20-F 1 d20f.htm FORM 20-F FORM 20-F
Table of Contents

As filed with the Securities and Exchange Commission on July 14, 2006


SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


Form 20-F

 


 

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

OR

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

 

¨ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report                     

Commission File Number: 1-14648

 


EDP—Energias de Portugal, S.A.

(Exact name of registrant as specified in its charter)

 


 

EDP—Energies of Portugal   Portuguese Republic
(Translation of registrant’s name into English)   (Jurisdiction of incorporation or organization)

Praça Marquês de Pombal, 12

1250-162 Lisbon, Portugal

(Address of principal executive offices)

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

 

Title of each class

 

Name of each exchange on which registered

Ordinary Shares, with nominal value €1 per share*   New York Stock Exchange
American Depositary Shares (as evidenced by American   New York Stock Exchange

Depositary Receipts), each representing 10 Ordinary Shares

 

 

* Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

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

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the last full fiscal year covered by this Annual Report:

As of December 31, 2005, there were outstanding: 3,656,537,715 Ordinary Shares, with nominal value of €1 per share

 


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    Yes  ¨    No  x

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x        Accelerated filer  ¨        Non-accelerated filer  ¨

Indicate by check mark which financial statement item the registrant has elected to follow. Item 17  ¨    Item 18  x

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

 



Table of Contents

TABLE OF CONTENTS

 

PART I       5

Item 1.

  

Identity of Directors, Senior Management and Advisers

   5

Item 2.

  

Offer Statistics and Expected Timetable

   5

Item 3.

  

Key Information

   5
  

SELECTED FINANCIAL DATA

   5
  

EXCHANGE RATES

   8
  

CAPITALIZATION AND INDEBTEDNESS

   9
  

REASONS FOR THE OFFER AND USE OF PROCEEDS

   9
  

RISK FACTORS

   9

Item 4.

  

Information on the Company

   15
  

HISTORY AND BUSINESS OVERVIEW

   15
  

Energy

   18
  

Telecommunications

   19
  

International Investments

   19
  

Group Capital Expenditures and Investments

   20
  

STRATEGY

   23
  

Iberian Energy

   23
  

International Activities

   25
  

Telecommunications

   25
  

Information Technology

   26
  

Development of Complementary Business Activities

   26
  

THE IBERIAN ENERGY MARKET

   26
  

PORTUGAL

   27
  

Electricity System Overview

   27
  

Electricity Regulation

   31
  

Gas System Overview

   37
  

Gas Regulation

   38
  

SPAIN

   41
  

Electricity System Overview

   41
  

Electricity Regulation

   41
  

Gas System Overview

   45
  

Gas Regulation

   46
  

GENERATION

   47
  

Portugal

   47
  

Spain

   59
  

RENEWABLE ENERGY

   62
  

History and Overview

   62
  

Portugal

   65
  

Spain

   66
  

Renewable Energy Outside Iberia

   68
  

DISTRIBUTION AND REGULATED SUPPLY

   68
  

Portugal

   68
  

Spain

   74
  

LIBERALIZED SUPPLY

   75
  

Portugal

   75
  

Spain

   76
  

GAS

   77
  

Portugal

   77
  

Spain

   78
  

BRAZIL

   79
  

Overview

   79
  

Regulation

   82
  

Generation

   85
  

Distribution

   87
  

Trading

   91
  

Related Activities

   92
  

TELECOMMUNICATIONS

   92
  

Overview

   92

 

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Regulation

   93
  

Telecommunications Activities

   96
  

OTHER INVESTMENTS AND INTERNATIONAL ACTIVITIES

   97
  

SUBSIDIARIES, AFFILIATES AND ASSOCIATED COMPANIES

   98
Item 4A.   

Unresolved Staff Comments

   99
Item 5.   

Operating and Financial Review and Prospects

   99
  

OVERVIEW

   99
  

CRITICAL ACCOUNTING POLICIES

   103
  

RESULTS OF OPERATIONS

   107
  

2005 COMPARED WITH 2004

   109
  

LIQUIDITY AND CAPITAL RESOURCES

   117
  

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

   118
  

PENSIONS AND BENEFITS

   118
  

INFLATION

   119
  

IFRS COMPARED WITH U.S. GAAP

   119
  

IMPACT OF RECENTLY ISSUED U.S. ACCOUNTING STANDARDS

   122
Item 6.   

Directors, Senior Management and Employees

   125
  

EXECUTIVE BOARD OF DIRECTORS

   125
  

GENERAL AND SUPERVISORY BOARD

   128
  

COMPENSATION OF DIRECTORS AND SENIOR MANAGEMENT

   135
  

SHARE OWNERSHIP

   135
  

EMPLOYEES

   136
  

EMPLOYEE BENEFITS

   137
Item 7.   

Major Shareholders and Related Party Transactions

   137
Item 8.   

Financial Information

   138
  

CONSOLIDATED STATEMENTS

   138
  

OTHER FINANCIAL INFORMATION

   138
  

Legal Proceedings

   138
  

Dividends and Dividend Policy

   139
  

SIGNIFICANT CHANGES

   139
Item 9.   

The Offer and Listing

   139
  

TRADING MARKETS

   139
  

MARKET PRICE INFORMATION

   140
  

THE PORTUGUESE SECURITIES MARKET

   140
  

TRADING BY US IN OUR SECURITIES

   142
  

PLAN OF DISTRIBUTION

   143
  

SELLING SHAREHOLDERS

   143
  

DILUTION

   143
  

EXPENSES OF THE ISSUE

   143
Item 10.   

Additional Information

   143
  

SHARE CAPITAL

   143
  

ARTICLES OF ASSOCIATION

   143
  

NYSE CORPORATE GOVERNANCE STANDARDS

   149
  

MATERIAL CONTRACTS

   151
  

EXCHANGE CONTROLS

   152
  

TAXATION

   152
  

PORTUGUESE TAXATION

   152
  

UNITED STATES TAXATION

   154
  

DIVIDENDS AND PAYING AGENTS

   156
  

STATEMENT BY EXPERTS

   156
  

DOCUMENTS ON DISPLAY

   156
  

SUBSIDIARY INFORMATION

   156
Item 11.   

Quantitative and Qualitative Disclosures About Market Risk

   157
Item 12.   

Description of Securities Other Than Equity Securities

   160
  

GLOSSARY OF TERMS

   160

 

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PART II

      161

Item 13.

