Prospectus Supplement
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

Form 6-K

 


 

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO

RULE 13a-16 OR 15d-16 UNDER THE SECURITIES

EXCHANGE ACT OF 1934

 

For the Month of November 2004

 


 

EDP- Energias de Portugal, S.A.

 

Praça Marquês de Pombal, 12

1250-162 Lisbon, Portugal

(Address of principal executive offices)

 


 

(Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.)

 

Form 20-F  x    Form 40-F  ¨

 

(Indicate by check mark whether the registrant by furnishing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.)

 

Yes  ¨    No  x

 

 

 



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PROSPECTUS SUPPLEMENT

(To the prospectus dated October 29, 2004)

 

Offering of 656,537,715 Ordinary Shares

including ordinary shares in the form of American Depositary Shares

 

EDP – ENERGIAS DE PORTUGAL, S.A.

 

We are offering new ordinary shares, which we refer to as offered shares, to holders of our ordinary shares, nominal value €1 per share. We have also made arrangements with Citibank, N.A., the depositary for our American Depositary Shares, or ADSs, to make available to holders of our ADSs, pursuant to the grant of the ADS rights described below, new ADSs, which we refer to as offered ADSs. Each ADS represents ten ordinary shares. Holders of shares or ADSs of record on the relevant record date will receive subscription rights in proportion to their existing holding of ordinary shares or ADSs, as the case may be (in the case of ordinary shares, the “share rights,” and in the case of ADSs, the “ADS rights,” and together, the “rights”).

Holders of rights will be entitled to subscribe for the offered ADSs or offered shares, as the case may be. Each right includes an oversubscription right, referred to as an oversubscription right, to subscribe for an additional number of any offered shares or offered ADSs, as the case may be, that are not subscribed for pursuant to the initial exercise of rights, subject to certain limitations as further described herein. See “The Rights Offering.” The oversubscription right is not separable from the share right or the ADS right, as the case may be.

The underwriters, as identified in the section entitled “Underwriting,” have severally agreed, subject to certain conditions, to procure subscribers, or otherwise themselves to subscribe, for any remaining offered shares that are not subscribed for pursuant to the exercise of the rights, including the oversubscription rights (the “remaining offered shares”).


If you own ADSs:

  If you own ordinary shares:
Holders of our ADSs will receive one ADS right for each ADS that they own on the ADS record date.   Holders of our ordinary shares will receive one share right for each ordinary share that they own on the share record date.
Holders of ADS rights will be entitled to subscribe at the ADS subscription price for a number of ADSs determined by multiplying the number of ADS rights they own by the factor 0.22.   Holders of share rights will be entitled to subscribe at the share subscription price for a number of offered shares determined by multiplying the number of share rights they own by the factor 0.22.
The ADSs began trading cum-rights on the New York Stock Exchange, or NYSE, following our board meeting on November 4, 2004.   The ordinary shares commenced trading cum-rights on the Official Market of the Euronext Lisbon Stock Exchange, or Euronext Lisbon, following our board meeting on November 4, 2004.
The ADSs are expected to begin trading ex-rights on the NYSE at 9.30 a.m. (New York City time) on November 9, 2004.   The share record date for the purpose of determining entitlement to share rights is 4.30 p.m. (Lisbon time) on November 8, 2004.
The ADS record date for the purpose of determining entitlement to ADS rights is expected to be the close of business on November 12, 2004.   The ordinary shares will commence trading ex-rights on Euronext Lisbon at 8.30 a.m. (Lisbon time) on November 9, 2004.
The ADS subscription period will be from 9.00 a.m. (New York City time) on November 13, 2004 to 3.00 p.m. (New York City time) on November 23, 2004.   The ordinary share subscription period will be from 8.30 a.m. (Lisbon time) on November 12, 2004 to 3.00 p.m. (Lisbon time) on November 25, 2004.
The ADS subscription price is U.S.$23.70 per offered ADS subscribed. The ADS subscription price is the U.S. dollar equivalent of the share subscription price, using an exchange rate of €1.2883 per U.S. dollar, multiplied by ten to reflect that each ADS represents ten ordinary shares. A subscriber of the offered ADSs must tender U.S.$24.89 per offered ADS subscribed, which represents 105% of the ADS subscription price, upon the exercise of each ADS right. This is to increase the likelihood that the ADS rights agent will have sufficient funds to pay the ADS subscription price in light of possible U.S. dollar to euro exchange rate fluctuations.   The share subscription price is €1.84 per offered share subscribed, which was the equivalent of U.S.$2.37 on November 4, 2004.
ADS rights expire at 3.00 p.m. (New York City time) on November 23, 2004.   Share rights expire at 3.00 p.m. (Lisbon time) on November 25, 2004.
Listing and Trading:
Outstanding ADSs are traded on the NYSE under the symbol “EDP.”   Outstanding ordinary shares are traded on Euronext Lisbon under the symbol “EDP.”
The ADS rights are non-transferable. ADS rights that are not exercised by the end of the ADS subscription period will expire valueless without any compensation.   Subject to compliance with relevant securities laws, the share rights are freely transferable. The share rights are expected to trade on Euronext Lisbon under the symbol “EDPDS” from 8.30 a.m. (Lisbon time) on November 12, 2004 until 4.30 p.m. (Lisbon time) on November 19, 2004.

The exercise of ADS rights will be irrevocable upon exercise and may not be canceled or modified after such exercise. The exercise of share rights will become irrevocable and may not be canceled or modified after the close of business on November 22, 2004. Any rights unexercised by the end of the ADS subscription period or the share subscription period, as applicable, will expire valueless without any compensation.

Our gross proceeds from the rights offering will be approximately €1.20 billion, which was the equivalent of U.S.$1.55 billion on November 4, 2004. We estimate that our expenses in connection with the rights offering will be approximately €44 million, which was the equivalent of U.S.$57 million on November 4, 2004, including commitment fees and selling and management commissions totalling €41 million, which was the equivalent of U.S.$53 on November 4, 2004. As a result, the net proceeds to us will be approximately €1.16 billion, which was the equivalent of U.S.$1.49 billion on November 4, 2004. See “Underwriting” for more information on the commitment fees and selling, management and discretionary commissions.

We expect the offered ADSs, which will be fully fungible and rank equally in all respects with the outstanding ADSs, to be issued by Citibank, N.A., the depositary for the ADSs, on or around December 7, 2004, but no assurance can be given that such issuance and delivery will not be delayed. We expect to issue the offered shares on or around December 2, 2004 and to have them admitted to listing and trading on Euronext Lisbon on or around December 7, 2004, but no assurance can be given that such issuance or admission will not be delayed.

See “ Risk Factors” beginning on page S-12 to read about factors you should consider before subscribing for any offered ADSs or offered shares.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.


Caixa—Banco de Investimento, S.A.

  Joint Global Coordinators   Goldman, Sachs & Co.

BCP Investimento—Banco Comercial

Português de Investimento, S.A.

     

Morgan Stanley

UBS Limited


BCP Investimento—Banco Comercial

Português de Investimento, S.A.

  Rights Offering Coordinators   Caixa—Banco de Investimento, S.A.

November 8, 2004


Table of Contents

ABOUT THIS PROSPECTUS SUPPLEMENT

 

Before you invest in any securities offered by this prospectus supplement, you should read the attached base prospectus, which, together with this prospectus supplement, we refer to as the prospectus, and the related exhibits filed with the SEC, together with the additional information described under the headings “Where You Can Find More Information about EDP.” The base prospectus is on file with the SEC and may cover a variety of offerings that EDP may undertake. For information regarding the rights offering in particular, please see the prospectus supplement.

 

As used in this prospectus, unless the context otherwise requires, the terms “EDP, S.A.,” “EDP,” “we,” “us” and “our” refer to EDP—Energias de Portugal, S.A. (formerly known as EDP—Electricidade de Portugal, S.A), and, as applicable, its consolidated subsidiaries. Unless we specify otherwise or the context otherwise requires, references to “U.S.$,” “$,” and “U.S. dollars” are to United States dollars and references to “€”, “euro” or “EUR” are to the euro, the single European currency established pursuant to the European Economic and Monetary Union.

 

FORWARD-LOOKING STATEMENTS

 

This prospectus contains forward-looking statements. We may from time to time make forward-looking statements in our reports to the SEC on Form 20-F and Form 6-K, in our annual reports to shareholders, in offering circulars and prospectuses, in press releases and other written materials, and in oral statements made by our officers, directors or employees to analysts, institutional investors, representatives of the media and others.

 

These forward-looking statements, including, among others, those relating to our future business prospects, revenues and income, wherever they may occur in this prospectus, the documents incorporated by reference in this prospectus and the exhibits to this prospectus, are necessarily estimates reflecting the best judgment of our senior management and involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. As a consequence, you should consider these forward-looking statements in light of various important factors, including those set forth in this prospectus. Important factors that could cause actual results to differ materially from estimates or projections contained in the forward-looking statements include, without limitation:

 

  the effect of, and changes in, regulation and government policy, including, in particular, Portuguese government and municipal concessions and environmental regulations;

 

  the effect of, and changes in, macroeconomic, social and political conditions in countries in which we operate;

 

  the effects of competition, including competition that may arise in connection with the development of an Iberian electricity market;

 

  our ability to reduce costs;

 

  hydrological conditions and the variability of fuel costs;

 

  anticipated trends in our business, including trends in demand for electricity;

 

  our success in developing our telecommunications business;

 

  our success in new businesses, such as gas;

 

  future capital expenditures and investments;

 

  the timely development and acceptance of our new services;

 

  the effect of technological changes in electricity, telecommunications and information technology; and

 

  our success at managing the risks of the foregoing.

 

Forward-looking statements speak only as of the date they are made. We do not undertake to update such statements in light of new information or future developments.

 

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PRESENTATION OF FINANCIAL INFORMATION

 

Unless we indicate otherwise, we have prepared the financial information contained in the prospectus in accordance with generally accepted accounting principles in Portugal, or Portuguese GAAP, which differs in significant respects from generally accepted accounting principles in the United States, or U.S. GAAP. We describe these differences in “Operating and Financial Review and Prospects—Portuguese GAAP Compared with U.S. GAAP” and in note 39 to our audited consolidated financial statements and note 37 to our interim consolidated financial statements. Unless we specify otherwise, references in the prospectus to our “audited consolidated financial statements” are to our audited consolidated financial statements as of December 31, 2003 and 2002 and for each of the three years in the three-year period ended December 31, 2003 and the notes thereto, which are incorporated in the prospectus by reference to our Annual Report on Form 20-F for the year ended December 31, 2003 (the “2003 20-F”), and references in the prospectus to our “interim consolidated financial statements” are to our unaudited consolidated financial statements as of and for the six-month periods ended June 30, 2003 and 2004, respectively, and the notes thereto, which are incorporated in the prospectus by reference to our Report on Form 6-K furnished to the SEC on October 21, 2004.

 

Beginning in 2002 (for fiscal year 2001 and thereafter), we published our consolidated financial statements in euros. Unless we indicate otherwise, we have translated amounts stated in U.S. dollars from euros at an assumed rate solely for convenience. By including these currency translations in the prospectus, we are not representing that the euro amounts actually represent the U.S. dollar amounts shown or could be converted into U.S. dollars at the rate indicated. Unless we indicate otherwise, we have translated the U.S. dollar amounts from euros at 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 June 24, 2004 of U.S.$1.217 per €1.00. That rate may differ from the actual rates used in the preparation of our audited consolidated financial statements and U.S. dollar amounts used in the prospectus may differ from the actual U.S. dollar amounts that were translated into euros in the preparation of our audited consolidated financial statements.

 

In addition, for convenience only and except where we specify otherwise, we have translated certain reais figures into euro at the fixed rate of exchange between the real and euro of 3.776 reais = €1.00. The rate of exchange between reais and euros represents the euro equivalent of the U.S. dollar/real fixed rate of exchange, calculated by translating reais into U.S. dollars using the Noon Buying Rate on June 24, 2004 of 3.103 reais = U.S.$1.00 and then translating U.S. dollars into euros using the rate of exchange between U.S. dollars and euros of U.S.$1.217 = €1.00, which was the applicable Noon Buying Rate on June 24, 2004. By including convenience currency translations in the prospectus, we are not representing that the reais amounts actually represent the euro amounts shown or could be converted into euros at the rates indicated.

 

Prior to January 1, 2001, our reporting currency was Portuguese escudos. For convenience and to facilitate a comparison, all escudo-denominated financial data for periods prior to January 1, 2001 included in the prospectus have been restated from escudos to euros at the fixed rate of exchange as of January 1, 1999 of PTE 200.482 = €1.00. Where escudo-denominated amounts for periods prior to January 1, 2001 have been rounded, the restated euro amounts have been calculated by converting the rounded escudo-denominated amounts into euros. The comparative balances for prior years now reported in euros depict the same trends as would have been presented had we continued to report such amounts in Portuguese escudos. Other financial data for periods prior to January 1, 1999 may not be comparable to that of other companies reporting in euros if those companies had restated from a reporting currency other than Portuguese escudos.

 

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SUMMARY

 

This summary highlights selected information contained elsewhere in the prospectus. It is not complete and may not contain all of the information that is important to you. To understand the rights offering, you should read the detailed information included in the prospectus fully, including the audited consolidated financial statements and the interim consolidated financial statements, the discussion under “Risk Factors,” and any documents incorporated by reference in the prospectus.

 

RECENT EVENTS

 

Our operating margin in the first three quarters of 2004 increased by 35.0% to €786.1 million compared to the same period in 2003, while revenues increased 2.4% to €5,312.1 million. This increase primarily resulted from:

 

  strong sales growth in our electricity markets, with electricity consumption increasing 5.1% in Portugal, 4.2% in Spain and 5.3% in our Brazilian concession areas in the first nine months of 2004 compared to the same period in 2003;

 

  cost controls and improvements in efficiency, with personnel costs decreasing 4.3% as a result of our HR Restructuring Program;

 

  The entry of TER’s first unit into industrial service, which contributed 1.9 TWh of electricity emission;

 

  tariff revisions in Brazil, which were partially offset by provisional retroactive changes in tariffs granted to Bandeirante (as further described below); and

 

  the contribution of Naturcorp to our results in the first nine months of 2004, following the acquisition of a 56.8% stake in that company by Hidrocantábrico in July 2003.

In October 2004, the Brazilian electricity regulator decided to amend the average electricity tariff increase granted to Bandeirante in connection with the October 23, 2003 tariff review from 18.08% to 10.51%. The retroactive impact of this revision was already fully provisioned in our first three quarters of 2004, with €22 million booked as operating provisions and the remaining €6 million as a non-operating provision.

 

Our net interest and related income/expenses decreased by 6.3% in the first three quarters of 2004 to €268.9 million compared to the same period in 2003, primarily as a result of an 8.3% decrease in financial interest charges following a reduction in our financial debt. Our other non-operating income/expenses were adversely impacted by retroactive changes in tariffs granted to Bandeirante, as described above, and Escelsa, resulting in expenses of €16.1 million, and by costs relating to negotiated dismissals and early retirement age anticipations, which resulted in €22.4 million in expenses.

 

Our net profit increased by 36.1% to €350.6 million in the first nine months of 2004 compared to the same period in 2003, with our generation business and Brazilian operations being the primary contributors to this improvement.

 

Our capital expenditure for the first three quarters of 2004 totalled €706.9 million, a 34% increase compared to the same period in 2003. The expenditures principally reflect EDP Produção’s investment in the second 400 MW group at its TER CCGT facility, investment by Enernova in new wind farms, investment by Hidrocantábrico at the Albacete wind farm, increased investment by EDPD to improve service quality and increased investments at the Peixe Angical hydro power plant in Brazil, partially offset by decreased investment by ONI following completion of major investments for network expansion. Our cash flow generation after capital

 

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expenditures at our core businesses, EDP Produção and EDPD, accounted for €646.2 million of our total cash flow in the first three quarters of 2004, which amounted to €586.4 million, and enabled us to reduce our gross financial debt by €64.7 million, from €7,492.7 million as of December 31, 2003 to €7,428.0 million as of September 30, 2004.

 

On October 20, 2004, Hidrocantábrico announced that it had reached an agreement with Grupo Corporativo Ono for the sale of its total shareholding position of 34.96% in Retecal, having enacted the corresponding sale and purchase notarial deed on that day. The cash proceeds from this sale will amount to €57.5 million, while the book value of the shareholding position is €32.8 million.

 

On October 15, 2004, the Portuguese electricity regulator, the Entidade Reguladora dos Serviços Energéticos, referred to as ERSE, released its proposal on the parameters, tariffs and prices of electricity and other services for 2005. ERSE has proposed that in 2005 the tariffs for sale to final customers in Portugal (mainland) will be increased by 2.1% in nominal terms compared to 2004. The Tariff Regulation enacted by ERSE provides that the Tariff Council of ERSE, a consulting body on tariffs and regulation, must issue its (non-binding) opinion on this proposal by November 15, 2004. Subsequently, ERSE, considering the opinion expressed by the Tariff Council, will approve the final parameters, tariffs and prices, which should be published by December 15, 2004. The tariff set for 2005 or any new regulations promulgated may adversely affect our business, results of operations and financial condition.

 

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BUSINESS

 

We are the largest producer and distributor of electricity in Portugal and will become the third largest utility operator in the Iberian market following our announced acquisition of a further 56.2% stake in Hidrocantábrico, which will bring our total interest in it to 95.7%. Hidrocantábrico operates electricity generation plants and distributes and supplies electricity and gas, mainly in the Asturias and Basque regions in Spain. We intend to use the proceeds of this offering to finance this acquisition. For further information on the acquisition, see “Use of Proceeds” and “Information on the Company—Overview—Electricity.”

 

In 2003, we accounted for approximately 82% of the installed generation capacity in the Portuguese Public Electricity System, or PES, and 99% of the distribution in the PES. REN, in which we hold a 30% equity interest, accounted for 100% of the transmission in the PES. Hidrocantábrico, Spain’s fourth largest utility operator, accounted for 4.7% of Spanish mainland generation capacity, or 5.5% excluding special regime facilities (which are generally cogeneration and renewable energy facilities), and 6.5% of the Spanish liberalized electricity supply market.

 

We are also in the process of consolidating our position in the Portuguese and Spanish gas markets. In Portugal, we entered into an agreement in March 2004 pursuant to which, subject to the satisfaction of certain conditions, we intend to translate our existing 14.27% investment in GALP for a directly held 51% controlling stake in GDP, the gas distributing company of GALP and the largest in Portugal. We have also entered into agreements giving us the option to acquire stakes in two of the main Portuguese regional gas distribution companies, Portgás and Setgás. For further information on these transactions, see “Information on Our Company—Strategy—Developing an Iberian Gas Business.” In Spain, our current interest in the gas sector consists of our 39.5% holding in Hidrocantábrico, which controls Naturcorp, with more than 500,000 customers and approximately 10% of Spain’s regulated revenues for gas distribution, or 8% of gas distributed in Spain in terms of GWh. Following the acquisition of the additional 56.2% stake in Hidrocantábrico, we will be the second largest gas operator in Spain.

 

Our 2003 operating revenues amounted to €6,977.5 million (U.S.$8,491.6 million), approximately 90% of which represented electricity sales, yielding operating income of €905.7 million (U.S.$1,102.3 million). As of December 31, 2003, our total assets were €18,650.7 million (U.S.$22,697.9 million), and shareholders’ equity was €5,298.0 million (U.S.$6,447.7 million).

 

In Portugal, we generate power for consumption in both the Public Electricity System and the Independent Electricity System. In 2003, our generation facilities in Portugal had a total installed capacity of 7,939 MW. In the transmission function, REN operates the national grid for transmission of electricity throughout mainland Portugal on an exclusive basis pursuant to Portuguese law. REN also manages the system dispatch and the interconnections with Spain. EDPD, our distribution company, carries out Portugal’s local electricity distribution almost exclusively. EDPD provided approximately 5.8 million customers with 38,916 GWh of electricity in 2003. In Spain, Hidrocantábrico had a total installed capacity in 2003 of 2,820 MW and distributed a total of 8,659 GWh through its own network to more than 561,000 customers.

 

We expect regional electricity markets to consolidate in Europe as an initial step toward an integrated and liberalized electricity market within the European Union. For geographical and regulatory reasons, we anticipate that the Iberian electricity market will become our core market for our main electricity business following the implementation of MIBEL, which is expected to be operational by June 30, 2005. Further to this strategic focus, in 2001 and 2002, we expanded our energy operations in Spain with the acquisition of a 39.5% interest in Hidrocantábrico. The increase of our stake in Hidrocantábrico to 95.7% will result in the full integration of Hidrocantábrico’s operations within ours, which should allow us to enhance management flexibility, realize further synergies from the combination of our operations and improve business performance, thereby reinforcing our position as a leading Iberian energy company in advance of the opening of MIBEL. For more information on MIBEL, see “Information on the Company—The Iberian Electricity Market.”

 

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FINANCIAL INFORMATION

 

You should read the following summary consolidated financial data in conjunction with “Operating and Financial Review and Prospects” below and our audited consolidated financial statements, interim consolidated financial statements and other financial data found elsewhere in this prospectus or incorporated by reference herein.

 

The summary financial data below has been extracted from our audited consolidated financial statements as of and for each of the three years ended December 31, 2003 and the notes thereto, as well as from our unaudited interim consolidated financial statements as of and for the six-month periods ended June 30, 2003 and 2004 and the notes thereto. These consolidated financial statements have been prepared in accordance with Portuguese GAAP, which differs in certain significant respects from U.S. GAAP. See “Operating and Financial Review and Prospects—Portuguese GAAP compared with U.S. GAAP” and note 39 to our audited consolidated financial statements and note 37 to our interim consolidated financial statements for a discussion of the principal differences between Portuguese GAAP and U.S. GAAP with respect to our consolidated financial statements.

 

    

Year ended

December 31,


   

Six months ended

June 30,


 
     2001

    2002

    2003

    2003

    2004

 
     (millions of EUR, except per ordinary share
and per ADS data)
 
     (audited)     (unaudited)  

Statement of income:

                              

Amounts in accordance with Portuguese GAAP

                              

Electricity sales

   5,201     5,876     6,296     3,116     3,138  

Other sales(1)

   98     112     160     31     127  

Services(2)

   351     398     521     199     267  

Total revenues

   5,650     6,387     6,978     3,346     3,532  

Raw materials and consumables

   3,080     3,687     3,921     1,841     1,920  

Personnel costs

   592     625     647     345     325  

Depreciation and amortization

   665     740     846     408     389  

Supplies and services

   651     675     633     310     302  

Own work capitalized(3)

   (233 )   (242 )   (236 )   (117 )   (104 )

Concession and power-generation rental costs(4)

   149     158     176     88     95  

Hydrological correction(5)

   0     0     0     0     0  

Other operating expenses, net

   73     95     86     63     54  

Total operating costs and expenses

   4,977     5,738     6,072     2,939     2,980  

Operating margin

   674     649     906     407     552  

Net interest expense(6)

   205     223     359     183     181  

Other non-operating income (expenses), net

   126     (139 )   (14 )   59     (20 )

Income before income taxes

   594     287     532     284     350  

Provision for income taxes (net of deferred taxes)

   (203 )   (172 )   (196 )   (111 )   (103 )

Minority interest

   60     220     44     9     28  

Net income

   451     335     381     182     275  

Net income from operations per ordinary share(7)

   0.22     0.22     0.30     0.14     0.18  

Net income from operations per ADS

   2.25     2.16     3.02     1.36     1.84  

Basic and diluted net income per ordinary share(7)

   0.15     0.11     0.13     0.06     0.09  

Basic and diluted net income per ADS(7)

   1.50     1.12     1.27     0.61     0.92  

Dividends per ordinary share(8)

   0.11     0.09     0.09     —       —    

Dividends per ADS(8)

   1.13     0.90     0.90     —       —    

 

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Year ended

December 31,


   

Six months ended

June 30,


 
     2001

   2002

   2003

    2003

    2004

 
     (millions of EUR, except per ordinary share and per ADS data)  
     (audited)     (unaudited)  

Cash flow data:

                            

Amounts in accordance with Portuguese GAAP

                            

Net cash from operating activities

   1,221    898    1,774     791     852  

Net cash used in investing activities

   1,243    1,141    529     270     504  

Net cash used in (from) financing activities

   96    297    (1,119 )   (512 )   (486 )

Balance sheet data (at period end):

                            

Amounts in accordance with Portuguese GAAP

                            

Cash and cash equivalents

   34    214    287     143     204  

Other current assets

   1,496    1,863    1,919     1,866     1,860  

Total current assets

   1,530    2,077    2,207     2,009     2,064  

Fixed assets, net(9)

   9,844    11,204    11,652     11,210     11,706  

Other assets

   4,860    4,844    4,792     4,852     5,020  

Total assets

   16,233    18,125    18,651     18,071     18,790  

Short-term debt and current portion of long-term debt

   1,744    1,887    1,579     1,789     1,649  

Other current liabilities

   1,286    1,631    1,711     3,041     1,896  

Total current liabilities

   3,030    3,518    3,290     4,830     3,545  

Long-term debt, less current portion

   4,055    6,107    5,914     6,214     5,811  

Hydro account(11)

   388    324    0     0     0  

Other long-term liabilities

   2,423    2,616    3,525     1,174     3,461  

Total liabilities

   9,896    12,566    12,729     12,218     12,817  

Minority interest

   241    65    236     57     234  

Hydro account(11)

   0    0    388     383     375  

Shareholders’ equity

   6,097    5,494    5,298     5,413     5,364  

Amounts in accordance with U.S. GAAP(10)

                            

Fixed assets, net(9)

   5,929    6,602    7,172           7,324  

Total assets

   15,455    16,922    17,730           18,118  

Total current liabilities

   3,052    2,551    3,280           3,416  

Total long-term liabilities

   7,721    10,420    10,892           10,731  

Total liabilities

   10,773    12,970    14,172           14,147  

Shareholders’ equity

   4,441    3,886    3,497           3,739  

Operating Data:

                            

Installed Capacity (MW)

                            

Portugal

   7,610    7,654    7,939     7,661     7,971  

Spain

   2,262    2,671    2,820     2,736     2,816  

Electricity Distributed (GWh)

                            

Portugal

   36,025    36,931    38,916     19,372     20,138  

Spain

   7,919    8,375    8,659     4,227     4,525  

Number of Electricity Distribution Customers (#)

                            

Portugal

   5,541,418    5,665,056    5,768,287     5,731,006     5,819,635  

Spain

   536,746    549,091    561,208     556,062     567,412  

(1) Consists of sales of steam, ash, information technology products and sundry materials.
(2) Consists of electricity-related services, services to information technology systems, telecommunications, engineering, laboratory services, training, medical assistance, consulting, multi-utility services and other services.
(3) Our consolidated income statements present expenses in accordance with their nature rather than their function. Therefore, costs incurred by us for self-constructed assets are capitalized as part of fixed assets and included as a reduction of total expenses under “Own work capitalized” when the related costs have been included in the relevant expense items.

