-Vitinia pipelines and of various connections to end users.

     Eni’s system is completed by: (i) 11 compressor stations with a total power of about 620 megawatts. In 2002, within the upgrading of import lines from Northern Europe, the Masera (Verbania) compression station was completed with the installation of 3 compressor units; and (ii) 4 marine terminals linking underwater pipelines with the on-land network at Mazara del Vallo and Messina in Sicily and Favazzina and Palmi in Calabria.

     Eni’s dispatching system is located in San Donato Milanese and oversees and monitors the whole transmission network in cooperation with local units. Peripheral units are represented by 8 districts that monitor the transmission network through 74 centers that guarantee operation, maintenance and control of the whole system. Each unit is responsible for operation in accordance with technical specifications and applicable laws and regulations. Two new IT projects are underway: New dispatching and Operating management of infrastructure, both aimed at upgrading information systems and equipment supporting dispatching, beside optimizing operations and maintenance of transmission infrastructure.

     In addition to the international pipeline transmission system, natural gas enters Eni’s system through the Panigaglia (Liguria) regasification plant, which receives LNG carried by tanker ships. This terminal is the only one of its kind in Italy, and has a maximum it can input approximately 3.5 billion cubic meters/year into the transmission network. LNG is downloaded from tanker ships and stored, then vaporized in a regasification plant composed of cryogenic pumps and submerged flame vaporizers. When it has recovered the gaseous state, natural gas is input in the transmission network. This terminal also regasifies LNG bought by Enel in Nigeria. In 2002, volumes of LNG regasified amounted to the equivalent of approximately 3.57 billion cubic meters of natural gas. Upgrading of this terminal is underway by means of an enhancement of the boil-off gas recovery system.

     In 2002, Eni transported 73.67 billion cubic meters of natural gas on its primary transmission network in Italy (69.58 in 2001), of which 54.56 billion cubic meters were on behalf of Eni’s primary distribution. This corresponds to an increase of 4.09 billion cubic meters, up 5.9% over 2001, due to increased volumes transported on behalf of third parties (7.70 billion cubic meters, up 67.5%), offset in part by the decline in volumes transported on behalf of Eni’s primary distribution (3.61 billion cubic meters).

     The Italian natural gas system is supplied for about 80% with imported gas, received by Eni outside Italy and transmitted to Italy through a network of international high pressure pipelines for a total of over 3,700 kilometers; in which Eni owns transportation rights, in particular:

 


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    the 924-kilometer long TENP pipeline (composed of a 500-kilometer long simple line and a 424-kilometer long doubling line) with transit capacity of 40.8 million cubic meters/day and four compression stations, transports natural gas from the Netherlands through Germany, from the German-Dutch border of Bocholtz to Wallbach at the German-Swiss border;
 
    the 291-kilometer long Transitgas pipeline, with one compression station, which transports natural gas from the Netherlands and from Norway crossing Switzerland with its 165-kilometer long main line and a 71-kilometer long doubling line, from Wallbach where it joins the TENP pipeline to Passo Gries at the Italian border. It has a transit capacity of 60.6 million cubic meters/day. A new 55-kilometer long line from Rodersdorf at the French-Swiss border to Lostorf, an interconnection point with the line coming from Wallbach was built for the transport of Norwegian gas;
 
    the 1,018-kilometer long TAG pipeline composed of two lines, each about 380-kilometer long and a third line 258-kilometer long, with a transit capacity of 81.2 million cubic meters/day and three compression stations, which transports natural gas from Russia across Austria from Baumgarten, the delivery point at the border of Austria and Slovakia, to Tarvisio, point of entry into Italy;
 
    the 742-kilometer long TTPC pipeline, composed of two lines each 371-kilometer long with a transit capacity of 78.2 million cubic meters/day and three compression stations, which transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast, where it links with the TMPC pipeline;
 
    the 775-kilometer long TMPC pipeline for the import of Algerian gas, composed of five lines each 155-kilometer long with a transit capacity of 100.8 million cubic meters/day, which crosses underwater the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into Italy.

     Various development projects of the national and international network are currently under way:

    the upgrade of the TAG pipeline through the completion of a third line 376-kilometer long in Austria (of which 258 kilometers have already been laid). This project will increase transit capacity by 25.1 million cubic meters/day, of which 13.3 are already operational;
 
    a pre-feasibility study is underway for the upgrade of the TTPC import system from Algeria with an increase in compression capacity. When the project is completed, the pipeline transit capacity will be equal to that of the TMPC pipeline;
 
    before the end of 2003 the upgrade of the TENP-Transitgas pipeline will be completed with the starting of operations of a further 44-kilometer doubling line with a 3.7 million cubic meters/day increase in transit capacity.

     In the second half of 2003 works are going to start for the laying of the Greenstream pipeline, an underwater 540-kilometer long pipe with a 32-inch diameter for the transport of natural gas from Mellitah in Libya to Gela in

 


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Sicily for the transmission of Libyan natural gas from the Wafa and Bahr Essalam fields (operated by Eni with a 50% interest), laid at a maximum depth of 1,160 meters with a transit capacity of 24.4 million cubic meters/day, capable of carrying 8 billion cubic meters/year, of which 4 billion is Eni’s share. The Greenstream will be connected to the Gela-Enna pipeline on Eni’s national network. This project is scheduled to be completed by the start of 2005 with an expenditure of euro 0.8 billion (0.6 billion is Eni’s share).

     At the end of 2002 the Blue Stream underwater pipeline started operating. This 774-kilometer long (on two lines) pipeline with a transit capacity of 48.7 million cubic meters/day, linking the Russian and Turkish coast of the Black Sea, will transport approximately 16 billion cubic meters (Eni’s share 8 billion) of natural gas to be sold on the Turkish market.

     Development Projects

     Portugal.  Eni holds a 33.34% interest in Galp Energia («Galp»), a Portuguese energy company operating in primary and secondary distribution of natural gas and in downstream oil. This investment (made in 2000) is part of Eni’s strategy of international growth in markets with interesting growth prospects, such as the Iberian market. Galp’s interest in two import infrastructures, the Transmaghreb pipeline and the Sines LNG terminal, expected to start operations in late 2003, provides Eni with a basis to access the Iberian market. In 2002 Galp, through its subsidiaries in the field of natural gas, sold about 3.3 billion cubic meters of natural gas to about 600,000 customers through a network of high, medium and low pressure pipelines approximately 9,000-kilometer long. Eni signed an agreement with the Portuguese government providing for the postponement of the IPO of Galp Energia to December 31, 2003, thus postponing also to June 30, 2004 the related six-month period available to Eni to exercise its option to purchase a proportional number of Galp Energia shares (12.9% of its share capital) if the IPO should not take place before December 31, 2003.

     Spain.  Eni operates in Spain through España Comercializadora de Gas SAU with the aim of seizing opportunities in the Spanish natural gas market. The company will supply gas to large customers at the border and to eligible customers requesting regasification and transmission of natural gas volumes to their consumption sites in Spain. In April 2002 Eni started its supplies of about 1.2 billion cubic meters per year of natural gas to Iberdrola, a primary operator in electricity in Spain. The contract has a 15-year term.

     Within its strategy of international expansion of gas activities on March 14, 2003 Eni reached a final agreement with Spanish company Unión Fenosa SA for the purchase of a 50% interest in its subsidiary Unión Fenosa Gas. This transaction will be achieved through a capital increase of Unión Fenosa Gas for euro 16 million (corresponding to 50% of its share capital after the increase to be entirely financed by Eni) with a premium of euro 424 million, bringing Eni’s total consideration to euro 440 million after the granting of authorizations by the relevant antitrust authority.

 


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     Unión Fenosa Gas is active in natural gas supply and sale to final users and to power generation companies. It holds a 25-year supply contract, with an option for a 25 year extension, involving 4 billion cubic meters of natural gas per year, with the Egyptian Natural Gas Holding Company (EGAS) and is building a liquefaction plant with a capacity of over 7 billion cubic meters per year near Damietta, on the Egyptian coast. In May 2002 Unión Fenosa Gas signed an agreement with the Government of Oman to develop a joint venture in the gas sector, including the participation in the construction of a new liquefaction plant in Oman, which is expected to start operations from 2006. From then onwards, a contract will guarantee 2.2 billion cubic meters per year for a 20-year period. In addition, Unión Fenosa Gas has two LNG Time-Charters contracted for 25 years and holds a 19% and a 45% interest in the Reganosa and Sagunto regasification plants, respectively, which will start operations in 2005.

     Management believes that Unión Fenosa Gas will benefit from the liberalisation of the Spanish gas market, which, according to management’s own estimatees, is expected to increase by an average of over 10% per year in the next five years to reach 42 billion cubic meters by 2010. The company targets a 13% market share while also developing on international markets; in particular it plans to sell approximately 2.5 billion cubic meters/year to Unión Fenosa SA’s combined cycle power plants.

     Blue Stream.  Eni and Gazprom hold equal shares in Blue Stream Pipeline Company BV, which operates the Blue Stream transport system, that links the Russian coast (at Beregovaya) to the Turkish coast (at SamSun) of the Black Sea for the transport of natural gas produced in Russia to be sold by Eni and Gazprom in Turkey to the Turkish company Botas under a contract expiring in 2026. The overall project costed about dollar 2.4 billion and is comprised of two parallel underwater lines, each 380-kilometer long and a compressor station at Beregovaya on the Russian coast of the Black Sea. Laying, which reached a record depth of 2,150 meters, was completed in February 2002 for the first line and in June 2002 for the second line; the compressor station is expected to be completed in the second half of 2003. The system was ready for operation by December 30, 2002. Commercial operations started in February 2003. Volumes transported and sold are expected to increase progressively from 2003 onwards to reach 16 billion cubic meters (8 billion net to Eni).

     Germany.  Eni and EnBW (Energie Baden-Württemberg AG, the third German operator in electricity) acquired through a 50/50 German joint venture (EnBW-Eni Verwaltungsgesellschaft mbH) a 97.81% interest in GVS (Gasversorgung Süddeutschland GmbH), the fourth operator in the German gas market. The remaining 2.19% interest is the object of a put option open to minority shareholders, which can be exercised before September 30, 2004 at the same price conditions of the purchase. The EnBW-Eni joint venture also acquired a 47.57% interest in EBS, a company in which GVS holds a 51% interest. EBS owns interests in companies in the area of natural gas distribution and co-generation. GVS transports and markets about 7.4 billion cubic meters of gas per year to local distribution companies serving about 750 municipalities in the south-western areas of the country through an approximately 1,880-kilometer long gas pipeline network. In 2001-2002(1) it generated revenues of about euro 1.5 billion and net income of about euro 59 million. On December 17, 2002 the European

 


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Commission authorized the purchase of GVS by Eni-EnBW provided that the parties accept to terminate in advance of maturity the long-term supply contracts entered by local natural gas distributors and GVS; this right will also be granted to any EnBW subsidiaries. In summary, Eni and EnBW are expected to deploy their best efforts so that GVS offers a withdrawal right to its customers (which they can exercise one time only in one of two contract years of their choice — 2004 or 2006 for the contracts expiring in 2008 and 2005 or 2007 for contracts expiring in 2015). The closing of the GVS purchase took place on December 27, 2002 for a total amount of euro 704 million paid by the joint venture. The partners financed the transaction through a capital increase of about euro 178 million (euro 89 million net to Eni); for the remaining part EnBW-Eni made recourse to financial markets. With this interest in GVS, Eni enters a large natural gas market.

     Greece. Eni holds a 49% interest in the natural gas secondary distribution companies (EPA) of Thessaloniki (about one and a half million inhabitants) and Thessaly (about 500,000 inhabitants). The two companies hold a 30-year concession for natural gas distribution to residential and commercial users and enterprises consuming up to 10 million cubic meters per year, as well as the right to use distribution networks. Eni will manage the companies’ operations and will have an option on further offers of shares. Both companies started to extend the distribution network in their areas. Natural gas sales of the two companies are expected to exceed 800 million cubic meters of natural gas per year and reach 375,000 customers served by 2005.

     Brazil. Eni is engaged in natural gas distribution in Brazil through its 88.79% owned subsidiary Gas Brasiliano Distribuidora, which holds a concession for natural gas distribution in the north-western area of the Brazilian State of São Paulo. Work is underway for the construction of a distribution network.

     Hungary. In January 2003, Tigaz (a subsidiary in which Eni holds a 50% interest) further strengthened its position in the natural gas distribution market by purchasing from the Hungarian national company MOL a majority stake in four distribution companies (Mol-Gàz, Zsàmbèrkgàz, Gerecsegàz and Turulgàz) active in the central-northern areas of Hungary for approximately euro 80 million. These companies supply an aggregate of 150,000 customers distributing a total 400 million cubic meters of natural gas to 407 municipalities. The purchase of these interests will be finalized after the authorizations by relevant authorities.

     Electricity Generation

     Eni operates in power generation and electricity sale through EniPower which owns five power stations with total installed capacity amounting to approximately 1,000 megawatts located at Eni’s refineries in Livorno and Taranto and at its petrochemical plants in Brindisi, Mantova and Ravenna. In 2002 electricity sales amounted to 6,748 gigawatthour (of these 5,004 were produced electricity), corresponding to 2.1% of all volumes input in the Italian network, also 9.3 million tonnes of steam were sold.

 


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     Eni intends to develop its electricity generation capacity by exploiting the advantages provided by the integration of natural gas and electricity production, in order to reach by 2006 an installed capacity of 6,000 megawatts, corresponding to a consumption of about 7 billion cubic meter/year of natural gas. This objective will be pursued by building new capacity at Eni’s industrial sites, in particular 12 combined cycle gas fired generators will be installed at Brindisi, Mantova, Ravenna, Ferrera Erbognone and Ferrara, while 3 more groups are going to be installed at other sites. High efficiency, low environmental impact, reduced expenditure and construction times are the main features of these plants, which show interesting profitability prospects due to the expected increase in demand for electricity and the ability to operate in co-generation (combined electricity and steam generation). The co-generation mode has been acknowledged by the Italian Authority for Electricity and Gas as a production mode that will be given priority on the national dispatching network and will be exempted from the purchase of «green certificates» (1). EniPower intends to become a cost leader in the Italian electricity industry thanks to the high technology content and optimal size of the plants it is building.

     In 2002 the following projects started: (i) construction works for the new combined cycle power station at Ferrera Erbognone (Pavia) that will have a capacity of approximately 1,030 megawatt and will be fired mainly with natural gas. When fully operational it will produce about 6.8 billion kilowatthour/year. Expected expenditure amounts to euro 550 million. The first 390 megawatt group is scheduled to start operating in late 2003; (ii) construction works for 2 new gas fired combined cycle groups for a total capacity of 780 megawatts at the Ravenna power station. The power station will reach a total capacity of over 970 megawatts and when fully operational will produce about 6.4 billion kilowatthour/year. The expected expenditure amounts to about euro 380 million. Completion and start-up of the first unit are scheduled by late 2003; (iii) in December 2002 construction works for 2 new combined cycle units for a total capacity of 780 megawatts at the Mantova power station, which will reach a total capacity of 836 megawatts and when fully operational will produce 5.3 billion kilowatthour/year. Expected expenditure amounts to euro 430 million.

     In 2002, sales of electricity amounted to 5,004 gigawatthour, of which 27% to other Eni segments. Sales of steam amounted to 9,302 million tons. Through EniPower Trading, Eni sold 1,744 gigawatthour of purchased electricity to eligible customers.

Refining & Marketing

     AgipPetroli SpA was merged into Eni SpA effective January 1, 2003 to become Eni’s Refining & Marketing division. Eni now conducts its refining and marketing activities through the Refining & Marketing division and its subsidiaries. Eni operates primarily in Italy, Europe and Latin America. Eni has the largest retail market share in Italy, with a 37.5% market share; its brands are Agip and IP. In 2002, sales of refined products totaled 52 million tons, of which 33 million in Italy. Eni’s total processing capacity of wholly-owned refineries amounted to 504,000

 


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barrels per day at December 31, 2002. In 2002, Eni’s Refining & Marketing division had net sales from operations (including intersegment sales) of euro 21,546 million and operating income of euro 321 million.

     Eni is implementing a rebalancing of its retail distribution activities in Italy and outside Italy and intends to continue the upgrading of its retail network in Italy by selling and closing marginal service stations and developing the stronger part of its network (service stations with high throughput and high non oil potential) and its non oil retail activities. Eni’s objective is to reach European standards in terms of average throughput, services to customers and automation. Outside Italy Eni intends to strengthen its position in selected areas in Europe where it can obtain logistical and operating synergies and exploit its well-known brand name. Eni also intends to increase the flexibility of its refining system aimed at optimizing its supply system and improving product quality, in line with the expected trends of demand for fuels. Eni will intensify its efforts for efficiency improvements in all its business lines.

     The matters regarding future rationalization plans discussed in this section and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include difficulties in obtaining approvals from relevant Antitrust Authorities and developments in the relevant market.

     Supply and trading

     In 2002, a total of 59.50 million tonnes of oil were purchased (58.51 in 2001), of which 34.04 million tonnes from Eni’s Exploration & Production segment, 17.06 million tonnes under long-term contracts with producing countries, and 8.40 million tonnes on the spot market. Some 25% of oil purchased came from North Africa, 24% from West Africa, 17% from the North Sea, 12% from the Middle East, 10% from countries of the former Soviet Union, 8% from Italy, and 4% from other areas. Some 27.26 million tonnes were resold, representing an increase of 4.56 million tonnes, up 20.1%, over 2001. In addition, 5.06 million tonnes of intermediate products were purchased (4.18 in 2001) to be used as feedstocks in conversion plants and 16.57 million tonnes of refined products (15.23 in 2001) were sold on markets outside Italy (10.16 million tonnes) and as a complement to own production on the Italian market (6.41 million tonnes).

     Refining

     Eni’s refining system in Italy is composed of five wholly owned refineries and a 50% interest in the Milazzo refinery in Sicily. At December 31, 2002, Eni’s wholly owned refineries in Italy had a balanced capacity of 504,000 barrels/day and conversion capacity of about 16.3 million tonnes, with a 58.5% conversion equivalent rate, one of the highest in Europe.

 


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     Within Eni’s strategy of downsizing its refining system, aimed at better balancing its own production with demand, Eni and Erg SpA conferred the Priolo (owned by Eni) and Melilli (owned by Erg) refineries in Sicily, as well as their related power stations to the newly established company Erg Raffinerie Mediterranee Srl (Eni’s interest 28%). Eni and Erg hold put and call options respectively on Eni’s interest expiring in 2006 at a set price. This operation includes a four-year processing contract under which Erg Raffinerie Mediterranee will process about 2 million tonnes/year of crudes on account of Eni and will provide to Eni refined products obtained therefrom at a set price. Following this agreement, Eni’s processing on its own account is targeted to decline by about 7.5 million tonnes in 2006.

     Eni is currently implementing a program for increasing refinery performance aimed at: (i) reducing operating costs through energy saving, more flexible operating structures and optimization of maintenance; and (ii) increasing the conversion index from the present 58.5% to over 60% by 2006, in order to improve product mix in line with the expected trends in fuel consumption.

     The table below sets forth certain statistics regarding Eni’s refineries at December 31, 2002.

                                     
                                Balanced
                                Primary
                Ownership   Conversion   Distillation
        Location   Interest   Equivalent (1)   Capacity (2)
       
 
 
 
Wholly-owned refineries:
                               
 
Sannazzaro
  Lombardy     100.0 %     42.0       160,000  
 
Gela
  Sicily     100.0 %     138.5       100,000  
 
Taranto
  Apulia     100.0 %     70.8       90,000  
 
Livorno
  Tuscany     100.0 %     11.4       84,000  
 
Porto Marghera
  Veneto     100.0 %     22.8       70,000  
   
Total wholly-owned refineries
                    58.5       504,000  
Partly-owned refineries:
                               
 
Milazzo
  Sicily     50.0 %     69.6       80,000  
 
Ingolstadt/Vohburg/Neustadt
  Germany     20.0 %     30.0       52,000  
 
Schwedt
  Germany     8.0 %     33.0       18,000  
   
Total partly-owned refineries
                    40.9       150,000  
   
Total Eni
                    48,7       654,000  


(1)   Stated in fluid catalytic cracking equivalent/topping (% by weight), based on 100% of balanced primary distillation capacity.
 
(2)   Barrels per calendar day. Based on percentage equity interest ownership in the refinery, not on actual utilization of balanced primary distillation capacity.

 


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     Each of Eni’s Italian refineries is specialized based on its logistical configuration, geographic location and integration with other Eni business segments.

     Sannazzaro, with a balanced primary conversion capacity of 160,000 barrels/day, is one of the most modern and efficient refineries in Europe. Located in the south-west of the Po Valley, at the confluence of the rivers Po and Tessin, it produces mainly gasolines and other light products for the supply of markets in Northwestern Italy, Austria, Switzerland and Bavaria. Beside its primary distillation plants, this refinery contains two catalytic reforming plants used to increase the octane number of gasolines, an isomerization plant and three desulfurization plants, which allow a high degree of flexibility of production related to market and environmental conditions. The conversion plants are: a fluid catalytic cracker (FCC), a HDCK middle distillate conversion, and a visbreaking thermal conversion. This refinery processes mainly oil from Russia and Africa incoming at the nearby Genoa harbor and oil from Eni’s nearby Villafortuna field. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genoa terminal with the French-speaking part of Switzerland and Bavaria. In 2002 a turbo expander was installed, that reduced energy consumption.

     Gela, with a balanced primary refining capacity of 100,000 barrels/day, represents an upstream integrated pole with the production of heavy crudes obtained from nearby Eni fields offshore Sicily, while downstream it is integrated with Eni’s nearby petrochemical plants. Located on the southern coast of Sicily, it manufactures fuels for automotive use and residential heating purposes, as well as petrochemical feedstocks. Its high conversion level allows it to minimize the yield of fuel oil and semi-finished products. Beside its primary distillation plants, this refinery contains conversions plants such as a FCC and two coking plants. All these plants are integrated in order to process heavy residues and manufacture valuable products. Besides its primary distillation plants, this refinery contains the following plants: an FCC reactor with advanced technology and two coking plants for the conversion of low grade feedstocks and vacuum conversion of heavy residues. All these plants are integrated in order to process heavy residues and manufacture valuable products. This refinery also contains modern residue and exhaust fume treatment plants which allow the refinery to reduce the environmental impact of its operations.

 


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     Taranto, with a balanced primary conversion capacity of 90,000 barrels/day, can process a wide range of crudes and semi-finished products with great operational flexibility. It mainly produces fuel for automotive use and residential heating purposes for the southeastern Italian markets. Beside its primary distillation plants, this refinery contains desulfurization plants, and conversions plants such as: a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant, one of the most advanced plants in the world with high yield of valuable products and low environmental impact. The plant is provided with a column for amminic washing of the gas deriving from the RHU process, which extends its useful life. This plant processes most of the oil produced in Eni’s Val d’Agri fields, carried to Taranto through the Monte Alpi pipeline which started operations in late 2001.