  

Defaults, Dividend Arrearages and Delinquencies

   161

Item 14.

  

Material Modifications to the Rights of Security Holders and Use of Proceeds

   161

Item 15.

  

Controls and Procedures

   162

Item 16.

  

[Reserved]

   162

Item 16A.

  

Audit Committee Financial Expert

   162

Item 16B.

  

Code of Ethics

   162

Item 16C.

  

Principal Accountant Fees and Services

   163

Item 16D.

  

Exemptions from the Listing Standards for Audit Committees

   163

Item 16E.

  

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

   164

PART III

      165

Item 17.

  

Financial Statements

   165

Item 18.

  

Financial Statements

   165

Item 19.

  

Exhibits

   165

 

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Defined terms

In this annual report, 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, references to “€,” “euro” or “EUR” are to the euro, the single European currency established pursuant to the European Economic and Monetary Union, references to “escudo(s)” or “PTE” are to Portuguese escudos and references to “real” or “reais” are to Brazilian reais. We have explained a number of terms related to the electricity industry in the “Glossary of Terms” included in this annual report.

Forward-looking statements

This annual report and the documents incorporated by reference in this annual report contain forward-looking statements. We may from time to time make forward-looking statements in our reports to the U.S. Securities and Exchange Commission, or SEC, on 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 annual report, the documents incorporated by reference in this annual report and the exhibits to this annual report, 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 annual report. 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 in countries in which we operate, including, in particular, European Union, or EU, directives, Portuguese, Spanish and Brazilian legislation, regulation and government policy, government and municipal concessions in Portugal 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 and telecommunications; 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

We have prepared the financial information contained in this annual report in accordance with International Financial Reporting Standards, or IFRS, as adopted by the European Commission for use in the European Union in articles 11 and 12 of Decree law no. 35/2005, of February 17, 2005, and article 4 of Regulation (EC) no. 1606/2002 of the European Parliament and Council, of July 19, 2002. IFRS differs in significant respects from generally accepted accounting principles in the United States, or U.S. GAAP. We describe these differences in “Item 5. Operating and Financial Review and Prospects—IFRS Compared with U.S. GAAP” and in note 48 to our consolidated financial statements. Unless we specify otherwise, references in this annual report to our “consolidated financial statements” are to the audited consolidated financial statements, including the related notes, included in this annual report.

The SEC has adopted an accommodation permitting eligible foreign issuers for their first year of reporting under IFRS to file two years rather than three years of statements of income, changes in shareholders’ equity and cash flows prepared in accordance with IFRS. We are required to prepare our financial statements for the year ended December 31, 2005 for the first time in IFRS, and this annual report on Form 20-F has been prepared in reliance on the SEC accommodation.

Beginning in 2002 (for fiscal year 2001 and thereafter), we published our consolidated financial statements in euros. Unless we specify 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 this annual report, 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 specify 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 July 11, 2006 of U.S.$1.2754 per €1.00. That rate may differ from the actual rates used in the preparation of our consolidated financial statements included in Item 18, and U.S. dollar amounts used in this annual report may differ from the actual U.S. dollar amounts that were translated into euros in the preparation of our consolidated financial statements. For information regarding recent rates of exchange between euros and U.S. dollars, see “Item 3. Key Information—Exchange Rates.”

PART I

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

SELECTED FINANCIAL DATA

You should read the following in conjunction with “Item 5. Operating and Financial Review and Prospects” and our consolidated financial statements and other financial data, including the related notes, found elsewhere in this annual report.

The summary financial data below has been extracted from our consolidated financial statements for each of the years ended December 31, 2004 and 2005 and as of December 31, 2004 and 2005 and the related notes, which appear elsewhere in this annual report. The consolidated financial statements have been prepared in accordance with IFRS, which differs in significant respects from U.S. GAAP. We describe these differences in “Item 5. Operating and Financial Review and Prospects—IFRS Compared with U.S. GAAP” and in note 48 to our consolidated financial statements.

Under the SEC accommodation for eligible foreign private issuers reporting in IFRS for the first time, such issuers must also present selected consolidated financial data for five years on a basis reconciled to U.S. GAAP. We have provided, in the information below, amounts in accordance with U.S. GAAP net income, net income per share, net income per ADS, net fixed assets, total assets, total liabilities and shareholders’ equity as of and for the years ended December 31, 2001, 2002, 2003, 2004 and 2005.

 

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In 2004, we selected a new firm of independent public accountants to audit our consolidated financial statements based on a solicitation of bids to a number of firms, including our previous firm of independent public accountants. Our fiscal year 2004 and 2005 consolidated financial statements were audited by KPMG. Fiscal years from 2000 through 2003 were audited by PricewaterhouseCoopers.

 

     Year ended December 31,  
    

2004

Euro

   

2005

Euro(1)

   

2005

U.S. $(1)

 
     (in millions, except per ordinary share and per
ADS data)
 

Statement of income:

      

Amounts in accordance with IFRS

      

Electricity sales

   6,539     8,584     10,949  

Other sales(2)

   249     664     847  

Services(3)

   522     428     546  
                  

Total revenues

   7,311     9,677     12,342  

Cost of consumed electricity

   (3,336 )   (4,222 )   (5,385 )

Changes in inventories and cost of raw materials and consumables used

   (608 )   (1,591 )   (2,029 )

Supplies and services

   (661 )   (817 )   (1,042 )

Personnel costs

   (528 )   (546 )   (696 )

Employee benefits expense

   (440 )   (200 )   (255 )

Other income/expenses, net

   (608 )   (247 )   (316 )
                  

Gross operating results

   1,131     2,053     2,619  

Provisions

   (64 )   (12 )   (16 )

Depreciation and amortization expense

   (835 )   (997 )   (1,271 )

Amortization of deferred income on partially funded properties received under concessions

   86     98     124  
                  

Operating results

   317     1,142     1,456  

Gains from the sale of financial assets

   10     441     562  

Financial income

   392     528     673  

Financial expenses

   (660 )   (927 )   (1,183 )

Share of profit of associates

   4     35     45  
                  

Profit before tax

   62     1,219     1,554  

Income tax expense

   (16 )   (152 )   (194 )
                  

Profit after tax but before gain on discontinued operation

   46     1,066     1,360  

Gain on sale of discontinued operation, net of tax

   0     46     58  
                  

Net income

   46     1,112     1,418  
                  

Attributable to:

      