 

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(4) Substantially all of these amounts relate to rent expenses paid to municipalities for the right to distribute electricity in the relevant municipal areas.
(5) As required by government regulation, we record charges and credits to operating income, depending on hydrological conditions in a given year, to smooth the effect on our earnings and customer prices that result from changes in hydrological conditions. The difference between the economic costs of generating electricity and the economic reference costs based on an average hydrological year are included in this item. The imputed interest on the accumulated balance of the hydro account and other adjustments are included in “Other non-operating expenses (income).” In 2003 and for the following years, net gains and losses arising from the hydrological account are being charged to other non-operating income (expenses). In this respect, in 2003 we booked a € 19.4 million income item, or US$ 23.6 million, under this profit and loss account caption. Additionally, in 2001 we recorded a € 47.5 million income item. We did not record such an item in 2002.
(6) Includes interest and related expenses and interest and related income.
(7) Basic and diluted earnings per ordinary share are based on our historical average number of ordinary shares outstanding after giving effect to a 5 for 1 stock split and our average number of ordinary shares outstanding after giving effect to the 5 for 1 stock split plus the effect of the exercise of employee stock options, respectively. Basic and diluted earnings per ADS are based upon basic and diluted earnings per ordinary share multiplied by 10 as each ADS is equivalent to 10 ordinary shares on a post-split basis.
(8) Based on 3,000,000,000 ordinary shares issued and outstanding.
(9) Substantially all of these assets are subject to reversion to the Republic or the municipalities.
(10) U.S. GAAP amounts for 2001 are not comparable to 2002 and 2003 due to the implementation of SFAS 142.
(11) Commencing with 2003, the hydrological correction account is no longer presented in our consolidated balance sheet as a liability.

 

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THE OFFERING

 

Holders of ADSs

 

ADS rights offering

Holders of our ADSs will receive one ADS right for each ADS they hold on the ADS record date. Holders of ADS rights will be entitled to subscribe at the ADS subscription price for a number of ADSs determined by multiplying the number of ADS rights they own by the factor 0.22. Fractions of ADSs will not be issued and any fractions arising through the exercise of ADS rights will be rounded down to the nearest whole ADS. Subscriptions will be accepted for a whole number of offered ADSs only, although holders of ADSs may exercise all or only part of their ADS rights.

 

To the extent you are a registered holder of ADSs on the ADS record date, we have arranged for our ADS depositary, Citibank, N.A., which is acting as ADS rights agent in connection with the rights offering, to send you an ADS rights certificate showing the number of offered ADSs you are entitled to subscribe for.

 

ADS rights agent

Citibank, N.A.

 

Oversubscription rights

ADS rights include oversubscription rights entitling holders of ADSs on the ADS record date to subscribe, at the ADS subscription price, for an additional number of offered ADSs, in the event that any offered shares (including offered ADSs) are not subscribed for pursuant to the initial exercise of rights.

 

In the event that the rights offering is oversubscribed pursuant to the exercise of oversubscription rights, the further offered ADSs available will be allocated to holders of ADS rights who have exercised their oversubscription rights. Such allocation will be prorated among oversubscribing ADS rights holders in proportion to their initial exercise of ADS rights in the event that the number of ADSs subscribed for pursuant to the exercise of oversubscription rights is greater than the number of offered shares, if any, (divided by ten) that the depositary is entitled to pursuant to the exercise of the oversubscription rights associated with the ordinary shares underlying the ADSs, and subject to any maximum limit specified by each oversubscribing holder. The oversubscription right is not separable from the ADS right.

 

Applications for offered ADSs pursuant to the exercise of oversubscription rights must be made together with subscriptions for offered ADSs pursuant to the initial exercise of ADS rights.

 

Underwriting

The underwriters have severally agreed, subject to certain conditions, to procure subscribers, or otherwise themselves to subscribe, for any remaining offered shares. See “Underwriting.”

 

Cum-rights date

The ADSs began trading with ADS rights on the NYSE following our board meeting on November 4, 2004.

 

Ex-rights date

The ex-rights date for the ADSs is expected to be November 9, 2004. The ADSs are expected to commence trading on the NYSE without any rights on and after that date.

 

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ADS record date

The “ADS record date” for the purpose of determining entitlement to ADS rights is expected to be the close of business on November 12, 2004. The ADS rights will be credited to the book-entry system of DTC for further credit to the accounts of persons who held ADSs on the record date and registered holders will be sent their ADS rights certificates via first class mail as promptly as practicable thereafter.

 

ADS subscription period

From 9.00 a.m. (New York City time) on November 13, 2004 to 3.00 p.m. (New York City time) on November 23, 2004.

 

ADS subscription price

The ADS subscription price is U.S.$23.70 per offered ADS subscribed. The ADS subscription price is the U.S. dollar equivalent of the share subscription price, using an exchange rate of U.S.$1.2883 per Euro, multiplied by ten to reflect that each ADS represents ten ordinary shares. A subscriber of the offered ADSs must tender U.S.$24.89 per offered ADS subscribed, which represents 105% of the ADS subscription price, upon the exercise of each ADS right. This is to increase the likelihood that the ADS rights agent will have sufficient funds to pay the ADS subscription price in light of possible U.S. dollar to euro exchange rate fluctuations.

 

Transfer of ADS rights

The ADS rights are non-transferable. ADS rights that are not exercised by the end of the ADS subscription period will expire valueless without any compensation.

 

Exercise of ADS rights

Each holder or beneficial owner of ADS rights may exercise all or only part of its ADS rights, and may elect to exercise its oversubscription rights. Subscriptions must be received prior to 3.00 p.m. (New York City time) on November 23, 2004 by the ADS Rights Agent.

 

Each beneficial owner of ADS rights who wishes to exercise its ADS rights should consult with the financial intermediary through which it holds its ADSs and ADS rights as to the manner, timing and form of exercise documentation, method of payment of the ADS subscription price and other related matters required to effect such exercise. The financial intermediary with whom the subscription is made may require any person exercising rights to pay or block the ADS subscription price for the offered ADSs being subscribed for in a deposit account as a condition to accepting the relevant subscription.

 

We provide further details on how to exercise rights under “The Rights Offering.”

 

ADS rights exercise irrevocable

Any exercise of ADS rights will be irrevocable upon exercise and may not be canceled or modified after such exercise.

 

Unexercised ADS rights

ADS rights that are not exercised prior to the end of the ADS subscription period will expire valueless without any compensation.

 

Delivery of offered ADSs

We expect to have issued all the offered shares underlying the offered ADSs by December 2, 2004. Following the registration of the resulting share capital increase with the Portuguese Commercial

 

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Registry in Lisbon, the issued ordinary shares will be delivered to subscribers by credit of such ordinary shares to each offered share subscriber’s individual book-entry securities account and, following the admission of the offered shares to listing and trading on Euronext Lisbon, the offered ADSs will be sent to each offered ADS subscriber (by credit to its book-entry account at the financial intermediary through which it holds the ADSs or in the form of an ADS certificate by first class mail if it is a holder registered directly with the depositary). This admission to listing and trading and the issuance of the offered ADSs is expected to take place on December 7, 2004. However, we can give no assurance that such admission to listing and trading or issuance and delivery will not be delayed.

 

Holders of Ordinary Shares

 

Share rights offering

Holders of our ordinary shares will receive one share right for each ordinary share that they own on the record date. Holders of share rights will be entitled to subscribe at the share subscription price for a number of offered shares determined by multiplying the number of share rights they own by the factor 0.22. Fractions of offered shares will not be issued and any fractions arising through the exercise of share rights will be rounded down to the nearest whole offered share. Subscriptions will be accepted for a whole number of offered shares only, although holders of ordinary shares may exercise all or only part of their share rights.

 

Rights offering coordinators

BCP Investimento—Banco Comercial Português de Investimento, S.A. and Caixa—Banco de Investimento, S.A.

 

Oversubscription rights

Share rights include oversubscription rights entitling holders of record on the record date to subscribe, at the share subscription price, for an additional number of offered shares, in the event that they are not subscribed for pursuant to the initial exercise of rights.

 

In the event that the rights offering is oversubscribed pursuant to the exercise of oversubscription rights, the further offered shares available will be allocated to holders of share rights who have exercised their oversubscription rights. Such allocation will be prorated among oversubscribing share rights holders in proportion to their initial exercise of share rights in the event that the number of shares subscribed for pursuant to the exercise of oversubscription rights is greater than the number of offered shares not initially subscribed for pursuant to the exercise of rights, if any, and subject to any maximum limit specified by each oversubscribing holder. The oversubscription right is not separable from the share right.

 

Cum-rights date

The ordinary shares commenced trading with share rights on Euronext Lisbon following our board meeting on November 4, 2004.

 

Share record date

The “share record date” for the purpose of determining entitlement to share rights will be 4.30 p.m. (Lisbon time) on November 8, 2004, which is the last day that the ordinary shares will trade with share

 

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rights on Euronext Lisbon. At the start of business on November 12, 2004, the share rights will be credited through the book-entry system of the Central de Valores Mobiliários, or CVM, the Portuguese book-entry system, to the accounts of persons who held ordinary shares on the record date.

 

Ex-rights date

The ex-rights date for the ordinary shares is November 9, 2004. The ordinary shares will commence trading on Euronext Lisbon without any rights on and after that date.

 

Share subscription period

From 8.30 a.m. (Lisbon time) on November 12, 2004 to 3.00 p.m. (Lisbon time) on November 25, 2004.

 

Share subscription price

€1.84 per offered share, which was the equivalent of U.S.$2.37 on November 4, 2004.

 

Transfer of share rights

Subject to compliance with relevant securities laws, the share rights are freely transferable and are expected to trade on Euronext Lisbon under the symbol “EDPDS” from 8.30 a.m. (Lisbon time) on November 12, 2004 to 4.30 p.m. (Lisbon time) on November 19, 2004.

 

Exercise of share rights

Each holder of share rights may exercise all or only part of its share rights, and may elect to exercise its oversubscription rights. Each holder of share rights can subscribe for offered shares pursuant to the exercise of share rights and oversubscription rights by delivering a duly executed subscription form to an authorized financial intermediary or by any other means approved by such authorized financial intermediary with whom the subscription is made. Subscription forms will be available during the subscription period at any of the branches of the rights offering coordinators in Portugal. Subscriptions must be received prior to 3.00 p.m. on November 25, 2004.

 

Each holder of share rights who wishes to exercise its share rights should consult with the financial intermediary through which it holds its ordinary shares and share rights as to the manner, timing and form of exercise documentation, method of payment of the share subscription price and other related matters required to effect such exercise. The authorized financial intermediary through whom the subscription is made may require any person exercising share rights to pay or block the share subscription price for the offered shares being subscribed for in a deposit account as a condition to accepting the relevant subscription.

 

We provide further details on how to exercise rights under “The Rights Offering.”

 

Share rights exercise irrevocable

Any exercise of share rights will become irrevocable and may not be canceled or modified after the close of business on November 22, 2004.

 

Unexercised share rights

Share rights that are not exercised prior to the end of the share subscription period will expire valueless without any compensation.

 

Delivery of offered shares

Upon due exercise of any share rights and payment of the share subscription price, the authorized financial intermediary with whom

 

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the subscription was made will register with the CVM such holder’s name or such holder’s nominee’s name and the amount of the exercised share rights.

 

We expect to issue the offered shares by December 2, 2004. Following the registration of the resulting share capital increase with the Portuguese Commercial Registry in Lisbon, the issued offered shares will be delivered to subscribers by credit of such offered shares to each subscriber’s individual book-entry securities account. This is expected to take place on or around December 7, 2004. We expect that the offered shares will be admitted to listing and trading on Euronext on December 7, 2004. However, we can give no assurance that such issuance and delivery or admission to listing and trading will not be delayed.

 

For additional information regarding the rights offering, see “The Rights Offering.”

 

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RISK FACTORS

 

In addition to the other information included and incorporated by reference in this prospectus, you should carefully consider the following factors. There may be additional risks that we do not currently know of or that we currently deem immaterial based on information currently available to us. Our business, financial condition or results of operations could be materially adversely affected by any of these risks, resulting in a decline in the trading price of our ordinary shares or ADSs.

 

RISKS RELATED TO OUR CORE ELECTRICITY BUSINESS

 

The competition we face in the generation and supply of electricity is increasing, which may affect our electricity sales and operating margins.

 

The increase in competition from the Portuguese and Spanish implementation of EU directives intended to create a competitive electricity market may materially and adversely affect our business, results of operations and financial condition.

 

In Portugal, while we currently face limited competition from independent power producers in generation, we expect that this competition will increase as the industry further liberalizes. Portuguese law requires that contracts for the construction of future power plants in Portugal in the Binding Sector be awarded through competitive tender processes, in which we expect to participate. In a competitive tender process, we may lose opportunities to generate electricity in the Binding Sector in Portugal. For further information on the Binding Sector and the structure of the Portuguese electricity market, see “Information on the Company—Portugal—Electricity System Overview.”

 

In addition, the Portuguese government has implemented selected measures to encourage the development of various forms of electricity production, including auto production (entities generating electricity for their own use that may sell surplus electricity to the national transmission grid), cogeneration, small hydroelectric production (under 10 MVA installed capacity) and production using renewable sources. As an incentive from the Portuguese government, the electricity generated by these producers has been granted priority of sale in the Binding Sector. In 2003, the installed capacity of these producers was 1,885 MW, which represents 17% of the total installed capacity in Portugal. Through its subsidiaries, EDP participates in this generation area with an installed capacity of 272 MW.

 

The Portuguese regulatory structure now allows for competition in the supply of electricity, which could adversely affect our sales of electricity. In particular, as more electricity consumers elect to participate in the market-based Non-Binding Sector in Portugal, more electricity will be sold in the competitive markets, where prices may be lower than existing tariffs. The effects of this increased competition have not yet been fully determined, as full liberalization in the supply of electricity was only achieved on August 18, 2004.

 

Despite the complete liberalization of the Spanish generation and wholesale market since January 1, 2003, the majority of consumers have not changed their electricity supplier. Until now, this liberalization has mainly produced effects among medium- and high-voltage consumers. Although fixed rate tariffs are expected to predominate, at least in the short and medium term, among Spanish electricity consumers, especially low voltage consumers, there could be a more pronounced move to contractually-agreed prices in the future and these prices could be lower than regulated tariffs.

 

In the context of liberalization of the electricity market within the European Union, since the end of 2001, the Portuguese and Spanish governments have entered into several agreements for the creation of an Iberian electricity market, referred to as MIBEL, the main principles of which are free competition, transparency, objectiveness and efficiency. The stated intent of MIBEL is to guarantee Portuguese and Spanish consumers access to electricity distribution and to create interconnections with third countries on equal conditions applicable to Portugal and Spain. In addition, it is intended that the production of electricity by producers in Portugal and

 

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Spain be subject to similar regulation, thereby allowing producers in one country to execute bilateral agreements for electricity distribution to consumers in the other country and facilitating the creation of an Iberian common electricity pool.

 

The scope of increased competition and any adverse effects on our operating results and market share resulting from the full liberalization of the European electricity markets, and in particular the Portuguese and Spanish electricity markets, combined with the opening of MIBEL (which is expected to occur by June 30, 2005), will depend on a variety of factors that cannot be assessed with precision and that are beyond our control. Accordingly, we cannot anticipate the risks and advantages that may arise from this market liberalization. When further implemented, the organizational model and resulting competition may materially and adversely affect our business, results of operations and financial condition.

 

Our core electricity operating results are affected by laws and regulations, including regulations regarding the prices we may charge for electricity.

 

As an electricity public service, we operate in a highly regulated environment. An independent regulator appointed by the Portuguese government, the Entidade Reguladora dos Serviços Energéticos, referred to as ERSE, or the regulator, regulates the electricity industry through, among other things, a tariff code that defines the prices we may charge for electricity services in the Binding Sector. In attempting to achieve an appropriate balance between, on the one hand, the interests of electricity customers in affordable electricity and, on the other hand, our need and the needs of other participants in the electricity sector to generate adequate profit, the regulator may take actions that adversely impact our profitability.

 

The final tariff collected by EDP Distribuição, or EDPD, our distribution company in Portugal, is calculated on the basis of a unitary tariff by level of electricity tension defined by ERSE, subject to a yearly adjustment on the basis of the Portuguese consumer price index, or CPI, less an efficiency factor. During the current regulatory period (2002-2004), the “efficiency factor” has increased from 5% (applicable during the 1999-2001 regulatory period) to approximately 7%. In addition, on the basis of this formula, net tariffs charged by EDPD have decreased in 2004 compared to 2003, which could adversely affect our profitability in 2004. In light of the expected implementation of the agreements creating MIBEL, we estimate that a new regulatory period will be established with a duration of only one year. The tariff set for that period or any new regulations promulgated in that period may adversely affect our business, results of operations and financial condition.

 

The current and future legislation contemplating the early termination of the PPAs could eventually adversely affect our revenues.

 

Following the Resolution of the Council of Ministers no. 63/2003 of April 28, 2003 relating to the promotion of liberalization of the electricity and gas markets in furtherance of the organizational structure of MIBEL, the Portuguese government enacted Decree law no. 185/2003 of August 20, 2003, which contemplates the eventual early termination of existing power purchase agreements, or PPAs, in accordance with conditions to be set out in a separate decree law, which will be approved by the Portuguese government pursuant to the legislative authorization granted by the Portuguese parliament under Law no. 52/2004 of October 29, 2004. Decree law no. 185/2003 of August 20, 2003 provides for the creation of compensation measures ensuring electricity generating companies an economic benefit equivalent to that of the PPAs, and the EU Commission announced on September 20, 2004 that the stranded cost compensation mechanism notified by the Portuguese government is not contrary to the state aid rules of the European Union. However, the amount of, and the criteria for determining, the compensation have not yet been defined and our generation revenues could otherwise be adversely affected if our generation sales are not made on terms substantially similar to those previously made to REN, the sole transmitter of electricity in Portugal. In addition, our operating margins may be adversely affected by new costs that are currently compensated through PPAs.

 

If our concessions from the Portuguese government and municipalities were terminated, we could lose control over our fixed assets.

 

Most of our revenues currently come from the generation and distribution of electricity. We conduct these activities pursuant to concessions and licenses granted by the Portuguese government and various municipalities.

 

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These concessions and licenses are granted for fixed periods ranging in most cases from 20 to 75 years, but are subject to early termination under specified circumstances. The expiration or termination of concessions or licenses would have an adverse effect on our operating revenues. Upon expiration of licenses or termination of concessions, the fixed assets associated with licenses or concessions will, in general, revert to the Portuguese government or a municipality, as appropriate. Although specified compensatory amounts would be paid to us with respect to these assets in these circumstances, the loss of these assets may adversely affect our operations.

 

Our operational cash flow is affected by variable hydrological conditions.

 

Hydroelectric plants, which are powered by water, account for approximately 54% of our generation capacity in mainland Portugal. Our hydroelectric generation in Portugal is dependent on the amount and location of rainfall and river flows from Spain, all of which vary widely from year to year. Consequently, there is a high degree of variation in levels of hydroelectric production.

 

In years of less favorable hydrological conditions, we generate less hydroelectricity and must rely more heavily on thermal production to meet demand for electricity. Thermal generation, which is fired by coal, fuel oil, natural gas or a combination of fuels, is more expensive in terms of variable costs than hydroelectric generation. Our total variable production costs and costs of purchased electricity in a very dry year can vary from those in a very wet year by approximately €200 million. These increased costs in a dry year could have an adverse impact on our operational cash flow but not our results of operations, due to the effects of the hydrological correction account, which is a legally mandated mechanism that adjusts for variation in hydrological conditions across different years. For further information on the hydrological correction account, see “Operating and Financial Review and Prospects—Critical Accounting Policies—Revenue Recognition—Hydrological Account.”

 

Our electricity business is subject to numerous environmental regulations that could affect our results of operations and financial condition.

 

Our electricity business is subject to extensive environmental regulations. These include regulations under Portuguese law, laws adopted to implement EU 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 waste products of fossil-fueled electricity generation are sulfur dioxide, or SO2, nitrogen oxides, or NOX, carbon dioxide, or CO2, and particulate matters such as dust and ash. A primary focus of environmental regulation applicable to our business is to reduce these emissions.

 

We incur significant costs to comply with environmental regulations requiring us to implement preventive or remediation measures. For example, we expect to make approximately €40 million of capital expenditures in 2004 to comply with applicable environmental laws and regulations to minimize the impact of our operations on the environment. Environmental regulatory measures may take such forms as emission limits, taxes or required remediation measures, and may influence our policies in ways that affect our business decisions and strategy, such as by discouraging our use of certain fuels.

 

Under the EU Directive relating to the emission of pollutants from Large Combustion Plants, Portuguese environmental authorities are currently creating a plan, called the National Emissions Reduction Plan, to reduce SO2 and NOx emissions. This plan is expected to be formally approved at the end of 2004. Additionally, with regard to CO2 emissions, new proposals defining greenhouse gas emission reduction measures were put forward for public comment in 2003, and are expected to be implemented in Portugal later this year. Although we expect to be in timely compliance with these new requirements, such requirements could necessitate additional licenses or the acquisition of emission rights and result in higher electricity costs.

 

We also have an interest in a nuclear power plant through Hidroeléctrica del Cantábrico, S.A., or Hidrocantábrico, which holds a 15.5% interest in the Trillo nuclear power plant in Spain. Nuclear operations use and generate radioactive and hazardous substances that have the potential to seriously impact human health and the environment.

 

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There are particular risks associated with the operation of nuclear power stations, including accidents, the breakdown or failure of equipment or processes or human performance, including safety controls, and other catastrophic events that could result in the dispersal of radioactive material over large areas, thereby causing injury or loss of life and extensive property or environmental damage. Liabilities we may incur in connection with these risks could significantly reduce our revenues and increase our expenses and result in negative publicity and reputational damage. In addition, insurance proceeds may not be adequate to cover all liabilities incurred, lost revenue or increased expenses.

 

For further information on environmental matters, see “Information on the Company—Environmental Matters” below.

 

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RISKS RELATED TO OUR OTHER BUSINESSES

 

Our involvement in international activities subjects us to particular risks that could affect our profitability.

 

Our investments in Brazil and in other countries present a different or greater risk profile than that of our electricity business in Portugal and Spain. Risks associated with our investments outside of Portugal and Spain include, but are not limited to:

 

  economic volatility;

 

  exchange rate fluctuations and exchange controls;

 

  strong inflationary pressures;

 

  government involvement in the domestic economy;

 

  political uncertainty; and

 

  unanticipated changes in regulatory or legal regimes.

 

We cannot assure you that we will successfully manage our operations in Brazil and other international operations.

 

Exchange rate instability and, in particular, fluctuations in the value of the Brazilian real against the value of the U.S. dollar (depreciation of 52% during 2002 and appreciation of 18% during 2003) may result in uncertainty in the Brazilian economy, which may affect the results of our Brazilian operations. In addition, we are exposed to translation risk when the accounts of our Brazilian businesses, denominated in Brazilian reais, are translated into our consolidated accounts, denominated in euro. We cannot predict movements in Brazil’s currency, and, since long-term Brazilian currency hedges are not available, a major devaluation of the real might adversely affect our results of operations and financial condition.

 

Regulatory, hydrological and infrastructure conditions in Brazil may adversely affect our Brazilian operations.

 

We hold interests in Brazilian distribution companies and have invested in Brazilian generation projects. In the past, our distribution activities and generation projects in Brazil have been adversely affected by regulatory, hydrological and infrastructure conditions in Brazil. These conditions could have a similar adverse effect on our Brazilian generation and distribution operations in the future.

 

Delays by the Brazilian energy regulatory authorities in developing a regulatory structure that encourages new generation have led to, and might also in the future contribute to, shortages of electricity to meet demand in some regions of Brazil. As a result, supply of electricity available for our distribution companies in Brazil has been limited and may be again in the future. In addition, the geographic location of generation plants, combined with transportation constraints, has limited, and might also in the future limit, our ability to transmit electricity generated in abundant rainfall areas to distribution companies operating in areas experiencing drought conditions. Sales by these distribution businesses have been and might in the future be affected by these conditions that limit the supply of electricity available for distribution.

 

The Brazilian electricity rationing program started in June 2001 and ended in February 2002 had an adverse effect on electricity consumption and on consumption habits in affected areas. Current consumption levels have not yet recovered to pre-rationing levels. This lower consumption has affected, and is expected to continue to affect, the demand for electricity supply with our distribution companies in Brazil. Consequently, in 2002 and 2003, our Brazilian operations could only dispose of surplus electricity at depressed prices.

 

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In 2004, laws regarding the so-called New Model for the Brazilian electric utility sector were approved. As the regulations for the New Model have not yet been implemented, there is a risk that the new regulations may not be favorable for us. In addition, the New Model contemplates significant control by the Brazilian government, creating uncertainty regarding competition and further investments in the private sector.

 

Tariffs of distribution companies in Brazil currently consist of two components: non-manageable costs and manageable costs. The main purpose of this split is the maintenance of an adjusted tariff for inflation and the sharing of efficiency gains with consumers. The aim of distribution tariffs is to pass non-manageable costs through and to index manageable costs to inflation. Although it is expected that the New Model will maintain the pass-through of non-manageable costs, there might be delays in readjustment of the tariffs in the event of large macro-economic fluctuations (e.g., inflation and exchange rates). We cannot assure you that regulations implementing the New Model will fully mitigate the risk of delayed tariff adjustments.

 

We face various risks in our telecommunications business, including increasing competition from various types of service providers.

 

The telecommunications sector is highly competitive within Portugal and Spain and across the EU, and we expect competition to remain vigorous and even increase in the future.

 

In the fixed line telephone area, we compete for market share primarily with Portugal Telecom, or PT, which historically held a monopoly on fixed line services in Portugal and continues to hold a dominant position in this market. We also face competition from other fixed line operators in Portugal.

 

Our fixed line telephone business also faces strong indirect competition from cellular telephone service providers, particularly those in the voice segment. Mobile subscriptions have already overtaken the number of fixed line connections in Portugal and we expect this growth to continue.

 

We also face significant competition from numerous existing operators in the Internet and data services areas, both of which we have targeted, and we expect that new competitors will emerge as these markets continue to evolve.

 

We face managerial, commercial, technological and regulatory risks, as well as other risks, related to our telecommunications activity. Our ability to develop and successfully achieve profitability in this area may be affected if we are not able to manage these risks and this business efficiently in a competitive market. In 2003, our telecommunications activity generated a loss before taxes of €148.7 million.

 

We face new risks and uncertainties related to our activities in the gas sector.

 

We intend to develop an Iberian gas business as complimentary to and strategically aligned with our electricity business, as described in more detail in “Strategy—Iberian Energy—Developing an Iberian Gas Business.” The development of a significant position in the Portuguese gas sector depends on the closing of the acquisition provided for in the agreement we entered in March 2004 to purchase, together with Eni and REN, the entire share capital of GDP, the largest gas distribution company in Portugal. The completion of the acquisition is subject, among other conditions, to approval of the relevant competition authorities, which has been requested and in connection with which the EU Commission has decided to initiate proceedings under article 6.1(c) of Commercial Regulation (EC) no. 139/2004 of January 20, 2004 on the control of concentrations between undertakings. We may also face difficulties integrating this business with our current activities and the development of the business will expose us to new risks, including governmental and environmental industry regulation and economic risks relating to the fluctuations in the price of energy, currencies and time-lags between purchase and sale prices. We cannot assure you that we will successfully manage the development of our gas business, and a failure to do so could have an adverse effect on our business, results of operations or financial condition.