     Livorno, with a balanced primary refining capacity of 84,000 barrels/day, manufactures gasolines, specialty products and lubricant bases. Besides its primary distillation plants, this refinery contains two gasoline treatment plants, an isomerization plant and an octanization plant for the manufacture of highly environmental friendly gasolines, as well as a technologically advanced solvex cycle for lubricant manufacture. Its pipeline links with the local harbor and with the Florence storage sites allow the Livorno facility to operate with great efficiency with respect to reception, handling and distribution of products.

     Porto Marghera, with a balanced primary conversion capacity of 70,000 barrels/day, produces mainly gasolines and other light products for the supply of markets in northeastern Italy, Austria, Slovenia and Croatia. Beside its primary distillation plants, this refinery contains a gasoline treatment plant, octanization plants and one two-stage thermal conversion plant (visbreaking/thermal cracking) in order to increase yields of valuable products and comply with applicable environmental requirements.

     Milazzo (a joint venture in equal shares between Eni and Kuwait Petroleum Italia) has a balanced primary refining capacity of 160,000 barrels/day and contains two primary distillation plants, one naphtha treatment plant, one gasoil treatment plant and an octanization plant for the manufacture of environmentally friendly gasolines. The refinery contains also three conversion plants: one high capacity FCC for gasoline manufacture, a HDCK middle distillate conversion plant for gasoil manufacturing and one conversion plant for heavy residues with hydrogen (LC finer) which allows manufacturing of environmentally friendly products. This refinery also has two docks which allow the mooring of vessels with a maximum dead weight of 104,000 and 420,000 tons respectively.

     In Germany Eni holds an 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated industrial pole including the Ingolstadt, Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 70,000 barrels per day. Eni’s share of production of the three integrated refineries of Bayernoil and of the Schwedt refinery is mainly used to supply Eni’s distribution network in Bavaria and eastern Germany.

 


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     Eni holds a 16.33% interest in Ceska Rafinerska (CRC) which owns and manages two refineries, in the Czech Republic, Kralupy and Litvinov, with a total refining capacity of about 8 million tonnes/year. In 2002 the CRC partners approved a plan under which the refinery will supply services to oil processing services to its partners in proportion to their respective interests. This plan will be operational in the second half of 2003. Previously CRC partners purchased refined products from the refinery in proportion to their respective interests. Under the new plan CRC partners, amongst which Eni, will earn the refining margin relating to oil processed on their own account since the second half of 2003.

     Within its strategy of selective development outside Italy, which provides for Eni’s disengagement from marginal areas, in January 2002 Eni sold its 50% share in the Indeni refinery located at Ndola in Zambia.

 


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

                                         
    1998   1999   2000   2001   2002
   
 
 
 
 
    (millions of tons)
Italy
                                       
Products processed in wholly-owned refineries
    34.05       32.00       32.93       32.24       30.09  
Products processed for third parties
    (3.24 )     (2.78 )     (3.41 )     (1.45 )     (1.88 )
Products processed in non owned refineries
    7.90       8.08       8.41       5.92       6.27  
Products consumed and lost
    (1.94 )     (2.07 )     (2.11 )     (1.95 )     (1.91 )
Products available
    36.77       35.23       35.82       34.76       32.57  
Purchases of finished products and change in inventories
    5.74       5.45       4.30       5.19       6.06  
Finished products transferred to foreign cycle
    (6.51 )     (5.23 )     (4.58 )     (4.96 )     5.56  
Products sold
    36.00       35.45       35.54       34.99       33.07  
Outside Italy
                                       
Products available
    3.33       3.08       3.07       3.02       2.98  
Purchases and change in inventories
    8.35       8.06       10.27       10.27       10.41  
Finished products transferred to Italian cycle
    6.51       5.23       4.58       4.96       5.56  
Products sold
    18.19       16.37       17.92       18.25       18.95  
Sales in Italy and outside Italy
    54.19       51.82       53.46       53.24       52.02  

     Logistics

     Eni is the leading transporter of petroleum products in Italy. Its logistical integrated infrastructure consists of a network of petroleum product pipelines, 2,413-kilometer long (of which Eni owns 1,476 kilometers). Included in this system is the Val d’Agri pipeline (which started operating in 2001) that links the Viggiano oil center to the Taranto refinery over 136 kilometers.

     Eni also owns storage facilities, tanker ships and a large fleet of tanker trucks (some of which wholly owned by Eni). Eni intends to sell its tanker ship fleet made up of four vessels. In October 2002 it published a tender offer and is currently expecting the completion of the due diligence phase from possible purchasers.

     Eni also operates and owns an underground storage facility in Livorno with the capacity to store 45,000 cubic meters of propane.

     From 2000, three joint ventures with Italian oil companies are operating wich provide services of handling and storage of refined products and bunkering to their partners with the aim of reducing costs, increasing efficiency and developing innovative integrated services to customers.

     Distribution and Marketing

     Eni markets a wide range of refined petroleum products, primarily in Italy, through an extensive direct sales network, franchises and other distribution systems. The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated.

 


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    1998   1999   2000   2001   2002
   
 
 
 
 
    (millions of tons)
Retail marketing
    12.02       11.85       11.57       11.64       11.14  
Wholesale marketing
    11.73       11.42       11.10       11.24       10.64  
 
    23.75       23.27       22.67       22.88       21.78  
Petrochemicals
    5.75       5.38       4.93       4.23       3.82  
Other sales(1)
    6.50       6.80       7.94       7.88       7.47  
Sales in Italy
    36.00       35.45       35.54       34.99       33.07  
Retail sales rest of Europe
    2.35       2.36       2.35       2.47       2.57  
Retail sales Africa and Brazil
    1.11       1.54       1.43       1.71       1.44  
 
    3.46       3.91       3.78       4.18       4.01  
Wholesale marketing
    6.20       6.40       5.46       5.55       5.65  
 
    9.66       10.31       9.24       9.73       9.66  
Other sales(1)
    8.53       6.06       8.68       8.52       9.29  
Sales outside Italy
    18.19       16.37       17.92       18.25       18.95  
 
    54.19       51.82       53.46       53.24       52.02  


(1)   Includes bunkering, consumption for power production and sales to oil companies.

     In 2002, sales of refined products (52.02 million tons) decreased by 1.22 million tons, down 2.3%, due mainly to sales and closures of service stations in Italy (641 units) within the network streamlining process, to the sale of Eni’s distribution network in Nigeria and to the streamlining of the distribution network in Brazil.

     Retail Marketing

     Italy. At December 31, 2002, Eni’s retail distribution network in Italy consisted of 7,710 service stations, of which approximately 61% under the «Agip» brand name and 39% under the «IP» brand name. Eni continues the requalification process of its (owned and leased) Italian retail network by selling and closing down service stations that do not meet Eni’s target standards and by developing the stronger part of its network (stations with high throughput and high non oil retail potential). Eni’s objective is to reach European standards in terms of throughput and services provided to customers and automation. The development and upgrade of large service stations will allow to better exploit the changes that are going to be introduced in Italian regulations, such as non oil sales and longer opening hours. Within this requalification project the new IP company was established to which all leased service stations were transferred (approximately 3,000 service stations), all of which with lower average throughput than the European standard.

     In 2002, the total number of Eni’s service stations decreased by 641 units, following the closing down of 549 stations and the sale of 246 stations, offset in part by the opening of 51 new service stations and the positive balance of acquisitions and expirations of lease contracts (103 units). Eni also agreed to the sale of 330 service stations to be finalized in 2003 within swap transactions on European markets.

     The «Do-it-yourself» policy supported by the «High fidelity» campaign continued its very successful course and was extended to more Agip-branded service stations (approximately 64% of the Agip-branded network). Eni’s average throughput increased by 3.9% over 2001, from 1,643,000 liters to 1,707,000 liters. Market share was 37.5% (39.7% in 2001). The aim to improve the quality of service to customers led to a further expansion of the automation process of the domestic network. At December 31, 2002 approximately 76% of Eni’s service stations and 94% of Agip-branded service stations were provided with a corporate credit card system (60% in 2001).

 


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     In line with the intent of improving the quality of products and services, Eni started selling in its Agip-branded service stations in Italy a new diesel fuel with low environmental impact named BluDiesel, containing only 10 parts per million of sulphur (10 mg/kg) and allowing for cleaner injection and protection of the fuel burning system in cars, better combustion and faster start-up even at low temperatures, anticipating by seven years the European regulations on this issue. The BluDiesel campaign gives greater value to the potential of Eni’s integrated system (refining, logistics and distribution) selling in a traditionally undifferentiated market a well identifiable and branded product, aimed at meeting the requirements of consumers that pay more attention to the environment and greater care to their cars. Sales of BluDiesel started in November 2002 and by year-end 1,500 service stations were selling the new product which was well accepted by customers all over Italy. BluDiesel sales amounted to 35,000 tonnes in 2002. On the ordinary service stations network where BluDiesel is sold, average sales amounted to 20-25% and peaked in some instances at 50% of total gasoil sales.

     Eni continued the development of its non oil retail activities aimed at promoting the development of its network in line with European standards, such as the diffusion of self-service and innovative commercial outlets. To this end Eni owns: (i) 50% of Finifast, a restaurant and catering company with a strong presence in highway outlets, which owns a 20-year license for the Fini trademark; (ii) master franchisor rights with exclusive rights for the oil sector for some international brands of the restaurant and catering sector. In the next 8 to 10 years Eni plans to open 4-500 food outlets (200 of these in the next four years) with high visibility. In 2002, a total of 69 food outlets were opened under own brands (Agip Cafè and RistorAgip) and also under the following trademarks: Fini, McDonalds and Pans & Co. The program provides also for more service stations to be equipped with car wash facilities and convenience stores.

     Retail sales (11.14 million tons) decreased by 500,000 tonnes, down 4.3%, due mainly to sales and closures of service stations (641 units) within the network streamlining process.

     Outside Italy. As of December 31, 2002, Eni’s distribution network outside Italy consisted of 3.052 service stations located mainly in Europe and Brazil. Eni intends to increase its market share in selected areas in Europe, where it can leverage on logistical and operational synergies and on its well established brand name. In 2002 it acquired 61 service stations in France with a total throughput of about 150 million liter/year and 40 service stations in central-eastern Europe (in particular 23 service stations in the Czech Republic, 11 in Hungary and 6 in Slovakia) with a total throughput of about 71 million liters/year. Still in 2002, Eni purchased additional 313 service stations: in particular two agreements were signed with respect to the Spanish market: (i) under the first one, in 2002, Eni bought 92 service stations, with a total throughput of 300 million liters/year, and a storage site with a capacity of about 50 million liters located on the Spanish Mediterranean coast; (ii) under the second one, in 2003, Eni purchased 130 service stations with total throughput of about 320 million liters/year and a storage site with a capacity of about 56 million liters, located in Gijon in northern Spain. A third agreement concerned 91 service stations in central Europe (56 in southern Germany and 35 in central-eastern France) with a total throughput of 273 million liters/year.

     As final step of its strategy of exiting the African market, Eni finalized the sale of its distribution network in Nigeria (242 service stations) and Zambia (20 service stations).

     Galp (in which Eni has a 33.34% interest), through its subsidiary Petrogal, is a leader in refining, distribution and sale of refined products in Portugal. Petrogal owns two refineries with a total capacity of 15.2 million tons/year and a sale network made up of 965 service stations (1,082 in 2001) with a 45.6% market share (46.7% in 2001) and average throughput of 2.75 million liters (2.52 in 2001). Petrogal holds also a 42.9% market share in LPG (44.6% in 2001). Galp controls 93% of the Portuguese logistics assets. In Spain Galp has a network of 162 service stations (189 in 2001).

     Retail sales in the rest of Europe amounted to 2.57 million tonnes and increased by 100,000 tonnes, up 4.0% over 2001, due to the purchase of service stations in France (following agreements signed in 2001 with TotalFinaElf) and in central-eastern Europe. Retail sales in Africa and Brazil (1.44 million tonnes) declined by 270,000 tonnes, down 15.8% over 2001, due mainly to the sale of Eni’s distribution network in Nigeria and to the streamlining of the distribution network in Brazil.

 


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     Wholesale Marketing and Other Sales

     Eni sells gasoline, gasoil, fuel oil, lubricants, petroleum coke and LPG both directly to large customers and through independent distributors on various wholesale markets. Major customers are the agricultural and manufacturing industries, public utilities and transport companies. Eni also sells jet fuel directly at 38 airports, of which 27 in Italy, and marine fuel (bunkering) directly at 38 ports, of which 23 are in Italy. In addition, it sells virgin naphtha and fuel oil to Eni’s Petrochemical segment. Enel is the single largest customer of Eni’s Refining & Marketing division, purchasing approximately 9% of its total refined products requirements from Eni and accounting for approximately 6% of Eni’s total revenues from wholesale sales in Italy in 2002.

     Sales on wholesale markets in Italy (10.64 million tons) decreased by 600,000 tonnes, down 5.3%, due mainly to lower sales of gasoil for heating purposes. Market share decreased by 1.7 percentage points from 25.6 in 2001 to 23.9% in 2002 due to the higher share of sales of fuel oil to the thermoelectric segment in domestic consumption; Eni’s sales to this segment were not material.

     Eni concluded the reorganization of its wholesale activities by concentrating all businesses into one company (Atriplex SpA) that integrates in one central and peripheral commercial structure the segments of large and small retailers and consumers. The business was transferred as of January 1, 2003.

     Sales to Eni’s Petrochemical segment in Italy (3.82 million tonnes) decreased by 410,000 tonnes, down 9.7%, due mainly to lower availability of specific refinery products (transfer of the Priolo refinery and standstills at the Gela refinery), while other sales (7.47 million tonnes) decreased by 410,000 tonnes, down 5.2%.

     Outside Italy, wholesale sales (5.65 million tonnes) increased by 100,000 tonnes. Other sales (9.29 million tonnes) increased by 770,000 tonnes, up 9%, due mainly to higher sales to oil companies.

     Other Activities

     Eni manufactures MTBE, a gasoline additive, through its production plant located in Ravenna, Italy (with a capacity of 120,000 tons/year), and through plants operated by joint ventures in Venezuela and Saudi Arabia. Eni is also a producer of methanol through a plant operated in a joint venture in Venezuela. Additionally Eni produces and markets specialty products such as solvents, paraffins, sulfur and aromatics.

     LPG

     Eni is a leader in Italy in the production, distribution and marketing of LPG with a retail and wholesale market share of 20.9% in 2002, while market share in LPG for automotive use was 23.8%. Eni also has a significant presence in Brazil and Ecuador with market shares of 21.3% and 37.5% respectively.

     Eni’s main activities in Brazil concern the direct sale of LPG to commercial and industrial users as well as the sale of bottled LPG, mainly employed in household use. Eni owns 28 LPG storage facilities and 28 bottling facilities with a sales network composed of over 5,000 vendors. Besides bottled LPG, Eni also sells LPG directly to over 16,000 customers, provided with tanks of varying sizes under gratuitous loans. In the near future capital expenditure will be aimed at expanding and upgrading its bottle manufacturing activities (Brazilian laws allow bottlers to handle only their own branded bottles), installing new LPG tanks and modernizing bottling facilities.

     Lubricants

     Eni operates 13 (owned and co-owned) blending plants, in Italy, Europe, North and South America and the Far East. Eni is a market leader in Italy in lubricants with the manufacturing of base oils, primarily at its refinery in Livorno, and in marketing. Eni owns a 33.33% share in facilities in Italy for the reprocessing of used oils, for the manufacture of base oils and greases, it also owns two facilities for the production of additives and solvents. In 2002, retail and wholesale markets sales in Italy amounted to 154,00 tonnes with a 26.7%

 


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market share. Outside Italy sales amounted to approximately 130,000 tonnes, of these about 42% in Europe (mainly Germany and Spain) and 34% in the Americas (Brazil and the United States).

Petrochemicals

     Eni operates in the businesses of olefins and aromatics, basic intermediate products, chlorine derivatives, polystyrene, elastomers and polyethylene. Its major production sites are located in Italy and in Western Europe.

     Effective from January 1, 2002 Eni transferred its Strategic Chemicals businesses owned by Enichem SpA to Polimeri Europa Srl which (both wholly-owned subsidiaries of Eni). These businesses includes EniChem’s core activities in olefins and aromatics, intermediate products, styrene and elastomers produced in Italy in Brindisi, Sarroch, Ferrara, Gela, Mantova, Porto Marghera, Priolo, Ravenna and Settimo Milanese. Also the research centers of Ferrara, Mantova, Porto Marghera, Ravenna and Novara were transferred, as well as the interests in industrial and commercial companies in Italy and outside Italy and about 6,100 employees. Certain plants were not transferred. Assets transferred had a net value of euro 432 million (determined by an independent expert named by the court). At the same time Polimeri Europa Srl (now Polimeri Europa SpA), which produces and sells mainly basic petrochemicals and polyethylene, increased its capital (fully paid in by Enichem SpA), for a nominal value of euro 359 million and additional-paid-in capital of euro 73 million. The transaction was entirely inter-company and for purposes of legal re-organization only. Accordingly, there was no effect on the consolidated financial statements. Despite the fact that Eni owned 100% of Polimeri Europa Srl from April 2001, it continued to account for this company under the equity method, in light of the fact that it intended to sell it in 2002, after the transfer of the above mentioned assets. This treatment is consistent with Eni’s principles of consolidation. When the financial statements for the year 2001 were approved by Eni’s Board of Directors, negotiations for a possible sale were underway. During 2002 these negotiations failed and Eni began to consolidate Polimeri Europa SpA.

     The persistence of negative market conditions and the structural problems of petrochemicals worldwide, related to overcapacity, made the need for restructuring Eni’s petrochemical activities compelling. In November 2002 Eni started procedures for selling its elastomer business which produces thermoplastic rubber, specialty rubber and latices in Ravenna and Ferrara in Italy, Hythe and Grangemouth in the United Kingdom, Champagnier in France and Baytown in the United States with a total of 1,895 employees. In 2002 the elastomer division generated revenues of euro 581 million and sales of 422,000 tonnes. The due diligence phase is underway. In 2002 Eni shut down the Porto Torres soda-chlorine plant and the Porto Marghera acetylene plant.

     In 2002 the demand for petrochemical products was affected by the slowdown of worldwide economy, whose effects were partly offset by the build-up of stocks by end users. Margins of petrochemical products declined significantly over 2001, in particular for olefins and elastomers, due to a decrease in selling prices (down 8.1% on average) higher than the decline in prices in euro of oil-based feedstocks (down 1.2% on average). Indications of a return to profitability in 2003 are affected by the high risk of further increases in oil-based feedstocks prices due to geo-political tensions and uncertainties on the future recovery of world economy.

     The prices of Eni’s principal petrochemical products decreased on average by 8.1%; the main declines concerned polyethylene (down 13%, in particular HDPE) and elastomers (down 9%, in particular BR and SBR general purpose rubbers).

     Sales of petrochemical products (6,307,000 tonnes) increased by 1,074 tonnes, up 20.5%, due mainly to the entry into scope of consolidation of Polimeri Europa and to the building up of stocks by end users in the first half of 2002, in particular of polyethylene and styrenic polymers. Sales of intermediate products increased significantly.

     Production (9,575,000 tonnes) increased by 1,745 tonnes, up 22.3%. The increase in production of core business activities due also to the consolidation of Polimeri Europa was offset by the decline in chlorine

 


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production, determined by the shutting down of the soda-chlorine Porto Torres plant and by the sale of the polyurethane business (effective from May 2001).

     Total nominal production capacity declined by 1%, due to the shutting down of the Porto Torres soda-chlorine plant and sale of the polyurethane business. The average capacity utilization rate calculated on nominal capacity was substantially stable (72.1%).

     About 42% of total production was directed to Eni’s own production cycle. Oil-based feedstocks supplied by Eni’s Refining & Marketing division covered 52% of requirements in 2002.

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

                                           
      Year ended December 31,
     
      1998   1999   2000   2001   2002
     
 
 
 
 
      (thousands of metric tons)
Basic petrochemicals
    6,305       6,354       6,475       6,119       6,634  
Styrene and elastomers
    1,629       1,584       1,693       1,537       1,565  
Polyethylene
    109       109       108       84       1,376  
Polyurethane
    247       252       255       91          
 
    8,291       8,298       8,532       7,830       9,575  
Internal consuption
    (3,740 )     (3,634 )     (3,674 )     (3,185 )     (3,979 )
Purchases and change in inventories
    981       957       757       588       711  
 
Total products
    5,532       5,622       5,616       5,233       6,307  

     The table below sets forth Eni’s sales of main petrochemical products by volume for the periods indicated.

                                           
      Year ended December 31,
     
      1998   1999   2000   2001   2002
     
 
 
 
 
      (thousands of metric tons)
Basic petrochemicals
    3,984       4,029       4,002       3,928       3,681  
Styrene and elastomers
    1,207       1,241       1,253       1,138       1,178  
Polyethylene
    106       115       107       84       1,448  
Polyurethane
    235       236       253       83          
 
Total sales
    5,532       5,622       5,616       5,233       6,307  

Oilfield Services and Engineering

     Through Saipem SpA, Eni engages in the laying of underwater pipelines and installation of offshore platforms and FPSO Systems, in onshore construction (pipelaying and plant erection) and onshore and offshore drilling. Through Snamprogetti SpA, Eni is an international operator in engineering and contracting services, in particular for the oil and gas, chemical and petrochemical industries. In 2002, Eni’s oilfield services activities were positively affected by the upward trend of oil companies’ demand for services which determined an increase in activity levels and in unit margins in the offshore construction and offshore drilling activities. The engineering activity too registered good signs of recovery in demand, in particular in the area of upstream plants for hydrocarbon treatment, which shows interesting growth prospects and where Eni has strong skills and technical know-how.

 


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     In 2002 orders acquired (euro 7,852 million) increased by euro 4,136 million over 2001, up 111%, due to the good trend of marketing activities and orders acquired following the purchase of Bouygues Offshore (euro 1,119 million). About 96% of new orders acquired was represented by work to be carried out outside Italy, and 12% by work originated by Eni companies. In light of the explain in the year, Eni’s order backlog reached euro 10,065 million at December 31, 2002, with an increase of euro 3,128 million, up 45% as compared to December 31, 2001. Projects outside Italy represented 78% of the total order backlog, while orders from Eni companies amounted to 13% of the total.

     Oilfield Services

     Through Saipem (a listed company of which Eni currently owns approximately 43% of the ordinary shares, with the balance publicly held), Eni engages in the laying of underwater pipelines and the installation of offshore platforms and FPSO Systems, onshore construction (pipelaying and plant erection) and onshore and offshore drilling. Saipem owns a world-class fleet of technologically advanced vessels.

     Eni intends to develop its competitive position in the segment of large EPIC (Engineering, Procurement, Installation, Commissioning) projects for the development of offshore and deep offshore hydrocarbon fields by leveraging on the strengthening of its role of global contractor following the purchase of Bouygues Offshore and of its technological and operational skills in the area of floating production systems. In particular Eni intends to increase its know-how in floating oil production systems and in LNG floating systems that integrate production, storage, transport and regasification of natural gas. Eni intends to increase the relative importance of offshore construction and floating production systems expanding its presence in key areas in the Middle East, the Caspian Sea and South East Asia, strengthening its position in the areas with the most promising growth prospects (currently, West Africa).