Minority interests

   3     41     52  

Equity holders of EDP

   43     1,071     1,366  

Operating results from continuing operations

   335     1,154     1,472  

Net income from operations per ordinary share(4)

   0.10     0.31     0.40  

Net income from operations per ADS(4)

   1.04     3.14     4.00  

Basic and diluted net income per ordinary share(4)

   0.01     0.29     0.38  

Basic and diluted net income per ADS(4)

   0.14     2.94     3.75  

Dividends per ordinary share(5)(6)(7)

   0.09     0.10     0.13  

Dividends per ADS(5)(6)

   0.92     1.00     1.28  

(1) For 2005, euros are translated into U.S. dollars at the rate of exchange of U.S.$1.2754 = €1.00, which was the U.S. Federal Reserve Bank of New York Noon Buying Rate on July 11, 2006.
(2) Consists of sales of natural gas, steam, ash, information technology products, telecommunications equipment and sundry materials.
(3) Consists of electricity-related services, services to information technology systems, telecommunications, engineering, laboratory services, training, medical assistance, consulting, multi-utility services and other services.
(4) Basic net income per share is based on the weighted average number of ordinary shares outstanding during the year. Diluted net income per share is computed on the basis of the weighted average number of ordinary shares outstanding during the year plus the effect of ordinary shares issuable upon the exercise of employee stock options using the treasury stock method. Basic and diluted net income per American Depository Share, or ADS, is based upon basic and diluted net income per ordinary share multiplied by 10 as each ADS is equivalent to 10 ordinary shares on a post-split basis.
(5) Based on 3,656,537,715 ordinary shares issued and outstanding in 2004 and 2005.
(6) Dividends per ordinary share in U.S.$, translated at the prevailing rate of exchange on the date of payment between the U.S. dollar and the euro, amount to U.S.$ 0.12 in both 2004 and 2005.
(7) Stated figure is rounded, as actual dividend paid in relation to 2004 net income was €0.09243.

 

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     Year ended December 31,
    

2001

Euro

  

2002

Euro

  

2003

Euro

  

2004

Euro

  

2005

Euro(1)

  

2005

U.S. $(1)

     (in millions, except per ordinary share and per ADS data)

Statement of income:

                 

Amounts in accordance with U.S. GAAP

                 

Revenues

   5,133    5,512    5,747    6,822    9,056    11,550

Income from continuing operations

   521    264    451    239    1,101    1.404

Income from continuing operations per share

   0.17    0.09    0.15    0.08    0.30    0.38

Net income

   521    264    451    239    1,109    1,414

Basic and diluted net income per ordinary share(2)

   0.17    0.09    0.15    0.08    0.30    0.39

Basic and diluted net income per ADS(2)

   1.74    0.89    1.51    0.78    3.05    3.89

(1) For 2005, euros are translated into U.S. dollars at the rate of exchange of U.S.$1. 2754 = €1.00, which was the U.S. Federal Reserve Bank of New York Noon Buying Rate on July 11, 2006.
(2) Basic net income per share is based on the weighted average number of ordinary shares outstanding during the year. Diluted net income per share is computed on the basis of the weighted average number of ordinary shares outstanding during the year plus the effect of ordinary shares issuable upon the exercise of employee stock options using the treasury stock method. Basic and diluted net income per ADS are based upon basic and diluted net income per ordinary share multiplied by 10 as each ADS is equivalent to 10 ordinary shares on a post-split basis.

 

     As of and for the Year ended December 31,  
    

2004

Euro

   

2005

Euro(1)

   

2005

U.S. $(1)

 
     (in millions, except per ordinary share and per
ADS data)
 

Cash flow data:

      

Amounts in accordance with IFRS

      

Net cash from operating activities

   1,643     1,653     2,108  

Net cash used in investing activities

   (2,311 )   (2,039 )   (2,601 )

Net cash used in (from) financing activities

   636     707     902  

(1) For 2005, euros are translated into U.S. dollars at the rate of exchange of U.S.$1. 2754 = €1.00, which was the U.S. Federal Reserve Bank of New York Noon Buying Rate on July 11, 2006.

 

     Year ended December 31,
    

2004

Euro

  

2005

Euro(1)

  

2005

U.S. $(1)

     (in millions, except per ordinary share and per
ADS data)

Balance sheet data:

        

Amounts in accordance with IFRS

        

Cash and cash equivalents

   231    585    747

Other current assets

   2,562    3,740    4,770

Total current assets

   2,793    4,326    5,517

Fixed assets, net(2)

   12,557    13,891    17,717

Other assets

   5,551    5,816    7,417

Total assets

   20,901    24,033    30,652

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

   1,961    1,984    2,530

Other current liabilities

   3,849    4,548    5,800

Total current liabilities

   5,810    6,531    8,330

Long-term debt, less current portion

   7,181    8,601    10,969

 

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     Year ended December 31,
    

2004

Euro

  

2005

Euro(1)

  

2005

U.S. $(1)

     (in millions, except per ordinary share and per
ADS data)

Hydro account

   364    170    217

Other long-term liabilities

   2,764    2,620    3,341

Total liabilities (including Hydro account)

   16,119    17,922    22,857

Minority interest

   744    1,288    1,642

Total Equity attributable to equity holders of EDP

   4,038    4,823    6,152

(1) For 2005, euros are translated into U.S. dollars at the rate of exchange of U.S.$1. 2754 = €1.00, which was the U.S. Federal Reserve Bank of New York Noon Buying Rate on July 11, 2006.
(2) Substantially all of these assets are subject to reversion to the Portuguese Republic or the municipalities. See “Item 4. Information on the Company—Portugal—Electricity regulation—Portuguese electricity legislation and regulation—Reversionary assets.”

 

     Year ended December 31,
    

2001

Euro

  

2002

Euro

  

2003

Euro

  

2004

Euro

  

2005

Euro(1)

  

2005

U.S. $(1)

     (in millions, except per ordinary share and per ADS data)

Balance Sheet Data:

                 

Amounts in accordance with U.S. GAAP

                 

Fixed assets, net(2)

   5,929    6,602    7,172    9,722    11,648    14,856

Total assets

   15,455    16,922    17,730    23,525    25,800    32,905

Total current liabilities

   3,052    2,551    3,270    6,920    6,408    8,173

Total long-term liabilities

   7,706    10,403    10,873    11,230    12,471    15,906

Total liabilities

   10,758    12,954    14,143    18,150    18,880    24,079

Shareholders’ equity

   4,456    3,865    3,440    4,583    5,558    7,088

(1) For 2005, euros are translated into U.S. dollars at the rate of exchange of U.S.$1. 2754 = €1.00, which was the U.S. Federal Reserve Bank of New York Noon Buying Rate on July 11, 2006.
(2) Substantially all of these assets are subject to reversion to the Portuguese Republic or the municipalities. See “Item 4. Information on the Company—Portugal—Electricity Regulation—Portuguese electricity legislation and regulation—Reversionary assets.”