 

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OTHER RISKS

 

The value of our ordinary shares and/or ADSs may be adversely affected by future sales of substantial amounts of ordinary shares by the Portuguese government or the perception that such sales could occur.

 

According to Decree law no. 218-A/2004 of October 25, 2004, known as the Reprivatization Decree Law, the Portuguese government may, after a period of 180 days following the verification of the results of the rights offering, sell all or a portion of its shareholding in us. Sales of substantial amounts of our ordinary shares by the Portuguese government, or the perception that such sales could occur, could adversely affect the market prices of our ordinary shares and ADSs and could adversely affect our ability to raise capital through subsequent offerings of equity.

 

Restrictions on the exercise of voting rights, as well as special rights granted to the Portuguese government, may impede an unauthorized change in control and may limit our shareholders’ ability to influence company policy.

 

Under our articles of association, no holder of ordinary shares, except the Portuguese Republic and equivalent entities, may exercise voting rights that represent more than 5% of our voting share capital. In addition, specific notification requirements are triggered under our articles of association when shareholders purchase 5% of our ordinary shares and under the Portuguese Securities Code when purchases or sales of our ordinary shares cause shareholders to own or cease to own specified percentages of our voting rights.

 

Pursuant to article 10 of the Reprivatization Decree Law, special rights granted to the Portuguese government by Decree law no. 141/2000 of July 15, 2000 are to be maintained for so long as the Portuguese government is an EDP shareholder. These rights provide that, without the favorable vote of the government, no resolution can be adopted at our general meeting of shareholders relating to:

 

  amendments to our by-laws, including share capital increases, mergers, spin-offs or winding-up;

 

  authorization for us to enter into group/partnership or subordination agreements; or

 

  waivers of, or limitations on, our shareholders’ rights of first refusal to subscribe to share capital increases.

 

The Portuguese government may also appoint one member of our board of directors whenever the government votes against the list of directors presented for election at our general meeting of shareholders.

 

RISKS RELATED TO THE RIGHTS OFFERING

 

The market prices for our ADSs and ordinary shares may fluctuate and may decline below the ADS subscription price and the share subscription price, and we cannot assure you that the listing and admission to trading of the offered shares on Euronext Lisbon, and thus the offered shares becoming fungible with our existing shares, as well as the issuance of the offered ADSs, will occur when we expect.

 

We cannot assure you that the public trading market prices of our ADSs and ordinary shares will not decline below the ADS subscription price and the share subscription price. Should that occur after you exercise your rights, you will suffer an immediate unrealized loss as a result. Moreover, we cannot assure you that, following the exercise of rights, you will be able to sell your offered ADSs or offered shares at a price equal to or greater than the ADS subscription price or the share subscription price, as applicable. Until the offered shares are admitted to listing and trading on Euronext Lisbon, they will not be fungible with our existing ordinary shares currently traded on Euronext Lisbon. The admission to listing and trading on Euronext Lisbon depends on the registration of our share capital increase with the commercial registry following settlement of the offering (including settlement of any offered shares delivered pursuant to exercise of oversubscription rights). Similarly, until the ordinary shares underlying the offered ADSs are admitted to listing and trading on Euronext Lisbon, you will not be issued any offered ADSs for which you subscribed. We cannot assure you that the registration of the share capital increase with the commercial registry and the admission of the offered shares to listing and trading on Euronext Lisbon will take place when anticipated. See “The Rights Offering” for further information on the expected dates of these events.

 

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Rights that are not exercised prior to the end of the ADS subscription period or the share subscription period, as applicable, will expire valueless without any compensation, and if you do not exercise your rights, you will suffer significant dilution of your percentage ownership of our shares and shares in the form of ADSs.

 

The ADS subscription period begins at 9.00 a.m. (New York City time) November 13, 2004 and expires at 3.00 p.m. (New York City time) on November 23, 2004. The share subscription period begins at 8.30 a.m. (Lisbon time) on November 12, 2004 and expires at 3.00 p.m. (Lisbon time) on November 25, 2004. Any rights unexercised at the end of the subscription period will expire valueless without any compensation. The ADS rights are not transferable and, accordingly, the only way to realize their value is to exercise them and purchase new ADSs.

 

The underwriters, as identified in the section entitled “Underwriting,” have severally agreed, subject to certain conditions, to procure subscribers, or otherwise themselves to subscribe, for any remaining offered shares. To the extent that you do not exercise your rights, your proportionate ownership and voting interest in EDP will, accordingly, be reduced, and the percentage that your current holdings of shares or shares in the form of ADSs represent of our increased share capital after completion of the rights offering will be disproportionately reduced. See “Dilution.” Even if you elect to sell your unexercised share rights, the consideration you receive for them may not be sufficient to fully compensate you for the dilution of your percentage ownership of our shares that may be caused as a result of the rights offering.

 

Holders of ADSs are subject to exchange rate risk.

 

In the event that the U.S. dollar to euro exchange rate declines, holders subscribing for offered ADSs may be required to pay more than U.S.$23.70 per offered ADS for which they have subscribed.

 

The ADS subscription price is U.S.$23.70 per offered ADS subscribed. The ADS subscription price is the U.S. dollar equivalent of the share subscription price, using an exchange rate of U.S.$1.2883 per Euro, multiplied by ten to reflect that each ADS represents ten ordinary shares. A subscriber of the offered ADSs must tender U.S.$24.89 per offered ADS subscribed, which represents 105% of the ADS subscription price, upon the exercise of each ADS right. This is to increase the likelihood that the ADS rights agent will have sufficient funds to pay the ADS subscription price in light of possible U.S. dollar to euro exchange rate fluctuations. The ADS rights agent expects to make the conversion from U.S. dollars into euros on November 24, 2004 at a market-based rate to pay the share subscription price for the offered shares underlying the offered ADSs subscribed for (excluding any offered ADSs subscribed for pursuant to the exercise of oversubscription rights), and, if necessary, to make an additional conversion at a market-based rate on a subsequent date to purchase any offered ADSs subscribed for pursuant to the exercise of oversubscription rights. If there is any excess in U.S. dollars as a result of such conversion or conversions, the ADS rights agent will refund the excess U.S. dollar subscription price to the subscribing ADS holder without interest. However, if there is a deficiency as a result of such conversion or conversions, the ADS rights agent will not issue and deliver the offered ADSs to such subscribing ADS holder until it has received payment of the deficiency.

 

An active trading market may not develop for the share rights and, if a market does develop, the share rights may be subject to greater volatility than our ADSs and ordinary shares.

 

A trading period has been set for the share rights from November 12, 2004 to November 19, 2004. We cannot assure you that an active trading market in the share rights traded on Euronext Lisbon will develop during the trading period or that any over-the-counter trading market in the rights will develop. Even if active markets develop, the trading price of the rights may be volatile.

 

In the event that there are remaining offered shares and the underwriting agreement is terminated, holders who have exercised their rights would effectively be unable to subscribe for the offered ADSs or

 

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offered shares, as the case may be, as the share capital increase relating to the offering will become invalid if the offering is not fully subscribed and the rights offering will be terminated.

 

As is market practice for offerings of this type, the underwriting agreement is subject to the fulfillment of certain conditions, and may be terminated upon the occurrence of certain events, including certain events of force majeure, the termination of our agreements to acquire Hidrocantábrico and the breach of representations and warranties by us under the underwriting agreement. Should the underwriting agreement be terminated, if there are any remaining offered shares, holders who have exercised their rights would effectively be unable to subscribe for the offered ADSs or offered shares, as the case may be, as the share capital increase will not be effective unless the offering is fully subscribed.

 

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USE OF PROCEEDS

 

The net proceeds to us from the rights offering, after deduction of commissions and estimated expenses, are estimated to be €1.16 billion, which was the equivalent of U.S.$1.49 billion on November 4, 2004. We plan to use the net proceeds to finance the acquisition of an additional 56.2% stake in Hidrocantábrico, which will increase our current holdings in that company from 39.5% to 95.7% of its outstanding share capital. See “Information on the Company—Overview—Electricity” for further details on this acquisition.

 

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CAPITALIZATION AND INDEBTEDNESS

 

The table below sets forth our capitalization and indebtedness as of September 30, 2004. You should read this table in conjunction with the audited consolidated financial statements and interim consolidated financial statements.

 

    

As of

September 30, 2004


    Adjustments to reflect
the rights offering


   As adjusted for the
rights offering


 
     (thousands of EUR)     (thousands of EUR)    (thousands of EUR)  

Short-term debt and current portion of medium- and long-term debt

   1,597,439        1,597,439  

Medium- and long-term debt:

   5,830,581        5,830,581  

Bank loans

   2,216,772        2,216,772  

Bonds

   3,513,809        3,513,809  

Commercial paper

   100,000

 

 

   100,000

 

Total debt

   7,428,020        7,428,020  
    

 
  

Shareholders’ equity:

                 

Authorized and issued share capital (nominal value of shares)

   3,000,000     656,538    3,656,538  

Treasury stock

   (37,182 )        (37,182 )

Reserves and retained earnings

   2,157,058     551,491    2,708,550  

Consolidated net profit

   350,612          350,612  

Total shareholders’ equity

   5,470,488     1,208,029    6,678,517  
    

 
  

Total capitalization

   12,898,508     1,208,029    14,106,537  
    

 
  


(1) The issued share capital is fully paid.
(2) As at September 30, 2004, no undertaking within the EDP Group, either individually or collectively, had any guarantees or other contingent liabilities outside the EDP Group, which were material in the context of the EDP Group.
(3) As at September 30, 2004, our indebtedness was unsecured, except for EUR 5.7 million of our total medium- and long-term debt, which was guaranteed.
(4) There has been no material change to the consolidated capitalization and indebtedness, contingent liabilities or guarantees of EDP since September 30, 2004.

 

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DILUTION

 

In the event that existing ADS holders or shareholders elect not to exercise their rights, such ADS holders or shareholders will experience substantial dilution of their ownership interest because other ADS holders or shareholders may subscribe for additional offered shares or offered ADSs pursuant to the exercise of their rights and because the underwriters have agreed, subject to certain conditions, to procure subscribers, or otherwise themselves to subscribe, for any remaining offered shares. See “Underwriting.” Existing ADS holders or shareholders that do not exercise their rights in the rights offering will be diluted such that a shareholder holding 1.00% of our outstanding ordinary share capital prior to the rights offering will have its shareholding reduced to approximately 0.82% of our outstanding ordinary share capital following the issuance of 656,537,715 offered shares (including offered ADSs) in the rights offering. See “Risk Factors—Risks Relating to the Rights Offering.” If you do not exercise all of your rights, you will suffer significant dilution of your percentage ownership of our ordinary shares.”

 

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INFORMATION ON THE COMPANY

 

OVERVIEW

 

Electricity

 

Historically, electricity has been our core business. We underwent a restructuring in 1994, at which time we formed subsidiaries to operate in the areas of electricity generation, transmission and distribution. Following the government’s purchase from us of a 70% interest in REN in 2000, our two principal electricity subsidiaries were our electrical generation company, CPPE, and our distribution company, EDPD, which was formed in early 2000 by the merger of our four wholly-owned distribution companies. These two wholly-owned subsidiaries, together with REN, carried out electricity generation, transmission and distribution activities in Portugal. On March 29, 2001, we announced the creation of EDP—Gestão da Produção de Energia S.A., or EDP Produção, a subsidiary that began operations in July 2001 and now holds most of our Portuguese energy production-related units as part of measures we are implementing to enhance our organizational efficiency.

 

We are the largest producer and distributor of electricity in Portugal and will become the third largest utility operator in the Iberian market following our announced acquisition of a further 56.2% stake in Hidrocantábrico, which is described in further detail below. Hidrocantábrico operates electricity generation plants and distributes and supplies electricity and gas, mainly in the Asturias and Basque regions in Spain. We intend to use the proceeds of this offering to finance this acquisition. For further information on the acquisition, see “Use of Proceeds” and “Information on the Company—Overview—Electricity.”

 

In 2003, we accounted for approximately 82% of the installed generation capacity in the Portuguese Public Electricity System, or PES, and 99% of the distribution in the PES. REN, in which we hold a 30% equity interest, accounted for 100% of the transmission in the PES. Hidrocantábrico, Spain’s fourth largest utility operator, accounted for 4.7% of Spanish mainland generation capacity, or 5.5% excluding special regime facilities (which are generally cogeneration and renewable energy facilities), and 6.5% of the Spanish liberalized electricity supply market.

 

Our 2003 operating revenues amounted to €6,977.5 million (U.S.$8,491.6 million), approximately 90% of which represented electricity sales, yielding operating income of €905.7 million (U.S.$1,102.3 million). As of December 31, 2003, our total assets were €18,650.7 million (U.S.$22,697.9 million), and shareholders’ equity was €5,298.0 million (U.S.$6,447.7 million).

 

The following table shows our revenues by activity and geography:

 

     Year ended December 31,

   

June 30,

2004


 
     2001

    2002

    2003

   
     (audited)     (unaudited)  
     (millions of EUR)  

Energy(1)

                        

Portugal

   4,599     5,001     5,038     2,483  

Spain

   0     324     675     379  

Brazil

   691     669     1,008     513  

Telecommunications

                        

Portugal

   126     187     161     78  

Spain

   62     134     170     88  

Information Technology

   189     224     186     91  

Adjustments(2)

   (16 )   (151 )   (261 )   (100 )
    

 

 

 

Total

   5,650     6,387     6,978     3,532  

(1) Consists of electricity in Portugal and Brazil and electricity and gas in Spain.
(2) Revenue figures for each year have been adjusted to include revenues from services and to exclude intercompany transactions.

 

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In Portugal, we generate power for consumption in both the PES and the Independent Electricity System. In 2003, our generation facilities in Portugal had a total installed capacity of 7,939 MW. In the transmission function, REN operates the national grid for transmission of electricity throughout mainland Portugal on an exclusive basis pursuant to Portuguese law. REN also manages the system dispatch and the interconnections with Spain. EDPD, our distribution company, carries out Portugal’s local electricity distribution almost exclusively. EDPD provided approximately 5.8 million customers with 38,916 GWh of electricity in 2003. In Spain, Hidrocantábrico had a total installed capacity in 2003 of 2,820 MW, distributed a total of 8,659 GWh through its own network to more than 561,000 customers and invoiced 4,712 GWh of electricity supply.

 

We expect regional electricity markets to consolidate in Europe as an initial step toward an integrated and liberalized electricity market within the European Union. For geographical and regulatory reasons, we anticipate that the Iberian electricity market will become our core market for our main electricity business following the opening of MIBEL, which is expected to occur by June 30, 2005. Further to this strategic focus, in 2001 and 2002, we expanded our energy operations in Spain with the acquisition of a 39.5% interest in Hidrocantábrico. The increase of our stake in Hidrocantábrico to 95.7% will result in the full integration of Hidrocantábrico’s operations within ours, which should allow us to enhance management flexibility, realize further synergies from the combination of our operations and improve business performance, thereby reinforcing our position as a leading Iberian energy company in advance of the opening of MIBEL.

 

Acquiring an Increased Stake in Hidrocantábrico

 

We intend to use the proceeds of this offering to finance the acquisition of an additional 56.2% stake in Hidrocantábrico, thereby bringing our total interest in it to 95.7%. Under agreements executed on July 29, 2004, we have agreed to acquire:

 

  a 34.6% interest in Hidrocantábrico from Energie-Baden-Württemberg AG, or EnBW, for consideration of €649 million in the form of cash;

 

  a 17.5% interest in Hidrocantábrico from Cajastur—Caja de Ahorros de Asturias, or Cajastur, for consideration of €453 million in the form of EDP shares; and

 

  a 4.1% interest in Hidrocantábrico from Cáser—Caja de Seguros Reunidos, Compañía de Seguros y Reaseguros, S.A., or Cáser, for consideration of €93 million in the form of cash.

 

The number of EDP shares to be delivered to Cajastur will be based on the volume-weighted average price of EDP’s shares during the six months prior to July 28, 2004 (€2.2862 per share), adjusted for the dilution effect resulting from the rights offering. On the basis of this same price determination, we have agreed to acquire the EDP shares to be delivered to Cajastur from the Portuguese Republic. Cajastur and Cáser will retain interests aggregating to a 3.1% stake in Hidrocantábrico and, pursuant to a new shareholders’ agreement entered into on July 29, 2004 that will be effective upon completion of the acquisition, will have certain veto rights, especially in relation to certain matters relating to regional concerns, which will preserve Hidrocantábrico’s links with the region of Asturias. In addition, Cajastur will have a long-term put option entitling it to sell its interest in Hidrocantábrico to us at a price indexed to the value of our ordinary shares. Completion of the acquisition of the additional stake in Hidrocantábrico depends on completion of the rights offering, such that if the rights offering is terminated, we will not acquire this additional stake.

 

Gas

 

We also have investments, notably in gas utilities, which we regard as complementary to our core electricity business.

 

Since July 2000, we have held a 14.27% ownership interest in GALP Energia SGPS, S.A. or GALP, a holding company with interests in GDP—Gás de Portugal, SGPS, S.A., or GDP, Transgás—Sociedade Portuguesa de Gás Natural, S.A., or Transgás, companies that transport and supply natural gas throughout Portugal, and Petróleos de Portugal—Petrogal, S.A., a company involved in oil refining and distribution and the production of petroleum products.

 

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In April 2003, the Portuguese government announced recommendations concerning the reorganization of the Portuguese energy sector, in the context of which we may become a major participant in the Iberian combined gas and electricity sector. This announcement included recommendations that Portuguese gas and electricity activities be combined and developed by us in order to strengthen our position in the competitive Iberian market. In connection with the Portuguese energy sector reorganization, in March 2004 we entered into an agreement to purchase, together with Eni, S.p.A., or Eni, and REN, the entire share capital of GDP. The agreement is subject to specified conditions, including the approval of the relevant competition authorities. In addition, in November 2003, we entered into agreements giving us an option to purchase interests in Portgás—Sociedade de Distribuição de Gás, S.A., or Portgás, and Setgás—Sociedade de Produção e Distribuição de Gás, S.A., or Setgás, two of the major regional gas distribution companies in Portugal. On September 20, 2004, the Portuguese Competition Authority declared its non-opposition to the Portgás transaction, which is a condition to completion of the transaction should the option be exercised. For more information on these transactions, please see “Strategy—Iberian Energy—Developing an Iberian gas business.”

 

Our interests in the gas sector in Spain are held through Hidrocantábrico, which is the controlling shareholder in Naturcorp, the leading gas company in the Basque region of Spain. For more information on our participation in the Spanish gas sector, please see “Spain-History and Overview.”

 

Telecommunications

 

In 2000, taking into consideration our existing resources and expertise, we decided to pursue telecommunications activities.

 

Currently, ONI, SGPS, S.A., or ONI, our 56%-owned subsidiary and the holding company for our telecommunications businesses has the overall responsibility for strategic and financial matters relating to our telecommunications business segments. Pursuant to a recent reorganization, ONI’s businesses are currently focused on two main areas: wireline Portugal and wireline Spain, which areas are discussed in further detail in “Telecommunications” below.

 

Information Technology

 

We pursue the information technology business through our wholly owned subsidiary EDINFOR, which holds a 57.77% interest in ACE—Holding SGPS, S.A., or ACE. ACE owns 100% of CASE—Concepção e Arquitectura de Soluções Informáticas Estruturadas, S.A., or CASE. CASE provides consulting and information systems services to us and to third parties. On September 30, we announced our intention to enter into exclusive negotiations with LogicaCMG a view to entering into a strategic partnership involving the sale of 60% of EDINFOR’s share capital. See “Strategy—Information Technology” below for more information on these negotiations.

 

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Group capital expenditures and investments

 

The following table sets forth our capital expenditures and investments for the years 2001 through 2003 and the first half of 2004, divided into operating investment and financial investment. Operating investment generally refers to the development and acquisition of fixed assets and financial investment generally refers to the acquisition of equity interests in companies.

 

     Year ended December 31,

  

Six months
ended

June 30,

2004


     2001

   2002

   2003

  
     (audited)    (unaudited)
     (thousands of EUR)

OPERATING INVESTMENT:

                   

Energy:

                   

Portugal:

                   

Generation:

                   

Thermal/Hydro

   109,646    204,979    213,851    91,939

Renewable: wind

   6,574    11,397    38,533    31,410

Renewable: biomass(1)

   0    35,205    922    28

Cogeneration

   13,142    9,618    33    22

Engineering and Operations and Maintenance(2)

   2,371    15,264    7,809    1,368
    
  
  
  

Total Generation

   131,733    276,463    261,148    124,767

Distribution:(3)

                   

Investment, net of subsidies

   181,938    241,551    263,056    117,929

IT Systems (transfer from EDINFOR to EDPD)

   0    80,547    11,974    0

Subsidies in kind (assets)

   69,533    54,095    61,039    31,083

Subsidies in cash

   78,490    56,853    59,714    34,619
    
  
  
  

Total Distribution

   329,961    433,046    395,783    183,630

Supply(4)

   980    8,337    6,218    1,629

Total technical costs

   462,674    717,846    663,148    310,026

Financial costs capitalized

   15,867    15,361    24,005    11,404
    
  
  
  

Total Portugal

   478,541    733,208    687,153    321,429

Spain:

                   

Hidrocantábrico(5)

   0    84,775    70,528    53,780
    
  
  
  

Total Spain

   0    84,775    70,528    53,780
    
  
  
  

Total Energy Portugal and Spain

   478,541    817,983    757,681    375,209

Brazil:

                   

Generation

   40,836    55,600    58,676    85,931

Distribution:

                   

Bandeirante

   47,226    25,413    39,392    12,462

Escelsa

   0    16,208    18,639    7,305

Enersul

   0    25,152    16,184    7,862

EDP Brazil

   1,608    261    415    402
    
  
  
  

Total Brazil

   89,670    122,634    133,306    113,962

Telecommunications(6) and Information Technology:

                   

Telecommunications

   239,019    311,962    28,564    13,541

Information Technology

   70,977    41,833    58,784    7,344
    
  
  
  

Total Telecommunications and Information Technology

   309,996    353,795    87,348    20,884

Other:

                   

Other Operating Investment(7)

   29,530    45,362    24,939    5,029
    
  
  
  

TOTAL OPERATING INVESTMENT

   907,737    1,339,773    1,003,274    515,084

 

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     Year ended December 31,

  

Six months
ended

June 30,

2004


     2001

   2002

   2003

  
     (audited)    (unaudited)
     (thousands of EUR)

FINANCIAL INVESTMENT:

                   

Energy:

                   

Portugal:

                   

Acquisition of additional 10% shareholding in Turbogás

   0    20,986    0    0

Spain:

                   

Acquisition of Naturcorp by Hidrocantábrico(8)

   0    0    100,235    0

Acquisition of Hidrocantábrico by EDP(9)

   262,388    520,591    0     

Brazil:

                   

Acquisition of share capital of IVEN (Escelsa/Enersul)

   209,011    0    0    0
    
  
  
  

Total Energy

   471,399    541,577    100,235    0

Telecommunications:

                   

Acquisition of Comunitel by ONI

   69,554    0    0    3,649
    
  
  
  

Total Telecommunications

   69,554    0    0    3,649

Other:

                   

Subscription to BCP rights issue and capital increase

   0    30,636    40,599    0

Acquisition of Escelsa notes(10)

   0    379,964    0     

Other financial investments

   12,328    15,718    40,926    5,709
    
  
  
  

Total Other

   12,328    426,318    81,525    5,709
    
  
  
  

TOTAL FINANCIAL INVESTMENT

   553,281    967,896    181,760    9,358
    
  
  
  

TOTAL CAPITAL EXPENDITURES AND INVESTMENTS

   1,461,018    2,307,669    1,185,034    524,442

(1) Renewable—biomass investment in 2002 includes €35.2 million relating to an internal transfer of the Mortágua biomass power plant, from EDP, S.A. to EDP Produção Bioeléctrica. As such, this did not affect our cash flow in 2002.
(2) In 2001, expenditures in engineering and operations and maintenance (or O&M) include the expenditures made by Tergen, HidrOeM and EDP Produção, which companies were created in 2001.
(3) Distribution includes capital expenditures of EDPD.
(4) Supply comprises the capital expenditures of EDP Energia, our company operating in the liberalized market.
(5) Investment represents 40% of Hidrocantábrico’s operational investments, as we proportionally consolidate our 39.5% interest in Hidrocantábrico at the 40% level.
(6) Investments for telecommunications include primarily infrastructure.
(7) Other Operating Investment includes investments by the EDP Group in installations and equipment at the holding company level, investments by our real estate companies and investments by our support services companies.
(8) Investment represents 40% of Hidrocantábrico’s financial investments in the acquisition of Naturcorp, as we proportionally consolidate our 39.5% interest in Hidrocantábrico at the 40% level.
(9 Total investment in the acquisition of 39.5% of Hidrocantábrico (which we proportionally consolidate at the 40% level) amounts to €782.9 million, of which €262.4 million was invested in 2001.
(10) In 2002, we acquired certain notes issued by Escelsa. For more information on this transaction, please see “Item 11. Quantitative and Qualitative Disclosures About Market Risk” in our 2003 20-F.

 

Total capital expenditures and investments of €1,185.0 million in 2003 represented a 48.6% decrease from total capital expenditures and investments of €2,307.7 million in 2002. This decrease was primarily due to lower financial investments in 2003 compared to 2002. In 2002, we finalized the acquisition of our 39.5% stake in Hidrocantábrico in the amount of €782.9 million, of which €262.4 million was paid in 2001 and €520.6 million in 2002. In addition, in 2002 we also acquired part of Escelsa’s notes issued in U.S. dollars for the total amount of €380 million. Having reduced the exchange rate risk relating to U.S. dollar debt of our Brazilian subsidiaries, we did not enter into any further debt acquisition programs in 2003. The decrease in total capital expenditures and investments from 2002 to 2003 was also due to a lower level of operational investments in 2003. In Portugal,

 

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we made lower operating investments in our distribution business in 2003, reflecting the internal transfer from EDINFOR to EDPD of a commercial and administrative information technology system in 2002, and overall investments in generation were lower as a result of the internal transfer in 2002, from EDP to EDP Produção Bioeléctrica, of the investment made in 1999 related to the Mortágua biomass power plant, which does not represent a cash outflow, but was included in our 2002 capital expenditures and investments. Additionally, we had lower expenditures in telecommunications in 2003, as a result of the divestment of our UMTS business.

 

We expect total operational investments in 2004 to be approximately €1,200 million, concentrated mainly in generation and distribution.

 

The capital expenditures set forth above have not been adjusted to reflect the fact that certain expenditures represent transfers between businesses within the EDP Group of assets that had previously been accounted for by the transferors as their own capital expenditures. The capital expenditures above have also not been adjusted for divestments of certain financial investments. Adjusting for these transactions would result in the following:

 

     Year ended December 31,

   

June 30,

2004


 
     2001

    2002

    2003

   
     (audited)     (unaudited)  
     (thousands of EUR)  

Total Capital Expenditures and Investments:

   1,461,018     2,307,669     1,185,034     524,442  
    

 

 

 

Internal Transfers:

                        

IT Systems (from EDINFOR to EDPD)

         (80,547 )   (11,974 )      

Mortágua Biomass Power Plant (from EDP, S.A. to EDP Produção Bioeléctrica)

         (35,180 )            

Divestments:

                        

ESSEL

   (77,800 )                  

Redal

         (26,905 )            

Optep (Optimus)

         (315,000 )            

Iberdrola, S.A.