     In the field of drilling Eni intends to focus on strategic geographical areas adopting long-term commercial policies that ensure high use of facilities also in case of low economic activity. In the onshore construction sector, Eni will focus on complex projects for the construction of natural gas transmission infrastructure.

     Eni intends to intensify efficiency improvements in all its activities and in the management of working capital.

     Among the most significant orders won in 2002 are:

    In the Offshore construction area: (i) a turnkey contract for dollar 662 million for Esso Exploration & Production Nigeria Ltd, related to a floating production, storage and offloading (FPSO) system for the development of the Erha field offshore Nigeria. The project includes engineering, procurement, construction, towing and commissioning of the FPSO, consisting of a 285-meter long, 63-meter wide and 32-meter high hull and 24,000 tonnes of production modules. The vessel will have a storage capacity of 2.2 million barrels and an initial production capacity of 165,000 barrels/day. The FPSO is scheduled to arrive on the Erha field in June 2005, in line with planned start-up in late 2005; (ii) a turnkey contract, awarded by Mobil Producing Nigeria Unlimited for dollar 345 million for the development of the Yoho and Awawa offshore fields which includes project management, engineering, procurement, construction, transportation and installation, hook up and commissioning of one production platform, underwater pipeline laying and the installation of other facilities. The Castoro 8 vessel will install the platform and lay the pipelines between late 2003 and early 2004, whereas the Saipem 7000 vessel will install the deck during the second half of 2004. The project is expected to be completed by the end of 2004; (iii) the EPSC2 turnkey contract for phase 4 of the Peciko Project for TotalFinaElf for euro 149 million. The contract includes engineering, procurement, transport and installation of two platforms and six sealines, offshore east Kalimantan in Indonesia. Marine activities performed by Castoro 2 and Maxita are expected to be completed by July 2004; (iv) a contract for euro 63 million for Shell for the Goldeneye Project in the North Sea, comprising the laying of two sealines by Castoro 6; (v) in joint venture with the Nigerian company Pelfaco a contract for the supply of the Okpoho platform for the development of the Okpoho field offshore Nigeria operated by Eni with a 100% interest. The contract (euro 53 million) includes engineering, procurement, construction and start-up activities.

 


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    In the Offshore drilling area: a contract with Statoil for a three-year lease of the Scarabeo 5 platform in the North Sea. The contract (dollar 160 million) includes the option of a 16-month extension.
 
    In the Onshore construction area: (i) a turnkey contract for the construction of an oil treatment plant in the Rhourde Ouled Dejmaa (ROD) field in Algeria with a capacity of 80,000 barrels/day for Sonatrach/BHP for dollar 129 million representive Eni’s share. The contract provides for the engineering, procurement and construction of the treatment plant and its auxiliary installations (a network of pipelines and some storage sites) and the provision of services for the operation of the plant; (ii) a contract with the Nigerian company NAOC for the upgrade of the gas plant at Obiafu/Obrikom and the construction of a flow station near the Irri field in Nigeria. The contract provides for the engineering, procurement and construction of the plant for an amount of dollar 72 million.

     At December 31, 2002, the order backlog of Saipem amounted to euro 5,158 million (compared with euro 2,853 million at December 31, 2001), of which approximately 96% related to projects outside Italy and approximately 12% related to orders from Eni group companies.

     On July 9, 2002, Saipem completed the acquisition of Bouygues Construction’s 50.8% interest in Bouygues Offshore after receiving the approval of the European Antitrust Authority. Bouygues Offshore is a French company leader in the field of engineering services for the oil industry. The cash offer price was euro 60.08 per share. Following approvals from the French and USA market authorities Saipem launched a tender offer for the remaining shares held by the public at the same price paid to Bouygues Construction for its majority interest. This tender offer on the French market was completed on September 6, 2002 with the purchase of a further 46% interest in Bouygues Offshore (thus bringing Eni’s total amount of voting rights to 96.8%). On September 23, 2002, Saipem performed a repurchase offer followed by a squeeze-out of the minority shareholders. Such procedures were closed on October 30 and Bouygues Offshore shares were withdrawn from the Paris and New York Stock Exchanges. At the end of these procedures Saipem owned 100% of the voting rights and 98.8% of the share capital, the remaining 1.2% being represented by treasury shares held by Bouygues Offshore for its stock option plans. The total cost of this transaction was euro 906 million (net of cash acquired for euro 100 million).

     The combination of Saipem’s construction capabilities supported by technologically advanced vessels and Bouygues Offshore’s engineering and project management expertise creates an operator able to compete in the market of turnkey projects to the oil industry. With this acquisition Saipem strengthens its competitive positioning in the provision of project management, engineering, procurement and construction services for the development of hydrocarbon fields, with a particular focus on challenging projects in remote areas, deep-water environments and gas-related projects. The new group will be a truly worldwide contractor, with strong local presence in strategic and emerging areas such as West Africa, the former Soviet Union, Central Asia, North Africa, Middle East and South East Asia. Bouygues Offshore has a sound competitive position in the market of services for onshore and offshore oil and gas production facilities. Other activities include maintenance services, construction of port facilities, and LNG supply. Bouygues Offshore’s main geographic areas of activity are Europe and Africa. The company employs approximately 2,500 engineers.

     In 2002 Eni purchased: (i) a 50% interest in European Marine Contractors (EMC), operating in the laying of large diameter subsea pipelines in the North Sea, in which it already held a 50% interest. Eni’s outlay amounted to euro 122 million. With this acquisition Eni obtains full availability of EMC vessels, among which the semisubmersible drilling rigs Castoro 6 and Semac and consolidates its capability in the field of large diameter pipelaying in deep waters: (ii) the whole share capital of SaiClo Luxembourg for euro 23 million, owner of the Maxita multipurpose vessel capable of laying flexible, umbilical lines and mooring systems in deep waters.

     Engineering

     Eni, through Snamprogetti, is engaged in engineering and contracting, in the area of plants for hydrocarbon production, refining, treatment and enhancement of natural gas, fertilizers and petrochemicals, pipeline transport systems, electricity generation and infrastructure.

 


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     Its firm standing on international markets as global contractor for complex projects is ensured by various competitive advantages deriving from its long track record in international contracting, its ability to supply integrated packages and turn-key projects, a flexible organizational structure and a continuous development of advanced proprietary technologies. The services offered cover the whole cycle of investments: consulting, feasibility studies, project financing assistance, basic and executive engineering, project management, procurement, supervision and direction of operations, testing and first operation of plant, personnel training.

     In over forty years of activity, Eni has operated in more than 100 countries, building 70 industrial grass-root complexes, over 1,300 plants (refineries, chemical and petrochemical plants, infrastructure, offshore rigs, marine terminals) and engineering 66,000 kilometers of onshore (for 45,000 kilometers of these it also carried out construction works) and 12,000 kilometers of offshore pipelines, including deep waters and hostile environments.

     Eni intends to consolidate its competitive positioning in the market segment of complex projects requiring a wide and integrated range of services, flexible organization and a continuous development of new technologies. It will therefore stress its role of global contractor based on its distinctive operating skills, the level of services provided and advanced proprietary technologies. It will focus its activity on market segments characterized by high growth rates and by the development of important technologies in strategic areas such as hydrocarbon production, treatment and transmission as well as upgrading of natural gas (conversion and liquefaction) and of heavy crudes. Eni intends to pursue a balance between turn-key contracts and special services (such as conceptual, basic FEED and PMC) as well as the participation in relevant projects. It will also intensify actions for improving efficiency and operating flexibility.

     In 1991, Eni’s Oilfield Services and Engineering segment, through its interest in Cepav Uno and Cepav Due consortia, signed two conventions with TAV SpA («TAV») to participate in the construction of the high speed railway from Milan to Bologna and from Milan to Verona. Eni holds a majority stake in both Cepav Uno (Eni’s interest 50.36%), in charge of building the track from Milan to Bologna (currently under construction) and Cepav Due (Eni’s interest 52%), in charge of building the track from Milan to Verona (for which arbitration is under way against TAV due to the withdrawal of the concession previously awarded to TAV itself from Ferrovie dello Stato).

     Among the most significant orders won in 2002 are:

    in the Oil & Gas and Refining area: (i) in joint venture in equal shares with Technip-Coflexip, Kellog Brown & Root and JGC, a turnkey contract for the expansion of the Bonny liquefaction plant in Nigeria for Nigeria LNG. The «NLNGplus» project has a value of over dollar 1.7 billion (25% is Eni’s share) and provides for the construction of the fourth and fifth LNG production trains with a capacity of approximately 5.2 billion cubic meters/year each. The trains will produce also 1.1 million tonnes/year of LPG and 0.4 million tonnes/year of condensates. When the two trains are completed in 2005, the Bonny plant will process 75 million cubic meters of natural gas/day with a total production of 21.8 billion cubic meters/year of LNG and 2.3 million tonnes/year of LPG; (ii) a turnkey contract for the design, procurement and construction of an industrial complex near Qatif, about 30 kilometers from Dhahran in Saudi Arabia for Saudi Aramco. The complex includes two plants for the separation of oil from gas (GOSP) and units for natural gas treatment, oil stabilization and power generation with a treatment capacity of 800,000 barrels/day. The work is expected to be completed in 31 months; (iii) in joint venture with the Japanese companies Chiyoda and Mitsui & Co Ltd, a turnkey contract to build the fourth production line of liquefied natural gas at the Ras Laffan complex for Ras Laffan Liquefied Gas Company in Qatar that will produce approximately 4.7 million tonnes/year of LNG. The plant will be completed before the end of 2005. The contract includes engineering, procurement and construction. The Ras Laffan complex produces 6.6 million tonnes/year of liquefied gas in two production lines. Snamprogetti is working also on the design and construction of the third line, with a capacity of 4.7 million tonnes/year under a contract won in 2001;
 
    in the Chemicals and fertilizers area: a contract to build a fertilizer complex in Oman. The project has a value of dollar 770 million (50% is Eni’s share) and will be carried out through a 50/50 joint venture with Technip-Coflexip for Oman-India Fertilizer Company (OMIFCO) and will be the world’s largest grass-roots fertilizer complex. It will consist of two 1,750 tonnes/day ammonia plants and two 2,530 tonnes/day urea plants. The contract includes engineering, design, materials, construction

 


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      management, start-up supervision and training of OMIFCO personnel. All these plants will use proprietary technologies of Snamprogetti and its affiliate Haldor Topsøe, a Danish company (in which Eni holds a 50% interest) operating in the provision of engineering services and the manufacture and sale of catalysts for the chemical, petrochemical and refining industries.

     At December 31, 2002, the order backlog of Snamprogetti amounted to 4,907 million euro (compared with 4,084 million euro at December 31, 2001), of which approximately 35% related to projects outside Italy.

Libya project

     In Libya, within the joint development plan of the oil, gas and condensates fields of Wafa and Bahz Essalam operated by Eni with a 50% interest (the other partner being the Libyan national company NOC), Eni companies were awarded five contracts:

    in a consortium with Hyundai Heavy Industries, a turnkey contract for the construction and installation of the Sabratha production platform, offshore western Libya, about 100 kilometer north of Tripoli, within the development of the offshore Structure C fields in permit NC-41. The total value of the contract is estimated at euro 620 million, of which Saipem’s share is euro 420 million and includes project management, engineering, procurement, fabrication, transportation and installation, hook-up and commissioning, start-up and six month of operational assistance. The platform will be installed during the first half of 2004 at a water depth of 190 meters using the Saipem 7000 vessel;
 
    a turnkey contract to a consortium led by Snamprogetti (other partners being ABB Lumus and Hyundai Engineering and Construction) for the construction of a grass-root treatment plant for gas, crudes and liquid hydrocarbons from the Libyan offshore at Mellitah. The total value of the contract is euro 700 million. The consortium will provide engineering, procurement and construction of the plant that will have a capacity of 6.66 billion cubic meters/year. Work is expected to be completed in 29 months;
 
    the third contract to Saipem with a value of approximately euro 400 million, includes project management, engineering, procurement, fabrication, transport and installation of two pipelines linking the Sabratha offshore platform to Mellitah on the Libyan coast, in addition to fabrication and installation of auxiliary facilities. The project will be carried out by the Castoro 6 vessel during the first half of 2004 and is expected to be completed in the spring of 2005;
 
    a fourth contract awarded to Bouygues Offshore in joint venture with Doris Engineering for euro 133 million includes design, construction and installation of an underwater production system at a water depth of 190 meters;
 
    a fifth contract for approximately euro 285 million was awarded to Saipem and involves the laying of the Green Stream pipeline linking Mellitah on the Libyan coast about 80-kilometer west of Tripoli to Gela in Sicily. The 540-kilometer long pipeline with a 32-inch diameter will be laid at a maximum water depth of 1,160 meters. Pipelaying activities will be carried out during the second half of 2003 by the vessel Castoro 6. The project is scheduled to be completed in June 2004.

Other Activities

     Eni SpA engages in strategic planning, human resources management, finance, administration, legal affairs, international affairs and corporate research and development functions for the Company. Through Enifin SpA, Societa Finanziamenti Idrocarburi-Sofid SpA and Eni International BV, Eni carries out lending, factoring, leasing and insurance activities, principally on an intercompany basis. Eni also engages in information technology, communications, technology research and other activities.

     Starting from January 2003 Eni’s non-core activities have been reorganized as follows:

    Syndial (former EniChem) was included in the «Other Activities» segment, which includes all Eni companies not included in specific segments (such as, among others, EniData, Sieco, Tecnomare, EniTecnologie, Eni Corporate University, AGI);

 


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    the new «Corporate and financial companies» segment was created, which includes Eni Corporate, Eni Servizi Amministrativi and the financial companies formerly included in the «Other Activities» segment.

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

Research and Development

     Eni conducts research and development activities within each of its principal operating subsidiaries and through EniTecnologie SpA, which is responsible for corporate research and development. Eni’s research and development expenses amounted to euro 234 million, euro 203 million and euro 175 million in 2000, 2001 and 2002, respectively. In year 2002, 1,390 employees were involved in research and development activities. During the year, 50 applications for patents were filed in Italy (65 in 2001).

     Eni’s activity aims at extending the boundaries of knowledge and promoting the exchange of experience, expertise and know-how, in the belief that technological excellence is an essential factor in competition and economic and industrial sustainability. To this end Eni is constantly striving in the research and development of technologies, services and products with a distinctively innovative character.

     In 2002 Eni reviewed the role of research and development in the light of the following guidelines: (i) to increase resources devoted to upstream issues; (ii) to allocate more resources to the development of prototypes; (iii) to support qualified laboratory research in order to direct it to long-term radical innovation.

     In accordance with these guidelines, the major turning points achieved in 2002 have been: (i) the implementation of a new model of innovation which integrates activities aimed at incremental improvement managed by business units with the long-term innovative projects managed by Eni corporate functions by means of a coordination center and the allocation of costs directly to corporate functions for the most innovative projects; (ii) a reorganization of R&D structures aimed at integrating all homogeneous skills and knowledge centers, including the laboratories of the Refining & Marketing division and of Snamprogetti.

     In the course of 2002, many technologies were implemented at the industrial level for the first time:

     In the Exploration & Production division, an innovative technology (Level 6 Junction) was developed and applied to a well in Nigeria that allows to divide the well in a number of branches while maintaining safety requirements and reducing operating costs and impact on the ground (Prime flow).

     Another innovative method was developed and applied. It does not require invasive inspections of pipes, but is based on indirect measurements capable of locating any obstructions, such as waxes and asphaltenic deposits, within flowlines.

     In the Refining & Marketing division, marketing of the new formula gasoil «BluDiesel» started and certification was obtained from a major German car manufacturer for an innovative «fuel economy» lubricant.

     In Petrochemicals, improved performance polymers were developed such as linear polyethylene for extensible films and thermoplastic elastomers for the compound area. A new competitive process for the manufacture of ethylbenzene was developed and tested as well as a new catalyst for the manufacture of linear polyethylene.

     Many technologies reached an advanced development stage.

     In the Exploration & Production segment, initial applications are underway based on original proprietary techniques of CRSS, a new method for the elaboration of geophysical data, that allows a more accurate definition of subsoil imaging. A new integrated IT application named SCREAM was developed which allows for the search of analogue situations in carbonated reservoirs, in existing database or reporting with a very fast access to geomineral data and information with significant reductions of the time necessary to start production. The corporate research function is developing, among other things, technologies to reduce the density of drilling fluids by means of hollow glass micro spheres and to stop water infiltration by means of the RPM (Relative Permeability Modifier) polymer.

 


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     In the Gas & Power division, the experimenting phase is nearly completed for the «Synthesis of waxes by means of Fischer Tropsch» technology used in a pilot plant built at Eni’s Sannazzaro refinery. Use in a pilot plant confirmed the performance of the new partial catalytic oxidation technology for the production of synthetic gas or hydrogen.

     At the Taranto refinery construction started of the Eni Slurry (EST) demonstration unit with a 1,200 barrels/day capacity for the upgrading of heavy oils.

     Various improvements were introduced in the designing and laying of pipelines, with specific reference to the use of high and very high grade (X-80 e X-100) steel and to advanced telecollection systems for the definition of routes and for the optimization of deep water operations (drilling, field development).

     In the Refining & Marketing division, work continued on the quality improvement of fuels, gasoline, gasoils and lubricants, fuels for special use in turbines and oil drilling operations.

     Work on environmental issues continued, focused in particular on the reduction of polluting emissions by means of the optimization of the vehicle/fuel ratio and the reclaiming of industrial sites also with biological techniques.

     Major research areas in 2002 were:

Reduction of exploration and development costs

Geosciences
High resolution prospecting techniques
Field simulation models
Field productivity enhancement methods
Advanced drilling systems
Production in hostile environments

Performance and product differentiation

Advanced process control
Innovative polymerization catalysis

Feedstocks enhancement

Long distance gaslines
Conversion of gas into liquid products
Conversion of heavy crudes into light products

Environmental protection

Hydrogen
New formulas for fuels and lubricants
«Clean» catalytic processes
Air quality monitoring
Reclaiming of polluted soil

Insurance

     Eni constantly assess its exposure for the Italian and foreign activities that are mainly covered through the Oil Insurance Limited («OIL»), a mutual insurance and reinsurance company that provides to its members a broad coverage tailored to the specific requirements of oil/energy companies. Eni makes use of a captive insurance company that covers the risks and implements Eni’s Worldwide Insurance Program placed with high-quality securities in order to integrate the terms and conditions of the OIL coverage.

     An insurance risk manager works in close contact with managers directly involved in core business activities in order to evaluate potential risks and their financial impact on the Group. This process allows to define a constant level of risk retention and, conversely, the amount of risk to be transferred to the market.

     The level of insurance maintained by Eni is generally appropriate for the risks of its businesses.

 


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Environmental Matters

     Together with other companies in the businesses in which it operates, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, limit or prohibit drilling activities on certain protected areas, and impose criminal or civil liabilities for pollution resulting from oil, natural gas, refining and petrochemicals operations. These laws and regulations may also restrict air emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemicals plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the generation, handling, transportation, storage, disposal and treatment of waste materials.

     Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in particular operations and products of Eni, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. Although management, considering the actions already taken, the insurance policies to cover environmental risks and the provision for risks accrued, does not currently expect any material adverse effect upon Eni’s results of operations and financial position as a result of its compliance with such laws and regulations, there can be no assurance that there will not be a material adverse impact on Eni’s results of operations and financial position due to: (i) the possibility of as yet unknown contamination; (ii) the results of the on-going surveys and the other possible effects of Decree No. 471/99 of the Ministry of Environment; (iii) the possible effect of future environmental legislation and rules; (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

     The recently enacted environmental legislation includes improvements of previous laws on operations, safety and waste waters, as well as regulations on waste disposal and remediation or shutdown of industrial sites. Eni is evaluating actions (such as voluntary agreements) and investments to comply efficiently with new regulations. In accordance with European guidelines, the protection from water pollution was strengthened with Legislative Decree No. 152/99 as completed by Decree No. 258/00, which provide for an integrated protection of water resources by extending control from each discharge place to all the effects of accumulation and interactions of various discharges into one single water course and set quality objectives to be reached within 2008. All discharges require preventive authorization, to be renewed every four years, and must lie below the thresholds set by Regions. Legislative Decree No. 152/99 sets the term of June 2002 for the upgrade of existing discharges to the new rules.

     To date Eni cannot evaluate the possible impact of the application of Decree No. 152/99, however there can be no assurance that there will not be a material adverse impact on Eni’s operations due to measures adopted by local authorities whenever the quality of a certain water source does not comply with set standards due to the industrial activity of all plants located above that water source. Legislative Decree No. 258 states that production water discharges from oil activities performed in the sea shall be progressively substituted by injection or reinjection in deep geological strata. Previously such production water discharges were treated as waste disposal. Eni expects that capital expenditure necessary to provide offshore wells with reinjection facilities will be paid off by lower operating expenses with respect to waste disposal costs.

     Management of waste, toxic waste, packaging and packaging waste is regulated by Legislative Decree No. 22 of February 5, 1997 which refers to three European Directives (91/156/CEE, 91/689/CEE and 94/62/CE) and provided incentives to clean technologies and recycling and reuse of waste. This decree prohibits the uncontrolled disposal of waste underground and in the water and obliges polluting entities to reclaim polluted areas. Whenever it is not possible to identify one person or entity responsible for existing pollution, the owner of the polluted area is expected to pay for its reclamation. This decree became operational with decree No. 471/99 of the Ministry of the Environment, which also defined limits for the contamination of soils and underground waters, the general guidelines for reclaiming and environmental recovery of polluted areas, and the criteria for the identification of polluted areas of national interest. For the storage of toxic waste, the decree favors techniques avoiding transport of waste and their on-site treatment. Whoever causes, wilfully or accidentally, pollution of an area or actual danger is expected to react within 48

 


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hours according to the procedure set by the decree. At present Eni is not yet able to evaluate the possible future consequences deriving from the completion of on-going surveys and other possible effects of the application of Decree No. 471/99 of the Ministry of Environment; however there can be no assurance there will not be a material adverse impact on Eni’s results of operations and financial position from the application of that decree. Law 388/00 changed the regulations concerning the reclamation of polluted sites, easing the discipline of crimes related to events prior to Legislative Decree No. 22/97 and imposing the reclamation of sites where industrial activity is ongoing. However, the reclamation is to be carried out provided that it does not involve a significant disruption in operations; reclamation costs can be amortized in ten years.

     In the next years Law 372/99 will gradually enter into force. This law, which is related to the European Directive 96/61/CE (IPPC — Integrated Pollution Prevention and Control), envisages that industrial installations will apply for an integrated authorization concerning emissions, wastes and water discharges. Before June 20, 2002 the competent authority is expected to define a schedule for the filing of requests for IPPC authorization. Many of Eni’s plants — refineries, chemical plants, power stations — will have to comply with this law but Eni expects no adverse impact on its operations, since the IPPC authorization intends to integrate and make compatible authorizations which now are given separately.

     In 2003, according to the IPPC Directive, the Member States must communicate their 2001 national values of emissions into the atmosphere, wastes produced and managed and, finally, discharges into water of some compounds specified in the annexes of the directive relative to EPER (European Pollutant Emission Register). The Directive applies to several Eni plants, so the Eni divisions and/or companies which own these plants, are going to report their data to the authority in charge of preparing the Italian national communication.

