20-F 1 u50474e20vf.htm FORM 20-F e20vf
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As filed with the Securities and Exchange Commission on June 28, 2006
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 20-F
         
  o     REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
  þ     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
        For the Fiscal Year Ended: December 31, 2005
OR
  o     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
  o     SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
        Date of event requiring this shell company report
        For the transition period from           to
Commission file number: 1-14970
ENEL-Società per Azioni
(Exact name of registrant as specified in its charter)
ENEL S.p.A.
(Translation of registrant’s name into English)
Italy
(Jurisdiction of incorporation or organization)
Viale Regina Margherita 137, Rome, Italy
(Address of principal executive offices)
 
Securities registered or to be registered pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
     
American Depositary Shares
Ordinary shares with a par value of 1 each
  New York Stock Exchange
New York Stock Exchange(*)
 
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
 
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
(Title of Class)
 
     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.
6,157,071,646 Ordinary Shares
     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes          þ        No          o
     If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934.
Yes          o        No          þ
     Note — checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 from their obligations under those sections.
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes          þ        No          o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exhange Act. (Check one):
Large accelerated filer    þ        Accelerated filer    o        Non-accelerated filer    o
     Indicate by check mark which financial statement item the registrant has elected to follow.
Item 17          o        Item 18          þ
     If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes          o        No          þ
 
(*) Not for trading, but only in connection with the registration of the American Depositary Shares.
 
 


Table of Contents

TABLE OF CONTENTS
             
 
           
PRESENTATION OF FINANCIAL AND OTHER INFORMATION     iii  
 
           
GLOSSARY     v  
 
 PART I
   IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS     1  
   OFFER STATISTICS AND EXPECTED TIMETABLE     1  
   KEY INFORMATION     1  
     The Enel Group     1  
     Selected Consolidated Financial Data     3  
     Exchange Rates     6  
     Risk Factors     7  
     Forward-Looking Statements     17  
   INFORMATION ON THE COMPANY     18  
     History and Development of the Company     18  
     Business     19  
       Overview     19  
       Strategy     23  
       The Enel Group     27  
          Italian Electricity Demand     27  
          Generation and Energy Management     28  
          Sales, Infrastructure and Networks     39  
          Competition in the Electricity and Gas Markets     47  
          Seasonality of Electricity and Gas Consumption     49  
          Discontinued Operations     49  
          Services and Other Activities     50  
          Capital Investment Program     52  
     Regulatory Matters     55  
       Overview of Regulation in the Energy Sector in Italy     55  
       Electricity Regulation     55  
       Gas Regulation     69  
       Environmental Matters     71  
     Property, Plants and Equipment     78  
   UNRESOLVED STAFF COMMENTS     78  
   OPERATING AND FINANCIAL REVIEW AND PROSPECTS     78  
     Summary of Results     78  
     The Electricity Market Regulatory Framework     79  
     Outlook     85  
     Analysis of Operating Results     87  
       2005 compared with 2004     88  
     Inflation     98  
     U.S. GAAP Reconciliation     98  
     Liquidity and Capital Resources     102  
     Off-Balance Sheet Arrangements     106  
     Contractual Obligations and Commitments     107  
     Trend Information     108  
   DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES     108  
     Directors     108  

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TABLE OF CONTENTS — (Continued)
             
     Senior Management     112  
     Board of Statutory Auditors     114  
     Executive Compensation     115  
     Share Ownership     118  
     Employees     119  
   MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS     120  
     Major Shareholders     120  
     Related Party Transactions     122  
   FINANCIAL INFORMATION     123  
     Consolidated Financial Statements     123  
     Other Financial Information     123  
       Legal Proceedings     123  
       Dividend Policy     128  
     Significant Changes     129  
   THE OFFER AND LISTING     130  
     Markets and Price Range of ADSs and Ordinary Shares     130  
   ADDITIONAL INFORMATION     131  
     Stock Option Plans     131  
     By-Laws     134  
     Significant Differences in Corporate Governance Practices for Purposes of Section 303A.11 of the NYSE Listed Company Manual     148  
     Material Contracts     153  
     Exchange Controls     153  
     Taxation     154  
     Documents On Display     158  
   QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK     158  
     Price Risk Management and Market Risk Information     158  
   DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES     163  
 
 PART II
   DEFAULTS, DIVIDENDS AVERAGES AND DELINQUENCIES     163  
   MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND PROCEEDS     163  
   CONTROLS AND PROCEDURES     163  
   [RESERVED]     163  
   AUDIT COMMITTEE FINANCIAL EXPERT     163  
   CODE OF ETHICS     164  
   PRINCIPAL ACCOUNTANT FEES AND SERVICES     164  
   EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES     165  
   PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS     165  
 
 PART III
   FINANCIAL STATEMENTS     165  
   FINANCIAL STATEMENTS     166  
   EXHIBITS     167  
 Exhibit 1.1
 Exhibit 8.1
 Exhibit 12.1
 Exhibit 12.2
 Exhibit 12.3
 Exhibit 13.1

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PRESENTATION OF FINANCIAL AND OTHER INFORMATION
      Unless we indicate otherwise, the financial information contained in this annual report is prepared in accordance with International Financial Reporting Standards (“IFRS”), as adopted by the European Union (“EU”), that we have applied for the first time in preparing our financial statements for periods beginning after December 31, 2004. There are no differences between IFRS, as adopted by the EU, and the IFRS, as published by the International Accounting Standards Board (“IASB”), relevant for our consolidated financial statements. For a description of these principles, see note 2 to our consolidated financial statements included in this annual report. Until December 31, 2004, our financial statements were prepared in accordance with Italian GAAP and, to the extent such requirements or principles were silent on particular issues and not at variance, by those standards laid down by the International Accounting Standards Board (I.A.S.B.).
      In relation to this transition to IFRS, in April 2005 the Securities and Exchange Commission (“SEC”) adopted amendments to Form 20-F to provide a one time accommodation relating to first financial statements prepared under IFRS for foreign private issuers registered with the SEC. This accommodation permits Enel for its first year of reporting under IFRS to report two years rather than three years of statements of income, changes in shareholders’ equity and cash flows prepared in accordance with IFRS, with appropriate related disclosure and respective reconciliation of financial statement items to generally accepted accounting principles in the United States of America (“U.S. GAAP”).
      IFRS differ in certain respects from generally accepted accounting principles in the United States (“U.S. GAAP”). We describe these differences in notes 21-22 to our consolidated financial statements. Unless indicated otherwise, any reference in this annual report to our consolidated financial statements is to the consolidated financial statements (including the notes to the consolidated financial statements) included in Item 18.
      We publish our consolidated financial statements in euros. In this annual report, unless we specify otherwise or the context otherwise requires:
  •  References to “dollars,” “$” and “U.S. dollars” are to United States dollars;
 
  •  References to “” or “euro” are to the euro, the single currency established for participants in the third stage of the European Economic and Monetary Union, or EMU, commencing January 1, 1999; and
 
  •  References to “lire,” “lira” or “Lit.” are to Italian lire.
      To facilitate a comparison, all lire-denominated financial data for periods prior to January 1, 2001, included in this annual report have been restated from lire to euro at the fixed rate as of December 31, 1998 established by the European Central Bank of Lit. 1,936.27 = 1.00.
      For convenience only and except where we specify otherwise, we have translated certain euro figures into dollars at the rate of 1.00 = $1.1842, the noon buying rate in The City of New York for cable transfers in foreign currencies as announced by the Federal Reserve Bank of New York for customs purposes (the “noon buying rate”) on December 31, 2005, the date of the most recent balance sheet included in this annual report. By including convenience currency translations in this annual report, we are not representing that the euro amounts actually represent the dollar amounts shown or could be converted into dollars at the rates indicated. On May 31, 2006, the noon buying rate for the euro was 1.00 = $1.2833. For information about the rate of exchange between the dollar and the euro since January 1, 2000, you should read “Item 3. Key Information — Exchange Rates.”

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Market share information and statistics
      Unless otherwise specified or the context requires otherwise, references in this annual report to statistical, market and forecast data have been obtained or derived from industry sources and other publicly available information, such as industry reports published by the GRTN (as defined in the Glossary below), Terna and the Energy Authority (as defined in the Glossary below). Certain data may be revised from that presented in our annual reports on Form 20-F for prior years to reflect subsequent updates to, or changes in, such data. Unless otherwise indicated, statistical data and other information presented herein regarding market trends and our market position relative to competitors represent our best estimates as of the date hereof based on data derived from publicly available sources or other information obtained from independent third parties. Although we believe that such sources are reliable, we have not independently verified such information.
Adjustments
      Certain figures included in this annual report have been subject to rounding adjustments. Accordingly, figures shown for the same category presented in different tables may vary slightly and figures shown as totals in certain tables may not be an arithmetic aggregation of the figures which precede them.

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GLOSSARY
      In this annual report, “Enel” and the “Company” refer to ENEL S.p.A. and the terms “Enel Group,” “Group,” “we,” “us” and “our” refer to ENEL S.p.A. together with its consolidated subsidiaries. In this document, when we use the word “currently,” we mean as of the date of this annual report.
      The following are definitions of certain terms and abbreviations that we use in this report. The explanations of electricity-related terms are not technical definitions, but are intended to assist you in understanding their meaning.
Antitrust Authority The Italian Antitrust Authority.
 
Average thermal efficiency A measure of the efficiency of a thermal generating plant in converting sources of energy such as fuel oil into electricity. Average thermal efficiency is expressed as the amount of electricity actually produced in kWh as a percentage of the kWh equivalent of the energy source consumed.
 
Bersani Decree Legislative Decree No. 79 of March 16, 1999, aimed at liberalizing the Italian electricity market.
 
CIP 6 Regulation 6/92 issued by Comitato Interministeriale Prezzi, an Italian governmental committee, which established incentives for new generation plants using renewable resources and for the sale of electricity produced from renewable resources.
 
CO2 Carbon dioxide.
 
Combined Cycle Gas Turbine (or “CCGT”) A type of generating plant that produces electricity through both gas turbines and steam turbines. Conventional boilers or other generators recover and use the exhaust heat exiting from gas turbines.
 
Co-generation The simultaneous generation of steam and electricity, typically where the need arises for industrial purposes.
 
Communications Authority The Italian Authority for the Guarantee of Communications.
 
Decommissioning The phase of declassification, decontamination and dismantling of nuclear power installations and clean up of the plant site with the aim of achieving: (i) the complete demolition of the nuclear power plant; (ii) the removal of any limitation due to the presence of radioactive material; and (iii) the restoration of the site for other activities.
 
Eligible Customer Electricity customers in Italy who meet consumption thresholds that permit them to participate in the free market for electricity.
 
Emission trading rights Tradable emission permits that give the right to produce the equivalent of one ton of carbon dioxide. These permits can either be assigned through a national allowance plan or earned through investments in projects in developing countries (Certified Emission Reductions) or in transition economies countries (Emission Reduction Units).
 
Energy Authority The Italian Authority for Electric Energy and Gas.
 
Environment Ministry The Italian Ministry of the Environment.
 
Gencos The three generating companies we disposed of in order to comply with the Bersani Decree, Elettrogen S.p.A. (now Endesa Italia

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S.p.A.), Eurogen S.p.A. (now Edipower S.p.A.) and Interpower S.p.A. (now Tirreno Power S.p.A.).
 
Generating unit An electric generator together with the turbine or other device which drives it.
 
Gigawatt (GW) 1,000,000,000 watts (1,000 megawatts).
 
Gigawatt hour (GWh) One gigawatt of power supplied or demanded for one hour.
 
GHG “Greenhouse gases,” which are gases that contribute to the greenhouse effect, such as carbon dioxide, methane, nitrous oxide, chlorofluorocarbons and ozone.
 
Gross installed capacity The maximum power that can be produced continuously throughout a prolonged period of operation with all equipment assumed to be fully operational.
 
GRTN Gestore del Sistema Elettrico — GRTN S.p.A. (formerly Gestore della Rete di Trasmissione Nazionale), a company owned by the MEF that until October 2005 mainly managed Italy’s national electricity transmission grid. These activities were transferred to Terna in November 2005. Since that time, the GRTN has focused on managing and promoting renewable resources (an activity it carried out also prior to November 2005). GRTN also owns the Single Buyer and the Market Operator (both as defined below).
 
Independent power producers Industrial companies that produce electricity for their own use and for sale to third parties.
 
Italian power exchange (Borsa dell’Energia Elettrica) A virtual marketplace in which producers, importers, wholesalers, the GRTN and Terna, other Eligible Customers and the Single Buyer buy and sell electricity at prices determined through a competitive bidding process.
 
Kilovolt (kV) 1,000 volts.
 
Kilovolt ampere (kVA) 1,000 volts ampere.
 
Kilowatt (kW) 1,000 watts.
 
Kilowatt hour (kWh) One kilowatt of power supplied or demanded for one hour.
 
Market Operator The entity, wholly owned by the GRTN, that manages the Italian power exchange.
 
Marzano Law Law No. 239 of August 23, 2004, aimed at reorganizing existing energy market regulation and further liberalizing the energy market.
 
MEF The Italian Ministry of the Economy and Finance and its predecessor, the Ministry of the Treasury, Budget and Economic Planning.
 
Megawatt (MW) 1,000,000 watts (1,000 kilowatts).
 
Megawatt hour (MWh) One megawatt of power supplied or demanded for one hour.
 
Megavolt ampere (MVA) 1,000,000 volts ampere.
 
Ministry of Productive Activities The Italian Ministry of Productive Activities and its predecessor, the Ministry of Industry, Commerce and Handcrafts.

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Net Installed Capacity The maximum power that can be produced continuously throughout a prolonged period of operation with all equipment assumed to be fully operational, as measured at the point of entry to the transmission network (or minus the power absorbed by plant use and the power lost in the transformers required to raise the voltage to the network level).
 
Non-Eligible Customers Electricity customers in Italy who do not meet consumption thresholds entitling them to participate in the free market.
 
NH3 Ammonia.
 
NOx Nitrogen oxides.
 
Orimulsion Abbreviation of “Orinoco emulsion,” which is a fossil fuel from the Orinoco river basin in Venezuela consisting of very fine bitumen dispersed in water. Orimulsion emits the same amount of CO2 as fuel oil of equivalent energy value.
 
Resellers Other distribution companies to whom we transport electricity because their networks are attached to our network rather than directly to the national transmission grid.
 
Single Buyer (Acquirente Unico) A company wholly owned by the GRTN, responsible for ensuring the supply of electricity to regulated customers who do not yet have access to the liberalized electricity market.
 
SO2 Sulfur dioxide.
 
Substation Equipment which switches and/or changes or regulates the voltage of electricity in a transmission and/or distribution network.
 
Terawatt (TW) 1,000,000,000,000 watts (1,000 gigawatts).
 
Terawatthour (TWh) One terawatt of power supplied or demanded for one hour.
 
Thermal unit A generating unit which uses combustible fuel as the source of energy to drive an electric generator.
 
Volt The basic unit of electric force.
 
Voltampere The basic unit of apparent electrical power.
 
Watt The basic unit of active electrical power.

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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
The Enel Group
Energy Generation, Distribution and Sales
      We are the principal electricity operator in Italy, with the leading position in the generation, distribution and sale of electricity. At December 31, 2005, we had net installed capacity in Italy of approximately 42.2 GW, which we estimate to have represented approximately 49% of total Italian net installed capacity at that date. Our net electricity production in Italy in 2005 was 112.1 TWh, and, based on data provided by Terna, we estimate that our production represented approximately 39% of Italian net production during 2005. In 2005, in Italy, we distributed 259.3 TWh of electricity and sold 148.2 TWh of electricity to end users. Of the total sold, 129.7 TWh were sold to approximately 30 million customers on the regulated market, of which approximately 23.5 million were residential customers (86.9% of all residential customers in Italy, based on our estimations) and 18.5 TWh were sold on the free market. At December 31, 2005, we also had electricity generation plants outside Italy (in Spain, Bulgaria and North, Central and South America) with aggregate net installed capacity of approximately 3.8 GW, as well as sales and distribution operations in Spain with more than 0.6 million customers. In addition, in April 2005 we acquired distribution and sales operations in Romania with approximately 1.4 million customers and in April 2006 we acquired generation operations in Slovakia with a gross installed capacity of approximately 7,000 MW. Based on revenues, we were one of the largest industrial companies in Italy in 2005, with operating revenues of 34,059 million, or approximately $40,333 million. We earned net income of 3,895 million, or approximately $4,612 million, in 2005.
      We are also active in the import, distribution and sale of natural gas. In 2005, we sold approximately 6.7 billion cubic meters of gas to third parties, of which approximately 5.1 billion cubic meters were sold to nearly 2.1 million end users.
      Until June 2004, we owned 100% of Terna, the principal Italian electricity transmission company, which currently owns more than 90% of the transmission assets of Italy’s national electricity grid. In light of Italian laws and regulations providing for the reunification of the ownership and management of the Italian transmission grid and imposing certain ownership restrictions on the entity that will own and manage it, in June 2004, we sold 50% of Terna’s share capital in an initial public offering in Italy and a private placement with certain institutional investors that was not registered under the Securities Act (“the “Terna IPO”). In April 2005, we sold an additional 13.86% of Terna’s share capital in another private placement that was not registered under the Securities Act. In September 2005, we sold an additional 29.99% of Terna’s share capital to Cassa Depositi e Prestiti and in January 2006 we distributed 1.02% of Terna’s share capital as “bonus” shares that we had promised to certain Italian retail investors as part of the Terna IPO, thus reducing our current stake in Terna to 5.12%. In November 2005, the management of the Italian transmission grid was transferred from the GRTN to Terna, which was renamed Terna — Rete Elettrica Nazionale.
Other Operations
      One of the objectives of our management is to focus on on our core energy operations. In line with this strategy of focusing on our core energy operations, in February 2006 we completed the sale of Wind, our telecommunication company, to Weather Investments, a company in which we have a 26.1% interest.

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Nonetheless, we remain active in other sectors, including real estate services, engineering and construction, information technology, personnel training and administration, factoring and insurance services.
Internal organizations
      At the end of 2005, our management decided to re-organize the Group’s internal structure by dividing our Sales Infrastructure and Networks Division into two separate divisions (a Market Division and an Infrastructure and Networks Division) and by allocating our international generation and distribution operations, which had previously been included in other divisions, to a new International Division. This reorganization is effective as of January 1, 2006 and, therefore, our divisions are currently the following: Generation and Energy Management Division, Market Division, Infrastructure and Networks Division and the International Division. Each division is headed by a senior manager who reports directly to the Chief Executive Officer of Enel. Moreover, all non-core activities provided by companies of the Group to other Group companies have been grouped in our Services and Other Activities sector. Enel, as the parent company, defines the strategic objectives for the Enel Group and coordinates the activities of all Group companies. Each of Enel, our divisions and the Services and Other Activities sector constitutes a reportable segment for financial reporting purposes.
Ownership
      The Ministry of Economy and Finance of the Republic of Italy, or the MEF, currently owns 21.4% of Enel’s shares, and Cassa Depositi e Prestiti S.p.A., a company 70% owned by the MEF and 30% owned by a consortium of Italian banking foundations, owns 10.2% of Enel’s shares.
Strategy
      We have worked to face the challenges posed by market deregulation by capitalizing on our expertise in the electricity and gas sectors and by seeking new opportunities for growth in Italy and abroad. We have refocused our operations on our core energy businesses, and we aim to achieve cost leadership in the generation, distribution and sale of electricity and gas, and make customer care a high priority. In addition, we will continue to evaluate strategically relevant international opportunities, both in new markets and in our existing markets, such as Spain, Bulgaria and Romania and, in the area of renewable energy, in North, Central and South America.

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Selected Consolidated Financial Data
      You should read the following selected consolidated financial data together with “Item 5. Operating and Financial Review and Prospects” and our consolidated financial statements and notes thereto included elsewhere in this annual report.
      Our consolidated income statement data for each of the two years in the period ended December 31, 2005 and the consolidated balance sheet data at December 31, 2004 and 2005 set forth below have been prepared in accordance with IFRS as adopted by EU, which differs in certain significant aspects from U.S. GAAP. For an explanation and quantification of such differences, see note 21 to our consolidated financial statements.
                           
    As of December 31,
     
    2004   2005   2005(2)
             
        (Dollars in
    (Euro in millions,   millions, except
    except per share   per share amounts)
    amounts)(1)    
CONSOLIDATED STATEMENT OF INCOME DATA
                       
Amounts in accordance with IFRS:
                       
Operating revenues
  31,011     34,059       $40,333  
Operating expenses:
                       
 
Depreciation, amortization and impairment
    2,201       2,207       2,614  
 
Other
    22,940       26,314       31,162  
Total operating expenses
    25,141       28,521       33,776  
Operating income
    5,870       5,538       6,557  
Financial income (expense) and income (expense) from investments
    (827 )     (714 )     (846 )
Income (expense) from investments accounted for using the equity method
    (25 )     (30 )     (36 )
Income before taxes
    5,018       4,794       5,675  
Income taxes
    2,116       1,934       2,290  
Income from continuing operations
    2,902       2,860       3,385  
Income from discontinued operations (net of tax)
    (155 )     1,272       1,506  
Net income (before minority interest)
    2,747       4,132       4,892  
Earnings per share(2)
    0.45       0.67       0.79  
Number of shares outstanding (in millions)
    6,104       6,157       6,157  
Amounts in accordance with U.S. GAAP(3)
                       
Operating revenues
    36,022       39,635       46,936  
Operating expenses
    32,316       31,627       37,453  
Operating income(4)
    3,706       8,008       9,483  
Income before taxes(4)
    2,614       7,031       8,326  
Net income (before minority interest)
    1,129       4,945       5,856  
Earnings per share(2)
    0.18       0.80       0.95  

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    As of December 31,
     
    2001   2002   2003
             
    (Euro in millions, except per
    share amounts)
CONSOLIDATED STATEMENT OF INCOME DATA
                       
Amounts in accordance with U.S. GAAP:
                       
Operating revenues
    28,781       30,604       31,237  
Depreciation and amortization
    4,478       4,069       4,506  
Operating income
    5,337 (5)     2,617 (6)     4,966  
Income before taxes
    3,965       1,373       3,798  
Net income
    3,688       1,399       2,376  
Earnings per share(2)
    0.61       0.23       0.39  
                         
    As of December 31,
     
    2004   2005   2005(1)
             
        (Dollars in
    (Euro in millions)   millions)
         
CONSOLIDATED BALANCE SHEET DATA
                       
Amounts in accordance with IFRS:
                       
Fixed assets, net
    36,702       30,188     $ 35,749  
Current assets
    13,532       12,746       15,094  
Total assets
    65,378       50,502       59,804  
Current liabilities
    18,607       13,446       15,923  
Short-term debt(7)
    6,589       2,296       2,719  
Long-term debt(8)
    20,291       10,967       12,987  
Shareholders’ equity
    17,953       19,057       22,567  
Amounts in accordance with U.S. GAAP(3):
                       
Fixed assets, net
    37,589       30,320       35,905  
Total assets
    67,152       50,596       59,916  
Short-term debt(7)
    6,589       2,296       2,719  
Long-term debt(8)
    20,291       10,967       12,987  
Shareholders’ equity
    15,697       17,638       20,887  
                         
    As of December 31,
     
    2001   2002   2003
             
    (Euro in millions)
CONSOLIDATED BALANCE SHEET DATA
                       
Amounts in accordance with U.S. GAAP:
                       
Fixed assets, net
    36,035       38,304       37,407  
Total assets
    63,799       66,423       68,505  
Short-term debt(7)
    7,107       8,371       8,643  
Long-term debt(8)
    16,072       17,172       18,005  
Shareholders’ equity
    19,467       18,526       18,651  
 
See notes on next page.

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    As of December 31,
     
    2004   2005   2005(1)
             
        (Dollars in
    (Euro in   millions)
    millions)(1)    
CONSOLIDATED CASH FLOW DATA
                       
Amounts in accordance with IFRS:
                       
Net cash provided by operating activities
  4,835     5,693     $ 6,742  
Net cash (used in) provided by investing activities
    (1,953 )     1,092       1,293  
Net cash (used in) provided by financing activities
    (2,966 )     (6,654 )     (7,880 )
Amounts in accordance with U.S. GAAP(3):
                       
Net cash provided by operating activities
    5,730       4,864       5,760  
Net cash used in investing activities
    1,055       (1,982 )     (2,347 )
Net cash (used in) provided by financing activities
    (6,654 )     (2,966 )     (3,512 )
                         
    As of December 31,
     
    2001   2002   2003
             
    (Euro in millions)
CONSOLIDATED CASH FLOW DATA
                       
Amounts in accordance with U.S. GAAP:
                       
Net cash provided by operating activities
  5,554     3,815     6,843  
Net cash used in investing activities
    (8,707 )     (4,241 )     (4,730 )
Net cash (used in) provided by financing activities
    3,249       239       (2,061 )
                                         
    As of December 31,
     
    2001   2002   2003   2004   2005
                     
Operating Data (Unaudited)
                                       
Net installed capacity (GW) in Italy
    50.0       43.8 (9)     41.8       42.0       42.2  
Net electricity production in Italy (TWh)
    169.1 (10)     145.1 (11       ) 137.8     125.9       112.1  
Electricity sales to end users in Italy (TWh)(12)
    194.9       181.3       152.2       157.8       148.2  
Total electricity distributed in Italy (TWh)(13)
    256.3       258.0       265.0       261.2       259.3  
Natural gas sold to end users (billions of cubic meters)
    1.1       4.0       4.4       5.2       5.2  
Natural gas sales customers at year end (millions)
    0.6       1.7       1.8       2.0       2.1  
Employees
    72,661       71,204       64,770       61,898       51,778  
 
  (1)  We have translated euro amounts into dollar amounts at the noon buying rate for euro on December 31, 2005, of 1.00 = $1.1842.
 
  (2)  We calculate earnings per share by dividing our consolidated net income by the number of Enel’s ordinary shares outstanding during each period. Prior to Enel’s initial public offering in November 1999, all of Enel’s ordinary shares were owned by the MEF. At December 31, 2005, the MEF owned 21.4% and its subsidiary Cassa Depositi e Prestiti owned 10.2% of Enel’s ordinary shares. You should consider that Enel’s share capital was Lit. 12,126,150,379,000 (corresponding to 6,262,634,023) divided into 12,126,150,379 shares with a par value of each share of Lit. 1,000 (corresponding to 0.52) until July 9, 2001, the date on which both the re-denomination of Enel’s share capital in euros and a one-for-two reverse stock split became effective. As a result of the re-denomination and the reverse stock split, Enel’s share capital amounted to 6,063,075,189, divided into 6,063,075,189 shares, each with a par value of 1. As of December 31, 2005 Enel’s share capital amounts to 6,157,071,646 divided into 6,157,071,646 shares with a par value of 1.
 
  (3)  For information concerning differences between IFRS and U.S. GAAP that are relevant to our consolidated financial statements, you should read note 21 to our consolidated financial statements.
 
  (4)  You should read note 21 to our consolidated financial statements for a discussion of the impacts generated by the differences between IFRS and U.S. GAAP in calculating operating income.

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  (5)  Includes gain on sale of Elettrogen, previously classified as other non-operating income (expense).
 
  (6)  Includes gain on sale of Eurogen, previously classified as other non-operating income (expense).
 
  (7)  Includes current portion of long-term debt.
 
  (8)  Excludes current portion of long-term debt.
 
  (9)  Including 2.6 GW of capacity of Interpower, which was divested in January 2003.
(10)  Including 12.2 TWh generated by Elettrogen and Valgen before they were divested during 2001, and 20.9 TWh generated by Eurogen, which was divested in May 2002.
 
(11)  Including 8.0 TWh generated by Eurogen before it was divested, and 5.7 TWh generated by Interpower.
 
(12)  Excluding sales to resellers.
 
(13)  Including electricity distributed to resellers.
Exchange Rates
      The following table shows, for the periods indicated, information concerning the exchange rate between the U.S. dollar and the euro. These rates are provided solely for your convenience. We do not represent that the euro could be converted into U.S. dollars at these rates or at any other rate.
      The column of averages in the table below shows the averages of the relevant exchange rates on the last business day of each month during the relevant period. The high and low columns show the highest and lowest exchange rates on any business day during the relevant period.
                                 
    End of            
    Period   Average   High   Low
                 
    U.S. dollars per euro(1)
Year:
                               
2001
    0.8901       0.8909       0.9535       0.8370  
2002
    1.0485       0.9495       1.0485       0.8594  
2003
    1.2597       1.1411       1.2597       1.0361  
2004
    1.3538       1.2478       1.3625       1.1801  
2005
    1.1842       1.24001       1.3476       1.6667  
Month ended:
                               
December 31, 2005
    1.1842       1.18609       1.2041       1.1699  
January 31, 2006
    1.2158       1.21255       1.2287       1.1980  
February 28, 2006
    1.1925       1.19397       1.2100       1.1860  
March 31, 2006
    1.2139       1.20284       1.2197       1.1886  
April 30, 2006
    1.2624       1.29192       1.2624       1.2091  
May 31, 2006
    1.2833       1.27674       1.2888       1.2606  
 
(1)  Based on the Noon Buying Rate for the euro for the periods indicated.
      Enel’s ordinary shares are quoted in euros on Mercato Telematico Azionario (“Telematico”), the Italian automated screen-based trading market managed by Borsa Italiana S.p.A. (“Borsa Italiana”). Enel’s American Depositary Shares (“ADSs”) are quoted in U.S. dollars and traded on the New York Stock Exchange (“NYSE”).

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Risk Factors
      You should carefully consider the risks described below and all of the other information in this document. If any of the risks described below actually occurs, our business, economic and financial results and the trading price of Enel’s ordinary shares or ADSs could be materially adversely affected.
Risks Relating to our Energy Business
Future regulation could have a significant adverse effect on our energy businesses and their profitability
      Future laws and regulations issued by the European Union or the Italian national and local authorities, in particular the decisions and policies of the Energy Authority, may require significant changes in our business or otherwise affect our business in ways that we cannot predict. Any new regulations that cause us to restructure or otherwise change our business or significantly change the conditions under which we operate may have a material adverse effect on our business prospects, financial condition and results of operations. You should read “Item 4. Information on the Company — Regulatory Matters” for a discussion of these regulatory matters.
Regulatory changes promoting market liberalization have significantly increased competition in our energy businesses
      The Italian energy markets have been the object of numerous regulatory initiatives designed to foster liberalization. The most significant effects of these initiatives on the Italian electricity market have been (i) a reduction in our generating capacity (through the mandatory disposal of three generating companies, the Gencos; (ii) the introduction of limits on the amount of energy we may produce and import; (iii) the introduction on April 1, 2004, of the Italian power exchange, where prices are determined by competitive bidding; (iv) the required disposal of certain of our municipal networks to local utilities; and (v) mandated increases in the number of consumers who are eligible to buy electricity on the free market (with all non-residential customers having become eligible as of July 1, 2004, and all customers scheduled to become eligible as of July 1, 2007).
      In the generation business, our competitors include independent power producers, municipal utilities and other operators of electricity generating capacity, including Italian and international power companies. In addition to the April 2004 introduction of the Italian power exchange, we expect that competition will increase further due to:
  •  An increase in bilateral contracts between our competitors and final customers;
 
  •  The construction of new generation facilities by our competitors and the development of new interconnection lines that will increase the volume of electricity that may be imported in Italy; and
 
  •  Possible initiatives taken by the Energy Authority to further competition such as the imposition of virtual power plant contracts and of restrictions on the operation of pumping plants.
      Please see “Item 4. Information on the Company — Business — The Enel Group — Competition in the Electricity and Gas Markets.”
      In the sale of electricity, based on data from Terna and from GRTN (for the years before 2005), we estimate that our market share in Italy has decreased from 92% in 1999 to approximately 50% in 2005; our market share could decline further in coming years as liberalization progresses. In sales of electricity on the free market, we face competition both from other electricity producers as well as from wholesalers that resell the electricity they purchase.
      Our ability to expand our business and increase operating profits may be limited unless we are able to offset the decrease in generation and sales volumes of our electricity business through improved efficiency, increased sales in other areas of our business or international expansion.
      Our gas operations also expose us to risks relating to market regulation. Italian regulations enacted in May 2000 have sought to introduce competition gradually into the Italian natural gas market. In particular, these regulations have eased entry into some activities, including the import, export and sale of gas. From January 1,

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2003, gas sales were supposed to be completely liberalized, with all customers eligible to choose their supplier and sellers able to freely determine prices. However, the Energy Authority has retained the right to control prices, mainly for residential customers. We cannot predict whether or when these regulations will result in a fully liberalized market, or how the natural gas market will develop under these conditions.
      Our strategy is to seek both to be the cost leader in the generation of electricity and in the distribution and sale of electricity and gas in Italy and to provide high quality customer service. If we are unable to implement this strategy, or are otherwise unable to adapt our core energy businesses to meet these regulatory challenges, it may have a material adverse effect on our business prospects, financial condition and results of operations.
      For a more complete description of the regulation of the Italian energy industry and the way we expect regulatory matters to affect the electricity and gas markets, you should read “Item 4. Information on the Company — Regulatory Matters.”
Our facilities are subject to operating risks outside of our control; certain of our activities depend on third-party patents and licenses
      Our generation plants, as well as our distribution networks, are constantly exposed to risks related to their malfunction and other interruptions in service resulting from events outside of our control. These events may result in increased costs and other losses. Although we have acquired insurance coverage for events of this nature in line with general market practice, our coverage may prove insufficient to fully compensate us for any increased costs or losses that may occur as a result of service interruptions or malfunctions, with a consequent adverse effect on our business prospects, financial condition and results of operations. You should also read “— We face legal proceedings and potential regulatory measures arising from the 2003 power outage that affected all of Italy that could have a material adverse effect on our financial condition and results of operations. Further power outages involving our electricity operations could also adversely affect our financial condition and results of operations,” below.
      In addition, our “Telemanagement” digital electricity meter project is dependent on certain communications components and technology that are based on patents and licenses held by third parties and may require certain additional related services by third parties, such as maintenance. Please see “Item 4. Information on the Company — Business — The Enel Group — Sales, Infrastructure and Networks — Domestic Distribution and Sales Operations — Telemanagement System” for a description of this project. Interruptions in the availability of these components and technology or of the necessary related services provided by such third parties may be outside of our control, and could have a material adverse effect on our financial condition and results of operations.
We may not be able to complete our power plant conversion and other capital investment programs on schedule or realize the expected benefits of these programs
      In line with our strategy to reduce generation operating costs, we are implementing a program to convert several of our thermal generation plants to adopt more efficient technology or use cheaper fuels, such as coal. We cannot predict whether we will be able to complete our conversion program in accordance with the schedule we have set or in the manner currently contemplated, nor whether we will be able to realize the anticipated benefits of this program. Any such failure could have a material adverse effect on our business prospects, financial condition and results of operations.
      In addition, there is public opposition to our construction plans and conversion of power plants in certain municipalities, and we cannot exclude the possibility that in the future, such opposition may have a material adverse effect on our development plans, and, as a result, on our business.
Significant increases in fuel prices or disruptions in our fuel supplies could have a negative effect on our business
      Our thermal generation plants use fuel oil, natural gas and coal to generate electricity. Increases in energy prices therefore have a direct effect on our operating costs. Both the cost and availability of fuel are subject to

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many economic and political factors and events occurring throughout the world, particularly those that affect fuel-producing regions. Although we attempt to manage our risk through the use of financial instruments hedging our exposure to fluctuations in the price of fuel, we can neither control nor accurately predict these factors and events.
      Given our conversion of significant generation capacity to combined-cycle technology, we expect natural gas to constitute a significant portion of our fuel consumption in the future. In 2005, approximately 46% of the electricity we produced at our thermal plants was generated by plants using natural gas. We currently obtain a significant portion of the natural gas we use directly from Algeria and Nigeria through pipelines and by sea. Imports of natural gas from these countries may be subject to disruption due to a number of things, including maintenance works on the pipelines and bad weather conditions at sea. Any major disruption of this imported supply, as well as the emergency measures that the Ministry of Productive Activities or other Italian authorities may take in the event of such disruption, could adversely affect our ability to generate electricity using natural gas.
      If in the future there are significant or unexpected changes in the price of the fuels we use to generate electricity or if adequate supplies of fuel become unavailable, our financial condition and results of operations could be materially adversely affected.
Our expansion outside of Italy subjects us to risks associated with local market conditions, as well as to risks associated with operating the businesses we acquire
      In recent years, we have expanded our operations outside Italy. Our operations abroad now include, among others, generation plants in Spain, Bulgaria, Slovakia and North, Central and South America, distribution networks and sales operations in Spain and distribution networks and sales operations in Romania. In 2004, we also established a joint venture to manage a generation plant in Russia, in 2005 we entered into a non-binding memorandum of understanding with French state-owned electricity company Electricité de France S.A. (“EDF”) regarding an industrial partnership that, among other things, provides for our acquisition of a 12.5% stake in EDF’s EPR nuclear power plant project.
      We expect this international expansion to continue. In particular, we have made binding offers to acquire interests in additional electricity generation companies in Panama and Slovakia and in June 2006 we (i) won the auction for a 67.5% interest in Electrica Muntenia Sud, a Romanian electricity distribution company, (ii) entered into an agreement with Grupo Rede for the acquisiton of 11 companies, which own concessions to operate hydroelectric plants in Brazil with an aggregate installed capacity of 98 MW, and (iii) acquired from the ESN Group a 49.5% interest in Res Holding, a Dutch company holding 100% of the Russian power supplier company RusEnergoSbyt. Please see “Item 4. Information on the Company — Business — The Enel Group — Generation and Energy Management — International Generation.” and “Item 4. Information on the Company — Business — The Enel Group — Sales, Infrastructure and Networks-International Distribution and Sales Operations.” We will continue to evaluate opportunities outside Italy in the generation, distribution and sale of electricity businesses in both the countries where we currently operate and new markets.
      This international expansion requires us to become familiar with new markets and competitors in order to manage and operate these businesses effectively, and exposes us to local economic, regulatory and political risks. The process of integrating acquired operations, personnel and information systems can also be difficult and could absorb management time and resources and distract management from other opportunities or problems in our business and industry. In addition, some of the companies we have acquired may require significant capital investments.
      Operating internationally may also subject us to risks related to currency exchange rate fluctuations, foreign investment restrictions or restrictions on remittances by local subsidiaries. Depending on the circumstances, unfavorable developments in or affecting our operations outside Italy could adversely affect our business prospects, financial condition and results of operations.
      In addition, in April 2006 we purchased 66% of Slovenske Elektrarne (“SE”), which currently has four nuclear power generating units with an aggregate net installed capacity of 2,398 MW and two nuclear units under construction.