               (400,102 )      

Oni Way

                     (61,449 )
    

 

 

 

Total Internal Transfers and Divestments

   (77,800 )   (457,632 )   (412,076 )   (61,449 )
    

 

 

 

Adjusted Total Capital Expenditures and Investments

   1,383,218     1,850,037     772,958     462,993  
    

 

 

 

 

In recent years, a significant part of our capital expenditures on electricity projects in mainland Portugal has been in distribution. Since EDPD is required by law to connect all customers who wish to be supplied by the PES, a large part of capital expenditures is spent in connecting new customers, improving network efficiency and developing the network (installing new cables and lines) to accommodate the growth in consumption. In addition, we are required to meet government standards for meter control, which requires us to make further investments in new meters. Our investment in distribution in Portugal in 2003 totaled €395.8 million compared with €433.0 million in 2002 and €330.0 million in 2001, and mainly consisted of recurring capital expenditures necessary for the operation, improvement and expansion of our distribution network in Portugal, including expansion to accommodate growth in consumption and maintenance. In keeping with our strategic goal of reducing recurring capital expenditures in our core electricity business, capital expenditures in distribution declined between 1998 and 2000 due to lower costs in materials and services and a reduced allocation of these costs to capital expenditures. Between 2000 and 2003, EDPD’s capital expenditures increased due to higher investments in the distribution network pursuant to our public commitment to improve the quality of service by reducing the equivalent interruption time in the distribution of electricity. In 2002, the increase in EDPD capital expenditures also reflects the internal transfer from EDINFOR to EDPD of €80.5 million worth of assets that relate to non-recurring investments made in a commercial and administrative information technology system based on the SAP platform. In 2003, EDPD capital expenditures also included €12.0 million related to the transfer of this information technology system. As such, this transfer did not affect our cash flow in 2002 and 2003.

 

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Under current regulations in Portugal, EDPD receives contributions directly from customers for a portion of its capital expenditures for new connections to the transmission and distribution networks. The total amount of contributions from customers in 2003 was approximately €121 million compared with approximately €111 million in 2002.

 

During 2003, we invested €261.1 million in generation in Portugal, compared with €276.5 million in 2002 and €131.7 million in 2001. The higher capital expenditures in 2003 and 2002 compared to 2001 were primarily a result of expenses incurred due to the start of construction of the first two 392 MW units of the TER CCGT plant and of the two 94 MW units of the Venda Nova hydroelectric plant. We expect a similar level of operational investment in generation in Portugal in 2004.

 

In Portugal, we expect to focus future distribution capital expenditures on connecting new clients and improving the quality of the electricity service through a more efficient network. We expect to concentrate future generation capital expenditures on the development of new hydroelectric projects and in the construction of the new TER CCGT power plant. Future capital expenditures in generation may also include special projects such as co-generation and wind power generation opportunities. While the actual amount of our future investments will depend on factors that cannot be currently foreseen, we expect to incur recurring capital expenditures of approximately €700 million annually until 2006 in the aggregate in our core electricity generation and distribution businesses in Portugal during this period.

 

In Spain, apart from the capital expenditure of €250.6 million (our proportional share of this expenditure being €100.2 million) for the acquisition of Hidrocantábrico’s 62% stake in Naturcorp, additional capital expenditures of €176.3 million were incurred (our proportional share of this expenditure being €70.5 million) during 2003 on generation, electricity distribution and on special regime generation projects. Hidrocantábrico’s 2003 operational investments decreased compared to 2002, due to lower investments in generation and electricity distribution activities. Investments in generation decreased due to the completion of the Castejón CCGT plant in September 2002. As for electricity distribution activity, fewer investments were made in expansion outside Asturias (northern region of Spain). Investment in special regime generation increased in 2003 with the construction of the P.E. del Cantábrico (65 MW), the P.E. Arlanzón (34 MW) and the P.E. Albacete (124 MW) wind farms.

 

In line with our strategic objectives of building our fixed line telecommunications and our international activities, we also may incur additional capital expenditures in connection with these activities and other strategic investments as well as non-recurring capital expenditures such as for information technology. With respect to investments in Brazil, we currently expect to fund any future capital expenditures with cash flow generated by local operations and or by reais-denominated debt.

 

We made capital expenditures related to environmental matters in 2003 and 2002 of approximately €15 million. We expect these capital expenditures to amount to approximately €40 million in 2004, of which €20 million will be related to new investments in emissions abatement equipment in the Sines power plant, in order to adapt the facility to the new environmental regulations relating to SO2 and NOx emissions.

 

Over the next three years, we expect to incur capital expenditures of approximately €3.25 billion, more than 75% of which will be dedicated to the expansion of electricity generation facilities in Portugal and Spain, including renewable energy facilities, and the improvement of the quality of our electricity distribution network in Portugal.

 

We believe that cash generated from operations and existing credit facilities is sufficient to meet present working capital needs. We currently expect that our planned capital expenditures and investments will be financed from internally generated funds, existing credit facilities and customer contributions, which may be complemented with medium- or long term debt financing and equity financing as additional capital expenditure

 

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and financial investment requirements develop. To learn more about our sources of funds and how the availability of those sources could be affected, see “Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

 

International Investments

 

Apart from Spain, we have made a number of international investments in the electricity and water sectors in Brazil, Cape Verde, Guatemala and Macau. In accordance with our strategy of shareholder value creation, we have divested in non-strategic holdings in Chile and Morocco. We have also reorganized our shareholding in CEM—Companhia de Electricidade de Macau, or CEM. As a result, China Power International Holding, a Chinese electricity company, has acquired a 6% interest in CEM and our stake in CEM has decreased slightly, from 21.78% to 21.19%. For more information on CEM and this transaction, please see “Other Investments and International Activities” below.

 

STRATEGY

 

Our principal strategic objective is the creation of shareholder value through the achievement of sustained real earnings growth and our primary strategic focus is on consolidating and expanding our position in energy activities in the Iberian Peninsula. Accordingly, we have redefined our concept of our domestic market to include the Iberian Peninsula and are positioning ourselves for the Iberian electricity market that will develop in the future, particularly following the implementation of MIBEL, which is expected to begin operating by June 30, 2005. In this context, we acquired operating control of Hidrocantábrico in 2001, the fourth largest electricity operator in Spain, which, in turn, acquired Naturcorp, the second largest gas operator in Spain, in 2003, and we plan to use the proceeds of this offering to increase our holdings in Hidrocantábrico to 95.7%. See “Use of Proceeds” and “Information on the Company—Overview—Electricity.”

 

While expanding into the Spanish gas and electricity sectors, we are also strengthening our core electricity and gas business in Portugal. During recent years, we have been making considerable efforts to optimize and restructure our Portuguese generation and distribution activities in preparation for the full liberalization of electricity supply in Portugal and the expected integration of the Portuguese and Spanish electricity markets. In connection with these efforts, we are taking steps to improve the quality of service through cost-conscious investment in technical and commercial infrastructure, particularly in the areas of electricity distribution and sales, and further restructure our human resources, primarily in our distribution business. In this regard, we have had and continue to have programs in place that are aimed at reducing our headcount and we intend to expand our sales and customer service human resource capabilities. We are also increasing our electricity generation capacity through modernization of existing facilities and selective development of new facilities, in each case mindful of environmental requirements and concerns.

 

Outside of our Iberian energy activities, we have also sought to focus on our core business through divestiture of non-strategic financial investments, as demonstrated by our sale in 2003 of our 3% stake in the Spanish electricity company Iberdrola, and to selectively pursue other business activities that are complementary to our energy activities. These other business activities include selectively pursuing international opportunities in electricity, developing our telecommunications business in Portugal and Spain, and restructuring our information technology business.

 

Iberian Energy

 

Our primary strategic focus is the Iberian energy market, where we are consolidating our position as a leading energy company. We are the leading electricity company in Portugal. We also intend to develop activities in the Portuguese gas sector by translating our financial investment in GALP into a controlling stake in GDP. In Spain, we currently exercise operating control over Hidrocantábrico. Hidrocantábrico acquired a 62% stake of Naturcorp in March 2003 and currently has a 56.8% stake in Naturcorp after Gas Natural exchanged its 20.5% interest in Gas de Euskadi, a subsidiary of Naturcorp, for a direct interest in Naturcorp. Following completion of the rights offering and the application of its proceeds as described above in “Use of Proceeds” and “Information on the Company—Overview—Electricity,” our stake in Hidrocantábrico will be 95.7%.

 

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In the Iberian energy market our strategic objectives are:

 

  preserving the value of our business in the Portuguese energy sector in light of the liberalization of the Portuguese electricity market and the creation of an integrated Iberian market;

 

  growing our electricity Iberian platform through Hidrocantábrico; and

 

  developing an Iberian gas business by leveraging our existing assets.

 

Preserving the Value of our Business in the Portuguese Energy Sector

 

In the Portuguese energy sector, we face increasing competition arising from the liberalization of the electricity market in Portugal, in the Iberian Peninsula and throughout the European Union. On August 18, 2004, the electricity market in Portugal was fully liberalized and all customers, including all low-voltage customers, became free to choose their electricity supplier. Competition in electricity supply will also increase as the newly created Iberian electricity market comes into operation. Additionally, we face increasing pressure on the operating margins of our electricity distribution business in Portugal due to regulation of electricity tariffs in the PES.

 

In response to these challenges, we plan to:

 

  continue efforts to enhance earnings and maintain our leading market share of generation and distribution in the liberalized and growing Portuguese electricity market, while also capitalizing on growth opportunities created by increasing liberalization within the EU, particularly in the Iberian electricity market; and

 

  continue our program to increase the efficiency of our operations in the Portuguese energy sector, reduce related costs with the goal of achieving international best practice standards, and minimize the impact of tariff reductions in the current regulatory period on operating margins of our electricity distribution business.

 

In pursuing these objectives, we intend to:

 

  pursue effective marketing to both new and existing customers, particularly those that benefit, or will benefit, from competitive alternatives in the Non-Binding Sector (where we are present through our subsidiary EDP Energia);

 

  continue to provide high-quality and cost-effective services to the Binding Sector and the Non-Binding Sector;

 

  further centralize our corporate structure, as we have done with the merger of our four distribution companies into EDPD and the centralization of most of our generation companies in EDP Produção;

 

  continue to centralize and improve the efficiency of our administrative activities, such as accounting, and procurement, with the aim of achieving cost savings in supplies of goods and services and personnel reduction, to which end we created EDP Valor, a company that integrates some of our service companies by consolidating resources and centralizing purchasing activities;

 

  identify opportunities to achieve future reductions in overhead expenses through the continued implementation of the “Efficiency Program” started in the beginning of 2002, in connection with which we have agreed with the Portuguese electricity regulator on an appropriate tariff mechanism that can facilitate further efficiency improvements through personnel reduction at EDPD; and

 

  continue to monitor the level of recurring capital expenditures in our Portuguese electricity business.

 

On October 26, 2004, we signed a call option agreement with International Power Plc, or IPR, and National Power International Holdings BV, or IPBV, for the purchase of a 20% shareholding and related shareholder loans in Turbogás-Produtora Energética, S.A., or Turbogás, and of a 26.667% shareholding and related shareholder loans in Portugen-Energia, S.A., or Portugen.

 

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The option is exercisable during a nine-month period commencing on the business day following the completion date of a sale and purchase agreement entered into by IPR, IPBV and RWE POWER AG, or RWE, in relation to the acquisition of a stake in Turbogás and Portugen, or during a term beginning on January 1, 2008 and ending on December 31, 2009. The option’s reference price is €55,667,350.00, which was determined based on the value of this sale and purchase and is subject to a price adjustment mechanism in order to reflect changes in assets and liabilities, which adjustment may occur until the exercise date of the call option. As part of the agreement, we have waived our pre-emptive right to acquire a 75% stake in Turbogás. In accordance with a notice served to EDP on October 4, 2004, all the shareholdings in Turbogás and Portugen currently held by RWE will be transferred to IPBV in completion of the share purchase agreement entered into between those companies.

 

In addition, we have also reached an agreement with IPR and IPBV regarding our possible involvement in the management of Tapada do Outeiro’s power output in the event that the current PPA of Tapada do Outeiro is terminated, with any such arrangement being subject to non-opposition by the relevant competition authority.

 

Both our purchase of the shareholdings in Turbogás and Portugen and the related shareholder loans and the possibility of our managing Tapada do Outeiro’s electricity output are subject to certain required approvals for their completion.

 

Growing our Iberian Electricity Platform

 

In light of the intended integration of the Spanish and Portuguese electricity sectors, we have expanded the definition of our domestic market to embrace the entire Iberian Peninsula. We are the first Iberian company to have significant generation and distribution assets, as well as a meaningful customer base in both Portugal and Spain—two EU countries with among the highest electricity consumption growth rates in the European Union.

 

To grow our Iberian electricity platform, we intend to:

 

  increase our stake in Hidrocantábrico through the acquisition of an additional 56.2% interest in that company, thereby bringing our total interest in it to 95.7%, with the aim of enhancing management flexibility and realizing further synergies between its operations and our existing ones;

 

  position ourselves to benefit from the creation of an Iberian electricity market and pursue growth opportunities in Spain by leveraging on our investment in Hidrocantábrico;

 

  grow our customer base by capitalizing on the fully liberalized electricity market in Spain;

 

  take advantage of a combined electricity and gas service offering in Spain through the activities of both Hidrocantábrico and Naturcorp and in Portugal through the activities of EDP and GDP; and

 

  increase generation capacity through the construction of a new CCGT power plant, the development of renewable energy generation projects, primarily through the construction or acquisition of new wind farms, and the increase of capacity in existing plants to cope with strong consumption growth.

 

Developing an Iberian Gas Business

 

We view the gas business as being highly complementary to electricity and of great strategic attractiveness. Both Portugal and Spain have gas and electricity consumption growth rates above the EU average. Each country requires new capacity to be gradually added and CCGT plants, fired by gas, are considered to be an advantageous option to meet the Iberian electricity system expansion requirements because of their lower investment costs required per MW, greater efficiency, lower operating and maintenance costs and lower emission levels compared to other thermal generation plants.

 

Since new gas-fired generation capacity is expected to be added to the Iberian electricity system, power generators, which are already among the largest gas consumers in the Iberian Peninsula, are and will continue to be the facilitators of the development and sustainability of the gas business in the Iberian Peninsula, although their competitive position will increasingly depend on gas prices and the flexibility of gas contracts. The natural

 

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gas market is characterized by the existence of long-term contracts. For electricity generators, long-term contracts in the natural gas market are usually indexed to the price of oil, are of a take-or-pay nature and restrict the final destination of contracted gas. Since gas represents a substantial portion of gas-fired power plants’ total costs, access to flexible and competitive gas contracts is of paramount importance to increase the efficiency of CCGT power plants.

 

There are two main reasons for us to develop an integrated Iberian gas business:

 

  to increase the competitiveness and efficiency of our gas-fired power plants. By being involved in both gas distribution and electricity generation we expect to be able to mitigate the risk presented by variable gas prices while increasing the flexibility of gas sourcing and placing; and

 

  to capture synergies from distributing both gas and electricity to final consumers, leveraging on our existing electricity client base and on the sharing of infrastructure and system costs.

 

Although we already have a significant position in the gas sector in Spain, our having a significant position in the Portuguese gas sector depends on the closing of the acquisition provided for in the agreement we entered in March 2004 to purchase, together with Eni and REN, the entire share capital of GDP, which operates in the Portuguese gas sector and owns assets for the transport and distribution of gas. The completion of the agreement and related transactions is subject to specified conditions, including approval of the relevant competition authorities, which has been requested and in connection with which the EU Commission has decided to initiate proceedings under article 6.1(c) of Commercial Regulation (EC) no. 139/2004 of January 20, 2004 on the control of concentrations between undertakings. Pursuant to this agreement, initially we, Eni and REN will hold 33.34%, 33.33% and 33.33%, respectively, of GDP’s share capital, although REN will only participate in GDP on a temporary basis. The agreement provides that the cost of the stake of each buyer will be €400 million. In connection with the purchase agreement, we also entered into a shareholders’ agreement with Eni and REN that provides rules for the temporary governance of GDP (until the exit of REN) and the mechanism by which REN will exchange its stake in GDP for GDP’s high pressure gas network assets. Following the exit of REN, we and Eni will own 51% and 49% of GDP, respectively. Accordingly, we also entered into a shareholders’ agreement with Eni that will govern the management of GDP following the exit of REN and includes the terms of collaboration between Eni and us and the exit clauses in the case of a deadlock event that cannot be resolved. In the case of a deadlock, we will have a call option over Eni’s stake in GDP. If we do not exercise this call option within the time specified in the agreement, Eni will have a call option over our stake in GDP. As we intend to leverage our stake in GALP to acquire our position in GDP and focus on the gas business rather than oil-related activities, we also agreed with Parpública—Participações Públicas, S.G.P.S., S.A. (formally known as Partest), or Parpública, on a mechanism for us to exit the share capital of GALP. Pursuant to this agreement, Parpública has a call option to acquire our 14.27% stake in GALP for €456.7 million and we have a put option to sell our stake in GALP to Parpública on the same terms. Parpública’s call option may be exercised from March 31, 2004 until one year after acquisition of the GDP shares by EDP, Eni and REN. Our put option may be exercised during the 3-month period after the expiration of the period for the exercise of Parpública’s call option.

 

We have also entered into agreements to acquire stakes in two of the main Portuguese regional gas distribution companies: Portgás and Setgás. Portgás has the concession to distribute gas in the districts of Porto, Braga and Viana do Castelo. We have entered into a call option agreement with GALP, GDP and GDP Distribuição, SGPS, S.A. to acquire a 46.265% shareholding in Portgás. We may exercise this option for 18 months from November 2003 by paying €86,400,000, subject to adjustments for variations in share capital and shareholder loans. At the same time, we entered into a call option agreement with CGD to acquire all of the shares of NQF—Projectos de Telecomunicações e Energia, S.A., or NQF, which owns 12.9% of Portgás and 10.1% of Setgás. Under the same agreement, we have granted to CGD a put option pursuant to which CGD may sell the NQF shares to us. The put option provides for a purchase price of €64,942,880.57 and was initially exercisable at any time between June 15, 2004 and September 15, 2004, although the exercise period was subsequently extended to November 30, 2004. Completion of the transaction involving Portgás is subject, among other things, to approval by the Portuguese Competition Authority, which was received on September 20, 2004, though as of the date of this prospectus supplement, none of the parties had exercised its option.

 

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Our current interest in the gas sector in Spain consists of our 39.5% holding in Hidrocantábrico, which controls Naturcorp, with more than 500,000 customers and approximately 10% of Spain’s regulated revenues for gas distribution, or 8% of gas distributed in Spain in terms of GWh.

 

Following completion of the rights offering and application of its proceeds as described in “Use of Proceeds” and “Information on the Company—Overview—Electricity,” our stake in Hidrocantábrico will be 95.7%.

 

International Activities

 

Although our core business has historically been electricity in Portugal, it has evolved to include the Iberian energy market. However, international opportunities arise in the electricity business and related businesses through which we believe we can achieve attractive returns. In international investments, we have looked particularly toward Brazil, where we believe we can play an active role in managing the electricity operations in which we are involved and where potential returns may be attractive. During the first half of 2003, we reassessed our Brazil strategy and are undertaking the following initiatives with the goal of rationalizing our Brazilian operations by making them more self-sustaining and independently managed:

 

  corporate restructuring: integration of all activities in Brazil under our subsidiary, EDP Brazil, which will consolidate not only financial results but also planning and strategic control;

 

  capital restructuring: assessment of the capital structure of EDP Brazil and its subsidiaries;

 

  corporate governance: harmonization and alignment of the corporate governance structures and procedures of EDP Brazil’s subsidiaries, with a view toward improving the efficiency and transparency of governance and the decision-making process;

 

  strategic positioning: introduction of the necessary adjustments to our existing investments with the aim at obtaining greater added value for shareholders and the establishment of strategic platforms for the development of future businesses; and

 

  generation of synergies: ensuring that EDP Brazil is worth more than the sum of its parts, thus providing adequate remuneration of capital employed, through initiatives such as the re-launch of an efficiency program and analysis of the feasibility of shared services.

 

We regularly review our international investments and may change their focus over time consistent with our strategic objectives. In this regard, we continuously monitor our investment portfolio in order to capitalize on our ability to efficiently manage electricity operations through significant influence or control. For a more detailed discussion of our international activities, you should read “Brazil” and “Other International Activities and Strategic Investments” below.

 

Telecommunications

 

Our telecommunications activities are conducted through ONI, our telecommunications subsidiary comprised of various business units. ONI is a fixed line telecommunications operator primarily focused on corporate clients and provides voice and data services in Portugal and Spain.

 

We plan to build on our existing operations in order to achieve a competitive role in the corporate fixed line telecommunications sector in Portugal and Spain, which we regard as attractive markets of suitable size and high growth potential.

 

Although our plans and strategy continue to evolve and adapt to trends in the telecommunications sector, we currently anticipate emphasizing the following business areas:

 

  fixed line operations, using ONI’s fixed line voice and data operations as a platform; and

 

  Internet access services, building on ONI’s Internet service provider activities.

 

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For a more detailed discussion of our telecommunications activities, please see “Telecommunications” below.

 

Information Technology

 

We are involved in the information technology market mainly through EDINFOR. During the second half of 2003, and following a decision to allow participation of a strategic partner in EDINFOR’s share capital, we have been implementing several initiatives that should facilitate the success of a future partnership. Such initiatives include concentrating on the improvement of the relationship with the EDP Group, the increase of sales outside the EDP Group and the winding up and/or merger of 17 companies within the EDINFOR group. In 2004, we hope to find a strategic partner for EDINFOR that will bring to EDINFOR technological expertise. To this end, on September 30, we announced our intention to enter into exclusive negotiations with LogicaCMG with a view to entering into a strategic partnership involving the sale of 60% of EDINFOR’s share capital. We expect this transaction to involve the renegotiation of our existing contracts with EDINFOR in order to ensure that we have access at competitive prices to the best international practices in the field of information technology and to ensure that our core information technology systems continue to be run by EDINFOR, while benefitting from the worldwide positioning of LogicaCMG. With such a partnership in place, we expect to be better able to focus on our core business, while maintaining the availability and security of key systems, and enhancing EDINFOR’s growth potential.

 

Development of Complementary Business Activities/Other Utilities

 

Consistent with our strategy, we are selectively evaluating opportunities that are complementary to our core businesses and that may enable us to achieve cost savings along the chain of activities from us to the consumer and that management expects can generate additional shareholder value.

 

For more information on our complementary business activities you should read “Subsidiaries, Affiliates and Associated Companies” below.

 

THE IBERIAN ELECTRICITY MARKET

 

In November 2001, the Portuguese and Spanish governments signed a “Protocol for Cooperation between the Spanish and Portuguese governments for the creation of the Iberian Electricity Market,” or the Protocol, in which they undertook to create an Iberian electricity market based on the principles of free and fair competition, transparency, objectivity and efficiency. In particular, the Protocol was intended to guarantee Portuguese and Spanish consumers better access to domestic and foreign electricity networks and give Iberian electricity operators the freedom to contract with consumers and to engage in distribution activities in a common Iberian electricity pool. After several delays in the process, the international agreement executed in January 2004 between the Portuguese and the Spanish governments provided for the beginning of MIBEL by April 20, 2004, although this did not occur. Pursuant to a new agreement (which has not yet been made public) signed by the Portuguese and Spanish governments at the Iberian Summit at Santiago de Compostela on October 1, 2004, it is expected that MIBEL will begin operating by June 30, 2005.

 

In 2003, total generation in Iberia amounted to approximately 227.4 TWh in the ordinary regime, of which EDP and Hidrocantábrico were responsible for approximately 41.8 TWh, which represents an 18% market share.

 

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PORTUGAL

 

Electricity System Overview

 

Portuguese Electricity System

 

Since 1997, Portugal has had an electricity market structured pursuant to the legislation enacted by the government that introduced the National Electricity System. The chart below illustrates the structure of the National Electricity System.

 

LOGO


Note: Operations that are 100%-owned by us are highlighted in bold.

 

(1) We own 10% of Tejo Energia and 20% of Turbogás.
(2) Began operations in early 1998.
(3) As of September 30, 2004, none existed.
(4) At the end of January 2004, approximately 21,300 potential Qualifying Consumers, or “Eligible Consumers,” existed, of which 2,714 had become Qualifying Consumers and 2,028 were already in the Non-Binding Sector. Prior to February 2004, all consumers except low-voltage consumers were Eligible Consumers. Decree law no. 36/2004 of February 26, 2004 provided for the decrease of the eligibility threshold in mainland Portugal to include special low-voltage consumers, which are those with subscribed demands above 41.4 KW and voltage levels below 1kV. Decree law no. 192/2004 of August 17, 2004 subsequently provided for the full liberalization of the electricity market through the decrease of the eligibility threshold in mainland Portugal to include all low-voltage customers.

 

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The National Electricity System consists of the PES, or the Binding Sector, and the Independent Electricity System. The PES is responsible for ensuring the security of electricity supply within Portugal and is obligated to supply electricity to any consumer who requests it. Within the Independent Electricity System are the Non-Binding Sector and other independent producers (including auto producers). We and other generators can supply electricity to the Non-Binding Sector. The Non-Binding Sector is a market-based system that permits “Qualifying Consumers” to choose their electricity supplier. Over the past several years the minimum consumption level required to be a Qualifying Consumer has progressively declined and Decree law no. 192/2004 of August 17, 2004 provided for the full liberalization of the electricity market through the decrease of the eligibility threshold in mainland Portugal to include all low-voltage customers. For more information on the liberalization of electricity sales you should read “Competition” below.

 

In the context of the liberalization of the Portuguese electricity sector, the creation of MIBEL and the termination of PPAs, we expect the structure of the National Electricity System to be significantly altered in the near future. For further information on the termination of the PPAs, see “Risk Factors—Risks Related to Our Core Electricity Business—The current and future legislation contemplating the early termination of the PPAs could eventually adversely affect our revenues.”

 

The Public Electricity System or Binding Sector

 

The PES, or the Binding Sector, includes the binding generation in our generation company, CPPE, the transmission company, REN, in which we have a 30% stake, and our distribution company, EDPD. The PES also includes two independent power producers: Tejo Energia’s plant at Pego, in which we have a 10% stake, and the Turbogás plant at Tapada do Outeiro, in which we have a 20% stake. All plants in the PES enter into PPAs with REN through which they commit to provide electricity exclusively to the PES through REN, acting as the single buyer in the Binding Sector and operator of the national transmission grid. For more information on REN’s activities, you should read “Transmission” below.

 

Power plants in the Binding Sector are each subject to binding licenses issued by the Direcção Geral de Geologia e Energia, or DGGE, which has succeeded the Direcção Geral de Energia, or DGE, that are valid for a fixed term, ranging from a minimum of 15 years to a maximum of 75 years, but which would be revoked upon termination of the related PPAs with REN. These licenses, together with PPAs, require each power plant in the Binding Sector to generate electricity exclusively for the PES.

 

While REN’s responsibilities relate primarily to the transmission of electricity and system dispatch, it is also responsible for working with DGGE to identify potential sites for the installation of new power plants and for the management of wholesale purchases of electricity and sales to distribution companies.