EXCHANGE RATES

Our consolidated financial statements are published in euros. A portion of our revenues and expenses and certain liabilities are nonetheless denominated in non-euro currencies outside the euro zone, and fluctuations in the exchange rates of those currencies in relation to the euro will therefore affect our results of operations. To learn more about the effect of exchange rates on our results of operations, you should read “Item 5. Operating and Financial Review and Prospects.” Exchange rate fluctuations will also affect the U.S. dollar price of the ADSs and the U.S. dollar equivalent of the euro price of our ordinary shares, the principal market of which is the Euronext Lisbon Stock Exchange. In addition, any cash dividends are paid by us in euro, and, as a result, exchange rate fluctuations will affect the U.S. dollar amounts received by holders of ADSs on conversion of those dividends by the depositary.

 

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The following table shows, for the periods and dates indicated, information concerning the exchange rate between the U.S. dollar and the euro. These rates are provided solely for your convenience. We do not represent that the euro could have converted into U.S. dollars at these rates or at any other rate.

The column of averages in the table below shows the average of the relevant exchange rate, calculated as the average of the exchange rate on the last business day of each month during the relevant period. The high and low columns show the highest and lowest exchange rates, respectively, on any business day during the relevant period.

 

U.S. dollar per euro(1)

Year Ended December 31,

   End of Period    Average

2001

   0.89    0.89

2002

   1.05    0.95

2003

   1.26    1.13

2004

   1.35    1.24

2005

   1.18    1.24

U.S. dollar per euro(1)

   High    Low

2006

     

January

   1.23    1.20

February

   1.21    1.19

March

   1.22    1.19

April

   1.26    1.21

May

   1.29    1.26

June

   1.29    1.25

(1) Euro amounts are based on the U.S. Federal Reserve Bank of New York Noon Buying Rate.

Our ordinary shares are quoted in euro on the Euronext Lisbon Stock Exchange. Our ADSs are quoted in U.S. dollars and traded on the New York Stock Exchange. On July 11, 2006, the exchange rate between the euro and the U.S. dollar was U.S.$1.2754 = €1.00.

CAPITALIZATION AND INDEBTEDNESS

Not applicable.

REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

RISK FACTORS

In addition to the other information included and incorporated by reference in this annual report, 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 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 Portuguese system. For further information on the structure of the Portuguese electricity market, see “Item 4. 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 PES. In 2005, the installed capacity of these producers was 2,389 MW, which represents 18.6% of the total installed capacity in Portugal. Through our subsidiaries, we participate in this generation area with an installed capacity of 337 MW.

 

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The Portuguese regulatory structure now allows for competition in the supply of electricity, which could adversely affect our sales of electricity. In particular, in the future more electricity will be sold in the competitive markets, where prices may be lower than existing tariffs. Although law provided for full liberalization in the supply of electricity in August 2004, these rules are not expected to be implemented until September 2006. Therefore the effects of this increased competition have not yet been fully determined.

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, Mercado Ibérico da Energia Eléctrica, or MIBEL, the main principles of which are free competition, transparency, objectivity 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 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, 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.

Through its laws and regulations, the Portuguese government has created the current legal and regulatory framework governing the Portuguese electricity sector in which we operate. We cannot predict if regulatory changes will be made in the future or, if any such regulatory changes were made, the effects these changes would have on our business, financial condition and results of operations.

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, or ERSE, regulates the electricity industry through, among other things, a tariff code that defines the prices we may charge for electricity services in the Public Electricity Sector, referred to as the PES or Binding Sector, and the prices for third-party access tariffs. 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, ERSE may take actions that adversely impact our profitability.

In real terms, adjusted for inflation, very high, high and medium voltage tariffs, generally applied to industrial customers, have declined by an average of 1.5% per year over the period 1999 to 2006. The tariffs for low voltage customers have also declined in real terms by an average of approximately 2.3% per year over the same period. For 2006, in nominal terms, tariffs for all voltage levels increased, on average, by 5.1% from the 2005 levels.

The component of the final tariff collected by EDP Distribuição Energia, S.A., or EDPD, our distribution company in Portugal, is calculated on the basis of a unitary tariff by voltage levels defined by ERSE, subject to a yearly adjustment on the basis of the Portuguese consumer price index, or CPI, less an “efficiency coefficient.” During the 2002-2004 regulatory period, the efficiency coefficient increased from 5% (applicable during the 1999-2001 regulatory period) to approximately 7%. There was no efficiency coefficient for the 2005 regulatory period as it was a one-year period without additional years within the period for the purposes of comparison. For 2006-2008, the efficiency coefficient is 4%. The tariffs to be set for the 2006-2008 regulatory period or any new regulations to be promulgated in respect of these periods may adversely affect our business, results of operations and financial condition.

 

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Due to uncertainty as to the timing of our receipt of compensation relating to the early termination of the PPAs, which is conditioned on the start of operations of MIBEL, we may not receive such compensation in the amount currently contemplated.

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 early termination of existing power purchase agreements, or PPAs. Pursuant to Decree law no. 52/2004, of October 29, 2004, which was enacted by the Portuguese parliament, the terms and conditions of such termination have been set out in Decree law no. 240/2004, of December 27, 2004, which provides for the creation of compensation measures designed to ensure electricity generating companies an economic benefit equivalent to that of the PPAs. However, the early termination of the PPAs, and the resulting implementation of related compensation mechanisms, is subject to the existence of various requirements and the satisfaction of various conditions precedent, the chief among these being the commencement of MIBEL operations. Although the MIBEL forward sale market managed by OMIP—Operador do Mercado Ibérico de Energia—Pólo Português, S.A., or OMIP, began operations on July 3, 2006, it is still unclear whether the adequate conditions have been met to allow for the commencement of MIBEL operations. Until the requirements and conditions for the early termination of the PPAs are met, our generation facilities in the PES will continue to be operated under the existing PPAs.