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      Prior to the closing of our purchase of SE, certain conditions were fulfilled, including the approval by the Slovakian government of the strategic investment plan we prepared for SE for the 2006-2013 period and the transfer to state-owned companies of the assets and liabilities of a nuclear power plant that is in the process of being decommissioned, including spent nuclear fuel and the radioactive waste produced by their operations, and the disposal of a water plant, as well as the approval by the Slovakian government of legislative provisions for a new fund for the decommissioning of nuclear installations in Slovakia and new rules governing the Slovakian electricity market. Although we believe that all of SE’s existing nuclear plants use internationally accepted technologies and are managed in accordance with Western European standards, our acquisition of the majority participation in SE’s share capital exposes us to the risks of ownership and operation of nuclear generating facilities, including the disposal and storage of radioactive materials and spent fuel, as well as of the potential harmful effects on the environment and human health. In addition, while the Republic of Slovakia and SE have ratified the Vienna Convention, potential limits may arise on the amount and types of insurance commercially available to cover the risks associated with these operations. Potential risks may also arise in connection with the decommissioning of these nuclear plants, particularly as the regulatory regime for nuclear power and nuclear decommissioning in Slovakia is currently in the process of being defined. We have not owned any nuclear power plants since November 2000, and we have not produced electricity from nuclear power plants since 1988.
      Consistent with our strategy of international expansion, we may make acquisitions of targets of very significant size. Without making any commitments, certain banks have expressed an intention to provide us with the financing necessary for such acquisitions. Should we incur significant external debt to finance any of these acquisitions, we would likely be required to make certain undertakings to the relevant banks (as customary for financings of this size and type), which could require us to get the consent of these banks in order to be able to take specified types of action. In addition, should we make any such large acquisition, we will have to manage the significant challenges inherent in our integration of the target’s business and we cannot predict whether and to what extent any such acquisition would be successful.
We face legal proceedings and potential regulatory measures arising from the 2003 power outage that affected all of Italy that could have a material adverse effect on our financial condition and results of operations. Further power outages involving our electricity operations could also adversely affect our financial condition and results of operations
      On September 28, 2003, Italy suffered a complete blackout of electrical service that affected the entire country with the exception of the island of Sardinia. After the blackout, approximately 21 hours were necessary before electricity again became available to all customers.
      The Energy Authority in September 2004 initiated a formal proceeding to determine whether certain companies, including our subsidiaries Enel Produzione S.p.A. (“Enel Produzione”), Enel Distribuzione S.p.A. (“Enel Distribuzione”), Terna and Deval S.p.A. (“Deval”), may have been partially responsible for the blackout. In 2005, we settled the proceeding against Enel Produzione through the payment of 50,000. Although no further fines may be imposed on Enel Produzione in connection with this proceeding, the Energy Authority may still impose measures to improve reliability of our energy supply, which may have an adverse impact on our results of operations. The proceedings remain pending against our subsidiaries Enel Distribuzione and Deval, and a decision is expected by October 31, 2006. If the Energy Authority finds that these companies have been partially responsible for the blackout, it may impose sanctions or request undertakings from them.
      Furthermore, certain of our customers brought legal actions against us in the Italian courts seeking damages as a result of this blackout. Although the claims made by these plaintiffs are for minor amounts, an increase in the number of decisions finding us liable for such damages could result in an increase in the number of such claims filed and the magnitude of the damages sought. For more information on the civil and administrative proceedings related to the blackout, please read “Item 8. Financial Information — Other Financial Information — Legal Proceedings — Blackout litigation.”
      While we do not believe we were responsible for the blackout, we cannot exclude the possibility that we will be held liable for it by Italian courts and/or the Energy Authority. Any finding of liability on our part could result

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in the imposition of fines and other administrative sanctions and in additional lawsuits by other parties against us, which could have a material adverse effect on our financial condition and results of operations.
      Although the blackout has not yet had a material impact on our operations or financial results, we cannot provide any assurance that further power outages or disruptions involving our operations will not occur in the future, or that any such outages or disruptions would not have a material adverse effect on our financial condition and results of operations. In May 2005, the Energy Authority issued proposals for public comment (through June 30, 2005) for the institution of a system of automatic compensation payable by electricity distributors to affected customers in the event of a blackout or other prolonged service interruption. For a description of this proposal, please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation — Continuity and Quality of Service Regulation.” The adoption of this system would augment the economic risks we face in the event of any such interruption in service.
We have been and are subject to regulatory investigations, including for possible abuse of dominant position and market abuse
      We have been and are likely to continue to be subject to regulatory and antitrust investigations in the Italian electricity market. We are currently subject to an Antitrust Authority investigation with respect to certain sharp increases in the price of electricity on the Italian power exchange in June 2004 and in January 2005. In April 2005, the Antitrust Authority opened proceedings against Enel and Enel Produzione after the Energy Authority officially concluded that these increases may have been associated with violations of antitrust law by us. For more information, please see “Item 8. Financial Information — Other Financial Information — Legal Proceedings.” If the Antitrust Authority were to hold us liable for the abusive practices alleged, it could impose a fine on us of up to 10% of our total revenues in the preceding fiscal year.
      Moreover, our subsidiary Enel Viesgo Generaciòn is currently subject to antitrust investigations in Spain for alleged abuse of dominant position. For more information please see “Item 8. Financial Information — Other Financial Information — Legal Proceedings.”
      While we do not believe we have committed any violation of antitrust laws, we cannot exclude the possibility that we will be held liable in the current investigations by the antitrust authorities in Italy or in Spain, nor that there will be other such investigations by the Energy Authority, the Antitrust Authority or other regulatory bodies in Italy or abroad in the future. Should we be held liable in the current or any future investigations, and should such liability result in the imposition of significant fines or of material restrictions on our activity, there could be a material adverse effect on our financial condition and results of operations.
The European Commission has launched an investigation into the functioning of the European energy market that could lead to measures which could have a material adverse effect on our operations
      In June 2005, the European Commission launched an investigation into the functioning of the European energy market. The overall objective of the inquiry is to investigate the barriers to the development of a fully functioning open and competitive EU-wide energy market. In its preliminary report issued in February 2006, the European Commission identified market concentration, vertical foreclosure, lack of market integration, lack of transparency and price formation as the five main barriers to a fully functioning EU-wide energy market. The European Commission is expected to publish its final report at the end of 2006. Although we cannot at this stage predict what actions the European Commission may take as a result, we cannot foreclose the possibility that the report will lead to the adoption of measures that could adversely affect our operations.
The European Commission may decide that priority access rights of long-term supply contracts are contrary to EU law
      In 2005, we controlled approximately 2,000 MW of the total capacity for electricity imports into Italy pursuant to two long-term supply contracts. Since April 1, 2004, the date on which the Italian power exchange started operations, we sell the electricity imported pursuant to these contracts to the Single Buyer at terms set by an Italian ministerial decree.

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      Until December 31, 2005, these long-term supply contracts enjoyed priority access to interconnection capacity for 2000 MW. However, in 2006, the French regulatory authority has decided not to assign any reserved capacity for our import of electricity under the terms of the long-term contract we entered into with the French electricity company EDF. As a consequence, only part of the electricity bought under this contract has been imported into Italy, with the remaining part being sold in France. We have appealed the decision of the French regulatory authority. Moreover, in April 2006 the European Commission has started proceedings against several Member States, including Italy, for failure to enact EU legislation. The proceedings also challenge priority access for long-term supply contracts. If the European Commission concludes that such rights are contrary to EU law, our ability to import electricity under these contracts will be impaired and we will probably be forced to pay congestion charges or to sell the electricity under this contract abroad. We believe, however, that the impact of this measure or any other measure adopted further to a decision by the European Commission that priority access rights are contrary to EU law would be in any event limited, as the contract with EDF expires in 2007 and the revenues derived from the other contract (which expires in 2011) are not material.
A European Commission challenge to Italian regulations on hydroelectric concessions could adversely affect our business, financial condition and result of operations
      We operate our hydroelectric plants pursuant to concessions granted and regulated by national and local authorities. These hydroelectric plants accounted for approximately 34% of our net installed capacity in 2005 (with 4.7% of our net installed capacity attributable to those in the Region of Trentino-Alto Adige).
      In January 2004, the European Commission determined that certain Italian regulations regarding hydroelectric concessions were contrary to EU law. In particular, the European Commission objected to renewal preferences granted to existing holders of concessions (and in the region of Trentino-Alto Adige, to the operator controlled by the local authorities) upon the expiry of those concessions, as well as to the fact that the regulations provided for the expiration of all concessions in 2029 (and for the region of Trentino-Alto Adige, in 2010), even though these concessions had previously been of perpetual duration.
      In December 2005, Italy amended the relevant regulations, abrogating the renewal preferences and postponing the expiration of all concessions for an additional 10 years. However, if the European Commission continues to pursue its formal action before the Court of Justice to enforce its request and the Court of Justice affirms the European Commission’s opinion, our hydroelectric concessions may be terminated prematurely and we may not be able to renew these concessions at all or on favorable terms. This could have a material adverse effect on our business prospects, financial condition and results of operations. The European Commission decision on whether to continue its formal action is expected in the second half of 2006.
We are dependent on government concessions for our electricity and gas distribution businesses
      Recent laws have modified the expiration date for gas distribution concessions. In 2000, a decree of the Ministry of Productive Activities set the expiration date of gas distribution concessions awarded prior to May 2000 by means other than competitive tender at the earlier of their original expiration date or December 31, 2005, with the expiration date extendible for up to five years under certain conditions. The Marzano Law, as interpreted by the Ministry of Productive Activities in November 2004, provided instead that these concessions are to expire at the earlier of their original expiration date or December 31, 2007, with the expiration date still extendible for up to five years under certain conditions. The Italian administrative courts, however, disagreed with the Ministry’s interpretation. As a result, on February 23, 2006, a law confirmed that gas distribution concessions expire by law at the earlier of their original expiration date or December 31, 2007, and extended the expiration date to December 31, 2009 under certain conditions. Local authorities may extend this date by one additional year. Furthermore, certain gas distribution concessions for southern Italy, partially financed through public funds made available in the context of a public incentive plan for the use of natural gas in southern Italy, expire at the later of June 21, 2012 or twelve years from the entry into force of their approval by the Ministry of Economy and Finance. Finally, gas distribution concessions awarded prior to May 2000 by competitive tenders expire at the earlier of their original expiration date or December 31, 2012. Please see “Item 4. Information on the Company — Regulatory Matters — Gas Regulation” for more details on gas distribution concessions. The majority of our existing gas distribution concessions are currently due to expire on December 31, 2009. If the

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expiration date of our gas and electricity distribution concessions is accelerated, or if we are unable to renew these concessions upon their expiration, our financial condition and results of operations could be materially adversely affected.
      In November 2004, the Italian Region of Tuscany challenged the Marzano Law before the Italian Constitutional Court regarding the allocation of powers between the Italian State and the regional governments with respect to regulation of electricity and gas distribution. With a ruling as of October 11, 2005, however, the Italian Constitutional Court rejected Tuscany’s contention that regulation of electricity and gas distribution fell within the jurisdiction of regional governments. Furthermore, the Italian Regions of Tuscany and Emilia-Romagna introduced regional regulations of the energy sector, which were challenged by the Italian government before the Constitutional Court. Depending on the outcome of this case, we cannot rule out the possibility that in the future electricity and gas distribution activities might be required to comply with diverging national and regional regulations.
      While the effect of such diverging regulations on our operations is difficult at this point to predict, it is possible that it would have a material adverse effect on our financial condition and results of operations, as it would likely increase our regulatory compliance costs and create regulatory uncertainty.
Our businesses are subject to numerous environmental regulations, and we are parties to a significant number of legal proceedings relating to environmental matters, that could significantly affect our financial condition and results of operations
      Our businesses are subject to extensive environmental regulation under Italian law, including laws adopted to implement European Union regulations and directives and international agreements on the environment. Environmental regulations affecting our business primarily relate to air emissions, water pollution, waste disposal and electromagnetic fields. The principal air emissions deriving from thermal electricity generation are sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) and particulate matter such as dust and ash.
      We incur significant costs to comply with environmental regulations requiring us to implement preventive or remedial measures. Environmental regulations may also influence our business decisions and strategy, such as by discouraging the use of certain fuels. In addition, expressions of public concern about environmental problems associated with electricity generating plants, power lines and other facilities may result in even more stringent regulation in the future, which could further increase costs.
      In 2005, we spent a total of 450 million on measures intended to reduce the impact of our operations on the environment, including measures to comply with applicable law. Of this aggregate amount, 350 million was accounted for as current expenditures and 100 million as capital expenditures. Major capital expenditures included projects to reduce SO2 and NOx emissions by our power plants and to install underground cables in our distribution network.
      In addition, we are parties to a significant number of legal proceedings relating to environmental matters. The aggregate amount of damages that we may be required to pay and the aggregate costs of remediation or preventive measures we may be required to implement in connection with these proceedings may be significant.
      The adoption of any additional or more rigorous environmental rules applicable to our businesses would be likely to increase our costs and could have a negative effect on our financial condition and results of operations. Please see “Item 4. Information on the Company — Regulatory Matters — Environmental Matters” and “Item 8. Financial Information — Other Financial Information — Legal Proceedings” for a more detailed discussion of environmental matters.

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Other Risks Relating to Our Businesses
We may be unable to exit the telecommunications business on acceptable terms or in accordance with the currently envisaged timetable, which would have an adverse effect on our management’s current business plan
      In line with our strategy of focusing on our core energy operations and exiting the telecommunications business, we sold Wind to Weather Investments in a series of transactions, the last one of which was completed in February 2006. As a result of these transactions, we no longer have direct interest in Wind and we received aggregate cash consideration of 3,009 million and a 26.1% interest in Weather Investments. Weather Investments is a private consortium headed by Naguib Sawiris, who controls Orascom, an Egypt-based mobile phone operator that provides telecommunications services in the Middle East, Africa and Pakistan, is listed on the London Stock Exchange and the Cairo and Alexandria Stock Exchange and holds a minority stake in Hutchinson Telecommunications International.
      In addition, we entered into a shareholders’ agreement with Weather Investments II S.a.r.l., the majority shareholder of Weather Investments, which contemplates an initial public offering of Weather Investments, when market conditions are favorable, and provides for both our and Weather Investments II S.a.r.l.’s undertakings, subject to certain exceptions, not to sell our interests in Weather Investments before the initial public offering. We can give no assurance that we will be able to complete an offering of Weather Investments’ shares or otherwise dispose of all or any part of our interest in Weather Investments on favorable terms or in accordance with our envisaged timetable and business strategy, if at all.
Our historical consolidated financial and operating results may not be indicative of future performance
      In 2005, we discontinued the operations of our former Telecommunications Division and Transmission Division, following the deconsolidation of Wind and Terna, respectively, as a result of our disposal of a controlling interest in each of these companies. We intend to use the proceeds from these sales primarily to finance our international expansion outside of Italy through acquisitions. However, should we fail to identify assets that meet the criteria set forth in our investment strategy by the end of 2007, we may use part of the available financial resources to buy back Enel shares in the market.
      Moreover, during 2005 and 2006 we also made significant acquisitions, most notably of SE, as well as entering into agreements to make other significant acquisitions. Please see “Item 4. Information on the Company — History and Development of the Company” for additional information on these transactions.
      We may continue to divest assets as a part of our ongoing efforts to refocus our activities on our core electricity and gas businesses, and to acquire new businesses as part of our international expansion. As a result, our historical consolidated financial and operational performance during or as of the end of periods ending on or prior to the consummation of these transactions may not be indicative of our future operating and financial performance.
The Italian social security fund is seeking to impose significant liabilities on us
      On May 6, 2005, INPS, the Italian social security fund, issued a circular purporting to extend an obligation for employers to make certain social security contributions to formerly state-owned companies and national public entities carrying out industrial activities. Although state-owned companies were exempted from this obligation, INPS indicated in its circular that this obligation would be applied to privatized companies with retroactive effect as of the date of privatization of the relevant entity. As we believe that this circular should not apply to us, we challenged it before the Tribunal of Rome. In March 2006, the Council of State, upon INPS’ request, expressed the opinion that INPS may not impose retroactive obligations. Though this opinion supports our position, it is not binding on the Tribunal of Rome and we cannot exclude that this court will state that the INPS circular apply to us, whether for the period after its issuance or also retroactively. In such cases, we estimate that the amounts we would be required to pay would total to approximately 80 million per year.

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Legislation enacted in 2005 could increase our local property tax burden
      On May 31, 2005, the Italian parliament passed a law to aid local governments that included, among other things, provisions regarding the determination of the deemed value of electricity generation facilities for purposes of assessing, among others, local property taxes. Under this law, owners of electric utilities are required to include in the computation of the taxable value of their facilities not only land and buildings, but also the value of removable parts of the facilities, such as generation equipment.
      Should these provisions be applied to all of the electricity generation facilities that we own and the pending and prospective litigation regarding the assessment of their deemed value be unsuccessful, we expect that our local property tax (the imposta comunale sugli immobili, or ICI) burden would increase by approximately 80 million per year.
      In addition, a recent interpretation of these provisions by the Italian Supreme Court, in a case relating to one of our facilities, may lead local authorities to claim that they apply retroactively, starting from the fiscal year 2003. We believe that these claims would be illegitimate and we would challenge them before the competent court. However, should these claims be successful, we estimate that our ICI liability would increase by approximately up to 40 million for each litigated tax period starting from 2003.
We are defendants in a number of legal proceedings
      We are defendants in a number of legal proceedings incidental to the generation and distribution of electricity and our other business activities. Our pending legal proceedings include various civil and administrative claims and disputes relating to the construction and operation of several power stations, transport and distribution lines, and other matters that arise in the normal course of our business. We have established a reserve for litigation and other contingent liabilities where we consider it probable that a claim will be resolved unfavorably and where we can reasonably estimate the potential loss involved. This reserve, which also includes provisions for other contingencies and uncertainties related to our operations, is included in other non-current liabilities in our consolidated balance sheet, and amounted to 1,146 million at December 31, 2005, of which 341 million related to legal proceedings. Please see “Item 8. Financial Information — Other Financial Information — Legal Proceedings.”
      However, we are not able to predict the ultimate outcome of any of the claims against us, and any material damages or other costs imposed on us in the event of an unfavorable outcome may be in excess of our existing reserves. We cannot exclude that unfavorable decisions in proceedings against us could have a material adverse effect on our financial position or results of operations.
Risks Relating to Enel’s Ordinary Shares and ADSs
The MEF, Enel’s controlling shareholder, has significant influence over Enel’s actions
      The MEF currently directly owns 21.4% of Enel’s outstanding share capital and controls Cassa Depositi e Prestiti S.p.A. (“Cassa Depositi e Prestiti”), which owns 10.2% of Enel’s outstanding share capital. Therefore, the MEF has de facto control of Enel. As long as the MEF retains control of Enel for purposes of applicable Italian law on controlled companies (which is determined based on having a majority of the vote at ordinary shareholders’ meetings or otherwise exercising a dominant influence over another company), the MEF will be able to exercise significant control over all matters to be voted on by Enel’s shareholders, including, without limitation, the election and removal of directors and possible capital increases or amendments to Enel’s by-laws. As a result, other shareholders’ ability to influence decisions on matters submitted to a vote of Enel’s shareholders may be limited.
The special powers of the Italian government may permit it to influence Enel’s business, regardless of the level of its shareholding
      The Italian privatization law (as amended) and Enel’s by-laws confer upon the Italian government, acting through the MEF (which acts after consultations with and in agreement with the Ministry of Productive

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Activities), certain special powers with respect to Enel’s business and actions by its shareholders. These powers, which the MEF confirmed with a decree issued on September 17, 2004, may permit the government to influence Enel’s business, regardless of the level of its shareholding.
      In particular, the MEF has the following special powers:
  •  The power to oppose the acquisition by persons or entities of an interest in the Company equal to or in excess of 3% of the shares with voting rights at the ordinary shareholders’ meetings;
 
  •  The power to oppose certain types of shareholders’ agreements entered into by holders of at least one-twentieth of the voting capital stock at ordinary shareholders’ meetings;
 
  •  The power to veto any resolution to dissolve, merge or demerge Enel, transfer a significant part of Enel’s business or Enel’s registered headquarters outside of Italy, change Enel’s corporate purpose or eliminate or modify any of the MEF’s special powers; and
 
  •  The power to directly appoint one non-voting member of Enel’s board of directors, in addition to the voting members elected by Enel’s shareholders.
      The MEF may exercise these powers only for due cause when it believes that a concrete detriment to vital national interests would otherwise result.
      The special powers retained by the MEF are described in further detail under “Item 7. Major Shareholders and Related Party Transactions — Major Shareholders” and “Item 10. Additional Information — By-Laws.” As a result of these powers, Enel may not enter into change of control transactions without the approval of the MEF, in agreement with the Ministry of Productive Activities. This may limit the ability of Enel’s shareholders to benefit from a premium in connection with a change of control transaction.
The value of ordinary shares or ADSs may be adversely affected by sales of substantial amounts of shares by the MEF or other shareholders or the perception that such sales could occur
      The MEF and/or Cassa Depositi e Prestiti may sell Enel’s ordinary shares at any time. In October 2004, the MEF sold an additional interest of approximately 19% in an offering consisting of a public offering in Italy and a private placement to international institutional investors that was not registered under the Securities Act. In July 2005, the MEF sold a further interest of 9.3% in the Company in a similar offering. There are no minimum ownership or similar requirements under Italian law that would limit sales of additional shares by the MEF or Cassa Depositi e Prestiti.
      Sales of substantial amounts of ordinary shares by the MEF or other shareholders, or the perception that such sales could occur, could adversely affect the market price of Enel’s ordinary shares and American Depositary Shares, or ADSs, and could limit Enel’s ability to raise capital through equity offerings.
The value, expressed in dollars, of the ordinary shares and ADSs and of any dividends Enel pays in respect of its ordinary shares and ADSs will be affected by the euro/dollar exchange rate
      Enel pays cash dividends in euros; as a result, exchange rate movements may affect the amounts, expressed in U.S. dollars, that investors receive from JP Morgan Chase Bank, the depositary for Enel’s ADR program (“JP Morgan” or the “Depositary”), in respect of such dividends if they hold ADSs. Moreover, the price of Enel’s ordinary shares is quoted in euros. Therefore, exchange rate movements may also affect the U.S. dollar price of the ADSs corresponding to Enel’s ordinary share price.
It is possible that the price of ordinary shares and ADSs will experience significant volatility
      The market price of Enel’s ordinary shares and ADSs may be significantly affected by factors such as variations in our results of operations, market conditions specific to our industry and changes in regulations applicable to us. In addition, stock markets can experience significant fluctuations that may be unrelated to the performance or circumstances of the specific companies whose shares are affected. Market fluctuations, as well as economic conditions, may adversely affect the market price of the ordinary shares and ADSs.

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If you hold ADSs rather than ordinary shares it may be difficult for you to exercise some of your rights as a shareholder
      It may be more difficult for you to exercise your rights as a shareholder if you hold ADSs than it would be if you directly held ordinary shares. For example, if Enel offers new shares and you have the right to subscribe for a portion of them, the Depositary is allowed, in its own discretion, to sell for your benefit that right to subscribe for new shares instead of making it available to you. Furthermore, in some cases, you may not be able to vote by giving instructions to the Depositary on how to vote for you.
Forward-Looking Statements
      This annual report includes forward-looking statements. When used in this annual report, the words “seek(s),” “intend(s),” “estimate(s)”, “plan(s)”, “project(s),” “aim(s),” “expect(s),” “will,” “may,” “believe(s),” “should,” “anticipate(s)” and similar expressions are intended to identify forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements regard, among other things:
  •  Anticipated trends in our businesses, including trends in demand for electricity;
 
  •  Changes in the regulatory environment and expectations on how and when new regulations will be implemented;
 
  •  The remuneration of our generation activities based on competitive electricity prices rather than tariffs following the introduction of trading on the Italian power exchange;
 
  •  The impact of changes in electricity and gas tariffs;
 
  •  Our ability to implement our cost reduction program successfully;
 
  •  The possibility that significant volumes of lower-cost electricity will become available as a result of increased imports and the construction of new plants in Italy;
 
  •  Our intention to divest our interest in Weather Investment;
 
  •  Our intentions with respect to future dividend payments;
 
  •  Our intention to expand our core businesses, including by increasing our presence in renewable energy and developing our gas distribution and sales business;
 
  •  Our intention to expand our operations outside Italy; and
 
  •  Future capital expenditures and investments.
      The forward-looking statements included in this annual report are subject to risks, uncertainties and assumptions about the Group. Our actual results of operations may differ materially from the forward-looking statements as a result of, among other things, the risk factors described under “— Risk Factors.” We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or events otherwise occurring after the date of this annual report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this annual report might not occur.

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ITEM 4. INFORMATION ON THE COMPANY
History and Development of the Company
      Enel was established in December 1962 as a state-owned entity (Ente Nazionale per l’Energia Elettrica) through the nationalization of approximately 1,250 private power companies in Italy. In 1992, Enel ceased to operate as a public entity and was transformed into a company limited by shares, Enel S.p.A.
      Until April 1, 1999, Italy’s electricity market was highly regulated. On that date, a new law, the Bersani Decree, came into force, beginning the transformation of the Italian electricity market into a liberalized market, in which energy prices charged by generators are freely determined. Beginning in October 1999, as required by the Bersani Decree, Enel formed separate subsidiary companies, to each of which Enel assigned the responsibility (and related assets, liabilities and personnel) for each of its significant businesses. As a part of this liberalization, Enel was also required to transfer responsibility for the management and control of the Italian national electricity transmission grid and responsibility for electricity dispatching to the GRTN, a company wholly owned by the MEF. In addition, as required by Italian legislation adopted as part of the liberalization of the electricity market, we have disposed of approximately 15,000 MW of our generating capacity through the sale of three generation companies and sold several municipal distribution companies.
      In November 1999, the MEF sold approximately 32% of Enel’s share capital in Enel’s initial public offering, in connection with which Enel’s ADSs were listed on the New York Stock Exchange and Enel’s shares were listed on the Telematico, the Italian screen-based trading market managed by Borsa Italiana. Following this sale, as part of the privatization and liberalization of the Italian electricity market, the MEF sold stakes in Enel of 6.6% in the context of a private placement transaction in November 2003 and approximately 10% to Cassa Depositi e Prestiti, a company now owned 70% by the MEF, in December 2003. In October 2004, the MEF sold an additional interest in Enel of approximately 19% in an offering consisting of a public offering in Italy and a private placement to international institutional investors that was not registered under the Securities Act. Finally, in July 2005, the MEF sold a further interest of 9.3% in the Company in a similar offering.
      Since 2000, we have expanded our operations in the gas sector through the acquisition of several independent gas distributors. Since 2000, we have also expanded our energy operations abroad, including through the purchase in 2002 of Electra de Viesgo S.L. (“Viesgo”), a company with electricity generation and distribution operations in Spain, and, in March 2003, of a controlling interest in Maritza East III Power Company AD (“Maritza East III”), a company with electricity generation operations in Bulgaria. We have also acquired power producers specializing in renewable resources in the Americas and have a 50% joint venture with Uniòn Fenosa Generaciòn S.A. in Spain called Enel Uniòn Fenosa Renovables S.A., or “EUFR”. In April 2006, we acquired a 66% interest in Slovenske Elektrarne (“SE”) for total consideration of approximately 840 million. SE, the principal electric power generation company in Slovakia, has a total gross installed capacity of approximately 7,000 MW. In June 2006 we (i) won the auction for a 67.5% stake in the Romanian power distribution company Electrica Muntenia Sud, a power distributor to more than 1.1 million customers in Bucharest, Romania, for total consideration of 820 million, (ii) acquired from the ESN Group a 49.5% interest in Res Holding, a Dutch company holding 100% of the Russian power supplier company RusEnergoSbyt with 11TWh of annual sales, for $105 million (corresponding to approximately 88 million), and (iii) entered into an agreement with Grupo Rede for the acquisiton of 11 companies that own concessions to operate hydroelectric plants in Brazil, with an aggregate installed capacity of 98 MW (closing of the transaction is subject to certain conditions, including the approval by the Brazilian electricity authority, and is expected in the second half of 2006).
      Until June 2004, we owned 100% of Terna, the principal Italian electricity transmission company, which currently owns more than 90% of the transmission assets of Italy’s national electricity grid. In light of Italian laws and regulations providing for the reunification of the ownership and management of the Italian transmission grid and imposing certain ownership restrictions on the entity that will own and manage it, in 2005 and in January 2006 we reduced our stake in Terna, the company through which we carried out our transmission activities, to

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5.12%. For more information please see “— Business — The Enel Group — Discontinued Operations-Transmission.”
      We have also invested in telecommunications, starting in 1997, when Enel, France Télécom and Deutsche Telekom together formed our former telecommunications subsidiary, Wind. Our initial stake in Wind was 51%, which increased to 73.4% following Deutsche Telekom’s exit from the joint venture in July 2000 and our contribution to Wind on July 30, 2001, of 100% of the capital stock of Infostrada, an Italian fixed-line telephone provider we purchased in 2001 from Vodafone Group plc. Infostrada was merged into Wind as of January 1, 2002. In July 2003, we acquired the 26.6% stake in Wind then held by Wireless Services Belgium SA, a subsidiary of France Télécom, becoming Wind’s sole shareholder.
      In line with our strategy of focusing on our core energy operations, in May 2005 we entered into an agreement for the sale of Wind to Weather Investments in a series of transactions. Weather Investments is a private consortium headed by Naguib Sawiris, who controls Orascom, an Egypt-based mobile phone operator that provides telecommunications services in the Middle East, Africa and Asia and is listed on the London Stock Exchange and the Cairo and Alexandria Stock Exchange. These transactions were completed in February 2006. As a result of these transactions, we received an aggregate cash consideration of 3,009 million and a 26.1% interest in Weather Investments.
      At the end of 2005, our management decided to re-organize the Group’s internal structure by substituting our Sales Infrastructure and Networks Division with two separate divisions (a Market Division and an Infrastructure and Networks Division) and by allocating our international generation and distribution operations, which had previously been included in other divisions, to a new International Division. This reorganization is effective as of January 1, and, therefore, our divisions are currently the following: Generation and Energy Management Division, Market Division, Infrastructure and Networks Division and the International Division. Each division is headed by a senior manager who reports directly to the Chief Executive Officer of Enel. Moreover, all non-core activities provided by companies of the Group to all Group companies have been grouped in our Services and Other Activities sector. Enel, as the parent company, defines the strategic objectives for the Enel Group and coordinates the activities of all Group companies. Each of Enel, our divisions and the Services and Other Activities sector constitutes a reportable segment.
      For additional information on our divisions and their activities, please see “— Business — The Enel Group” below. For a detailed discussion of our operational and financial results in the period 2004-2005, please see “Item 5. Operating and Financial Review and Prospects.” For a description of our capital expenditures in each of the last three fiscal years, please see “— Business — The Enel Group — Capital Investment Program.”
      Enel S.p.A. is a società per azioni, or a company whose capital is represented by shares, incorporated under the laws of Italy. Enel’s statuto, or by-laws, provide that the duration of the Company is until December 31, 2100. Enel’s registered office is at Viale Regina Margherita 137, Rome, Italy. Enel’s main telephone number is +39 06 83051. Individual investors may reach our retail investor team at telephone number +39 06 8305 2081, while institutional investors may reach our investor relations team at telephone number +39 06 8305 7008. Enel is represented in the United States by our subsidiary Enel North America Inc. (“Enel North America”), located at One Tech Drive, Suite 220, Andover, MA 01810.
Business
Overview
      We are the principal electricity operator in Italy, with the leading position in the generation, distribution and sale of electricity. Based on revenues, we were one of the largest industrial companies in Italy in 2005, with operating revenues of 34,059 million, or approximately $40,333 million. We earned net income in 2005 of 3,895 million, or approximately $4,612 million. We believe that, in terms of the volume of electricity sold in the year 2005, we were one of the largest electric utilities in Europe, and according to Bloomberg, as of May 31, 2006, we were also one of the largest publicly traded electric utilities in the world based on market capitalization.

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      The following table shows selected operating data for our electricity and natural gas operations in Italy for each of the past three years. Net production equals gross production of electricity less consumption by units generating electricity and mechanical and electrical losses in production.
                           
    2003   2004   2005
             
Net installed capacity (GW) in Italy at year end
    41.8       42.0       42.2  
Net electricity production in Italy (TWh)
    137.8       125.9       112.1  
Electricity sales to end users in Italy (TWh)(1)
    152.2       157.8       148.2  
 
Electricity sales on the regulated market in Italy (TWh)
    141.5       137.0       129.7  
 
Electricity sales on the free market in Italy (TWh)
    10.7       20.8       18.5  
Total electricity distributed in Italy (TWh)(2)
    265.0       261.2       259.3  
Natural gas sales to end users in Italy (billions of cubic meters)
    4.4       5.2       5.1  
Natural gas sales customers in Italy at year end (millions)
    1.8       2.0       2.1  
 
(1)  Excluding sales to resellers.
 
(2)  Including electricity distributed to resellers.
      In 2005, our operations were organized, reflecting our internal structure, into six business segments: Generation and Energy Management; Sales, Infrastructure and Networks; Transmission; Telecommunications; Services and Other Activities; and Corporate.
      At the end of 2005, our management decided to re-organize the Group’s internal structure by substituting our Sales, Infrastructure and Networks Division with two separate divisions (a Market Division and an Infrastructure and Networks Division) and by allocating our international generation and distribution operations, which had previously been included in other divisions, to a new International Division. Our divisions are currently the following: Generation and Energy Management Division, Market Division, Infrastructure and Networks Division and the International Division. Each division is headed by a senior manager who reports directly to the Chief Executive Officer of Enel. Moreover, all non-core activities provided by companies of the Group to all Group companies have been grouped in our Services and Other Activities sector. Enel, as the parent company, defines the strategic objectives for the Enel Group and coordinates the activities of all Group companies. Each of Enel, our divisions and the Services and Activities sector constitutes a reportable segment. However, our reorganization is effective as of January 1, 2006 and, therefore, the following description reflects the structure that we had in 2005 with our former Transmission and Telecommunications segments each being treated as discontinued operations following the deconsolidation of Terna and Wind.
      Generation and Energy Management. Our Generation and Energy Management Division is responsible for our operations related to the production of electricity and the procurement and trading of fuel for electricity generation, and until the end of 2005 also included our power generation activities in Italy and abroad. Effective as of January 1, 2006, its international operations were allocated to our new International Division.
      We are the largest producer of electricity in Italy. At December 31, 2005, we had net installed capacity in Italy of approximately 42.2 GW, which, based on data provided by Terna, we estimate to have been approximately 49% of total Italian net installed capacity at that date. Our net electricity production in Italy in 2005 was 112.1 TWh, and, based on data provided by Terna, we estimate that our production represented approximately 39% of Italian net production during 2005. Our net production declined by 10.9%, or 13.8 TWh, in 2005 as compared to 2004. As of December 31, 2005, we had 599 generating plants in Italy, consisting of thermal, hydroelectric, geothermal and other renewable resources facilities. In 2005, 73.0% of our net production was from thermal plants, 22.2% was from hydroelectric plants and the remaining 4.8% was from geothermal and other renewable resources plants. We do not own or operate any nuclear plants in Italy.

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      At December 31, 2005, we also had electricity generation plants outside Italy with aggregate net installed capacity of approximately 3.786 GW, including facilities in Spain, Bulgaria and North, Central and South America. In addition we manage a generation plant in Russia, and in April 2006 we acquired generation operations in Slovakia with our purchase of SE. Effective as of January 1, 2006 our international generation operations are carried out by our new International Division.
      In 2005, the Generation and Energy Management Division had revenues after intrasegment eliminations of 14,215 million, reflecting revenues prior to intrasegment eliminations of 13,376 million in Italy and 914 million abroad. This compares to revenues after intrasegment eliminations of 13,028 million in 2004, reflecting revenues prior to intrasegment eliminations of 12,446 million in Italy and 622 million abroad.
      Sales, Infrastructure and Networks. Until the end of 2005 our Sales, Infrastructure and Networks Division operated in both the electricity and gas markets through two sub-divisions — a sales sub-division and an infrastructure and networks sub-division — responsible respectively for sales of products and services and for management of our distribution network. Effective as of January 1, 2006, these two sub-divisions became two independent divisions, the Market Division and Infrastructure and Networks Division, that replaced the Sales, Infrastructure and Networks Division. In addition, effective on the same date, international operations previously carried out by the Sales, Infrastructure and Networks Division were allocated to our new International Division.
      We are the largest electricity distributor in Italy, distributing a total of 259.3 TWh of electricity in 2005. At December 31, 2005, our Italian distribution network consisted of a total of 1,090,129 kilometer of lines, mostly medium and low voltage, and 413,429 primary and secondary transformer substations, with a total transformer capacity of 157,037 MVA.
      We are also the largest supplier of electricity in Italy. The market for electricity sales in Italy is divided into a regulated market and a free market. Customers in the regulated market must purchase electricity from their local distributor; customers in the free market may choose from whom to purchase their electricity. In 2005, we sold electricity to approximately 23.4 million residential customers, which we estimate were 86.7% of all residential customers in Italy. In 2005, we distributed and sold approximately 129.7 TWh of electricity on the regulated market, and distributed approximately 121.4 TWh of electricity and sold approximately 18.5 TWh of electricity on the free market (including sales to final customers by Enel Trade S.p.A. (“Enel Trade”), of our Generation and Energy Management Division).
      We are also active in the import, distribution and sale of natural gas. In 2005, we sold approximately 6.7 billion cubic meters of natural gas to third parties, of which approximately 5.1 billion cubic meters were sold to nearly 2.1 million end users.
      We also have electricity sales and distribution activities in Spain, and on April 28, 2005, we acquired a 51% interest in two electricity distribution and sales companies in Romania. In 2005 we distributed 9.7 TWh and sold 8.1 TWh. Since January 1, 2006, our international sales and distribution operations are carried out by our new International Division.
      In 2005, the Sales, Infrastructure and Networks Division had revenues after intrasegment eliminations of 20,422 million, reflecting revenues prior to intrasegment eliminations of 17,905 million from our Italian electricity sales and distribution operations, 913 million from international electricity sales and distribution operations, and 1,602 million from natural gas sales and distribution in Italy. In 2004, the Sales, Infrastructure and Networks Division had revenues of 19,254 million after intrasegment eliminations, reflecting revenues of 17,474 million from our Italian electricity sales and distribution operations, 391 million from international electricity sales and distribution operations and 1,396 million from natural gas sales and distribution in Italy.
      Corporate. Enel S.p.A., as the parent company, defines the strategic objectives for the Enel Group and coordinates the activities of all Group companies. In addition, Enel manages finance operations and insurance risk coverage for all Group companies and provides assistance and guidelines on organizational, human resources, industrial relations, accounting, administrative, tax, corporate and legal issues. Moreover, Enel S.p.A. is the party

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that enters into the Group’s long-term electricity contracts. In 2005, Enel S.p.A. had revenues of 1,103 million, compared to 1,649 million in 2004. Accordingly, we consider Enel as a separate reportable segment.
      Services and Other Activities. Our Services and Other Activities sector provides several services to all Group companies including real estate, engineering and construction, information technology, personnel training and administration, factoring and insurance services. After the re-organization of our internal structure at the end of 2005, we no longer consider this sector as a separate division in light of its focus on providing support to all Group companies following our divestitures of certain non-core operations in 2004 and 2005 that previously formed part of this division. These divestitures included the sale in July 2004 of real estate firm NewReal S.p.A. (“NewReal”), to which we had contributed real estate assets having a market value of approximately 1,400 million, and the sale in May 2005 of most of our interest in water operations through the sale of our wholly-owned subsidiary Enel.Hydro and of our 20% interest in Idrosicilia S.p.A., thus reducing our stake in this company to 40%. In 2005, our Services and Other Activities sector had revenues of 1,660 million, compared to 1,794 million in 2004. Effective January 1, 2006, our EPC activities related to companies of our Generation and Energy Management Division, which were previously included in this sector, were transferred to our Generation and Energy Management Division.
      Discontinued Operations. Consistent with our objective of focusing on our core energy businesses, we reduced our presence in the telecommunications business through the transfer in 2005 and 2006 of the entire share capital of Wind to Weather Investments, a company in which we currently have a 26.1% interest. For more information please see “— Business — The Enel Group — Discontinued Operations — Telecommunications.”
      Moreover, in light of Italian laws and regulations providing for the reunification of the ownership and management of the Italian transmission grid and imposing certain ownership restrictions on the entity that will own and manage it, in 2005 and in January 2006 we reduced our stake in Terna, the company through which we carried out our transmission activities, to 5.12%. For more information please see “— Business — The Enel Group — Discontinued Operations — Transmission.”
      As a result of these divestitures, we deconsolidated Wind as of August 11, 2005, and Terna as of September 15, 2005, and no longer have a Telecommunications division and a Transmission division.