 

The Independent Electricity System

 

The Independent Electricity System consists of two parts—the Non-Binding Sector and the other independent producers, including renewable source producers, which include small hydroelectric producers (under 10 MW installed capacity), and cogenerators.

 

The Non-Binding Sector

 

At present, the only producers in the Non-Binding Sector are our three wholly-owned embedded hydroelectric generators, which are small hydroelectric plants with more than 10MW installed capacity that deliver all of the energy they produce directly to the distribution system, and CPPE’s CCGT plant in Ribatejo. Although producers in the Non-Binding Sector are required to obtain licenses, they have no obligation to supply electricity to the PES. These entities are free to contract directly with Qualifying Consumers. In 2003, the total number of Eligible Consumers in Portugal represented approximately 45% of total demand in mainland Portugal in volume terms. During 2003, 1,430 Eligible Consumers exercised their right to become Qualifying Consumers, of which 1,054 entered into contracts with EDP Energia and 376 entered into contracts with producers in the Spanish market. Of the 1,919 existing Qualifying Consumers at the end of 2003, 1,404 are customers of EDP

 

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Energia, representing approximately 7% of the electricity sold by us and 3% of our revenues in 2003. As of December 31, 2003, approximately 21,300 Eligible Consumers existed and 1,919 of these had opted to become Qualifying Consumers. On August 18, 2004, the electricity market in Portugal was fully liberalized through the decrease of the eligibility threshold in mainland Portugal to include all low-voltage customers. We expect a limited impact on our revenues due to this final step in the progressive elimination of the eligibility threshold. Two of the three tariff components relating to distribution, representing approximately 90% of tariff revenue in 2003, are payable to EDPD by Eligible Consumers electing to become Qualifying Consumers. In addition, EDP Energia has the opportunity to gain Qualifying Consumers as its customers, in which case the third distribution tariff component would be payable to EDP Energia.

 

Producers in the Non-Binding Sector are able to use the national transmission grid and distribution system on an open-access basis to connect to Qualifying Consumers, which pay regulated transmission and distribution charges to REN for transmission and EDPD or other companies for distribution, respectively. Our hydroelectric plants in the Independent Electricity Systems deliver all of the electricity they produce directly to the distribution system without going through the national transmission grid. Contractual relationships between producers and consumers in the Non-Binding Sector are freely negotiable between the parties.

 

Other Independent Producers

 

The Portuguese government has implemented selected measures to encourage the development of various forms of electricity production, including auto producers (entities that generate electricity for their own use and may sell surplus electricity to REN), cogenerators, small hydroelectric producers and other producers using renewable sources. REN is currently required by law to purchase the excess electricity produced by these independent producers at a regulated price based on avoidable costs, defined as the costs REN avoids by receiving power from these producers rather than dispatching plants in the Binding Sector and/or investing in new plants to increase installed capacity, plus an environmental premium, referred to as the “green tariff.” For more information on our electricity sales, you should read “Distribution” below.

 

Size and Composition of Portugal’s Electricity Market

 

During the period from 2001 through 2003, the total electricity supplied by EDPD (in both the Binding and Non-Binding Electricity Sectors) experienced an average growth rate of 3.9% per annum. In 2002, there was a reduction in the annual growth rate to 2.4% due to a slowdown in the economy. In 2003, the annual growth rate increased to 5.4%.

 

The primary factors that management believes have an impact on demand are the rate of GDP growth, electricity connections to new households and changes in electricity consumption per capita. We anticipate that the Portuguese economy will recover and that overall consumption in the National Electricity System will increase at an average of 3.7% per year in 2004, 2005 and 2006. Residential consumption is assumed to increase each year over the same period by an average of 4.5%, services by an average of 2.8%, and industrial by an average of 2.9%.

 

Peak demand as a percentage of the total installed capacity, which is the sum of the total installed capacity of the PES, and the total installed capacity of the Non-Binding System, has remained fairly constant in recent years, except in 2003 when it increased slightly due to an extremely cold winter and a decrease in installed capacity in the PES following the decommissioning of the Alto Mira power plant (132 MW). Our available capacity as a percentage of the total installed capacity has maintained a value of approximately 78% from 2001 through 2003. The ratio of peak demand to EDP’s average available capacity indicates that EDP alone did not have sufficient available capacity to cover the total peak demand in 2001, 2002 and 2003. To address this, in early 2004, the first 392 MW unit of the TER CCGT plant began operation. The second unit has been in testing since September 30, 2004 and is expected to begin operation before the end of 2004. The third unit is expected to begin operation in 2006. We are also building new hydroelectric generation capacity.

 

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The following table sets forth the ratios of peak demand to installed capacity, EDP’s available capacity to the installed capacity of the PES and the Non-Binding System and peak demand to EDP’s available capacity for the periods indicated. Peak demand includes demand satisfied by generation from Other Independent Producers.

 

     As of December 31,

   

As of
June 30,

2004


 
     1999

    2000

    2001

    2002

    2003

   
     (in MW, except percentages)  

Installed capacity of the PES(1)

   8,804     8,758     8,758     8,758     8,626     8,626  

Installed capacity of the NBES(2)

   255     255     255     255     647     647  
    

 

 

 

 

 

Total installed capacity (PES plus NBES)

   9,059     9,013     9,013     9,013     9,273     9,273  
    

 

 

 

 

 

Peak demand (PES plus NBES)

   6,522     6,890     7,466     7,394     8,046     7,760  

Peak demand as a percentage of the total installed capacity (PES plus NBES)

   72.0 %   76.4 %   82.8 %   82.0 %   86.8 %   83.7 %

EDP:

                                    

EDP’s average available capacity (PES)

   6,808     6,765     6,801     6,841     6,695     6,831  

EDP’s average available capacity (NBES)(3)

   196     215     247     226     228     562  

EDP’s available capacity as a percentage of the total installed capacity (PES plus NBES)

   77.3 %   77.4 %   78.2 %   78.4 %   74.7 %   79.7 %

Peak demand as a percentage of EDP’s average available capacity (PES plus NBES)

   93.1 %   98.7 %   105.9 %   104.6 %   116.2 %   105.0 %

(1) PES.
(2) Non-binding Electricity System, which consists of generation in the Independent Electricity System other than the “other independent producers.” All of the NBES hydroelectric plants with an installed capacity less than or equal to 10 MW became special regime producers in October 2002. Special regime generation generally consists of small or renewable energy facilities, from which the electricity system must acquire all electricity offered, at tariffs fixed according to the type of generation. Installed capacity of the NBES in 2003 includes the first 392 MW unit of TER CCGT that was in testing at the end of the year.
(3) Provisional values from 1999 to 2001 take into account the restructuring of the Vila Cova plant in 1999.

 

The Portuguese overall growth rate in demand for electricity is slightly higher than the rate reflected in the figures above due to the growth of auto production of electricity in certain industries. Auto producers supply their surplus electricity to REN, which displaces electricity generation in the PES.

 

The term “installed capacity,” as used herein, refers to the maximum capacity of a given generation facility under actual operating conditions. Maximum capacity of a hydroelectric facility is based on the gross electricity emission to the transmission network by the units of such facility, whereas maximum capacity of a thermal facility is based on the net electricity emission (net of own consumption) to the transmission network.

 

Generation

 

As of December 31, 2003, our Portuguese electricity generation facilities consist of hydroelectric, thermal (coal, fuel oil, natural gas and gas oil), biomass, cogeneration and wind generation facilities, and had a total installed capacity of 7,939 MW (including one 392 MW unit of the new TER CCGT plant, which was in service by the end of 2003 for testing purposes and began commercial operations in early 2004), 7,052 MW of which was in the PES and 888 MW of which was in the Independent Electricity System, and approximately 53% of which was represented by hydroelectric facilities, 28% by fuel oil/natural gas facilities, 15% by coal-fired facilities, 2% by gas oil facilities and 2% by wind-driven, biomass and cogeneration facilities. We do not own or operate any nuclear-powered facilities in Portugal.

 

Our installed capacity in the PES of 7,052 MW represents approximately 82% of the total installed capacity in the PES. From 2000 to 2002, the installed capacity of the PES remained constant. In 2003, a small decrease resulted from the decommissioning of the 132 MW Alto de Mira plant. Our smaller hydroelectric plants, wind generating facilities and cogeneration and biomass plants are part of the Independent Electricity System.

 

In 2003, our electricity generation in Portugal was approximately 27.7 TWh in the ordinary regime. According to REN, the total generation value in the ordinary regime in Portugal in 2003 was approximately 37.0 TWh.

 

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Since its creation in 1994, CPPE has operated all of our conventional thermal plants and approximately 92.6% of our hydroelectric plants. In 2003, CPPE accounted for approximately 96.3% of our electricity generation in Portugal. During the second half of 2003, we began reorganizing our generation business in preparation for the liberalization of the Iberian electricity market, which was expected to start operations by June 20, 2004. Pursuant to a new agreement (which has not yet been made public) signed by the Portuguese and Spanish governments at the Iberian Summit at Santiago de Compostela on October 1, 2004, it is expected that MIBEL will begin operations by June 30, 2005. We are in the process of consolidating a number of generation companies formerly held by EDP Produção, which operate in the Independent Electricity System, into CPPE as part of the reorganization of our generation business.

 

EDP Energia was created to supply electricity to Qualifying Consumers and to conduct energy trading activities. The energy trading activities were subsequently transferred to EDP Produção.

 

EDP Produção also holds a variety of engineering and operations and maintenance, or O&M, companies, including EDP Produção EM—Engenharia e Manutenção, S.A., a company which undertakes hydroelectric and thermal engineering projects and studies, project management, engineering and consulting.

 

Enernova (wind energy) and EDP Bioeléctrica (biomass plants) are now held directly by EDP outside of EDP Produção. Since 1996, Enernova has increased by six times its installed generation capacity, from 10 MW to 65 MW. New projects are in progress, some of which are under construction and others are in licensing development, which will add installed capacity of 280 MW by 2006, and 300 MW by 2008.

 

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The following map sets forth the CPPE power plants in the Binding Sector as of December 31, 2003.

 

LOGO

 

The generation capacity of CPPE plants in the Binding Sector is bound to the PES under PPAs between CPPE and REN. Under the PPAs, CPPE is guaranteed a monthly fixed revenue component (capacity charge) that remunerates, at an 8.5% real rate of return, the net asset value of CPPE’s power plants. The revenue amount CCPE receives as a capacity charge also includes the depreciation related to these assets, and is based on the contracted availability of each power plant, regardless of the energy it produces. The PPAs also allow CPPE to

 

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pass-through to the final tariff its total fuel consumption cost through a variable revenue component (energy charge) that is invoiced monthly to REN. Pursuant to the Portuguese government’s policy for the reorganization of the energy sector, the PPAs may be subject to early termination, as a step in the creation of an Iberian electricity market.

 

In fact, Decree law no. 185/2003 of August 20, 2003, contemplates the eventual early termination of the PPAs in accordance with certain rules to be set out in a separate decree law, which is expected to provide for adequate compensatory measures to cover the investments and other commitments set out in each PPA that are not otherwise compensated through market-derived revenues. For that purpose, Law no. 52/2004 of October 29, 2004 has granted a legislative authorization from the Portuguese parliament to the Portuguese government permitting it to provide for the granting of compensation with respect to the early termination of the PPAs (including in relation to the definition of the methodology for the determination of the amounts due, as well as in relation to procedure and time for such payment) and for the creation of the necessary mechanisms to ensure the payment of such compensatory amounts through the pass-through of charges to all electric energy consumers as permanent components of the Global Use of System Tariff (UGS Tariff).

 

This legislative authorization, which was granted for a 180-day period, also establishes that the Portuguese government is authorized to determine (i) that the charges relating to the compensatory measures should be billed to electric energy consumers simultaneously with the remaining components of the UGS Tariff, and (ii) the time at which compensation paid to producers is to be included in the relevant taxable income so as to have a tax-neutral effect.

 

Once the decree law regarding early termination of the PPAs is enacted, we may consider, in accordance with applicable legislation, securitizing the compensation amounts arising from such terminations, subject to terms and conditions to be defined. In the event such amounts are securitized, we intend to use the proceeds for the partial redemption of our financial indebtedness.

 

The following table sets forth our total installed capacity by type of facility at year-end for the years 1999 through 2003 and the first half of 2004.

 

     As of December 31,

  

As of
June 30,

2004


Type of facility


   1999

   2000

   2001

   2002

   2003

  

Hydroelectric:

                             

CPPE plants

   3,903    3,903    3,903    3,903    3,903    3,903

Independent System hydroelectric plants

   309    309    309    309    311    311
    
  
  
  
  
  

Total hydroelectric

   4,212    4,212    4,212    4,212    4,214    4,214

Thermal(1)

   3,327    3,281    3,281    3,281    3,149    3,149

Wind

   20    30    41    41    65    96

Biomass

   9    9    9    9    9    9

Cogeneration

   0    67    67    111    111    111

CCGT(2)

   0    0    0    0    392    392
    
  
  
  
  
  

Total

   7,568    7,599    7,610    7,654    7,939    7,971

(1) On June 30, 2003, the PPA of the Alto de Mira plant expired and the plant was decommissioned.
(2) The first unit of this plant began commercial service on February 14, 2004 and the second unit is currently in testing.

 

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The following table sets forth the global gross margin of our PPAs per year until 2027, assuming that contracted availability is met, and including the PPA capacity charge, environmental capital expenditure at Sines (SO2 and NOx reduction) and other charges, such as land rentals and startup costs.

 

CPPE’s Power Purchase Agreements - Gross Margin

 

Year

   PPA

   Year

   PPA

   Year

   PPA

     (thousands of EUR)         (thousands of EUR)         (thousands of EUR)
2004    887,169    2012    849,160    2020    387,791
2005    905,349    2013    746,481    2021    364,932
2006    916,055    2014    686,310    2022    364,672
2007    917,463    2015    682,710    2023    351,339
2008    944,296    2016    592,999    2024    347,269
2009    970,771    2017    586,813    2025    17,655
2010    942,736    2018    390,839    2026    16,981
2011    854,094    2019    390,325    2027    16,272

 

Hydroelectric generation is dependent upon hydrological conditions. In years of less favorable hydrological conditions, less hydroelectricity is generated and the PES must depend upon increased thermal production. In addition, in years of less favorable hydrological conditions, imports of electricity may increase. For purposes of forecast models, our estimated annual hydroelectric production based on current installed capacity in an average year is 10.6 TWh and can reach about 15 TWh in a wet year and may fall to less than 7 TWh in a dry year. Between 1993 and 2003, our actual hydroelectric production ranged from a low of 6.9 TWh in 1999, a very dry year, to a high of 14.9 TWh in 2003, a record wet year.

 

The following table summarizes our electricity production, excluding losses at our plants and our own consumption, by type of generating facility from 1999 through 2003 and the first half of 2004, and also sets forth our hydroelectric capability factor for the same period:

 

     Year ended December 31,

   

June 30,

2004


Type of facility


   1999

   2000

   2001

   2002

   2003

   
     (in GWh, except hydroelectric capability factor)

Hydroelectric:

                              

CPPE plants(1)

   6,457    10,229    12,607    6,764    13,964     5,335

Independent System hydroelectric plants

   447    624    790    573    901     313
    
  
  
  
  

 

Total hydroelectric

   6,904    10,853    13,397    7,336    14,865     5,648

Thermal:

                              

Coal

   9,319    9,091    8,677    9,532    9,473     4,887

Fuel oil and natural gas

   7,596    4,631    5,583    7,848    3,120     547

Gas oil

   2    38    50    13    26     5

Coal and fuel oil(2)

   85    11    30    44    (1 )   0

Cogeneration

   0    134    423    590    679     358

CCGT(3)

   —      —      —      —      203     1,155
    
  
  
  
  

 

Total thermal

   17,002    13,905    14,763    18,027    13,500     6,952

Wind

   53    70    90    113    128     96

Biomass

   2    5    18    37    38     24
    
  
  
  
  

 

Total

   23,961    24,833    28,269    25,513    28,532     12,720

Hydroelectric capability factor(4)

   0.68    1.08    1.19    0.75    1.33     0.83

(1) Includes the following amounts of our own consumption for hydroelectric pumping, 491 GWh in 1999, 558 GWh in 2000, 485 GWh in 2001, 670 GWh in 2002, 485 GWh in 2003 and 176 GWh in June 2004.
(2) Since the beginning of 1998, our existing plant at Tapada do Outeiro uses only fuel oil. Production in 2003 reflects the fact that our plant at Tapada do Outeiro generated an amount of electricity that was less than the plant’s own consumption.
(3) The first unit of this plant began commercial service on February 14, 2004 and the second unit is currently in testing.
(4) The hydroelectric coefficient varies based on the hydrological conditions in a given year. A hydroelectric capability factor of one corresponds to an average year, while a factor less than one corresponds to a dry year and a factor greater than one corresponds to a wet year.

 

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The average availability for production of CPPE’s plants remained stable from 1999 (93.0%) through 2003 (92.7%) for thermal plants, and increased slightly from 95.1% to 96.8% for hydroelectric plants during the same period. Forced outage is unplanned availability at a power plant caused by trips, critical repairs or other unexpected occurrences. Non-availability results from planned maintenance and forced outages. CPPE is reducing planned maintenance outages through more efficient maintenance techniques. CPPE’s generating facilities have experienced very low rates of forced outage over the past five years. Management believes these low rates compare favorably with the European average. In the period 1999 through 2003, forced outages of CPPE’s thermal plants has ranged between 2.1% and 2.8%. During the same period, forced outages of CPPE’s hydroelectric plants ranged between 0.4% and 1.0%. In 2003, forced outages of CPPE’s thermal plants was 2.1% and hydroelectric plants was 0.44%.

 

The average availability factor is defined as the total number of hours per year that a power plant is available for production as a percentage of the total number of hours in that year. This factor reflects the mechanical availability, not the actual availability of capacity, which may vary due to hydrological conditions. The table below indicates for each type of CPPE generating facility the “average capacity utilization” and “average availability factor” indicators, comparable with other European utilities, each calculated in accordance with our computational method, for the indicated periods:

 

    Average capacity utilization (1)

  Average availability factor

    Year ended December 31,

 

Six
months
ended
June 30,

2004


  Year ended December 31,

 

Six
months
ended
June 30,

2004


Type of facility


  1999

  2000

  2001

  2002

  2003

    1999

  2000

  2001

  2002

  2003

 

Hydroelectric

  18.9%   29.8%   36.9%   19.8%   40.8%   31.3%   95.1%   95.0%   94.8%   95.9%   96.8%   98.5%

Thermal:

                                               

Coal(2)

  89.3%   86.8%   83.1%   91.3%   90.7%   93.9%   90.5%   89.2%   90.5%   94.0%   94.2%   96.3%

Fuel oil and natural gas

  50.6%   30.8%   37.2%   52.3%   20.8%   7.3%   93.2%   94.6%   96.6%   93.7%   90.8%   93.2%

Coal and fuel oil(3)

  10.3%   2.8%   7.2%   10.8%   0.0%   0.0%   98.6%   99.6%   98.9%   98.2%   94.9%   100.0%

Gas oil(4)

  0.1%   1.3%   1.7%   0.4%   1.2%   0.6%   99.6%   99.4%   98.4%   99.1%   98.0%   99.7%

Total weighted average thermal(5)

  58.3%   47.8%   49.9%   60.7%   44.8%   39.5%   93.0%   93.2%   94.6%   94.4%   92.7%   94.8%

(1) The average capacity utilization is defined as actual production as a percentage of theoretical maximum production.
(2) The average availability of the coal plants in 1999 was affected by the installation of low NOX burners in each unit of the Sines plant, one per year, which required production from each unit to stop temporarily.
(3) None, primarily due to minimal generation at our Tapada do Outeiro plant as a result of a wet year in 2003 and the fact that this is a peak load power plant.
(4) Increase in average capacity utilization was due to the need to use the fuel stock of the Alto de Mira power plant in the context of its decommissioning in 2003.
(5) Weighted average is based on total installed capacity of the thermal system.

 

During the period from 1999 through 2003, CPPE has had operating and maintenance costs, excluding fuel and depreciation costs, below the limits contained in the relevant PPAs over that time period. Management expects to continue to maintain these costs below the PPA limits in 2004. However, we expect most of the PPAs to terminate during 2004 or 2005 as a result of a decree law expected to be enacted, and we expect that compensation mechanisms for these terminations will be defined with the goal of maintaining the economic value of the terminated PPAs. On June 30, 2003, the PPA of our 132 MW Alto de Mira plant terminated on the scheduled expiration date.

 

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Hydroelectric Plants

 

As of December 31, 2003, we operated 25 hydroelectric generating facilities in the Binding System, with 63 total units and an aggregate installed capacity of 3,903 MW.

 

Based on an independent revaluation of our assets in 1992, we estimate that the average remaining useful life of our dams is approximately 45 years. The table below sets out our hydroelectric plants, installed capacity as of December 31, 2003, the type of hydroelectric plant, the year of commencement of operation and the year in which the most recent major refurbishment, if any, was accomplished.

 

Hydroelectric plants


   Installed
capacity
(MW)


   River reservoir
plant type


   Year entered
into service


   Year of last
major
refurbishment


CPPE Plants:

                   

Alto Lindoso

   630.0    Reservoir    1992    —  

Miranda

   369.0    Run of river    1960/95    1970

Aguieira

   336.0    Reservoir    1981    —  

Valeira

   240.0    Run of river    1976    —  

Bemposta

   240.0    Run of river    1964    1969

Pocinho

   186.0    Run of river    1983    —  

Picote

   195.0    Run of river    1958    1969

Carrapatelo

   201.0    Run of river    1971    —  

Régua

   180.0    Run of river    1973    —  

Torrão

   140.0    Reservoir    1988    —  

Castelo de Bode(1)

   159.0    Reservoir    1951    2003

Vilarinho Furnas

   125.0    Reservoir    1972/87    —  

Vila Nova (Venda Nova/Paradela)

   144.0    Reservoir    1951/56    1994

Fratel

   132.0    Run of river    1974    1997

Crestuma-Lever

   117.0    Run of river    1985    —  

Cabril

   108.0    Reservoir    1954    1986

Alto Rabagão

   68.0    Reservoir    1964    —  

Tabuaço

   58.0    Reservoir    1965    —  

Caniçada

   62.0    Reservoir    1954    1979

Bouçã

   44.0    Reservoir    1955    1988

Salamonde

   42.0    Reservoir    1953    1989

Pracana

   41.0    Reservoir    1950/93    1993

Caldeirão

   40.0    Reservoir    1994    —  

Touvedo

   22.0    Reservoir    1993    —  

Raiva

   24.0    Reservoir    1982    —  
    
              

Total

   3,903.0               

Independent System Hydroelectric Plants:

                   

Hidrocenel(2)

   107.6    Various    Various     

HDN(3)

   118.5    Various    Various     

EDP Energia(4)

   84.9    Various    Various     

Total

   311.0               
    
              

Total maximum capacity

   4,214.0               

(1) We invested approximately €13 million in the modernization of the electricity generating turbines and other dam equipment at Castelo de Bode, which was completed at the end of 2003.
(2) Hidrocenel, which operates 15 plants with capacities ranging from 0.1 MW to 24.4 MW and dates of entry into service from 1906 to 2003, was merged into CPPE in 2004.
(3) HDN, which operates 13 plants with capacities ranging from 0.9 MW to 44.1 MW and dates of entry into service from 1922 to 1992, was merged into CPPE in 2004.
(4) EDP Energia owns five plants with capacities ranging from 0.2 MW to 80.7 MW and dates of entry into service from 1927 to 1951.

 

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The following table presents the net generation, for the last two years, of our hydroelectric power plants operating under PPAs, as well as the end date of each PPA.

 

Profile of CPPE’s Hydroelectric Power Plants under PPA with REN

 

     End of PPA

  

Annual

Net Generation


   Average
Net Generation


 
          2002    2003    1990-2003  
          (GWh)  

Hydro

                     

Alto Lindoso

   2024    599    948    910  

Touvedo

   2024    48    72    71  

Alto Rabagão

   2015    54    145    105  

Paradela

   2015    135    264    241  

Venda Nova 1

   2015    218    456    346  

Venda Nova 2

   2027              (1 )

Salamonde

   2015    153    261    226  

Vilarinho Furnas

   2022    160    181    182  

Caniçada

   2015    238    347    315  

Miranda

   2013    478    1,365    995  

Picote

   2013    513    1,121    833  

Bemposta

   2013    535    1,374    909  

Pocinho

   2024    262         412  

Valeira

   2024    444    1,049    633  

Vilar-Tabuaço

   2024    48    178    123  

Régua

   2024    428    891    580  

Carrapatelo

   2024    558    1,092    756  

Crestuma-Lever

   2024    258    513    330  

Torrão

   2024    272    314    262  

Caldeirão

   2024    49    76    50  

Aguieira

   2024    538    614    384  

Raiva

   2024    41    66    44  

Cabril

   2015    185    491    285  

Bouçã

   2015    97    230    149  

C. Bode

   2015    216    608    359  

Pracana

   2024    49    99    57  

Fratel

   2020    188    528    259  
         
  
  

Total Hydro

        6,764    13,964    9,814  
         
  
  


(1) Venda Nova 2 Power Plant will start industrial service in January 2005.

 

 

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Thermal plants

 

CPPE operates all our conventional thermal power plants, with total installed capacity, as of December 31, 2003, of 3,148.5 MW and installed capacity per generating unit ranging from 16 MW to 298 MW. The following table sets forth, as of December 31, 2003, our conventional thermal plants by installed capacity, type of fuel, net efficiency at maximum output, number of units and year entered into service.

 

Thermal plants


   Installed
Capacity (MW)


  

Fuel


   Net efficiency
at maximum
output


   Number of
units


  

Years
entered

into service


Sines

   1,192.0    Coal    36.8    4    1985-89

Setúbal

   946.4    Fuel oil    38.2    4    1979-83

Carregado I

   473.8    Fuel oil    37.3    4    1968/1974

Carregado II(1)

   236.4   

Fuel oil /

Natural gas

   37.6    2    1976

Tunes

   197.0    Gas oil    28.4    4    1973/1982

Tapada do Outeiro (EDP facility)(2)

   46.9    Coal /fuel oil    29.4    1    1959/ 1967
(unit 3)

Barreiro

   56.0    Fuel oil    34.2    2    1978
    
                   

Total maximum capacity

   3,148.5                    

(1) These units began burning natural gas in 1997.
(2) This three-unit plant is being progressively decommissioned by the end of 2004. The first unit of 50 MW was decommissioned on December 31, 1997. The second unit of 50 MW was decommissioned on December 31, 1999. Since 2000, only one 50 MW unit, currently burning fuel oil, has been operational.

 

There has been no significant change in average net efficiency of CPPE’s thermal plants over the past five years. With continued proper maintenance of the thermal facilities, CPPE expects to maintain net efficiency at least at levels contracted in the PPAs.