The estimated amount of compensation relating to the early termination of the PPAs contemplates, among other things, the commencement of MIBEL operations by June 30, 2005, which did not occur. Currently, we do not know the timing for commencement of MIBEL. To the extent that the timing of our receipt of compensation for the early termination of the PPAs is delayed, the amount of such compensation could be different from that which is currently contemplated. As a result, perceptions of our value in the market that are based on the currently contemplated compensation amount could change.

In addition, the compensation mechanisms relating to the early termination of PPAs were devised in the context of the existing legal and regulatory framework for the Portuguese electricity market, changes to which could result in changes to the assumptions or other factors underlying the existing compensation mechanisms and eventually adversely affect the compensation we receive.

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. 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 operating in the PES in Portugal account for approximately 47% of the installed capacity in the PES. These plants are dependent on the amount and location of rainfall and river flows from Spain, all of which vary widely from year to year. In years of favorable hydrological conditions, there is an increase in hydroelectric generation, while in years of unfavorable hydrological conditions, there is a decrease in hydroelectric generation and a greater dependence on thermal generation. 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.

To account for the variability of hydrological conditions and their impact on generation costs in the PES, we use the “hydrological correction account,” or hydro account, which was established in accordance with Portuguese law. Because the tariffs in Portugal are computed based on the assumption of conditions in an average hydrological year, the purpose of this account is to correct the short-term effect of hydro variability on PES generation costs.

The hydro account is reinforced through cash payments by REN—Rede Eléctrica Nacional, S.A., or REN (the system operator of the PES), in years of favorable hydrological conditions, while in years of unfavorable hydrological conditions we draw from the hydro account and make cash payments to REN, in order to compensate for the increased generation costs in the PES. Both the cash reinforcements and draws are based on the economic reference costs calculated on the basis of an average

 

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hydrological year and observed fuel prices. The increased PES generation costs in a dry year could have an adverse impact on our operational cash flow but not on our results of operations, due to the effects of the hydro account. For further information on the hydrological correction account, see “Item 5. Operating and Financial Review and Prospects—Critical Accounting Policies—Hydrological correction account.”

A significant amount of the energy we produce in certain markets is subject to market forces that may affect the price and amount of energy we sell.

We are exposed to market price risk for the purchase of fuel (including fuel-oil, coal and natural gas) used to generate electricity and the sale of a portion of the electricity that we generate. A portion of this risk is currently managed by the PPAs and we actively manage the market price risk relating to our fuel requirements. There can be no assurance that such management will eliminate all market price risk relating to our fuel requirements.

The combined-cycle gas fired power station, or CCGT, at Ribatejo, or the Ribatejo CCGT, does not operate under a PPA and its supply of natural gas is subject to market price risk for the purchase of fuel. If the Ribatejo CCGT plant does not receive an adequate supply of natural gas or if the price of natural gas is too high, it may not generate electricity or electricity generation may be limited.

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 and Spanish law, laws adopted to implement EU regulations and directives and international agreements on the environment. In Brazil, although we only operate hydroelectric plants and Brazil does not belong to Annex I of the Kyoto Protocol, we are nonetheless subject to strict environmental regulations relating to operators of generation facilities. 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 made approximately €90.5 million of capital expenditures in 2005 to comply with applicable environmental laws and regulations to minimize the atmospheric emissions 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 created a new National Emissions Reduction Plan, or PNRE, to reduce SO2 and NOx emissions. The new PNRE, which replaces the 1996-2003 PNRE, was prepared and discussed with the competent authorities during 2004 and 2005, and formally approved in June 2006. The investments we made by to minimize emissions impact took into account these targets now imposed. Additionally, with regard to CO2 emissions, the Emission Trading Scheme, or ETS, began in the EU in 2005, and emission allowances were distributed to our operators in Portugal and Spain. We were allocated allowances for Portugal and Spain totaling 68.7 MtCO2, for the period spanning 2005 to 2007. The total amount of allowances received by the electricity sectors accounts for nearly 43% and 40% of the total CO2 accounted for in Portugal and Spain, respectively. In the binding generation system in Portugal, the costs of our thermal installed capacity are covered by the PPAs, taking into account allowances of CO2, which means that about 50% of the risk of insufficient CO2 emissions allowances is protected. For the other 50%, relating to the thermal generation in Spain and the Ribatejo CCGT plant, we are dependent on our CO2 risk management practices. There can be no assurance that we will manage our CO2 emissions within the applicable allowances.

We also have an interest in a nuclear power plant through HidroCantábrico—Hidroeléctrica del Cantábrico, S.A., or HidroCantábrico, which holds a 15.5% interest in the Trillo nuclear power plant in Spain. Spanish law and regulations limit, consistent with international treaties ratified by Spain, the liability of nuclear plant operators for nuclear accidents. Current Spanish law provides that the operator of each nuclear facility is liable for up to €150.3 million as a result of claims relating to a single nuclear accident. We would be liable for our proportional share of this €150.3 million per accident amount. Trillo currently has insurance to cover potential liabilities related to third parties arising from a nuclear accident in Trillo up to €150.3 million. The €150.3 million per accident limit on liability could be increased pursuant to changes in Spanish law. In the proportion of HidroCantábrico’s stake in Trillo, we could be subject to the risks arising from the operation of nuclear

 

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facilities and the storage and handling of low-level radioactive materials. These risks include accidents, the breakdown or failure of equipment or processes or human performance, including safety controls, and other events that could result in injury or damage to property or the environment. Liabilities we may incur in connection with these risks could result in negative publicity and reputation damage.

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 (appreciation of 22%, 9% and 13% during 2003, 2004 and 2005, respectively) 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 Brazilian real might adversely affect our business, 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, the 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 that started in June 2001 and ended in February 2002 had an adverse effect on electricity consumption and on consumption habits in affected areas. During this rationing program, electricity consumption in our concession area decreased and did not return to pre-rationing levels until 2004. Consequently, in 2002 and 2003, our Brazilian operations could only dispose of surplus electricity at depressed prices. Although total electricity distributed by our subsidiaries in the Brazilian market increased in 2004, reflecting a stronger economic environment in that region and an increase in the number of customers, material reductions in electricity consumption or generation, due to below-average rainfall or otherwise, may adversely affect our future financial results. In 2005, according to data from the Empresa de Pesquisa Energética, or EPE, energy consumption in Brazil grew 4.6% from 2004 and exceeded pre-2001 rationing levels for almost every month of the year, reflecting a recovery in demand.