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      The following chart sets forth our principal business units and the main companies through which we conduct these businesses as of May 31, 2006, as well as the country in which each such company is incorporated. All subsidiaries in the chart are directly or indirectly wholly owned by Enel, unless otherwise indicated.
(ORGANIZATION CHART)
Strategy
      In recent years, we have streamlined our operations to focus on our core electricity and natural gas businesses, including through the divestment of a number of non-core activities. We aim to become one of the largest European electricity and gas suppliers by 2010, with the goal of creating value for Enel’s shareholders,

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satisfying our customers and developing our employees. We have the following short and medium-term strategic objectives:
  •  Reducing our Italian power generation costs to levels lower than those of our competitors, in particular through the conversion of certain generation plants to run on less expensive fuels, and the alignment of our other operating costs with international best practice through an integrated approach to quality and standards;
 
  •  Increasing our presence in the market for electricity generated from renewable resources;
 
  •  Increasing electricity sales volumes and the number of customers in the free market in order to maximize our production margin by matching production volumes and sales volumes;
 
  •  Consolidating our position in the natural gas distribution business in Italy, where we are the second-largest operator;
 
  •  Extracting value from the integrated management of our electricity and natural gas services in Italy;
 
  •  Meeting our operating efficiency targets in the distribution and sale of electricity and natural gas; and
 
  •  Expanding our operations outside Italy, particularly in countries where we are already present or where market liberalization and privatization efforts are in progress, in which we can capitalize on the experience and technical know-how we have acquired in the Italian market.
      Consistent with our objective of focusing on our core energy businesses, we view our 26.1% interest in Weather Investments (to which we sold Wind) solely as a financial investment. We intend to focus our non-core activities on providing competitive services to the Group.
      In addition to the interim dividend of 0.19 per share paid in November 2005, on June 22, 2006 Enel paid its shareholders a balance dividend of 0.44 per share with respect to its 2005 results. With respect to its 2006 results, Enel expects to pay its shareholders an aggregate dividend of at least 0.42 per share, part as an interim dividend in 2006 and part as balance dividend in 2007. Please see “Item 8. Financial Information — Other Financial Information — Dividend Policy.”
      In order to pursue the Group’s objectives, each of our divisions has its own set of specific strategies, as described below.
Generation and Energy Management
      As a result of the progressive liberalization of the Italian electricity market and the required sale of a portion of our generation capacity, we estimate that our share of the power generation market in Italy has declined from approximately 63% in 1999 to approximately 39% in 2005.
      In order to maintain profitability and provide services on competitive terms in Italy, our Generation and Energy Management Division seeks to be the lowest-cost generator of electricity, in particular by diversifying appropriately its use of fuels. In this respect, we have reduced the percentage of our total production that we generate through plants fueled by oil and natural gas (excluding natural gas-fueled plants using CCGT technology) from approximately 45% in 2002 to approximately 26% in 2005. At the same time, we have increased the percentage of electricity we generate through thermal plants fired by coal and orimulsion from approximately 22% in 2002 to approximately 27% in 2005 and our production using renewable resources from approximately 24% in 2002 to approximately 27% in 2005. We do not currently generate any electricity using orimulsion. Our aim is for approximately 30% of our overall electricity output to be generated using renewable resources.
      In order to implement its strategy, our Generation and Energy Management Division intends to:
  •  Continue its program to convert certain of our thermal generation plants to CCGT plants capable of generating approximately 5,000 MW. Much of this program has already been completed;

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  •  Upgrade additional plants to run on lower-cost fuels, such as coal, while still respecting environmental norms;
 
  •  Consolidate its position in the field of renewable energy, including through an investment program expected to total approximately 1.3 billion from 2006 through 2010. This program includes plans for the maintenance, refurbishment and construction of wind, hydroelectric and geothermal generation plants in Italy that we expect will result in 300 MW of additional net installed capacity;
 
  •  Reduce CO2 emissions through our integrated investment strategy, which contemplates the conversion of old oil-fired plants into CCGT and high efficiency coal plants and the enhancement of our renewable generation capacity, as well as sourcing CO2 credits by participating in the Clean Development Mechanism and Joint Implementation Projects (emission reduction projects under the terms of the Kyoto Protocol);
 
  •  Continually seek to achieve operating excellence while increasing the efficiency and availability of its plants and respecting the environment and the health and safety of its employees;
 
  •  Continue its efforts to reduce its operating and maintenance expenses until it attains international best practice levels; and
 
  •  Optimize its fuel procurement activities, through a diversification of suppliers and supply channels.
Infrastructure and Networks
      We currently transport more than 80% of the electricity transported in Italy on our distribution network. In our electricity distribution operations, we are seeking to face the challenges of market liberalization and changes in applicable tariff regimes by taking action to reduce costs, and in particular our cash cost per customer of distributing electricity, as well as by continuing to focus on the quality of service we provide. In particular, we intend to:
  •  Continue our program to reduce operating costs and optimize our investment expenditures, by seeking constantly to improve our administrative processes, increasing our use of technology to support our activities and evaluating our investments more strictly from a financial perspective;
 
  •  Continue to improve our performance with respect to the targets set by the Energy Authority for quality and continuity of service in those geographic areas where these targets have not yet been achieved, and maintaining the quality and continuity of service where they have been achieved or exceeded; and
 
  •  Complete the roll-out of our “Telemanagement” digital metering program in Italy by the end of 2006, in order to (i) reduce costs associated with physical measurement of consumption and on-site maintenance of meters by our personnel, as these tasks would be accomplished remotely; (ii) measure the electricity consumption of our customers more accurately; (iii) improve our response times in providing technical assistance to our customers and provide higher quality service; and (iv) offer our customers tailored tariff plans that promote the use of electricity in off-peak periods and provide customers with opportunities to save money. We entered into an agreement with IBM in March 2004 to commercialize our digital metering know-how for use by other utilities in Italy and abroad in an effort to further benefit from this program. At March 31, 2006, we had installed approximately 27.6 million digital meters, of which approximately 25.5 million were connected to our remote network.
      In our natural gas distribution business, our primary objective is to operate as efficiently as possible and consolidate our market position, through both bidding on new gas distribution concessions and, where appropriate, acquiring additional gas distribution companies, particularly where there are opportunities for significant synergies with our existing operations. By controlling costs and increasing our customer base, we expect to further reduce our distribution cash cost per customer.

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Market
      As a result of the liberalization process, based on data from Terna and from the GRTN (for the years before 2005), we have seen our market share in direct sales of electricity to end users in Italy decline from approximately 92% in 1999 to approximately 50% in 2005.
      Our strategy to counter the effects of this trend is to continue to improve our quality of service and our cost-containment policies, further focus on small business clients and leverage our brand to target customers who elect to participate in the free market.
      In our natural gas sales business, we intend to increase our market share and margins by selectively expanding our customer base and increasing the volume of natural gas we sell. We seek to increase our customer base and to retain customers who elect to participate in the free market through initiatives targeting residential and medium-size businesses, including “dual fuel” offers (providing electricity and gas service through one sales network, with one customer service department and one bill) and offers tailored to customers. In addition, our goal is to lower the costs we incur in serving our customers.
International Operations
      Consistent with our objective to become one of the largest electricity companies in Europe and expand our operations outside Italy, we are focusing our efforts in European markets in which we are already present (such as Spain, Slovakia, Romania and the Americas) as well as considering opportunities that may arise in other markets (such as France and other Central and Eastern Europe markets).
      Consistent with our strategy of international expansion, we may make acquisitions of targets of very significant size. Without making any commitments, certain banks have expressed an intention to provide us with the financing necessary for such acquisitions.
      In particular, our strategy in markets where we already have a presence is the following:
        Spain. The Spanish electricity market is particularly important for us, since the demand for electricity in Spain is expected to grow at a higher rate than in other European markets, and we are already present in Spain through our Spanish subsidiaries Enel Viesgo Generaciòn (electricity generation), Electra de Viesgo Distribuciòn (electricity distribution) and our affiliate EUFR (electricity generation from renewable resources). We intend to develop our ability to generate electricity from renewable resources and convert certain coal and gas/oil-fired units into CCGT and more environmentally friendly plants. Moreover, by 2009 we intend to implement a Telemanagement digital meter system in Spain similar to the system we are completing in Italy. Please see “— Sales, Infrastructure and Networks — Domestic Distribution and Sales Operations — Telemanagement Systems” for a description of our Telemanagement digital meter system in Italy. We expect to invest approximately 2,044 million in our Spanish operations from 2006 through 2010.
 
        Romania. We are interested in the Romanian electricity market, particularly in light of Romania’s scheduled accession to the EU in 2007. We are already present in Romania through Enel Electrica Banat (formerly Electrica Banat), and Enel Electrica Dobrogea (formerly Electrica Dobrogea), two distribution companies in which we acquired a 51% stake in 2005, and where we are introducing management know-how and standards that are in line with Western European best practices. Moreover, in June 2006 we won the auction for a 67.5% stake in the Romanian power distribution company Electrica Muntenia Sud. Upon the successful completion of this transaction, we expect to serve approximately 2.5 million customers in Romania, including customers from Enel Electrica Banat and Enel Electrica Dobrogea. We also intend to enter the Romanian generation business, once it is privatized.
 
        Slovakia. We are interested in the Slovakian electricity market due to its strong interconnection with other Central European markets. We already have a strong presence in the Slovakian electricity market through SE, and we will monitor further opportunities that may arise. We also plan to upgrade SE’s existing nuclear plants and to invest in renewable resources. We are currently committed to develop two additional nuclear units for SE by 2013. Finally, in April 2006 we submitted a binding offer for the acquisition of a

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  90% interest in Paroplinovy Cyklus Bratislava, a Slovakian electricity generation company with an installed capacity of 220 MW. We do not expect the outcome of this offer to be known before August 2006.
 
        Northern and Latin America. We are present in North America and Central and South America through Enel North America and Enel Latin America, respectively. We intend to grow our operations in these regions, particularly in the renewable resources market through the acquisitions and development of hydroelectric, wind and geothermal generation plants in North America and in Central and South America.

The Enel Group
Italian Electricity Demand
      Demand for electricity in Italy has grown at an average annual rate of approximately 2.0% during the past five years. The following table shows the annual rate of growth in Italy’s GDP in real terms and the annual rate of growth in electricity demand for the years indicated.
                                                 
                        Average Annual
                        Growth Rate
    2001   2002   2003   2004   2005   2001-2005
                         
Growth in real GDP(1)
    1.8 %     0.4 %     0.3 %     1.2 %     0.0 %     0.74 %
Growth in electricity demand(2)
    2.1 %     1.9 %     3.2 %     1.5 %     1.3 %     2.0 %
 
Sources:
(1)  National Institute of Statistics (Istituto Nazionale di Statistica).
 
(2)  Terna (data for the years before 2005 were provided by the GRTN). Data for 2005 are provisional.
      Electricity demand grew by 1.3% in 2005, after having grown by 1.5% in 2004 and by 3.2% in 2003. Growth in demand for electricity is determined by a variety of factors, including the rate of economic growth, the level of business activity and weather conditions. In 2005, growth in demand for electricity slowed compared to that in 2004, reflecting the lower demand from small and medium-sized businesses. Please see “Domestic Distribution and Sales Operations — Sales, Infrastructure and Networks — Sales to Regulated Electricity Market.” According to data published in June 2006 by the Italian National Institute of Statistics, Italian GDP contracted by 0.6% in the first quarter of 2006 as compared to the fourth quarter of 2005, and increased by 1.5% as compared to the first quarter of 2005.
      Per capita electricity consumption is lower in Italy than in a number of other leading industrialized countries. On the basis of the data from the GRTN for 2004, the most recent available, we calculate that in 2004, electricity consumption in Italy was approximately 5,236 kWh per capita, compared to 5,208 kWh in 2003. As differences in the industrial or commercial and service sectors among countries not related to individual electricity use can distort comparisons of overall per capita production, we prefer to use per capita residential electricity use as our basic comparative measure. The following table compares per capita residential electricity consumption in Italy with that of other countries in the European Union for 2003, the most recent year for which complete data is available.
                         
            Per Capita
        Residential   Residential
    Inhabitants   Consumption   Consumption
             
    (In millions)   (TWh)   (KWh/inhabitant)
France
    59.8       141.0       2,358  
United Kingdom
    59.4       117.2       1,973  
Germany
    82.6       135.7       1,643  
Spain
    41.1       53.7       1,307  
Italy
    57.7       63.7       1,104  
European Union
    380.2       685.3       1,803  
 
Source: Enel, based on data established by Enerdata — World Energy database — February 2005.
      We believe that a reason per capita residential electricity consumption is lower in Italy than in the other countries of the European Union indicated in the table above is that in the past the tariff structure established by

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government regulation in Italy discouraged high-volume residential use. Please see “— Regulatory Matters — Electricity Regulation — The Tariff Structure” for a discussion of the current tariff structure.
Generation and Energy Management
      We are the largest producer of electricity in Italy through our Generation and Energy Management Division. Our key subsidiaries in this division include Enel Produzione, the division’s lead company and our primary generating company, and Enel Trade, which purchases fuel for all of our generating operations, sells electricity to resellers and wholesalers, sells natural gas to gas distribution companies and is active in the fuel trading sector. Moreover, in 2004 and 2005 this division was also responsible for sales of electricity to customers with annual consumption higher than 100 GWh (which sales are carried out by our Market Division since April 2006). Since January 1, 2006, the international generation operations previously carried out by this division have been allocated to our new International Division.
      Enel Trade also carries out commodity risk management activities on behalf of all Group companies. Please see “Item 11. Quantitative and Qualitative Information Disclosure about Market Risk” for additional information on our hedging activities. We also carry out emission trading through Enel Trade.
      Until May 31, 2005, our Generation and Energy Management Division also included Enel Green Power, which specialized in producing electricity from renewable resources, Enel Logistica Combustibili S.r.l., active in the fuel logistics sector, and Conphoebus S.r.l., which provided renewable energy-related services. We merged these companies into Enel Produzione as of June 1, 2005, uniting these electricity generation-related companies into a single entity as part of our efforts to streamline and simplify the division’s operations.
      This division also carries out research and development activities, in order to provide technological innovations to our businesses. The objective of our research and development activity is to improve the efficiency and capacity of our core energy operations, to expand and make more innovative the services they offer and to reduce the environmental impact of our operations. We develop new products and processes internally and also acquire technology in the market, which we then customize for our own purposes.
      In particular, our research and development activities seek to improve the efficiency of our generation plants and distribution networks, to minimize the environmental impact of electricity generation and to develop alternative fuels and innovative technologies, including projects to develop hydrogen and high temperature solar technologies.
      We carried out research and development activities mainly through Enel Produzione in 2005. Our expenditures on research and development were approximately 20 million in 2005, in line with those in 2004.
      Moreover, as of January 2006, this division has assumed charge of the EPC activities related to the companies of the Group, which were previously carried out by our Service and Other Activities Division.
      Unless otherwise specified, all operating data furnished in this section excludes data from our generating companies located outside of Italy.
Domestic Generation
Generating Facilities
      At December 31, 2005, Enel Produzione operated a total of 599 generating plants. Our Italian generating facilities include thermal plants (which burn fossil fuels), hydroelectric plants, geothermal plants and other facilities that generate electricity from renewable resources. At December 31, 2005, these plants had a total net installed capacity of 42.2 GW, representing approximately 49% of the total net installed capacity in Italy. Our net electricity production in 2005 decreased by 10.9% to 112.1 TWh from 125.9 TWh in 2004.
      We estimate that our net electricity production in 2005 represented approximately 39% of Italian production during the year, compared to 43% in 2004.
      The following table shows the gross production in 2003, 2004 and 2005 for the Italian electricity sector as a whole in gigawatt hours, broken down by type of generating plant. Net production is the difference between gross

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production less consumption by units generating electricity and mechanical and electrical losses in production, referred to as “power used by auxiliary installations.” Imports include electricity purchased from foreign producers on the spot market or under annual or long-term contracts. Pumped storage consumption refers to the use of electricity by pumped storage hydroelectric plants to pump water to elevated areas for use at a later time to generate electricity.
                           
    2003   2004   2005*
             
    (In GWh)   (In GWh)   (In GWh)
Gross production:
                       
Thermal
    242,784       246,125       252,412  
Hydroelectric
    44,277       49,908       42,482  
Geothermal and other renewable
    6,804       7,288       7,465  
                   
 
Total gross production in Italy
    293,865       303,321       302,359  
Power used by auxiliary installations
    (13,682 )     (13,299 )     (12,704 )
                   
 
Total net production in Italy
    280,183       290,022       289,655  
Net electricity imports
    50,968       45,635       49,155  
Total pumped storage consumption
    (10,492 )     (10,300 )     (9,369 )
                   
 
Total electricity demand in Italy
    320,659       325,357       329,441  
                   
 
Source: Terna (data for the years before 2005 were provided by the GRTN).
  * Data for 2005 are provisional.
      Please see “— Competition in the Electricity and Gas Markets” for a more detailed discussion of the electricity markets in Italy.
      The following table shows certain statistics about our domestic generating facilities, broken down by type of plant, at December 31, 2005, and for the year 2005. The weighted average age of the plants does not take into account refurbishments or upgrades after initial construction, but does reflect the effects of the refurbishing of geothermal plants, the conversion of thermal plants into CCGT plants and the conversion of one coal unit to clean coal technology that we completed in 2005. The forced outage factor represents the amount of electricity that was not produced during the period because of unplanned outages, expressed as a percentage of the maximum theoretical amount of electricity that could have been produced during the period.
                                           
    At December 31, 2005   2005
         
    Net   Weighted       Percentage   Forced
    Installed   Average Age   Net   of Our Net   Outage
    Capacity   of Plant   Production   Production   Factor
                     
    (GW)   (Years)   (GWh)    
                (Percent)
Thermal
    26.9       20       81,823       73.0 %     1.5 %
Hydroelectric
    14.4       43       24,883       22.2 %     1.4 %
Geothermal and other renewable
    0.9       8       5,381       4.8 %     1.5 %
                               
 
Total
    42.2               112,087       100.0 %        
                               
      We have no plans to construct new plants or add significant amounts of generating capacity in Italy, other than from renewable resources, in the near term. Instead, we have focused our investment plans on our existing generating plants. Please see “— Capital Investment Program — Generation and Energy Management” for a more detailed discussion of these plans.
Thermal Production
      In Italy, at December 31, 2005, we owned 46 thermal plants with an aggregate net installed capacity of 26.9 GW, or 63.7% of our net installed capacity at that date. Our thermal net production was 81,823 GWh in 2005, as compared to 91,854 GWh in 2004, representing in each year 73.0% of our net production for that year.

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      All our thermal plants consist of two or more generating units and most have a standardized design, with the generating units being of one of three types: steam-condensing units, gas turbine units and internal combustion units. Steam-condensing units consist of closed-cycle plants in which water is transformed into steam and used in a turbine to generate electricity. Steam is turned back into water through a cooling process using sea or river water or air tower cooling. Gas-turbine units burn natural gas and diesel fuel to drive a turbine and generate electricity. Internal combustion units use diesel engines to generate electricity. In addition to these conventional thermal plants, we own plants with CCGT gas turbines. At December 31, 2005, we derived approximately 68% of the net installed capacity of our thermal plants from steam-condensing units, approximately 6% from gas-turbine units in repowered steam plants, approximately 8% from gas-turbine units in open cycle, and approximately 18% from CCGT units. Internal combustion units represented a minimal part of our thermal gross installed capacity.
      Each of our conventional thermal generating units is designed to operate using one or more kinds of fuel. Single fuel units use either natural gas, petroleum products or coal, while dual fuel units can use petroleum products and either natural gas or coal, while triple fuel units can use petroleum products, coal and natural gas. In 2005, single fuel units generated approximately 51% of our net production from thermal plants (compared to approximately 55% in 2004) and represented approximately 69% of the net installed capacity of these plants at year end. Dual fuel units accounted for approximately 49% of our net production from thermal plants (compared to approximately 45% in 2004) and approximately 31% of our net installed capacity of these plants at December 31, 2005. The average thermal efficiency, or the ratio of useful energy produced to the energy consumed to produce it, of our thermal plants was 38.8% at December 31, 2005, slightly decreasing from 39.1% in 2004.
      In 1997, we began converting a number of our conventional thermal plants into CCGT plants, generally by installing one or more gas turbines and replacing conventional boilers with heat recovery steam boilers used to drive existing steam turbines. Converting plants to CCGT increases efficiency and reduces emissions. We plan for our new CCGT plants to have an expected average thermal efficiency of approximately 56%, in line with that at our existing CCGT plants.
      Since 1997, we have completed the conversion of approximately 4,300 MW of generating capacity to CCGT, and we expect to convert additional capacity of approximately 750 MW by the end of 2007. We currently estimate the average costs of conversion over the course of the project to be approximately 350,000 per MW of net installed capacity, or a total of approximately 1,800 million through 2008. At December 31, 2005, we had spent approximately 1,600 million of this total.
      In addition to our CCGT conversion program, we are planning to upgrade additional net installed capacity of approximately 4,100 MW by:
  •  completing the upgrading of the coal-burning technology of our existing coal plant, Sulcis, which we expect to become operational in the second half of 2006 (accouting for approximately 300 MW);
 
  •  converting three units at our fuel-oil plant at Torrevaldaliga Nord to clean coal technology, a process which is in progress and which we expect complete between 2008 and 2009 (accounting for approximately 1,900 MW); and
 
  •  subject to receipt of required permits, converting another three units to clean coal technology (accounting for approximately 1,900 MW). Depending on whether and when we obtain the required permits, we estimate that the converted facilities would be operational by 2010 or 2011.
      We have made significant investments since 1990 to improve the environmental standards of our thermal plants and to comply with the emission thresholds established by applicable environmental laws and regulations. These measures have included installing desulphurization and denitrogenation units and upgrading burners and units for the treatment of waste water and ash resulting from the electricity generation process. Installation of desulphurization and denitrogenation units increases our flexibility to use different types of fuel, including lower-cost fuels such as high sulfur fuel oil, while maintaining compliance with emission restrictions.

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      Our environmental capital expenditures for conventional thermal generation in 2005 were in line with those in 2004 and amounted to approximately 35 million. Please see “— Regulatory Matters — Environmental Matters” for a discussion of the environmental laws and regulations affecting our generation operations.
Hydroelectric Production
      At December 31, 2005, we had 500 hydroelectric plants in Italy with an aggregate net installed capacity of 14.4 GW, or approximately 34% of our net installed capacity at that date. In 2005, our hydroelectric net production was 24,883 GWh, or 22.2% of our net production for the year.
      We classify our hydroelectric plants with reservoirs by fill-in rate, which represents the time required for a plant’s reservoir to fill from empty based on normal water flow. Pondage plants have fill-in rates ranging from two to 400 hours and reservoir plants have fill-in rates exceeding 400 hours. We also have run-of-river and pumped storage hydroelectric plants.
      In 2005, pondage plants generated 24.5% of our net hydroelectric production and represented 19.7% of our net installed hydroelectric generation capacity at year end, while run-of-river plants accounted for 24.6% of our net production from hydroelectric plants and 11.5% of our net installed hydroelectric generating capacity. Pumped storage (including mixed pumped storage) plants generated 27.1% of our net hydroelectric production in 2005, and represented 52.1% of our net installed hydroelectric generating capacity, with reservoir plants accounting for the remaining approximate 23.8% of our net hydroelectric production and 16.7% of our net installed hydroelectric capacity in the same period.
      We invested 178 million in 2005 on our hydroelectric plants, including on work carried out to comply with safety and environmental regulations, as well as on refurbishment and revamping. Our hydroelectric plants generate electricity from water streams in the public domain under licenses from the Italian government. Under the Bersani Decree, the Provincial Authorities of Trento and Bolzano, which enjoy special autonomous status under Italian law, were entitled to impose earlier license termination dates for hydroelectric plants in these areas. If any of these licenses expire without being renewed, we will have to transfer the affected hydroelectric plants (with an aggregate net installed capacity of 1,975 MW, or 4.7% of our current total net installed capacity) to the governmental authority granting the license. The Provincial Authorities of Trento and Bolzano set a termination date of 2010 for the licenses they have granted. The licenses from the Italian goverment were originally due to expire in 2029 and were subject to renewal.
      In January 2004, however, the European Commission determined that certain Italian regulations regarding hydroelectric concessions were contrary to EU law. In particular, the European Commission objected to renewal preferences granted to existing holders of concessions (and in the region of Trentino-Alto Adige, to the operator controlled by the local authorities) upon the expiry of those concessions, as well as to the fact that the regulations provided for the expiration of all concessions in 2029 (and for the region of Trentino-Alto Adige, in 2010), even though these concessions had previously been of perpetual duration. In December 2005, Italy amended the relevant regulations, abrogating the renewal preferences and postponing the expiration of all concessions for an additional 10 years. However, if the European Commission continues to pursue its formal action before the Court of Justice to enforce its request and the Court of Justice affirms the European Commission’s opinion, our hydroelectric concessions may be terminated prematurely and we may not be able to renew these concessions on favorable terms or at all. The European Commission decision on whether to continue its formal action is expected in the second half of 2006. Please see “Item 3. Key Information — Risk Factors — Risks Related to Our Energy Businesses — A European Commission challenge to Italian regulations on hydroelectric concessions could adversely affect our business, financial condition and results of operations.”
Production from Geothermal and Other Renewable Resources
      We produce energy from renewable resources, and have both significant experience in multiple technologies, including geothermal, wind and solar energy, as well as our own engineering and project development capabilities. We formerly conducted these activities through Enel Green Power, which we merged into Enel Produzione as of June 1, 2005.

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      At December 31, 2005, we had 32 geothermal power plants with an aggregate net installed capacity of 671 MW. In 2005, our geothermal net production was 5,012 GWh, or 4.5% of our net production for the year.
      We also generate electricity from other forms of renewable resources, including solar photovoltaic systems and wind energy. At December 31, 2005, we operated 17 wind farms with an aggregate net installed capacity of about 277 MW and four photovoltaic solar grid connected power plants with an aggregate net installed capacity of 3 MW. Together, these plants accounted for 369 GWh of our net production in 2005.
      Most of our revenues from renewable energy come from sale agreements entered into under the CIP 6 regime, which provides incentives for the production of renewable energy, and from sales of energy produced by small hydroelectric plants, including sales on the free market through Enel Trade. We expect that the demand for energy produced from renewable resources to increase as a result of current regulations requiring producers to supply a specified amount of electricity generated from qualifying renewable resources. Please see “— Regulatory Matters — Electricity Regulation — Promotion of Renewable Resources” for additional information.
      To comply with these regulatory requirements, we can either produce electricity from qualified renewable resources ourselves, which would entitle us to receive “green certificates”, or we can purchase “green certificates” from other qualified producers or the GRTN. Based on our production for 2004, we were required to provide approximately 2.1 TWh of electricity from qualified renewable resources in 2005, the same amount we were required to provide in 2004. In 2005, we generated 1.3 TWh of energy from qualified renewable resources and purchased “green certificates” for the remaining 0.8 TWh, at a cost of approximately 90 million. We estimate that in 2006 we will increase our generation from qualified renewable resources significantly, thus reducing the amount of green certificates we have to purchase from other qualified producers or from the GRTN in order to comply with the regulatory requirements.
      We have started a capital investment program in order to reach a level of qualifying production from renewable resources of approximately 2.5 TWh by year-end 2007, which we believe will permit us to meet the regulatory requirements and may enable us to sell green certificates to the market starting in 2007. This program is expected to result in an additional increase in our renewable capacity (hydroelectric, wind and geothermal) of about 300 MW by 2010.
Fuel
      We use fuel oil, natural gas, coal and other fuels in operating our thermal generation plants, and also engage in fuel trading activities. We do not use significant amounts of fuel in operating our hydroelectric, geothermal or other renewable resource plants. Italy has small reserves of fossil fuels. As a consequence, we depend on imported fuel oil, natural gas and coal for a large proportion of our energy needs.
      Our fuel costs are influenced by prices in the world market for oil, fuel oil, natural gas and coal. In 2005, the per barrel market price for oil increased from $38.2 at December 31, 2004, to $54.4 at December 31, 2005, or by 42.4%. This substantial increase was the result mainly of geopolitical factors, such as the current situation in a number of oil-producing regions, including Iraq, other parts of the Middle East, Nigeria and Venezuela, as well as structural factors, such as high production and refinery capacity utilization levels and increased demand in India, China and the United States. However, we attempt to maintain secure and flexible supplies by diversifying our sources of fuel, and are also partially hedged against rising fuel prices. Please see “Item 3. Key Information — Risk Factors — Risks Relating to our Energy Business — Significant increases in fuel prices or disruptions in our fuel supplies could have a negative effect on our business” for a description of the risks connected to significant increases in fuel prices. See also “Item 11. Quantitative and Qualitative Disclosure about Market Risk” for a discussion of our hedging activities. In addition, we seek to increase our use of less expensive fuels, such as coal, as well as fuels that have less impact on the environment when consumed, such as natural gas. However, generation using coal generally results in higher emissions levels compared to natural gas. Our ability to increase our use of coal is dependent on our ability to acquire and implement technologies that will permit us to comply with restrictions on emissions established by national and European Union authorities. Please see “— Regulatory Matters — Environmental Matters” for a discussion of these restrictions.

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      We manage our fuel supply by entering into term contracts for base quantities and supplementing these contracts with purchases of fuel on spot markets both in Italy and abroad. Our long-term fuel contracts, primarily for the purchase of natural gas, will require us to pay an average of approximately 2,774 million per year over the next five years, based on current prices. Please also see “Item 5. Operating and Financial Review and Prospects — Contractual Obligations and Commitments.”
      In 2005, our aggregate fuel costs for thermal production, including fuel transport, at our plants in Italy and abroad were 3,910 million, compared to 3,598 million in 2004. This 8.7% increase was primarily due to higher prices in the international fuel markets, the effect of which was only partially offset by the lower volume of electricity production during 2005.
      From July 1997 until the start of trading on the Italian power exchange on April 1, 2004, the tariff structure contained an energy reimbursement component calculated with reference to an index of weighted average fuel prices and a consumption index based on the efficiencies expected to be obtained from the fuels comprising the fuel price index. Accordingly, we sought to use a mix of fuels less expensive in the aggregate than the fuels comprising the weighted index and to generate energy more efficiently than the efficiency levels assumed in the calculation of the “heat rate” used in the Energy Authority’s consumption index. This tariff structure also included incentives to reduce production from thermal plants and to increase the use of renewable resources.
      Since April 1, 2004, the price paid to electricity producers is determined by competitive bidding on the Italian power exchange or through freely negotiated bilateral contracts. Please see “— Regulatory Matters — Electricity Regulation — The Italian Power Exchange” for additional information.
      The following table provides a breakdown of our net electricity production in Italy for the periods indicated by primary energy source utilized. The data represent production by Enel Produzione and Enel Green Power (which in 2005 was merged into Enel Produzione).
                                                   
    2003   2004   2005
             
    Net       Net       Net    
    Electricity   Percentage   Electricity   Percentage   Electricity   Percentage
    Produced   of Total   Produced   of Total   Produced   of Total
                         
    (GWh)       (GWh)       (GWh)    
Thermal
                                               
— Natural gas
    48,802       35.4       40,602       32.3       37,824       33.7  
— Coal and orimulsion
    30,030       21.8       30,700       24.4       30,001       26.8  
— Oil
    27,838       20.2       20,552       16.3       13,998       12.5  
 
Total thermal
    106,669       77.4       91,854       73.0       81,823       73.0  
Hydroelectric
    26,012       18.9       28,659       22.8       24,883       22.2  
Geothermal
    5,036       3.6       5,120       4.1       5,012       4.5  
Wind and photovoltaic
    77       0.06       235       0.2       369       0.3  
                                     
 
Total
    137,794       100.0 %     125,868       100.0 %     112,087       100.0 %
                                     
      In 2005, the approximate percentages of our net electricity produced by thermal generation in Italy represented by each of the following fuels was approximately:
  •  46% natural gas;
 
  •  37% coal; and
 
  •  17% fuel oil.
      We do not currently generate any electricity using orimulsion. The fuel oil plant at Porto Tolle, which previously we were planning to convert to burn orimulsion, will instead be converted to burn coal upon receipt of the necessary permits.
      Our subsidiary Enel Trade is responsible for the purchase and sale of fuel for all of our domestic generating operations and our natural gas sales and distribution operations in the Italian market, as well as a portion of the

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fuel requirements of our Spanish subsidiary Viesgo. In addition, Enel Trade buys and sells other energy products and has land and sea fuel shipping operations. In 2005, Enel Trade purchased an aggregate volume of 24.3 million tons of oil and oil equivalents, including petroleum products, coal and natural gas, of which 1.6 million were sold to third parties, compared to purchases of 29.1 million tons of oil and oil equivalents in 2004, of which 3.6 million were sold to third parties.
      Enel Trade also sells natural gas to gas distribution companies and other third parties, and engages in fuel trading activities, as part of its management of, and efforts to optimize, its supply of fuel to the rest of the Enel Group, as well as in electricity trading. Enel Trade also trades “green certificates” in Italy, engages in similar activities at a European level and engages in trading of CO2 emission rights, having obtained the necessary approvals. In 2004 and 2005, Enel Trade was also responsible for sales of electricity to customers with annual consumption higher than 100 GWh (which sales have been carried out by our Market Division since April 2006). In 2005, Enel Trade sold approximately 10.1 TWh of electricity to Eligible Customers and 3.8 TWh to resellers in Italy, as well as 15.5 billion cubic meters of natural gas, of which 8.8 billion cubic meters were sold to our thermal generation operations, 5.1 billion cubic meters to our gas distribution and sales operations and 1.6 billion cubic meters to third parties.
Fuel Oil
      We are reducing our need for fuel oil for power generation as a consequence of the conversions of some of our fuel-fired plants to coal and natural gas. The following table shows the amount of fuel oil supplied to our generation companies purchased from domestic and foreign suppliers in each of the periods indicated. Domestic suppliers include suppliers whose headquarters are in Italy, including the Italian energy group Eni S.p.A. (“Eni”), while foreign suppliers include suppliers and refiners outside of Italy and traders of primarily non-Italian sources of oil.
                           
    Year Ended
    December 31,
     
    2003   2004   2005
             
    (In millions of tons)
Domestic suppliers
    1.2       1.0       0.9  
Foreign suppliers
    5.3       3.8       2.7  
                   
 
Total fuel oil purchased
    6.5       4.8       3.6  
                   
      In 2005, we purchased approximately 20% of our fuel oil on the spot market and approximately 80% under contracts ranging in term from one to twelve months. All purchases made on the basis of term contracts are indexed to market prices.
      The following table shows the amounts of fuel oil with low, mid and high sulfur content that we purchased in each of the periods indicated.
                           
    Year Ended
    December 31,
     
    2003   2004   2005
             
    (In millions of tons)
Fuel oil purchased
                       
Low sulfur
    4.0       3.0       2.3  
Mid sulfur
    2.5       1.6       1.0  
High sulfur
    0.0       0.2       0.3  
                   
 
Total
    6.5       4.8       3.6  
                   
Natural Gas
      We purchase most of our natural gas under long-term, take-or-pay contracts. The price of natural gas under these contracts is generally tied to market prices for fuel oil. In 2005, we purchased 15.5 billion cubic meters of

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natural gas, of which 8.8 billion cubic meters were used for our thermal generation operations. Eni, the main Italian gas supplier and transporter, supplied approximately 30% of this natural gas.
      We also continued to purchase large volumes under a supply contract with Sonatrach, the Algerian gas producer, which accounted for approximately 37% of the natural gas we purchased in 2005.
      In 1992, we entered into a 20-year take-or-pay contract with NLNG, a Nigerian joint venture, for the supply of 3.5 billion cubic meters of liquefied natural gas per year, commencing in October 1999. However, due to environmental concerns, a once-planned Italian regasification facility has never been constructed. As a result, we are unable to import liquefied natural gas, and instead, in 1997, entered into a swap agreement with Gaz de France and related transportation arrangements with Eni whereby Gaz de France takes the liquefied natural gas supplied by NLNG under the contract and provides us with an equivalent volume of non-liquefied natural gas. We obtained approximately 25% of the natural gas we purchased in 2005 pursuant to our Nigerian gas contract. Under current regulations, we expect to continue to receive until 2009 reimbursement for part of our stranded costs incurred in connection with the NLNG contract. Please see “— Regulatory Matters — Electricity Regulation — Stranded Costs” for additional information on reimbursement of our stranded costs.
      We purchased 5% of our natural gas in 2005 from Edison S.p.A. (“Edison”), an Italian gas and electricity company, and the remaining 3% on a spot basis in the national and international markets.
      On June 21, 2005, we sold to BG Group plc (formerly British Gas plc) (“BG”) our 50% interest in Brindisi LNG, which we had formed as a partnership with BG to build and manage a liquefied natural gas regasification terminal in Brindisi in southern Italy. Under the terms of the deal, we are entitled to receive approximately 44 million, which was intended to reimburse us for the costs we have incurred for the project. Of the total consideration, we received 17 million at closing, with the remaining balance of approximately 27 million being due within June 30, 2006 (subject to certain conditions relating to BG’s continuous involvement in the project).
Coal
      In 2005, we purchased 12.8 million tons of coal, all of which was used by our generating companies and imported, principally from South Africa, South America, the Far East and Eastern Europe.
CO2 emission rights
      The Kyoto Protocol established a market mechanism for the trading of CO2 emission rights. Pursuant to EU directives implementing this mechanism, the Italian Environment Ministry issued a decree in February 2006 allocating among Italian producers the emissions levels for the 2005-2007 period. Our Group was assigned emissions quotas for its existing installations of 48.2 million, 40.5 million and 39.9 million metric tons of CO2 for the years 2005, 2006, 2007, respectively. Our emissions for 2005 were eight million tons higher than the emission quotas we were assigned for the same year and we believe that the quotas we have been assigned for 2006 and 2007 will not be sufficient to meet our production needs in those years. Therefore, in May 2006 we challenged the decree of the Environment Ministry.
      The Environment Ministry decree, however, allocates some emission quotas to new plants when they become operational. Based on our current emissions projections, we expect to be entitled to part of these quotas for new plants and to reduce the difference between our actual emissions and the emission quotas allocated to us for 2006 and 2007. We will cover any such difference (which we currently expect will be limited to a few million tons) through the purchase of emission trading rights on the market.
      Moreover, our subsidiaries Enel Viesgo Generaciòn has been assigned emission quotas by the Spanish Environment Ministry for its existing installations of 3.9 million, 3.4 million and 2.65 million metric tons of CO2 for the years 2005, 2006 and 2007, respectively. The emissions of Enel Viesgo Generaciòn in 2005 were 6.06 million tons, higher than the emission quotas assigned.
      At May 25, 2006, the weighted average price for one emission trading right for the years 2005, 2006 and 2007 was approximately 22 per ton. Each emission trading right corresponds to 1 ton of CO2 and may also be

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sourced through CO2 credits issued according to the Clean Development Mechanism and Joint Implementation Project (emission reduction projects under the terms of the Kyoto Protocol).
Purchased Power
      Our Generation and Energy Management Division purchases power to comply with certain regulatory rules. We also, through Enel Trade, purchase power to diversify our sources of electricity and to reduce our costs, as well as for supply to third parties. In 2005, our Generation and Energy Management Division purchased approximately 9.4 TWh of power from domestic and foreign producers to supply electricity to Eligible Customers and resellers in Italy.
      Our Generation and Energy Management Division also purchases power from outside Italy, through both annual contracts and on the spot market. In addition, Enel is party to three long-term contracts for the purchase of imported electricity. These contracts are for 1,400 MW, 600 MW and 55 MW per year, expire in 2007, 2011 and 2033, respectively, and were entered into under regulations in effect prior to the issuance of the directive implementing the Bersani Decree. Since April 1, 2004, Enel has been required to sell the imported electricity purchased pursuant to these long-term supply contracts to the Single Buyer.
      The table below sets forth the amount of electricity imported into Italy that Enel purchased under long-term contracts and that Enel Trade purchased under annual contracts, and spot purchases during each of the years indicated.
                           