 

The following table presents the net generation, for the last two years, of our thermoelectric power plants operating under PPAs, as well as the end date of each PPA and the fuel costs per power station:

 

 

Profile of CPPE’s Thermoelectric Power Plants under PPA with REN


     End of PPA

   Annual Net Generation

   Annual Fuel Costs

          2002

   2003

   2002

   2003

          (GWh)    (EUR)

Sines

   2017    9,532    9,473    149,741    131,771

Setúba

   2012    5,191    1,834    173,290    71,333

Carregado (I and II)

   2010    2,408    1,091    92,121    51,075

Barreiro

   2009    249    195    16,003    16,971

Other

        57    26    3,457    2,757
         
  
  
  

Total

        17,437    12,619    434,612    273,908
         
  
  
  

 

Other Energy Sources

 

Renewables

 

In addition to our hydroelectric and thermal plants, we promote the use of renewable energy sources with other types of facilities. Enernova, our subsidiary specializing in this area, concentrated its initial investments in wind farms (due to greater technological advances made to date). Our first wind facility commenced operation in 1996. We now have five wind facilities with a combined installed capacity of 65 MW. In 2002, we created a new subsidiary for the biomass assets, EDP Produção Bioeléctrica, which owns the Mortágua biomass (forestry waste) power plant. This plant started operations in 1999 and has an installed capacity of 9 MW.

 

Fuel

 

CPPE uses a number of fossil fuels in the generation of electricity. The introduction of natural gas to Portugal is diversifying the sources of primary energy. For more information on our use of natural gas you should read “Natural Gas” below.

 

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CPPE fuel consumption costs, including transportation, were €273.9 million in 2003 and €434.6 million in 2002, which represented approximately 41.2% and 52.8%, respectively, of CPPE’s total operating expenses. The decrease in the total cost of fuel consumed from 2002 to 2003 resulted primarily from a decrease in the thermal production powered by fuel oil, due to increased hydroelectric production in 2003, which was a wet year.

 

The table below shows a breakdown of costs of fuel consumed by CPPE from 1999 through 2003 and the first half of 2004:

 

     Year ended December 31,

  

June 30,

2004


Type


   1999

   2000

   2001

   2002

   2003

  
     (thousands of EUR)

Imported coal

   116,823    128,902    142,810    148,773    130,531    80,704

Fuel oil(1)

   109,371    146,721    193,867    259,816    117,716    21,413

Gas oil(2)

   219    1,895    4,618    1,526    2,744    567

Natural gas

   42,163    25,364    12,260    24,497    22,917    7,383
    
  
  
  
  
  

Total

   268,576    302,882    353,555    434,612    273,908    110,067

(1) Includes consumption for the production of steam at the Barreiro power plant.
(2) Small amounts of gas oil are consumed by the gas oil plants for the operation of these plants in synchronous compensation mode for purposes of voltage regulation and a very small amount of generation.

 

The following table sets forth the amounts of fuel purchased by CPPE in each of the last five years.

 

     Year ended December 31,

  

June 30,

2004


Type


   1999

   2000

   2001

   2002

   2003

  
     (thousands of metric tons, except natural gas)

Imported coal

   3,533    3,564    3,108    3,587    3,593    1,580

Fuel oil(1)

   1,712    1,052    1,237    1,941    716    42

Gas oil

   0    0    26    3    10    1

Natural gas(2)

   376    142    60    150    131    190,508

(1) Includes purchases for the production of steam at the Barreiro plant.
(2) Measured in millions of cubic meters. The increase in 2004 is due to the start of the first unit of the TER CCGT power plant.

 

Coal

 

As the Sines power plant is a base load, or continuous operation power plant, CPPE enters into supply contracts for more than one year for the major part of its consumption of coal. Pursuant to the PPAs, for purchases of coal, an annual Target Contract Quantity, or TCQ, is defined by REN based on the forecasts for coal consumption for a wet year. The TCQ is the basis for long-term supply and shipping contracts, which are negotiated by CPPE, subject to REN approval. In addition, CPPE makes spot-market purchases as necessary. In both 2003 and 2002, CPPE purchased 78% of its coal through long-term contracts and 22% of its coal on the spot market. In comparison, in 2002 and 2001, CPPE purchased 78% and 70%, respectively, of its coal through long-term contracts, and 22% and 30%, respectively, of its coal on the spot market.

 

The following table shows a breakdown of CPPE’s coal purchases from 1999 to 2003 and the first half of 2004 by geographic markets as a percentage of total purchases.

 

     Year ended December 31,

  

June 30,

2004


Region


   1999

   2000

   2001

   2002

   2003

  

South Africa

   28.0%    38.0%    28.0%    28.9%    34.6%    28.6%

United States

   12.0%    10.0%    17.0%    3.2%    9.9%    16.6%

Australia

   17.0%    0.0%    13.0%    23.2%    18.6%    8.1%

South America

   43.0%    48.0%    27.0%    16.3%    32.9%    35.5%

Southeast Asia

   0.0%    4.0%    15.0%    16.9%    0.0%    9.9%

Europe

   0.0%    0.0%    0.0%    11.3%    4.0%    1.4%
    
  
  
  
  
  

Total

   100%    100%    100%    100%    100%    100%

 

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In 2003, the average cost of coal consumed was €36.7 per ton. In 2002 and 2001, the average cost of coal consumed for imported coal was €41.4 per ton and €43.8 per ton, respectively.

 

Fuel Oil and Gas Oil

 

Fuel oil purchases by CPPE are made in the spot market and pursuant to contracts. CPPE purchases fuel oil from refineries in Europe, primarily in Portugal and northwestern Europe, and is remunerated through PPAs based on, among other things, costs of fuel oil indexed to the spot market.

 

The average cost of fuel oil consumed in 2003 was €164.76 per ton, compared with €143.25 and €141.22 in 2002 and 2001, respectively. The increase in 2003 was due to increases in market prices as a result of the conflict in Iraq and production control by OPEC members. To meet its objectives to improve air quality, CPPE has shifted its fuel oil purchases to lower sulfur fuel oil, which has increased the cost of consumed fuel oil. In 2003, the average sulfur content of fuel oil purchased by CPPE was approximately 0.9%, compared with 2.1% in 2002. In October 2002, CPPE initiated the use of fuel with a 1% sulfur content. The use of lower sulfur fuel oil has increased, and will increase in the future, the average cost of fuel oil consumed.

 

CPPE maintains gas oil reserves as fuel for emergency gas turbine generators. Since gas oil is very expensive and economically inefficient, these reserves are used on a very limited basis. Consequently, small purchases of gas oil have been made by CPPE, as required by REN.

 

The increase in 2003 of the consumption of gas oil was due to higher production by the Alto de Mira plant prior to its decommissioning in order to exhaust its fuel inventory.

 

Natural Gas

 

Since the introduction in 1997 of the import of natural gas from Algeria into Portugal by Transgás, CPPE has had access to natural gas as a source of primary energy. CPPE converted two units of Carregado into dual-fired (fuel oil and natural gas) in late 1997. In 2003, CPPE purchased 131 million cubic meters of natural gas for a total of €22.9 million compared to 150 million cubic meters of natural gas in 2002 for a total of €24.5 million. For more information on our activities related to natural gas you should read “Other International Activities and Strategic Investments.”

 

Planned New Plants

 

In order to meet increased demand for electricity in Portugal, additional capacity is planned for the National Electricity System. The following table sets out planned new power facilities in Portugal.

 

Facility


  

Type of

generation


  

Developing

entity


  

Planned capacity

(MW)


  

Target

year


   Status

Alqueva(1)

   Hydroelectric    EDIA/CPPE    240    2004    Under Construction

Venda Nova II

   Hydroelectric    CPPE    192    2004    Under Construction

Baixo Sabor

   Hydroelectric    CPPE    180    2010    Planning

Picote II

   Hydroelectric    CPPE    236    2010    Planning

CCGT Ribatejo

   CCGT    TER(2)    3x392    2004/2006    Under Construction

(1) EDIA—Empresa de Desenvolvimento e Infra-estruturas de Alqueva, S.A. (“EDIA”) is a company wholly-owned by the Portuguese Republic that is developing a multi-purpose hydro scheme for irrigation and the production of electricity. CPPE will operate the Alqueva hydroelectric power plant.
(2) TER CCGT operates in the Non-Binding Sector. The first unit began commercial service in February 2004, the second unit has been in testing since September 30, 2004 and is expected to begin commercial service before the end of 2004. The third unit is expected to begin commercial service in March 2006. TER was merged into CPPE in 2004.

 

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Capital Expenditures

 

In 2003, we spent €261.1 million in capital expenditures in technical costs for our generation facilities, compared with €276.5 million in 2002 and €131.7 million in 2001. Our capital expenditures in the generation sector have been concentrated on the following activities: conducting preliminary studies for and building of hydroelectric plants, maintaining and upgrading existing power plants, investing in environmental projects such as the installation of emission reduction equipment and, in 2003, investing €142.4 million in the new TER CCGT (combined cycle gas turbine) power plant units 1 and 2, and €38.4 million in wind energy farms. At this stage, management expects that the TER CCGT plant will cost approximately €600 million, including all three units.

 

The following table sets forth our capital expenditures in technical costs from 1999 through 2003 and the first half of 2004 on plants by type and status of generating plant.

 

     Year ended December 31,

  

June 30,

2004


Plant type and status


   1999

   2000

   2001

   2002

   2003

  
     (audited)    (unaudited)
     (thousands of EUR)

Thermal/Hydro

                             

Public Electricity System

                             

Hydroelectric plants under construction

   6,449    14,235    16,877    25,690    34,359    5,017

Hydroelectric plants in operation

   10,475    9,038    10,289    12,756    11,732    2,303

Thermal plants in operation

   25,199    17,623    14,764    16,261    20,340    3,349

Plants under study

   359    190    1,450    1,011    349    9
    
  
  
  
  
  

Total CPPE

   42,482    41,086    43,380    55,718    66,780    10,679

Independent Electricity System

                             

Hydroelectric plants

   11,457    7,913    4,964    4,137    3,849    326

TER

   0    3,571    58,535    142,946    142,350    80,582

Wind

   5,726    11,128    6,521    11,159    38,389    31,408

Cogeneration facilities

   37,654    25,439    13,083    9,602    255    22

Biomass(1)

   12,679    0    0    35,180    614    28

Total Independent Electricity System

   67,516    48,051    83,103    203,024    185,456    112,365

Others(2)

   0    0    0    0    312    654

Non-specific investment(3)

   4,070    4,969    5,250    17,721    8,599    1,068
    
  
  
  
  
  

Total Generation

   114,068    94,106    131,733    276,463    261,148    124,767

(1) Investments in 2002 include €35.2 million related to an intra-group transfer of the Mortagua biomass power plant (built in 1999), to EDP Produção.
(2) Other investments include studies and investment relating to our trading system.
(3) Non-specific investment refers to investments not directly related to our plants, such as administrative buildings, transportation equipment and implementation of new information systems.

 

We currently expect that our planned capital expenditures and investments will be financed from internally generated funds, existing credit facilities and customer contributions, which may be complemented with medium- or long-term debt financing and equity financing as additional capital expenditure requirements develop. To learn more about our sources of funds and how the availability of those sources could be affected, see “Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

 

Transmission

 

The transmission system in mainland Portugal is owned and operated by REN, which is obligated by law to supply electricity within the National Electricity System. Electricity transmission in Portugal is the bulk transfer of electricity, at voltages between 150 kV and 400 kV, from generation or acquisition sites across a transmission system to areas of use via networks that are linked to each other to form an interconnected national transmission grid. As described above, the Portuguese government purchased a 70% interest in REN from us in late 2000. For more information on this purchase, you should read “Operating and Financial Review and Prospects—Overview.”

 

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REN operates the national transmission grid on an exclusive basis pursuant to Portuguese law under a concession provided for by Decree law no. 182/95 of August 27, 1995. The concession is valid for 50 years from September 2000, when the concession agreement was signed.

 

The Portuguese transmission system operates at a frequency of 50 Hz, which is in line with the majority of the European transmission systems. At year-end 2003, there were 47 substations operating on the national transmission grid, not including power plants. All of these substations are now fully automated and operated by remote control.

 

Of REN’s transmission lines at December 31, 2003, approximately 2,438 km were 150 kV lines, 2,704 km were 220 kV lines and 1,403 km were 400 kV lines. Additionally, at the beginning of April 2004, a new 400 kV circuit of the interconnection line Alto-Lindoso-Cartelle was put into operation. We understand that, within the context of creation of MIBEL, REN plans to establish two additional interconnections with Spain by 2006: Alqueva-Balboa, a 400 kV line scheduled for completion by the end of 2004, and Douro Internacional-Aldeadavila, a 220 kV or 400 kV line scheduled for completion in 2006.

 

In addition to the construction and operation of the national transmission grid, REN is also responsible for central dispatch of all power plants with installed capacity of more than 10 MW. This includes scheduling generation to match, as closely as possible, the demand on the national transmission grid. As part of managing the national transmission grid, REN is also responsible for scheduling imports and exports with Spain. It buys and sells electricity in the Spanish organized electricity market at market prices. Apart from the power plants in the PES, REN is also obligated to buy energy from auto producers, cogenerators, small hydroelectric producers and other renewable source energy plants operating under Portuguese law within the Independent Electricity System.

 

The following table sets forth REN’s net imports made in the conduct of its operations in each of the last five years in GWh and as a percentage of total demand.

 

Year


   Net imports
(GWh)


    Percentage of
total demand


1999

   (857 )   N/A

2000

   931     2.5

2001

   239     0.6

2002

   1,899     4.7

2003

   2,794     6.5

 

Distribution

 

Electricity distribution in Portugal is a regulated business and involves the transfer of electricity from the transmission system and its delivery across a distribution system to regulated consumers and Qualifying Consumers, meter reading and installation, and supply to regulated consumers. The local electricity distribution function in mainland Portugal is carried out almost exclusively by EDPD. Through fourteen network distribution areas, as well as seven commercial areas directed at serving customers supplied in the PES, EDP distributed electricity to 5,767,401 million consumers in 2003 out of a total of 5,767,916 according to DGGE, amounting to 38,916 GWh, of which 4,048 GWh was distributed to Qualifying Consumers. At December 31, 2003, EDPD employed approximately 6,334 personnel.

 

Under Portuguese law, distribution of high-voltage electricity, greater than 45kV and less than 110kV, and medium-voltage electricity, greater than 1kV and less than or equal to 45kV, is regulated by DGGE through the issuance of a binding license with no time limitation. EDPD holds high- and medium-voltage electricity licenses, which it obtained in 2000. Distribution of low-voltage electricity is regulated through 20-year municipal concession agreements with municipal councils. EDPD pays rent to each municipality as required by law. For more information on licenses and concessions held by us, you should read note 1 to our audited consolidated financial statements.

 

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Under the terms of the binding licenses, EDPD is obliged to supply electricity to all customers located within its licensed area that are part of the PES. EDPD is also obliged to provide access to the distribution network to producers in the Independent Electricity System in return for a regulated access charge from consumers. EDPD owns, leases or has rights of way for the land on which its substations are situated. In addition, EDPD has long-term rights of way for its distribution lines. If necessary, new properties may be acquired through the exercise of eminent domain. In those cases, EDPD compensates affected private property owners.

 

The authorized area of EDPD covers all of mainland Portugal. At December 31, 2003, EDPD’s distribution lines spanned a total of approximately 194,609 kilometers. The only distribution lines in Portugal not owned by EDPD are those of the auto producers and small cooperatives, which own their own lines. The following table sets forth the kilometers of EDPD’s distribution lines, by voltage level, at December 31, 2003.

 

Distribution lines


   Km

Overhead lines:

    

High-voltage (60/130kV)

   7,267

Medium-voltage (6/10/15/30kV)

   52,742

Low-voltage (1kV)

   98,099

Total overhead lines

   158,108

Underground cables:

    

High-voltage (60/130kV)

   361

Medium-voltage (6/10/15/30kV)

   11,513

Low-voltage (1kV)

   24,627

Total underground cables

   36,501
    

Total

   194,609

 

Customers and Sales

 

EDPD distributes electricity to approximately 5.8 million customers. Approximately 67% of electricity consumption in 2003 was along the coast, with approximately 15% in the Oporto metropolitan region and 20% in the Lisbon metropolitan region. EDPD classifies its customers by voltage level of electricity consumed. The following charts show the number of customers as of December 31, 2003 and June 30, 2004, according to level of voltage contracted, and indicates whether such customers are binding customers supplied by EDPD or Qualifying Consumers to which EDPD distributes electricity on behalf of suppliers in the Independent Electricity System.

 

     Year Ended December 31, 2003

Customers by voltage level


   Binding
customers


   Qualifying
consumers


   Total

High- and very high-voltage(1)

   146    3    149

Medium-voltage(2)

   19,039    1,916    20,955

Special low-voltage(3)

   28,184    0    28,184

Low-voltage(4)

   5,718,999    0    5,718,999
    
  
  

Total

   5,766,368    1,919    5,768,287

(1) High-voltage is greater than 45 kV and less than or equal to 110 kV. Very high-voltage is greater than 110 kV.
(2) Medium-voltage is greater than or equal to 1 kV and less than or equal to 45 kV.
(3) Special low-voltage consumers have subscribed demands above 41.4KW and voltage levels below 1 kV. Special low-voltage customers are primarily small industrial and commercial customers.
(4) Low-voltage is less than 1 kV.

 

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     Six Months Ended June 30, 2004

Customers by voltage level


   Binding
customers


   Qualifying
consumers


   Total

High and very high-voltage(1)

   160    2    162

Medium-voltage(2)

   18,516    2,594    21,110

Special low-voltage(3)

   28,691    0    28,691

Low-voltage(4)

   5,769,672    0    5,769,672
    
  
  

Total

   5,817,039    2,596    5,819,635

(1) High-voltage is greater than 45 kV and less than or equal to 110 kV. Very high-voltage is greater than 110 kV.
(2) Medium-voltage is greater than or equal to 1 kV and less than or equal to 45 kV.
(3) Special low-voltage consumers have subscribed demands above 41.4KW and voltage levels below 1 kV. Special low-voltage customers are primarily small industrial and commercial customers.
(4) Low-voltage is less than 1 kV.

 

EDPD has experienced increased demand over the past five years in all electricity voltage levels. Considering overall demand on EDPD’s distribution network, both from binding customers and Qualifying Consumers, consumption has grown at an average annual growth rate of 4.8% from December 31, 1999 to December 31, 2003. The highest average annual growth rate during this period (6.0%) was in demand from very high—and high-voltage customers. These voltage levels experienced a 9.3% increase in demand in 2003 due to a large increase in the industrial activity of one of our largest customers, as well as a higher demand on the distribution grid from auto producers. Under current regulations, REN must purchase all surplus electricity offered by auto producers, among other independent producers, at a specified tariff through EDPD. As the auto producers may purchase electricity at a price below that at which they sell to REN, the buying and selling of electricity by auto producers has increased demand for use of the distribution grid. Demand by medium-voltage levels increased from 10,639 GWh in 1999 to 12,534 GWh in 2003, representing average annual growth of 4.2%.

 

Following the gradual decrease of the eligibility threshold between 1999 and 2003, more electricity distributed through EDPD’s network corresponds to consumption by medium-voltage qualifying consumers. As a result, electricity demand by medium-voltage binding consumers decreased from 10,639 GWh in 1999 to 8,600 GWh in 2003, whereas electricity demand by medium-voltage qualifying consumers, non-existent in 1999, increased to 3,934 GWh in 2003. Consumption by low-voltage customers, typically residential and services, increased from 17,786 GWh in 1999 to 21,513 GWh in 2003, representing average annual growth of 4.8%. The growth in low-voltage consumption during this period resulted primarily from the increase in the number of low-voltage customers from approximately 5.3 million to approximately 5.8 million, as well as an increase in annual consumption per consumer.

 

The following table shows electricity distributed in each of the last five years and the first half of 2004, separated by type of consumer.

 

     Year ended December 31,

  

Six months
ended
June 30,

2004


     1999

   2000

   2001

   2002

   2003

  
     (GWh)

Electricity distributed

                             

Very high-voltage and high-voltage:

                             

Binding customers

   3,855    4,104    4,259    4,271    4,755    2,659

Qualifying consumers

   0    83    176    182    114    27
    
  
  
  
  
  

Total very high-voltage and high-voltage

   3,855    4,187    4,435    4,453    4,869    2,686

Medium-voltage:

                             

Binding customers

   10,639    11,092    11,358    11,198    8,600    3,378

Qualifying consumers

   0    133    344    776    3,934    2,860
    
  
  
  
  
  

Total medium-voltage

   10,639    11,225    11,702    11,974    12,534    6,238

Low-voltage

   16,839    17,884    18,823    19,424    20,346    10,550

Public lighting

   947    1,010    1,065    1,080    1,167    664
    
  
  
  
  
  

Total

   32,280    34,306    36,025    36,931    38,916    20,138

 

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On a revenue basis, our Portuguese electricity sales grew from €2,938 million in 1999 to €3,546 million in 2003. The most significant increase in sales has been to low-voltage customers (typically residential and services), to whom sales increased from €2,056 million in 1999 to €2,596 million in 2003. Recent growth in revenue from electricity sales was due to expansion in consumption and average tariff increases set by the regulator of 2.8% in 2003 and 2.3% in 2002. Furthermore, the increase in revenue from electricity sales in 2001, 2002 and 2003 was also influenced by the tariff adjustment, as discussed below. The following table shows EDPD’s total domestic sales of electricity to binding customers by level of voltage required, as well as revenues from the use of distribution network, charged to Qualifying Consumers for the periods indicated.

 

     Year ended December 31,

  

Six months
ended

June 30,

2004


 
     1999

   2000

    2001

   2002

   2003

  
     (audited)    (unaudited)  
     (thousands of EUR)  

Electricity sales

                                

Very high-voltage and high-voltage

   158,887    156,049     165,957    167,827    186,467    108,058  

Medium-voltage

   722,963    749,100     772,357    783,388    615,394    250,412  

Low-voltage

   1,981,460    2,080,475     2,194,035    2,335,135    2,500,380    1,373,161  

Public lighting

   74,351    80,279     83,918    86,614    95,731    55,250  

Tariff adjustment

   0    (55,995 )   42,218    70,482    77,919    (118,324 )
    
  

 
  
  
  

Total binding customers

   2,937,661    3,009,908     3,258,485    3,443,446    3,475,891    1,668,557  

Qualifying Consumers

   0    1,152     2,788    12,939    70,485    58,254  
    
  

 
  
  
  

Total

   2,937,661    3,011,060     3,261,273    3,456,385    3,546,376    1,726,811  

 

Tariffs are fixed by the regulator in advance for each year and are based in part on estimated data for variables such as demand and cost. If there are differences between the estimated data and the data actually experienced during the period, adjustments, shown in the table above as the tariff adjustment, will be made to the tariff in a subsequent period to account for these differences. The tariff adjustment reflects our estimate of the amount that will be applied in fixing tariffs in subsequent periods as a result of these differences. Tariff adjustments represent adjustments related to EDPD’s distribution and supply activities. Due to actual consumption in 2002 and 2003 below that assumed in the setting of the 2002 and 2003 tariffs, amounts invoiced to final customers did not sufficiently compensate EDPD for the fixed amount that EDPD was required to pay for electricity acquired from REN, giving rise to a tariff adjustment in each of 2002 and 2003. For more information on the tariff adjustments, you should read “Operating and Financial Review and Prospects.”

 

The number of distribution customers per distribution employee is an important measure for EDPD. In the period from 1999 through 2003 and the first half of 2004, the number of customers per employee has increased from 586 to 910.

 

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Purchases of Electricity

 

EDPD purchases all of its electricity in the Binding Sector from REN. In 1999, the regulator established a legal framework that limits purchases of electricity by EDPD from the Non-Binding Sector, which for the 2002-2004 regulatory period is 8%. EDPD has historically purchased less than 8% of its total energy from suppliers in the Non-Binding Sector and abroad. REN must purchase, and EDPD must purchase from REN, all electricity surplus produced by Other Independent Producers. The cost of purchased electricity is passed through to customers in accordance with the regulated tariff system and is not a determining factor in EDPD’s results.

 

     Year ended December 31,

  

Six months
ended
June 30,

2004


     1999

   2000

   2001

   2002

   2003

  
     (GWh)

Electricity Purchases

                             

From Binding Sector generation

   32,483    33,915    35,282    34,801    32,307    15,117

From Other Independent Producers

   2,165    2,469    2,552    2,817    3,694    2,162

From the non-binding system (SENV)

   447    622    891    1,354    2,044    1,662
    
  
  
  
  
  

Total

   35,095    37,007    38,726    38,972    38,046    18,941

 

Distribution Losses

 

EDPD experiences technical losses of electricity which are associated with the normal use of its network and, to a far lesser extent, commercial losses of electricity due primarily to gaps between estimated meter readings and actual levels of consumption, which are usually recovered in subsequent years, with the exception of losses due to stolen energy and faulty meters. The losses are within the normal range for the types of networks employed and we expect the amount of annual losses to remain constant as a result of capital expenditures in our distribution network, although we expect an increase in consumption.

 

The following table sets forth data regarding the losses of EDPD in absolute terms and as a percentage of demand, as well as EDP’s own uses of energy for the periods indicated.

 

     Year ended December 31,

   

Six months
ended
June 30,

2004


 
     1999

    2000

    2001

    2002

    2003

   
     (in GWh, except percentages)  

Demand on the distribution network

   35,095     37,230     39,263     39,965     42,261     22,128  

Own uses of energy

   31     21     22     20     33     16  

Distribution losses

   2,756     2,875     3,183     3,008     3,259     1,704  

Distribution losses/demand on the distribution network

   7.9 %   7.7 %   8.1 %   7.5 %   7.7 %   7.7 %

 

Capital Expenditures

 

In recent years, our largest capital expenditures have been on the distribution system. EDPD is obligated by law to connect all customers who request to be linked to the PES. As a result, the largest component of capital expenditures is spent on connecting new customers, improving network efficiency and developing the network (installing new cables and new lines) to accommodate the growth in demand.

 

EDPD’s total 2003 capital expenditures in technical costs amounted to €334.7 million, of which approximately 8% are expenditures on “non-specific” administrative, technical and commercial systems and corresponding technology support infrastructure, including an installment payment of approximately €12.0million for the acquisition of an information technology system from EDINFOR. EDPD’s capital expenditures in technical costs in distribution totaled €379.0 million in 2002, €260.4 million in 2001, €234.0 million in 2000 and €231.4 million in 1999. These amounts also include amounts paid by customer

 

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contributions in cash, but do not include assets in kind contributed by customers. These in kind contributions amounted to €61.0 million in 2003, €54.1 million in 2002, €69.5 million in 2001, €52.8 million in 2000 and €57.1 million in 1999. New customers are required by current regulation to make a contribution, in cash or in kind, for connections based on factors such as the type of voltage, the amount of power to be supplied, and distance to the network. In 2003, total customer contributions, and certain amounts contributed for infrastructure improvements, amounted to approximately €120.7 million.

 

Conservation Measures

 

We have been progressively implementing a voluntary policy to promote electricity conservation in an effort to decrease the variability of the load on the system and to increase efficient use of electricity. In doing so, we have increased dissemination of information on end-use efficiency in several industrial subsectors, services and residential use. We have also launched a program of granting awards to industrial customers for successfully implementing electricity efficiency projects and have established a joint venture with other energy sector companies whose main goal is to promote energy conservation.

 

In addition, the tariff structure has been designed to promote the rational use of electricity, basing tariffs on marginal costs, which may vary by time of day or season. Large consumers with a capability to reduce demand are offered an interruptible tariff rate, which results in a discount to the consumer and helps to alleviate demand at peak times.