 

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In 2004, Law No. 10,848, named the Law of the New Electricity Industry Model (Lei do Novo Modelo do Setor Elétrico), or New Electricity Law, for the Brazilian electric utility sector was enacted. As the regulations for the New Electricity Law have not yet been fully implemented, there is a risk that the new regulations may not be favorable for us. In addition, the New Electricity Law 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 Electricity Law 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 Electricity Law will fully mitigate the risk of delayed tariff adjustments.

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

We also are developing an Iberian gas business as complimentary to and strategically aligned with our electricity business, as described in more detail in “Item 4. Strategy—Iberian Energy—Developing an Iberian gas business.” We may 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 fluctuation in the price of energy, currencies in which gas prices are quoted and time-lags in prices between the times of purchase and sale. 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 and financial condition.

The supply chain of gas to Iberia by foreign countries involves gas production and treatment, transportation through international pipelines and in vessels, and processing in liquefaction terminals. This supply chain is subject to political and technical risk. Although these political and technical risks are often dealt with through “force majeure” clauses in supply, transit and shipping contracts that may, to a certain extent, shift risk to the end-user market, thereby mitigating contractual risk, contractual provisions do not mitigate margin risk associated with loss of profits. Additionally, once liberalization occurs in Portugal, access rules and available capacity in the infrastructures will be defined. Any capacity access or operational restrictions imposed by the system operator may impair normal supply and sales activities with resulting contractual risk leading to loss of profits.

The gas market is becoming more complex and more interrelated with the dynamics of other markets, including the market for electricity and CO2, leading to volatility in international spot markets, with greater alternation between periods of high prices and low prices. Both high and low prices cause margin risk for market participants whose supply chain does not rely on long-term, stable contracts. Although the contractual structure of EDP’s supplies in Portugal is designed to mitigate these fluctuations, we cannot assure you that our contractual structure will fully mitigate the risk arising from market volatility.

The demand for natural gas by electricity generators may be significantly affected not only by gas prices but also by a number of other factors including hydrological conditions, prices in electricity pool markets, prices of competing fuels and the availability of plants that are not gas fired. Commercial gas sales and gas distribution are affected by tariff levels, the economies conditions of the countries in which we sell and distribute gas, environmental and climate conditions and competition.

The European Commission and national regulators and authorities can unilaterally change, sometimes in a significant way, the regulation and rules applicable to the local gas industry. These changes may affect the return on investment of gas infrastructure owners, the conditions for access to infrastructure by participants, the level of storage or stranded costs supported by participants and, consequently, the potential economics of all market participants.

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 across the EU, and we expect competition to remain vigorous and even increase in the future.

 

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In the fixed line telephone area in Portugal, 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 2005, our telecommunications activity generated a loss before taxes of €87.7 million.

OTHER RISKS

The value of our ordinary shares and 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.

The Portuguese government may sell all or a portion of its shareholding in us at any time. 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 shareholder, 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, other than the Portuguese Republic and equivalent entities, purchase 5% of our shares and under the Portuguese Securities Code when purchases or sales of our shares cause shareholders to own or cease to own specified percentages of our voting rights.

Pursuant to article 10 of Decree law no. 218-A/2004, of October 25, 2004, known as 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 or an equivalent entity is an EDP shareholder. These rights provide that, without the favorable vote of the government or an equivalent entity, 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 or an equivalent entity may also appoint one member of our board of directors whenever it votes against the list of directors presented for election at our general meeting of shareholders.

Item 4. Information on the Company

HISTORY AND BUSINESS OVERVIEW

We were incorporated in 1976 under the name EDP—Electricidade de Portugal, E.P., as a result of the nationalization and merger of the principal Portuguese companies in the electricity sector in mainland Portugal. In 1991, we changed our name to EDP—Electricidade de Portugal, S.A. and, in October 2004, we changed our name to EDP—Energias de Portugal, S.A.

 

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We are the largest generator and distributor of electricity in Portugal. In addition, we own 30% of REN, the sole transmitter of electricity in Portugal, and we have significant electricity operations in Spain and Brazil. Our principal executive offices are located at Praça Marquês de Pombal, 12, 1250-162 Lisbon, Portugal. Our telephone number at this location is +351-21-001-2500. Our agent for service of process in the United States is CT Corporation System at 111 Eighth Avenue, New York, New York 10011.

Our official website address is http://www.edp.pt. The information on our website is not incorporated by reference in this annual report.

Through a privatization process that began in 1997, the Portuguese government has reduced its interest in us. The sixth phase of privatization was completed in December 2005 with the issuance of convertible bonds by Parpública corresponding to 4.376% of our share capital. As of May 31, 2006, we were approximately 20.49% owned indirectly by the Portuguese Republic and an additional 4.95% of our shares were held by Caixa Geral de Depósitos, S.A., or CGD, a state-owned bank. Other significant shareholders include Iberdrola, S.A. (9.5%), Caja de Ahorros de Asturias, or CajAstur (5.53%), BCP - Banco Comercial Português, S.A., or BCP (2.91%), the BCP Group’s Pension Fund (2.23%), UBS AG (2.41%), Banco Espírito Santo, S.A., or BES (2.17%) and Baltic – SGPS, S.A., or Baltic (2.00%).

The following chart shows our current structure and a list of the primary companies and investments within the EDP Group. For a more detailed listing and description, see “—Subsidiaries, Affiliates and Associated Companies” and note 17 to our consolidated financial statements.

 

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LOGO

Our 2005 operating revenues amounted to €9,677 million (U.S.$12,342 million), approximately 89% of which represented electricity sales, yielding operating income of €1,142 million (U.S.$1,456 million). As of December 31, 2005, our total assets were €24,033 million (U.S.$30,652 million), and shareholders’ equity was €4,823 million (U.S.$6,109 million).

 

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The following table shows our consolidated revenues by activity and geography:

 

     Year ended December 31,  
             2004                     2005          
     (millions of EUR)  

Electricity

    

Portugal

   5,521     6,301  

Spain

   416     1,697  

Brazil

   1,148     1,607  

Gas

    

Portugal

   0     49  

Spain

   198     671  

Telecommunications

   156     150  

Adjustments(1)

   (129 )   (798 )
            

Total

   7,311     9,677  

(1) Adjustments to include revenues from services and to exclude intercompany transactions.