     To meet future environmental obligations, Eni is engaged in a continuing program to develop effective measures for the protection of the environment. This program includes research and capital expenditures related to reducing sulphur levels in heavy fuel oils and diesel fuel, reducing benzene and sulphur content in gasoline, improving the quality of emissions and effluents from Eni’s refineries and petrochemical plants, developing and installing monitoring systems at Eni’s facilities and developing environmental impact assessments for major projects.

     During 2002 the Kyoto Protocol has been ratified by the EU and also by Italy, with Law 120/2002. After the Italian Government ratified the Kyoto Protocol, Eni actively participated in the definition of the National Action Plan for the reduction of greenhouse gas emissions. Eni companies are engaged in a comprehensive plan aimed at:(i) improving and adopting an advanced protocol for greenhouse gas emissions accounting and certification; (ii) defining a portfolio of projects for emission reduction in its own installations and a portfolio of ongoing and new projects consistent with the Flexible Mechanisms of the Kyoto Protocol (Clean Development Mechanism and Joint Implementation); (iii) participating to international emission trading markets (EU is finalizing a directive for the introduction of an emission trading scheme, by the year 2005; (iv) preparing a medium-long term strategy for the sustainable management of greenhouse gases.

     A recent important development in the Italian environmental legal system is the draft law for the restructuring of all environmental legislation. The draft law has been firstly proposed at the end of 2001 and is now being re-examined by the Italian Parliament after the adoption of some amendments. The main target is to better coordinate and integrate various environmental laws, in view of a more complete harmonization with EU legislation. It is difficult to predict now the overall impact on Eni operations, but certainly the present Italian environmental legislation in some cases is stricter than the EU counterpart.

     In order to more effectively respond to and anticipate the increasing complexity of the international and national environmental legislation, to better adapt to the international context where it operates and to increase its effectiveness in the implementation of its Corporate HSE Guidelines, during 2002 Eni created the HSE Corporate Department, with the following tasks: (i) elaborating a plan consistent with Eni’s policies and guidelines; (ii) defining a HSE management system model, to be used as reference by all business units; (iii) responding to the increasing challenges of sustainability by means of the design and the implementation of a sustainable energy system.

     In 2002, operating and capital expenditures in health, safety and environment amounted to euro 887 million. Environmental expenditures amounted to euro 590 million, of which euro 51 million related to air emissions, euro 79 million to water, euro 88 million to waste and euro 147 million to soil. In addition to operating and capital expenditures, Eni also creates provisions for future environmental remediation. Expenditures against such provisions are normally incurred in subsequent periods and are not included in

 


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environmental operating expenditure. Provisions for environmental remediation are made when a clean-up is probable and the amount reasonably determinable. Generally, their timing coincides with the commitment to a formal plan of action or, if earlier, on divestment or closure of inactive sites. In addition, Eni makes provisions against costs expected to be incurred with respect to the abandonment of hydrocarbon-producing assets. In 2002, Eni accrued euro 184 million to the site restoration and abandonment reserve. See ‘‘Note 13 to the consolidated financial statements — Reserves for contingencies and other deferred non-current tax liabilities’’ for more details regarding environmental and site restoration and abandonment reserves.

     In 2002, the equivalent of about 1,373 full time employees were employed by the Group in the area of health, safety and environment.

     The total certifications (ISO 14000, OHSAS, EMAS, ISM, etc.) obtained in 2002 were 85, of which 7 in the Exploration & Production division, 18 in the Gas & Power division, 24 in the Refining & Marketing division, 22 in the Petrochemical segment and 14 in the Oilfield Services and Engineering segment. To ensure operating efficiency of health, safety and environment management systems, 501 internal auditors were available in 2002.

     Training played a relevant role in the management of safety and environmental issues, with a total of 279,466 hours of HSE training provided to 68,155 participants in 2002.

     In the area of health Eni employs a system of constant monitoring, increasing the frequency of checks where risks are higher. In 2002, a total of 34,086 medical examinations and 215,418 medical tests were performed in the whole Eni Group.

     Regarding Safety, in 2002 both accidents rates (frequency and seriousness) showed a marked improvement compared with the values of the previous year.

     Regarding environmental issues, in 2002 greenhouse gas («GHGs») emissions from flaring (representing 37% of Eni total GHGs emissions) decreased by 4,7% compared with the values of the previous year.

     Pursuing the creation of a sustainable energy system, in 2002 Eni further developed action plans for the reduction of greenhouse gas emissions and the mitigation of the possible impact of climate changes. In this perspective Eni continued its programs for the development of natural gas in Italy and abroad by means of technologically advanced projects such as Blue Stream (a gas pipeline from Russia to Turkey) and Greenstream (a gas pipeline which allows to increase the Italian imports of natural gas). Outside Italy Eni is also implementing a «Zero Gas Flaring Program», with the development of projects in Nigeria and Congo (construction of new high efficiency combined cycle power plants for the exploitation of associated gas, coming from the near oilfields).

     Furthermore, in 2002 Eni Refining & Marketing division launched a new product: BluDiesel, a virtually sulphur free diesel fuel which anticipates environmental regulations and ensures better engine performance. This product is currently sold in 1,500 service stations with average sales amounting to 20-25 % of total gasoil sales and in some cases peaking at 50%.

Regulation of Eni’s businesses

     Regulation of exploration and production activities

     Eni’s exploration and production activities are conducted in many different countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil and gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See «Regulation of the Italian Hydrocarbons industry» and «Environmental Matters» for a description of the specific aspects of the Italian regulation and of environmental regulation concerning Eni’s exploration and production activities.

 


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     Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any royalties that are payable in kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in kind. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area.

     Production sharing agreements (PSAs) entered into with a government entity or state company generally obligate Eni to provide all the financing and bear the risk of exploration and production activities in exchange for a share of the production remaining after royalties, if any.

     In general, Eni is required to pay income tax on income generated from production activities (whether under a license or production sharing agreement). The taxes imposed upon oil and gas production profits and activities may be substantially higher than those imposed on other businesses.

Regulation of the Italian Hydrocarbons Industry

     Overview

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

     The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the «Hydrocarbons Laws»).

     In the early 1990s, the Government commenced the gradual liberalization of the Italian hydrocarbons industry by implementing legislation that provided for, among other things, (i) the elimination of price controls on petroleum products, (ii) the abolition of Eni’s right of first refusal with respect to the purchase of natural gas produced offshore Italy, (iii) the implementation of a partial third-party access system for the transportation of domestic natural gas, (iv) the establishment of a system for the updating of on natural gas retail prices and (v) the establishment of a royalty reduction program. Law No. 481 of November 14, 1995 (the «Authority Law»), provided for the establishment of a new regulatory body, known as the Autorità per l’Energia Elettrica e il Gas (the «Authority»), the Italian Public body charged with, among other things, regulatory supervision of electricity activities and natural gas distribution in order to guarantee the promotion of competition and efficiency while providing for an adequate level of service quality. As the latter is concerned, the Authority is mainly responsible for the public service of natural gas distribution through urban networks.

     Decree No. 164, which enacted into Italian Legislation European Directive on Natural Gas 98/30/CE, regulates the Italian natural gas market. Prior to the implementation of Decree No. 164, the Italian natural gas market lacked a legislative framework. See «—Natural Gas».

     Legislative Decree No. 32 of February 11, 1998 («Decree No. 32») as amended by Legislative Decree

     No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, significantly changed Italian regulation of service stations. In particular, the Decree replaced the process of concessions granted by the Ministry of Industry, regional and local authorities with a license granted by city authorities. See «—Refining and Marketing of Petroleum Products».

     Legislative Decree No. 443 of October 29, 1999 («Decree No. 443) modified Legislative Decree No. 112 of March 31, 1998 («Decree No. 112») which attributed to Regions many responsibilities in the field of energy and specifically in the sector of hydrocarbons. Decree No. 443 attributes to the State administrative decisions

 


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concerning exploration and production of hydrocarbons in the Italian offshore as well as natural gas storage in fields, whilst administrative decisions concerning exploration and production of hydrocarbons on the Italian mainland are made by the Government in agreement with Regions.

     Exploration and Production of Hydrocarbons

     Exploration Permits and Production Concessions.  Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are the property of the State. Exploration activities require an exploration permit, while production activities require a production concession, in each case granted by the Ministry of Industry. The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State. The initial duration of a production concession is 20 years, with the possibility of obtaining one ten-year extension and additional five-year extensions.

     Royalties.  The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. Royalties are equal to 7% and 4%, respectively, for onshore and offshore production of oil and 7% for both onshore and offshore production of natural gas.

     Preferential Rights.  Until December 31, 1996, Eni was entitled to a number of preferential rights, including, among other things, the exclusive right to explore for and exploit, without permit or concession, hydrocarbon deposits in the Exclusive Area.

     In 1994, the EU enacted a licensing directive (the «Licensing Directive»), which required member states to enact legislation eliminating, by December 31, 1996, all laws that provided exclusive rights to a single entity in a specific geographic area. Decree No. 625, which was adopted to implement the Licensing Directive, eliminated the exclusivity of Eni’s rights in the Exclusive Area. Decree No. 625 allows Eni to obtain upon application exploration permits and production concessions having effect from January 1, 1997 that would preserve such rights as have vested under the regime of exclusivity (based on the activities that have been carried out or are currently underway). As of December 31, 2002, Eni held 100 exploration permits and 180 production concessions for a total net acreage of 43,961 square kilometers and 9 storage concessions.

     Natural Gas

     Legislative Decree No. 164 of May 23, 2000 for the Implementation of the European Directive on Natural Gas 98/30/CE.  The European Directive on natural gas was implemented into Italian legislation through Legislative Decree No. 164 of May 23, 2000 («Decree No. 164»), effective from June 21, 2000. As concerns natural gas activities carried out by Eni the most relevant aspects of the decree are as follows: (i) it defines until December 31, 2002 eligible customers (with access to the natural gas system) to be: final customers consuming more than 200,000 cubic meters per year; wholesalers and all distributing companies; electricity producers and co-generators; consortia consuming more than 200,000 cubic meters per year provided each partner consumes more than 50,000 cubic meters per year. Starting in 2003 all customers are eligible customers; (ii) from January 1, 2003 to December 31, 2010 no single operators is allowed to hold a market share higher than 50% of domestic sales to final customers. In addition, no single operators is allowed to supply more than 75% of all natural gas volumes introduced in the domestic transmission network by 2002, decreasing by 2 percentage points per year until it reaches 61%. The two ceilings are calculated net of losses (in the case of sales) and own consumption. A three-year average mechanism is used to evaluate whether volumes introduced in the domestic transmission network or sold to final customers are above set ceilings. Those ceilings are considered exceeded if at the end of the first three-year period, the average of volumes introduced in the domestic transmission network or sold to final customers is higher than the allowed average for that period. In subsequent years, the three-year average is calculated on data of the most recent three years; (iii) imports from the European Union are free, while natural gas imported from outside the European Union is subject to an authorization of the Ministry of Productive Activities. Subjects importing from countries outside the E.U. must secure a certain availability of strategic storage. Such constraints applies also the import contracts entered into before the coming into effect of Decree No. 164, these contracts are automatically

 


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considered authorized since this date; (iv) from January 1, 2002, natural gas transport and dispatching activities are to be carried out by a separate company that is not allowed to carry out any other activity in the natural gas field. By the same date distribution, which includes the management of local networks, is to be carried out by a separate company which may not perform other gas related activities. Sale activity to final customers is compatible only with import, export and production activities and is subject to an authorization from the Ministry of Productive Activities). Concessions for the distribution of natural gas will be assigned only through an auction procedure; (v) tariff criteria and return on capital employed for transport, dispatching, storage, use of LNG terminals and distribution are determined by the Authority. Third parties are allowed to access transport infrastructure on the basis of criteria set by the Authority. As provided for by the decree, a Network Code containing norms and regulations for the operation of and access to infrastructure was prepared by operators. Approval is still pending before the Authority.

     On July 17, 2002, the Italian Authority for Electricity and Gas adopted its Decision No. 137 concerning «guarantees regarding the free access of operators to the natural gas transmission network and rules for the preparation of network codes», in implementation of article 24, subsection 5 of Decree No. 164. Decision No. 137 established priority criteria for the entitlement of transmission capacity at entry points from international networks into the domestic network. Entitlement periods can last no longer than five years. In particular it recognizes priority access to take-or-pay contracts entered into before 1998, within the limit of the average daily contractual quantity. There is therefore no guaranteed access priority for the whole contractual flexibility. In fact, take-or-pay contracts entered by Eni before 1998 envisage Eni’s right, in its quality of purchaser, to withdraw daily amounts larger than the average daily contractual amount; this contractual flexibility provided by the difference between the maximum daily amount Eni is entitled to and the average contractual daily amount is used in particular in winter. In the event of congestion at entry points, natural gas volumes not receiving a priority are assigned available transmission capacity on a pro-rata basis. Decision No. 137 establishes a transitional regime according to which for thermal year 2002-2003 access priority is granted also to two thirds of the difference between maximum contractual daily amounts and average daily amounts. For thermal year 2003-2004, priority will be granted to only one third of that difference. On November 6, 2002 Eni filed a claim with the Regional Administrative Court of Lombardia requesting the annulment of decision No. 137/2002 as Eni considers this decision non consistent with the overall European legislative framework, especially with reference to Directive 98/30/CE and Legislative Decree No. 164/2000.

     On November 21, 2002 the Italian antitrust authority concluded the inquiry started on request of Blugas SpA concerning Eni’s alleged violation of competition rules, acquitted Eni for the specific claims brought by of Blugas (deriving from the fact that in the spring-summer of 2001 Eni partially accepted Blugas’s request to access the network) but judged that Eni had abused of commanding position for having given, with the aim of respecting binding market thresholds, priority access to Italian purchasers with which Eni had entered supply contracts with volumes bought out of Italy supplied at entry points into the Italian network. The Antitrust Authority considers that these contracts infringe the rationale of article 19 of Decree No. 164 which defines the limits for volumes to be input by a single operator into the national network. Given this infringing behavior and the lack of clarity of Italian regulations and Eni’s availability to increase the transmission capacity of gaslines outside Italy, the Antitrust Authority imposed on Eni a symbolic fine amounting to euro 1,000 and requested Eni to submit «a report indicating measures to be taken to eliminate infringing behaviors with specific attention to the upgrading of the transmission network or equivalent actions». Eni filed this report on March 6, 2003. On February 5, 2003 Eni filed a claim with the Regional Administrative Court of Lazio in Rome requesting the annulment of the measures taken by the Authority.

     In order to meet the medium and long-term demand of natural gas in particular of the Italian market, Eni entered into long-term purchase contracts with operators in producing countries that have a residual average term of approximately 17 years. Existing contracts, which in general contain take-or-pay clauses, will ensure a total of about 66 billion cubic meters of natural gas per year (Russia 28.5, Algeria 21.5, Netherlands 10 and Norway 6) by 2008. The above quantities are based on the annual contract quantity of the relevant contract. The average annual minimum quantity is approximately the 85% of said quantities. To date natural gas supply contracts have not entailed the application of take-or-pay clauses. Natural gas imports for the next few years have been programmed based on the highest flexibility allowed by such contracts, assuming that access capacity to the Italian network will be available in accordance with said flexibility. However this assumption may be inconsistent with the current network code (as established by the authority with decision No. 137), also taking into account the claims filed by Eni and other operators.

 


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     Based on the best estimates currently available despite regulatory uncertainties, Eni does not consider it necessary to accrue a contingency reserve for any possible penalty payment related to take-or-pay clauses in supply contracts.

     Transport and distribution tariffs. With decision No. 120 of May 30, 2001, the Authority published the criteria which transport companies have to apply in determining natural gas transport and dispatching tariffs on national and regional transportation networks, as provided for by Decree No. 164. Tariffs are subject to approval by the same Authority, which ensures their compliance with preset criteria. Such tariffs are applicable to eligible customers as defined by Decree No. 164 (approximately 11,000 entities, of which 3,200 are industries and thermoelectric power stations linked to high pressure lines), the so called «shippers». The new tariff system substituted preceding agreements between Eni and customers of any category. The new tariff system is in force for the first regulatory period including four thermal years and starting on October 1, 2001 (the so called thermal year goes from October 1 to September 30). This regime also applies retroactively to the period June 21, 2000 to September 30, 2001. At the beginning of each the annual year transport companies submit the tariff proposal to the Authority wich in turn approves or rejects the proposal of transport companies.

     Criteria established by the Authority provide for a cap on revenues from transport and dispatching activity («allowed revenues») which is adjusted annually; those criteria also provide for a separate treatment of revenues on existing assets and on new capital expenditure on expansions and extension of infrastructure. In the first thermal year allowed revenues are calculated as the sum of: (i) operating costs including storage and modulation costs; (ii) amortization and depreciation of transport assets; and (iii) return on net capital employed. Net capital employed is calculated by revaluating historic costs of transport infrastructure (pipelines, compressor stations and other support equipment) on the basis of certain inflationary indexes; resulting amounts are adjusted to take into account the residual useful life of assets (pipelines are estimated to have a useful life of 40 years) and also subtracting State grants. The application of this methodology implies an estimated value of Eni’s transport assets of approximately euro 9.6 billion. This, however, is a valuation for regulatory purposes and should not be read as an indication of the market value of Snam Rete Gas. The rate of return on capital employed set by the Authority is 7.94% (pre-tax). Once established, allowed revenues for the first year are divided into two components: (i) capacity revenues equal to 70% of allowed revenues which are the maximum amount of revenues collectable from the sale of transport capacity to customers; (ii) commodity revenues equal to 30% of allowed revenues which are the maximum amount of revenues collectable from transported volumes. Starting from the second year these two components are adjusted on a yearly basis to take into account inflation and certain reduction factors (set at 2% and 4.5% for capacity revenues and commodity revenues respectively); commodity revenues are also adjusted to transported volumes of the current regulatory period. The 2% reduction factor on capacity revenues provides scope for improving results of operations of the transport company if cost reductions exceed the set amount, whereas the 4.5% reduction factor on commodity revenues provides scope for improving results of operations of the transport company if transported volumes grow more than the reduction factor. Allowed revenues can also be increased to reflect costs associated with exceptional events, quality improvement in service and efficient utilization of resources; this increases have yet to be established by the Authority. New capital expenditure in extension and expansion enable transport companies to increase the capacity revenue by a stated percentage in the regulatory period following the period in which new capital expenditure is made. In addition, those capital expenditures give rise to a 6 year fixed increase in allowed commodity revenues. This tariff system will be in force for four years (first regulatory period). At the end of the first regulatory period, all transport cost components will be recalculated and 50% of higher cost reductions with respect to established efficiency improvements will be recognized to transport companies and 50% will be transferred to customers. Once the allowed revenues are established, transport companies define individual tariffs to clients which are based on a charge for the capacity used at the entry location (border, fields, storage sites) and the capacity used at interconnection joint nodes with regional networks (divided into 15 zones) and on a charge for the capacity used at regional level, providing for discounts to those entering the network at less than 15 kilometers from the interconnection point. A further charge (commodity charge) is related to the amounts of gas transported plus an annual fixed charge varying according to the delivery points.

     With decision No. 237 dated December 28, 2000, the Authority determined tariff criteria for natural gas distribution and supply to non eligible customers as provided for by Decree No. 164. This tariff reform

 


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separates distribution from sale activities and links tariffs to costs in order to provide safe and efficient services. Tariffs are determined so that annual revenues from natural gas distribution and supply activities to non eligible customers do not exceed the threshold on distribution and sale revenues determined in order to cover operating costs and the remuneration of capital employed and are adjusted according to the price cap method based on parameters and formulas determined by the Authority. Provisional tariffs were defined for the first six months of 2001. From July 2001 current tariffs (varying according to type of use—cooking, heating, small enterprises) have been progressively substituted by tariffs varying according to consumption levels and costs. Every three months the portion of the tariff which relates to the cost of natural gas is adjusted to international oil, home heating oil and low sulphur fuel oil prices as measured over a nine-month period. On June 13, 2001, the Regional Administrative Court of Lombardia accepted the claim of the Association of natural gas distribution companies against the parameters used by the Authority in determining the cost of capital employed in order to quantify the revenue cap of said companies. As the Authority filed a claim with the Council of State against the Regional Court’s decision, Eni applied the criteria suggested by the Authority to the determination of revenues of natural gas distribution and supply activity in its 2001 financial statements. With decision No. 122/2002, the Authority for Electricity and Gas changed the tariff regime for natural gas distribution and supply to eligible customers which had been defined in decision No. 237. Decision No. 122, which takes into account the decision of the Regional Administrative Court of Lombardia, introduced the method of revaluated historical cost for the determination of capital employed for those companies that are provided with audited financial statements starting from the year closing before January 1, 1991, (such as Italgas), as an alternative to the parameters defined in decision No. 237/2000. In its financial statement for year 2002 Eni applied this new revised tariff regime which resulted in higher tariff for Eni’s secondary distribution with respect to 2001. See Item 5 «Operating financial review and prospects—Results of operations—Operating income—Gas & Power».

     Law Decree No. 193 of September 4, 2002, in force from September 5, 2002, and converted into Law No. 238/2002, among other things prevented any increases in natural gas distribution tariffs to customers consuming less than 200,000 cubic meters/year and in electricity tariffs to eligible customers until November 30, 2002. Decree No. 193, while confirming tariffs in force before August 2002, prohibited the application of tariff increases set by the Authority for Electricity and Gas for the September-October 2002 period and suspended increases foreseen for the November-December period. As concerns the September-October period in particular, the Authority had confirmed the current tariff for natural gas distribution. On October 31, 2002, the Council of Ministers indicated to the Authority further criteria for the determination of tariffs. Based on this Decree, the Authority will: (i) define, calculate and update electricity and gas tariffs also after the opening up of markets to eligible customers with consumption under 200,000 standard cubic meters, in order to ensure a regular and gradual access to the free market of final users that are non eligible customers as well as eligible customers who opt for this regime; (ii) define methods for updating tariffs with reference to variable costs that minimize the impact of inflation by providing for updating schedules adequate to the objective of reducing the effects of energy prices on inflation, but safeguarding the functioning of energy producing companies and the competitivity of the producing system; (iii) define criteria for allocating the costs deriving from social support measures, in order to reduce the aggregate net cost of interventions as much as possible and to ensure neutrality in the application of tariffs to the various groups of users. Consistently with this decree, the Authority: (i) with Decision No. 195 of November 29, 2002 changed the methods for periodically updating the tariff components of electricity and natural gas related to the changes in international prices of fuels and raw materials. Such changes concern the schedules update process (from every two months to every three), and the duration of the reference period for the calculation of changes in average international prices as compared to the application quarter (from the preceding six months to the preceding nine months). The invariance threshold, beyond which tariffs are updated, remained at 5%. These changes caused the confirmation of tariffs defined in July until December 2002; (ii) with Decision No. 207 of December 12, 2002, it decided that companies selling natural gas through local networks can maintain the conditions applied to non eligible customers at December 31, 2002. In addition, the Authority decided that these companies can propose their own new contract offers and offers determined according to the criteria established by the Authority adequately advertising them before March 31, 2003 (such offers must be published on the companies web page, on at least one newspaper of general circulation and on the Official Gazette of their region or autonomous province).