 

Tariffs

 

The prices we charge for electricity are subject to extensive regulation under a tariff regime that was revised in 1998, causing significant price reductions. In December 1998, the regulator implemented a new tariff regulatory code to be applied in mainland Portugal, establishing a periodic definition of regulatory parameters for tariffs and a methodology for setting tariffs. During the first regulatory period, including the years 1999-2001, and the second regulatory period, including the years 2002-2004, prices were set annually according to a series of formulae that were derived based primarily upon what was deemed to be an appropriate return on assets in transmission, a return fixed by price cap in distribution, and a return on assets and agreed costs in commercialization, i.e., the activity of supply, measurement and billing of energy sales to final clients.

 

In April 2002, the Portuguese government extended the powers of the regulator to the Portuguese archipelagos of Azores and Madeira, with the intention of leveling the higher tariffs of these island regions to comparatively lower tariffs of the mainland Portugal while providing adequate financial returns to island electricity companies. This leveling led to an incremental increase in prices charged to mainland customers, although such prices cannot increase more than inflation.

 

In the Binding Sector, distribution tariffs for customers are differentiated by voltage level, tariff option and period of electricity consumption. These tariffs, when set, are uniform throughout mainland Portugal within each level of voltage.

 

For the 2002-2004 regulatory period, the regulator has applied a four-rate tariff price structure related to the time of day for medium-, high- and very high-voltage consumers. Low-voltage consumers with subscribed demands above 20.7 kVA have a three-rate time of day structure, while low-voltage consumers with subscribed demands up to 20.7 kVA might choose between a single-rate tariff, or a day-night tariff option.

 

Producers and consumers in the Non-Binding Sector have a right to access and use the national transmission grid and our distribution network through the payment of access tariffs for the Global Use of System, the Use of the Transmission Network, the Use of the Distribution Network and Network Commercialization, which terms and conditions were established by the regulator.

 

Tariffs are set by the regulator pursuant to a periodic registration of regulatory parameters. In 1999, high-, medium-and low-voltage tariffs declined in real terms by 12.8%, 12.8% and 7.5%, respectively, from 1998

 

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levels. For 2000, in nominal terms, tariffs for all voltage levels declined by 0.6% from the 1999 levels. For 2001, in nominal terms, tariffs for all voltage levels increased, on average, by 1.2% from the 2000 levels. In November 2001, the regulator published the regulatory framework for the 2002-2004 regulatory period. For 2002, in nominal terms, tariffs increased across all voltage levels by an average of 2.2% from the 2001 levels. For 2003, in nominal terms, tariffs increased across all voltage levels by an average of 2.8% from the 2002 levels. In real terms, adjusted for inflation, very high-, high- and medium-voltage tariffs have declined by an average of 3.4% over the period 1999 to 2004. The tariffs for low-voltage customers have also declined by an average of approximately 3.1% over the same period. For 2004, in nominal terms, tariffs increased across all voltage levels by an average of 2.1% from the 2003 levels.

 

For the 2002-2004 regulatory period, the regulator considers the distribution function to consist of three business areas, which could in the future be liberalized at different times and subject to different tariff regulatory regimes: use of the distribution network, network commercialization services and commercialization of supply in the Binding Sector. The use of the distribution network area involves activities relating to investments in and the operation of the distribution grid. Tariffs applicable to the use of the distribution network are based on a price cap mechanism designed to reduce distribution tariffs on an annual basis by an average over the three years of the regulatory period, a percentage equal to the Portuguese Consumer Price Index, minus a percentage referred to as the “efficiency coefficient.” The efficiency coefficient was approximately 5% for the 1999-2001 regulatory period and is approximately 7% for the 2002-2004 regulatory period. The network commercialization area consists of activities related to meter installation, reading and the billing of all services associated with the use of the distribution network. The commercialization of supply in the Binding Sector area consists of activities directly relating to the final consumer, such as customer service, billing of final consumers in the Binding Sector and collecting payments from consumers. The tariff applicable to the network commercialization services and commercialization of supply in the Binding Sector area is based on costs accepted by the regulator plus a 9% return on assets.

 

Tariffs are also subject to an annual extra adjustment mechanism that takes into account the deviations of actual costs compared to forecasted costs used to derive tariffs for the previous one or two years. As a result, we have adopted a “tariff adjustment” in our financial statements that reflects our estimate of the amount that will be applied in fixing tariffs in subsequent periods as a result of differences between estimated and actual data. Customer tariffs for very high-voltage, high-voltage and medium-voltage are subject to quarterly adjustments, primarily to accommodate changes in fuel prices. For more information on the tariff adjustment, you should read “Distribution—Customers and Sales,” “Operating and Financial Review and Prospects” and note 39(p) to our audited consolidated financial statements.

 

According to the proposal on the parameters, tariffs and prices of electricity and other services for 2005 released by ERSE on October 15, 2004, ERSE has proposed that in 2005 the tariffs for sale to final customers in Portugal (mainland) will be increased by 2.1% in nominal terms compared to 2004. The proposal is based on certain assumptions, including an expected inflation rate in 2005 of 2% and an expected increase in the electricity consumption of 3.4% in 2005 (in mainland Portugal). In addition, in the proposal, ERSE states that the approval of a new framework law for the electric system, the termination of PPAs and the opening of MIBEL are expected to cause an extraordinary revision of the tariffs during 2005.

 

The Tariff Regulation enacted by ERSE provides that the Tariff Council of ERSE, a consulting body on tariffs and regulation, must issue its (non-binding) opinion on this proposal by November 15, 2004. Subsequently, ERSE, considering the opinion expressed by the Tariff Council, will approve the final parameters, tariffs and prices, which should be published by December 15, 2004.

 

Competition

 

Until 1988, we had a monopoly for the generation, transmission and distribution of electricity in Portugal, although a very small number of municipalities distributed low-voltage electricity to consumers. Since 1988,

 

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measures have been taken to encourage limited competition in power generation in Portugal. In 1999, the regulator implemented measures to encourage competition in the supply of electricity in Portugal. For more information on these measures, you should read “Electricity System Overview.” In addition, as a result of political and regulatory developments, especially within the context of the creation of MIBEL, we expect increased competition from Spanish electricity companies.

 

In December 2003, four qualified suppliers were authorized to operate in the Portuguese non-binding system, three of which are Spanish companies: Endesa Energia, S.A.; Iberdrola, S.A.; Union Fenosa Comercial; and Sodesa—Comercialização de Energia, S.A. See “Iberian Electricity Market” and “Spain—History and Overview.”

 

Generation

 

The existing power stations of CPPE, which in 2003 formed 89% of our generating capacity, are all part of the PES. The earnings that CPPE derives from these power stations are unlikely to be affected by competition from generators in the Independent Electricity System. In accordance with the terms of the PPAs, CPPE’s operating income is dependent on the availability of capacity and is substantially unaffected by levels of actual output. Under Portuguese law, any projects for construction of new thermal power plants in the PES must be subject to an open tender coordinated by DGGE. In the case of hydroelectric generation, all plants planned to be commissioned until 2010 are allocated by law to CPPE.

 

The PES includes two power stations that are not owned and operated by us: the Pego power plant, which was constructed and commissioned by us and later sold to Tejo Energia, and Tapada do Outeiro, which commenced full operations in 1999 and is owned and operated by Turbogás. The admission of these power stations to the PES resulted from two international tender processes coordinated by us in accordance with Portuguese government policy in effect at that time to establish competitive practice in the electricity generation sector. We expect to participate in future tender processes.

 

Subject to the issuance of generation licenses, we may construct plants that will operate in the Independent Electricity System, such as the TER CCGT plant. The first unit of the TER CCGT plant entered commercial service in early 2004. The two remaining units are expected to start operating in October 2004 and March 2006, respectively.

 

New plants in the Independent Electricity System will operate in the openly competitive market and sell power to REN under competitive offers or make bilateral contracts with REN, Non-Binding Sector customers, Binding Sector distributors or Spanish agents.

 

Because Portugal is contiguous only with Spain and there are limited connections between Spain and the rest of Europe, and because of recent political, legal and regulatory developments, we expect that a regional market on the Iberian Peninsula will develop. In January 2004, the Portuguese and Spanish governments signed a final agreement for the creation of the Iberian electricity market, which agreement was approved by the Portuguese parliament under Resolution no. 33-A/2004 of April 20, 2004 and ratified by the President of the Portuguese Republic under Decree no. 19-B/2004 of April 20, 2004. This agreement calls for, among other things, the harmonization of tariff structures, and the creation of a common pool for Portugal and Spain to be fully implemented in 2006. See “Iberian Electricity Market” and “Spain.” Accordingly, we expect to face increased competition in generation and wholesale supply from Spanish participants in the market.

 

Distribution

 

EDPD, and previously, our distribution companies, have historically held an effective monopoly over distribution. However, increases in the levels of industrial auto production have reduced the amount of electricity sold to these entities from the PES. In addition, in early 1999, the regulator implemented legislation liberalizing the electricity supply business.

 

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As of May 15, 2003, all Eligible Consumers automatically may become Qualifying Consumers. In 2003, the total number of Eligible Consumers represented approximately 45% of demand in mainland Portugal in volume terms.

 

From January 1, 2002 until February 25, 2004, all electricity consumers other than low-voltage consumers were Eligible Consumers. From February 26, 2004 to August 18, 2004, the eligibility threshold was extended to include special low-voltage consumers, and with Decree law no. 192/2004 of August 17, 2004, full liberalization of the electricity market was completed with the opening of the market to the remaining low-voltage consumers.

 

If Eligible Consumers elect to become Qualifying Consumers, EDPD will continue to receive two of the three tariff components relating to distribution.

 

SPAIN

 

History and Overview

 

The creation of an Iberian Electricity Market is the driving force behind our decision to expand our operations to Spain. In 2001, we identified Hidrocantábrico as an independent utility company that could facilitate our entry into the Spanish energy market.

 

In December 2001, we signed an agreement with EnBW, Cajastur and Cáser concerning joint control of Hidrocantábrico. The agreement of all parties is required for specified key corporate actions. Operational matters require only the consent of us and EnBW. In the event of a deadlock concerning operational matters, however, we would ultimately be able to decide the course of action, but EnBW would have a right to require us to purchase its shares in Hidrocantábrico in such an event. The appointment of Hidrocantábrico’s chief executive officer, chairman and the secretary of the board of directors requires the agreement of all three parties. If agreement cannot be reached, we would designate the chief executive officer, Cajastur would appoint the chairman and EnBW would appoint the secretary of the board of directors. Hidrocantábrico is currently 39.5% owned by us, 34.6% owned by EnBW and 24.7% owned by Cajastur and Cáser. The remaining 1.2% comprises shares owned by other shareholders and own shares held by Hidrocantábrico. As described below, in connection with the acquisition of an additional 56.2% stake in Hidrocantábrico, we have agreed to terminate this shareholders’ agreement and entered into a new shareholders’ agreement with Cajastur and Cáser in respect of Hidrocantábrico. The termination of the existing agreement and the effectiveness of the new agreement will be effective upon completion of the acquisition.

 

In March 2003, Hidrocantábrico won the auction privatization process that led to its acquisition of 62% of Naturcorp. Subsequently, Naturcorp reorganized its gas holdings, as a result of which a minority shareholder in Gas de Euskadi, another gas company controlled by Hidrocantábrico, exchanged its holding for shares in Naturcorp such that 100% of Gas de Euskadi was integrated into the Naturcorp group and Hidrocantábrico’s ownership of Naturcorp decreased from 62% to 56.8%. As part of this reorganization, Gas Natural, the minority shareholder in Gas de Euskadi, a subsidiary of Naturcorp, exchanged its 20.5% stake in Gas de Euskadi for a stake in Naturcorp. As a result of the reorganization of Naturcorp, Hidrocantábrico has become the second largest gas company in the Spanish market, with more than 500,000 customers and approximately 10% of Spain’s regulated revenues for gas distribution, or 8% of GWh of gas distributed.

 

Following completion of the rights offering and the application of its proceeds as described above in “Use of Proceeds” and “Information on the Company—Overview—Electricity,” our stake in Hidrocantábrico will be 95.7%. As described above, Cajastur and Cáser will retain interests aggregating to a 3.1% stake in Hidrocantábrico and, pursuant to a new shareholders’ agreement entered into on July 29, 2004 that will be effective upon completion of the acquisition, will have certain veto rights, especially in relation to certain matters relating to regional concerns, which will preserve Hidrocantábrico’s links with the region of Asturias. In addition, Cajastur will have a long-term put option entitling it to sell its interest in Hidrocantábrico to us at a

 

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price indexed to the value of our ordinary shares. Completion of the acquisition of the additional stake in Hidrocantábrico depends on completion of the rights offering, such that if the rights offering is terminated, we will not acquire this additional stake.

 

Market Structure

 

The two major characteristics of the Spanish electricity sector are the existence of the wholesale Spanish generation market, or Spanish pool, and the fact that any consumer is free to choose its supplier as of January 1, 2003. Competition was first introduced in the Spanish electricity market on January 1, 1998 by Law 54/1997, which provided a regulatory framework that reorganized the functioning of the market.

 

Generation facilities in Spain operate either in the “ordinary regime” or the “special regime.” Special regime generators, which comprise cogeneration and renewable energy facilities of up to 50 MW may sell their net electricity output to the system either (i) at tariffs fixed by decree, or at tariffs linked to pool prices plus a premium, that vary depending on the type of generation and are generally higher than Spanish prices, or (ii) in the Spanish pool (or by bilateral contracts), together with certain premiums and incentives. Ordinary regime generators provide electricity to the Spanish pool and by bilateral contract to consumers and liberalized suppliers at market prices.

 

Companies with the capability to sell and buy electricity may participate in the Spanish pool. Electricity generators sell electricity in the pool and the regulated electricity distributors, suppliers in the liberalized, or unregulated, market and consumers that are permitted to participate in the pool, or qualified consumers, buy electricity in this pool. Foreign companies or consumers that have foreign agent status may also sell and buy in the Spanish pool. The market operator and agency responsible for the market’s economic management and bidding process is OMEL.

 

In addition to selling electricity to regulated consumers (customers that are subject to a regulated final tariff and are not qualified consumers), transmission companies and regulated distributors must provide network access to all suppliers and qualified consumers that have chosen to be supplied in the liberalized market. However, qualified consumers must pay an access tariff to the distribution companies if such access is provided. At the beginning of each year, the Spanish government sets both the final and access tariffs. By Royal Decree no. 1802/2003, the Spanish government established the electricity tariffs for 2004.

 

Liberalized suppliers are free to set a price to qualified consumers. These entities’ main direct activity costs are the wholesale market price and the regulated access tariffs to be paid to the distribution companies. Electricity generators and liberalized suppliers or consumers may also engage in bilateral contracts without participating in the wholesale market.

 

Generation

 

Hidrocantábrico’s installed capacity represents 4.7% of Spain’s mainland generation capacity, or 5.5%, excluding special regime facilities (which are generally cogeneration and renewable energy facilities). In 2003, Hidrocantábrico had a total installed capacity of 2,820 MW, approximately 56.9% of which are coal-fired facilities, 13.9% a CCGT facility, 16.1% hydroelectric facilities, 1.3% cogeneration facilities and 5.9% renewable energy facilities other than special regime hydroelectric. Hidrocantábrico also holds a 15.5% interest in the Trillo nuclear power plant that accounts for 165 MW of the plant’s total installed capacity of 1,066 MW.

 

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The following table sets forth Hidrocantábrico’s total installed capacity by type of facility at year-end 2001, 2002 and 2003 and as of June 30, 2004.

 

     As of December 31,

  

As of
June 30,

2004


Type of facility


   2001

   2002

   2003

  
     (MW)

Hydroelectric:

                   

Hydroelectric—Ordinary regime

   408    413    432    432

Hydroelectric—Special regime(1)

   23    23    23    23
    
  
  
  

Total hydroelectric

   431    436    455    455

Thermal:

                   

Coal

   1,588    1,588    1,605    1,604

CCGT

   0    393    393    393

Nuclear

   165    165    165    166
    
  
  
  

Total Thermal

   1,753    2,146    2,163    2,163

Cogeneration(2)

   38    41    37    33

Wind(2)

   24    30    129    129

Biomass(2)

   3    5    6    3

Waste(2)

   13    13    30    34
    
  
  
  

Total

   2,262    2,671    2,820    2,816

(1) Includes 19.15 MW related to Hidrocantábrico’s 48.86% stake in Hidraulica de Santillana (39.2 MW).
(2) In the case of projects owned by SINAE, these figures represent SINAE’s stake in each project’s installed capacity. Hidrocantábrico owned 60% of SINAE in 2001 and 2002, and 80% in 2003 and during the first half of 2004. For more information on SINAE, see “Special Regime Generation” below.

 

The following table sets forth Hidrocantábrico’s thermal plants.

 

Thermal plants


   Installed
capacity
(MW)


   Fuel

   Year
entered
into
service


Coal

              

Aboño

              

Unit I

   366    Coal    1974

Unit II

   556    Coal    1985

Soto de Ribera

              

Unit I

   68    Coal    1962

Unit II

   254    Coal    1967

Unit III

   361    Coal    1984

Nuclear

              

Trillo

   165    Uranium    1988

CCGT

              

Castejón

   393    Natural Gas    2002
    
         

Total installed capacity

   2,163          

 

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The following table sets forth Hidrocantábrico’s hydroelectric plants in the ordinary regime:

 

Hydroelectric plants


   Installed
capacity
(MW)


   River
reservoir
plant type


   Year
entered
into
service


   Year of last
major
refurbishment


La Malva

   9.14    Reservoir    1917/24    2002

La Riera

   7.83    Run of river    1946/56    2001

Miranda

   73.19    Run of river    1962    2000

Proaza

   50.33    Reservoir    1968    2002

Priañes

   18.50    Reservoir    1952/67    2003

Salime

   78.99    Reservoir    1954    2003

Tanes

   125.46    Reservoir    1978    1995

La Barca

   55.72    Reservoir    1967/74    2002

La Florida

   7.60    Reservoir    1952/60    1998

Laviana

   1.10    Run of river    1903    2001

Caño

   1.00    Run of river    1928    1996

San Isidro

   3.12    Run of river    1957    2002
    
              

Total installed capacity

   431.98               

 

The average remaining useful life of Hidrocantábrico’s hydroelectric generation plants is approximately 47 years.

 

Since hydroelectric generation is dependent on hydrological conditions, for forecasting model purposes the estimated Hidrocantábrico hydroelectric production based on current installed capacity in an average year is 806 GWh, ranging from a maximum of 1,058 GWh in a wet year to a minimum of 590 GWh in a dry year.

 

Generation activity in 2003 was characterized by high availability and efficiency of, and high production by, Hidrocantábrico’s power plants, together with lower pool prices than in 2002 due to the higher hydro availability in the Spanish power system. Hidrocantábrico’s generation in the ordinary regime, excluding its own or ancillary consumption, rose 4.8% from 13,503 GWh in 2002 to 14,155 GWh in 2003 (out of a total generation in the Spanish market in 2003 of approximately 190.4 TWh, according to OMEL), of which hydroelectric generation represented 861 GWh, an increase of 11.7% from 2002. Coal-fired thermal generation amounted to 10,491 GWh in 2003, a reduction of 4.6% from 2002 due to a wet year. Nuclear generation, in respect of the 15.5% stake in the Trillo plant, amounted to 1,257 GWh in 2003, an increase of 3.7% from 2002. Natural gas-fired thermal generation amounted to 1,546 GWh in 2003, a threefold increase from 2002 due to the full-year operation, in 2003, of the new Castejón CCGT that commenced electricity production in October 2002.

 

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The following table summarizes Hidrocantábrico’s electricity generation for 2001, 2002 and 2003 and the first half of 2004, excluding losses at generation plants and Hidrocantábrico’s own or ancillary consumption, and sets forth the hydroelectric coefficient at year-end 2001, 2002 and 2003 and as of June 30, 2004.

 

     Year ended December 31,

   Six
months
ended
June 30,
2004


Type of facility


   2001

   2002

   2003

  
     (in GWh, except by hydroelectric
coefficient factor)

Hydroelectric:

                   

Hydroelectric—Ordinary regime(1)

   867    771    861    544

Hydroelectric—Special regime

   78    41    86    56
    
  
  
  

Total hydroelectric

   945    812    947    600

Thermal:

                   

Coal

   9,832    10,997    10,491    5,052

Natural Gas

   0    522    1,546    905

Nuclear(2)

   1,222    1,212    1,257    568

Cogeneration

   78    110    114    56
    
  
  
  

Total thermal

   11,132    12,841    13,408    6,581

Wind

   59    61    119    145

Biomass

   24    28    32    7

Waste

   11    44    81    67
    
  
  
  

Total

   12,171    13,786    14,587    7,399

Hydroelectric coefficient(3)

   1.080    0.96    1.068    1.165

(1) Includes the following amounts of consumption for hydroelectric pumping: 140 GWh in 2001, 131 GWh in 2002 and 127 GWh in 2003.
(2) Corresponding to 15.5% of Trillo’s generation.
(3) The hydroelectric coefficient varies based on the hydrological conditions in a given year. A hydroelectric coefficient of one corresponds to an average year, while a factor less than one corresponds to a dry year and a hydroelectric coefficient greater than one corresponds to a wet year.

 

The average availability for production of Hidrocantábrico’s power plants increased from 94.21% in 2002 to 95.68% in 2003 for thermal plants and decreased from 89.26% in 2002 to 87.71% in 2003 for hydroelectric plants. Hidrocantábrico’s forced outages in 2003 were 1.58% at thermal plants and 1.88% at hydroelectric plants.

 

The table below sets out for each type of Hidrocantábrico generating facility the average capacity utilization and the average availability factor for 2002 and 2003 and the first six months of 2004.

 

     Average capacity utilization(1)

   Average availability factor

     Year ended December 31,

   Six
months
ended
June 30,
2004


   Year ended December 31,

   Six
months
ended
June 30,
2004


Type of facility


   2001

   2002

   2003

      2001

   2002

   2003

  

Hydroelectric

   24.56%    21.66%    23.12%    29.26%    93.21%    89.26%    87.71%    95.86%

Thermal:

                                       

Coal

   74.97%    83.79%    78.75%    76.13%    93.80%    93.94%    95.73%    94.61%

Natural gas(2)

   0%    47.31%    46.55%    54.59%    0%    97.19%    96.26%    96.89%

Nuclear

   90.35%    89.57%    92.95%    84.13%    90.67%    89.66%    93.85%    85.82%
    
  
  
  
  
  
  
  

Total weighted average thermal(3)

   76.42%    81.75%    73.98%    72.83%    93.51%    94.21%    95.68%    94.35%

(1) The average capacity utilization is defined as actual production as a percentage of theoretical maximum production.
(2) Hidrocantábrico’s natural gas fueled CCGT plant began operations in 2002.
(3) Weighted average is based on total installed capacity of the thermal system.

 

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Although Hidrocantábrico experienced increased production and plant efficiency, in terms of plant availability, in 2003, prices decreased in the Spanish electricity market due to very favorable hydrological conditions. This led to increased hydroelectric production, which adversely affected operating results of Hidrocantábrico’s generation activity in 2003.

 

Planned outages in 2003 occurred as a result of maintenance on the Aboño Unit 1, Soto Unit 2 and Castejón power plants, as well as a refueling outage in the Trillo nuclear power plant. Hidrocantábrico’s generation facilities benefited from several environmental improvements and equipment upgrades. Hidrocantábrico has improved its systems and management procedures through the integration of several functions and processes, including technical, administrative and purchasing processes.

 

Thermal generation consumed 3,865 thousand metric tons of coal in 2003, 73.4% of which was imported and 26.6% domestic. Fuel consumption costs including transportation amounted to €211 million in 2003 and €198.4 million in 2002, representing approximately 79.6% and 77.3%, respectively, of Hidrocantábrico’s total consolidated operating expenses. Despite the fact that 2003 was a wetter year than 2002, Hidrocantábrico’s fuel costs increased due to the full-year operation in 2003 of Hidrocantábrico’s new CCGT plant at Castejón that started commercial operation in September 2002. Castejón’s gas cost was the main cause of the fuel cost increase that occurred during 2003.

 

As a result of its increased thermal production, Hidrocantábrico’s market share in the Spanish pool rose from 7.5% in 2002 to 7.6% in 2003. Hidrocantábrico generating plants sell all their electricity output into the Spanish pool at very competitive prices.

 

In 2003, capital expenditures on generating facilities amounted to €93.9 million, an increase of 8.18% from 2002. These expenditures are set forth below.

 

     Year ended December 31,

  

Six

months
ended

June 30,

2004


Plant type and status


   2001

   2002

   2003

  
          (audited)         (unaudited)
     (thousands of EUR)

Hydroelectric plants in operation

   1,106    1,428    2,107    352

Thermal plants in operation

   9,801    65,082    20,151    10,156

Plants under construction

   101,776    0    0    224

Special regime:(1)

                   

Hydroelectric plants in operation

   3    2    0    0

Wind

   6,147    16,264    49,047    92,752

Waste

   698    2,067    3,500    3,316

Biomass

   2,194    1,120    350    225

Cogeneration facilities

   1,339    814    18,720    2,625
    
  
  
  

Total Generation

   123,064    86,777    93,875    109,650

(1) Excludes capital expenditures of H. Santillana, a company in which we hold in minority stake. Data corresponding to SINAE, a 60%-owned subsidiary of Hidrocantábrico as of December 31, 2001 and 2002, respectively, and an 80%-owned subsidiary of Hidrocantábrico as of December 31, 2003 and June 30, 2004, represents 100% of capital expenditures of SINAE and its subsidiaries. For more information on SINAE, see “Special Regime Generation” below.

 

Hidrocantábrico is planning to develop three CCGT plants as set forth in the table below:

 

Facility


   Type of
generation


  

Developing entity


   Planned
capacity
(MW)


   Target
year


   Status

Soto

   CCGT   

Contratación de Construcción y Servicios

   400    2007    Licensing Process

Castejón 2

   CCGT   

Contratación de Construcción y Servicios

   400    2006    Licensing Process

Cadiz

   CCGT   

Contratación de Construcción y Servicios

   400    2008    Licensing Process

 

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Special Regime Generation

 

Special regime generation is developed by Hidrocantábrico through Genesa, a 80%-owned subsidiary, which mainly focuses on cogeneration and wind power. Throughout 2003, Hidrocantábrico worked on the restructuring of this business’s shareholdings and industrial activities, with the objective of providing a basis for stable and sustained development focusing on the promotion, operation and management of renewable energy sources, mainly wind power. As part of this restructuring, on July 31, 2004, Hidrocantábrico merged its subsidiaries, Genesa and Sinae to form a new company, Genesa I, which was subsequently renamed Genesa. In respect of operations, delays in the launching of some projects resulted in a lower contribution than previously anticipated from Hidrocantábrico’s renewable energy business, as did the high natural gas prices that reduced cogeneration margins, one of the main activities of this business.

 

During 2003, we commenced the construction of the 124 MW Campollano wind farm in Albacete. The construction of the 65 MW Parques Eólicos del Cantábrico in Asturias (including the Cuesta 8MW, the Los Lagos 39 MW and the Acebo 18MW wind farms) and the 34 MW Parque Eólico Arlazón wind farm in Burgos were concluded and all commenced operations in 2003, with the exception of the Acebo wind farm, which went into production in January 2004. Additionally, the 20MW Sierra del Cortado wind farm began operating in 2003. The waste plant of Sinova at Soria, with an installed capacity of 16.3 MW, started operations at the end of 2003.