    2003   2004   2005
             
    (TWh)
Long-term contracts
    15.5       14.4       14.4  
Annual contracts
    0.6       1.1       2.5  
Spot purchases
    0.0       0.1       0.1  
                   
 
Total imports
    16.0       15.7       17.0  
                   
      The Italian electricity grid is interconnected to foreign networks through 15 international transmission lines. We believe these lines are operating at full capacity only during daylight hours. Please see “— Regulatory Matters — Electricity Regulation — Imports” for additional information on the Italian electricity import market.
      Since April 1, 2004, we have also purchased power to comply with a new rule that took effect with the start of trading on the Italian power exchange requiring electricity generators to purchase the electricity used to power pumping at hydroelectric plants from third parties. We previously used our own electricity production for these purposes.
International Generation
      Our international generation operations in 2005 included Enel Viesgo Generaciòn, an electricity generation company in Spain; Enel Uniòn Fenosa Renovables S.A. (“EUFR”), a company active in Spain in the field of renewable energy; Maritza East III, a generating company in Bulgaria; and Enel North America and Enel Latin America which are active in power generation from renewable sources in North America and in Central and South America, respectively. Following the re-organization of our internal structure at the end of 2005, these international generation activities are no longer included in our Generation and Energy Management Division, but are carried out by our new International Division.
      We acquired the Spanish company Electra de Viesgo S.L. (“Viesgo”), which owned Viesgo Generaciòn (currently Enel Viesgo Generaciòn) as well as certain distribution companies, from Endesa S.A. in January 2002 for a total consideration of 2,070 million, including 1,920 million in cash and the assumption of 150 million in debt. Enel Viesgo Generaciòn (currently wholly owned by Enel Produzione) operates 6 thermal plants and 12 hydroelectric plants in Spain, which taken together have a total net installed capacity of approximately 2,264 MW, and, in 2005, had a net production of 7,423 GWh. Please see “— Fuel — CO2 emissions” for more information on emission quotas that have been assigned to Enel Viesgo Generaciòn.

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      In March 2003, we acquired from Entergy Power Bulgaria Ltd. (“Entergy”), through our subsidiary Enel Generation Holding BV, 60% of the share capital of Maritza East III Power Holding BV, which in turn holds 73% of Bulgarian generation company Maritza East III Power Company A.D. (“Maritza East III”), for 73.5 million. Maritza East III, which has 549 MW of net installed capacity and had a net production of 3,005 GWh in 2005, is working on the refurbishment, environmental upgrade and management of its lignite-fired generation plant, located on the border with Greece. The total financial outlay of Maritza East III for the project, which is expected to result in an increase in Maritza East III’s net installed capacity to 794 MW, is estimated to be about 499 million, to be funded through project financing, cash flow from operations and equity.
      In June 2006, Enel purchased from Entergy the remaining 40% stake in Maritza East III Power Holding BV and 100% of Maritza O&M Holding Netherlands BV, a Dutch company holding 73% of Maritza East 3 Operating Company A.D. for a total consideration of 47.5 million.
      In December 2003, we acquired 80% of the share capital of Uniòn Fenosa Energìas Especiales (now EUFR), from Uniòn Fenosa Generaciòn SA, for 178 million. We granted Uniòn Fenosa Generaciòn SA an option to repurchase 30% of EUFR’s capital stock before the end of 2007. In May 2006, Uniòn Fenosa Generaciòn SA exercised this option and repurchased 30% of EUFR for approximately 82 million. As a result, Uniòn Fenosa Generaciòn SA and we each hold 50% of EUFR. EUFR’s assets include plants and projects for the generation of electricity from renewable resources, primarily wind and hydroelectric facilities. EUFR has 373 MW of net installed capacity currently in operation, and more than 190 MW in development that we expect to be in operation by the end of 2006. EUFR’s net production in 2005 was 1,030 GWh.
      We have generation operations in the United States through Enel North America, a North American independent power producer specializing in renewable resources. At December 31, 2005, Enel North America operated 65 power plants in the United States and two in Canada with an aggregate net installed capacity of 402 MW and a net production of approximately 1,283 GWh in 2005. In April 2005, Enel North America acquired full control of the 25 MW Sheldon Springs hydroelectric project located on the Missisquoi River in Sheldon, Vermont (in which it had previously owned a 1% stake). On February 9, 2006, Enel North America acquired an additional 36% interest in St. Felicien Cogeneration Limited Partnership (“St. Felicien”), a 21.4 MW biomass project in Quebec (Canada), thereby increasing its stake in this company to 96%. We also have generation operations in Central and South America through Enel Latin America, another power producer specializing in renewable resources. At December 31, 2005, Enel Latin America operated two hydroelectric plants and a wind plant in Costa Rica, as well as two hydroelectric plants in Chile and two hydroelectric plants in Guatemala, which together had aggregate net installed capacity of 198 MW and net production in of 884 GWh in 2005.
      Enel ESN Energo, a wholly owned Russian subsidiary of Enel ESN Management BV, entered into a three-year agreement (renewable for an additional year) in June 2004 with OAO North-West CHPP to manage North West Thermal Power Plant (“NWTPP”), a CCGT generation plant near St. Petersburg with installed capacity of approximately 450 MW. NWTPP is controlled by RAO UES, the company that operates Russia’s unified power system. At present, NWTPP is engaged in the construction of a second unit with installed capacity of 450 MW, which is expected to be operational at the end of 2006. Enel ESN Management BV is a joint venture currently held 75% by us and 25% by ZAO ESN, a privately held Russian company.
      As part of our international expansion objectives and our efforts to consolidate our presence in Central and Eastern Europe, on April 28, 2006 we purchased a 66% interest in SE, the principal electric power generation company in Slovakia, with an estimated market share of more than 80%, for approximately 840 million and entered into a shareholders’ agreement with the state-owned entity National Property Fund, the remaining shareholder of SE. SE has total net installed capacity of 6,356 MW, of which 38% is nuclear-powered, 37% is hydroelectric-powered and 25% is powered by conventional thermal sources. This acquisition marks our re-entry into the field of nuclear power generation; we have not owned any nuclear power plants since November 2000, and we have not produced electricity from nuclear power plants since 1988. Please see “— Regulatory Matters — Environmental Matters — Discontinued Nuclear Operations.” SE owned prior to our acquisition six nuclear power units with net installed capacity of 400 MW each, which we believe were equipped with internationally accepted technology. Prior to the closing certain conditions were fulfilled, including the approval by the Slovakian government of the strategic investment plan we prepared for SE for the 2006-2013 period and

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the transfer to state-owned companies of the assets and liabilities (including spent nuclear fuel and the radioactive waste) of a nuclear power plant built in 1970 and operational since 1978, that is in the process of being decommissioned, and the disposal of a water plant, as well as the approval by the Slovakian government of legislation on a new fund for the decommissioning of nuclear installations in Slovakia and new rules governing the Slovakian electricity market. The four nuclear power units that SE now retains have been recognized by the International Atomic Energy Association as being in line with Western European security standards. SE will continue to sell the energy produced by the spun-off assets to the Slovakian market and reimburse the state-owned company for the costs it incurs in the operation of the plants.
      On May 30, 2005, we entered into a non-binding memorandum of understanding with EDF for an industrial partnership permitting us to invest in the French electricity market, including in EDF’s latest generation European Pressurized Water Reactor, or “EPR,” nuclear reactor project, which is expected to be fully operational by 2012. Under the terms of this memorandum of understanding: Enel will have a 12.5% stake in EDF’s EPR project; Enel will bear its proportional share of the costs associated with the project, including investment, operating and fuel costs, as well as its share of budgeted reactor decommissioning costs and the corresponding share of the back-end fuel and waste disposal costs; EDF will be the operator of the power plant, and will bear any related nuclear civil liability; Enel will receive a share of the generation capacity and output proportional to its initial stake in the project, which may be increased, so long as EDF retains a majority interest. The parties had agreed to execute a definitive agreement by September 30, 2005, subject to the receipt of a favorable non-binding opinion of the European Commission, which it has not yet released. Although the parties have not executed a definitive agreement, pursuant to the memorandum of understanding we have been receiving a portion of the electricity generated by EDF from nuclear sources since January 1, 2006, which is expected to increase over time to a maximum of 1,200 MW, pending completion of the EPR project.
      On April 24, 2006, we submitted a binding offer for the acquisition of a 90% interest in Paroplinovy Cyklus Bratislava, a Slovakian electricity generation company with an installed capacity of 220 MW, in which our subsidiary SE holds the remaining 10% interest. We expect that the outcome of this offer will not be known before August 2006.
      On May 15, 2006, we submitted a binding offer for the acquisition from Hydro-Quebec International of a 24.55% interest in Fortuna, a company that owns a 300 MW hydro-plant in Panama.
      On June 9, 2006, we entered into an agreement with Grupo Rede for the acquisition of 11 companies, which own concessions to operate hydroelectric plants in Brazil with an aggregate installed capacity of 98 MW, for a total consideration of 450 million Brazilian real (approximately 155 million). Closing of the transaction is subject to certain conditions, including approval by the Brazilian electricity authority, and is expected in the second half of 2006.
      The following table shows the net installed capacity at December 31, 2005, of our foreign generating companies broken down by type of plant. Net installed capacity excludes capacity held by unconsolidated associated companies.
                                                   
    Enel   Enel               Total at
    North   Latin       Maritza   Uniòn   December 31,
    America   America   Viesgo   East III   Fenosa   2005
                         
                (MW)        
Thermal
                1,592       549             2,141  
Hydroelectric
    313       174       672                   1,159  
Wind
    67       24                   321       412  
Biomass and Biogas
    22                               22  
Cogeneration
                            52       52  
                                     
 
Total
    402       198       2,264       549       373       3,786  
                                     
      Our international operations generated a total of 13,625 GWh of electricity in 2005, as compared to 12,321 GWh in 2004, including 7,423 GWh produced by Enel Viesgo Generaciòn (6,062 GWh in 2004), 3,005 GWh

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produced by Maritza East III (3,213 GWh in 2004), 2,167 GWh produced by our North and Latin American companies (2,193 GWh in 2004) and 1,030 GWh generated by EUFR (853 GWh in 2004).
Sales, Infrastructure and Networks
      In 2005, our Sales, Infrastructure and Networks Division carried out our electricity and natural gas sales and distribution operations. At the end of 2005, this division was divided into a Market Division and an Infrastructure and Networks Division, each of which operates in both the electricity and gas markets and are responsible for sales of products and services and for management of our distribution network, respectively. In addition, at the end of 2005 our electricity sales and distribution operations outside of Italy were allocated to our new International Division.
      Our Infrastructure and Networks Division operates in Italy mainly through Enel Distribuzione, which distributes and sells electricity on Italy’s regulated market, Deval, which distributes and sells electricity in the region of Valle d’Aosta in Italy, and Enel Rete Gas, which distributes natural gas in Italy.
      Our Market Division sells electricity and natural gas and provides electricity-related services, mainly through Enel Energia, which sells electricity on the free market, and Enel Gas, which resells natural gas to end users. Until March 2006, Enel Energia sold electricity on the free market to customers with annual consumption up to 100 GWh, while electricity to consumers with annual consumption above this threshold was sold by our Generation and Energy Management Division.
      Other subsidiaries in this area include Enel Sole, which offers public lighting services, and Enel.si, which offers electricity systems-related services and “beyond-the-meter” products and services, such as consulting and sales of electricity equipment.
Domestic Distribution and Sales Operations
Electricity Companies
      We operate in the market for the distribution and sale of electricity in Italy through the following companies:
  •  Enel Distribuzione, which owns the electricity distribution network serving the free and regulated markets and sells electricity on the regulated market;
 
  •  Deval, a subsidiary in which we own a 51% interest, which engages in similar activities in the region of Valle d’Aosta ;
 
  •  Enel Energia, which sells electricity on the free market to customers with annual consumption of up to 100 GWh (while sales to customers with higher consumption levels are made through Enel Trade of our Generation and Energy Management Division);
 
  •  Enel Sole, which provides public and art lighting services; and
 
  •  Enel.si, which provides electricity systems-related services.
      The Italian electricity market comprises a free market, in which Eligible Customers may participate, and the regulated market, in which Non-Eligible Customers are required to participate and Eligible Customers may continue to participate if they so choose. Please see “— Regulatory Matters — Electricity Regulation” for additional information.
Distribution of Electricity
      We own and operate the principal electricity distribution network in Italy. We use the term “distribution” to refer to the transport of electricity from the transmission grid to end users. Enel Distribuzione, our wholly owned subsidiary, holds almost all of our distribution assets and operations, excepts for the assets and operations held by Deval in Valle d’Aosta. Its main responsibilities consist of operating and maintaining the distribution network, distributing electricity to the free market and distributing and selling electricity on the regulated market.

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      The following table sets forth the aggregate volumes of electricity distributed to the free market and distributed to (and sold) on the regulated market by Enel Distribuzione and Deval for the periods indicated, excluding electricity distributed to resellers.
                           
    Year Ended December 31,
     
    2003   2004   2005
             
    (In GWh)
Distributed to free market
    102,973       113,691       121,370  
Distributed (and sold) on the regulated market
    141,453       136,961       129,677  
                   
 
Total
    244,426       250,652       251,047  
                   
      The total volume of electricity we distributed in 2005 increased by 0.2% compared to the volume distributed in 2004. The volume of electricity we distributed to the free market increased by 6.7% compared to 2004, reflecting an increase in the number of Eligible Customers and their migration to the free market. The volume of electricity we distributed (and sold) to the regulated market decreased by 5.3% in 2005 compared to 2004, primarily reflecting the fact that since April 1, 2004, other electricity distributors acquire their electricity directly from the Single Buyer, while prior to that date, we were obliged to buy electricity on their behalf. The decrease also reflected our sale of local distribution networks in Trento and other smaller municipalities. Please see “— Regulatory Matters — Electricity Regulation — Eligible and Non-Eligible Customers” for additional information on consumers eligible to participate in the free market. Including electricity transported to resellers, we distributed a total of 265,055 GWh, 261,239 GWh and 259,277 GWh of electricity in 2003, 2004 and 2005, respectively.
      We have focused on reducing operating costs in our electricity distribution operations, as well as our electricity sales operations, in recent years. In particular, we have reduced the aggregate number of employees involved in these operations by 11.5% over the past three years, and by approximately 23% from December 31, 2001 to December 31, 2005. In the future, we expect this trend to continue, but with a decrease in the volume of reductions. The following table shows the aggregate number of employees of Enel Distribuzione and Deval at the dates indicated:
             
    At December 31,
     
    2003   2004   2005
             
Employees
  33,106   32,595   29,299
      We have also been investing in our Telemanagement digital meter system since 1999 in connection with our focus on reducing costs. Please see “— Telemanagement System” below for additional information.
Electricity Distribution Network
      The table below sets forth certain information about our primary and secondary distribution networks at December 31, 2005.
                                                 
    Under-   Insulated   Bare       Number of   Transformer
Type   ground Lines   Aerial Lines   Aerial Lines   Total Lines   Substations   Capacity
                         
    (km)   (km)   (km)   (km)   (MVA)    
Primary:
                                               
High voltage lines (40-150 kV)
    468             18,484       18,952                  
Primary substations
                                    2,029       94,000  
Secondary:
                                               
Medium voltage lines (1-30 kV)
    125,017       7,932       202,202       335,151                  
Low voltage lines
    226,238       385,915       123,873       736,026                  
Secondary substations
                                    411,404       68,600  

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      In September 2003, pursuant to a ministerial decree, Enel Distribuzione transferred to Terna the ownership of approximately 900 kilometer of high-voltage transmission lines. Enel Distribuzione transferred an additional 100 kilometer of high-voltage transmission lines to Terna in 2004.
      Our replacement and construction of distribution lines and substations are subject to Italian environmental and aesthetic regulatory limitations, including legislation on electromagnetic fields that may make it more difficult to build new distribution lines and substations in the future and may require removing existing distribution lines and substations. Please see “— Regulatory Matters — Environmental Matters — Electromagnetic Fields” for a more detailed description of the environmental laws and regulations affecting our distribution operations and the risks they pose for our business.
Consolidation of Electricity Distribution Networks
      The Bersani Decree included provisions for the consolidation of distribution networks in municipalities served by more than one electric utility, giving certain municipal networks the right to request that we sell our distribution network in their municipalities. As a consequence, we have been forced to sell to a significant number of these networks in the past few years. In 2005, we sold local distribution networks to one municipality, serving a total of approximately 9,600 clients and having an annual sales volume of approximately 160 million kWh, for an aggregate consideration of approximately 14 million. From January 1, 2001, through December 31, 2005, we sold a number of local distribution networks, including those in the Rome, Milan and Turin metropolitan areas, serving an aggregate of approximately 1.90 million customers, for aggregate consideration of approximately 1,903 million. At the same time, we acquired the distribution networks of 62 other small municipalities, serving an aggregate of approximately 22,762 clients, for aggregate consideration of 18.6 million. Negotiations are currently pending regarding our sale of the distribution networks of 27 small municipalities and our acquisition of the distribution networks of certain other small municipalities.
      The distribution networks that we sold were more profitable than our average distribution network, mainly because distribution in metropolitan areas has lower costs because of the high customer concentration. In 2004, the Energy Authority put in place a mechanism to compensate affected distributors for some of the comparative disadvantages of serving non-urban areas. Please see “— Regulatory Matters — Electricity Regulation — The Tariff Structure.”
      In addition to the divestitures carried out pursuant to the Bersani Decree, on December 31, 2003, we sold our network in Brescia and 45 neighboring municipalities, which served an aggregate of 100,205 clients and had an annual sales volume of 2.8 billion kWh, for total consideration of 168 million. On June 27, 2006, Enel Distribuzione and Hera S.p.A. (formerly Meta S.p.A.), an Italian energy and waste-management company, agreed on the sale of our electricity distribution and sales activities in 18 municipalities of the province of Modena, serving approximately 80,000 customers, for a total consideration of 107.5 million. The sale will be effective as of July 1, 2006.
      On December 21, 2004, pursuant to the Presidential Decree no. 235/77 and the Legislative Decree no. 463/99, we entered into a settlement agreement with SET Distribuzione S.p.A. (“SET”), a company controlled by the Province of Trento, providing for our sale to SET of our local distribution network in that province. In 2003, local authorities had issued an expropriation order that was intended to force us to transfer to SET this electricity distribution network, which comprises approximately 6,700 kilometer of distribution lines and 3,000 substations, serves approximately 223,000 customers and employs approximately 250 people. We had appealed this order to the Administrative Tribunal of Trentino Alto Adige. In accordance with the settlement agreement, we sold this network to SET for total consideration of 169 million on July 1, 2005.
      We are currently in negotiations with the Province of Bolzano for the sale of our local distribution network in that province.

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Sales to Regulated Electricity Market
      The regulated market for electricity sales in Italy consists of:
  •  All Non-Eligible Customers, or customers who do not meet the consumption threshold for participation in the free market; and
 
  •  Those Eligible Customers, or customers who meet the consumption threshold for participation in the free market, that choose not to participate in it.
      The consumption threshold for qualification as an Eligible Customer, which is set by regulation, has decreased over time, reducing the number of customers who must buy electricity on the regulated market. Please see “— Regulatory Matters — Electricity Regulation — Eligible and Non-Eligible Customers” for further information. The Marzano Law provides for the complete liberalization of sales in the electricity market from July 1, 2007, when all customers will be eligible to purchase electricity on the free market. The law provides that the Single Buyer will nonetheless continue to supply electricity to consumers who choose not to leave the regulated market.
      The following table sets forth the amount of electricity we distributed to the free market and the amount of electricity we distributed and sold on the regulated market in 2004 and 2005, excluding sales to resellers, broken down by type of distribution line, as well as the revenues generated by these activities. Revenues for electricity distributed to the free market represent transport charges, while revenues from sales to the regulated market represent both transport charges and the cost of electricity sold. The breakdown by type of distribution line reflects the breakdown made by the Energy Authority in establishing tariff categories. Please see “— Regulatory Matters — Electricity Regulation — The Tariff Structure” for additional information on electricity tariffs.
                                                                   
    2004   2005
         
        Distributed           Distributed    
        and Sold           and Sold    
    Distributed   on the       Distributed   on the    
    to the Free   Regulated       to the Free   Regulated    
    Market   Market   Total   Revenues   Market   Market   Total   Revenues
                                 
        (In GWh)       (Millions       (In GWh)       (Millions
                of euro)               of euro)
High voltage(1)
    45,083       4,827       49,910       529       46,212       5,319       51,131       611  
Medium voltage
    63,372       23,966       87,338       2,782       67,060       20,247       87,307       2,641  
Low voltage
    5,236       108,168       113,404       11,791       8,098       104,111       112,209       12,260  
                                                 
 
Total
    113,691       136,961       250,652       15,102       121,370       129,677       251,047       15,512  
                                                 
 
(1)  High-voltage sales on the regulated market are sales to the Ferrovie dello Stato, the Italian railway system. All high-voltage customers are Eligible Customers.
      In 2005, the volume of electricity we distributed to customers connected to high voltage lines, generally large industrial customers, increased by 2.4%, reflecting increasing industrial activity in Italy during the year.
      For medium-voltage lines, which generally serve medium-sized businesses, electricity distributed and sold on the regulated market decreased by 15.5%, primarily reflecting the significant increase in the number of customers eligible to participate on the free market in 2005, many of whom migrated to that market. As a result of this migration, distribution of electricity to the free market over medium-voltage lines increased by 5.8%.
      The amount of electricity we distributed to the free market over low-voltage distribution lines, which generally serve small business and residential customers, increased by more than 50% in 2005. Reflecting the extension of Eligible Customer status to all non-residential customers as of July 1, 2004. Electricity distributed and sold to low-voltage customers on the regulated market decreased by 3.7%, reflecting mainly the fact that in 2004 we had billed customers for the energy we had dispatched to them, but for which we had not billed them, during 2003 and 2004 following the introduction of a method that allowed us to determine how much electricity had been dispatched but not billed.

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      On April 1, 2004, a new pool market for the trading of electricity, the Italian power exchange, became operational as part of the continuing liberalization of the Italian electricity market. Under the new system, generation companies may sell their electricity on the Italian power exchange or through bilateral contracts with other market participants. In addition, as part of the new system, the Single Buyer, a company wholly owned by the GRTN, is now responsible for ensuring the supply of electricity to customers who purchase their electricity on the regulated market. As a result, our generation companies are now required to sell electricity destined for regulated customers to the Single Buyer, and our distribution companies are now required to purchase electricity to be distributed and sold on the regulated market from the Single Buyer. Please see “— Regulatory Matters — Electricity Regulation — The Italian Power Exchange” and “— Regulatory Matters — Electricity Regulation — The Single Buyer” for additional information.
Telemanagement System
      Since 1999, we have been rolling out our “Telemanagement” digital metering system in Italy, in order to create an integrated system able remotely to manage and read electricity meters. This system is intended to help us (i) reduce costs associated with physical measurement of consumption and on-site maintenance of meters by our personnel, as these tasks would be accomplished remotely; (ii) measure more accurately the electricity consumption of our customers; (iii) improve our response times in providing technical assistance to our customers; and (iv) offer our customers diversified tariff plans that promote the use of electricity in off-peak periods.
      As of December 31, 2005, we had approximately 27 million digital meters installed, of which approximately 25 million were already remotely connected to our system. Please see “— Capital Investment Program — Sales, Infrastructure and Networks” for additional information on the roll-out of this system and the related capital expenditures we have incurred. As of March 31, 2006, we had installed 27.6 million digital meters, of which approximately 25.5 million were connected to the remote network. To complete the roll-out, we still must install an additional 3.5 million meters and remotely connect 4.5 million meters to the system.
      The Telemanagement system has permitted Enel Distribuzione, starting in 2004, to launch new tariff options for residential customers tailored to customers’ consumption habits. The Telemanagement system permits us to monitor precisely when a customer is consuming electricity and apply and bill the relevant peak/off-peak prices. In particular, we offer a so-called “Night and Day” tariff, which sets electricity prices according to the time of day in which customers use electricity, allowing them to control more effectively their electricity expenses. In 2005, we launched two additional tariff options, the so-called “One” tariff, tailored for customers with low consumption who prefer to pay a flat fee, and the so-called “August” tariff, tailored for customers with a holiday house, to permit them to pay for electricity service only for the period in which they use their property.
Customer Service
      Providing high-quality customer service is an important part of our commercial strategy. In recent years, Enel Distribuzione has reorganized its sales network to change the manner in which customer relations are managed. We have expanded our customer services to provide customers with access to us through a number of different channels, and we have introduced specialized departments to manage relations with corporate and individual customers. Among other things, we have a customer call center, targeted primarily at individual consumers, and provide a self-service area through our Internet portal. The call center is supported by both a national documentation center located in southern Italy, which receives, processes and electronically files all contractual documentation, and by a national printing center, which prints and distributes all correspondence with customers. As of December 31, 2005, our customer service network also included approximately 130 retail locations managed directly by Enel Distribuzione, 190 key account managers dedicated to mid-size business customers and 1,000 “QuiEnel” retail locations, which include QuiEnel points in Enel.si and Wind stores and in approximately 200 post offices.

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Continuity and Quality of Network Service
      The Energy Authority has issued guidelines setting targets for electricity service continuity (based on minutes of service interruptions per year) and quality (such as waiting time for appointments). The Energy Authority has also instituted a system that grants bonuses to companies that exceed targets for continuity of service or lack of service interruptions, and imposes penalties on companies that fail to meet them. Please see “— Regulatory Matters — Electricity Regulation — Continuity and Quality of Service Regulation.”
      Distributors that outperform the targets are paid their bonuses through a component of the tariff structure. We have on average consistently exceeded our continuity of service targets, and received resulting bonus payments, for each year since 2000. In 2005, we received a 63 million bonus for having outperformed the continuity of service targets in 2004. We estimate that in 2005, our average duration of service interruptions per customer decreased to 64 minutes, or by approximately 11%, from 72 minutes in 2003, largely as a result of improvements in the accuracy of the method we use to calculate this measure. We expect to receive, in the second half of 2006, at least 85 million in bonus payments with respect to continuity of service for 2005.
      In May 2005, the Energy Authority issued proposals for public comment for the institution of a system of automatic compensation payable by electricity distributors to affected customers in the event of a blackout or other widespread and prolonged service interruption. Please see “— Regulatory Matters — Electricity Regulation — Continuity and Quality of Service Regulation.”
Sales of Electricity to the Free Market
      Since July 1, 2004, all Italian non-residential customers (approximately 7 million consumers) have qualified as Eligible Customers, and may choose to purchase electricity on the free market.
      According to our internal estimates, total Italian electricity consumption on the free market increased by approximately 6% in 2005 to 136 TWh, representing approximately 47% of total Italian electricity consumption for the year. We believe our share of the free market in 2005 was approximately 14% (as compared to 16% in 2004). In 2005, approximately 79% of the electricity distributed in Italy was distributed to Eligible Customers. We currently expect that in 2006, total Italian electricity consumption on the free market will be approximately 151 TWh, or approximately 51% of total Italian electricity consumption for the year.
      In 2005, Enel Energia continued to focus its operation on sales to Eligible Customers with annual consumption up to 100 GWh. Enel Energia sold 8.4 TWh of electricity to Eligible Customers during 2005, generating revenues of 812 million. The amount of electricity sold by Enel Energia on the free market in 2005 was approximately 13% higher than the 7.5 TWh sold in 2004, which generated revenues of 648 million. Consumers with annual consumption above 100 GWh are served by Enel Trade in our Generation and Energy Management Division. In 2005, Enel Trade sold approximately 10.1 TWh of electricity to Eligible Customers, as well as 3.8 TWh to resellers in Italy. In 2004, Enel Trade sold approximately 13.4 TWh of electricity to Eligible Customers, and 5.5 TWh of electricity to resellers, who since April 1, 2004, have generally purchased their electricity directly from the Single Buyer.
      The progressive liberalization of the Italian electricity market requires that Enel Energia provide its customers with increasingly flexible and competitive services that go beyond providing a reliable supply of electricity.
      As part of our marketing efforts, we have implemented a series of customer initiatives including:
  •  specially tailored contract terms for different types of customers; and
 
  •  value-added services such as energy monitoring and management.
International Distribution and Sales Operations
      In 2005, the international activities of our Sales, Infrastructure and Networks Division included our electricity distribution and sales activities outside of Italy. Following the re-organization of our internal structure effective as of January 1, 2006, these international operations are no longer included in our Sales, Infrastructure

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and Networks Division (now the Market Division and Infrastructure and Networks Division), but are carried out by our new International Division.
      We carry out our international distribution and sales activities in Spain through our wholly owned subsidiaries Electra de Viesgo Distribuciòn SL and Enel Viesgo Energia SL, and in Romania through Enel Electrica Banat S.A and Enel Electrica Dobrogea S.A. On April 28, 2005, Enel Distribuzione acquired a 51% interest in each of Electrica Banat S.A (now Enel Electrica Banat S.A.) and Electrica Dobrogea S.A. (now Enel Electrica Dobrogea S.A.), purchasing approximately 25% of each of these companies’ share capital from Electrica S.A., a Romanian state-owned company, and simultaneously subscribing to a capital increase of approximately 26% in each of these companies for an aggregate consideration of 131 million (including price adjustments).
      In accordance with EU law, electricity sales in Spain are also divided between a free and a regulated market. Please see “— Regulatory Matters — Electricity Regulation” for a discussion of relevant EU law. In 2005, our sales of electricity in Spain amounted to 4,861 GWh (compared to 3,709 GWh in 2004), of which 3,576 GWh were sold by Electra de Viesgo Distribuciòn SL to the regulated market and 1,285 GWh by Enel Viesgo Energia SL to the free market (compared to 749 GWh in 2004). In addition, Electra de Viesgo Distribuciòn SL owns 29,662 kilometers of distribution network and it distributed 5,196 GWh of electricity in 2005 (compared with 4,952 GWh in 2004) to 625,000 customers in the Spanish regulated market (611,000 customers in 2004).
      Enel Electrica Banat S.A., which operates in western Romania, and Enel Electrica Dobrogea S.A., which operates in eastern Romania, own an aggregate of 80,100 kilometers of distribution network and in 2005 distributed 4,455 GWh of electricity in the Romanian regulated market to 1,441,000 customers. In 2005, these companies sold 3,232 GWh of electricity, mostly in the regulated market. We expect these two companies to undertake major investment programs to improve their distribution networks in order to increase efficiency and the quality of service.
      In June 2006, we won the auction for a 67.5% stake in the Romanian power distribution company Electrica Muntenia Sud (“EMS”), an electricity distribution company with 1.1 million customers and a 45,350 kilometer distribution grid in the region of Bucharest, Romania, for total consideration of 820 million. Upon the successful completion of this transaction, we expect to serve approximately 2.5 million customers in Romania.
      In addition, in June 2006 we acquired from the ESN Group a 49.5% interest in Res Holding, a Dutch company holding 100% of the Russian power sale company RusEnergoSbyt for total consideration of $105 million (corresponding to approximately 88 million). The company had approximately 11TWh of annual sales in 2005.
      The following table shows our international electricity sales on the regulated and free markets in Spain and Romania, as well as the electricity dispatched on our foreign distribution networks in Spain and Romania, in each of the years indicated. Information about Romania is provided only from the date of our entry in this market on April 28, 2005.
                         
    2003   2004   2005
             
Electricity sales (TWh)(1)
    3.943       4.458       8.093  
Electricity sales on the regulated market (TWh)(1)
    3.734       3.709       6.766  
Electricity sales on the free market (TWh)(1)
    0.209       0.749       1.327  
Electricity transported on our distribution networks (TWh)(2)
    4.741       4.952       9.651  
 
(1)  Excluding sales to resellers
 
(2)  Excluding electricity distributed to resellers
Public and Art Lighting
      Enel Sole operates our public lighting services in Italy. Enel Sole targets the general market for public lighting, as well as the market for customized lighting systems for monuments, public squares, churches and

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other landmarks and public spaces. Enel Sole offers both indoor and outdoor lighting systems, and provides maintenance services for the systems and the related electricity plants.
      In 2005, Enel Sole built lighting systems for third parties with an aggregate value of approximately 36 million. In addition, Enel Sole signed new contracts for approximately 89,000 public lighting points throughout Italy in 2005. As of December 31, 2005, Enel Sole managed approximately 1.8 million public lighting sites in more than 4,000 client municipalities.
Electricity Systems-related Services
      Enel.si offers our clients electricity systems-related services through a franchising network made up of selected companies which operate in the electrical maintenance and installation business. Enel.si franchises draw on the technical capabilities of the Enel Group to assist clients in optimizing their use of electricity, as well as to offer them consulting and personnel training services.
      At the end of 2005, Enel.si had a total of 404 franchise stores focusing on the retail market (residential and small office/home office customers), offering services and products aimed at providing safety (such as safer electrical installations and security systems), energy efficiency (such as air conditioning, heating, and home automation systems) and environmentally friendly energy systems (such as solar, thermal and small photovoltaic plants).
      Enel.si also provides business customers full assistance with their energy facilities, including construction and maintenance services for small co-generation power plants and medium-large photovoltaic plants.
Gas Distribution and Sales
      We distribute and sell natural gas to end users in Italy through:
  •  Enel Rete Gas and other minor companies, which own local distribution networks in specific parts of Italy and hold the related concessions for their use; and
 
  •  Enel Gas and Easygas (which we acquired in October 2005), which sell natural gas to end users.
      The Italian natural gas market is undergoing a process of liberalization. Under current legislation, the natural gas market was supposed to have been completely liberalized as of January 1, 2003, with all consumers able to freely choose their supplier and all sellers able to freely set prices to all customers. However, while all consumers are now able to freely choose their supplier, the Energy Authority retained the right to control prices for certain, mainly household consumers that qualified as Gas Non-Eligible Customers as of January 1, 2003. Please see “— Regulatory Matters — Gas Regulation” for a more detailed discussion of gas regulation in Italy.
      While full market liberalization is still developing, we believe that the most effective way for us to build our natural gas business is through acquisitions of other distributors or client bases. We believe that expanding our natural gas distribution activities offers us opportunities for potential synergies, including, for example, the ability to schedule and perform gas and electric network maintenance and upgrades in the same area at the same time and the ability to use call centers for both gas and electricity customers, as well as certain competitive advantages, including potential cost savings from economies of scale. Since March 2005, we have offered Eligible Customers in several Italian cities, including Rome and Milan, “dual fuel” contracts, providing electricity and gas service through one sales network, with one customer service department and one bill.
      We have acquired several gas distribution companies with operations in various Italian regions over the past several years. These acquisitions include those of the Colombo Gas Group in 2000, So.ge.gas and Agas in 2001 and Camuzzi Gazometri (subsequently renamed Enel Rete Gas) in 2002. Through these acquisitions, as of 2003, we had become the second-largest operator in the Italian gas distribution market, second only to Eni’s subsidiary, Italgas, the incumbent provider, according to a study of the Italian gas industry by Anigas (the Italian association of gas distribution companies) published in 2005. In acquiring Camuzzi Gazometri, we acquired both significant gas distribution assets and Camuzzi Gazometri’s waste management operations. In February 2004, we sold Camuzzi’s waste management operations, the Aimeri Group, to Green Holding for approximately 14 million.

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      In January 2004, we acquired Sicilmetano and Sicilmetano Energy, which distributed and sold natural gas to 37,000 customers in Sicily, for 40 million. On September 15, 2004, we acquired from Metanambiente 100% of two gas companies — a distribution company, Ottogas Rete, and a sales company Ottogas Vendita — for an aggregate purchase price of 31.5 million. These companies together have approximately 36,000 customers in the provinces of Naples and Salerno. In December 2004, we acquired 100% of Italgestioni, a distribution company, and Italgestioni Gas, a sales company, which together serve approximately 34,000 customers in 83 municipalities in the provinces of Calabria and Naples, for 32 million.
      On December 31, 2004, Enel Distribuzione Gas, GE.AD. and Sicilmetano were merged into Enel Rete Gas and Sicilmetano Energy was merged into Enel Gas. On June 30, 2005, Ottogas Rete, Italgestioni and other minor companies were merged into Enel Rete Gas, and Ottogas Vendita and Italgestioni Gas were merged into Enel Gas.
      In October 2005, we acquired two companies from Italtecna, Metanodotti Padani, a distribution company, and Easygas, a sales company, for an aggregate purchase price of about 23 million. These companies together have approximately 19,000 customers in the northern Italian provinces of Rovigo, Padova, Trento, Mantova, Ferrara and Modena. In January 2006, we acquired from Thüga (an Italian subsidiary of the E.On Group) the distribution company Simeo, which serves approximately 24,000 customers in Sicily, for approximately 37 million. We intend to merge Metanodotti Padani and Simeo into Enel Rete Gas, and Easygas into Enel Gas, by December 31, 2006.
      As of December 31, 2005, we offered natural gas distribution services in 1,205 municipalities (as compared to 1,188 in 2004) and operated on approximately 29,869 kilometer of network. In 2005, we distributed 333 million cubic meters of natural gas on behalf of gas companies that are not part of the Enel Group (as compared to 139 million in 2004) and 3.6 billion cubic meters to end users on behalf of gas companies of the Enel Group (as compared to 3.7 billion in 2004). As of December 31, 2005, we distributed natural gas to 1,983,741 end users (as compared to 1,966,264 in 2004), or approximately 8% of natural gas customers in Italy, based on figures provided by Anigas, the Italian association of gas distribution companies.
      In 2005, we sold approximately 5.1 billion cubic meters of natural gas to more than 2.1 million end users (as compared to the approximately 5.2 billion cubic meters of natural gas sold to nearly 2.0 million end users in 2004), representing 10.5% of natural gas customers in Italy. The following table shows the total amount of natural gas we sold to end users in 2004 and 2005 in millions of cubic meters, and the number of customers to whom these sales were made, broken down by type of customer.
                   
    2004   2005
         
Retail (millions of m3)
    2,783       3,021  
Business
    2,403       2,068  
             
 
Natural gas sold
    5,186       5,089  
Retail
    1,963,577       2,140,865  
Business
    2,038       2,129  
             
 
Number of customers
    1,965,615       2,142,994  
      These figures do not include the 1.6 billion cubic meters and 1.7 billion cubic meters of natural gas sold to third parties in 2005 and 2004, respectively, by Enel Trade, which is part of our Generation and Energy Management Division.
Competition in the Electricity and Gas Markets
      We face competition in the markets for electricity generation, and sales of electricity and natural gas. Instead, there is no competition in the market for electricity or gas distribution, which are natural local monopolies.
      Electricity generation. In 2005, we accounted for approximately 39% of Italian electricity production. We purchased approximately 35% of the electricity imported into Italy, and also purchased electricity produced by

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independent power producers and electricity produced from renewable resources under the CIP 6 regime, which the GRTN buys from producers and resells at auction on the free market.
      As a result of limitations on the production and import of electricity imposed by the Bersani Decree, we were required to sell plants with a total installed net capacity of at least 15.0 GW by January 1, 2003. In order to comply with the requirement, we created and sold the Gencos, after transferring an aggregate of approximately 16.0 GW of gross installed capacity to them. At December 31, 2005, we estimate that we had approximately 49% of total Italian net installed capacity, as compared to approximately 75% at the start of 2001.
      The disposal of the Gencos has exposed us to increasing competition from other generating companies. Our competitors also include domestic independent power producers, municipal utility companies and foreign operators that have acquired Italian generation assets or export electricity to the Italian market. In addition to the introduction on April 1, 2004, of trading on the Italian power exchange, we expect that competition will increase further due to:
  •  An increase in bilateral contracts between our competitors and final customers;
 
  •  Regulations limiting each operator’s access to international electricity sources to a maximum percentage of available interconnection capacity; and
 
  •  The development of new interconnection lines that will increase the volume of electricity that may be imported in Italy. Through 2005, other producers were authorized to build approximately 20 GW of new generating capacity in Italy, of which approximately 6 GW is already operational, and another 8 GW is expected to be operational by 2010. For imports, we expect an additional 2.1 GW of capacity to become available between 2006 and 2010, of which 1.3 GW of import capacity has already become available.
      In addition, on May 7, 2005, the Energy Authority issued for public comment proposals for possible measures to promote competition in the wholesale electricity market and limit the impact of market power held by dominant producers. Please see “— Regulatory Matters — Electricity Regulation — The Italian Power Exchange” for additional information on these proposals.
      Our main competitors in Italy are Edison, the three former Gencos — Edipower, Endesa Italia and Tirreno Power — and Eni. According to their respective annual reports, in 2005 Edipower had a reported installed capacity of 8.3 GW, Edison had a reported capacity of 6.9 GW, Endesa Italia had a reported capacity of 6.6 GW, Eni had a reported capacity of 4.7 GW and Tirreno Power had a reported capacity of 3.3 GW.
      The following table sets forth the main energy producers in Italy and the amount of energy they produced in 2005 in GWh. It also shows this production as a percentage of the total amount of energy produced in Italy during the year, as well as the percentage of the electricity demand in Italy during the year that was met by such production. Italian electricity demand has historically exceeded the amount of electricity produced in the country each year, with the difference being made up through electricity imports.
                           