     Natural Gas Prices. Before the coming into force of Decree No. 164, the price of natural gas charged by Eni for primary sales, as well as the terms of supply, were generally determined through arm’s-length negotiations with associations representing major categories of customers, such as industrial companies

 


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(Confindustria and Confapi), industrial electricity producers (Unapace), electricity producers and distributors (Federelettrica) and local distribution companies (ANCI, Federgasacqua and Gasit) as well as with Enel, the former Italian national electricity utility, directly. Once established, contractual terms, including the pricing provisions, were applied uniformly to buyers in each category. Prices were generally updated by means of indexation to certain parameters (such as the price of oil and certain refined products). These contracts were also subject to supervision of the Government. This framework has been changed by the liberalization of the natural gas sector introduced by Decree No. 164 and the unbundling of the several segments of the natural gas industry which highlights the revenues and costs of each segment. Eni plans to re-formulate its commercial offer by applying a multi-choice price structure to individual customers or groups of customers who will be able to choose among various forms of price indexation. This new price structure is offered to customers at the expiration of existing contracts and aims at reducing the impact of the volatility of raw material prices due to fluctuations in the prices of energy parameters and in exchange rates by introducing mechanisms that minimize commodity risks.

     Storage of natural gas.  The right to store natural gas in depleted fields in Italy is exercised pursuant to concessions granted by the Ministry of Productive Activities (the former Ministry of Industry). Before Decree No. 164 came into force, only entities already holding a concession to exploit a hydrocarbon deposit were entitled to receive a concession to store natural gas, which is granted by the Ministry of Industry (now the Ministry of Productive Activities). The initial duration of a concession is 20 years, with the possibility of obtaining ten-year extensions. After the expiration of a concession, new storage or production concessions on the same field may be granted through competitive auctions. Pursuant to Decree No. 625, unused storage capacity can be made available to third parties, subject to the approval of the Ministry, on a negotiated basis. Until December 31, 1996, Eni had the exclusive right to store natural gas in depleted fields in the Exclusive Area. Decree No. 625 eliminated this exclusive right, while granting Eni the right to obtain upon application storage concessions having effect from January 1, 1997 that would preserve such rights as had vested during the regime of exclusivity (based on current storage activities or certain statutory conditions). Eni obtained the nine storage concessions which it had applied for. In 1999, Eni applied for another concession.

     The most important aspects of Decree No. 164 concerning production and storage activities performed by Eni are the following: (i) it favors the development of domestic natural gas reserves; (ii) effective January 1, 2002, storage can be carried out by a separate company non operating in other gas activities (such as Stoccaggi Gas Italia SpA) or by companies which only engage in transmission and dispatching, provided the accounts of these two activities are clearly separated from the accounts of storage. Existing storage concessions are subject to the Decree. Their original term was confirmed and includes relevant production concessions: (iii) the need for strategic storage in Italy is defined explicitly; the burden of strategic storage is imposed upon companies importing from non-EU countries, which have to provide a strategic storage capacity in Italy corresponding to 10% of the amount of natural gas imported each year; (iv) holders of storage concessions are required to provide storage capacity for domestic production, for strategic use and for modulation to eligible users without discriminations, where technically and economically viable; (v) modulation storage costs are charged to shippers which have to provide modulation services adequate to the requirements of final customers; (vi) storage tariffs criteria are determined by the Authority in order to ensure a proper return on capital employed, taking into account the typical risk inherent in upstream activities as well as volumes stored for ensuring peak supplies and provides incentives to capital expenditure for the upgrading of the system; and (vii) in the transitional period until the publication of the Authority’s decision, storage companies determine and publish their own tariffs, (viii) the Authority has to establish the criteria and priority of access most storage operators have to include in their storage codes.

     In compliance with the provisions of article 21 of Decree No. 164/2000, on October 21, 2001 all storage activities carried out with the Eni Group were conferred to Stoccaggi Gas Italia SpA,which holds ten storage concessions.

     With decision No. 26 dated February 27, 2002 the Authority determined tariff criteria for natural gas storage for the first regulated period (from April 1, 2002 to March 31, 2006). The Authority determined criteria on the basis of the costs of the service, plus a weighted average pre-tax rate of return of 8.33%. Tariffs are adjusted through a price cap mechanism that takes into account inflation and a productivity recovery of 2.75% per year. The tariff structure for modulation consists of two fixed elements, one based on the annual capacity used (space occupied in the reservoir) and one based on maximum output capacity demand for one day in the year, as well as a variable element calculated on the basis of the quantities entering and leaving the field. On the basis of these criteria on March 18, 2002, Stoccaggi Gas Italia SpA

 


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presented its suggested tariffs for cyclical modulation, mineral and strategic storage services for the first regulatory period. The Authority rejected Stoccaggi Gas Italia proposal and set storage tariffs for thermal year 2002-2003 with decision No. 49 of March 26, 2002. Tariffs set by the Authority are 50% lower than those applied by Eni. In 2002, Stoccaggi Gas Italia SpA appealed against both Authority decisions to the Regional Administrative Court of Lombardia in order to obtain their repeal.

     Decree No. 625, as amended by Decree 164, provides for the holders of storage concessions to keep storage capacity available for mineral, strategic and modulation storage functions for the national natural gas system.

     In implementation of Decree 164, the Decree of the Minister of Productive Activities of September 26, 2001 defined the criteria for the determination and use of strategic storage. The utilization of natural gas volumes held under strategic storage becomes mandatory in case of interruption or reduction of imports from non-EU countries due to technical and unpredictable causes, in case of emergency on the national gas network, in case of colder winters than those expected by the Authority in its periodic statements concerning the determination of modulation obligations for seasonal consumption peaks.

     On March 14, 2002, the Authority issued a consultation document containing criteria relating the storage code that storage companies have to propose. The consultation document, among other things, suggests: (i) a preference order in assigning storage capacity which favours natural gas transport companies, natural gas distribution companies as defined by Decree No. 164 art. 18, eligible customers and other natural gas companies of members States of the European Union and non members; (ii) mechanisms to assign scarce storage capacity (competitive bid, pro quota or first come first served); (iii) contents of the storage code, among which access criteria to storage services and criteria of utilization of storage service.

     Regional Law No. 2 of March 26, 2002. Under Regional Law No. 2 of March 26, 2002, the Sicilia Region introduced an environmental tax on owners of primary pipelines (operating at a maximum pressure of over 24 bar) in Sicily. The purpose of the tax is «to finance investments aimed at reducing and preventing potential environmental damage caused by pipelines containing natural gas». The tax for 2002, based on the volume of the gas pipelines, has been fixed at a rate of euro 153 per cubic meter for pipelines on public land and euro 137.70 per cubic meter for pipelines on private land. The tax is payable from April 2002 and the amount due by Snam Rete Gas SpA for 2002 totaled approximately euro 97 million. The amount of the tax can be changed by the Region with special ruling before December 31 of each year. Otherwise the tax is automatically adjusted according to the official rate of inflation as published by ISTAT.

     In order to protect its interests, Snam Rete Gas: (i) on July 30, 2002, filed a claim with the European Commission commencing a proceeding against the Italian Government, which may lead to a suspension of the regional law pending a final ruling; (ii) notified the Sicilia Region of its request for reimbursement of taxes paid, as a first step to the furthering of the dispute and warned the Sicilia Region not to make use of those sums pending final rulings; (iii) on October 18, 2002, as circumstances materialized constituting tacit rejection of the request for reimbursement of the tax paid, filed a claim with the Tax Commission of Palermo aimed at obtaining a definitive and rapid decision against the legitimacy of the tax.

     The Authority, although acknowledging that the tax burden is an operating cost for the transmission activity, subjected its inclusion in tariffs to the final ruling on its legitimacy by relevant authorities. Therefore, with decision No. 146/2002 a the Authority published two sets of tariffs: one, in force, that does not take into account the tax and a second one including it, that will be automatically applied with retroactive effect should the tax a be judged legitimate.

     In September 2002 Snam Rete Gas filed a claim with the Regional Administrative Court of Lombardia requesting the immediate application of tariffs including the tax. With ruling of December 20, 2002, the Court judged the tax at variance with European rules and therefore did not accept Snam Rete Gas’s claim. In December 2002, Snam Rete Gas suspended payments of the tax based on authoritative legal advise and said Court ruling. Payments effected until November 2002 totaled euro 86.4 million.

     In January 2003 the Sicilia Region presented an appeal to the Council of State against the ruling of the Regional Administrative Court of Lombardia for the part that states the variance of the regional law with European rules. For cautionary reasons, Snam Rete Gas did not record the recovery of costs incurred in its

 


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accounts, taking into account the uncertainties on the future evolution of this dispute and the time necessary to reach a final judgement.

     Refining and Marketing of Petroleum Products

     Refining.  Under Decree No. 112, companies that seek to establish refining operations in Italy or to expand the capacity of existing refining operations must obtain an operating concession from the relevant Region, while companies that seek to build or operate new plants that do not increase refining capacity must obtain an authorization from the relevant Region.

     Service Stations.  Decree No. 32 of February 11, 1998 as amended by Legislative Decree No. 348 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, significantly changed Italian regulation of service stations. The Decree replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities. Legislative Decree No. 112/98 confers the power to grant concessions for the construction and operation of service stations on highways to Regions. Decree No. 32 also requires that contracts between license holders and service station operators have a duration of not less than six years and be drafted in accordance with arrangements agreed by the relevant trade group of license holders and the union representatives for the service station operators. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) upon the closure of at least 7,000 service stations, the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; (iv) establishment of a fund for the restructuring of the sales network, in part financed through a contribution of lire 4 per liter of fuel sold (lire 3 paid by licence holders and lire 1 paid by operators of service stations) in the 1998-2000 period; (v) the opening up of the logistics segment by permitting third party access to unused storage capacity for petroleum products; and (vi) measures designed to increase competition on the market for LPG for residential, industrial and agricultural users. With the goal of renewing the Italian distribution network, Law no 57/2001 provides that the Ministry of Industry (now Ministry for Productive Activities) is to prepare guidelines for the modernization of the network, and the Regions shall follow those guidelines in the preparation of regional plans. The Decree was issued on October 31, 2001 and established the criteria for the closing down of incompatible stations, for the approval of the plan for the renewal of the network, the opening up of new ones and will regulate the operations of service stations on matters such as automation, working hours and non oil activities.

     Petroleum Product Prices.  Petroleum product prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Productive Activities and service station operators, and such recommendations are considered by service station operators in establishing retail prices for petroleum products. With Ministerial Decree dated February 16, 2000 an entity was established that supports the Ministry of Industry in monitoring trends in domestic and international prices of oil and oil products. Furthermore, in order to avoid initiatives inhibiting competition, Law No. 57/2001 provides the compliance with EU Regulation No. 2790/1999 concerning «vertical agreements» on economic relations between operators in this area. Management believes that these developments will not have any significant impact on Eni’s operations.

     Compulsory Stocks.  Compulsory stocks imposed by the Ministry of Productive Activity, in line with the European Directive 98/1993, must be at their minimum level equal to the quantities required by 90 days of consumption (net of oil products obtained by domestically produced oil).

     In order to satisfy the agreement with the International Energy Agency (Law No. 883/1997), the Minister of Productive Activity with Decree of January 31, 2001, No. 22, increased the level of compulsory stocks by 10% (this level to be reached in four years). The impact of the Decree on Eni’s compulsory stocks is of approximately 700 thousands tons, of which 170 thousands tons in 2002.

     Decree No. 32 of February 11, 1998 established an entity responsible for the maintenance and management of this compulsory reserve whose main tasks are to: (i) distribute stocks on the national territory according to available storage sites and consumption levels; (ii) meet the demand for refined products in case

 


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of crisis; (iii) guarantee storage volumes to operators; and (iv) record demand for refined products in the various areas of Italy. The agency is not yet operational.

     In 2002 Eni owned on average 7.2 million tons of oil products inventories, of which 5.1 millions relating to «compulsory stocks» as required by Italian law. The balance is composed of oil products which cannot be used to meet compulsory stock requirements; in particular 0.9 million tons relate to operating inventories (oil products contained in facilities and pipelines), 0.7 millions relate to oil products contained in ships and 0.5 millions relate to specialty products.

     Eni’s compulsory stocks are in general composed of oil (35%), distillates (45%) and fuel oil (20%). They are located throughout the Italian territory in both refineries (75%) and storage sites (25%).

     Eni also held natural gas for strategic reserves purposed in its storage business, as established by the Legislative Decree No. 164 of May 23, 2000. The reserves of strategic gas are defined as «stock destined to substitute situations of deficit/decrease of supply or crisis of the gas system». The Ministry of Productive Activities determines quantities and usage criteria of such reserves. As of December 31, 2002 Eni held approximately 180 billion standard cubic feet of strategic reserves of natural gas.

     Competition

     Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999 («Article 81» and «Article 82», respectively being the result of the new denomination of former Articles 85 and 86) and EU Merger Control Regulation No. 4064 of 1989 («EU Regulation 4064»). Article 81 prohibits collusion among competitors that may affect trade among member states and that has the object or effect of restricting competition within the EU. Article 82 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among member states. EU Regulation 4064 sets certain limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the «EEA Agreement»), which are analogous to the competition rules of the Treaty of Rome and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority.

     In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the «Antitrust Law»). In accordance with the EU competition rules, the Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers. The Antitrust Authority has intervened on the basis of the Antitrust Law in several instances, particularly in order to prohibit the imposition of discriminatory tariffs in the telecommunications, railway and air transport sectors, among others. In addition, the Antitrust Authority has undertaken investigations regarding the activities of certain oil and gas companies, including Eni. See «Note 21 to the Consolidated Financial Statements—Legal Proceedings—Antitrust Proceedings.»

Property, Plant and Equipment

     Eni has freehold and leasehold interests in real estate in numerous countries throughout the world, but no one individual property is material to Eni as a whole. See «Exploration & Production» above for a description of Eni’s reserves and sources of crude oil and natural gas.

 


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Organizational Structure

     The significant subsidiary and associated undertakings and joint ventures of the Eni Group controlled directly or indirectly by Eni at December 31, 2002 and included in the scope of consolidation as well as Eni’s percentage of equity capital or joint venture interest (rounded to the nearest whole number) are set forth in the table below. The principal country of operation is generally indicated by the company’s country of incorporation or by its name.

                 
Company/Undertaking   Country of Incorporation   %

 
 
Exploration & Production              
Agip Algeria Production BV Netherlands     100  
Agip Angola Production BV Netherlands     100  
Agip Azerbaijan BV Netherlands     100  
Agip Caspian Sea BV Netherlands     100  
Agip Congo SA Netherlands     100  
Agip Exploration BV Netherlands     100  
Agip Iran BV Netherlands     100  
Agip Karachaganak BV Netherlands     100  
Lasmo Plc United Kingdom     100  
Agip North Africa BV Netherlands     100  
Agip North Sea Ltd United Kingdom     100  
Agip Oil Ecuador BV Netherlands     100  
Agip Petroleum Co Inc USA     100  
Agip (UK) Ltd United Kingdom     100  
Brithish-Borneo Oil & Gas Plc United Kingdom     100  
Ieoc Production BV Netherlands     100  
Lukagip NV Netherlands     50  
Naoc — Nigerian Agip Oil Co Ltd Nigeria     100  
Norsk Agip A/S Norway     100  
Gas & Power              
Greenstream SpA Italy     100  
Snam Rete Gas SpA Italy     60  
Società Italiana per il Gas pA Italy     44  
Adriaplin Doo Slovenia     22  
Distribuidora de Gas Cuyana SA Argentina     20  
Gas Brasiliano Distribuidora SA Brazil     89  
Inversora de Gas Cuyana SA Argentina     33  
Tigaz Hungary     28  
EniPower SpA Italy     100  
Refining & Marketing              
AgipGas SpA Italy     100  
Atriplex Srl Italy     100  
Ecofuel SpA Italy     100  
Eni Portugal Investment SpA Italy     100  

 


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Company/Undertaking   Country of Incorporation   %

 
 
Agip Deutschland AG
  Germany     100  
Agip Do Brasil SA
  Brazil     100  
Agip Ecuador SA
  Ecuador     100  
Agip Espana SA
  Spain     100  
Agip Française SA
  France     100  
American Agip Co Inc
  USA     100  
Petrochemicals
               
EniChem SpA (now Syndial SpA)
  Italy     100  
Polimeri Europa SpA
  Italy     100  
Dunastyr Polystyrene Manufacturing Company Ltd
  Hungary     100  
Polimeri Europa Americas Inc
  USA     100  
Polimeri Europa Benelux SA
  Belgium     100  
EniChem Deutschland GmbH
  Germany     100  
Polimeri Europa Elastomères France SA
  France     100  
Polimeri Europa France Snc
  France     100  
Polimeri Europa UK Ltd
  United Kingdom     100  
Oilfield Services and Engineering
               
Saipem SpA
  Italy     43  
Snamprogetti SpA
  Italy     100  
Consorzio Eni per l’Alta Velocità — Cepav Uno
  Italy     50  
European Marine Contractors Ltd
  United Kingdom     75  
Saipem SA
  France     43  
Other Activities
               
Società Finanziaria Eni SpA—Enifin
  Italy     100  
Società Finanziamenti Idrocarburi — Sofid-Spa
  Italy     100  
EniData SpA
  Italy     100  
EniTecnologie SpA
  Italy     100  
Eurosolare SpA
  Italy     100  
Sieco SpA
  Italy     91  
Tecnomare SpA
  Italy     57  
Eni International BV
  Netherlands     100  
Eni Coordination Center SA
  Belgium     100  

Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

     The information in this item should be read together with the Key Information presented in Item 3 and the Consolidated Financial Statements and related Notes thereto included in Item 18. The Consolidated Financial Statements and the related Notes thereto have been prepared in accordance with Italian GAAP, which differ in certain respects from generally accepted accounting principles applied in the United States. For a summary of the

 


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significant differences between Italian accounting principles and U.S. GAAP that are relevant to Eni, see «—Summary of Differences Between Italian accounting principles and U.S. GAAP» and Notes 28, 29 and 30 to the Consolidated Financial Statements. Note 30 to the Consolidated Financial Statements provides certain additional disclosures required under U.S. GAAP.

Critical Accounting Policies

     The consolidated financial statements of Eni have been prepared in accordance with Eni Group accounting policies which are in accordance with accounting principles prescribed by Italian law and supplemented by the accounting principles issued by the Consiglio Nazionale dei Dottori Commercialisti e dei Ragionieri (C.N.D.C.R.) or, in the absence thereof and if applicable, the International Accounting Standards Committee (I.A.S.C.). In the absence of indications in said principles, specific criteria for hydrocarbon exploration and production applied internationally have been followed (collectively «Italian GAAP»).

     Italian GAAP differ in certain respects from generally accepted accounting principles in the United States («U.S. GAAP»); a description of these differences is set forth in Note 28 to Financial Statements.

     Accounting policies affect the recognition of assets and liabilities in the balance sheet and revenues and expenses on the income statement. The accounting methods used can affect net income, stockholders equity and various financial statement ratios. However, Eni’s accounting policies generally do not change cash flows or liquidity.

     Oil and Gas Activities

     Costs associated with the acquisition of mineral rights, including reserves purchased in connection with such acquisition, are capitalized. Mineral rights can also include exploration permits, among other items. Mineral rights are amortized on a straight-line basis over the expected period of benefit. Capitalized costs associated with proved reserves are amortized on a Unit-of-Production (UOP) basis, while capitalized costs related to all other reserves are not amortized until classified as proved. Capitalised costs related to abandoned drilling programs are expensed.

     Costs associated with exploratory activities for oil and gas producing properties incurred to obtain information in order to characterize fields (such as acquisition of seismic data from third parties, test wells and geophysical surveys) are expensed as incurred for financial reporting purposes.

     Costs incurred in development activities (acquisition of concessions, drilling of wells and their completion before production, as well as plant and equipment necessary for production, etc.) are capitalized and amortized on a UOP basis. Costs related to unsuccessful developmental wells are expensed immediately as loss on disposal.

     Eni regularly accrues costs expected to be incurred with respect to eventual well abandonment, including costs associated with site restoration, on a UOP basis.

     Engineering estimates of the Company’s oil and gas reserves are inherently uncertain; the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. There are authoritative guidelines regarding the engineering criteria that have to be met before estimated oil and gas reserves can be designated as «proved». Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves include: (i) developed proved reserves: amounts of hydrocarbons that are expected to be retrieved through existing wells, facilities and operating methods; (ii) non developed proved reserves: amounts of hydrocarbons that are expected to be retrieved following new drilling and facilities. Proved reserves do not include probable or possible reserves.

 


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     Results of drilling, testing and production after the date of the estimate may require substantial upward and downward revision. In addition changes in oil and natural gas prices could have an effect on the value of Eni’s proved reserves. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recorded.

     Despite the inherent imprecision in these engineering estimates, estimated reserves are used in determining depreciation expenses and impairment expense. Depreciation rates on oil and gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the year and proved developed reserves existing at the year-end increased by the amounts extracted during the year. Therefore, assuming all other variables are held constant, an increase in estimated proved reserves decreases depreciation, depletion and amortization expense. On the contrary, a decrease in estimated proved reserves increases depreciation, depletion and amortization expense. The UOP rate is then applied to the costs capitalized.

     Also, estimated reserves are often used to calculate future cash flows from oil and gas operations, which serve as an indicator in determining whether a property is impaired or not. The larger the estimated reserves, the less likely the property is impaired.

     Impairment of Assets

     Fixed assets are written down whenever events and changes in circumstances indicate that the carrying amount may not be recoverable. Eni calculates the writedown as the difference between the expected accumulated discounted cash flow and the book value of the asset. According to Italian GAAP, when the circumstances causing an impairment cease to exist, Eni reverses previously recorded impairment charges net of depreciation.

     For oil and natural gas properties, the expected future cash flows are estimated based on developed and non developed proved reserves including, among other elements, the cost for closure and abandonment of wells, production taxes and the costs to be incurred for the reserves yet to be developed. The estimated future level of production is based on assumptions about future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors.

     Asset Retirement Obligations

     Eni has significant obligations to remove tangible equipment and restore land or seabed at the end of operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells and removal and disposal of offshore oil and gas platforms around the world. The estimated undiscounted costs, net of salvage value, of dismantling and removing these facilities are accrued over the productive life of the asset. Estimating the future asset removal costs is difficult and requires management to make estimates and judgements because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public relations considerations.

     Environmental Liabilities

     Together with other companies in the industries in which it operates, Eni is subject to numerous EU, national, regional and local environmental laws and registrations concerning its oil and gas operations, productions and other activities, including legislations that implements international conventions or protocols.

     Environmental expenditures are made in order to prevent, reduce, repair or control the environmental impact

 


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of production activities. Reserves for environmental contingencies are established when it becomes probable or certain that a liability has been incurred and the amount can be reasonably estimated.