ENERGY

Iberian electricity

Historically, electricity has been our core business. We are the largest producer and distributor of electricity in Portugal. We underwent a restructuring in 1994, at which time we formed subsidiaries to operate in the areas of electricity generation, transmission and distribution. The Portuguese government purchased a 70% interest in the transmission company REN from us in 2000. We currently conduct most of our electrical generation business in Portugal through EDP—Gestão da Produção de Energia, S.A., referred to in this annual report as EDP Produção, or EDPP. Our electricity distribution business in Portugal is conducted through Distribuição Energia, S.A., or EDPD.

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. HidroCantábrico operates electricity generation plants and distributes and supplies electricity and gas, mainly in the Asturias and Basque regions in Spain. We are now the third largest utility operator in the Iberian market following our acquisition of an additional 56.2% stake in HidroCantábrico in 2004, increasing our stake to 95.7%. In connection with our 2004 acquisition of HidroCantábrico, we entered into a shareholders’ agreement with CajAstur and Caser, which together retained an aggregate stake in HidroCantábrico of 3.1%. The shareholders’ agreement gives CajAstur and Caser certain veto rights, especially in relation to certain regional concerns, which will preserve HidroCantábrico’s links with the region of Asturias. In addition, CajAstur has 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.

In 2005, we accounted for approximately 82% of the installed generation capacity in the 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 5% of Spanish mainland installed generation capacity in the conventional regime, which includes generation in the competitive market or through bilateral contracts, and 6% of the Spanish liberalized electricity supply market.

In Portugal, we generate power for consumption in both the PES and the Independent Electricity System, or IES. In 2005, our generation facilities in Portugal had a total installed capacity of 8,921.2 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 5.9 million customers with 43,784 GWh of electricity in 2005. In Spain, HidroCantábrico had a total installed capacity in the conventional regime in 2005 of 2,596 MW, distributed a total of 9,247 GWh through its own network to approximately 584,922 regulated customers and invoiced 13,611 GWh of electricity supply to regulated and liberalized customers.

Our generation activities in Portugal and Spain include renewable energy facilities that are primary held by Nuevas Energias de Occidente, SL, or Neo Energia, a company formed in 2005 to participate in the renewable energy business. In December 2005, Neo Energia acquired the Spanish operations of Nuon International Renewables Projects, B.V., a Dutch company involved in renewables, for €485.4 million. The acquired business, Grupo Nuon España, S.L.U., or Nuon España, participates in the Spanish renewable energy sector through Desarollos Eolicos, S.A., or DESA, and has a portfolio of wind farm projects with a total capacity of 1,407 MW, of which 221 MW were already fully operational at the end of 2005 and

 

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1,186 MW were in different stages of development. The wind farms are located in Galicia, Aragon, Andalusia and Canary Islands and comprise assets with an average number of wind hours of 2,650 hours/year, above the average for the sector in Spain, which stands at 2,350 hours per year.

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, the regional electricity market of the Iberian Peninsula is our natural market and will be integrated with the opening of MIBEL. In anticipation of MIBEL, we elected the Iberian Peninsula electricity market as the core market for our main electricity business and expanded our energy operations in Spain with an increase of our stake in HidroCantábrico to 95.7% in 2004. Our main activities in the electricity sector are already conducted in the Iberian Peninsula market in an integrated manner. We expect this acquisition to result in the full integration of HidroCantábrico’s operations with 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.

Iberian gas

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

In Portugal, we have direct and indirect shareholdings equal to 72.0% of Portgás – Sociedade de Produção e Distribuição de Gás, S.A., or Portgás, the natural gas distribution company for the northern region of Portugal and direct and indirect shareholdings equal to 19.8% of Setgás – Sociedade de Produção e Distribuição de Gás, S.A., or Setgás, the natural gas distribution company for the Setúbal region. For more information on our participation in the Portuguese gas sector, see “—Gas—Portugal.”

Our interests in the gas sector in Spain are held through HidroCantábrico, which is the controlling shareholder with a 56.18% stake in Naturgás Energia, or Naturgás, the leading gas company in the Basque region of Spain. For more information on our participation in the Spanish gas sector, see “—Gas—Spain.”

Brazilian electricity

Our investments in Brazil are held through Energias do Brasil and consist of distribution, generation and related activities in the electricity sector. Energias do Brasil is engaged in distribution through the following subsidiaries: EBE—Empresa Bandeirante de Energia, S.A., or Bandeirante, Escelsa—Espirito Santo Centrais Eléctricas S.A., or Escelsa, and Enersul—Empresa Energética do Mato Grosso do Sul S.A., or Enersul. In generation, Energias do Brasil participates in Investco S.A., or Investco, the owner of the Lajeado plant, through EDP Lajeado S.A., or EDP Lajeado, and Enerpeixe S.A., or Enerpeixe. Energias do Brasil’s related trading business is concentrated in Enertrade S.A., or Enertrade. For more information, see “—Brazil—Overview.”

TELECOMMUNICATIONS

In 2000, taking into consideration our existing resources and expertise, we decided to pursue telecommunications activities. Currently, ONI—Operadora Nacional de Interactivos, S.G.P.S., S.A., or ONI, our 56.6%-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 wireline Portugal, discussed in further detail in “—Telecommunications” below. In June 2006, we announced that a process for the sale of our stake in ONI might be initiated.

INTERNATIONAL INVESTMENTS

Apart from Spain and Brazil, we have made a number of international investments in the electricity and water sectors in Cape Verde, Guatemala, and Macau. Other than Neo Energia’s acquisition of three wind farms in France in 2005, discussed in further detail in “—Renewable Energy” below, we have not initiated any other new significant international investment projects since 2003.