        Percentage of Total   Percentage of
Producer   2005 Production   Italian Output   Demand
             
    (GWh)        
Enel
    112,087       39 %     31 %
Former Gencos
    52,162       18 %     16 %
Edison*
    33,369       11 %     10 %
Eni
    25,000       9 %     8 %
Main municipal electricity companies*
    10,596       4 %     3 %
Other independent power producers
    56,441       19 %     17 %
                   
 
Total production in Italy
    289,655       100 %      
Pumped storage consumption
    (9,369 )            
Net imports
    49,155             15 %
                   
 
Total demand in Italy
    329,441             100 %
                   

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Source:  Enel elaboration based on provisional data for Italy from Terna, and publicly available information of other producers.
Excluding stakes in former Gencos.
      The following table shows the main energy producers in Italy and our estimates of the net installed capacity of each producer in GW, as well as the total net installed capacity in Italy, for each of the years indicated.
                   
Net Installed Capacity (GW) by Producer   2004   2005
         
Enel
    42.0       42.2  
Former Gencos
    17.5       18.2  
Eni
    3.6       4.7  
Edison*
    5.7       6.9  
Main municipal electricity companies*
    2.8       4.0  
Other independent power producers
    9.8       10.7  
             
 
Total net installed capacity in Italy
    81.5       86.8  
             
 
Source: Enel estimates.
Excluding stakes in former Gencos.
      The main municipal electricity companies are AEM S.p.A. of Milan, ACEA S.p.A. of Rome, AEM Torino S.p.A. and ASM Brescia S.p.A. They are each publicly traded, but remain majority-owned by the relevant municipality. In addition to their electricity businesses, these companies offer gas and/or water services.
      Electricity sales on the free market. For sales on the free market, we compete with independent and other power producers, importers, wholesalers and brokers. We expect competition in the free market to increase further following the Energy Authority’s decision to permit all non-residential customers to qualify as Eligible Customers as of July 1, 2004 and to allow residential customers access the market from July 1, 2007.
      Gas sales. In our natural gas business, we compete mainly with Eni, the incumbent operator that historically held a monopoly for natural gas distribution and sales activities in Italy and continues to hold a significant majority of the overall market for such activities. In 2005, our share of the market for natural gas sales to end users, based on number of customers served, was 10.5%.
      The Italian gas market is currently going through a process of liberalization. Please see “— Regulatory Matters — Gas Regulation” for a discussion of the regulation of the gas market.
Seasonality of Electricity and Gas Consumption
      Electricity and gas consumption in Italy is somewhat seasonal. Since use of artificial light is highest in winter, electricity and gas consumption peaks during winter months. Nevertheless, increased use of air conditioning has rendered less significant the difference in electricity demand during winter versus summer months, and increased use of natural gas for industrial production has rendered less significant the difference in gas demand during winter versus summer months. Electricity and gas consumption is particularly low in August, the traditional vacation period in Italy.
Discontinued Operations
      In 2005 we discontinued the operations of our former Telecommunications Division and Transmission Division, following the deconsolidation of Wind and Terna, respectively, as a result of our disposal of a controlling interest in these companies.

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Telecommunications
      Our Telecommunications Division consisted of Wind and its subsidiaries. Wind is a telecommunications company providing mobile and fixed-line telephony, Internet and data transmission services in Italy.
      In line with our strategy of focusing on our core energy operations, in May 2005 we entered into an agreement for the sale of Wind to Weather Investments in a series of transactions. Weather Investments is a private consortium headed by Naguib Sawiris, who controls Orascom, an Egypt-based mobile phone operator that provides telecommunications services in the Middle East, Africa and Asia and is listed on the London Stock Exchange and the Cairo and Alexandria Stock Exchange. On August 11, 2005, we completed the first part of the transaction, which consisted of our sale of a 62.75% stake in Wind to one of Weather Investments’ subsidiaries for 2,986 million plus the acquisition by us of a 5.2% stake in Weather Investments through our subscription to a 305 million capital increase. On February 8, 2006, we completed the transaction by selling to one of Weather Investments’ subsidiaries an additional 6.28% stake in Wind for 328 million, and thereafter, transferring to Weather Investments the remaining 30.97% stake in Wind in exchange for shares representing 20.9% of Weather Investments’ share capital. As a result of these transactions, we no longer have any direct interest in Wind and we received an aggregate cash consideration of 3,009 million and a 26.1% interest in Weather Investments. We view this holding in Weather Investments solely as a financial investment. In addition, we entered into a shareholders’ agreement with Weather Investments II S.a.r.l., Weather Investments’ controlling shareholder, which provides for an initial public offering of Weather Investments when market conditions are favorable, and for both our and Weather Investments II S.a.r.l.’s undertakings, subject to certain exceptions, not to sell any share of Weather Investments before the initial public offering. Moreover, the shareholders’ agreement grants de facto consent rights to identified directors (including directors designated by us) over certain transactions taken by Weather Investments or its subsidiaries (for example, transactions effected to incur additional indebtedness or to sell certain material assets).
Transmission
      We use the term “transmission” to refer to the transport of electricity on high and very high voltage interconnected networks from the plants where it is generated (or, in the case of imported energy, from the points of acquisition) to distribution systems.
      Our Transmission Division consisted of Terna and its subsidiaries. Terna owns a large majority of the Italian national transmission grid. In light of Italian laws and regulations that require the reunification of the ownership and management of the Italian transmission grid and impose certain restrictions on its ownership and management, we have disposed of most of our interest in Terna retaining only 5.12% of its share capital. In particular, in June 2004, we sold 50% of Terna’s share capital in an initial public offering in Italy and a private placement with certain institutional investors that was not registered under the Securities Act (the “Terna IPO”). In April 2005 we sold an additional 13.86% of Terna’s share capital in the context of a private placement and in September 2005 an additional 29.99% to Cassa Depositi e Prestiti. Finally, in January 2006, we distributed 1.02% of Terna’s share capital as “bonus” shares that we had promised to certain Italian retail investors as part of the Terna IPO. Please see “Item 5. Operating and Financial Review and Prospects — Analysis of Operating Results — Operationg Expenses — Income/ Loss from Discontinued Operations —” and note 5 to consolidated financial statements for information on the results of our telecommunications and transmission discontinued operations.
Services and Other Activities
      In line with our strategy of focusing on our core energy operations, we divested certain of our non-core operations, including real estate and water activities, and are refocusing our remaining non-core operations on providing services to the companies of our Group rather than third parties.
      We set forth below a description of the other services and other activities of the Group in 2005.

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Services
      In accordance with our new core-business-oriented strategy, in 2004 we undertook a specific project aimed at centralizing responsibility for all of our services and staff activities, as well as improving quality and efficiency, including through the creation of shared services. As part of this process, in January 2005 we merged our wholly owned services companies, Enel Facility Management (real estate and other services) and Enel.it (information technology) into Enel Servizi (formerly Enel Ape), and transferred to Enel Servizi the Information & Communication Technology (“ICT”) units of Enel Produzione and of Enel Distribuzione.
      In the first half of 2005, Enel Servizi became responsible for the internal service and administration functions (and related personnel) of the main Group companies. Moreover, Enel Servizi provides information technology services for Group companies and, in 2005, focused on certain strategic projects, including:
  •  supporting Enel Distribuzione in completing the roll-out of the Telemanagement system for remote metering; and
 
  •  developing a disaster recovery system to enhance the stability and performance of critical information technology applications.
      Enel Servizi is also responsible for managing personnel payrolls, pension funds and social security funds and providing related administration services for Group companies. Finally, Enel Servizi offers third parties services similar to that provided to Group companies. In 2005, Enel Servizi recorded revenues of approximately 820 million, of which approximately 69 million related to services provided to third parties.
Engineering and Construction
      In 2004 and 2005, we conducted our engineering, procurement and construction, or EPC, operations through Enelpower.
      Enelpower served as the primary EPC contractor for our Generation and Energy Management Division. Effective January 1, 2006, EPC activities related to our Generation and Energy Management Division were transferred to Enel Produzione. Other than completing third-party projects to which it had already committed, Enelpower does not provide services to third-parties, either domestically or internationally in line with our strategy of focusing on our core energy operations.
      In 2005, Enelpower recorded revenues (including advances on contract work in progress) of 804 million, approximately 37% of which was for third-party projects compared to revenues of 973 million in 2004, approximately 64% of which was for third-party projects.
Real Estate and Other Services
      On July 14, 2004, we sold the entire share capital of NewReal, a company to which we had transferred real estate assets, to a consortium formed by an investment fund belonging to the Deutsche Bank group and CDC-IXIS for a total consideration of 1,400 million. Before the closing of this transaction, NewReal transferred real estate assets with a net book value of approximately 384 million to another of our real estate subsidiaries, Dalmazia Trieste.
      At December 31, 2005, Dalmazia Trieste owned most of our real estate assets, with a net book value of approximately 695 million. Our goal is to exploit the opportunities available with respect to properties used by the Group and to divest all of the Group’s residential properties by 2010.
Factoring
      Our subsidiary Enel.factor is responsible for managing receivables owned by third parties against companies of the Group. In January 2005, we acquired 20% of Enel.factor’s share capital from Meliorbanca, an Italian bank, for approximately 7 million, becoming its sole shareholder.

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Professional Training Services
      Our subsidiary Sfera is responsible for providing professional training services to our employees. In 2001, Sfera launched an integrated remote training system for our employees (Enel Distance Learning System), reaching 39,056 registered users at the end of 2005. In 2005, Sfera provided a total of 74,252 “full-time equivalent” classroom days of instruction.
Water
      In 2004, we continued with the divestiture of our water activities, agreeing to sell our wholly owned subsidiary Enel.Hydro S.p.A., which included our water initiatives in Calabria and the province of Latina, and 20% of Idrosicilia S.p.A., which operates large scale water transportation activities in Sicily, to Compagnie Générale des Eaux SCA (a subsidiary of Veolia Environnement) for approximately 37 million. These transactions closed on May 10, 2005. Enel and Compagnie Générale des Eaux SCA also entered into a put and call option agreement for the sale to the latter of our remaining 40% stake in Idrosicilia S.p.A. We continue to own Enel.NewHydro, a company we formed in June 2004, which holds a 51% interest in Wisco, a joint venture company we set up with Trenitalia S.p.A. which is active in industrial waste water purification.
Capital Investment Program
      We have summarized in the table below our aggregate capital expenditures on tangible and intangible assets by division during each of 2004 and 2005. During these years, we have not incurred significant capital expenditures with respect to activities of our Corporate sector.
                   
    2004   2005
         
    (In millions of
    euro)
Generation and Energy Management
    857       1,027  
Sales, Infrastructure and Networks
    1,711       1,692  
Transmission
    277       141  
Telecommunications
    867       287  
Corporate and Others(1)
    122       110  
             
 
Total
    3,834       3,257  
             
 
(1)  In 2004 we did not incur capital expenditures with respect to activities of our Corporate sector.
      In 2005, we incurred total capital expenditures on tangible and intangible assets in our core electricity generation, sales and distribution businesses of 2,719 million (of which 2,577 million was spent on tangible assets). In 2005, during the period prior to the deconsolidation of Wind and Terna, we incurred total expenditures in our former telecommunications and transmission businesses of 287 million and 141 million, respectively.
      We have summarized in the table below our aggregate capital expenditures on tangible assets by division during each of 2004 and 2005.
                   
    2004   2005
         
    (In millions of
    euro)
Generation and Energy Management
    842       1,003  
Sales, Infrastructure and Networks
    1,632       1,574  
Transmission
    277       139  
Telecommunications
    680       251  
Corporate and Others(1)
    87       70  
             
 
Total
    3,518       3,037  
             
 
(1)  In 2004 we have not incurred capital expenditures with respect to activities of our Corporate sector.

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      For the period 2006-2010, we expect to incur capital expenditures on tangible and intangible assets for the Enel Group of approximately 18.6 billion. Of this total, we expect to incur capital expenditures of approximately 3,643 million in 2006 and approximately 4,168 million in 2007. We expect to cover our capital expenditures in the 2006-2010 period with our cash flow from operations.
      The following discussion analyzes in greater detail the capital expenditures in 2005 of each of our divisions, focusing on tangible assets, which are the most significant part of our capital investments in our core electricity and gas operations.
Generation and Energy Management
      In 2005, the Generation and Energy Management Division’s capital expenditures on tangible assets were 1,003 million, an increase of 161 million, or 19.1%, from 842 million in 2004. Of the expenditures in 2005, 990 million were on the maintenance, upgrading and repowering of generation plants, including 768 million in Italy and 222 million abroad. These expenditures included:
  •  In Italy, the ongoing process of conversion of our approximately 1,900 MW oil-fired plant at Torrevaldaliga North to clean coal technology, on which we spent approximately 159 million during the year, and of construction of fluidized bed combustion facilities at a section of our power plant at Sulcis with approximately 300 MW of net installed capacity, on which we spent approximately 54 million. We also continued implementing our strategic plan to increase investment in renewable generation facilities (wind, hydroelectric, geothermal), spending approximately 280 million in 2005. Of this amount, we spent 133 million on capital improvements that we expect will allow us to comply with regulations requiring us to provide a specified amount of “green certificates” each year; and
 
  •  In our international operations, the development of Uniòn Fenosa’s generation facilities (approximately 111 million), the improvement of Enel Viesgo Generatiòn’s plants (approximately 51 million, of which we invested 32 million in new projects), the Maritza East III’s ongoing plant refurbishment project (approximately 45 million), Enel Latin America’s new projects (approximately 12 million), as well as regular maintenance and other minor expenditures to improve the capacity, efficiency and productivity of plants in North America (approximately 5 million).
      Overall, our Generation and Energy Management Division, which effective as of January 1, 2006 no longer includes our international generation operations (which now form part of our new International Division) expects to invest approximately 6,800 million on tangible and intangible assets in the 2006-2010 period. We expect to make approximately 4,300 million of our expenditures on tangible assets on the ongoing implementation of our program to convert oil-fired thermal generation plants to CCGT or to burn coal. In particular:
  •  For CCGT conversions, we have completed the conversion of approximately 4,300 MW and plan to continue the CCGT conversion program, with the most significant projects at our Santa Barbara and Termini Imerese power plants (for approximately 750 MW); and
 
  •  For coal conversions, we plan to continue the conversions of our thermal generation plants at Torrevaldaliga North, finish our trial phase in Sulcis, and begin similar conversions of certain other power generation units, expected to affect in the aggregate approximately 4,100 MW of net installed capacity. The conversion plans for approximately 1,900 MW of this amount are still subject to regulatory approval.
      We also plan to invest approximately 1,300 million in the 2006-2010 period on developing generation from renewable resources.
      See “Capital Expenditures for the International Division in the 2006-2010 period” below for a description of the capital expenditures we have planned with regard to international distribution and sales for the 2006-2010 period.
Sales, Infrastructure and Networks
      Capital expenditures on tangible assets in our Sales, Infrastructure and Networks Division (which we have split into a Market Division and an Infrastructure and Networks Division) decreased 3.6% to 1,574 million in

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2005, from 1,632 million in 2004. Capital expenditures on our Italian electricity distribution networks decreased 5.2% to 1,319 million in 2005, from 1,391 million in 2004, reflecting more selective investing in quality improvements in light of the service continuity levels already achieved. Amounts spent on our distribution network in 2005 included approximately 464 million relating to our “Telemanagement” digital meter project. Please see “— The Enel Group — Sales, Infrastructure and Networks — Domestic Distribution and Sales Operations — Telemanagement System.” In 2005, we installed 6.2 million additional meters, bringing the total number of meters installed at December 31, 2005, to approximately 27 million (of an expected total of approximately 30.8 million), of which approximately 25 million were already remotely connected to our system. We expect that the Telemanagement project, for which we expect installation of the new meters to be largely completed by the end of 2006, to entail total investments of approximately 2,200 million.
      We plan to invest approximately 5,857 million in tangible assets (6,570 million including intangible assets) in our electricity and natural gas sales and distribution businesses in Italy and abroad in the 2006-2010 period. Of this amount, we expect to invest approximately 2,209 million in promoting new customer connections in our electricity business. We also expect to make investments in our electricity network of approximately 1,215 million to improve service quality, so that we may continue to exceed the targets established by the Energy Authority in those areas in which we are exceeding them, and improve our performance in those areas in which we are not. We expect to invest approximately 731 million in improving load factor and plant safety, of which we plan to invest 624 million in the Telemanagement integrated system. We also plan to invest approximately 338 million in developing our natural gas distribution networks, primarily in new pipelines built either in response to customer requests or as part of our business development policies, as well as in improving the quality of our gas service levels and plant safety.
      Our Market Division and Infrastructure and Networks Division plan to continue their capital expenditures in information technology, in particular on a new, more customer-friendly billing system and to implement internal resource planning software to improve the efficiency of both our distribution activities and our accounting system.
      In 2005, Electra de Viesgo Distribuciòn SL made capital expenditures on tangible assets of 56 million, primarily to upgrade its distribution network in compliance with regulatory requirements. During 2005, we made capital expenditures of 12 million on on tangible assets in Romania, primarily to improve our distribution network.
      See “Capital Expenditures for the International Division in the 2006-2010 period” below for our planned capital expenditures, in the 2006-2010 period, on international distribution and sales operations that are now included in our new International Division.
Services and Other Activities
      With respect to our non-core businesses, we incurred total capital expenditures on tangible and intangible assets of approximately 99 million in 2005, as compared to 112 million in 2004, and expect to incur similar total capital expenditures on tangible and non-tangible assets in 2006.
Transmission and Telecommunications
      All capital expenditures on tangible and intangible assets related to Wind and Terna (287 million and 141 million in 2005, respectively, as compared to 867 million and 277 million in 2004), refer to the period prior to our deconsolidation of these companies following the disposal of our controlling interest in them. Please see “— Business — The Enel Group — Discontinued Operations” for additional information.
Capital Expenditures for the International Division in the 2006-2010 period
      In the 2006-2010 period, we plan to spend approximately 4,808 million on our international operations, of which we plan to spend 4,191 million on our international generation operations and 617 million on our international distribution and sales operations.
      International generation operations. In the 2006 through 2010 period, Enel Viesgo Generaciòn expects to invest approximately 1,334 million, primarily to implement a program to convert certain of its coal plants to

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CCGT. In addition, during the same period, we expect to spend 709 million on further development of our generation capacity from renewable resources at EUFR, 228 million at Maritza East III in Bulgaria, primarily to complete its ongoing plant refurbishment program, and an aggregate of 106 in North America and South America for the development of two new hydroelectric plants in Guatemala, which we expect to become operational between 2006-2009, and on geothermal exploration activities in Chile. Finally, SE expects to invest approximately 1,812 million during the 2006-2010 period, 1,162 million of which it plans to spend on the construction of a new nuclear power plant.
      International distribution and sales operations. In the 2006 through 2010 period, Electra de Viesgo Distribuciòn SL is planning to make capital expenditures of approximately 276 million to improve service performance and network safety, and to implement its own digital meter project. In the same period, we expect to invest approximately 326 million, in line with the plan authorized by the Romanian Authority (ANRE) for the years 2005-2007, in order to improve the quality and the efficiency of our distribution network in Romania.
Regulatory Matters
Overview of Regulation in the Energy Sector in Italy
      The Ministry of Productive Activities and the Energy Authority share responsibility for overall supervision and regulation of the Italian energy sector, comprising both electricity and gas.
      The Ministry of Productive Activities is responsible for establishing the strategic guidelines for the energy sector and for ensuring the safety and economic soundness of the electricity and gas sectors.
      The Energy Authority is responsible for:
  •  setting and adjusting tariffs on the basis of general criteria established by law;
 
  •  advising the Ministry of Productive Activities on the structuring and administration of licensing and authorization regimes for the energy sector;
 
  •  ensuring the quality of services provided to customers;
 
  •  overseeing the separation of utility companies into distinct units for accounting and management purposes;
 
  •  promoting competition; and
 
  •  otherwise protecting the interests of consumers, including the authority to mediate disputes between utilities and consumers, and to impose sanctions for violations of regulations.
      The EU also takes an active role in energy regulation by means of its legislative powers, as well as investigations and other action by the European Commission.
Electricity Regulation
      The regulatory framework for the Italian electricity sector has changed significantly in recent years pursuant to the implementation through the Bersani Decree of the December 1996 EU Electricity Directive.
      The Bersani Decree, which entered into force on April 1, 1999, began the liberalization of the electricity sector through the separation of generation, transmission and distribution activities and the gradual introduction of free competition in power generation and sales to consumers meeting certain consumption thresholds, while maintaining a regulated monopoly structure for power transmission, distribution and sales to the other customers. In particular, the Bersani Decree, among other things,
  •  liberalized, as of April 1, 1999, the generation, import and export of electricity;
 
  •  provided that consumers, or Eligible Customers, meeting certain consumption thresholds, which have been progressively reduced, may negotiate supply agreements directly with any domestic or foreign producer, wholesaler or distributor of electricity, while other, “Non-Eligible Customers” must continue to

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  purchase electricity from the distributor serving the area in which they are located and pay regulated prices determined by the Energy Authority;
 
  •  provided that after January 1, 2003, no electricity company may produce or import more than 50% of the total of imported and domestically produced electricity in Italy, which limit resulted in our sale of the Gencos;
 
  •  provided for the establishment of the Single Buyer, a central purchaser of electricity from producers on behalf of all Non-Eligible Customers;
 
  •  provided for the creation of the Italian power exchange, a virtual marketplace in which producers, importers, wholesalers, the GRTN, other Eligible Customers and the Single Buyer buy and sell electricity at prices determined through a competitive bidding process;
 
  •  provided for the creation of a Market Operator to manage the Italian power exchange;
 
  •  provided for the separation of management and operation of the national electricity transmission grid, which was to be licensed to an independent transmission system operator, the GRTN, from ownership of the grid assets, which were retained by existing owners, primarily Terna; and
 
  •  established a new licensing regime for electricity distribution and provided incentives for the consolidation of electricity distribution networks within each municipality.

      The Bersani Decree was amended following the enactment of a law in October 2003 that provided, among other things, for the reunification of management and operation of the national transmission grid with its ownership under a single private entity. Pursuant to an implementing decree enacted in May 2004, on November 1, 2005 responsibility to manage the national transmission grid and the related assets was transferred from the GRTN to Terna, although the GRTN retained its other responsibilities. Following this transfer, no electricity operator, including us, is entitled to voting rights in excess of 5% with respect to the appointment of Terna’s directors. In addition, the implementing decree required us to reduce our holding in Terna to no more than 20% by July 1, 2007. Accordingly, we have reduced our holding to 5.12%.
      In 2003, the EU adopted a new directive and a related regulation to further liberalize the electricity market. The new Electricity Directive, which replaced the 1996 Electricity Directive, enables all consumers to freely choose their supplier by 2007, irrespective of consumption levels, with all non-household consumers enjoying this right of choice from 2004. Further, the new Electricity Directive introduces new definitions of public service obligations and security of supply, establishes a regulator in all EU member states with well-defined functions, and, finally, requires legal unbundling of network activities from generation and supply. The related EU regulation establishes common rules for the cross-border trade in electricity in the EU, laying down principles on charges to be paid as a result of transit flows and access to networks as well as on congestion management. EU member states were required to implement the new directive by July 1, 2004, and Italy did so partly through the Marzano Law, which is discussed below.
      On September 28, 2004, the Marzano Law (so named after the then-Minister of Productive Activities, Antonio Marzano), a law aimed at reorganizing existing energy market regulation and further liberalizing the natural gas and electricity markets, took effect. Among other things, the Marzano Law aims to clarify the respective roles of the Italian central government, regional and local authorities, and the Energy Authority. The Marzano Law also seeks to facilitate investments in the energy sector. To further liberalize the market, and consistent with the new Electricity Directive, the Marzano Law provides that all customers will be eligible to purchase electricity on the free market from July 1, 2007, although the law provides that the Single Buyer will nonetheless continue to supply electricity to consumers who choose not to leave the regulated market.
      The Marzano Law also authorized the Italian government to limit the ability of companies based in other EU member states to invest in the Italian energy sector if their home country did not adequately guarantee a reciprocal ability for Italian companies to invest in its energy market. The Italian government had already approved such a measure in 2001, which limited the ability of EDF to exercise its voting rights with respect to the stake it held in Italenergia Bis S.p.A., the controlling shareholder of Edison. In June 2005, the European Court of Justice ruled that this limitation was contrary to EU law. However, the Italian government lifted the limitation

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before the European Court of Justice issued its judgment. Accordingly, in July, 2005 EDF and AEM took control of Edison.
      Certain provisions of the Marzano Law concerning the allocation of powers between the Italian national and regional government have been challenged before the Italian Constitutional Court. In 2005, the Constitutional Court rejected an action brought by the Italian Region of Tuscany for interference by the national government with the regional government’s authority. The national government has also challenged a law passed by the Tuscany government for interference with the national government’s authority in the field of competition and regulation. A decision by the Constitutional Court on this matter is expected in the second half of 2006. Please see “Item 3. Key Information — Risk Factors — Risks Relating to our Energy Business — We are dependent on government concessions for our electricity and gas distribution businesses.”
      In June 2005, the European Commission launched an inquiry into the effects of the regulatory measures that have been adopted which show that progress in achieving a truly integrated energy market has been slow. According to the preliminary findings released in February 2006, market concentration, vertical foreclosure, lack of market integration, lack of transparency and price formation are the five main barriers to a fully functioning internal energy market. While the final report will be published at the end of 2006, the Commission has already indicated that it intends to carry out antitrust investigations in light of the inquiry’s conclusions. Moreover, in April 2006, the Commission started proceedings against certain Member States, including Italy, for failure to adequately enact EU legislation.
Eligible and Non-Eligible Customers
      One of the most important features of the regulatory framework is the distinction between Eligible Customers and Non-Eligible Customers. All customers that do not qualify as Eligible Customers are considered Non-Eligible Customers.
      Eligible Customers may enter into bilateral contracts for the supply of energy at freely negotiated prices directly with any domestic or foreign producer or reseller, or, since January 1, 2005, buy electricity directly on the power exchange. Resellers, including our subsidiaries Enel Energia and Enel Trade, may buy electricity for resale to Eligible Customers from any producer or on the power exchange.
      Non-Eligible Customers may purchase electricity only from the distribution company serving the geographic area in which they are located, at tariffs set by the Energy Authority. Distributors who transport electricity to the regulated market must in turn purchase the electricity so distributed from the Single Buyer, also at purchase prices fixed by the Energy Authority. Please see “— The Tariff Structure” for additional information on the electricity tariff system in Italy.
      The consumption threshold for qualification as an Eligible Customer, which is set by regulation, is decreasing over time, reducing the number of customers who must buy electricity on the regulated market. The consumption threshold in January 2002 was 9 GWh or more of electricity per year, declining on May 1, 2003, to 0.1 GWh per year, which resulted in approximately 60% of our electricity customers becoming eligible to participate in the free market.
      In accordance with the new 2003 Electricity Directive, the Energy Authority on June 30, 2004, recognized all non-residential customers, or approximately 7 million consumers, as Eligible Customers as of July 1, 2004, permitting them to take part in the free market from that date if they so choose. From July 1, 2007, all customers, including residential customers, will be eligible to purchase electricity on the free market.
      Eligible Customers who choose not to participate on the free market will continue to purchase electricity from their local distributor on the regulated market under conditions set by the Energy Authority. The law also provides that even after all customers have become Eligible Customers, the Single Buyer will continue to supply electricity to distributors for resale to their customers who choose not to leave the regulated market.

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The Single Buyer
      The Single Buyer, a corporation formed in 1999 and wholly owned by the GRTN, is responsible for ensuring the efficient, adequate and non-discriminatory supply of electricity to Non-Eligible Customers until they are allowed to freely choose their supplier. The Single Buyer became operational on January 1, 2004. Electricity distribution companies, including us, may take stakes of up to 10% in the Single Buyer, although the GRTN must remain the majority shareholder.
      Based on its own periodic estimates of future electricity demand and Ministry of Productive Activities guidelines, the Single Buyer purchases all electricity for the regulated market from us and other domestic and foreign producers. All distribution companies, including ours, are required to purchase electricity to be distributed on the regulated market from the Single Buyer.
      The Single Buyer may purchase electricity on the power exchange, through bilateral contracts (including “contracts for differences,” as described below) with domestic and foreign producers, or from the GRTN, which resells the electricity it is required to purchase under the CIP 6 regime.
      The Single Buyer held an auction in March 2004 for contracts for the physical delivery of a total of 4,800 MW of electricity to be supplied to customers on the regulated market for the period from April 1, 2004 through December 31, 2004. Producers bid for these contracts on the basis of percentage discounts from a base price. Under these contracts, winning bidders were awarded their discounted bid price, plus a fixed component aimed at covering the cost of fuel. In these auctions, we were awarded physical delivery contracts for approximately 3,620 MW of electricity purchased by the Single Buyer (or approximately 75% of the total amount awarded).
      In 2004 and 2005, the Single Buyer also held a series of auctions for “contracts for differences,” which are financial derivative contracts used to hedge the price risk of operations on the power exchange. These contracts establish a reference price, or “strike” price for a specified quantity of electricity, which the Single Buyer then purchases on the power exchange at the market price. In 2004, these contracts were “two-way” contracts for differences: when the market price paid by Single Buyer was higher than the strike price, the counterparty would pay the Single Buyer an amount equal to the difference, while when the market price was lower than the strike price, the Single Buyer would pay the counterparty the difference. In 2005, Single Buyer has offered only “one-way” contracts, under which the counterparty still pays the Single Buyer any excess of the market price for its electricity purchases over the strike price, while the Single Buyer instead pays the counterparty a contractually set premium.
      For the year 2004, we were awarded contracts for differences with the Single Buyer covering approximately 28 TWh (equal to approximately 70% of the total amount awarded). For the year 2005, the Single Buyer held auctions for contracts for differences in December 2004 and January 2005 with respect to a total of approximately 19,500 MW of electricity; we won approximately 12,500 MW of the final amount awarded. These contracts give us the right to extend their duration at our option, a right which we exercised in May 2005. As a consequence, we will supply to the Single Buyer 6,660 MW until December 31, 2006 and 5,550 MW until December 31, 2007. Under new auctions held by the Single Buyer in October and November 2005, we were awarded “two-ways” contracts for differences for the supply of 3,300 MW in 2006.
      The total payments by the Single Buyer to electricity producers for its purchases of electricity, either through bilateral contracts or on the power exchange, plus its own operating costs, must equal the total revenues it earns from sales to the regulated market under the regulated tariff structure. As a consequence, the Energy Authority may adjust tariffs from time to time to reflect the prices actually paid by the Single Buyer, as well as other factors.
The Italian Power Exchange
      The Italian power exchange, a virtual marketplace for the spot trading of electricity by producers and consumers under the management of the Market Operator, started operations on April 1, 2004.

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      In the initial phase of the power exchange, from April 1, 2004, through December 31, 2004, the GRTN, based on its own estimates of aggregate electricity demand, placed bids on the power exchange on behalf of all consumers who had not fully satisfied their demand through bilateral contracts. Since January 1, 2005, Eligible Customers have been able to participate directly in bidding for electricity on the power exchange.
      The power exchange is organized into three different markets in order to ensure a steady supply of electricity — the “day-ahead” market, the “adjustment market” and the “ancillary service” market.
      In the day-ahead market, sellers and buyers submit bids and offers for electricity to be supplied on the day following the transaction under the supervision of the Market Operator. The Market Operator is responsible for matching electricity demand and supply and, consequently, for the definition of power injection (supply) and withdrawal (demand) schedules and for communicating these schedules to the transmission system operator, currently Terna, which is responsible for physical delivery of energy. Variations in the schedules agreed upon in the “day-ahead” market are negotiated through an “adjustment market.” In the “day-ahead” market and in the “adjustment market,” a market-clearing price (the “system marginal price”) at which all transactions must take place is set by the Market Operator on the basis of an aggregation of all bids and offers, starting, respectively, from the highest bid and the lowest offer. In addition, the Market Operator must also take into account physical network limitations which place constraints on the transport power from particular generation facilities to consumers and may result in market congestion.
      If there is no market congestion, the Market Operator is able to set one system marginal price throughout Italy. However, if market congestion occurs, the Market Operator may divide the market into various zones, in which different system marginal prices may be set. In such event, the Market Operator will still determine one national price for purchasers on the power exchange, called the “unified national price,” based on a weighted average of the different system marginal prices set in the various zones. Suppliers, however, will receive the system marginal price that is applicable in their zone. In order to ensure that all producers in a congested zone bear the costs associated with the congestion, Terna will impose on suppliers who have produced electricity under bilateral contracts within a zone a congestion fee equal to the price differential between the applicable system marginal price in that producer’s zone and the unified national price.
      In the ancillary service market, producers submit bids and offers to Terna to increase (or decrease) the volume of energy to be supplied (or withdrawn) in order to permit the real-time balancing of supply and demand required for the physical delivery of electricity. Terna also procures reserve production capacity through the ancillary service market by accepting bids from producers willing to guarantee availability of reserve power. Transactions on the ancillary service market also serve to help manage network congestion that results when physical delivery schedules agreed upon in the day-ahead and adjustment markets are incompatible with network constraints. In the ancillary service market, prices are determined on the basis of individual negotiations between producers and Terna, or on a “pay-as-bid” basis.
      The Energy Authority and the Antitrust Authority constantly monitor the power exchange to ensure that it delivers the expected results: improved competition between electricity producers and enhancement of the efficiency of the Italian electricity system.
      In February 2005, the Energy Authority and Antitrust Authority issued a joint report on the state of the liberalization process of the Italian electricity sector in which, among other things, we were found to be in a position to set wholesale electricity prices throughout Italy, except in Sardinia (where Endesa holds a similar power). On May 5, 2005, the Energy Authority proposed certain possible measures to further promote competition in the wholesale electricity market over the next few years. The proposals include measures to reduce the structural power of operators in the market and disincentives to electricity producers to seek to exercise market power, in particular with respect to prices. Among the structural measures proposed are the required sale by us of additional power plants (on top of the 15,000 MW of productive capacity we have already sold through the disposal of the Gencos), or the required lease by us to third parties of generating capacity, as well as the partial entrusting to the Terna of the management of certain power plants deemed essential to cover demand for electricity, and hence whose production is a significant determinant of the wholesale price of electricity. The proposed disincentives to the exercise of market power include certain price cap mechanisms and the imposition of a requirement that producers enter into two-way contracts for differences or “Virtual Power Plant” contracts

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(“VPP”), in either case at predetermined quantities and at regulated prices. VPPs are contracts similar to contracts for differences that give the buyer the right, when the market price is higher than the contract price, to request from the seller an amount equal to the difference between the market and contract prices. Following these proposals, in the last quarter of 2005, the Energy Authority required us to enter into VPP contracts for 2006. Furthermore, the Energy Autority decided that the functioning of plants that provide energy for pumping water into hydroelectric power production facilities should be regulated. These measures were reversed by an Italian administrative court on February 6, 2006.
      In April 2005, the Energy Authority officially concluded that two cases of price spikes on the power exchange, one in June 2004 and one in January 2005, may not have been the result of underlying market conditions, and instead may have been caused by violations of antitrust law by us. As a result, the Antitrust Authority opened an investigation into these alleged violations and the surrounding events, which is due to be completed by November 15, 2006.
      For more information on these matters, please see “Item 3. Key Information — Risk Factors — Risks Relating to our Energy Business — We have been and are subject to regulatory investigations, including for possible abuse of dominant position and market abuse” and “Item 8. Financial Information — Other Financial Information — Legal Proceedings.”
Imports
      The volume of electricity that can be imported into Italy is limited by the capacity of transmission lines that connect the Italian grid with those of other countries and by concerns relating to the security of the system. Currently, a maximum import capacity of approximately 7,690 MW is available to import energy safely. A law passed in 2003 provides incentives to the development of new transmission infrastructures.
      In 2005, we controlled approximately 2,000 MW of the total import capacity pursuant to two long-term supply contracts. Since April 1, 2004, the date on which the power exchange started operations, we sell the electricity imported pursuant to these contracts to the Single Buyer under terms set by Ministerial Decree.
      Until December, 31 2005 the energy we purchased under these long-term supply contracts enjoyed priority access to interconnection capacity for transmission of electricity into Italy from neighboring countries, for up to 2000 MW. However, in 2006, the French regulatory authority decided not to assign to us any transmission or any reserved capacity for our import of the electricity we purchased under a long-term contract with EDF. As a consequence, only part of the electricity bought under this contract was imported into Italy, with the remaining part being sold in France. We have appealed the decision of the French regulatory authority before the competent administrative court. Moreover, in April 2006, the European Commission started proceedings against certain Member States, including Italy, challenging priority access for long-term supply contracts. If the European Commission concludes that such rights are contrary to EU law, our ability to import electricity under these contracts will be impaired and we will be forced to sell the electricity under this contract outside of Italy or pay for congestion rights that will give us access to transmission facilities to import this energy. The impact of this measure or any other measure adopted further to a decision by the European Commission that priority access rights are contrary to EU law would be in any event limited, as the contract with EDF expires in 2007 and the revenues derived from the other contract (which expires in 2012) are not material.
      The Bersani Decree authorized the Ministry of Productive Activities to set terms and conditions to allocate the interconnection capacity available after deducting the capacity used by existing long-term contracts, taking into account a fair allocation of the generally less expensive imported electricity between the free and regulated markets if import demand exceeds total interconnection capacity.
      The allocation mechanism for 2004 set out by the Ministry of Productive Activities in accordance with EU law and applied by the Energy Authority and the GRTN considered the total interconnection capacity available at the borders with France and Switzerland (the north-west pool) and Austria and Slovenia (the north-east pool) separately. Interconnection capacity was allocated on a pro-rata basis; in addition, in no case may a single importer hold more than 10% of the interconnection capacity available in any given pool. The Ministry of Productive Activities put a new allocation mechanism into effect for 2005. Under the new mechanism, capacity is

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allocated pursuant to an implicit auction mechanism, with the price to be paid for access to this capacity determined based on the price in the power exchange’s “day-ahead market” (please see “— The Italian Power Exchange,” above). Because of the link to prices on the power exchange, this mechanism may result in higher price volatility for, and an increase in the cost of, imported electricity. As a result, the Energy Authority has also established a mechanism to provide purchasers of imported electricity with an exemption from congestion charges. In 2005, this exemption was awarded by the GRTN on a pro-rata basis in the event applications exceed the total available quantity. In 2006, the exemption was allocated through an auction.
Incentives to Provide Generation Capacity
      In order to address a current deficit in Italian generation capacity relative to rising electricity demand, the regulatory framework provides incentives to power generators both to build new capacity as well as to maintain their existing plants in good working order and available to cover sudden variations in electricity demand.
      In 2004, the Energy Authority established a provisional system of payments to remunerate producers that make generation capacity available to the electricity system at times of peak demand, known as “capacity payments.” Capacity payments to a given producer comprise both an amount due for capacity available on “critical” days, which was previously set by the GRTN and is now set by Terna, and a further amount payable when pool market prices fall below specified thresholds, as an extra incentive. This provisional mechanism remains in place. The Energy Authority is currently developing the definitive mechanism, which by law must be market-based and also provide incentives for new generation capacity.
New Generation Plants
      In order to promote investment in new generation facilities, the October 2003 law amending the Bersani Decree included provisions to streamline the authorization procedures relating to the construction of new power generation plants and the renovation and expansion of existing plants.
      The Marzano Law requires all entities receiving authorization to construct new plants or to increase generating capacity of existing power plants after September 28, 2004, to pay the authorities of the region in which the plant is located compensation (based on generating capacity) for the lost alternative use of the plant site and the impact thereof on surrounding communities, unless the parties agree otherwise.
Transmission
      As noted, we use the term “transmission” to refer to the transport of electricity on high and very high voltage interconnected networks from the plants where it is generated or, in the case of imported energy, from the points of acquisition, to distribution systems. The Italian national electricity transmission grid includes all of Terna’s very high voltage (380/220 kV) and high voltage (150/132 kV) lines.
      In accordance with a law passed in 2003 that required the reunification of ownership and management of the grid, we no longer control Terna following our disposal of a controlling stake in this company. Please see “— Business — The Enel Group — Discontinued Operations” for additional information.
Distribution of Electricity
      As noted, we use the term “distribution” to refer to the transport of electricity from the transmission grid to end users of electricity.
      Distribution companies in Italy are required to be licensed by the state and to provide service to all customers who request it, subject to payment of applicable tariffs and to compliance with technical and safety requirements. In addition, distributors serving more than 300,000 customers must distribute electricity to the regulated market through separate companies whose sale activity is the distribution and sale of electricity on the regulated market.
      Our concessions for the distribution of electricity are scheduled to expire in 2032.