     Although management, considering the actions already taken, the insurance policies to cover environmental risks and provision for risks accrued, does not expect any material adverse effect upon Eni’s results of operations and financial position as a result of its compliance with such laws and regulations, there can be no assurance that there will not be a material adverse impact on Eni’s results of operations and financial position due to: (i) the possibility of as yet unknown contamination; (ii) the results of the ongoing surveys; (iii) the possible effect of future environmental legislations and rules; (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty in determining Eni’s liabilities, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

     Contingencies

     In addition to accruing the estimated costs for asset retirement obligation and environmental liabilities, Eni accrues for all probable and estimable contingencies. These other contingencies are primarily related to litigation and tax issues. Determining appropriate amounts for accrual is a complex estimation process that includes subjective judgements. Eni reviews these contingencies on at least a quarterly basis to determine if new accruals need to be recorded or if adjustments to existing accruals need to be made.

     Margin (1)

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

Background and Recent Developments

     Eni’s results of operations and the period-to-period comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining and petrochemical margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas segment and, to a lesser extent, of the refining and marketing segment. See “Item 3. Risk Factors.” The trading environment was mixed in 2002. Hydrocarbon prices were weak in the first half of the year; then they began to increase due to geopolitical worries. Refining margins were weak all year round due to sluggish demand for refined products. Margins on distribution of refined products in Europe benefited from higher levels of efficiency of distribution networks. Natural gas demand in Italy was affected by unfavorable climatic conditions especially in the fourth quarter of 2002 and by slow economic activity. Margins on natural gas primary distribution in Italy were affected by increasing competitive pressure in the domestic natural gas market and by the change in sale mix due to compliance with regulatory thresholds provided for by Legislative Decree no. 164/2000 (See «Item 3. Risk Factors»). Petrochemical product margins suffered from the weak economic environment and overcapacity and came under pressure as decreases in selling prices were sharper than those in the prices of oil-based feedstocks.

     In the first quarter of 2003 oil prices continued their upward trends with the spot price for Brent, a benchmark crude oil, above the key level of 30 dollar/barrel due to geopolitical developments. Refining margins rebounded sharply due to higher demand for refined products as a consequence of geopolitical factors, a colder winter in North America and Europe as well as low inventory levels. Natural gas margins were higher due mainly to the different trends in the reference parameters for the determination of natural gas purchase and selling prices (related also to different contractual intervals). Petrochemicals margins improved

 


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slightly over the first quarter of 2002 but did not show any signs of a sustained recovery. The euro appreciated markedly against the dollar.

     Eni’s net income for the first quarter of 2003 increased by 45.2% over the first quarter of 2002, due in particular to an increase in international oil prices (prices realized on oil were up 55.4%; on natural gas 36.6%) and in refining margins (Brent margin was up 3.60 dollar/barrel), these effects were reduced by the appreciation of the euro over the dollar (up 22.5%), higher margins on natural gas distribution and cost reductions. The increase in net income was also determined by the recording of net extraordinary income related to the settlement of a dispute concerning the EniMont joint venture with Edison SpA and the decline in the share of net income attributed to minorities resulting from the acquisition by way of tender offer of the majority of outstanding Italgas shares. These positive factors were partly offset by higher income taxes, due mainly to higher income before income taxes.

     Eni’s operating income for the first quarter of 2003 increased by 23.4% over the first quarter of 2002, mainly due to increases recorded by:

    the Exploration & Production segment (up 34.8%) related essentially to higher international oil prices, whose effect was partly offset by the appreciation of the euro over the dollar;
 
    the Gas & Power segment (up 7.2%) related essentially to higher margins and volumes sold in primary and secondary distribution of natural gas, whose effect was offset in part by a change in the sales and supply mix in primary distribution;
 
    the Refining & Marketing segment (up 88.7%) essentially due to an especially favorable refining scenario, whose effects were offset in part by: (i) lower profitability of lubricant bases, kerosene and petrochemical feedstocks related to lower demand, as well as lower profitability of semi-finished products; (ii) the effect of plant maintenance standstills that did not allow to take full advantage of the favorable refining scenario; (iii) the appreciation of the euro over the dollar.

     In the first quarter of 2003, streamlining and efficiency improvement continued and allowed cost savings, which offset almost entirely salary increases and the effects of inflation.

     Eni’s net sales from operations for the first quarter of 2003 increased by 13% over the first quarter of 2002, due mainly to an increase in international oil prices, in natural gas and main downstream product prices and to the effect of the consolidation of Bouygues Offshore in the Oilfield Services and Engineering segment, the effects of which were reduced by the appreciation of the euro over the dollar.

     Net borrowings at March 31, 2003 increased over December 31, 2002. See «Glossary» for a definition of net borrowings. Increased financial requirements for capital expenditure and investments and the buy-back of Eni’s shares were covered for the most part by the cash flows generated from operating activities. The positive effect of the appreciation of the euro over the dollar contributed to the decline in net borrowings.

     In the first quarter of 2003 hydrocarbon production increased by approximately 4% as compared to the first quarter of 2002, due to: (i) production of Fortum Petroleum, purchased in the first quarter of 2003; (ii) start-ups of new fields mainly in Iran, Trinidad & Tobago, Egypt, the United States, and Pakistan; (iii) production increases mainly in Nigeria and Kazakhstan; (iv) the effect of the cancellation of production cuts by OPEC. These increases were partly offset by: (i) lower entitlements in PSA’s due to the increase in oil prices; (ii) the effect of production standstills in Venezuela due to a national strike; (iii) declines in mature fields.

     Natural gas sales in primary distribution in Italy and Europe increased 6.3% as compared to the first quarter of 2002, due to higher sales in Europe, offset in part by lower sales in Italy.

     In the April-May 2003 two-month period the spot price of Brent crude declined with respect to the first quarter and was also slightly below the level achieved in the same period of 2002. This factor is expected to adversly affect results of operations of Eni’s Exploration & Production segment in 2003. Refining margins declined somewhat with respect to the first quarter but were well above the level of the second quarter 2002. Petrochemical margins improved slightly over the first quarter; however based on economic and industry conditions management does not expect any significant improvement in the near future. The euro continued to

 


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appreciate against the dollar due to the process of adjustment of structural imbalances of U.S. economy; management expects this movement in exchange rates to characterize the rest of 2003 and to adversely impact Eni’s results of operations in 2003.

     The table below sets forth certain indicators of some of these external factors for the periods indicated:

                                                         
                            Three months   Two months
    Year ended December 31,   ended March 31,   April-May,
   
 
 
    2000   2001   2002   2002   2003   2002   2003
   
 
 
 
 
 
 
Average price of Brent dated crude oil(1)
    28.39       24.46       24.98       21.14       31.51       25.50       25.29  
Average European refining margin(2)
    3.99       1.97       0.80       0.21       3.81       0.56       2.33  
Average EUR/USD Exchange rate(3)
    0.924       0.896       0.946       0.876       1,073       0.901       1.121  
EURIBOR—three-month euro rate %
    4.4       4.3       3.3       3.3       2.7       3.4       2.6  


(1)   In U.S. dollars per barrel. Source: Platt’s Oilgram.
 
(2)   In U.S. dollars per barrel. FOB Mediterranean Brent dated crude oil. Source: Eni calculations based on Platt’s Oilgram data.
 
(3)   Source: European Central Bank.

     The most relevant recent developments occurred after December 31, 2002 are the following:

    on January 27, 2003 the public tender offer on shares of Società Italiana per il gas pA («Italgas») was successfully closed. The tender offer, which was launched on November 25, 2002, concerned all Italgas SpA ordinary shares outstanding not owned directly or indirectly by Eni, corresponding to approximately 56% of share capital. Eni offered a price of euro 13 per share, to be fully paid in cash. Following the squeeze-out of the remaining minority shareholders, Eni now owns 100% of share capital of Italgas. Total consideration amounted to approximately euro 2.5 billion;
 
    on March 4, 2003 Eni completed the purchase of the Norwegian oil company Fortum Petroleum AS, which in 2002 produced 39,000 boepd and held proved reserves of hydrocarbons of 159 million boe as of December 31, 2002. Total financial requirements for this purchase amounted to dollar 975 million (of which a cash consideration of dollar 256 million and net borrowings acquired of dollar 719 million);
 
    on March 6, 2003 Eni and EniChem SpA (now Syndial SpA) accepted the settlement proposal presented by Edison SpA for the closing of an arbitration proceeding initiated by Eni and EniChem SpA in 1992 in relation to guarantees given by Montedison SpA and its subsidiaries in connection with the establishment of a joint venture in the petrochemicals sector between Eni and Montedison. Edison SpA recognized euro 200 million to Enichem to be paid in four instalments of euro 50 million each.
 
    on April 16, 2003 Eni launched a fixed rate bond issue for a notional amount of euro 1.5 billion. The transaction was placed in the international Eurobond market. The bond has a 10 year maturity and pays a fixed annual coupon of 4.625%. The reoffer price is 99.862 which implied, at the moment of pricing, a spread of 28 basis points over the 10 year mid swap rate. The new security will be listed on the Luxembourg Stock Exchange.

Principles of Consolidation

     For a description of Eni’s principles of consolidation see Notes to the Consolidated Financial Statements—Note 2 «Principles of consolidation».

 


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Results of Operations

     Three Years ended December 31, 2002

     The table below sets forth a summary of Eni’s income statement for the periods indicated.

                           
      Year ended December 31,
     
      2000   2001   2002
     
 
 
      (millions E)
Net sales from operations
    47,938       48,925       47,922  
Other income and revenues(1)
    905       921       1,080  
 
Total revenues
    48,843       49,846       49,002  
Operating expenses
    (34,228 )     (34,679 )     (34,996 )
Depreciation, amortization and writedowns
    (3,843 )     (4,771 )     (5,504 )
 
Operating income
    10,772       10,396       8,502  
Net financial income (expense)
    64       (259 )     (167 )
Net income (expense) from investments
    33       (216 )     43  
 
Income before extraordinary income and income taxes
    10,869       9,921       8,378  
Net extraordinary income (expense)(2)
    (512 )     1,837       (29 )
 
Income before income taxes
    10,357       11,758       8,349  
Income taxes
    (4,335 )     (3,530 )     (3,127 )
 
Income before minority interest
    6,022       8,228       5,222  
Minority interest
    (251 )     (477 )     (629 )
 
Net income
    5,771       7,751       4,593  


(1)   Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income.
 
(2)   Gross of income tax.

     The table below sets forth certain income statement items as a percentage of net sales from operations for the periods indicated.

                         
    Year ended December 31,
   
    2000   2001   2002
   
 
 
Operating expenses
    71.4 %     70.9 %     66.6 %
Depreciation, amortization and writedowns
    8.0 %     9.8 %     11.5 %
Operating income
    22.5 %     21.2 %     17.7 %

     Revenues from sales of products are recognized upon transfer of title. In particular, revenues are recognized:

  1)   for natural gas, when the natural gas leaves Eni’s distribution network and is delivered to the customer;
 
  2)   for crude oil, generally upon shipment;
 
  3)   for petroleum products sold to retail distribution networks, generally upon delivery to the service stations, whereas all other sales are generally recognized upon shipment from Eni’s plants; and,
 
  4)   for chemicals, generally upon shipment.

     In all instances where revenue is recognized upon shipment, all risk of loss is transferred to the buyer upon shipment.

     Revenues from natural gas and crude oil production in which Eni has an interest together with other producers are recognized based on actual quantities produced and sold on Eni’s behalf (sales method). Differences between Eni’s net working interest volume and actual production volumes are not significant.

 


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     Revenues related to long-term construction contracts are recognized using the percentage-of-completion method measured on the cost-to-cost basis. Provisions for anticipated losses on long-term contracts are recorded in full when such losses become evident. Revenues related to amounts in excess of the original contract price due to the incurrence of unanticipated additional costs (i.e. Eni claims against third parties), are recognized when it is probable that the claim will result in additional contract revenue and the amount of the claim can be reasonably estimated.

     Eni is a party to certain Production Sharing Agreements (PSAs) whereby Eni’s taxes are settled by its joint-venture partners which are state-owned entities. A portion of Eni’s share of oil and gas production is withheld and sold by the state-owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA-related tax liabilities. Without this specific provision in its PSAs, Eni would otherwise be entitled to the sale proceeds of this portion of oil and gas production withheld.

     2002 compared to 2001. Eni’s a net income in 2002 was euro 4,593 million, with a decrease of euro 3,158 million over 2001, down 40.7%, due to: (i) a euro 1,894 million decrease in operating income (down 18.2%) related in particular to lower refining margins (Brent down 59.4%) and lower natural gas realization prices, a change in the supply/sale mix and lower volumes sold in natural gas primary distribution, as well as higher asset impairment; these negative factors were offset in part by higher international oil prices and improved oil production mix (overall oil realization prices were up 5.2%), increased hydrocarbon production sold (up 4.7%) and lower costs; (ii) lower net extraordinary income (euro 1,766 million) due to lower gains on disposal of assets (down euro 3,216 million), the effects of which were offset in part by lower restructuring charges, in particular in Petrochemicals. These negative changes were partly offset by lower income taxes (euro 402 million), due in particular to a decrease in income before income taxes and lower net financial expense (euro 128 million).

     Rationalization and improved efficiency actions led to cost savings amounting to euro 523 million, offsetting almost entirely the effect of salary increases and inflation, as well as increases related to higher activity levels and acquisitions. Cost savings achieved in the 1999-2002 period amounted to approximately euro 1.7 billion, or 50% of the euro 3.4 billion target set for 2006.

     Return on average capital employed «ROACE» was 13.7% (24% in 2001 which included the effects of the significant gains on disposal recorded). See «Glossary» for a definition of ROACE.

     2001 compared with 2000. Eni’s consolidated financial statements at December 31, 2001 showed a record net income of euro 7,751 million, with an increase of euro 1,980 million over 2000, up 34.3%, mainly due to: (i) an euro 2,349 million increase in net extraordinary income related to higher gains on disposals (euro 3,387 million) generated in particular by the offering of 40.24% of the share capital of Snam Rete Gas SpA, the sale of part of Eni’s real estate portfolio and of the Polyurethane business in the Petrochemical segment, offset in part by an euro 1,038 million increase in extraordinary expense due to higher restructuring charges, in particular in the Petrochemical segment; (ii) lower income taxes (euro 805 million) mainly related to the effects of the voluntary revaluation of assets as per Law 342/2000 carried out by some of Eni’s subsidiaries in 2000. These positive factors were offset in part by: (i) an euro 376 million decrease in operating income (down 3.5%) due in particular to the decline in oil prices; (ii) the negative change amounting to euro 323 million in the balance of financial income/expense due to higher net borrowings; (iii) the negative change amounting to euro 249 million in the balance of income/loss on investments due mainly to higher losses recorded by subsidiaries and (iv) the share of profits of Snam Rete Gas attributed to minorities following the offering (euro 232 million).

     Cost reduction and efficiency improvement actions allowed savings amounting to euro 475 million (including Lasmo), offsetting almost completely salary increases, inflation and the effect of the appreciation of the dollar over the euro. Savings obtained in 2001 brought total savings in the 1999-2001 period to euro 1,199 million, or 40% of the euro 3 billion target set for 2005 of which 0.6 billion related to the planned divestment of the petrochemical segment.

     ROACE increased significantly to 24% (21.5% in 2001).

     The table below shows significant non-recurring items in order to allow a better understanding of trading performance for years 2000, 2001 and 2002 as was affected by significant impairments, net extraordinary income or expense, change in fiscal regulations and other charges or credits.

 


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      2000   2001   2002
     
 
 
      (million E)
Asset impairment
    (55 )     (100 )     (542 )
Environmental tax of the Sicilia Region
                    (86 )
(Costs) revenues of previous years
                    61  
Gains on disposals
                    92  
(Devaluation) revaluations of stocks
    80       (69 )     40  
Other
                    (22 )
Effect on operating income
    25       (169 )     (457 )
of which:
                       
 
— Exploration & Production
            (88 )     (253 )
 
— Gas & Power
    (5 )     (3 )     (129 )
 
— Refining & Marketing
    (45 )     22       9  
 
— Petrochemicals
    79       (100 )     (78 )
 
— Other segments
    (4 )             (6 )
Non-recurring expense on investments
            (82 )     (36 )
Net extraordinary income (expense)
    (512 )     1,737       (29 )
Non-recurring items before taxes
    (487 )     1,486       (522 )
Adjustment of reserve for deferred tax liabilities due to changes in UK tax regime
                    (215 )
Release of reserve for anticipated amortization (ex art. 4 of Law 448/2001)
                    95  
Taxes (estimated)
    508       508       312  
 
— related to non-recurring items in operating income
    19       32       245  
 
— related to other non-recurring items
    489       476       67  
Minority interest
    (54 )                
Non-recurring items after taxes
    (33 )     1,994       (330 )

     Revenues

     Eni’s total revenues were euro 49,002, 49,846 and 48,843 million in 2002, 2001 and 2000, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations amounted to euro 47,922, 48,925 and 47,938 million in 2002, 2001 and 2000, respectively, and its other income and revenues totalled euro 1,080, 921 and 905 million, respectively, in these periods.

     The table below sets forth, for the periods indicated, the net sales from operations generated by each of Eni’s business segments, together with consolidated net sales from operations.

                         
    Year ended December 31,
   
    2000   2001   2002
   
 
 
    (millions E)
Exploration & Production
    12,308       13,960       12,877  
Gas & Power
    14,427       16,098       15,297  
Refining & Marketing
    25,462       22,083       21,546  
Petrochemicals
    6,018       4,761       4,781  
Oilfield Services and Engineering
    2,146       3,114       4,546  
Other activities
    608       695       897  
Elimination of intersegment sales(1)
    (13,031 )     (11,786 )     (12,022 )
Consolidated net sales from operations
    47,938       48,925       47,922  

 


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(1)   Intersegment sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The most substantial intersegment sales are recorded by the Exploration & Production segment. See Note 24 to the Consolidated Financial Statements for a breakdown of intersegment sales by segment for the three years ended December 31.

     2002 compared with 2001. Eni’s net sales from operations (revenues) for 2002 amounted to euro 47,922 million, declining by euro 1,003 million, down 2.1% over 2001, due mainly to lower natural gas realization prices and lower prices for the main downstream products, the change in the sale mix and lower volumes sold in natural gas primary distribution, as well as the effects of the appreciation of the euro against the U.S. dollar. These negative effects were offset in part by an increase in international oil prices and improved oil production mix, higher hydrocarbon production sold and higher activity levels in the Oilfield Services and Engineering segment.

     Revenues generated by the Exploration & Production segment (euro 12,877 million) declined by euro 1,083 million, down 7.8%, due essentially to lower natural gas realization prices (down 11.1%), the appreciation of the euro over the dollar (up 5.6%) and lower volumes of purchased hydrocarbons marketed (down 51 million boe) due mainly to the transfer of the natural gas trading activity to the Gas & Power division. These negative factors were partially offset by higher international oil prices and improved oil production mix (overall oil realization prices were up 5.2%) and higher hydrocarbon production sold (23.4 million boe, up 4.7%).

     Revenues generated by the Gas & Power segment (euro 15,297 million) declined by euro 801 million, down 5%, due essentially to lower prices for natural gas, the effects of which were partially offset by the transfer of the natural gas trading activity from the Exploration & Production division.

     Revenues generated by the Refining & Marketing segment (euro 21,546 million) declined by euro 537 million, down 2.4%, essentially due to lower prices for refined products (the retail prices of gasoline and diesel fuel were down 5.9% and 8.7%, respectively) and to reduced sales volumes on both the retail and wholesale market in Italy (overall 1.1 million tonnes, down 4.8%), due to the effect of closures/sales of service stations and lower gasoil sales on wholesale markets.

     Revenues generated by the Petrochemical segment (euro 4,781 million) increased by euro 20 million, up 0.4%, due mainly to the consolidation of Polimeri Europa, whose effect were almost entirely offset by an 8.1% fall in the average selling prices of products.

     Revenues from the Oilfield Services and Engineering segment (euro 4,546 million) increased by euro 1,432 million, up 46%, due to increased activity levels also in connection with the purchase of Bouygues Offshore.

     Revenues generated by the other activities segment (euro 897 million) increased by euro 202 million, up 29.1% due mainly to higher insurance premiums received by Padana Assicurazioni and by increased activity levels at Sieco, a company performing general services for Eni Group companies.

     2001 compared with 2000. Eni’s net sales from operations (revenues) amounted to euro 48,925 million, representing an euro 987 million increase over 2000, up 2.1%, due mainly to higher prices of natural gas, higher hydrocarbon production sold, the appreciation of the dollar over the euro and higher activity levels in the Oilfield Services and Engineering segment. These positive factors were offset in part by the decline in international oil prices and in the prices of the main downstream products, as well as in volumes of petrochemical products sold.

     Net sales from operations generated by the Exploration and Production segment (euro 13,960 million) increased by euro 1,652 million, up 13.4%, due mainly to: (i) an increase in hydrocarbon production sold (72 million boe, up 17%) mainly related to the acquisition of Lasmo; (ii) the appreciation of the dollar over the euro; (iii) higher prices realized by Eni on natural gas (up 2%); (iv) increased resales of purchased hydrocarbons (39 million boe). These positive factors were offset in part by lower selling prices realized by Eni on oil (down 16%).

     Net sales from operations generated by the Gas & Power segment (euro 16,098 million) increased by euro 1,671 million, up 11.6%, mainly due to higher natural gas prices as well as higher sales in the electricity generation activity due mainly to the fact that in 2001 Eni in addition to selling internally produced electricity

 


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began to sell traded electricity mainly to industrial customers for use in their business. Higher electricity prices also increased net sales from operations.

     Net sales from operations generated by the Refining and Marketing segment (euro 22,083 million) decreased by euro 3,379 million, down 13.3%, due to the decline in prices in euro of refined products (in Italy retail diesel fuel and gasoline decreased by 9.1 and 8.2% respectively) and lower resales of purchased crudes (3.6 million tons).

     Net sales from operations generated by the Petrochemical segment (euro 4,761 million) decreased by euro 1,257 million, down 20.9%, due to a 13.9% decrease in average selling prices of products and a 6.8% decrease in volumes sold, due in part to the sale of the Polyurethane business.

     Net sales from operations generated by the Oilfield Services and Engineering segment (euro 3,114 million) increased by euro 968 million, up 45.1%, due to increased activities in particular in oilfield services.

     Net sales from operations generated in the Oilfield Services and Engineering segment (euro 2,146 million) decreased by euro 842 million, down 28.2%, essentially due to decreased activities, particularly in Chemicals and fertilizers, Onshore and offshore construction activities.

     Operating Expenses

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

                           
      Year ended December 31,
     
      2000   2001   2002
     
 
 
      (millions E)
Purchases, services and other
    31,442       31,828       31,893  
Payroll and related costs
    2,786       2,851       3,103  
 
Operating expenses
    34,228       34,679       34,996  

     2002 compared with 2001. Operating expenses (euro 34,996 million) increased by euro 317 million, or 0.9% over 2001 due to salary increases and inflation as well as increases due to higher activity levels, acquisitions and the consolidation of Polimeri Europa, this was partly offset by lower supply costs for natural gas, cost reductions resulting from streamlining and increased efficiency and the effect of the appreciation of the euro over the dollar.