 

Hidrocantábrico is planning to develop the following wind farms:

 

Facility


   Type of
Generation


   Planned
Capacity
(MW)


   Target
Year


   Status

P.E. Cruz del Hierro (improvements)

   Wind    5.3    2004    In construction

P.E. Albacete

   Wind    124.1    2004    In construction

P.E. Madero (improvements)

   Wind    33    2005    Planning

P.E. Curiscao-Pumar

   Wind    87.8    2005    Planning

P.E. Brújula

   Wind    73.5    2005    Planning

P.E. Las Lomillas

   Wind    49.5    2005    Planning

P.E. Carondio

   Wind    41.6    2006    Planning

P.E. Avila Oeste

   Wind    68.0    2006    Planning

P.E. Munera I & II

   Wind    70    2006    Planning

P.E. Medinaceli

   Wind    40    2007    Planning

P.E. Avila Oeste

   Wind    68.0    2007    Planning

P.E. Burgos Este

   Wind    111    2007    Planning

P.E. San Roque

   Wind    24    2008    Planning

P.E. La Dehesica

   Wind    28    2008    Planning

 

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Distribution and Supply

 

Electricity Distribution

 

Hidrocantábrico has a network infrastructure that covers the regions of Asturias (accounting for the vast majority of its network), Valencia, Madrid and Alicante, totaling 19,147 km as follows:

 

Distribution lines


   Km

Overhead lines:

    

High-voltage (50/132kV)

   1,211

Medium-voltage (5/10/16/20/22/24 kV)

   4,493

Low-voltage (<1kV)

   11,089

Total overhead lines

   16,793

Underground cables:

    

High-voltage (50/132kV)

   7

Medium-voltage (5/10/16/20/22/24 kV)

   919

Low-voltage (1kV)

   1,428

Total underground cables

   2,354
    

Total

   19,147

 

Electricity distributed in 2003 through Hidrocantábrico’s own network amounted to 8,659 GWh, a 3.4% increase from 2002 levels. As of December 31, 2003, Hidrocantábrico had 561,208 customers out of a total number of consumers of 22,935,663, according to the Comisión Nacional de Energia, representing a 2.2% increase from 2002 and includes 1,468 qualified consumers that previously had been supplied by non-regulated suppliers. Since January 1, 2003, every consumer in Hidrocantábrico’s market can elect to be supplied by non-regulated suppliers. In 2003, there were a total of 28,703,579 consumers in Iberia according to the Portuguese DGGE and the Spanish Comisión Nacional de Energia.

 

In 2003 and the first six months of 2004, the volume of electricity distributed and the number of customers by voltage level was as follows:

 

     2003 Sales and Customers

Distribution by level of voltage


   GWh

   % annual increase
(decrease) from
2002


    Total
customers


High and very high-voltage(1)

   5,520    0 %   19

Medium-voltage(2)

   991    19 %   690

Low-voltage(3)

   2,148    6 %   560,499
    
        

Total

   8,659    3 %   561,208

(1) High-voltage is greater than 36 kV and less than or equal to 145 kV. Very high-voltage is greater than 145 kV.
(2) Medium-voltage is greater than or equal to 1 kV and less than or equal to 36 kV.
(3) Low-voltage is less than 1 kV.

 

    

Sales and Customers as of

June 30, 2004


Distribution by level of voltage


   GWh

   % annual increase
(decrease) from
June 30, 2003


    Total
customers


High and very high-voltage(1)

   2,846    6 %   20

Medium-voltage(2)

   512    6 %   728

Low-voltage(3)

   1,167    10 %   566,664
    
        

Total

   4,525    7 %   567,412

(1) High-voltage is greater than 36 kV and less than or equal to 145 kV. Very high-voltage is greater than 145 kV.
(2) Medium-voltage is greater than or equal to 1 kV and less than or equal to 36 kV.
(3) Low-voltage is less than 1 kV.

 

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During 2003, Hidrocantábrico’s distribution business, Hidrocantábrico Distribución Eléctrica, S.A.U., continued its expansion outside of Asturias in the autonomous communities of Madrid, Valencia and Alicante, all of which are geographic areas with strong economic activity. The operating results of the distribution business in 2003 increased from 2002 as a consequence of connecting new substations in Valencia and Alicante, which also reduced the initial launching activity expenses outside of Asturias.

 

In 2003, Hidrocantábrico continued to improve technical and operational management activities. The networks and facilities were enlarged and Hidrocantábrico continued the development of information technology and automation of the distribution network.

 

Gas Distribution

 

Gas invoiced in 2003 to the regulated market amounted to 4,370 GWh, representing a 199% increase from 1,464 GWh in 2002, due to the contribution of Naturcorp. Additionally, the volume of gas distributed in the liberalized market (in which we provide third-party access to our network) reached 5,257 GWh. The total number of gas consumers that are connected to Hidrocantábrico’s distribution network increased from 157,051 in 2002 to 542,794 in 2003, out of a total number of consumers of 5,295,362, according to the Comisión Nacional de Energia. The acquisition of Naturcorp added 372,364 customers. Hidrocantábrico’s gas distribution activities revenues of €157.0 million in 2003 compared with €55.6 million in 2002, the increase primarily reflecting the acquisition of Naturcorp. In 2003, Hidrocantábrico had 9% of the 6,053,669 gas consumers in Iberia. (According to Galp Energia there were 758,307 consumers in Portugal in 2003 and according to the Comisión Nacional de Energia there were 5,295,362 consumers in Spain in 2003.)

 

Electricity and Gas Supply

 

The energy supply activity performed by Hidrocantábrico Energía, S.A.U., or Hidrocantábrico Energía, includes the supply of electricity to qualified consumers. Hidrocantábrico Energía invoiced 4,712 GWh of electricity supply in 2003, with revenues of €394.3 million in 2003, compared to €241.8 million in 2002. This figure represents 6.5% of the liberalized market. More than 74% was supplied outside of Hidrocantábrico’s traditional market.

 

In 2003, Hidrocantábrico Energía successfully participated in the annual auction of the RENFE electricity contract, the Spanish railroad and the biggest electricity consumer currently in the market. Hidrocantábrico Energía won 28% of the 2003 and 2004 supply contracts.

 

In 2003, Hidrocantábrico Energía continued its natural gas supply service that began in 2002. Since August 1, 2003, Naturcorp has been included in reported results of gas supply. Taking Naturcorp into account, Hidrocantábrico has entered into 474 contracts and invoiced 5,711 GWh.

 

Other Activities

 

Telecommunications

 

In 2003, Hidrocantábrico’s cable telecommunications business continued its development through two subsidiaries, which are the concessionaires of television, fixed line telephony and internet for Asturias, Telecable de Asturias, S.A.U., or Telecable, and for Castilla y León, Retecal, Sociedad Operadora de Telecomunicaciones de Castilla y León, S.A., or Retecal. Telecable is 100%-owned by Sociedad Promotora de las Telecommunicaciones en Asturias, S.A., which is 45.95%-owned by Hidrocantábrico. Retecal is 34.96%-owned by Hidrocantábrico.

 

As of December 31, 2003, there were a total of 732,700 cabled homes and 189,982 customers for both subsidiaries, an increase of 17% from 2002. Telecable adopted a new network technology that allows voice over Internet Protocol (VoIP) services, deployed a television infrastructure improving image and sound quality, rolled out its cable network to the city of Pravia and moved its technical teams to its new headquarters at the Gijón City Technological campus.

 

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Hidrocantábrico increased its shareholding position in Retecal from 30.99% in 2002 to 34.96% in 2003, as a consequence of a share exchange of its participation in TV Castilla-León, which resulted in receipt of additional Retecal shares. The transmission network among its 17 urban networks was finished, as was the fiber optics interconnection between León and Oviedo. Telecable revenues were €49.1 million in 2003, compared to €35.5 million in 2002. Retecal revenues were €49.6 million in 2003, compared to €45.9 million in 2002.

 

On October 20, 2004, Hidrocantábrico announced that it had reached an agreement with Grupo Corporativo Ono for the sale of its total shareholding position of 34.96% in Retecal, having enacted the corresponding sale and purchase notarial deed on that day. The cash proceeds from this sale amounted to €57.5 million, while the book value of the shareholding position was €32.8 million.

 

Research and Development

 

Research and development activities carried out in 2003 were aimed at the reduction of emissions, treatment of by-products, maintenance and the extension of equipment life at various plants and were conducted in coordination with various universities and industry groups and were partially subsidized by the Spanish government and European Union entities.

 

BRAZIL

 

Overview

 

Brazil’s electricity industry is organized into one large interconnected electricity system, which is known as the Sistema lnterligado Nacional, or the Brazilian SIN, comprised of electricity companies in the southern, southeast, central-western, northeast and parts of the northern regions of Brazil, and several other small, isolated systems. Generation, transmission, distribution and supply activities are legally separated in Brazil.

 

In 2003, Brazil had a total installed capacity of 77,321 MW, of which approximately 86% was hydroelectric and 14% was thermoelectric. In addition, in order to satisfy its electricity requirements, Brazil imported 8,078 MW of electricity in 2003. Centrais Elétricas Brasileiras S.A.—Eletrobrás, or Eletrobrás, a company controlled by the Brazilian government, owns approximately 32.57% of the installed generating capacity within Brazil. Eletrobrás has regional subsidiaries responsible for generation and transmission of electricity: Centrais Elétricas do Norte do Brasil S.A.—Eletronorte and Companhia Hidroelétrica do São Francisco—CHESF in the north and northeast of Brazil, Furnas Centrais Elétricas S.A. in the southeast and central-west of Brazil and Centrais Elétricas do Sul do Brasil S.A.—Eletrosul in the south of Brazil. In addition, Eletrobrás controls Eletrobrás Termonuclear S.A.—Eletronuclear.

 

In addition to the government-owned entities at the federal level, certain Brazilian states have government-owned entities involved in the generation, transmission and distribution of electricity. They include among others, Companhia Energética de São Paulo—CESP, Companhia Paranaense de Energia—COPEL and Companhia Energética de Minas Gerais—CEMIG. With regard to distribution activity, most of the former state-owned companies were privatized and, in 2003, private companies distributed more than 70% of the distributed electricity in Brazil.

 

Our electricity operations in Brazil consist of distribution, generation and related activities. The following of our Brazilian subsidiaries are engaged in distribution:

 

  Bandeirante Energia S.A., or Bandeirante, in São Paulo;

 

  Espirito Santo Centrais Eléctricas S.A., or Escelsa, in the state of Espirito Santo; and

 

  Empresa Energética do Mato Grosso do Sul S.A., or Enersul, in the state of Mato Grosso do Sul.

 

In generation, we participate in the following companies:

 

  FAFEN Energia S.A. in the state of Bahia;

 

  Investco (Lajeado plant) in the state of Tocantins, through EDP Lajeado S.A.; and

 

  Enerpeixe S.A. (under construction), in the state of Tocantins.

 

Our related businesses comprise our trading businesses, which are concentrated in Enertrade S.A.

 

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In recent years the electricity sector in Brazil has been adversely affected by internal and external economic circumstances related to Brazil in general and by problems specific to the electricity sector. The Brazilian economy was affected by the worldwide economic slowdown in recent years, and, in 2002, uncertainty inside and outside Brazil surrounding the October presidential elections. As a result, there was a sharp depreciation in the value of the real against other major currencies and increases in Brazilian inflation and interest rates. These conditions led to a scarcity of financing sources, which adversely affected the industrial sectors of the Brazilian economy including the electricity sector.

 

In addition to these adverse economic circumstances, in recent years electric utility companies in Brazil have had to contend with a government imposed rationing program that was in effect from June 2001 until February 2002, low wholesale prices in the wholesale electricity market, or the MAE, and uncertainties regarding the electricity sector’s regulations and framework.

 

In 2003, the main events affecting the Brazilian electric utility industry were: (i) the macroeconomic turnaround in the country; (ii) the good hydrological conditions in the main consumption markets (except the Northeast region); (iii) the substantial increase in the installed capacity, mainly due to investments started in the previous periods; and (iv) the moderate consumption growth despite the nearly zero economic growth. As a result, the electric sector in 2003 was characterized by energy oversupply. While the installed capacity increased on average 5% from 2000 to 2003, the consumption in 2003 was lower than in 2000.

 

We continue to carry out a restructuring plan in Brazil. On October 31, 2002, we completed the first stage of the restructuring, which put our interests in the following companies under the direct control of EDP Brasil S.A., our holding company for Brazil, or EDP Brazil: Energest S.A., Enertrade Comercializadora de Energia S.A., Bandeirante Energia S.A., EDP Lajéado S.A., FAFEN Energia S.A. and Enerpeixe S.A. On December 31, 2003, EDP Brazil took the control of IVEN S.A., or IVEN, the company that directly controls Escelsa and indirectly controls Enersul. In connection with this process, EDP Brazil merged Calibre Participações S.A., 135 Participações S.A., EDP 2000 Participações Ltda, and EDP Investimentos Ltda. Following the reorganization of the IVEN holding, EDP Brazil owns a 69.55% stake in the voting shares and a 23.99% stake in IVEN’s total capital. The main goals of this transaction were to simplify the shareholding structure and to eliminate tax inefficiencies. In furtherance of our Brazilian shareholding restructuring process, we expect EDP Brazil to take control of the remaining shares of IVEN owned by EDP Group during 2004.

 

Another action taken was the merger of Enerpro into Energest, consolidating in Energest all activities concerning the development and implementation of generation projects, and also engineering, operation and maintenance services for the generation business units in Brazil.

 

Generation

 

EDP Lajeado

 

In late 1997, EDP Brazil formed a consortium with three Brazilian distribution companies that were awarded a 35-year concession to build a dam and operate a hydroelectric power plant in Lajeado, Brazil. We own 14.36% of the shares and 27.65% of the voting rights in Investco, the company that operates the plant. EDP Lajeado owns the right to sell 27.37% of the energy generated by the Lajeado hydroelectric power plant. Of the total energy generated, 24.75% can be freely traded with other electricity market agents, while the remaining energy must be sold at regulated prices to distribution companies. The Lajeado hydroelectric power plant began full operation in November 2002, following the completion and commissioning of its fifth unit, and has an installed capacity of 902.5 MW. The plant produced 4,457 GWh in 2003.

 

On December 30, 2003, Investco, a company that operates the Lajeado plant and of which EDP Lajeado owns 14.36% of the shares and 27.65% of voting rights, did not redeem part of the Redeemable Shares Class R from Eletrobras scheduled to be redeemed at that time because it did not have sufficient retained results from

 

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previous years as required under Brazilian Law. Discussions are under way between Investco and Eletrobas in order to find alternatives to resolve the situation. The shares not redeemed amount to approximately 150 million reais (€39.2 million).

 

With regard to EDP Lajeado, EDP Brazil recorded a provision of 90 million reais (€26 million at the time of the charge) in 2003. EDP Brazil’s trading company, Enertrade, entered into a PPA to acquire electricity produced by the Lajeado plant and entered into PPAs with EDP Brazil’s distribution companies with respect to such electricity. At the time these PPAs were entered into, the electricity price permitted under tariff regulations was higher than under regulations subsequently issued by ANEEL, but before ANEEL’s approval of the PPAs. Enertrade contested ANEEL’s decision and obtained an injunction permitting it to charge prices set forth in the PPAs until there is a decision on the merits. However, EDP Brazil’s distribution companies have not yet obtained such an injunction despite contesting ANEEL’s decision and are, therefore, prohibited from passing on to customers the prices in the PPAs. Given the current situation, EDP has recorded a provision for future losses.

 

Couto Magalhães

 

In November 2001, a consortium 49%-owned by EDP Brazil and 51%-owned by Grupo Rede was awarded a concession to build and operate a 150 MW hydroelectric power plant on the Araguaia River in Brazil, the Couto Magalhães power plant. The construction of the project was expected to start in 2003 and its operations during 2006. The project was interrupted due to additional environmental requests by regulators that were not agreed to in the original concession contract, which led to increasing development costs and postponing the start-up of construction, as well as plant operations. These requests negatively impact the economic viability of the project. The consortium has informally requested rescission by the regulator of the concession contract and is now waiting for a formal response.

 

Peixe Angical

 

In June 2001, a consortium 95%-owned by EDP Brazil and 5%-owned by Grupo Rede was awarded a concession to build and operate a 450 MW hydroelectric power plant on the Tocantins River in Brazil, the Peixe Angical power plant. The annual concession rent is 6.8 million reais (€1.8 million) for 29 years starting in the seventh year of the 35-year concession. After a one-year suspension, construction of the plant was reinitiated in October 2003, following the completion of an agreement between us and Eletrobrás and BNDES. The agreement included an equity participation of 40% of Furnas and funding of 670 million reais (€175 million) approved by BNDES, reducing the amount to be supported by us. At the end of 2003, we had invested 204 million reais (€72 million) in this project. Plant operations are planned to begin in 2006.

 

FAFEN Energia

 

The first phase of the FAFEN Energia thermoelectric plant in the Bahia state of Brazil began on August 25, 2002, with an installed capacity to produce 54 MW of electricity and 152 tons per hour of steam. From that capacity, the plant has to produce 22 MW and 42 tons per hour of steam under a tolling regime for Petrobras–Petróleo Brasileiro S.A. EDP Brazil has an 80% participation in the venture, and Petrobras holds the remaining 20%. Its second phase configuration will include an additional gas turbine of 26.7 MW and a steam turbine of 53 MW. The construction was initiated in March 2003 and should be completed during 2004. It is estimated that following completion of the second phase, the plant will produce a total of 133 MW of electricity and 42 tons per hour of steam. In 2003, FAFEN Energia produced 173,902 MWh and 352,603 tons of steam. At the end of 2003, we had invested 269 million reais (€83 million) in this project.

 

In respect of FAFEN Energia, in 2003, EDP Brazil recorded a provision of 139 million reais (€40 million at the time of the charge) due to the unlikelihood of FAFEN Energia selling energy at prices equivalent to the normative value for thermal plants, i.e., the regulated tariff for electricity from thermal plants. When the decision was made to invest in the FAFEN Energia plant, electricity price estimates were based on the normative value for

 

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thermal plants. In 2002, Bandeirante and FAFEN Energia signed a PPA based on such estimated value. The PPA was subject to approval by ANEEL, which was denied because FAFEN Energia had not complied with all of the conditions set out in Brazil’s Thermal Plant Priority Program, which provides for the sale of electricity at the normative value for thermal plants. Subsequently, FAFEN Energia and Bandeirante entered into a new PPA. The new PPA uses as a reference, in accordance with conditions set by ANEEL for its approval, the normative value of hydroelectric plants, which is considerably lower than the price previously expected. The new PPA was approved by ANEEL in June 2004. As a result of the foregoing, EDP Brazil recorded this provision for future losses.

 

Distribution

 

In 2003, our distribution companies in Brazil served more than 2.9 million customers, distributed 21,424 GWh of electricity and had revenue of 3.2 billion reais (€919.8 million).

 

     Year Ended December 31, 2003

Company


   Customers
(thousands)


   GWh
Distributed


   Revenue
(thousands
of reais)


   Revenue
(thousands
of euros)


Bandeirante

   1,320    11,380    1,674,395    484,069

Escelsa

   968    7,187    943,697    272,824

Enersul

   614    2,857    563,586    162,933
    
  
  
  

Total

   2,902    21,424    3,181,678    919,826

 

In the first six months of 2004, our distribution companies in Brazil served more than 2.9 million customers, distributed 11,120 GWh of electricity and had revenue of 1.7 billion reais (€486.9 million).

 

Company


   Customers
(thousands)


   GWh
Distributed


   Revenue
(thousands
of reais)


   Revenue
(thousands
of euros)


Bandeirante

   1,348    6,038    937,141    257,690

Escelsa

   978    3,563    499,610    137,380

Enersul

   626    1,519    333,806    91,788
    
  
  
  

Total

   2,951    11,120    1,770,557    486,858

 

Bandeirante

 

EDP Brazil holds a 96.50% stake in the share capital of Bandeirante, a distribution company in the Brazilian state of São Paulo that, in 2003, served more than 1.32 million customers.

 

In 2003, Bandeirante sold 9,539 GWh, a 6% decrease from 2002, primarily due to consumption decreases in the industrial segment. Consumption in the residential segment represented 22.4% of total sales volume, an increase of 0.8% from 2002. Consumption in the industrial segment represented 54.8% of total sales volume, a decrease of 12.8% from 2002, reflecting the loss of liberalized customers to other energy suppliers. Consumption in the commercial segment represented 12.4% of total sales volume, an increase of 4.5% from 2002. In the other segments, which represent 10.5% of total sales volume, the consumption increase was 8.2% from 2002. Taking into account electricity distributed to liberalized customers, which pay Bandeirante a fee for use of its distribution grid, Bandeirante distributed 11,380 GWh in 2003, a 4.2% increase from 2002.

 

On October 23, 2003, Bandeirante’s tariffs were adjusted as part of a periodic tariff review resulting in an increase of 18.08% over the period from 2004-2008, of which 14.68% will be applied during the first year and the remaining 3.4% will be applied over the next three annual tariff readjustment processes.

 

In 2003, Bandeirante made capital expenditures of 136 million reais (€39.3 million) with a focus on modernization, customer service, improvement of the network’s operational conditions in expanding regions and

 

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increases in the electricity grid’s operational flexibility. As part of a program of modernization, 50 million reais (€15 million) was spent in 2003, including expenditures relating to a new operations center and in the new commercial information system.

 

In order to improve productivity, Bandeirante has been encouraging its employees to adopt procedures that build a creative and innovative culture that is focused on results and responsive to customers and the market. In 2003, Bandeirante reduced its workforce to 1,261 employees, achieving a customer per employee ratio of 1,050.

 

At the end of March 2003, the company raised 200 million reais (€55 million at the time of the issue) through the issuance of 6-month promissory notes. In September 2003, the company issued new promissory notes in amount of 180 million reais (€53 million at the time of the issue) to refinance the notes issued in March 2003.

 

At the end of 2003, Bandeirante’s board of directors approved a long-term loan of U.S.$100 million from the Inter-American Development Bank to finance the expansion of the distribution grid and to improve the general quality of services.

 

On October 22, 2004, we announced that the Brazilian electricity regulator, ANEEL, had decided to amend the average electricity tariff increase granted to Bandeirante as part of the October 23, 2003 tariff review from 18.08% to 10.51%. Despite the provisional status of this review (the definitive asset base and tariff impact is to be decided and communicated by ANEEL in connection with the October 23, 2005 tariff adjustment), we have opted to book the retroactive effects of this measure (covering the period from October 23, 2003 through October 23, 2004) already in our financial statements for the third quarter of 2004. The impact of this adjustment on Bandeirante’s results before taxes in 2004 is estimated to be approximately R$104 million (€29 million based on the average Portuguese Central Bank rate for real for 2004 through September 30, 2004) and the total estimated impact on EDP’s net income in 2004 approximately R$66 million (€18 million based on the average Portuguese Central Bank rate for real for 2004 through September 30, 2004).

 

On October 22, 2004, ANEEL, through an additional resolution, also authorized Bandeirante to increase electricity tariffs for the one-year period commencing October 23, 2004 by an average of 15.95% on the “new” tariff. In practical terms, this represents an 11.4% increase on the average tariff charged by Bandeirante from October 23, 2004 through October 22, 2005.

 

We believe that the cumulative effect of these two measures will not have a material impact on the results anticipated by the business plan we announced on December 2, 2003.

Escelsa

 

EDP and its subsidiaries own 54.76% of Escelsa, a distribution company in the Espírito Santo state of Brazil that, in 2003, served more than 968,000 customers.

 

In September 2002, a lawsuit with GTD Participações, S.A., or GTD, a Brazilian company, received a favorable decision on the merits in our favor. This decision, however, is subject to an appeal to the High State Court of Rio de Janeiro, which has not yet been decided. Previously, a shareholders’ agreement with GTD that provided for joint control of Escelsa was in force. The lawsuit was filed by GTD when it contested the termination of this shareholders’ agreement. GTD attempted to suspend our rights as controlling shareholder, but the judiciary denied this request. We convened an extraordinary shareholders’ meeting of Escelsa in September 2002 at which we gained control of Escelsa, which control had previously been shared jointly with GTD. In October 2002, we took over the management of Escelsa and appointed new executive officers. Since that time, we have fully consolidated Escelsa. Following the decision of the Lower Court of Rio de Janeiro, GTD filed an additional lawsuit in the Federal Court of Rio de Janeiro with a similar complaint, but this time against Brazilian Union and Eletrobras, as well, on which no ruling has yet been made.

 

The electricity required by Escelsa’s distribution grid in 2003 totaled 8,185 GWh, an 11% increase from the previous year. In order to meet market demand, Escelsa’s hydroelectric plants generated 922 GWh internally, which represents 11.2% of the electricity required. Escelsa purchased the remaining 5,975 GWh from other suppliers. In addition, 1,287 GWh produced by other generators passed through Escelsa’s grid.

 

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Escelsa’s total electricity sales volume was 5,900 GWh in 2003, representing a 7% decrease from 2002 due to decreased electricity sales to the commercial and industrial segments. Consumption by the residential segment represented 20.3% of total sales volume, an increase of 5.5% from 2002. Consumption by the industrial segment represented 46.5% of total sales volume, a decrease of 16.6% from 2002, which reflects the loss of liberalized customers to other energy suppliers. Consumption by the commercial segment represented 12.8% of the total sales volume, a decrease of 10% from 2002, also reflecting the loss of liberalized customers. The energy supply sold to other electric utilities represented 5.4% of the total sales volume, an increase of 1% from 2002. Finally, sales to other segments represented 15.0% of the total sales volume, an increase of 13% from 2002. Taking into account electricity distributed to liberalized customers, which pay Escelsa a fee for use of its distribution grid, Escelsa distributed 7,187 GWh in 2003, an 11% increase from 2002.

 

On August 7, 2003, ANEEL approved Escelsa’s tariff readjustment, an increase of 17.3% that consisted of:

 

  8.96% to compensate for Escelsa’s non-controllable costs, which are passed along to customers;

 

  7.8% to compensate for Escelsa’s controllable costs, which were adjusted to reflect inflation, and were discounted by 0.63%, due to the pass-through to the tariffs of the year’s productivity gains, or the X Factor; and

 

  0.54% to compensate for Escelsa’s losses during the rationing period in 2001-2002.

 

Every three years, Escelsa’s tariffs are reviewed according to its concession contract, for the purpose of reassessing the fair return on capital employed. On August 7, 2004, ANEEL approved a 6.33% increase in Escelsa’s tariffs.

 

In 2003, Escelsa had capital expenditures of 64 million reais (€19 million), of which 57 million reais (€17 million) were technical costs related to the expansion and improvement of the distribution grids, new substations and company modernization. The remaining 7 million reais (€2 million) were financial costs related to the expenditures capitalized in Escelsa’s assets.

 

Escelsa’s workforce at the end of 2003 totaled 1,309 employees, 3.5% less than in 2002. Esclesa continues to increase the customers per employee ratio, reaching 742 in 2003 from 705 in 2002, an improvement of 5%.