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      The Bersani Decree sought to promote the consolidation of the Italian electricity distribution industry by providing for the issuance of only one distribution license within each municipality and establishing procedures to consolidate distribution activities under a single operator in municipalities where both we and a local distribution company were engaged in electricity distribution by giving municipal networks the right to request that we sell our distribution network in their municipalities to them.
      Substantially all of the qualifying distribution companies in municipalities with co-existing networks made requests to purchase our networks in those cities. For more details on the consolidation process, please see “— Business — The Enel Group — Sales, Infrastructure and Networks — Domestic Distribution and Sales Operations — Consolidation of Electricity Distribution Networks.”
      On average, the distribution networks that we have been required to sell were more profitable than our other distribution networks, mainly because distribution in metropolitan areas has lower costs. In 2004, the Energy Authority put in place an equalization system to compensate distributors for the higher costs associated with serving non-urban areas. However, the compensation system does not apply to Enel Distribuzione. Please see “— The Tariff Structure” below.
The Tariff Structure
      Prices paid by all Italian customers for electricity include a transmission component, a distribution component, a generation component covering the price of the electricity itself and system charges.
      Under the current electricity tariff regime, all customers pay regulated prices, set either directly by the Energy Authority or in accordance with Energy Authority guidelines and subject to its approval, for the transmission and distribution components and system charges. The transmission and distribution components, together referred to as “transport charges,” are subject to a price cap mechanism aimed at progressively reducing these charges on the basis of annual efficiency targets. For customers purchasing electricity on the regulated market, the Energy Authority also regulates the generation component, which is set on a quarterly basis, while customers purchasing electricity on the free market pay prices agreed through bilateral contracts or on the power exchange.
      The Energy Authority sets base tariff levels every four years. In setting the base tariff levels, the Energy Authority takes into account:
  •  Operating costs of generation (for electricity prices on the regulated market), transmission and distribution activities, including procurement costs, and amortization and depreciation. In order for operators to be able to recover particular costs, the costs must be both actually incurred by them and recognized by the Energy Authority;
 
  •  An appropriate return on invested capital, including both equity and debt financing; and
 
  •  The costs associated with system charges.
      In 2004, the Energy Authority set new base tariffs for the 2004-2007 period, which have been in force since February 1, 2004. The Energy Authority has estimated that the new tariff regime in place for 2004-2007 will result in a reduction of the overall tariff paid by regulated market customers of approximately 13% in real terms (assuming no change in fuel costs and system charges) during the period.
      The actual impact of tariff levels on our revenues depends on a number of factors, including the volume of electricity we sell in the regulated market, fuel prices and the mix of customers we serve.
      The tariff structure currently in place also includes certain mechanisms to take into account structural factors affecting distributors’ costs.
      The Energy Authority in 2004 established a price equalizing mechanism intended to minimize the effects of a timing discrepancy in the setting of prices distributors pay to the Single Buyer for electricity to be distributed on the regulated market and the prices that distributors may charge to end users on the regulated market. The prices distributors pay to the Single Buyer for electricity to be distributed on the regulated market are set monthly by the Energy Authority based on the average unit costs incurred by the Single Buyer in connection with its purchases of

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electricity. However, the generation component included in the overall tariff that distributors may charge to end users on the regulated market is fixed by the Energy Authority on a quarterly basis, as explained in more detail below. In order to minimize the effects of this discrepancy, the Energy Authority has established a price equalizing mechanism applicable for the first time in 2004. The equalizing mechanism is funded through a system charge in an amount set by the Energy Authority, applicable starting in 2005.
      In 2004, the Energy Authority also put in place a system to compensate distributors that serve areas where costs are significantly higher than the national average due to uncontrollable factors such as population density and geography. The costs to be taken into account in setting this compensation are to be based on infrastructural elements such as length of cables and installation type (aerial or underground). The compensation system does not apply to Enel Distribuzione, but it applies to our subsidiary Deval, which has requested approximately 2.4 million as compensation. A preliminary decision by the Energy Authority on this matter has granted Deval 1.1 million as compensation. We expect the Energy Authority to issue a final decision on this matter in the second half of 2006.
      The Energy Authority currently defines the following six tariff categories of electricity consumers:
  •  low-voltage domestic consumers (residential customers);
 
  •  low-voltage public lighting;
 
  •  other low-voltage end users;
 
  •  medium-voltage public lighting;
 
  •  other medium-voltage end users; and
 
  •  high-voltage end users.
      The Energy Authority has been seeking to introduce a new tariff system designed to protect disadvantaged residential customers. However, this system has not yet been formally proposed or approved.
Generation Component of Electricity Tariffs
      The generation component refers to the price paid by customers for electricity sold on the regulated market. Prior to the start of the power exchange on April 1, 2004, the Energy Authority determined generation costs based on fixed and variable components of production costs. The fixed-cost component, which was intended to reflect non-fuel operating costs, was based on an estimate of the average recognized fixed costs associated with generation plants in Italy and was set on annual basis.
      The variable-cost component of the tariffs was principally intended to reflect fuel costs associated with thermal power generation. This system resulted in an increase in the relative profitability of:
  •  Hydroelectric or geothermal generation, since these plants do not incur fuel costs; and
 
  •  The resale of electricity imported under long-term contracts in effect as of the date of the entry into force of the first Electricity Directive on February 19, 1997, which was frequently cheaper than electricity generated in Italy.
      The Energy Authority decided to reduce this potential windfall profit for hydroelectric or geothermal producers by establishing a new surcharge to be paid by these producers to the GRTN with respect to electricity sold by them. This surcharge applied until December 2001. Pursuant to rules on stranded costs enacted in 2002 (which are described in more detail below), the surcharge on hydroelectric and geothermal generation was abolished as of January 1, 2002.
      In February 2004, the Energy Authority modified the price electricity producers were permitted to charge to distributors for the electricity to be supplied to regulated customers in order to reduce the component of electricity tariffs related to generation during March 2004. We and other electricity operators challenged this reduction before the Administrative Tribunal of Lombardy, which annulled the Energy Authority decision. The Council of State, however, overruled this decision on January 16, 2006. Accordingly, we are required to

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reimburse consumers approximately 200 million, which is the difference between the price paid by regulated customers for the electricity supplied in March 2004 and the amount resulting from implementation of the reduction mandated by the Energy Authority.
      Since April 1, 2004, the Energy Authority sets the generation cost component of the electricity tariff paid by customers on the regulated market every three months on the basis of the average costs incurred by the Single Buyer for the procurement of electricity, both on the power exchange and directly from producers.
      We sell electricity on the free market through bilateral contracts at prices that are negotiated with each customer and that may vary based on several elements, such as quantity purchased, type of electricity sold and duration of the contract; electricity sold on the power exchange is sold at the price determined through the relevant market mechanism. Please see “— The Italian Power Exchange” above for additional details on these mechanisms.
Transmission and Distribution Components
      As noted above, the regulated tariff for transmission and distribution services, or transport charges, for all customers takes into account both the operating costs of transmission and distribution activities, including procurement costs, and amortization and depreciation, as well as an appropriate return on invested capital. In order for operators to be able to recover particular costs, the costs must be both actually incurred by them and recognized by the Energy Authority. The transmission component of the transport charges is currently set by the Energy Authority. As explained in more detail below, distributors may propose various price options for both residential and non-residential customers, within guidelines set by, and subject to the approval of, the Energy Authority.
      The costs of transmission and distribution companies used in determining transport charges are subject to a price-cap mechanism. During the 2000-2003 period, the Energy Authority set the annual rate of reduction with respect to total costs (capital costs, depreciation and operating costs) in real terms at 4% for each of the transmission and distribution components. For the period 2004-2007, the Energy Authority has set the annual percentage decrease only for operating costs and depreciation, but excluding capital costs, for transmission and distribution services at 2.5% and 3.5%, respectively.
      For distributors, the determination of operating costs is required to reflect the average costs incurred by the main distributors for the transport of electricity through the local distribution networks and for the sales-related services they provide to final customers, plus a specified return on invested capital. The return on capital recognized by the Energy Authority for the 2004-2007 period was set at 6.8% for distribution networks and at 6.7% for transmission networks, or a higher percentage for capital invested in transmission network development.
      Depreciation and invested capital are calculated by the Energy Authority under criteria consistent with international regulatory practices. In setting tariff levels for the 2004-2007 period, the Energy Authority revised the way depreciation costs are calculated for transmission and distribution companies; whereas in the 2000-2003 period, the depreciation costs recognized were based on the value of a company’s network assets and the related depreciation expenses as recorded in companies’ statutory accounts, these costs are now calculated based on the historical cost of infrastructure, as revalued annually. The useful lives of assets considered by the Energy Authority to determine depreciation expenses to be recognized through the transport charges have also been increased to bring them into line with the expected useful life of plant and equipment.
      Prior to 2004, both the transmission and distribution component of the transport charges paid by non-residential customers to distributors were set on the basis of proposals made by each distributor and approved by the Energy Authority. During that period, the transport charges for residential customers were set directly by the Energy Authority as part of the tariff paid by them to distributors. Starting in 2004, the Energy Authority has directly set the transmission component of the transport charge for all customers, while distributors retain the ability to propose to non-residential customers one or more options for the distribution component of the transport charge, based on the distributors’ costs as described above and within limits set by the Energy Authority.

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      These limits are of two types. One limit sets an aggregate maximum amount of tariff revenues that each distributor will be allowed to receive from all customers belonging to the same category in a single year. A second limit sets the maximum amount of tariff revenues that any distributor will be allowed to receive from a single customer in a given category. If the aggregate limit is exceeded, the distributor must compensate customers for the amount of the excess. The Energy Authority monitors compliance with the individual limit at the time the distributor submits its price options for approval. In addition, distributors must comply with a trade policy code aimed at ensuring transparency.
      Residential customers do not have any options for the distribution component per se, since the tariff they pay includes the generation component and transport charges without distinguishing between the two. However, distributors may now also offer regulated market customers different tariff options, subject to approval by the Energy Authority. Please see “Item 4. Information on the Company — Business — The Enel Group — Sales, Infrastructure and Networks — Domestic Distribution and Sales Operations — Telemanagement System” for information regarding our tariff options.
System Charges and Other Charges
      The tariff structure also addresses the need to cover various costs resulting from public policy-related requirements imposed on the Italian electricity industry by providing for the following charges, payable by all electricity consumers:
  •  Charges concerning the electricity system, established by the Ministry of Productive Activities, that consist of:
  •  a nuclear surcharge, covering part of the costs incurred by So.g.i.n., the company to which we transferred our discontinued Italian nuclear operations, in connection with the dismantling of nuclear plants and decommissioning of nuclear fuels; this surcharge is designed to cover substantially all of such costs when added to the funds that we transferred to So.g.i.n.;
 
  •  a surcharge that benefits producers from renewable resources;
 
  •  special surcharges covering the cost of supplying electricity at mandated discounts to certain customers (primarily the Italian state-owned railway company and Acciai Speciali Terni S.p.A., both of which transferred electricity assets to us as part of the nationalization of the Italian electricity industry in 1962);
 
  •  research and development surcharges, covering related costs; and
 
  •  certain stranded costs that have not yet been recovered. Please see “— Stranded Costs” below for a discussion of these costs.
  •  Other general interest charges established by the Energy Authority to adjust or refine the operation of the tariff mechanism, which include adjustments to cover potential differences between distributors’ costs as recognized under the current tariff structure and actual tariff revenues.
 
  •  Incentives for the enhancement of the quality of service.
 
  •  Charges recovered through upward adjustments to the price caps, as established by the Energy Authority, which cover:
  •  costs deriving from unforeseeable events, changes in the regulatory framework or new obligations for universal service;
 
  •  costs deriving from demand-side management initiatives intended to promote a more efficient use of resources by electricity customers, including information campaigns; and
 
  •  additional recognized costs incurred in connection with the offer of value-added services on top of basic options.

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      Revenues deriving from system charges are remitted to and managed by the Cassa Conguaglio per il Settore Elettrico, or the Equalization Fund, a public entity charged with redistributing these revenues to the electricity companies entitled to receive them.
Stranded Costs
      Stranded costs are current costs deriving from contractual commitments or investment decisions that electricity companies:
  •  undertook for reasons of public policy;
 
  •  undertook at a time when the electricity markets were not yet open to competition; and
 
  •  could have been recovered in a monopoly regime but cannot be recovered under a regime of competitive electricity pricing.
      To facilitate the transition to open electricity markets, the European Commission has stated that electricity companies should be refunded their stranded costs provided that:
  •  they minimize the impact of those costs (and, hence, the amount of the refund) on their future operations; and
 
  •  they submit an industrial plan demonstrating the long-term profitability of the activity related to the stranded costs.
      A law enacted in April 2003 limited the amount of stranded costs we are entitled to recover for periods through 2003 to (i) certain costs relating to our generation plants incurred to comply with requirements that were imposed in the past concerning their design and operation (for example, because of governmental policies, we built most of our plants to ensure a high degree of flexibility in the types of fuel that they can use), and (ii) costs arising from our inability to fulfill our Nigerian LNG contract because of the Italian government’s failure to allow construction of a required regasification terminal. The April 2003 law provides that for periods after January 1, 2004, we will be limited to recovering only those stranded costs associated with the Nigerian LNG contract.
      In August 2004, the MEF and the Ministry of Productive Activities issued a joint decree that determined the overall amount of stranded costs we are entitled to recover. On December 1, 2004, following the European Commission’s approval of the decree pursuant to the state aid rules of the European Union, we became entitled to recover approximately 513 million on account of stranded costs related to our generation plants for the period 2000-2003. The amount of stranded costs related to the Nigerian LNG contract we are entitled to recover was determined to be approximately 555 million in respect of the 2000-2003 period and approximately 910 million in respect of the 2004-2009 period. Although we did not actually received these funds in 2004, during that year we recorded related revenues of 1,219 million, the amount we became entitled to receive in respect of 2004 and prior years under the August 2004 decree.
      The timing and manner in which these amounts are to be paid to us were set out in a decree issued jointly by the Ministry of Productive Activities and the MEF on June 22, 2005. The decree provides that stranded costs related to the Nigerian LNG contract for the period ending in 2004 and stranded costs related to our generation plants will be reimbursed by December 2009 through quarterly payments. Stranded costs related to the Nigerian LNG contract for the period from 2004 through 2009 will be limited to the value of gas effectively used for electricity generation, calculated on a yearly basis. At the end of 2005, we had received 361 million as compensation for those stranded costs.
Continuity and Quality of Service Regulation
      Since July 1, 2000, the Energy Authority has issued guidelines setting targets for electricity service continuity and quality. Continuity of service is measured by the frequency and total duration in minutes of service interruptions and is assessed with reference to annual targets set by the Energy Authority. Quality of service is measured in terms of waiting time for the performance of the most frequent commercial activities (such as connection cost estimates, connections, disconnections and reconnections).

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      The Energy Authority has instituted an incentive system whereby it grants bonuses to companies that exceed its targets for continuity of service and imposes penalties on companies that fail to meet them. We have consistently exceeded our continuity of service targets since 2000. Distributors that outperform the targets are paid their bonuses through a component of the tariff structure. We received bonuses of 63 million for having outperformed the continuity of service targets in 2004. We expect that the Energy Authority will assign bonuses with respect to 2005 in the second half of 2006.
      With respect to quality of service, if a distribution company fails to meet standards set by the Energy Authority in providing a particular service to a customer, the company is required to reimburse that customer an amount that is fixed by the Energy Authority. We have achieved most of the quality of service targets set by the Energy Authority, and have not been required to make material reimbursements.
      In May 2005, the Energy Authority issued a consultation document, subject to public comment through June 30, 2005, proposing to institute a system of automatic compensation payable by electricity distributors to affected customers in the event of a blackout of other prolonged service interruption. Under these proposals, compensation would be payable by a distributor that fails to restore service within eight hours from the start of the interruption, if the interruption has not been caused by damage to the distributor’s facilities, or within 24 hours from the start of the interruption, if the interruption has been caused by damage to the distributor’s facilities. The Energy Authority’s proposals also provide for incentive mechanisms for distributors to restore service as soon as possible in the event of a widespread and prolonged service interruption. The Energy Authority has not yet taken any action as a result of its consultation.
      We believe that the level of revenues expected under the current tariff structure will allow us and other distributors to cover the costs we need to incur to meet the continuity and quality of service targets set by the Energy Authority. See also “— Business — The Enel Group — Sales, Infrastructure and Networks — Domestic Distribution and Sales Operations — Continuity and Quality of Network Service.”
Promotion of Renewable Resources
      In 1992, the Comitato Interministeriale Prezzi, an Italian governmental committee, issued Regulation 6/92 (“CIP 6”), which established incentives for new generation plants using renewable resources and for the sale of electricity produced from renewable resources. Initially under the CIP 6 regime, we had been required to purchase substantially all of the qualifying domestic production of electricity from renewable resources at fixed prices. In November 2000, the Ministry of Productive Activities issued a decree that transferred all energy produced from renewable resources under the CIP 6 regime to the GRTN as of January 1, 2001. Under current regulations, the GRTN is required to purchase all CIP 6 electricity, which it resells to Eligible Customers and, starting from 2004, also to the Single Buyer. The Single Buyer has a right to a predefined quota of CIP 6 electricity. Until 2003, Eligible Customers obtained CIP 6 electricity pursuant to an auction mechanism; starting from 2004, they are awarded CIP 6 electricity on a pro-rata basis. The GRTN sells “green certificates” representing electricity from renewable resources purchased from CIP 6 producers. In June 2005, the GRTN estimated that total annual CIP 6 electricity production in 2005 would be equal to approximately 50 TWh, in line with the amount produced in 2004.
      The Bersani Decree provided that, starting in 2001, all companies introducing more than 100 GWh of electricity generated from conventional sources into the national transmission grid in any year must, in the following year, introduce into the national transmission grid an amount of electricity produced from newly qualified renewable resources equal to at least 2% of the amount of such excess over 100 GWh, net of co-generation, self-consumption and exports. Electricity from renewable resources may be produced directly or purchased from other producers who have obtained tradable “green certificates” representing a fixed amount of electricity certified as generated from renewable resources.
      In addition, the Bersani Decree directed the GRTN to dispatch electricity into the national transmission grid so that energy produced from qualified renewable resources takes priority over other types of electricity.
      An EU directive issued in September 2001 set targets for energy production from renewable resources, requiring that by 2010 a share equal to 22% of total electricity consumed in the EU be generated from renewable

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resources and providing recommended national targets to achieve this goal. Italy adopted legislation to implement this directive in December 2003, setting a 22.5% target for total production of electricity from renewable resources by 2010, lower than the 25% target for Italy recommended in the EU directive. December 2003 legislation amending the Bersani Decree provided for a progressive increase in the 2% share of electricity produced from newly qualified renewable resources electricity generators are required to introduce into the national transmission grid. For 2004, the percentage was increased to 2.35%, and this level will increase by a further 0.35 percentage points in each of 2005 and 2006. Further increases may be implemented for the three-year periods starting in 2007 and 2010.
Hydroelectric Power
      Under the Bersani Decree, all of our licenses for the generation of electricity from large bodies of water, which had originally been granted to us for an indeterminate period of time, were instead to expire in April 2029. In addition, the Bersani Decree automatically extended to December 31, 2010 the term of all hydroelectric licenses for the generation of electricity from large bodies of water that were granted to other electricity producers and were scheduled to expire before such date. All hydroelectric licenses expiring after December 31, 2010 were to retain their original expiration date. The decree also provided that in any bidding contest, an existing license holder would enjoy preferential treatment over competitors in the case of equal bids.
      In January 2004, the European Commission determined that certain of the Italian regulations regarding hydroelectric concessions were contrary to EU law. In particular, the European Commission objected to the renewal preferences granted to existing holders of concessions (and in the region of Trentino-Alto Adige, to the operator controlled by the local authorities) upon the expiry of those concessions, as well as to the fact that the regulations provided for the expiration of all concessions in 2029 (and for the region of Trentino-Alto Adige, in 2010), even though these concessions had previously been of perpetual duration.
      In December 2005, Italy amended the relevant regulations, abrogating the renewal preferences and postponing the expiration of all concessions for additional 10 years. However, if the European Commission continues to pursue its formal action before the Court of Justice to enforce its request and the Court of Justice affirms the European Commission’s opinion, our hydroelectric concessions may be terminated prematurely and we may not be able to renew these concessions at all or on favorable terms. This could have a material adverse effect on our business prospects, financial condition and results of operations. The European Commission’s decision on whether to continue its formal action is expected in the second half of 2006. Please see “Item 3. Key Information — Risk Factors — Risks Related to Our Energy Business — A European Commission challenge to Italian regulations on hydroelectric concessions could adversely affect our business, financial condition and results of operations.”
      Five regional governments in Italy and the local authorities of the region of Trentino Alto Adige have brought proceedings against these amended regulations in front of Italy’s Constitutional Court, seeking the reinstitution of the original expiry dates for operations they control. A ruling from the Constitutional Court is not expected before the end of 2006.
Taxes
      Since January 1, 2001, consumers of electricity services have been subject to three indirect taxes, the first two of which are not applicable to residential customers whose consumption is below certain specified thresholds, qualifying them for a social protection scheme:
  •  A state tax for residential uses (of 0.0047/kWh) and for other uses (of 0.0031/kWh excluding users with consumption over 1.2 GWh per month);
 
  •  Additional local taxes that vary from 0.0093/kWh up to a maximum of 0.0204/kWh; and
 
  •  Value-added tax of 20% for all users with the exception of residential and industrial customers (who are taxed at a rate of 10%).

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Gas Regulation
      Italian regulations enacted in May 2000 pursuant to EU Directive 98/30, which mandated the general liberalization of natural gas markets in the member states, seek to introduce competition into the Italian natural gas market through the liberalization of the import, export, transport, dispatching, distribution and sale of gas. In 2007, the Italian government may enact more regulations to foster competition in the Italian natural gas market pursuant to EU Directive 2003/55.
Gas Eligible and Non-Eligible Customers
      Until December 31, 2002, only certain large consumers known as Gas Eligible Customers, were able to freely choose their supplier of natural gas. During the same period, customers, mainly residential, who did not qualify as Gas Eligible Customers, which we refer to as Gas Non-Eligible Customers, were obliged to purchase gas from distributors operating in their local area at a tariff set by the Energy Authority. Since January 1, 2003, all customers have had direct access to the natural gas system and the right to freely choose their natural gas supplier. However, natural gas suppliers and distributors are still subject to regulation with respect to the tariffs they may charge customers who were considered Gas Non-Eligible Customers at that date. Our management believes that to date only a few Gas Non-Eligible Customers have switched their natural gas supplier. Please see “— Distribution Tariffs and Sale Tariffs for Gas Non-Eligible Customers” below.
Transport and Storage
      Companies engaged in the transport and dispatching of gas must allow access to their gas transport networks to third parties, provided that they have enough capacity and that granting such access is economically and technically feasible. The Energy Authority establishes transport fees based on proposals from the individual operators.
      Operators of natural gas storage facilities must obtain a concession from the Ministry of Productive Activities and are required to provide storage services to third parties upon request, provided that they have enough capacity and that giving such storage services is economically and technically feasible. In addition, importers are required to maintain storage reserves equal to 10% of the gas they import from countries outside the EU.
Distribution and Sale of Gas
      The term distribution refers to the transport of gas through local networks for delivery to customer premises. Since January 1, 2002, gas distribution activities may be carried out only by companies that are not otherwise engaged in the natural gas industry, and gas sales to end users may be made only by companies that are not otherwise engaged in the natural gas industry except as importers, producers or wholesalers.
      The Marzano Law provides incentives for investment in new natural gas pipelines and LNG regasification terminals by exempting the investing entity from the obligation to provide third-party access up to 80% of the storage capacity of new storage facilities for a period of not less than 20 years. We expect these investment incentives eventually to lead to increased competition in the gas distribution storage sector.
Restrictions on Sale and Imports of Gas
      The sale of gas to end users is made under an authorization granted by the Ministry of Productive Activities, which both Enel Gas and Enel Trade have obtained. Enel Trade is also authorized to import gas to be sold to power plants and wholesalers. Each year from January 1, 2003 to December 31, 2010, no single operator has been allowed to hold a market share higher than 50% of domestic sales to final customers. In 2004, based on data provided by the Energy Authority, Enel Gas had a market share in sales of natural gas to final customers of approximately 14%. In addition, no single operator is allowed to introduce imported or national gas into the domestic transmission grid in a quantity exceeding a specified percentage of the total, set at 75% in 2002 and decreasing by two percentage points each year thereafter, to 61% in 2010. The applicable percentage is calculated net of quantities of gas consumed by the relevant operator or by its controlled or affiliated companies.

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Rules Governing Distribution of Gas
      Under Italian regulations, distributors operate under concessions awarded by local authorities pursuant to tender procedures for periods not longer than 12 years. Through service agreements, local authorities may regulate the terms and conditions for the provision of the service and the quality objectives to be achieved. The tenders are awarded based on financial terms, quality and safety standards, investment plans and technological and management skills offered. Distributors are required to connect to the distribution network any customer who so requests.
      Prior to enactment of the Marzano Law, gas distribution concessions awarded prior to May 2000 by means other than competitive tender expired by law at the earlier of their original expiration date or December 31, 2005, with the expiration date extendible for up to five years under certain conditions. The Marzano Law, as interpreted by the Ministry of Productive Activities in November 2004, provided instead that the expiration date of these gas distribution concessions are to expire at the earlier of their original expiration date or December 31, 2007, with the expiration date extendible for up to five years under certain conditions. However, certain local authorities have passed measures that would terminate gas distribution concessions in their jurisdictions on December 31, 2005. The Italian administrative courts before which these measures have been challenged disagreed with the Ministry of Productive Activities’s interpretation of the Marzano Law. To remedy the resulting uncertainty, on February 23, 2006, the Italian parliament approved a law confirming that gas distribution concessions expire by law at the earlier of their original expiration date or December 31, 2007, but extended the expiration date to December 31, 2009 under certain conditions. Local authorities may further extend the expiration date by one year. Furthermore, certain gas distribution concessions for southern Italy, partially financed through public funds under a public incentives plan of the use of natural gas in the south of Italy, expire at the later of June 21, 2012 or twelve years from the entry into force of their approval by the Ministry of Economy and Finance. Finally, gas distribution concessions awarded prior to May 2000 by competitive tender expire at the earlier of their original expiration date or December 31, 2012. The majority of our existing gas distribution concessions are currently due to expire on December 31, 2009.
Distribution Tariffs and Sales Tariffs for Gas Non-Eligible Customers
      In December 2000, pursuant to Italian regulations, the Energy Authority identified tariff criteria that we and other gas distributors and suppliers must apply in setting tariffs for the distribution and supply of gas to Gas Non-Eligible Customers. The tariff criteria for both distribution and supply include a fixed and a variable component reflecting the balance between fixed and variable costs incurred by distributors and suppliers, respectively, and operate to impose a cap on the rates gas distributors and suppliers may charge. The portion of the variable component in the sale tariff relating to the cost of natural gas is revised on a quarterly basis.
      For distributors, the tariff criteria generally take into account average capital costs, as determined by the Energy Authority based on a sample of selected operators. However, since June 2002, the Energy Authority has permitted distributors to set their rates based on actually incurred capital costs if such costs can be adequately proven.
      The Energy Authority has issued new distribution tariffs for the period October 2004 through September 2008. However, in February 2005, the Administrative Tribunal of Lombardy annulled these new tariffs. As a consequence, pending action from the Energy Authority to revise the tariff mechanism, the old tariffs remain applicable. In any event, we do not expect any such revisions to have a material impact on our gas business going forward and, should the new tariffs require adjustments, we will be entitled to modify customers’ bills accordingly.
      From 2004, distributors are also bound by regulations concerning quality of service. So far, the Energy Authority has introduced both penalties for distributors that do not comply with applicable quality of service targets and incentives to achieve higher safety standards.
      For suppliers, prices charged to Gas Non-Eligible Customers were supposed to be freely set from January 1, 2003. However, in December 2002, the Energy Authority imposed a transitory regime under which suppliers were obliged to continue to supply former Gas Non-Eligible Customers using the tariff criteria established by the

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Energy Authority and in effect at December 31, 2002, if the Gas Non-Eligible Customers so requested. Pursuant to these criteria, the Energy Authority updates the tariffs on a quarterly basis. In March 2006, the Energy Authority established the tariffs applicable from April 1, 2006 to June 30, 2006.
      In December 2004, the Energy Authority revised the tariff criteria for former Gas Non-Eligible Customers in order to reduce the effect of fuel price increases on gas prices. In June 2005, the Administrative Tribunal of Lombardy annulled the Energy Authority’s decision in a series of judgments. However, in March 2006 the Council of State overruled one of these judgments and by June 2007 it should rule on the validity of the others. Should the Energy Authority decide to restore the revised tariff criteria, our tariff revenues would be considerably reduced.
Gas Emergency
      In early 2006, Italy suffered a gas shortage, due to an increase of gas demand and a reduction of gas imports, which significantly diminished available gas stocks. As a result, the Italian government issued a decree aimed at reducing gas consumption by power generators. The Energy Authority is currently responsible for establishing adequate compensation to cover any additional costs incurred by power generators as a result of this decree.
Environmental Matters
      Our electricity and other operations are subject to extensive environmental regulation, including laws adopted by the Italian parliament or government to implement regulations and directives adopted by the European Union and international agreements on the environment.
      The principal objective of our environmental policy is to comply with all relevant legislation and to seek to reduce adverse effects that our activities may have on the environment. Since 1996, we have taken the initiative of publishing an annual environmental report. In 2002, we also started publishing a sustainability report, which contains an environmental section. We believe that environmental performance will represent an increasingly important competitive factor in a liberalized market.
      Environmental regulations affecting our business primarily relate to air emissions, water pollution, waste disposal, noise and the clean up of contaminated sites. The principal air emissions of fossil-fueled electricity generation that pollute the atmosphere are sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate matter. A primary focus of the environmental regulations applicable to our business is an effort to reduce these emissions. We have also given particular attention to seeking to minimize the impact of electromagnetic fields and carbon dioxide (CO2) and other greenhouse gas (“GHG”) emissions.
Electromagnetic Fields
      The Italian government adopted regulations in 1992 and 1995 relating to exposure to electromagnetic fields applicable to low frequency infrastructure, such as that used for the transmission, distribution and consumption of electricity. These regulations set two types of limits: maximum levels of exposure to electromagnetic fields from new and existing transmission and distribution lines and distribution substations, and minimum distances between transmission or high-voltage distribution lines or substations and residential buildings, office buildings and similarly habited areas for lines built after the adoption of the 1992 regulation.
      In February 2001, the Italian parliament passed a framework law on electromagnetic field exposure amending these earlier regulations. The 2001 law is intended to protect the general public and workers against alleged potential long-term health effects of exposure to electromagnetic fields generated by both low frequency and high-frequency infrastructures. The law has made it more difficult to install new transmission and distribution lines and substations.
      Furthermore, the 2001 law provides for the adoption and implementation of programs to restructure electricity transmission and distribution lines, substations and high frequency infrastructures, in accordance with maximum exposure levels. In 2003, two governmental decrees were enacted providing for measures to implement the 2001 law and setting maximum exposure levels, precaution levels and quality targets. However, these

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measures have not yet taken effect, as they require action from the Italian Authority for Environmental Protection that has not yet been taken.
      We believe that the costs of complying with these measures, including costs for the related restructuring described above, will not have a material impact on our results of operations. Moreover, because of the 2005 and 2006 disposal of all but 5.12% of our stake in Terna, which owns over 90% of Italy’s power transmission lines, we are no longer materially affected by regulations relating to electricity transmission. Currently, we only own power lines for the distribution of electricity.
CO2 Emissions
      Both the European Union and Italy are signatories to the Kyoto Protocol, which was signed under the United Nations Framework Convention on Climate Change. In accordance with a burden-sharing agreement among EU member states, Italy has set a target to reduce emissions of CO2 and the other GHGs listed in the Kyoto Protocol over the 2008-2012 period by 6.5% from their 1990 levels. As of 2004, we produced approximately 11% of total GHG emissions in Italy.
      In implementing the Kyoto protocol, on November 19, 1998, the Italian inter-ministerial committee for economic planning issued the guidelines for Italian policies and measures for the reduction of GHG emissions in order to implement the Kyoto Protocol. These guidelines, which were updated in 2002, set targets for CO2 and other GHG emissions to be achieved through measures concerning various sectors of the Italian economy, including a reduction of carbon produced in thermal electricity generation, an increased use of electricity generation from renewable resources and demand-side management to increase the efficiency of energy use. Furthermore, the guidelines promote certain projects aimed at the development of so called clean energy.
      In July 2000, we signed a voluntary undertaking with the Environment Ministry and the Ministry of Productive Activities to reduce the annual level of CO2 emissions produced by our plants during the period between 2002 and 2006 from our level of emissions in 1990. The undertaking anticipates a number of measures to reduce GHGs emissions, including employing high-efficiency technologies, such as CCGT conversions, promoting the use of renewable resources and developing innovative generation technologies.
      In January 1999, the Italian government introduced a carbon tax in accordance with European Union directives. The carbon tax is designed to reduce Italy’s CO2 emissions so as to comply with the Kyoto Protocol. Under the current Italian legislation, the amount of the tax, which is based on fossil fuel consumption, although initially scheduled to increase on an annual basis from 1999 through 2005, has been frozen at the level for 1999. The relevant EU directives provide for a periodic review of this tax, including its possible abolition. We and other European electricity companies believe that, with the introduction of the emission trading rules in January 2005, the carbon tax should have been abolished in order to avoid market distortion and double taxation since both this tax and the emission trading rules have the objective of reducing CO2 emissions to comply with the Kyoto Protocol.
      In the period between 2003 and 2005, our carbon tax liability decreased from approximately 40 million in 2003 and 2004 to 37 million in 2005.
      With a view to ensuring compliance with the Kyoto Protocol, in 2003 the EU adopted an Emission Trading Directive establishing a scheme for GHG emission allowance trading. Italian legislation partly implementing this directive came into force at the end of 2004. In October 2004, the EU also passed another directive (the so-called “linking directive”), which amended the Emission Trading Directive to allow the use of other flexible mechanisms for limiting GHG emissions. The Legislative Decree fully implementing the EU legislation on emission trading in Italy entered into force on June 20, 2006.
      The Emission Trading Directive requires that each member state submit to the European Commission a proposal on how it plans to comply with the directive’s emission limits. This proposal is to consist of an allocation plan by which each member state sets CO2 emissions thresholds for the 2005-2007 period for various industries, including the energy sector, and must provide for fines to be imposed on entities whose emissions exceed these thresholds. In 2006, the allowable levels for the 2008 to 2012 period will be established.

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      In July 2004, the Environment Ministry and the Ministry of Productive Activities submitted to the European Commission a national allocation plan for Italy. Under the national allocation plan, the thresholds for thermal power plants would vary depending on the type of fuel burned, so as not to disadvantage plants that burn fuels such as coal, which, although generating higher levels of emissions, contribute to the stability and reliability of supply. In December 2004, the Italian government put in place the procedures necessary to authorize plants to emit GHGs and to gather the necessary information to grant emission rights. We received the relevant authorizations for our power plants in December 2004. In an amendment to the national allocation plan published on February 2005, the Enel Group was assigned emissions quotas of 54 million, 45 million and 45 million metric tons of CO2for the years 2005, 2006 and 2007, respectively. Viesgo Group has been assigned emission quotas for its existing installations of 3.9 million, 3.4 million and 2.65 million metric tons of CO2 for the years 2005, 2006 and 2007, respectively.
      On May 25, 2005, the European Commission approved Italy’s national allocation plan, including, however, modifications that reduce the allowable emissions assigned to Italy by 9% (from 255 million metric tons to 232 million per year), which therefore required a revision to the February 2005 emissions quota allocations. On February 23, 2006, the Environment Ministry issued a decree establishing the emissions quotas for the Enel Group from 2005 through 2007, reducing the quotas we had been granted in February 2005 to 48.2 million, 40.5 million, 39.9 million tons of CO2 for the years 2005, 2006 and 2007 respectively.
      Enel’s actual emissions in 2005 were higher than the emission quotas to which its plants were entitled for that year by approximately 8 million tons in Italy and approximately 2 million tons in Spain. Our emission quotas for the years 2006 and 2007 are substantially in line with the level of emissions we are currently projecting for those years. Moreover, these quotas allocations do not include allowances reserved for new plants.
      The measures that we plan to implement in order to comply with the Emission Trading Directive limits and Italian implementing legislation include:
  •  Switching fuel;
 
  •  Converting existing oil-fired thermal power plants into gas-fired or high-efficiency coal-fired plants;
 
  •  Increasing renewable energy capacity; and
 
  •  Sourcing CO2 credits through the development of Clean Development Mechanism (CDM) and Joint Implemetation (JI) projects in the energy sector (in particular geothermal), investing in carbon funds and purchasing emission reductions through bilateral contracting.
SO2, NOx and Other Emissions
      The principal EU directive on air emissions affecting the electricity industry is the large combustion plants directive (“LCPD”). The LCPD requires each EU member state to establish and implement a program of progressive reduction of total SO2 emissions and total NOx emissions from generation plants licensed before July 1, 1987, and to establish emission limits for SO2, NOx and particulate matter from individual generation plants licensed after July 1, 1987. In 2001, new, more stringent emission limits were set in an amendment to the LCPD.
      Limitations on plant emissions set by Italian legislation are stricter than those envisaged in the LCPD as well as in the 2001 amendment (which Italy has not yet implemented), also requiring 5-year gradual reduction targets of aggregate emissions from plants licensed prior to July 1, 1988 through the end of 2003. We achieved the required reductions in each of the years in which they were applicable, including 2003.
      In addition, Italy is bound by an EU directive issued in 2001 mandating that member states achieve specified reduction targets on SO2, NOx, volatile organic compounds and NH3 emissions by 2010. To this end, member states were required to establish and implement a program of emissions reduction in order to achieve the targets set in the directive. Italy is also a member of the Helsinki Protocol and the Oslo Protocol, which require signatory countries to reduce SO2 emissions, and the Sofia Protocol, which requires signatories to reduce NOx emissions. The requirements under these protocols have been reflected in Italian law.