     Payroll and related costs (euro 3,103 million) increased by euro 252 million, up 8.8%, mainly due to the consolidation of Polimeri Europa and Saipem SA (the new name of Bouygues Offshore) in the Oilfield Services and Engineering segment and an approximately 3.8% increase in unit labor cost in Italy. These factors were offset in part by an approximately 2,400 decline in the average number of employees in Italy resulting from the streamlining initiatives undertaken.

     2001 compared with 2000. Operating expenses in 2001 (euro 34,679 million) increased by euro 451 million over 2000, up 1.3%, due primarily to: (i) increased purchase costs of natural gas; (ii) the inclusion of Lasmo in the scope of consolidation; (iii) increased activity levels in the Oilfield Services and Engineering segment; (iv) higher resales of purchased hydrocarbons (13 million boe); (v) the appreciation of the dollar over the euro. Such increases were offset in part by: (i) lower international prices of oil-based raw materials and petrochemical feedstocks; (ii) lower production in the Petrochemical segment (702,000 tons, down 8.2%) due in part to the sale of the Polyurethane business; (iii) lower costs due to streamlining and efficiency improvement actions which offset almost entirely salary increases, the effects of inflation and the appreciation of the dollar over the euro.

     Payroll and related costs (euro 2,851 million) increased by euro 65 million, up 2.3%, due essentially to the consolidation of Lasmo, the effect of new hiring on a temporary base in Oilfield Services and Engineering

 


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segment, as a result of increased activity levels, and the 2.6% increase in unit labor costs in Italy. These factors were offset in part by a decline in Eni’s average workforce in Italy by approximately 2,800 employees related to streamlining.

     Depreciation, Amortization and Writedowns

     The table below sets forth a breakdown of depreciation, amortization and writedowns by business segment for the periods indicated.

                             
        Year ended December 31,
       
        2000   2001   2002
       
 
 
        (millions E)
Exploration & Production(1)
    2,364       3,163       3,552  
Gas & Power
    474       500       417  
Refining & Marketing
    502       508       490  
Petrochemicals
    273       251       161  
Oilfield Services and Engineering
    144       203       267  
Other activities
    31       46       75  
 
Total of depreciation and amortization
    3,788       4,671       4,962  
 
Writedowns
    55       100       542  
   
Depreciation, amortization and writedowns
    3,843       4,771       5,504  


(1)   Exploration expenditures of euro 744, 757 and 865 million are included in these amounts relative to years 2000, 2001 and 2002, respectively.

     2002 compared with 2001. Depreciation, amortization and writedown charges (euro 5,504 million) increased by euro 733 million, up 15.4% over 2001, mainly due to the increases in the Exploration & Production segment, resulting from increased production and higher exploration activity, and higher asset impairment (euro 442 million). Asset impairment concerned in particular mineral assets in the Exploration & Production segment (euro 332 million), petrochemical plants (euro 105 million) and natural gas distribution assets in Brazil and Argentina (euro 93 million).

     2001 compared with 2000. Depreciation, amortization and writedown charges (euro 4,771 million) increased by euro 928 million over 2000, up 24.1%, in particular in the Exploration and Production segment, principally due to the inclusion of Lasmo in the scope of consolidation (euro 810 million).

     Operating Income

     The table below sets forth Eni’s operating income by business segment for the periods indicated.

                           
      Year ended December 31,
     
      2000   2001   2002
     
 
 
      (millions E)
Exploration & Production
    6,603       5,984       5,175  
Gas & Power
    3,178       3,672       3,244  
Refining & Marketing
    986       985       321  
Petrochemicals
    4       (332 )     (347 )
Oilfield Services and Engineering
    144       255       298  
Other activities
    (143 )     (168 )     (189 )
 
Operating income
    10,772       10,396       8,502  

 


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     2002 compared with 2001.  Eni’s operating income (euro 8,502 million) decreased by euro 1,894 or 18.2% over 2001 as a result of lower refining margins (Brent down 59.4%) and lower natural gas realization prices, a change in the supply/sale mix and lower volumes sold in natural gas primary distribution, as well as higher asset impairment; these negative factors were offset in part by higher international oil prices and improved oil production mix (overall oil realization prices were up 5.2%), increased hydrocarbon production sold (up 4.7%) and lower costs.

     2001 compared with 2000.  Eni’s operating income (euro 10,396 million) decreased by euro 376 million over 2000, down 3.5% due to:

     —   a decrease in operating income generated by the Exploration & Production segment (euro 619 million, down 9.4%), due to the decline in selling prices realized by Eni on oil (down 16%), whose effects were offset in part by the contribution of the acquisition of Lasmo (euro 275 million), increased natural gas production sold in Italy (30.24 BCF million boe, up 6.1%), higher selling prices realized by Eni on natural gas (up 2%), the appreciation of the dollar over the euro (up 3%) and lower operating expenses;
 
     —   an euro 332 million operating loss registered by the Petrochemical segment compared to the operating income of euro 4 million generated in 2000, due mainly to a decline in product margins (down 14%) and volumes sold (down 6.8%).

     These decreases were offset in part by:

     —   an increase in operating income generated by the Gas & Power segment (euro 494 million, up 15.5%), due mainly to higher margins on primary distribution, a decrease in costs, as well as higher volumes sold in Italy and outside Italy in secondary distribution, whose effects were offset in part by a change in the sale mix of products sold in primary distribution and lower margins in secondary distribution;
 
     —   an increase in operating income of the Oilfield Services and Engineering segment (euro 111 million, up 77.1%), resulting from the positive trend of the oilfield services activity;

     The table below sets forth, for each of Eni’s principal business segments, operating income as a percentage of such segment’s net sales from operations (including intersegment sales) for the periods indicated.

                         
    Year ended December 31,
   
    2000   2001   2002
Exploration & Production
    53.6 %     42.9 %     40.2 %
Gas & Power
    22.0 %     22.8 %     21.2 %
Refining & Marketing
    3.9 %     4.5 %     1.5 %
Petrochemicals
    0.1 %     (7.0 %)     (7.3 %)
Oilfield Services and Engineering
    6.7 %     8.2 %     6.6 %

     Exploration & Production.   Operating income in 2002 totaled euro 5,175 million, representing a euro 809 million decrease over 2001, down 13.5%, due mainly to: (i) lower natural gas realization prices (down 11.1%); (ii) higher mineral asset impairment (euro 244 million) in particular in the North Sea and in the Gulf of Mexico; (iii) the effect of the appreciation of the euro over the dollar (up 5.6%); (iv) a decrease in storage and modulation tariffs due to the effects of decision No. 49/2002 of the Authority for Electricity and Gas (euro 144 million); and (v) higher exploration costs (euro 94 million). These negative factors were offset in part by: (i) higher international oil prices and improved oil production mix (overall oil realization prices were up 5.2%); (ii) increased hydrocarbon production sold (23.4 million boe, up 4.7%); (iii) gains on disposal of assets (euro 92 million); and (iv) cost reductions related to synergies deriving from the integration of purchased companies and streamlining (euro 154 million).

     Operating income in 2001 totaled euro 5,984 million, a decrease of euro 619 million over 2000, down 9.4%, due mainly to: (i) lower selling prices realized by Eni on oil (down 16%); (ii) lower oil production sold

 


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in Italy (3.5 million barrels, down 12.5%) and outside Italy (4 million barrels, down 1.7%, excluding Lasmo’s contribution); (iii) writedowns of assets (euro 88 million). These negative factors were offset in part by: (i) the contribution of Lasmo which generated an operating income of euro 275 million; net sales from operations and operating income before the amortization of the difference of purchase price over net equity amounted to euro 1,586 and euro 553 million, respectively; (ii) increased natural gas production sold in Italy (30.24 BCF million boe, up 6.1%) related to higher withdrawals from storage; (iii) higher prices realized by Eni on natural gas (up 2%); (iv) the appreciation of the dollar over the euro; (v) cost reductions (approximately euro 137 million) related to synergies deriving from the integration of purchased companies, the rationalization of exploration expenditure and streamlining.

     Gas & Power.   Operating income in 2002 amounted to euro 3,244 million, a euro 428 million decrease over 2001, down 11.7%, due mainly to: (i) a decline in results of primary distribution related to a change in the sales mix with higher share of sales in Europe due to ceilings set by Legislative Decree No. 164/2000, a change in the supply mix and lower sales (1.20 billion cubic meters, down 1.9%); (ii) asset impairment in the distribution of natural gas in Brazil and Argentina (euro 93 million) due to lower profitability prospects; (iii) the payment of the environmental tax established by the Sicilia Region with Regional Law No. 21 of March 26, 2002 (euro 86 million); and (iv) lower results in the power generation activity resulting from lower sale margins mainly due to the expiration of tax incentives on certain sale contracts for the Livorno and Taranto power stations. These negative factors were offset in part by the positive effect of the application of decision No. 122/022 of the Authority for Electricity and Gas (euro 74 million related to 2001) and lower costs (euro 58 million) related to efficiency improvement actions, in particular in transport activities in Italy, which were partly offset by salary increases and inflation.

     Operating income in 2001 amounted to euro 3,672 million with an increase of euro 494 million, up 15.5% over 2000, due essentially to: (i) higher margins on natural gas sold in primary distribution, related to the appreciation of the dollar over the euro and to the pricing of natural gas, as sales prices are linked to an index which moved favourably compared to the cost of supplies, especially in the first half of 2001. See also «Item 4—Information on the company. Regulation of the Italian Hydrocarbon Industry. Natural Gas»; (ii) lower costs (approximately euro 56 million) related to streamlining and disposals which were partly offset by salary increases and inflation; (iii) increased volumes sold in secondary distribution in Italy (0.21 billion cubic meters, up 2.7%) and outside Italy (0.43 billion cubic meters, up 12.4%). These positive factors were offset in part by: (i) a change in the sales mix in primary distribution, related to the higher share of volumes sold in Europe for resale in Italy which bear a lower margin than direct sales in Italy; (ii) lower margins in secondary distribution related to the new tariff regime imposed by the Authority for Electricity and Gas with decision No. 237 of December 28, 2001. See also «Item 4—Information on the company. Regulation of the Italian Hydrocarbon Industry. Natural Gas». Operating income for electricity activities in 2001 amounted to euro 66 million, an euro 38 million increase, up 135.7%, due mainly to higher margins on electricity sales, in particular in the fourth quarter, resulting from the positive trend in fuel prices. The increase in electricity and steam production sold and margins on trading activities (operational since January 2001) also contributed to the increase in operating income.

     Refining and Marketing.   Operating income in 2002 amounted to euro 321 million, a euro 664 million decrease over 2001, down 67.4%, due mainly to: (i) a sharp decline in refining margins reflecting the unfavorable trading environment (Brent margin was down 59.4%), related to weak demand, a reduction in Fob/Cif differentials on products that reduced the advantage of refineries based near end markets, and the appreciation of the euro over the dollar; (ii) lower margins on oxygenates (MTBE and methanol) related essentially to lower international prices of products; (iii) the fact that in 2001 the positive effect of a decrease in stocks (valued at Lifo) was recorded for euro 36 million as compared to a revaluation of euro 13 million in 2002; (iv) lower volumes sold in wholesale markets in Italy due to a weak economic situation. These negative factors were offset in part by (i) lower costs (euro 60 million) related to streamlining and disposals, offset in part by salary increases and inflation, (ii) higher retail margins in Europe, and (iii) efficiency improvement, offset in part by lower retail sales in Italy due to the the network restructuring process.

     Operating income for 2001 amounted to euro 985 million, substantially similar to 2000 levels, due to: (i) higher selling margins on European retail markets and higher LPG margins; (ii) lower provisions to the environmental risk reserve (euro 95 million), due to the fact that in year 2000 a significant charge was recorded in connection with the rationalization process of the Italian network; (iii) lower costs (approximately euro 100 million) related to streamlining that substantially offset salary increases, inflation and the

 


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appreciation of the dollar over the euro; (iv) lower writedowns of assets (euro 36 million); (v) a profit relating to withdrawals from inventories (euro 36 million). These positive factors were offset by a decline in refining results due to a price environment less positive than the exceptionally favorable scenario of 2000, whose effects were offset in part by higher margins for the refineries located on continental Italy (resulting from increased CIF/ FOB differentials), higher processing yields related also to the higher profitability of crudes supplied, and the appreciation of the dollar over the euro.

     Petrochemicals.   Operating losses in 2002 amounted to euro 347 million, an increase of euro 15 million over 2001, up 4.5%, due mainly to: (i) a decline in margins, especially in the first quarter of 2002, related to lower selling prices of products (on average down 8.1%), as compared to a slower decline in prices in euro of oil-based feedstocks (on average down 1.2%), and (ii) assets impairments (euro 105 million). These negative factors were offset in part by: (i) lower depreciation and amortization charges (euro 90 million) following plant writedowns recorded in 2001; (ii) the fact that in 2001 the impact of price decreases on the evaluation of stocks had been negative for euro 100 million (in 2002 this impact was positive for euro 27 million); (iii) lower costs related to streamlining and disposals (euro 70 million), offset in part by salary increases and inflation; (iv) a 3.3% increase in volumes sold on a comparable basis.

     In 2001 the Petrochemical segment recorded an operating loss amounting to euro 332 million, as compared to an operating income of euro 4 million generated in 2000. This euro 336 million decline was due to: (i) the negative impact of the decline in prices on the evaluation of stocks (euro 100 million as compared to the positive effect of euro 80 million of 2000); (ii) lower product margins (down in average 14%) due to a decline in selling prices, only partly offset by the decline in prices in euro of oil-based feedstocks; (iii) a 6.8% decline in volumes sold related to declining demand, lower product availability and the sale of the Polyurethane business. These negative factors were offset in part by lower costs related to streamlining and divestments (approximately euro 92 million), only partially offset by salary increases and inflation and by lower recurring environmental charges.

     Oilfield Services and Engineering.   Operating income totaled euro 298 million, of which euro 302 million related to oilfield services, with a euro 43 million increase over 2001, up 16.9%. Oilfield services recorded an increase in operating income of euro 46 million due to the contribution of the Blue Stream and Karachaganak projects and to the results obtained by increased activities in West Africa, Saudi Arabia and the Far East, as well as to the contribution of Bouygues Offshore (euro 35 million before the allocation of euro 21 million for the amortization of the difference between purchase price and net equity non attributable to fixed assets). These positive factors were offset in part by the lower profitability of some contracts in the Offshore drilling area. Engineering activities recorded an operating loss of euro 4 million, with a euro 3 million decline, due primarily to higher provisions to the reserve for risks and contingencies on contracts nearing completion (euro 18 million) and the negative outcome of a transaction (euro 8 million), offset in part by increased turnover for 2002, in particular related to the contract for the construction of the Milan-Bologna high speed train tracks. Note that income earned from joint venture projects is accounted for as income on investments in Eni’s income statement. Operating income calculated with the inclusion of this income amounted to euro 23 million (euro 11 million in 2001 in comparable terms).

     Operating income in 2001 amounted to euro 255 million, with an euro 111 million increase over 2000, up 77.1%. Operating income of oilfield services amounted to euro 256 million, with an increase of euro 115 million, up 81.6%, due to the contribution of the Blue Stream contract, an increased use of the Scarabeo 7 and Saipem 10000 vessels, the recovery of demand and higher profitability of orders in the Onshore construction area, the effects of which were offset in part by higher depreciation and amortization charges related to the entry into service of new vessels and investments concerning ongoing projects. Engineering activities recorded an operating break-even as compared to the income of euro 3 million generated in 2000. This decline is mainly due to the prudential provision to the reserve for contingencies on nearly completed projects in the Chemicals and fertilizers area, offset in part by the proceeds recorded after the payment of insurance damage, improvements in the Field upstream facilities and pipelines and Energy areas and the contribution of the contract for the construction of the high capacity/high velocity train tracks from Milan to Bologna. The results obtained from the completion of joint venture projects (euro 22 million in 2001 and euro 16 million in 2000) are recorded under investments.

     Other Activities.   This area includes Eni’s corporate and financial overhead costs as well as the operating results of insurance and service businesses (administration, technical services and IT), in addition to those of EniTecnologie SpA, Eurosolare SpA and Tecnomare SpA. Operating losses amounted to euro 189 million (euro 168 million in year 2001).

 


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     Net Financial Expense

     The table below sets forth a breakdown of Eni’s net financial (expense) income for the periods indicated:

                         
    Year ended December 31,
   
    2000   2001   2002
   
 
 
    (millions E)
Net financial expense
    (302 )     (433 )     (259 )
Income on receivables related to operations and tax credits
    201       184       122  
Exchange difference, net
    165       (10 )     (30 )
 
    64       (259 )     (167 )

     2002 compared with 2001. Net financial expense (euro 167 million) decreased by euro 92 million over 2001, due mainly to lower interest rates (three-month Euribor down 1 percentage point) and lower average net borrowings for about euro 950 million.

     2001 compared with 2000. Net financial expense totaled euro 259 million, as compared to net financial income of euro 64 million in 2000. The euro 323 million negative change is due to higher financial charges (euro 131 million), related to an increase in average net borrowings of approximately euro 3,400 million, as well as to the fact that in year 2000 an euro 99 million exchange rate income was recorded on dividend payment to Eni SpA from a foreign subsidiary due to the fact that a different exchange rate was applied to net income and reserves in the years they were first recorded with respect to the exchange rate of the year in which they were distributed.

     Net Income from Investments

     2002 compared with 2001. Net income from investments amounted to euro 43 million (net expense of euro 216 million in 2001) and represented the balance of income of euro 288 million and expense of euro 245 million. Income from investments concerned mainly: (i) Eni’s share of income on investments accounted for with the equity method (euro 184 million) in particular in the Gas & Power (euro 98 million), Oilfield Services and Engineering (euro 38 million) and Refining & Marketing (euro 40 million) segments; (ii) gains on disposal (euro 55 million) essentially on the disposal of a 10% interest in Qatar Petrochemical Co in the Petrochemical segment (euro 52 million); (iii) dividends from investments accounted for at cost (euro 32 million).

     Expense on investments (euro 247 million) concerned: (i) Eni’s share of losses on investments accounted for with the equity method and at cost (euro 209 million), in particular Galp Energia SGPS SA (euro 85 million related to the amortization of the euro 107 million difference between purchase price and net equity); Albacom SpA (euro 37 million) and Inversora de Gas del Centro SA and Distribuidora de Gas del Centro SA (euro 36 million), minor interests in the Exploration & Production (euro 24 million), Oilfield Services and Engineering (euro 8 million) and other segments (euro 25 million); (ii) losses on disposal of assets (euro 24 million, of which 20 related to the sale of Eni’s 7% interest in Blu SpA).

     The positive change of euro 259 million in the balance of gains and losses on investments as compared to 2001 was due mainly to the circumstance that in 2001 a euro 209 million loss was recorded on Polimeri Europa, which in 2001 was accounted for under the equity method, as well as a lower loss recorded on Galp Energia SGPS SA (euro 59 million).

     2001 compared with 2000. Net expense on investments amounted to euro 216 million (as compared to a net income of euro 33 million in 2000) and represented the balance between euro 491 million expense on

 


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investments and euro 275 million income on investments. Expense on investments was primarily due to Eni’s share of losses on investments accounted for under the equity method under the cost method (euro 486 million) and related to Polimeri Europa Srl (euro 209 million, including non recurring items for euro 100 million), Galp Energia SGPS SA (euro 144 million, including goodwill amortization for euro 107 million and non recurring items for euro 82 million), Blu SpA (euro 57 million) and Albacom SpA (euro 42 million).

     Income from investments (euro 275 million) was mainly related to: (i) Eni’s share of income on investments accounted for under the equity method (euro 158 million) relating in particular to the Natural Gas segment (euro 81 million), the Refining and Marketing segment (euro 43 million), and the Oilfield Service and Engineering segment (euro 21 million); (ii) gains on disposals (euro 76 million) related mainly to the sale of 15% of Saras SpA-Raffinerie Sarde (euro 38 million) and 4.7% of Nuovo Pignone Holding SpA (euro 36 million); (iii) dividends paid by affiliates accounted for under the cost method (euro 40 million).

     The euro 249 million negative change was mainly related to the euro 209 million losses of Polimeri Europa Srl (as compared to a net income of euro 35 million in 2000) and higher losses of Galp Energia SGPS SA (euro 99 million), whose effects were partially offset by increased gains on disposals (euro 35 million) and lower losses of Albacom SpA (euro 39 million).

     Net Extraordinary Expense

     The table below sets forth Eni’s extraordinary income and extraordinary expense for the periods indicated:

                           
      Year ended December 31,
     
      2000   2001   2002
     
 
 
      (millions E)
Gains on disposals
    86       3,473       257  
 
Gain on the offering of Snam Rete Gas
            2,453          
 
Gain on the sale of real estate
            751          
Other extraordinary income
    146       173       112  
 
Extraordinary income
    232       3,646       369  
Restructuring costs:
                       
 
Provisions for risks
    (182 )     (885 )     (157 )
 
Writedowns of fixed assets
    (34 )     (607 )     (55 )
 
Cost of redundancy incentives
    (202 )     (237 )     (114 )
 
Total restructuring costs
    (418 )     (1,729 )     (326 )
Other extraordinary expense
    (326 )     (80 )     (72 )
 
Extraordinary expense
    (744 )     (1,809 )     (398 )
Net extraordinary income (expense)
    (512 )     1,837       (29 )

     2002 net extraordinary expense. Gains on disposals (euro 257 million) related to the sale of investments, businesses and fixed assets as a result of restructuring activities. In particular they concerned: (i) in the Refining & Marketing segment, the sale of service stations in Italy to Tamoil, TotalFinaElf and others (euro 127 million), the sale of Agip Nigeria Ltd and other minor interests in Africa (euro 87 million) and logistic assets, small businesses and minor assets (euro 11 million); and (ii) in the Gas & Power segment, the sale of real estate (euro 21 million).

     Other extraordinary income of euro 112 million concerned the reversal of redundant funds, settlements of disputes and recovery of receivables in the Petrochemicals (euro 72 million), Gas & Power (euro 23 million), Refining & Marketing (euro 13 million) and other segments (euro 6 million).

 


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     Provisions for risks and contingencies of euro 157 million related mainly the reserve for environmental risks and expense related to streamlining and disposals in the Refining & Marketing (euro 79 million) and Petrochemical (euro 71 million) segments.

     Redundancy incentives of euro 114 million concerned primarily the Petrochemical segment (euro 34 million), the Gas & Power division (euro 28 million), the Refining & Marketing division (euro 26 million), the Oilfield Services and Engineering segment (euro 14 million) and the Exploration & Production division (euro 9 million).

     Writedowns and losses for euro 55 million concerned essentially assets in the Petrochemical segment (euro 23 million) and a euro 22 million loss related to the conferral of the Priolo refinery and of its power station to Erg Raffinerie Mediterranee Srl, in which Eni holds a 28% interest after the conferral.

     Other extraordinary expense (euro 72 million) concerned essentially the Refining & Marketing division (euro 49 million) mainly related to restructuring and expense of previous years.