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      In addition, in 1990, Italy established a regulation limiting emissions of polluting substances from thermal plants licensed before July 1, 1988 that is more strict than the LCPD and covers a much broader range of pollutants. This regulation required that individual existing thermal plants in Italy reduce emissions to levels similar to those established under the LCPD for individual plants licensed after July 1, 1988. This regulation also provided a time schedule for the implementation of environmental compliance measures at existing plants.
      In response to this regulation, in 1990 we implemented a significant program of environmental measures that affect our entire thermal generation operation. We submitted this program to the relevant ministries of the Italian government, including those for industry, environment and health. The program was approved and provided for modifications of both physical plant and operating practices. Enel has achieved the targets the Italian regulation provided for the implementation of these environmental compliance measures for generating facilities.
      We are currently in compliance with the limits set by existing legislation. We had received a derogation from the required limits with regard to our plant at Porto Tolle pending our receipt of required authorizations to effect a conversion of the plant to make it fully compliant. While this derogation expired on December 31, 2004, we expect to complete the conversion of this plant by 2011, and meanwhile are meeting the required limits at the plant through operational means.
      The following tables show the level of SO2 and NOx emissions from our power plants included within our present limits in the period from 2001 to 2005, and the percent reductions in the level of these emissions compared to 2000.
Reductions of SO2 emissions against 2000 levels
                 
        Percentage
Year   Metric Tons   Change
         
    (In thousands)    
2001
    213       (11 )
2002
    187       (21 )
2003
    101       (58 )
2004
    94       (61 )
2005
    73       (69 )
Reductions of NOx emissions against 2000 levels
                 
        Percentage
Year   Metric Tons   Change
         
    (In thousands)    
2001
    71       (8 )
2002
    71       (9 )
2003
    62       (20 )
2004
    56       (28 )
2005
    49       (37 )
      In 1997, the Italian parliament imposed a tax on total SO2 and NOx emissions from thermal plants that have a nominal capacity greater than 50 MW. These plants are the same plants as those regulated under the LCPD. In 2003, 2004 and 2005, our costs in connection with this tax were approximately 9 million, 8 million and 7 million, respectively.

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PCBs and Asbestos
      In May 1999, the Italian government adopted a legislative decree concerning the recovery and disposal of electric transformers and other equipment containing polychlorinated biphenyls, or PCBs. The decree provides that:
  •  electric transformers and other equipment which contains PCBs above 500 parts per million must be decommissioned or decontaminated by 2009;
 
  •  equipment which contains PCBs below the limit set out above can be used until the end of its operational life; and
 
  •  equipment which has been contaminated by PCBs spillage must be decommissioned by 2005.
      In December 2003, we adopted a disposal plan to comply with this legislation and we are delivering all of our equipment containing PCBs to companies authorized to recover and dispose of such equipment. We estimate the phasing out of the equipment containing more than 500 ppm to be completed by 2006 and the phasing out of the equipment containing less than 500 ppm by 2010.
      We also deliver waste products containing asbestos to specialized companies authorized to treat and dispose of asbestos. Such waste products derive from the clean up of our plants we conduct in accordance with our general maintenance and environmental clean-up programs.
Water Pollution Prevention
      We are subject to environmental laws and regulations limiting heat and other physical and chemical characteristics of cooling water and industrial water discharges from our thermal plants and hydroelectric plants. In May 1999, the Italian parliament adopted a new law for the prevention of the pollution of fresh and salt water, which was amended in August 2000. In the same year, the EU adopted a directive to prevent water pollution. We believe that the waste water treatment facilities already in operation at our generation plants are in line with the new requirements on waste water under EU law.
      In April 2006, Italy implemented the EU directive on water pollution through a legislative decree, which in addition took initial steps to reorganize Italy’s environmental regulations, in this field. We do not believe that this reorganization, which will be completed through additional decrees, will materially change the obbligations to which we are subject with respect to water pollution.
Solid Waste Management
      In February 1997, the Italian government issued a legislative decree implementing the EU directives on solid waste management. In accordance with this decree, we increased the level of recycling of our waste. In the last five years, our waste recovery rate has always exceeded 90%.
Site Clearance
      Italian legislation provides for ground and underground inspections to evaluate the possible contamination of sites, particularly in areas declared to be of national interest, using specific chemical, physical and historical analyses. If sites we own are found to be contaminated, the current regulation requires that we undertake a program of site clearance and remediation. In that case, under new legislation, the Italian government may provide financial support for remediation with respect to contaminated sites located in areas of national interest. Our costs of compliance with these measures were 16 million in 2005. For 2006, we currently expect to spend approximately 10 million.

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Landscape Safeguards
      We have taken the following actions to reduce the environmental impact of our power distribution lines:
  •  re-using routes of previous power lines wherever possible;
 
  •  using towers for high voltage lines whose design is aimed at reducing the environmental and aesthetic impact in non-urban areas of particular landscape value;
 
  •  acting to reduce the impact of lines in environmentally sensitive or protected areas;
 
  •  increasing use of underground cables in urban areas where possible;
 
  •  for medium-voltage lines, placing underground cables in urban areas and aerial cables with low environmental impact in other areas with specific environmental value; and
 
  •  using aerial insulated cables or underground cables in low voltage networks (at present, we have built approximately two-thirds of our network in this way).
      We limit our use of underground high-voltage cables to urban areas because they are significantly more expensive than aerial cables and the process of installing and operating them may involve significant logistic and environmental problems. In 2003, our medium voltage aerial insulated cables and underground cables totaled 127,987 kilometer, which represented 38.3% of our medium voltage lines, compared to 35.9% in 2000, and our low voltage aerial insulated cables and underground cables totaled 600,675 kilometer, which represented 82.5% of our low voltage lines, compared to 80.6% in 2000.
      In 2005, due to further work on our network, the percentage of aerial insulated cables and underground cables rose to 40% and 83% for medium and low voltage lines, respectively.
Environmental Registrations, Certifications and Authorizations
      We have joined EMAS, a European Union initiative to implement a voluntary environmental management and registration system, which seeks to improve the level of environmental efficiency and disclosure of European industrial companies. Rules concerning EMAS are contained in an EU Regulation issued in 1993. Originally applicable only to individual sites, in 2001 the EU passed a new regulation which extended the scope of the EMAS system to groups of sites and non generation assets, such as distribution networks.
      In October 2004, Enel Distribuzione’s distribution network obtained ISO 14001 environmental certification. As of December 2005, generating plants that accounted for approximately 77% of our net installed generating capacity had obtained ISO 14001 certification. One hundred and thirty plants that accounted for approximately 43% of our net installed capacity have also obtained EMAS registration.
      EMAS registration has significant advantages in terms of the operation of our assets. In August 1999, the Italian government enacted a legislative decree implementing the 1996 EU directive on the prevention and reduction of pollution. This legislative decree requires all industrial plants to operate under a new integrated environmental license by 2007 and to make use of the best techniques available for the prevention and reduction of pollution. The new licenses set pollution limits and are reviewed every five years or at any time plants undergo significant renovation. This law, however, allows licenses for EMAS-registered plants to be reviewed every eight years (instead of five) in light of the stringent requirements that must be met to obtain EMAS registration.
Cost of Compliance
      The costs of ensuring compliance with applicable environmental regulation generally consist of costs associated with equipping newly constructed facilities with required technology or modifying existing facilities to comply with applicable regulation.
      In 2005, environmental capital expenditures were equal to approximately 100 million, representing 3.1% of our total capital expenditures. In 2003 and 2004, these environmental capital expenditures totaled 131 million and 112 million, respectively, representing 3.5% and 2.9%, respectively, of our total capital expenditures. In 2005 current expenses for compliance with environmental regulations were equal to approximately 350 million,

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of which we spent approximately 260 million on the purchase of ‘clean’ fuels (low-sulphur oil and natural gas) in lieu of standard fuels, when required. These amounts do not include taxes on fuels, polluting emissions and geothermal generation and possible loss of revenues due to compliance with environmental standards that limit the operation of our plants.
Discontinued Nuclear Operations
      Since November 2000, we have not owned any nuclear power plants. We have not produced electricity from nuclear power plants in Italy since 1988. For information on the nuclear power plants we now control in Slovakia and our nuclear related initiatives in France, please see “— Nuclear Liability” below.
      Following a national referendum in 1987 in which the Italian electorate expressed its opposition to the use of nuclear power, the Italian government ordered the interruption of power production from nuclear fuels and we ceased operations at our four nuclear plants in Italy, which had an aggregate net installed capacity of 1,500 MW.
      In addition to our nuclear power plants, we owned a 33% stake in NERSA, an electricity generation company that operated a nuclear power plant located in France. French and German utilities owned the balance of NERSA. In July 1998, we sold our stake in NERSA. We, however, retained ownership and responsibility for the decommissioning of our share of the nuclear fuel in the plant.
      Pursuant to the Bersani Decree, we transferred our discontinued nuclear operations to So.g.i.n., then one of our wholly owned subsidiaries. The principal activity of So.g.i.n. will be the decommissioning of the nuclear plants and of our share of the nuclear fuel in the NERSA plant in France, including disposal of nuclear fuel and nuclear waste.
      Under the Bersani Decree, we were required to transfer to the MEF all the shares of So.g.i.n. at no cost. The transfer was completed on November 3, 2000.
Nuclear Liability
      Italy is a party to the 1960 Paris Convention on Third Party Liability in the Field of Nuclear Energy and the 1963 Brussels Supplementary Convention. Italian law implementing the conventions imposes strict liability for claims relating to nuclear plants and the transportation and storage of nuclear matter. Strict liability under Italian law means that someone does not need to be negligent in order to be found liable. The law imposes strict liability for nuclear accidents only on the entity that is the operator of the plant at the time of the accident. Consequently, we are not liable for any accident that may occur after the transfer to the MEF of So.g.i.n.’s shares on November 3, 2000, even if the cause of the accident predates the transfer. Although we are not aware of any accident that predates the transfer, we will remain liable for any accident that occurred before the transfer, even if the damage, or the accident itself, is discovered in the future. The operator of the plant may claim reimbursement from a third party which has contributed to the cause of the accident for any sums it may have to pay but only if that party has accepted liability contractually or is a physical person who has intentionally caused the damage. Italian law implementing the conventions imposes a maximum period of ten years from the date of the accident in which someone claiming damages must bring claims. At the time of our transfer of So.g.i.n.’s shares, we represented to the Treasury that we had performed, on a regular basis, every required test on our nuclear plants and that we were not aware, with respect to all nuclear assets owned by So.g.i.n., of any event which might be the source of civil liability for nuclear operations.
      Under Italian law and in accordance with the Paris Convention, direct liability arising from nuclear liability claims is limited to five million International Monetary Fund Special Drawing Rights (“SDRs”) per accident. Under Italian law, to the extent any claim exceeds five million SDRs, someone claiming damages may sue us for only five million SDRs and must sue the Italian government for the excess liability up to 175 million SDRs. If the claim is in excess of 175 million SDRs, that person must sue the signatories to the conventions, but then only for the excess liability up to 300 million SDRs. However, the Italian government can claim reimbursement from us for any sums it may have to pay because of a nuclear accident arising from negligence on our part. On May 31, 2006, the value of five million SDRs equaled approximately 5.9 million.

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      A provision of the Italian law implementing the conventions states that when damage has been caused concurrently by a nuclear accident and the emission of ionizing radiation, the liability of the person that caused this radiation is not subject to the limitations described above for damages caused by that emission. This provision does not fully conform to the conventions because it does not specify that the ionizing radiation must not independently qualify as a nuclear accident in order to give rise to unlimited liability. We believe, however, that the correct interpretation of Italian law implementing the conventions is that only radiation not classified as a nuclear accident gives rise to liability outside the limitations described above. We believe all emissions of radiation originating from within nuclear plants would qualify as nuclear accidents. As a consequence, because we held nuclear material inside our plants, we believe that we could only be liable for amounts beyond the limitations described above under remote circumstances.
      In April 2006, we finalized the acquisition of 66% of Slovenske Elektrarne, the major generating company in Slovakia, which owns nuclear power plants. Slovakia is a party to the Vienna Convention on Civil Liability for Nuclear Damages, under which operators of nuclear installations are subject to strict liability of at least $5 million which may be claimed for a period of ten years from the date of the nuclear incident, except when national legislation provides for different limits or longer periods. Slovakian law provides for a 75 million maximum liability for the operation of nuclear power plants (50 million for the transportation of nuclear materials) and a 20-year limit from the date of the nuclear incident for the right to compensation. We have purchased insurance coverage for claims up to ten years through the insurance market and are seeking additional coverage for claims arising after ten years.
      On May 30, 2005, we entered into a memorandum of understanding with EDF regarding an industrial partnership that would permit us to invest in the French electricity market, including in EDF’s latest generation European Pressurized Water Reactor, or “EPR,” nuclear power plant project. Under the memorandum of understanding, EDF will be the operator of the power plant, and will bear any related nuclear civil liability. For additional information, please see “— Business — The Enel Group — Generation and Energy Management — International Generation.”
Property, Plants and Equipment
      At December 31, 2005, we had 761 generating plants, consisting of thermal, hydroelectric, geothermal and other renewable resources facilities, 599 of which were located in Italy. For further information with respect to our plants, please see “— Business — The Enel Group — Generation and Energy Management.” We own the principal electricity distribution network in Italy, which consisted, at December 31, 2005, of a total of 1,090,129 kilometer of lines, mostly medium and low voltage, and 413,429 primary and secondary transformer substations. For a description of such properties and related construction, expansion and improvement plans, please see “— Business — The Enel Group — Capital Investment Program — Sales, Infrastructure and Networks.” At December 31, 2005, we owned real estate, mainly in Italy, with an approximate net book value of 872 million, consisting mainly of office buildings and other commercial properties and to a lesser extent residential real estate. For a description of our real estate properties and activities, please see “— Business — The Enel Group — Services and Other Activities — Real Estate and Other Services.”
      Management believes that our significant properties are in good condition and that they are adequate to meet our needs.
ITEM 4A. UNRESOLVED STAFF COMMENTS
      Not applicable.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
Summary of Results
      Following the coming into force of European Regulation No. 1606 dated July 2002, we and other EU companies whose securities are traded on regulated markets in the EU are required to adopt IFRS (known as international accounting standards, or IAS, until May 2002) in the preparation of our 2005 consolidated financial

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statements. Our financial statements for the period ending December 31, 2005, were prepared in accordance with International Financial Reporting Standards as adopted by the European Union. Standards introduced prior to the renaming of IAS as IFRS are still referred to as IAS; we refer to the combined body of IAS and IFRS standards as IFRS.
      You should read note 20 to our consolidated financial statements for additional information on our transition to International Financial Reporting Standards.
      In 2005, our consolidated operating revenues increased by 3,048 million, or 9.8%, from 31,011 million in 2004 to 34,059 million in 2005. Our operating expenses, excluding depreciation, amortization and impairment increased by 3,374 million, or 14.7%, from 22,940 million in 2004 to 26,314 million in 2005. Our operating income decreased by 332 million, or 5.7%, from 5,870 million in 2004 to 5,538 million in 2005. Our financial income (expense) and income (expense) from investments decreased by 113 million, or 13.7%, from 827 million in 2004 to 714 million in 2005. Our income (expense) from investments accounted for using the equity method increased by 5 million, or 20.0%, from 25 million in 2004 to 30 million in 2005. Our net income, including discontinued operations, increased by 1,385 million, or 50.4%, from 2,747 million in 2004 to 4,132 million in 2005 (while our income from continuing operations decreased by 42 million, or 1.4%, from 2,902 million in 2004 to 2,860 million in 2005).
      Our principal measure of liquidity is net financial indebtedness, which was 12,312 million at December 31, 2005, as compared to 24,514 million at December 31, 2004. Net financial indebtedness is a non-GAAP measure; cash at banks and marketable securities, the most directly comparable IFRS measure, was 508 million at December 31, 2005, as compared to 363 million at December 31, 2004. Please see “— Liquidity and Capital Resources — Capital Resources” for a reconciliation of net financial indebtedness to cash at banks and marketable securities. As of December 31, 2005, we had 51,778 employees, as compared to 61,898 as of December 31, 2004.
The Electricity Market Regulatory Framework
Overview
      Our financial results have been and will be affected to a large extent by the developments in the regulatory framework for the Italian electricity market, which was first opened to competition by the Bersani Decree in 1999 and has been subsequently further liberalized by EU and national legislation. The Bersani Decree also provided for the first time that certain customers, also known as Eligible Customers, could freely choose their supplier and buy electricity on the free market at negotiated prices. This freedom was progressively extended, from customers with high consumption thresholds, to all non-residential customers as of July 1, 2004. In 2007, all customers will become Eligible Customers. Currently, Non-Eligible Customers must purchase electricity from their local distribution company. The price of electricity for Non-Eligible Customers is set by the Energy Authority.
      On April 1, 2004, the Italian power exchange, a virtual marketplace for the trading of electricity, started operations. The Single Buyer, a state-owned entity entrusted with the responsibility of purchasing all of the electricity to be supplied to the regulated market, also started operations on that date. Please see “— Comparability of Information — Regulatory and Other Developments” for a description of the impact of the start of operation of the Italian power exchange and the Single Buyer on our results in 2004.
      Since the start of the liberalization of the market, the Energy Authority, the Antitrust Authority and the European Commission have adopted several measures to further competition and constantly monitor the market in order to reduce the risk of abuses of market power. Furthermore, under the Bersani Decree, no single company or group could have more than a 50% market share of the electricity generation and import market after January 1, 2003, a limit which resulted in our sale of the Gencos.
      In light of Italian laws and regulations providing for the reunification of the ownership and management of the Italian transmission grid and imposing certain ownership restrictions on the entity that owns and manages it, we disposed of most of our interest in Terna during 2005, and now hold only 5.12% of Terna’s share capital. You

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should read “Item 4. Information on the Company — Business — The Enel Group — Discontinued Operations — Transmission” for more details on our sale of Terna shares.
      Please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation” for a more detailed discussion of the regulatory framework of the electricity market and “Item 3. Key Information — Risk Factors — Risks Relating to Our Energy Business” for a discussion of the principal regulatory and other risks we face.
Tariffs and Prices
      Most of our operating revenues come from the sale of electricity in Italy. The price of electricity in Italy has historically been determined by a system of tariffs. Since the liberalization of the electricity market, the Energy Authority has set tariffs for electricity sold on the regulated market, updating them periodically. The Energy Authority also sets transport charges payable by all customers for the transmission and distribution of electricity. Electricity on the free market can be bought through bilateral contracts or on the Italian power exchange.
      Our operating revenues from electricity operations are directly related to the level of transport charges and the price of electricity for the regulated market. In addition, our revenues also include some system charges. Please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation — The Tariff Structure” for a more detailed discussion of these charges.
      The tariff regime that applied in the period from 2002 through February 2004 included:
  •  a “generation cost component,” reflecting fuel costs; and
 
  •  the application of global price-cap reductions to transmission and distribution transport charges.
      In 2004, the Energy Authority set new base tariffs for the 2004-2007 period, which have been in force since February 1, 2004. The Energy Authority has estimated that the new tariff regime in place for 2004-2007 will result in a reduction of the overall tariff paid by regulated market customers of approximately 13% in real terms (assuming no change in fuel costs and system charges) during the period. The actual impact of tariff levels on our revenues depends on a number of factors, including the volume of electricity we sell in the regulated market, fluctuations in fuel prices and the mix of customers we serve.
      Prices for electricity sold on the Italian power exchange are determined on the basis of competitive bidding (please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation — The Italian Power Exchange”). Prices on the power exchange also influence the generation cost component of the tariff, which is now calculated by the Energy Authority every three months on the basis of an estimate of the average costs that the Single Buyer incurs for the procurement of electricity, both on the Italian power exchange and through bilateral contracts. The tariff structure currently in place also includes certain mechanisms to take into account structural factors affecting distributors’ costs.
      Please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation — The Tariff Structure” for a more detailed discussion of electricity charges.
Macroeconomic Factors
      Electricity demand in Italy grew by 1.3% in 2005, after having grown by 1.5% in 2004. Growth in demand for electricity is determined by a variety of factors, including the rate of economic growth, the level of business activity and weather conditions. Please see “Item 4. Information on the Company — Business — The Enel Group — Italian Electricity Demand” for more information.
      Interest rates in Italy and the rest of Europe have declined in recent years, though they have begun to increase in 2006. The weighted average interest rate on our long-term debt as of December 31, 2005 was 3.9% (in line with the rate of 3.8% as of December 31, 2004). Our financing costs increase or decrease in line with changes in interest rates.
      Although historically we were insulated to a significant extent from the economic effect of fluctuations in fuel prices through the application of the fuel cost component of the tariff described above, time lags between our

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actual purchase of fuel and the calculation and payment to us of such fuel cost component affected our revenues and income. As a result of the introduction of the Italian power exchange, which began operations on April 1, 2004, and increases in the number of consumers qualifying as Eligible Customers, we now face increased risks relating to fuel price fluctuations, which we attempt to manage through the implementation of our hedging policy. Please see “Item 11. Quantitative and Qualitative Disclosure About Market Risk — Price Risk Management and Market Risk Information” for a more detailed description of our hedging policy.
Critical Accounting Policies
      Our results of operations, as presented below, are based on the application of IFRS. The application of these principles often requires management to make certain judgments, assumptions and estimates that may result in different financial presentations. We believe that certain accounting principles are critical in terms of understanding our financial statements. We believe that our most critical accounting policies relate to the following factors.
      Use of estimates. The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Certain accounting principles require subjective and complex judgments used in the preparation of financial statements. Accordingly, a different financial presentation could result depending on the judgment, estimates or assumptions that are used. Such estimates and assumptions, include, but are not specifically limited to: depreciation, amortization, interest rates, discount rates, future commodity prices, investment returns, impact of new accounting standards, international economic policy, future costs associated with long-term contractual obligations and future compliance costs associated with environmental regulations. Actual results could materially differ from those estimates or assumptions. Effective January 1, 2005, the economic depreciation rates of certain assets related to power generation plants were revised in order to better reflect the estimated economic useful life of these facilities. Please see “Increased estimates of the useful lives of certain distribution assets” in “— Comparability of Information — Regulatory and Other Developments.”
      Revenue Recognition. We usually record revenues for sales to retail and wholesale customers under the accrual method. Under both IFRS and U.S. GAAP, revenues from sales of electricity and gas to retail customers are recognized when the power and gas are provided to customers on the basis of periodic meter readings and include an estimate of the value of the power and gas consumed from the meter reading date to the end of the period. Revenues for the period after the date of the reading to the end of the period are estimated on the basis of estimates of the daily consumption of the customer based on his historical profile, adjusted to reflect weather and other factors affecting consumption.
      Pension and other post-retirement benefits. Many of our employees are covered by pension plans, which provide retirement benefits based upon their historical earnings and years of service. Certain employees are also covered by other post-retirement benefit plans. We base our calculation of the estimated expenses and liabilities related to these plans on estimations provided by our actuarial consultants who use a combination of factors, including statistical data from past years and predictions about future expenses. We consider quantifiable factors, such as withdrawal and mortality rates, along with assumptions about future changes in the discount rate and the rate of future compensation increases, and analyses of trends in health care costs. These estimates may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants and changes in the actual costs of health care. These differences may have a significant impact on the amount of pension and other post-retirement benefit expenses recorded.
      Recoverability of long-lived assets. We periodically review the carrying value of our long-lived assets held and used and that of assets to be disposed of, including goodwill and other intangible assets, when events and circumstances warrant such a review. If the carrying value of a long-lived asset group is considered impaired, an impairment charge is recorded for the amount by which the carrying value of the long-lived asset group exceeds its estimated recovery value, in relation to its use or realization, as determined by reference to the most recent corporate plans. Management believes that the estimates of these recovery values are reasonable; however, changes in estimates of such recovery values could affect the relevant valuations. The analysis of each long-lived

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asset group is unique and requires management to use certain estimates and assumptions that are deemed prudent and reasonable for a particular set of circumstances.
      Realization of deferred tax assets. As of December 31, 2005, we had assets recorded for tax loss carry-forwards. We have recorded our deferred tax assets in an amount that we believe is more likely than not to be recovered. The recoverability of the deferred tax assets associated with the tax loss carry-forwards are subject to the achievement of future profitability by the entities that recorded such losses. While we have considered future taxable income and used ongoing prudent tax planning strategies in assessing the need for valuation allowances, should we determine that we would not be able to realize all or part of our net deferred tax assets in the future, the resulting adjustment to the deferred tax assets would be charged to income in the period such determination was made.
      Litigation. We are defendants in a number of legal proceedings incidental to the generation, transmission and distribution of electricity. Because of the nature of these proceedings, it is not possible to predict the ultimate outcomes of certain of these matters, some of which may be unfavorable to us. However, provisions are made for all significant liabilities where it has been determined by legal advisors that an unfavorable outcome is probable and the amount of loss is estimable. A number of disputes are pending in relation to urban planning, landscape and environmental matters (mainly related to exposure to electromagnetic fields) linked to the construction and operation of several of our generating plants and power lines. The examination of such disputes, including on the basis of legal advice, leads us to believe that unfavorable outcomes would be a remote possibility. While the possibility is remote, the risk that a limited number of cases might have unfavorable outcomes, which could entail the payment of damages, cannot be ruled out. At the present time, the possible imposition and magnitude of any such damages are not predictable and, we have, therefore, not accrued any liabilities for these disputes.
      Allowance for doubtful accounts. Our allowance for doubtful accounts reflects our estimate of losses inherent in our credit portfolio. We have established provisions for expected credit losses, based on past experience with similar receivables, including current and historical past due amounts, write-offs and collections, the careful monitoring of portfolio credit quality and the current and projected economic and market conditions. We believe that our reserves are adequate; however, different assumptions or changes in economic circumstances could result in changes to the allowance for doubtful accounts and therefore could affect earnings.
Comparability of Information
      Several factors significantly affected the inter-period comparability of the information presented in this section, including changes in market regulation and other developments, changes in our scope of consolidation and changes in our business segment presentation. These factors, which should be considered when reviewing the performance of our individual segments and of the Group as a whole, are discussed below.
Regulatory and Other Developments
      The most important regulatory developments affecting our financial results for 2005 are discussed below.
  •  Start of operation of the Italian power exchange and the Single Buyer. On April 1, 2004, the Italian power exchange for the spot trading of electricity started operations and the Single Buyer became responsible for purchasing all of the electricity to be supplied to the regulated market. Please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation” for a detailed discussion of the Italian power exchange, the Single Buyer and related developments in the Italian electricity market. As a result of this development, since April 1, 2004, our Generation and Energy Management segment sells the electricity it produces that is destined for the regulated market to the Single Buyer, and our Sales, Infrastructure and Networks segment purchases the electricity that it distributes on the regulated market from the Single Buyer. These sales and purchases are recorded as operating revenues and operating expenses, respectively. Before April 1, 2004, our Generation and Energy Management segment sold electricity for distribution on the regulated market directly to our Sales, Infrastructure and Networks segment, and the revenues and costs arising from these sales were eliminated from, and therefore not recorded in, our consolidated financial statements. As a result, both our operating revenues and operating expenses have increased substantially on a consolidated basis since April 1, 2004. Sales to the Single

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  Buyer are now included in the line item “Sales to regulatory entities, sales on the free market and sales on foreign markets” in the results presented below. For prior periods, this line item was referred to as “Sales to Eligible Customers, sales to the GRTN and sales on foreign markets,” as the Single Buyer was not fully operational. Purchases from the Single Buyer are recorded in the operating expense line item “Purchased Power.”
 
  •  Capacity payments. In order to address a current deficit in Italian generation capacity relative to rising electricity demand, the regulatory framework provides incentives to power generators both to build new capacity as well as to maintain their existing plants in good working order and available to cover sudden variations in electricity demand. Effective March 1, 2004, the Energy Authority established a provisional system of payments to remunerate producers that make generation capacity available to the electricity system at times of peak demand, known as “capacity payments.” Capacity payments to a given producer comprise both an amount due for capacity available on “critical” days (set by the GRTN and now by Terna) and a further amount payable when pool market prices fall below specified thresholds, as an extra incentive. This provisional system has been in place from March 2004 and during all of 2005.
 
  •  August 2004 decree on stranded costs. Stranded costs are current costs deriving from contractual commitments or investment decisions that electricity companies undertook for reasons of public policy, at a time when the electricity markets were not yet open to competition, and could have been recovered in a monopoly regime but cannot be recovered under a regime of competitive electricity pricing. Please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation” for more information on stranded costs. In August 2004, the MEF and the Ministry of Productive Activities issued a joint decree that determined the overall amount of stranded costs we are entitled to recover. On December 1, 2004, following the European Commission’s approval of the decree, we became entitled to recover approximately 513 million on account of stranded costs related to our generation plants for the period 2000-2003, as well as our stranded costs related to the Nigerian LNG contract, which were determined to be 555 million in respect of the 2000-2003 period and approximately 910 million in respect of the 2004-2009 period (151 million of which related to 2004). As a result, in 2004 we recorded as “other revenues” a total of 1,219 million arising in connection with stranded costs, the amount we became entitled to receive in respect of 2004 and prior years under the August 2004 decree. Of this total, the 513 million related to our generation plants and the 151 million related to the Nigerian LNG contract for 2004 were recorded by our Generation and Energy Management segment, and the 555 million related to the Nigerian LNG contract in respect of the 2000-2003 period were recorded by our Corporate segment. In 2005, our Generation and Management segment recorded 158 million for stranded costs related to our Nigerian LNG contract. In 2005, we received payments amounting to 361 million for stranded costs accounted in 2004. We have yet to receive any other amount in this regard.
 
  •  Increased estimates of the useful lives of certain generation assets. Effective January 1, 2005, following an independent appraisal, we increased our estimates of the useful lives of certain assets related to power generation plants. As a consequence, the amount of depreciation expense we recorded in 2005 with respect to these assets was lower than the amount recorded for the same assets in 2004 by 100 million.

Changes in Scope of Consolidation
      The principal transactions that have resulted in changes in our scope of consolidation during the periods under review were the following:
  •  the disposal of a controlling stake in Terna as of September 15, 2005;
 
  •  the disposal of a controlling stake in Wind as of August 11, 2005;
 
  •  the acquisition of Enel Electrica Banat and Enel Electrica Dobrogea as of April 28, 2005;
 
  •  the acquisition of Italgestioni and Italgestioni Gas (together, the “Italgestioni Group”), which are companies active in the distribution and sale of natural gas to end users in the provinces of Calabria and Naples, as of December 14, 2004;

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  •  the acquisition of Ottogas Rete and Ottogas Vendita (together, the “Ottogas Group”), which are companies active in the distribution and sale of natural gas to end users in the area of Naples and Salerno, as of September 15, 2004; and
 
  •  the disposal of NewReal (a real estate company) as of July 14, 2004.
Business Segments
      In 2005, our operations were organized, reflecting our internal structure, into six business segments: Generation and Energy Management; Sales, Infrastructure and Networks; Transmission; Telecommunications; Services and Other Activities; and Corporate.
      At the end of 2005, our management decided to re-organize the Group’s internal structure by substituting our Sales, Infrastructure and Networks Division with two separate divisions (a Market Division and an Infrastructure and Networks Division) and by allocating our international generation and distribution operations, which had previously been included in other divisions, to a new International Division. Our divisions are currently the following: Generation and Energy Management Division, Market Division, Infrastructure and Networks Division and the International Division. Each division is headed by a senior manager who reports directly to the Chief Executive Officer of Enel. Moreover, all non-core activities provided by companies of the Group to all Group companies have been grouped in our Services and Other Activities sector. Enel, as the parent company, defines the strategic objectives for the Enel Group and coordinates the activities of all Group companies. Each of Enel, our divisions and the Services and Other Activities sector constitutes a reportable segment. However, such reorganization of our business segments will be effective from January 1, 2006 and, therefore, the reportable segments presented in our financial statements for 2005 (and the segment information presented below) still reflect the structure that we had in 2005 with our former Transmission and Telecommunications segments each being treated as discontinued operations following the deconsolidation of Terna and Wind.
      Generation and Energy Management. This segment corresponded to the division that was responsible for our operations related to the production of electricity and the procurement and trading of fuel for electricity generation, and included power generation activities in Italy and abroad. This division generated operating revenues mainly from the sale of electricity to the Single Buyer (or, prior to April 1, 2004, to our Sales, Infrastructure and Networks Division), to the GRTN and Terna and other resellers in the domestic electricity market, as well as through fuel trading. The division, which procured fuel for all of the companies of the Group, also sold natural gas to our Sales, Infrastructure and Networks Division and to third parties. This division also sold electricity to large electricity users, or Eligible Customers, with annual electricity consumption higher than 100 GWh. The main companies in this division included the following: in Italy, Enel Produzione (thermal and hydroelectric generation), Enel Green Power (geothermal, hydroelectric and wind power generation), and Enel Trade (fuel procurement and trading, risk management, sales to large electricity users). We merged Enel Green Power into Enel Produzione as of June 1, 2005. Outside of Italy, this division included the following operations for most of the period presented herein: Enel Viesgo Generaciòn and EUFR in Spain, Maritza East III in Bulgaria; Enel North America in the U.S.; and Enel Latin America in Central and South America. The results from our international generation operations through December 31, 2005 are included in those of our Generation and Energy Management segment.
      Sales, Infrastructure and Networks. This segment corresponded to the Sales, Infrastructure and Networks division that included our electricity and gas network operations and carried out distribution and sales of electricity on the regulated market and to free market customers with an annual electricity consumption of 100 GWh or lower in Italy. It also distributed and sold natural gas to end users and provided public and art lighting services and electricity systems-related services. This division also included our electricity distribution and sales activities outside of Italy. Operating revenues at this division derived primarily from fees for transport of electricity and gas on our distribution networks, the sale of electricity on the regulated and free markets and of natural gas to end users. Electricity-related activities included in this division were carried out in Italy primarily through Enel Distribuzione (sale of electricity on the regulated market and transport of electricity on our distribution network), Deval (distribution and sales of electricity in the Valle d’Aosta area), Enel Energia (sale of electricity on the free market), Enel Sole (public lighting services) and Enel.si (electricity systems-related

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services). Outside of Italy this division primarily included Electra de Enel Viesgo Distribuciòn SL and Enel Viesgo Energia SL in Spain, Enel Electrica Dobrogea and Enel Electrica Banat in Romania. Natural gas operations of this division were carried out primarily through Enel Rete Gas, which distributed natural gas in Italy, and Enel Gas, which sold natural gas to end users in Italy. We merged Enel Distribuzione Gas, GE.AD and Sicilmetano, Ottogas Rete and Italgestioni into Enel Rete Gas, and Sicilmetano Energy, Ottogas Vendita and Italgestioni Gas in Enel Gas. The operations carried out by this division have been allocated to the new Market Division, Infrastructure and Networks Division and International Division effective as of January 1, 2006.
      Corporate. Enel, as the parent company, defines the strategic objectives for the Enel Group and coordinates the activities of these divisions. In addition, Enel manages finance operations and insurance risk coverage for all Group companies and provides assistance and guidelines on organizational, industrial relations, accounting, administrative, tax and legal issues. We consider Enel as a separate reportable segment because it holds long-term contracts to purchase imported electricity. Until March 31, 2004, Enel sold the imported electricity it purchases to Enel Distribuzione at prices established by the Energy Authority. Since that date, Enel has been required to sell this electricity to the Single Buyer.
      Services and Other Activities. This segment included non-core business operations, including Enelpower, which provided power-related engineering and construction (or EPC) services, and Enel Servizi (previously Enel Ape), which provides information technology services and administration services mainly to Group companies. Effective January 1, 2006, our EPC activities for other Group companies that were previously carried out by Enelpower have been transferred to our Generation and Energy Management Division.
      Discontinued Operations. Following our deconsolidation of Terna and Wind, we have treated as discontinued operations the Transmission segment and the Telecommunications segment. For a description of the transactions that resulted in our exiting the transmission business and the telecommunications business, please see “Item 4. Information on the Company — Business — Overview — Discontinued Operations.” Accordingly, we treated our transmission operations and telecommunications operations as discontinued operations in our consolidated financial statements for 2005.
Outlook
      We expect that the ongoing liberalization of the Italian electricity sector will continue to materially affect our financial condition and results of operations over the next several years.
      In our generation business, the further evolution of the electricity market following the start of operations of the Italian power exchange in 2004 will have a significant impact on our business in Italy. For instance, in May 2005, the Energy Authority proposed certain possible measures to further promote competition in the wholesale electricity market over the next few years, including the possible sale or lease by us of additional generating capacity to third parties. However, the implementation of such measures has been blocked by an administrative tribunal. Please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation — The Italian Power Exchange” and “Item 3. Key Information — Risks Factors — Risks Relating to our Energy Business — Regulatory changes promoting market liberalization have significantly increased competition in our energy businesses”. We cannot say whether other measures will be enacted to foster competition, but they could have a significant effect on our generation business. We are also exposed to increased competition resulting from the increase in the number of bilateral contracts concluded between our competitors and final customers, the construction of new generation facilities by our competitors and the development of new interconnection lines that would increase the volume of electricity that might be imported in Italy. In this context, we intend to reduce generation costs through the conversion of certain generation plants to run on less expensive fuels, and the alignment of our other operating costs with international best practice through an integrated approach to quality and standards. We also plan to continue to increase our presence in the market for electricity generated from renewable resources.
      In our electricity distribution and sales business, we expect that our results in Italy will continue to be affected by the tariff regime in place for the 2004-2007 period, which includes a price-cap mechanism imposing an annual decrease of 3.5% in the value of operating costs and depreciation, excluding capital costs, for

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distribution services that can be recovered through tariffs. We also expect that our sales of electricity in the regulated market will decrease due to the ongoing liberalization of the market, including the fact that all customers will become eligible to purchase electricity on the free market as of July 1, 2007. However, we expect that the impact of any such decrease on our revenues will be offset to some extent by increased fees paid by third parties for transport of electricity on our network, as well as increased sales in the free market. We intend to face these changes in the market by continuing our program to reduce operating costs, optimizing our investment expenditures, completing our Telemanagement project, and strengthening our market presence (including through the offer of new tariff plans and the roll-out of a new billing system).
      In our gas business, we intend to continue to pursue our growth strategy by selectively acquiring additional natural gas distribution and sales companies and through targeted marketing, with the aim of achieving a market share in the distribution and sale of natural gas in Italy up to 14% by 2010.
      We also intend to pursue our strategy of expanding our operations outside Italy, particularly in countries where we are already present or where market liberalization and privatization efforts are in progress. In this context, in April 2006, we purchased a 66% interest in SE, the principal electric power generation company in Slovakia, with total gross installed generation capacity of about 7,000 MW. In addition, we have entered into a non-binding memorandum of understanding with EDF for an industrial partnership permitting us to invest in the French electricity market, including in the field of nuclear power generation. In Spain, Enel Viesgo Generacion has launched an investment program totaling more than 1,300 million to convert certain coal plants to combined cycle technology. We are also considering opportunities in the Russian market. Please see “Item 4. Information on the Company — Business — The Enel Group — Generation and Energy Management — International Generation.”
      You should read the sections “Strategy” and “The Enel Group” in “Item 4. Information on the Company — Business,” “Item 4. Information on the Company — Regulatory Matters” and “Item 3. Key Information — Risk Factors” for a more detailed discussion of our strategy and other matters affecting our business.
Sale of Wind
      The treatment of the goodwill related to our telecommunications operations (which we discontinued as a result of our disposal of Wind) had an impact on our results from discontinued operations in 2004.
      In 2001 we acquired Infostrada, a provider of fixed line telecommunication services, that we subsequently merged into Wind. In 2003, we acquired the stake in Wind held by France Télécom, and became Wind’s sole shareholder. Under IFRS, the goodwill arising from these acquisitions is to be subject to annual impairment tests, comparing the carrying amount to the related market value. The IFRS results for the year 2004 presented in our consolidated financial statements included in this annual report reflected an impairment of 1,671 million in the carrying value of this goodwill, reflecting the value attributed to Wind that was implied by the binding offer we received from Weather Investments in April 2005. In May 2005, we entered into an agreement pursuant to which we have sold Wind to Weather Investments in a series of transactions. Please see “Item 4. Information on the Company — Business — Overview — Discontinued Operations” for more details on our disposal of Wind.

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Analysis of Operating Results
      The following table shows certain of our IFRS financial data for the years ended December 31, 2004 and 2005, expressed in each case as a percentage of our operating revenues:
                   
    Year Ended
    December 31,
     
    2004   2005
         
Operating revenues
    100.0 %     100.0 %
Operating expenses
               
 
Personnel
    (10.4 )     (8.1 )
 
Fuel for thermal generation
    (11.6 )     (11.5 )
 
Purchased power
    (33.5 )     (42.0 )
 
Depreciation and amortization
    (7.1 )     (6.5 )
 
Other operating expenses
    (18.5 )     (15.6 )
             
Total operating expenses
    (81.1 )     (83.7 )
             
Operating income
    18.9       16.3  
Financial income (expense) and income (expense) from investments
    (2.7 )     (2.1 )
Income (expense) from investments accounted for using the equity method
    (0.1 )     (0.1 )
Income before taxes
    16.1       14.1  
             
Income taxes
    (6.8 )     (5.7 )
             
Income from continuing operations
    9.3       8.4  
Income from discontinued operations
    (0.5 )     3.7  
Income (before minority interests)
    8.8       12.1  
Net Income
    8.5 %     11.4 %
      Following the disposal of our controlling stakes in Wind and Terna and their subsidiaries, which took place respectively on August 11, 2005 and September 15, 2005, these entities were deconsolidated as from these dates and the financial results achieved up to the disposal date are reported under discontinued operations.
      The following table shows certain financial data from discontinued operations for the years ended December 31, 2004 and 2005, expressed in each case as a percentage of our continuing operating revenues:
                 
    Year Ended
    December 31,
     
    2004   2005
         
Operating revenues
    17.5 %     9.6 %
Operating expenses
    (21.1 )     (7.9 )
Operating income (loss)
    (3.6 )     1.7  
Net financial expense
    (1.5 )     (0.7 )
Income taxes
    2.0       0.6  
Net income (loss) before capital gains
    (3.1 )     0.4  
Gains on disposal of assets
    2.6       3.3  
Income from discontinued operations
    (0.5 )%     3.7 %
      The capital gains for 2005 essentially related to the disposal of a 43.85% interest in Terna, while the capital gains for 2004 related to the disposal of a 50% interest in Terna. All the gains realized upon disposal of interests in Terna in 2004 and in 2005 have therefore been reported under discontinued operations in order to allow a consistent comparison.

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2005 Compared with 2004
      In accordance with IFRS, the financial information presented for the years ended December 31, 2005 and 2004 reflects only our continuing operations, except where specific reference is made to discontinued operations. You should read note 5 to our consolidated financial statements for additional information on discontinued operations.
Operating Revenues
      The following table provides a breakdown of the operating revenues from our continuing operations for the years ended December 31, 2005 and 2004.
                   
    Year Ended
    December 31,
     
    2004   2005
         
    (In millions of
    euro)
Electricity sales:
               
 
Tariff revenues from sales on the regulated market and transport of electricity on our distribution network
    15,305       15,347  
 
Sales to regulatory entities, sales on the free market and sales on foreign markets(1)
    9,776       13,548  
 
Equalization Fund contributions
    17       113  
             
Total revenues from electricity sales
    25,098       29,008  
             
Gas sales to end users
    1,374       1,556  
Fees for customer connections, inspections and repositioning services
    657       656  
Other revenues(2)
    3,882       2,839  
             
 
Total operating revenues
    31,011       34,059  
 
(1)  “Sales to regulatory entities” includes sales to Terna, the Single Buyer (since April 1, 2004) and the Market Operator. While sales to third-party resellers of electricity on the free market are included in “Sales on the free market”, this line item does not include revenues from sales to resellers purchasing electricity for distribution on the regulated market. Since April 1, 2004, these resellers have been required to purchase electricity directly from the Single Buyer. Revenues received prior to that date from resellers purchasing electricity for distribution on the regulated market were recorded in the line item “Tariff revenues from sales on the regulated market and transport of electricity on our distribution network.”
 
(2)  “Other revenues” mainly includes our revenues from sales of fuel (including natural gas) to third parties, engineering and contracting activities, and non-recurring items such as reversals of provisions, bonus payments and reimbursements.
      Our consolidated operating revenues from continued operations for 2005 increased by 3,048 million, or 9.8%, compared to 2004. As explained in more detail below, this improvement was almost entirely due to the 3,910 million, or 15.6%, increase in our consolidated revenues from sales of electricity. In addition, revenues from gas sold to end users increased by 182 million, or 13.3%. The impact of these factors on our overall operating revenues was partially offset by a decrease of 1,043 million, or 26.9%, in revenues from other activities.
Electricity sales
      In 2005, total revenues from electricity sales increased by 3,910 million, or 15.6%, as compared to 2004. The increase was primarily due to higher sales to regulatory entities, sales on the free market and sales on foreign markets, which increased by 3,772 million, from 9,776 million to 13,548 million. The increase also reflected an increase of 96 million, from 17 million to 113 million, in equalization fund contributions and a slight increase of 42 million, from 15,305 million to 15,347 million, in tariffs from sales on the regulated market and transport of electricity on our distribution network.

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      The increase in sales to regulatory entities primarily reflected the fact that, following the start of operations of the Italian power exchange and of the Single Buyer as of April 1, 2004, sales of electricity on the regulated market were made by our Generation and Energy Management segment to the Single Buyer, whereas, during the first quarter of 2004, such sales were made directly to our Sales, Infrastructure and Networks segment and were, therefore, eliminated from our consolidated results. The increase in sales to regulatory entities, sales on the free market and sales on foreign markets also reflected an increase of 1,427 million, or 114.5%, in revenues from international sales of electricity (reflecting a 669 million increase in revenues from international trading of electricity, a 310 million increase in sales on the foreign markets by our Generation and Energy Management segment, a 298 million increase in revenues attributable to the first time consolidation of Enel Electrica Banat and Enel Electrica Dobrogea and a 150 million increase in sales on the Spanish market by our Sales, Infrastructure and Networks segment). The increase in revenues from sales to regulatory entities, sales on the free market and sales on foreign markets also reflected an increase of 334 million, or 30.2%, in revenues from dispatching services and an increase of 59 million, or 3.4%, in revenues from sales on the free market in Italy (which mainly reflected increases in volumes sold to end users with annual consumption in excess of 100 GWh per year).
      Revenues from sales on the regulated market and transport of electricity on our distribution network were substantially in line with 2004, having increased by 42 million, or 0.3%.
      Reimbursements received from the Equalization Fund increased by 96 million, primarily as a result of the fact that in 2005 we received 100 million related to the reimbursement of certain charges incurred in 2002 and 2003 for the purchase of green certificates. Please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation — System Charges and Other Charges” for a description of the Equalization Fund.
Gas sales to end users
      Our revenues from sales of natural gas to end users (which exclude sales of gas to distributors and to other third parties by Enel Trade, which are recorded in “Other revenues”) increased by 182 million, or 13.3%. This increase was largely due to increased tariffs reflecting increased market prices for natural gas.
Fees for customer connections, inspections and repositioning services
      Revenues from fees for customer connections, inspections and repositioning services decreased slightly, by 1 million, or 0.2%, from 2004.
Other revenues
      Other revenues decreased by 1,043 million, or 26.9%, primarily due to the fact that in 2004 we had recorded revenues of 1,068 million on the basis of the European Commission’s approval of the decree issued in August 2004 by the MEF and the Ministry of Productive Activities setting the overall amount of stranded costs we were entitled to recover (please see “— Comparability of Information — Regulatory and Other Developments” and “Item 4 Information on the Company — Regulatory Matters — Electricity Regulation — Stranded Costs”). The decrease in other revenues also reflected the combined effect of a decrease of 448 million, or 50.1%, in revenues from sales of fuel to third parties, and a 319 million, or 52.4%, decrease in revenues from sales of engineering and contracting services to third parties. These factors were only partially offset by 338 million that we recorded in 2005 related to services provided to the GRTN for the period 2002-2004, a 288 million increase in net gains from commodity risk management primarily resulting from contracts for differences with the Single Buyer and a 118 million increase in capital gains from disposal of assets.
      The following table shows operating revenues for each of our business segments for the periods presented. As a result of our disposal of Terna and Wind, we deconsolidated Terna and Wind as of September 15, 2005 and August 11, 2005, respectively (please see “— Outlook — Sale of Wind”, and “Item 4. Information on the Company — Business — Overview — Discontinued Operations”). Accordingly, we have eliminated the reporta-

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ble segments corresponding to these two entities, and financial information therewith for the period prior to their respective deconsolidation is presented as information on discontinued operations.
                   
    Year Ended
    December 31,
     
    2004   2005
         
    (In millions of
    euro)
Generation and Energy Management
  13,028     14,215  
Sales, Infrastructure and Networks
    19,254       20,422  
Corporate
    1,649       1,103  
Services and Other Activities
    1,794       1,660  
Eliminations
    (4,714 )     (3,341 )
             
 
Total operating revenues from continuing operations
  31,011     34,059  
Generation and Energy Management
      In 2005, the operating revenues of our Generation and Energy Management segment, prior to intersegment eliminations, increased by 1,187 million, or 9.1%, as compared to 2004. The total revenues of the segment of 14,215 million comprised revenues from its Italian operations of 13,376 million, revenues from its international operations of 914 million and eliminations for intrasegment sales of 75 million, which mainly related to sales of fuel by Enel Trade to our international generation companies. The overall increase in the segment’s revenues was primarily attributable to a 930 million, or 7.5%, increase, in revenues from the segment’s operations in Italy prior to intrasegment eliminations, and a 292 million, or 46.9%, increase in revenues from international operations prior to intrasegment eliminations.
      The increase in revenues from Italian activities mainly reflected a 624 million, or 7.5%, increase in revenues earned by Enel Produzione from electricity sales (including revenues from dispatching services), a 587 million, or 41.8%, increase in revenues from electricity sales by Enel Trade, primarily in connection with trading activities in the international market, the recognition in 2005 of 338 million related to services provided to the GRTN and Terna for the period 2002-2004, a 311 million increase in net gains from commodity risk management, primarily resulting from contracts for differences with the Single Buyer, a 170 million, or 17.9%, increase in revenues from sales of natural gas to our Sales, Infrastructure and Networks Division and the fact that in 2005 we recorded 100 million relating to the reimbursement of certain charges incurred in 2002 and 2003 for the purchase of green certificates. These positive factors were offset in part by the fact that revenues from Italian activities of this segment in 2004 included revenues of 513 million related to stranded costs on our generation plants for the period 2000-2003, and by a decline of 448 million, or 50.1%, in revenues from sales of fuel to third parties, largely as a result of Enel Trade’s new focus on the supply of gas to Group companies and by the effects of Resolution No. 20/04 of the Energy Authority, pursuant to which we are required to reimburse 191 million as a reduction of the prices charged in the sale to distributors in March 2004.
      The 292 million increase in revenues from international operations prior to intrasegment eliminations reflected a 259 million increase in revenues earned by Enel Viesgo and a 40 million increase in revenues earned by EUFR (in each case, largely resulting from an increase in generation volumes and average sales prices).
Sales, Infrastructure and Networks
      The operating revenues of our Sales, Infrastructure and Networks segment, prior to intersegment eliminations, increased by 1,168 million, or 6.1%, as compared to 2004. The total revenues of the segment of 20,422 million comprised revenues from Italian electricity distribution and sales of 17,905 million, revenues from gas distribution and sales of 1,602 million, revenues from the segment’s international electricity operations of 913 million and eliminations for intrasegment sales of 2 million. The overall increase in the segment’s revenues was primarily attributable to a 431 million, or 2.5%, increase in revenues, prior to intrasegment eliminations, from electricity distribution and sales in Italy, a 522 million increase in revenues, prior to intrasegment eliminations from sales of electricity by the segment’s international operations, which more than

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doubled, and a 206 million, or 14.8%, increase in revenues, prior to intrasegment eliminations, from gas distribution and sales.
      The increase in Italian electricity revenues reflected a 553 million increase in revenues earned by Enel Distribuzione and Deval from electricity sales to end users, primarily due to the increase in the component of electricity tariffs linked to the market price for oil (please see “— Comparability of Information — Regulatory and Other Developments”). In addition, the increase in the Italian electricity revenues reflected a 168 million increase in revenues earned by Enel Energia as a result of both a higher volume of electricity sold and higher average prices, and a 89 million increase in capital gains on disposals, primarily due to the sale of our distribution network in the Province of Trento. These factors were partially offset by a 252 million decline in sales to resellers purchasing electricity for distribution on the regulated market as a result of the fact that, following the start of operations of the Single Buyer in April 2004, we no longer sell electricity to resellers for distribution on the regulated market (which sales accounted for 252 million in revenues in 2004). The overall increase was also reduced by a 135 million decrease in the revenues recorded in connection with the bonus scheme for continuity and quality of service performance, primarily attributable to the fact that in 2004 we had recorded revenues in connection with bonuses relating to services provided in both 2004 and 2003 (please see “Item 4. Information on the Company — Regulatory Matters — Electricity Regulation — The Tariff Structure” for a more detailed discussion of this mechanism) and a 41 million decrease in revenues from franchising activities.
      The 522 million increase in revenues from sales of electricity by our international operations was attributable to the first time consolidation of Enel Electrica Banat and Enel Electrica Dobrogea (which recorded 332 million in revenues), as well as to a 190 million increase in revenues earned by our Spanish subsidiaries.
      The 206 million increase in revenues from gas distribution and sales was primarily attributable to a 182 million, or 13.2%, increase in revenues from gas sales to end users reflecting increased sales prices.
Corporate
      The operating revenues of our Corporate segment, prior to intersegment eliminations, decreased by 546 million, or 33.1%, as compared to 2004. The decrease was largely attributable to the fact that in 2004 we had recorded 555 million in revenues corresponding to the amount of reimbursement we are entitled to receive in relation to costs we had incurred in the period 2000-2003 related to the Nigerian LNG contract following the approval of the decree about stranded costs mentioned above.
Services and Other Activities
      The operating revenues of our Services and Other Activities segment, prior to intersegment eliminations, decreased by 134 million, or 7.5%, as compared to 2004. Of the segment’s total of 1,660 million in operating revenues, prior to intersegment eliminations, 804 million were attributable to engineering and contracting, 86 million to real estate and related services and 820 million to other activities. Approximately 77.5% of these revenues were generated by transactions with other Group companies in 2005, as compared to 58.6% in 2004. Eliminations for intrasegment operations in 2005 were 50 million.
      The decrease in revenues from this segment’s operations was primarily due to a 169 million decrease in revenues, prior to intrasegment eliminations, from our engineering and contracting activities reflecting their shift in focus towards work on projects for other Group companies rather than third parties. Other negative factors included a decline of 36 million in revenues, prior to intrasegment eliminations, from real estate and related activities, reflecting the sale of NewReal on July 14, 2004. The overall decline was partially offset by a 60 million increase in revenues, prior to intrasegment eliminations, from our other activities, including, mainly, personnel administration, professional training services, factoring and water operations.
Eliminations
      Eliminations in operating revenues generally relate to intersegment sales (primarily of electricity and fuel) and services (primarily engineering and contracting). In 2005, eliminations decreased by 1,373 million, or

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29.1%, as compared to 2004, mainly reflecting the fact that sales of electricity on the regulated market were made by our Generation and Energy Management segment to the Single Buyer during all of 2005, whereas, during the first quarter of 2004, such sales were made directly to our Sales, Infrastructure and Networks segment.
Operating Expenses
      The following table shows a breakdown of our operating expenses for each of the periods presented:
                   
    Year Ended
    December 31,
     
    2004   2005
         
    (In millions of
    euro)
Operating expenses:
               
 
Personnel
  3,224     2,762  
 
Fuel for thermal generation
    3,598       3,910  
 
Fuel for trading and gas for resale to end users
    1,795       1,604  
 
Purchased power
    10,380       14,321  
Other operating expenses:
               
 
Services and rentals
    3,106       3,057  
 
Materials and supplies
    1,027       798  
 
Other
    783       911  
 
Capitalized expenses
    (973 )     (1,049 )
             
Total
  22,940     26,314  
      As described in more detail below, our consolidated operating expenses for 2005 increased by 3,374 million, or 14.7%, as compared to 2004. Expressed as a percentage of operating revenues from our continuing operations, operating expenses were 77.3% in 2005, as compared to 74.0% in 2004. The increase in the absolute figure was primarily due to a 3,941 million, or 38.0%, increase in our expenses for purchased power, reflecting the fact that the 2005 results reflect a full year’s operation of the Italian power exchange, which was introduced on April 1, 2004. The overall increase also reflected a 312 million, or 8.7%, increase in costs for fuel for thermal generation, a 128 million, or 16.3%, increase in other costs and a 76 million, or 7.8%, increase in capitalized expenses. These increases were offset in part by declines of 462 million, or 14.3%, in costs for personnel, 229 million, or 22.3%, in costs for materials and supplies, 191 million, or 10.6%, in costs for fuel for trading and gas for resale to end users, and 49 million, or 1.6%, in costs for services and rentals.
Personnel
      Personnel costs decreased by 462 million, or 14.3%, as compared to 2004, primarily due to a 361 million decrease relating to early retirement incentives, as well as to a 3.8%, or 1,964 person, decline in the average number of employees during the period.
Fuel for thermal generation
      Costs for fuel for thermal generation increased by 312 million, or 8.7%, as compared to 2004, primarily reflecting a sharp increase in the average price of fuel, which was only partially offset by the decrease in the volume of electricity we produced from thermal sources in Italy and our use of a less expensive mix of fuels.
Fuel for trading and gas for resale to end users
      Costs for the purchase of fuel for trading and natural gas for sale to end users decreased by 191 million, or 10.6%. This decrease reflected the effect of a 416 million decline in costs for the purchase of fuel for trading, consistent with lower trading volumes, which was partially offset by a 225 million increase in costs for natural gas for resale to end users, reflecting the expansion of our gas operations.

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Purchased power
      Purchased power costs increased by 3,941 million, or 38.0%, as the quantity of power purchased increased by 13.9%. The increase in purchased power costs primarily reflected the fact that the 2005 operating expenses reflect a full year’s operation of the Italian power exchange, which was introduced on April 1, 2004, following which our distribution companies purchase power for sales on the regulated market exclusively from the Single Buyer, rather than directly from our generation companies, and our generation companies purchase from third parties the electricity they use to power pumping at our hydroelectric plants.
Services and rentals
      Services and rentals costs decreased by 49 million, or 1.6%, primarily due to a 140 million decrease in costs relating to our engineering and construction activities. The impact of this decrease was partially offset by a 36 million increase in leasing and rental costs (mainly reflecting our July 2004 disposal of NewReal, from which we continue to lease certain real estate assets), a 23 million increase in services reflecting the first time consolidation of Enel Electrica Banat and Enel Electrica Dobrogea, a 14 million increase in fees for the use of water in power generation and a 11 million increase in costs for commercial services, primarily in our Sales, Infrastructure and Networks segment.
Materials and supplies
      Materials and supplies costs decreased by 229 million, or 22.3%, as compared to 2004, primarily due to a 149 million decline reflecting lower activities for third parties by our engineering and contracting unit.
Other costs
      Other costs increased by 128 million, or 16.3%, as compared to 2004, reflecting a cost of 228 million that we recorded in 2005 related to charges resulting from the fact that our CO2 emissions in 2005 exceeded the emissions quotas allocated to us pursuant to the Emission Trading Directive and Italian and Spanish implementing legislation. Please see “Item 4. Information on the Company — Regulatory Matters — Environmental Matters — CO2 Emissions” for a discussion of these limits on CO2 emissions.
Capitalized expenses
      Capitalized expenses increased by 76 million, or 7.8%, as compared to 2004, primarily reflecting higher levels of construction activity in our Generation and Energy Management segment.
      The following table shows a breakdown of our operating expenses by business segment for each of the periods presented.
                 
    Year Ended
    December 31,
     
    2004   2005
         
    (In millions of
    euro)
Generation and Energy Management
  9,248       10,511  
Sales, Infrastructure and Networks
    15,724       16,685  
Corporate
    997       1,036  
Services and Other Activities
    1,580       1,411  
Eliminations
    (4,609 )     (3,329 )
             
Total
  22,940     26,314  
Generation and Energy Management
      In 2005, the operating expenses of our Generation and Energy Management segment (which primarily consist of costs for purchased power, fuel costs, fees paid to the GRTN and Terna, and personnel and maintenance costs for our power plants), increased by 1,263 million, or 13.7%, prior to intersegment

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eliminations, as compared to 2004. The segment’s total operating expenses of 10,511 million comprised expenses for Italian generation of 9,961 million, expenses for international generation of 624 million and eliminations for intrasegment operations of 74 million. The overall increase was primarily attributable to a 1,080 million, or 12.2%, increase, prior to intrasegment eliminations, in expenses for the segment’s Italian operations and a 217 million, or 53.3%, increase, prior to intrasegment eliminations, in expenses for its international operations.
      The increase at the segment’s Italian operations was mainly attributable to a 771 million, or 42.3%, increase in costs for purchased power, a 277 million, or 64.5%, increase in other costs (primarily reflecting charges for CO2 emissions in excess of the emissions quotas allocated to us in Italy) and a 124 million, or 2.4%, increase in expenses for fuel (primarily reflecting higher average prices). These factors were partially offset by a 154 million, or 22.0%, decrease in personnel costs.
      The increase in expenses for the segment’s international generation operations reflected the increased scope of their activities and primarily consisted of a 118 million increase in expenses for purchased power, which more than tripled, a 64 million, or 33.0%, increase in expenses for fuel for thermal generation and 46 million cost reflecting charges for CO2 emissions in excess of the emissions quotas allocated to us in Spain.
Sales, Infrastructure and Networks
      In 2005, the operating expenses of our Sales, Infrastructure and Networks segment (which primarily consist of purchases of power and natural gas and costs associated with running our distribution network), prior to intersegment eliminations, increased by 961 million, or 6.1%, as compared to 2004. The segment’s total operating expenses of 16,685 million comprised expenses of Italian electricity activities of 14,602 million, expenses of gas distribution and sales of 1,360 million, expenses of the segment’s international electricity operations of 721 million and eliminations for intrasegment operations of 2 million. The overall increase in the segment’s expenses was primarily attributable to a 407 million increase in expenses, prior to intrasegment eliminations, for the segment’s international operations, which more than doubled, a 356 million, or 2.5%, increase in expenses for electricity activities in Italy and a 189 million, or 16.1%, increase in expenses, prior to intrasegment eliminations, for gas activities.
      The increase in expenses for electricity activities in Italy primarily reflected a 826 million, or 8.3%, increase in costs for purchased power (largely due to higher average purchase prices and higher volumes purchased for the regulated market). This factor was partially offset by a 353 million decrease in costs for personnel, a 90 million decrease in costs for materials and supplies (reflecting a decreased level of construction on our Italian electricity distribution network) and a 34 million decrease in costs for services and rentals.
      The increase for expenses at the segment’s international operations was primarily attributable to a 325 million increase in costs for purchased power (reflecting the first time consolidation of Enel Electrica Banat and Enel Electrica Dobrogea — which recorded an aggregate of 194 million in such expenses — and increased purchase volumes at the segment’s Spanish operations) and a 23 million increase in services reflecting the first time consolidation of Enel Electrica Banat and Enel Electrica Dobrogea.
      The increase in expenses for gas activities was primarily attributable to a 169 million increase in costs for gas purchased for resale to end users (reflecting higher prices), and a 24 million increase in costs for services and rentals.
Corporate
      In 2005, the operating expenses for our Corporate segment, prior to intersegment eliminations, increased by 39 million, or 3.9%, as compared to 2004, primarily due to a 29 million increase in costs for services and rentals and a 27 million increase in costs for the purchase of electricity (reflecting higher prices). These factors were offset in part by a 18 million decrease in costs for personnel.

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Services and Other Activities
      In 2005, the operating expenses of our Services and Other Activities segment, prior to intersegment eliminations, decreased by 169 million, or 10.7%, as compared to 2004, primarily reflecting a 171 million decrease in costs at our engineering and contracting operations, reflecting their refocused activities. The overall decline in this segment’s expenses also reflected a 16 million decrease in costs at our real estate activities, primarily reflecting the sale of NewReal. Operating expenses for other activities (such as personnel administration, professional training services, factoring and water activities) increased by 6 million. Eliminations for intrasegment operations in 2005 were 50 million (61 million in 2004).
Eliminations
      Eliminations for operating expenses principally consist of the elimination of intersegment electricity and fuel purchases and costs for the provision of intersegment services. In 2005, the decrease in eliminations of 1,280 million, or 27.8%, as compared to 2004, mainly reflected the fact that since the introduction of the Single Buyer in April 2004, our Sales, Infrastructure and Networks segment purchases most of the electricity it sells directly from the Single Buyer, rather than from our Generation and Energy Management segment.
Depreciation, Amortization and Impairment
      The following table shows depreciation, amortization and impairment expenses for each of our business segments for each of the periods presented:
                 
    Year Ended
    December 31,
     
    2004   2005
         
    (In millions of
    euro)
Generation and Energy Management
  1,249       1,139  
Sales, Infrastructure and Networks
    837       959  
Corporate
    5       14  
Services and Other Activities
    108       95  
Eliminations
    2       0  
             
Total
  2,201       2,207  
      Depreciation, amortization and impairment expenses in 2005 increased by 6 million, or 0.3%, as compared to 2004. The increase primarily reflected a 122 million increase in such expenses at our Sales, Infrastructure and Networks segment that was primarily due to a 93 million increase related to the Italian electricity operations of the segment, a 18 million increase related to the international operations of the segment (mainly reflecting the first time consolidation of Enel Electrica Banat and Enel Electrica Dobrogea) and a 11 million increase related to our gas distribution and sales activity. These factors were partially offset by a 110 million decrease in depreciation, amortization and impairment expenses at our Generation and Energy Management segment (primarily arising from the upward revision of our estimates of the useful lives of certain assets, as described in “The Electricity Market Regulatory Framework — Comparability of Information — Regulatory and Other Developments” above (see also “The Electricity Market Regulatory Framework — Critical Accounting Policies”)).

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Operating Income
      The following table shows operating income for each of our business segments for the periods presented:
                 
    Year Ended
    December 31,
     
    2004   2005
         
    (In millions of
    euro)
Generation and Energy Management
  2,531     2,565  
Sales, Infrastructure and Networks
    2,693       2,778  
Corporate
    647       53  
Services and Other Activities
    106       154  
Eliminations
    (107 )     (12 )
             
Total
  5,870     5,538  
      Operating income decreased by 332 million, or 5.7%, as compared to 2004, reflecting a 594 million decrease in the operating income earned by our Corporate segment, which was only partially offset by increases in the operating income earned by our Sales, Infrastructure and Networks, Generation and Energy Management and Services and Other Activities segments.
Generation and Energy Management
      The operating income of our Generation and Energy Management segment, prior to intersegment eliminations, increased by 34 million, or 1.3%, as compared to 2004. The segment’s operating income comprised operating income from Italian generation operations of 2,403 million and operating income from international operations of 162 million. The overall increase in the segment’s operating income reflected a 66 million, or 68.8%, increase in operating income from its international generation operations that was partially offset by a 32 million, or 1.3%, decrease in operating income from its Italian generation operations.
      The decrease in operating income from Italian generation activities primarily reflected the fact that revenues from Italian activities of this segment in 2004 included 513 million related to stranded costs on our generation plants for the period 2000-2003, the effect of the 191 million we are required to reimburse pursuant to the Resolution No. 20/04 of the Energy Authority (as explained above) and a 182 million charge in 2005 for CO2 emissions in excess of the emissions quotas allocated to us. This decrease was partially offset by the effect of the 338 million revenues related to services provided in the period 2002-2004 (as explained above), a 311 million increase in net income from commodity risk management, a 115 million decrease in depreciation, amortization and impairment primarily due to the upward revision of our estimates of the useful lives of certain power plants and 100 million revenues relating to the reimbursement of certain charges incurred in 2002 and 2003.
      The increase in operating income generated by the international generation operations of the segment was primarily attributable to a 31 million increase in operating income at Enel Viesgo and a 25 million increase in operating income at EUFR.
Sales, Infrastructure and Networks
      The operating income of our Sales, Infrastructure and Networks segment, prior to intersegment eliminations, increased by 85 million, or 3.2%, as compared to 2004. Total operating income of the segment comprised 2,487 million of operating income from Italian electricity distribution and sales, 143 million of operating income from international operations, and 148 million of operating income from gas distribution and sales.
      The overall increase in the segment’s operating income was primarily attributable to a 97 million increase in operating income from international electricity distribution and sales operations (which more than doubled), mainly due to the first time consolidation of Enel Electrica Banat and Enel Electrica Dobrogea (which recorded aggregate operating income of 70 million). The overall increase also reflected a 6 million, or 4.2%, increase in

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the operating income from gas distribution and sales. These factors were offset in part by a 18 million decrease in operating income from Italian electricity distribution and sales.
Corporate
      The operating income of our Corporate segment, prior to intersegment eliminations, decreased by 594 million, or 91.8%, as compared to 2004, mainly due to the fact that in 2004 we had recorded 555 million in revenues corresponding to the amount of reimbursement we were entitled to receive in relation to costs we had incurred in the period 2000-2003 related to the Nigerian LNG contract following the approval of decree about stranded costs mentioned above.
Services and Other Activities
      The operating income of our Services and Other Activities segment, prior to intersegment eliminations, increased by 48 million, or 45.3%, as compared to 2004. The overall increase reflected a general increase in income from the segment’s businesses other than real estate which recorded a 12 million decline, mainly reflecting the deconsolidation of NewReal, as of July 14, 2004.
Eliminations
      Intersegment eliminations for operating income mainly related to income from our engineering and contracting activities arising from transactions with companies in our Generation and Energy Management segment.
Financial Income/ Expense and Income/ Expenses from Investments
      Net financial expenses and net expenses from investments (which relate to our investments not accounted for using the equity method) decreased by 113 million, or 13.7% (from 827 million in 2004 to 714 million in 2005). The decrease was primarily attributable to a 97 million decrease in our net financial expenses, reflecting a decrease in the average amount of our net financial debt over the period. Please see “— Liquidity and Capital Resources — Capital Resources” for additional information about our debt in 2005.
Income/ Expense from Investments Accounted For Using The Equity Method
      Expenses from investments increased by 5 million, or 20.0% (from 25 million in 2004 to 30 million in 2005). The increase primarily reflected the impact of the equity method evaluation of Wind and of the fair value valuation of our put option in connection with Wind’s shares, which accounted for a net expense of 37 million. You should read note 9 to our consolidated financial statements for additional information on income/expense from investments accounted for using the equity method.
Income Taxes
      The following table shows a breakdown of our income tax expenses for the periods indicated.
                   
    Year Ended
    December 31,
     
    2004   2005
         
    (In millions of
    euro)
Current taxes
    1,328       1,398  
Difference on estimated income tax from prior years
    (14 )     14  
Deferred tax assets
    459       277  
Deferred tax liabilities
    343       245  
             
 
Total
    2,116       1,934  
      Estimated income tax expenses from our continuing operations decreased by 182 million, or 8.6%, compared to 2004, from 2,116 million to 1,934 million. The decrease was mainly attributable to a 182 million

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decrease in deferred tax assets primarily relating to accruals to provisions for risk and charges and impairment losses with deferred deductibility, a 98 million decrease in deferred tax liabilities mainly due to the reduction of depreciation charged for tax purposes including accelerated depreciation and impairment of investments and a 70 million increase in current taxes due to higher income before taxes. The decrease in income tax from continuing operations was partially offset by a 21 million increase in foreign income taxes, which amounted to 43 million in 2005, as compared to 22 million in 2004.
      You should read note 10 to consolidated financial statements for more details on our income taxes and effective tax rate.
Income/loss from discontinued operations
      We recorded income from discontinued operations of 1,272 million in 2005, as compared to a loss of 155 million in 2004. The increase primarily reflected the fact that in 2004 we recorded a loss primarily due a 1,671 million impairment on our stake in Wind. Please see “Item 4 Information on the Company — Business — Overview — Discontinued Operations” and “— Business Segments — Outlook — Sale of Wind” for additional information on this impairment. The impact of this factor in 2004 was only partially offset by the capital gain of 812 million we recorded on disposal of a 50% stake in Terna. The 2005 increase also reflected a capital gain in 2005 of 1,153 million on disposals (mainly reflecting our disposal of a 43.85% stake in Terna).
Net income
      Net income represents our income from continuing operations after taxes plus income from discontinued operations after taxes minus minority stockholders’ interest. Net income increased by 1,264 million, or 48.0%, from 2,631 million in 2004 to 3,895 million in 2005. This increase was primarily due to a 1,427 million increase in income from discontinued operations, a 113 million decrease in net financial expenses and expenses from investments and a 182 million decrease in our income taxes. The positive effects of these factors on our net income were partially offset by a 332 million decrease in our operating income and a 5 million increase in the expenses in investments accounted for using the equity method. The change in the result attributable to minority interests (from 116 million in 2004 to 237 million in 2005) primarily reflected our sale of Terna.
Inflation
      The tariffs for sales of electricity in effect over the periods covered by the financial statements included in this annual report were not adjusted for inflation. Inflation in Italy was 2.2% in 2004, and 1.9% in 2005. As a result, the real value of the tariffs decreased over time.
U.S. GAAP Reconciliation
      We have prepared our consolidated financial statements in accordance with IFRS, which differ in certain respects from U.S. GAAP. The principal differences between IFRS and U.S. GAAP, as applied to our consolidated financial statements, relate to the following:
  •  Fixed assets and related depreciation;
 
  •  Capitalized interest and related depreciation;
 
  •  Customers’ connection fees;
 
  •  Pension and employee termination accounting;
 
  •  Other post-retirement benefits accounting;
 
  •  Early retirement program;
 
  •  Goodwill, impairment and related amortization;
 
  •  Intangible assets;

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  •  Asset retirement obligations;
 
  •  Gain on sale of real estate businesses;
 
  •  Stock option compensation expense;
 
  •  Accounting for income taxes; and
 
  •  Investment in equity securities.
      You should read note 21 to our consolidated financial statements for a more detailed discussion of the principal differences between IFRS and U.S. GAAP that affect our consolidated financial statements and for a reconciliation of net income and shareholders’ equity between IFRS and U.S. GAAP; and note 22 to our consolidated financial statements for additional U.S. GAAP disclosures.
      Our consolidated net income under U.S. GAAP was approximately 1,031 million in 2004 and 4,698 million in 2005, as compared to consolidated net income under IFRS of 2,631 million in 2004 and 3,895 million in 2005. Our shareholders’ equity under U.S. GAAP was 15,697 million at December 31, 2004 and 17,638 million in at December 31, 2005, as compared with shareholders’ equity under IFRS of 17,953 million at December 31, 2004 and 19,057 million at December 31, 2005.
Critical Accounting Policies under U.S. GAAP
      In addition to the critical accounting policies discussed above under “The Electricity Market Regulatory Framework — Critical Accounting Policies,” management considers that the following critical accounting policies in the reconciliation of net income and shareholders’ equity between IFRS and U.S. GAAP require reliance upon significant judgments, estimates and assumptions.
      Recoverability of goodwill. For U.S. GAAP, we adopted the provisions of Statement of Financial Accounting Standard SFAS No. 142 (FASB 142), “Goodwill and Other Intangible Assets,” as of January 1, 2002, which did not result in any impairment as of that date. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized and that goodwill be tested for impairment at least annually (and between annual tests when certain triggering events occur) using a two-step approach at the reporting unit level. Reporting units may be tested at different times during the year. The first step involves comparing the fair value of the reporting unit to its book value, including goodwill and intangible assets. The determination of fair value of each reporting unit is based on the present value of future cash flows and requires significant judgment. If the fair value of the reporting unit is less than its book value, a second step is required to be performed comparing the implied fair values to the book values of the reporting units’ goodwill. The implied fair value of the goodwill is the difference between the fair value of the reporting unit and the net fair values of the recognized and unrecognized intangible identifiable assets and liabilities of the reporting unit. The fair value of intangible assets with indefinite lives is determined based on expected discounted future cash flows. If the fair value of goodwill and other intangible assets with indefinite lives are less than their book values, the differences are recorded as impairment charges. With regard to our telecommunications reporting unit, the annual impairment test which was performed at June 30, 2002, resulted in us recording impairment charges of 2,336 million under U.S. GAAP related to goodwill during the year ended December 31, 2002. No such impairment resulted from the similar testing performed in 2003. The annual impairment test performed at June 30, 2004 did not result in an impairment. However, due to a change in circumstances that we believed would more likely than not reduce the fair value of the reporting unit below its carrying amount, we performed a new impairment test at December 31, 2004, which resulted in the recording of impairment charges under U.S. GAAP of 3,393 million.
      Accounting for derivatives. In 1998, the Financial Accounting Standards Board (FASB), issued SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS 133 was later amended by SFAS 137 and 138 (collectively referred to as SFAS 133). For U.S. GAAP purposes only, we use the criteria in SFAS 133, as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments. The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. As a result, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. The types of contracts we currently account for as

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derivative instruments are interest rate swaps and locks, foreign currency exchange contracts, call options and swaps. We do not account for electric capacity, gas supply contracts, or purchase orders for numerous supply items as derivatives. If a contract must be accounted for as a derivative instrument, the contract is recorded as either an asset or a liability in the financial statements at the fair value of the contract. Any difference between the recorded book value and the fair value is reported either in earnings or in other comprehensive income depending on certain qualifying criteria. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the market value of the contract. In order to value the contracts that are accounted for as derivative instruments, we use a combination of market quoted prices and mathematical models. Option models require various inputs, including forward prices, volatilities, interest rates and exercise periods. Changes in forward prices or volatilities could significantly change the calculated fair value of the call option contracts. The models we use have been tested against market quotes to ensure consistency between model outputs and market quotes. For derivative instruments to qualify for hedge accounting under SFAS 133, the hedging relationship must be formally documented at inception and be highly effective in achieving offsetting cash flows or offsetting changes in fair value attributable to the risk being hedged. If hedging a forecasted transaction, the forecasted transaction must be probable. If a derivative instrument used as a cash flow hedge is terminated early because it is probable that a forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. If a derivative instrument used as a cash flow hedge is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and recorded when the forecasted transaction affects earnings.
      Recoverability of intangible assets and other long-term assets. Under U.S. GAAP, in order to test the recoverability of intangible assets and other long term assets, we apply SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” We estimate the useful lives of intangible and other long-term assets based on the nature of the asset, historical experience and the terms of any related supply contracts. We test for impairment by comparing the sum of the future undiscounted cash flows expected to be received or derived from an asset or a group of assets to their carrying value. If the carrying value exceeds the future undiscounted cash flows, the impairment is measured using an estimation of the assets’ fair value, primarily using a discounted cash flow method. The identification of indicators of impairment, the estimation of future cash flow and the determination of fair values for assets or groups of assets require management to make significant judgments concerning the identification and validation of impairment indicators, expected cash flows and appropriate discount rates. A significant change to these assumptions could impact the estimated useful lives or valuation of intangible and other long-term assets resulting in a change to amortization expense and impairment charges.
New U.S. GAAP Accounting Standards
      In addition to the critical accounting policies discussed above under “The Electricity Market Regulatory Framework — Critical Accounting Policies” and “— Critical Accounting Policies under U.S. GAAP,” our future U.S. GAAP results will be affected by a number of new accounting standards that have been