     2001 net extraordinary income. Gains on disposals (euro 3,473 million) related to the sale of investments, businesses and fixed assets as a result of restructuring activities. In particular, gains on disposal were primarily due to: (i) the public offering of 40.24% of the share capital of Snam Rete Gas (euro 2,453 million); this gain derives from the difference between proceeds from the sale of Snam Rete Gas shares and the corresponding stake of consolidated equity, which does not include the voluntary revaluation of assets, performed by Snam SpA in 2000 as per Law 342/2000, which is eliminated in accordance with Italian GAAP; (ii) the sale of Eni’s interest in Immobiliare Metanopoli (euro 348 million) and other real estate (euro 403 million) within Eni’s real estate divestment program; (iii) the sale of the Polyurethane business in the Petrochemical segment (euro 211 million).

     Other extraordinary income of euro 173 million relates primarily to the release of the reserve for contingencies of euro 112 million which AgipPetroli had accrued in fiscal 2000 on the basis of a ruling by the Antitrust Authority, No. 8353 of June 8, 2000, for alleged horizontal cartel with other oil companies. This ruling was appealed by the company and definitively annulled by the Council of State on July 20, 2001 with decision No. 359/2001. Accordingly, the accrual was reversed.

     Provisions for risks of euro 885 million related to closing downs, disposals and environmental remediation on plants still in operation as of December 31, 2001 in the Petrochemical segment (euro 616 million, of which euro 240 million related primarily to environmental remediation efforts at plants that management has specifically identified to close down in the next two-three years and euro 376 million related to environmental compliance provisions on all operating plants made in application of Law 471/99), and to environmental remediation on de-industrialized areas in the Petrochemical (euro 91 million), Refining & Marketing (euro 77 million) and Gas & Power (euro 44 million) segments.

     Writedowns for euro 607 million concerned primarily the writedown of fixed assets and investments in the Petrochemical segment (euro 574 million) in order to align the book value of assets to both the results of the impairment test made on the basis of estimated future cash flows in a declining market scenario for petrochemical products margins and also to the result of an asset valuation made by a court-appointed expert in connection with the transfer of same to Polimeri Europa on January 1, 2002. These write-downs relate primarily to olefins and aromatics plants, phenol plants and various other petrochemicals assets.

     Redundancy incentives of euro 237 million concerned primarily the Exploration and Production segment (euro 101 million), the Gas & Power segment (euro 44 million), the Refining & Marketing segment (euro 42 million), the Petrochemical segment (euro 39 million).

     Other extraordinary expenses (euro 326 million) concern mainly the provision to a reserve of euro 112 million relating to a fine imposed by the Antitrust Authority on AgipPetroli SpA for the breach of art. 2 of Law 287/90 related to alleged cartel agreements with other oil companies, tax loss carryforwards relating to Agip Angola Production BV (euro 90 million) and the additional tariff on natural gas transmission (euro 72 million) paid to Tenp, as mentioned among other extraordinary income, and expenses for litigations (euro 40 million).

 


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     See Note 27 to the Consolidated Financial Statements for a discussion of the different criteria used under Italian GAAP and U.S. GAAP for determining extraordinary items.

     Taxes

     Under Italian tax law, Eni, like all other Italian groups, is unable to offset fully income earned by certain subsidiaries with losses recognized by other subsidiaries because each legal entity must pay income tax on the basis of the results recorded by it rather than on the basis of consolidated financial results.

     2002 compared with 2001.   Income taxes (euro 3,127 million) decreased by euro 402 million over 2001, due mainly to a decline in income before taxes and the positive effect (euro 95 million) of the release of the reserve for anticipated amortization as per Law 448/2001, offset in part by the adjustment of the reserve for deferred tax liabilities due to a 10 percentage point increase in corporate taxes (from 30 to 40%) of oil companies in the United Kingdom (euro 215 million).

     The 7.5 percentage points increase in tax rate compared to 2001 (from 30 to 37.5%) was due mainly to the fact that the gains on the placement of 40.24% of Snam Rete Gas in 2001 were recorded net of substitute tax paid.

     The 4.6 percentage point difference between effective tax rate (37.5%) and statutory tax rate (42.1%) was due to: (i) for 5 percentage points the effect of the application of a favorable tax regime as provided for by certain Italian tax laws (such as the law on dual income tax, Law 383/2001 which provides for fiscal incentives to new investments and Law 448/2001); (ii) the effect of a revaluation of assets in 2000 as per Law 342/2000 for 4.7 percentage points. These effects were partially offset by the higher rate of taxes of foreign subsidiaries (2.7 percentage points) and other factors (2.4 percentage points).

     Income taxes of foreign subsidiaries in the Exploration & Production division amounted to euro 2,093 million, representing a euro 28 million decrease over 2001 reflecting lower income before taxes of foreign subsidiaries with relatively higher tax rates and the recording of anticipated taxes on tax loss carryforwards of Agip Petroleum Co Inc and Agip Exploration & Production Ltd, partially offset by the adjustment of the reserve for deferred tax liabilities of oil companies in the United Kingdom (euro 215 million).

     2001 compared with 2000.   Income taxes (euro 3,530 million) decreased by euro 805 million over 2000, due to: (i) the effect of the application in 2000 of the voluntary revaluation of assets as per Law 342/2000; (ii) a higher taxable income at the reduced 19% rate as provided for by Legislative Decree No. 466/97 related to dual income tax; (iii) a decrease in Irpeg rate (from 37 to 36%). These positive factors were offset in part by increased tax rates of foreign subsidiaries.

     Effective tax rate was 30% as compared with a statutory tax rate of 40.9%. This 10.9 percentage point difference was due to: (i) permanent timing differences for 7.6 percentage points, of which 7.2 related to the gain recorded in Eni’s consolidated financial statements following the offering of 40.24% of the share capital of Snam Rete Gas; this gain is not subject to income taxes due to the fact the substitute tax paid on a 19% basis in application of Law 342/2000 was recorded by increasing Eni consolidated accounts of the book value of assets transferred to Snam Rete Gas, consequently affecting the measure of the gain. Substitute taxes will be charged to Eni consolidated income statements in line with the amortization process of relevant assets; (ii) the effect of the application in 2000 of the voluntary revaluation of assets as per Law 342/2000 for 4.6 percentage points; (iii) for 2.3 percentage points the effect of the application of a favourable tax regime as provided for by certain Italian tax laws (for example the law on dual income tax, Law 383/2001 which provides for fiscal incentives to new investments, and substitute taxes allowed on gains on disposals); (iv) for 1.4 percentage points for other reasons. These effects were partially offset by the higher rate of taxes on some foreign subsidiaries (5.0 percentage points).

     Income taxes of foreign subsidiaries in the Exploration & Production segment amounted to euro 2,028 million, representing a euro 84 million increase over 2000 reflecting the acquisition of Lasmo partially offset by lower oil prices.

 


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     Minority Interest

     2002 compared with 2001. Minority interest (euro 629 million) increased by euro 161 million over 2001, due mainly to the placement of 40.24% of Snam Rete Gas in late 2001 and higher net income earned by Saipem SpA.

     2001 compared with 2000. Minority interests (euro 477 million) increased by euro 226 million over 2000, due in particular to the share of profits of Snam Rete Gas SpA attributed to minorities and higher net income earned by Saipem SpA, partially offset by lower net income earned by Italgas SpA.

Liquidity and Capital Resources

     The table below sets forth the principal components of Eni’s cash flow for the periods indicated.

                             
        Year ended December 31,
       
        2000   2001   2002
       
 
 
        (millions E)
Net income before minority interest
    6,022       8,228       5,222  
 
Adjustments to reconcile to cash generated from operating income before changes in working capital:
                       
 
• Amortization and depreciation and other non-monetary items
    4,307       4,942       5,682  
 
• Net gains on disposals of assets
    (82 )     (170 )     (152 )
 
• Dividends, interest, extraordinary income (expense) and income taxes
    4,990       2,038       3,305  
Net cash generated from operating income before changes in working capital
    15,237       15,038       14,057  
Changes in working capital related to operations
    (1,592 )     (197 )     (510 )
Dividends received, taxes paid, interest and extraordinary income/expense (paid) received during the year
    (3,062 )     (6,695 )     (2,969 )
 
Net cash provided by operating activities
    10,583       8,146       10,578  
Capital expenditures
    (5,431 )     (6,577 )     (8,048 )
Investments
    (3,483 )     (3,082 )     (1,315 )
Disposals
    277       2,114       935  
Other cash flow related to capital expenditure, investments and divestments
    (69 )     (88 )     (319 )
 
Free cash flow(1)
    1,877       513       1,831  
Dispositions (acquisitions) of highly liquid investments
    111       994       (1,171 )
Changes in short and long-term financial debt
    121       (534 )     3,736  
Dividends paid and changes in minority interests and reserves
    (2,118 )     (950 )     (3,846 )
Effect of change in consolidation scope and exchange differences
    41       38       (64 )
 
Net cash flow for the year
    32       61       486  

 


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     The table below sets forth changes in Eni’s net borrowings for the periods indicated.

                         
    Year ended December 31,
   
    2000   2001   2002
   
 
 
    (millions E)
Free cash flow(1)
    1,877       513       1,831  
Net borrowings of acquired companies
    (901 )     (1,582 )     (51 )
Net borrowings of divested companies
    20       185       39  
Exchange differences on net borrowings and other changes
    (353 )     (312 )     990  
Dividends paid and changes in minority interests and reserves
    (2,118 )     (950 )     (3,846 )
Change in net borrowings
    (1,475 )     (2,146 )     (1,037 )


(1)   Consists of the sum of (i) net cash provided by operating activities, (ii) capital expenditures, (iii) financial investments (iv) disposals, (v) other investments and divestments.

     Cash generated from operating income before changes in working capital

     Cash generated from operating income before changes in working capital totaled euro 14,057 million, 15,038 million and euro 15,237 million in 2002, 2001 and 2000, respectively.

     In 2002, income before minority interests has been adjusted to take into account depreciation, amortization and other non-cash items (euro 5,682 million). Adjustments concerned primarily depreciation and amortization of tangible and intangible assets (euro 4,962 million) and writedowns of fixed assets and investments (euro 597 million).

     In 2001, income before minority interests has been adjusted to take into account depreciation, amortization and other non-cash items (euro 4,942 million). Adjustments concerned primarily depreciation and amortization of tangible and intangible assets (euro 4,671 million), writedowns of fixed assets and investments (euro 571 million) and a decrease in the reserve for contingencies (euro 323 million) relating primarily to the reversal (euro 200 million) made in the Gas & Power segment of the provision recorded in year 2000 in connection with Decision No. 193/1999 of the Authority for Electricity and Gas relating to the price of natural gas, as well as to the reversal of the loss adjustment and actuarial reserve made by Eni’s insurance subsidiaries (euro 79 million).

     Changes in working capital related to operations

     Net working capital related to operations increased by euro 510 million, by euro 197 million and by euro 1,592 million in 2002, 2001 and 2000, respectively.

     In 2002, the increase in net working capital (euro 510 million) was mainly due to the anticipated payment of certain excise taxes due for year 2002, partly offset by decrease in trade accounts payable.

     In 2001, the increase in net working capital (euro 197 million) was mainly due to the decrease in trade accounts payable and other (euro 420 million) reflecting the deferral to year 2001 of the payment of excise taxes due for year 2000, partly offset by a decrease in inventories (euro 179 million) due to withdrawals from inventories in particular of oil and refined products in the Refining & Marketing segment.

     Dividends, interest, taxes and extraordinary expense

     Dividends, interest, taxes and extraordinary expense paid (which is net of amounts received) totaled euro 2,969 million, euro 6,695 million and euro 3,062 in 2002, 2001 and 2000, respectively. In 2002, dividends received, interest, extraordinary income (expense) and income taxes paid (euro 2,969 million) concerned primarily the payment of income taxes. In 2001, dividends received, interest, extraordinary income (expense) and income taxes paid (euro 6,695 million) concerned primarily the payment of income taxes for euro 6,189 million, of which euro 2,166 million relating to the payment of the substitute tax due on the voluntary revaluation of assets as per Law 342/2000 carried out by some of Eni’s subsidiaries in year 2000.

 


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     Capital expenditures and Investing Activities

     Capital expenditures totaled euro 8,048 million, euro 6,577 million and euro 5,431 million in 2002, 2001 and 2000, respectively. The euro 1,471 million increase from 2002 to 2001 was due mainly to the euro 1,399 million increase in the Exploration & Production segment and to the euro 250 million in the Gas & Power segment, partly offset by decreases in all Eni other segments.The euro 1,146 million increase from 2000 to 2001 was due mainly to the euro 737 million increase in the Exploration & Production segment and to the euro 271 million in the Gas & Power segment.

     Investments (including net borrowings acquired) totaled euro 1,366 million, euro 4,664 million and euro 4,384 million in 2002, 2001 and 2000, respectively. In 2002 investments (euro 1,366 million) related in particular to the purchase of French company Bouygues Offshore (euro 906 million, net of assets acquired of euro 100 million) and of other companies (euro 149 million) in the Oilfield services segment and the purchase of 97.81% of GVS in joint venture with German company EnBW in the Gas & Power segment. The joint venture paid for the purchase (euro 704 million) by increasing the share capital for euro 178 million (Eni’s share was euro 89 million) and raising finance debt for the remaining part. In 2001, investments (euro 4,664 million) referred in particular to the completion of the acquisition of Lasmo for euro 4,128 million (including net borrowings for about euro 970 million, total investment for this operation amounted to euro 5,353 million including euro 1,225 million paid in 2000), the purchase of 50% of Polimeri Europa — the remaining 50% already owned by Eni — (euro 204 million), the share capital increase related to the two telecoms affiliates Albacom SpA (euro 53 million) and Blu SpA (euro 26 million), the purchase of three engineering companies (for a total of euro 69 million) in the oilfield services activity and the purchase of an interest in a company engaged in the marketing of refined products in Brazil (euro 34 million). In its cash-flow statement, Eni classifies as financial investments the cash used for corporate acquisitions.

     Disposals

     Disposals (including net debt discharged) totaled euro 974 million, euro 2,299 million and euro 297 million in 2002, 2001 and 2000, respectively. Disposals (euro 974 million) concerned essentially: (i) the Exploration & Production segment (euro 436 million) mainly relating to the rationalization of Eni’s mineral asset portfolio; (ii) the Refining & Marketing segment (euro 322 million) relating to the sale of service stations in Italy (euro 160 million), the sale of Agip (Nigeria) Ltd and other minor assets in Africa (euro 76 million) and logistical assets and other minor assets (euro 86 million); (iii) the Petrochemical segment (euro 105 million) of which euro 81 million related to the sale Eni’s 10% interest in Qatar Petrochemical Co; (iv) the Gas & Power segment (euro 59 million) of which 17 million related to the sale of the water business of Fiorentina Gas SpA. In 2001, disposals (euro 2,299 million, including net debt discharged of euro 185 million) concerned: (i) the sale of the entire interest in Immobiliare Metanopoli and of part of Eni’s real estate (for a total of about euro 1,400 million, of which euro 60 million of transferred net debt); (ii) the sale of the Polyurethane business in the Petrochemical segment (euro 428 million); (iii) the sale of the 15% interest in Saras SpA-Raffinerie Sarde (euro 59 million); (iv) the sale of the 4.7% interest in Nuovo Pignone Holding SpA (euro 46 million).

     Dispositions (acquisitions) of highly liquid investments

     The table below sets forth the principal movements of the cash flow from dispositions (acquisitions) of highly liquid investments.

                           
      Year ended December 31
     
      2000   2001   2002
     
 
 
      (millions E)
Financing investments:
                       
 
— securities
    (2,648 )     (291 )     (4 )
 
— financing receivables
    (222 )     (8 )     (1,455 )
 
    (2,870 )     (299 )     (1,459 )

 


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      Year ended December 31
     
      2000   2001   2002
     
 
 
      (millions E)
Disposals of financing investments:
                       
 
— investments
    8                  
 
— securities
    2,951       758       205  
 
— financing receivables
    22       535       83  
 
    2,981       1,293       288  
Net cash flows
    111       994       (1,171 )

     Dividends paid and changes in minority interests and reserves

     In 2002, dividends paid and changes in minority interest and reserves (euro 3,846 million) concerned mainly the payment of dividends for fiscal year 2001 by Eni SpA for a total amount of euro 2,876 million corresponding to euro 0.750 per share or U.S. dollar 3.71 per ADS (converted at the Noon buying rate of the payment date 1 euro = 0.9885 U.S. dollar), the purchase of 52.26 million Eni shares within the share buy-back program (euro 770 million), payment of dividends by Snam Rete Gas SpA (euro 74 million), Italgas SpA (euro 37 million) and Saipem SpA (euro 32 million).

     In 2001, dividends paid and changes in minority interests and reserves (euro 950 million) consisted primarily of the distribution of dividends for fiscal year 2000 by Eni SpA for a total amount of euro 1,664 million corresponding to euro 0.424 per share or U.S. dollar 1.81 per ADS (converted at the Noon buying rate of the payment date), as well as the purchase of 109,999,326 own shares for euro 1,494 million (at an average price per share of euro 13.58). These outflows were partly offset by the euro 2,202 million inflow generated by the offering of 40.24% of the share capital of Snam Rete Gas.

     Net borrowings

     Eni evaluates its financial condition by reference to «net borrowings», which it calculates as total debt (short-term and long-term debt) less: cash, and cash equivalent, securities not related to operations, non-operating financing receivables and other items, net. In 2002, net borrowings amounted to euro 11,141 million, a euro 1,037 million increase over December 31, 2001. Debt and bonds increased by euro 2,872 million; cash and cash equivalent increased by euro 1,875 million due to the fact that Eni made a deposit of euro 1,447 million for the public tender offer of Italgas SpA shares. In 2001, net borrowings amounted to euro 9,888 million, an increase of euro 2,146 million over December 31, 2000. In 2001, cash and cash equivalent and accounts receivable financing and securities decreased by euro 642 million (from euro 3,302 million in 2000 to euro 2,660 million). Debts and bonds were consequently increased by euro 1,504 million. Cash and cash equivalent are denominated principally in euro and U.S. dollars.

     The table below sets forth the calculations of net borrowings for the periods indicated.

                                                 
    Year ended December 31,
   
    2001   2002
   
 
    Short-   Long-           Short-   Long-        
    term   term   Total   term   term   Total
   
 
 
 
 
 
                    (millions E)                
Short-term and long-term debt
    6,464       6,084       12,548       8,870       6,550       15,420  
Cash and cash equivalent
    (1,390 )             (1,390 )     (3,265 )             (3,265 )
Securities not related to operations
    (929 )     (312 )     (1,241 )     (719 )     (290 )     (1,009 )
Non operating financing receivables
    0               0       (2 )             (2 )
Other, net
    (29 )             (29 )     (3 )             (3 )
 
    4,116       5,772       9,888       4,881       6,260       11,141  

 


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     Short-term and long-term debt outstanding at December 31, 2002, amounted to euro 15,420 million, of which 8,870 were short-term (including the share of long-term debts due within twelve months for euro 980 million) and 6,550 were medium and long-term. Euro 5,152 million of Eni’s long-term debt outstanding at December 31, 2002 is scheduled to mature after December 31, 2004. Of the total debt at December 31, 2002, euro 8,563 million was denominated in euro and 6,857 million in other currencies (principally U.S. dollar). The weighted average interest rate on Eni’s long-term debt (including current maturities) at December 31, 2002 was approximately 5.48%.

     Short-term and long-term debt outstanding at December 31, 2001, amounted to euro 12,548 million, consisting of short-term debt (including bonds and the current portion of long-term debt) of euro 6,464 million and long-term debt of euro 6,084 million. Euro 4,368 million of Eni’s long-term debt outstanding at December 31, 2001, is scheduled to mature after December 31, 2003. Of the total debt at December 31, 2001, euro 4,731 million was denominated in euro and euro 7,817 million was denominated in other currencies (principally U.S. dollars). The weighted average interest rate on Eni’s long-term debt (including current maturities) at December 31, 2001, was approximately 5.33%. The increase in long-term debt of euro 1,615 million, relates primarily to the change in the scope of consolidation (euro 1,683 million of which euro 1,846 million related to Lasmo Plc) and exchange rate differences deriving from the translation into euro of financial statements denominated in other currencies (euro 326 million). This increase was offset in part by the net change in debt assumed and repaid in the year (euro 394 million).

     The amount of debt subject to restrictive covenants was not material.

     Eni financial arrangements generally include customary cross default provisions.

     Capital expenditures by segment

     The table below sets forth a breakdown, by segment, of capital expenditures.

                           
      Year ended December 31,
     
      2000   2001   2002
     
 
 
      (millions E)
Exploration & Production
    3,539       4,276       5,615  
Gas & Power
    794       1,065       1,315  
Refining & Marketing
    533       496       550  
Petrochemicals
    265       361       249  
Oilfield Services and Engineering
    245       304       233  
Other activities
    55       75       86  
 
Total
    5,431       6,577       8,048  

     In 2002, capital expenditure in the Exploration & Production segment amounted to euro 5,615 million, increasing by euro 1,339 million over 2001, up 31.3%. Exploration expenditure amounted to euro 902 million, of which 93% was outside Italy, with a 19.2% increase over 2001. Outside Italy exploration concerned mainly the United States, Kazakhstan, Egypt, Angola, Russia and Brazil; in Italy mainly the deep waters of the Sicily Channel and areas in central-southern Italy. Investment in the purchase of proved and unproved property (euro 317 million) concerned primarily the purchase of: (i) a 2.39% interest in the North Caspian Sea PSA, where the Kashagan field is located (Eni is single operator with a 16.67% interest after the purchase) in Kazakhstan; (ii) a 5.6% interest in the Bayu Undan field (Eni’s interest 12.32% after the purchase) in Australia; (iii) an 11.3% interest in the T-Block fields (Eni is operator with an 88.7% share after the purchase) in the British section of the North Sea; (iv) a 7.9% interest in the Mikkel field in Norway; (v) an 8.9% interest in the Liverpool Bay fields (Eni’s interest 53.9% after the purchase) in the Irish Sea. Expenditure for development and capital goods totaled euro 4,396 million of which 89% outside Italy, increasing by 27.3% over 2001. Development expenditure outside Italy concerned fields in Nigeria, Iran, Libya, Kazakhstan, Angola, Venezuela and the United Kingdom. Development expenditure in Italy referred in particular to the continuation of construction of plant and infrastructure in the Val d’Agri.

 


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     In the Exploration & Production segment, capital expenditure in 2001, amounted to euro 4,276 million, increasing by euro 737 million over 2000, up 20.8%. Exploration expenditure amounted to euro 757 million (euro 811 million in 2000), of which 89% was directed outside Italy, representing a 6.7% decrease over 2000. Expenditure in Italy (euro 80 million as compared to euro 156 million in 2000) concerned primarily areas in Northern Italy and the Southern Apennines. Outside Italy, exploration expenditure amounted to euro 677 million (euro 655 million in 2000) and concerned mainly core areas in North Africa (in particular Algeria and Egypt), West Africa (Nigeria, Congo and Angola), the North Sea (Norway), Latin America and the Caspian Sea and recently acquired areas (those of Lasmo and British-Borneo and the United States). Expenditure for the purchase of proved and unproved property amounted to euro 67 million (euro 416 million in 2000), of which euro 34 million related to the purchase of a 30% interest in the T-Block fields in the North Sea, in which Eni a