 

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GROUP CAPITAL EXPENDITURES AND INVESTMENTS

The following table sets forth our capital expenditures and investments for the years 2003 through 2005, 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,
     2003    2004    2005
     (thousands of EUR)

OPERATING INVESTMENT:

        

Energy:

        

Portugal:

        

Generation:

        

Thermal/Hydro

   213,851    178,735    182,926

Renewable: wind

   38,533    53,667    46,030

Renewable: biomass

   922    155    0

Cogeneration

   33    161    249

Other

   0    0    3,699

Engineering and Operations and Maintenance

   7,809    14,181    125
              

Total Generation

   261,147    246,899    233,029

Distribution:(1)

        

Investment, net of subsidies

   275,030    311,513    335,926

Subsidies in kind (assets)

   61,039    70,405    71,158

Subsidies in cash

   59,714    76,592    79,330
              

Total Distribution

   395,783    458,510    486,415

Supply(2)

   6,218    6,524    5,663
              

Total technical costs

   663,148    711,933    725,107

Financial costs capitalized

   24,005    24,785    15,233
              

Total Portugal

   687,152    736,718    740,339

Spain:

        

HidroCantábrico(3)

   70,528    115,071    347,294
              

Total Spain

   70,528    115,071    347,294
              

Total Energy Portugal and Spain

   757,680    851,789    1,087,633

Brazil:

        

Generation(4)

   58,676    195,545    255,400

Distribution:

        

Bandeirante

   39,392    33,173    42,729

Escelsa

   18,639    30,055    50,817

Enersul

   16,184    25,932    69,857

EDP Brasil

   415    222    552
              

Total Brazil

   133,307    284,926    419,355

Telecommunications(5) and Information Technology:

        

Telecommunications

   28,564    33,498    34,070

Information Technology

   58,784    20,424    0
              

Total Telecommunications and Information Technology

   87,348    53,922    34,070

Other:

        

Other Operating Investment(6)

   24,939    31,317    36,583
              

TOTAL OPERATING INVESTMENT

   1,003,274    1,221,954    1,577,642

 

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     Year ended December 31,
     2003    2004    2005
     (thousands of EUR)

FINANCIAL INVESTMENT:

        

Energy:

        

Portugal:

        

Acquisition of additional 20% shareholding in Turbogás

   0    0    52,010

Acquisition of shareholding in Portgás and Setgás

   0    124,120    0

Other

   0    0    6,747

Spain:

        

Acquisition of 66.2% of Naturcorp (now Naturgás) by HidroCantábrico(7)

   100,235    0    0

Acquisition of 56.2% of HidroCantábrico by EDP

   0    1,200,763    0

Acquisition of DESA by Neo Energia

   0    0    485,355

Acquisition of Ider, S.L. by Sinae Inversiones Eólicas, S.A.

   0    0    14,907

Other

   0    0    9,149

 

Brazil:

        

Other

   0    0    0
              

Total Energy

   100,235    1,324,883    568,168

Other:

        

Subscription to BCP rights issue and capital increase

   40,599    0    0

Other financial investments

   40,926    25,240    0
              

Total Other

   81,525    25,240    0
              

TOTAL FINANCIAL INVESTMENT

   181,760    1,350,123    568,168
              

TOTAL CAPITAL EXPENDITURES AND INVESTMENTS

   1,185,034    2,572,077    2,145,810

(1) Distribution includes capital expenditures of EDPD.
(2) Supply comprises the capital expenditures of EDP Energia, our company operating in the liberalized market.
(3) Investments represent 40% of HidroCantábrico’s operational investments in 2003 and 2004, and 100% in 2005.
(4) Investments in 2004 and 2005 include investments Peixe Angical.
(5) Investments for telecommunications include primarily infrastructure.
(6) 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.
(7) Investments represent 40% of HidroCantábrico’s financial investment in the acquisition of Naturcorp. Naturcorp has since reorganized its gas holdings, as a result of which HidroCantábrico’s ownership of Naturcorp decreased to 56.2%.

Total capital expenditures and investments of €2,145.8 million in 2005 represented a 16.6% decrease from total capital expenditures and investments of €2,572.1 million in 2004. This decrease in 2005 was primarily due to the acquisition of an additional 56.2% shareholding in HidroCantábrico in 2004. In 2005, our main investments included the acquisition in Spain of Nuon España by Neo Energia, and the construction of the Peixe Angical hydroelectric power station in Brazil, which is expected to start operations during the second half of 2006. Capital expenditures by EDPD in 2005 were focused on the distribution network in order to continue improving the quality of service.

Capital expenditures and investments increased from €1,185 million in 2003 to €2,572.1 million in 2004 due to the acquisition of HidroCantábrico in 2004, a higher level of investments in generation in Portugal, following the near conclusion of Venda Nova II, which was renamed Frades in 2005, the completion of construction of the first two units of the Ribatejo CCGT plant and the additional 72 MW of Enernova’s wind farm capacity and investments made at the 124 MW Albacete wind farm through HidroCantábrico.

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,  
     2003     2004     2005  
     (thousands of EUR)  

Total Capital Expenditures and Investments:

   1,185,034     2,572,077     2,145,810  
                  

Internal Transfers:

      

IT Systems (from EDINFOR to EDPD)

   (11,974 )   0     0  

Divestments:

      

60% of Edinfor–Sistemas Informáticos, S.A.

   0     0     (69,771 )

Comunitel

   0     0     (117,305 )

14.27% of Galp Energia

   0     0     (144,100 )

2.01% of BCP–Banco Comercial Português, S.A.

   0     0     (153,154 )

3.0% of Red Eléctrica de España, S.A.

   0     0     (75,879 )

48.9% of Hidraulica de Santillana, S.A

   0     0     (21,338 )

3% of Iberdrola, S.A.

   (400,102 )   0     0  

Oni way

   0     (61,449 )   0  

Retecal

   0     (23,004 )   0  

Stake in Fafen and Enersul turbine

   0     (37,936 )   0  

Other divestments

   0     0     (14,519 )
                  

Total Internal Transfers and Divestments

   (412,076 )   (122,389 )   (596,066 )
                  

Adjusted Total Capital Expenditures and Investments

   772,958     2,449,688     1,549,743  

 

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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 2005 totaled €486.4 million compared with €458.5 million in 2004 and €395.8 million in 2003, 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. Between 2001 and 2005, 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 2003, EDPD capital expenditures also included €12.0 million related to the internal transfer of an information technology system from Edinfor to EDPD.

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 2005 was approximately €150.5 million compared with approximately €147.0 million in 2004.

During 2005, we invested €233 million in generation in Portugal, compared with €246.9 million in 2004 and €261.1 million in 2003. Capital expenditures in 2005, 2004 and 2003 were primarily a result of expenses incurred due to the construction of the three 392 MW units of the Ribatejo CCGT plant, the two 95.8 MW units of the Frades hydroelectric plant and 160 MW of wind farms.

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 on the construction of new CCGT power plants. Future capital expenditures in generation may also include special projects such as co-generation and wind power generation opportunities.

In Spain, capital expenditures incurred in generation, electricity distribution, special regime generation and gas amounted to €347.32 million in 2005. HidroCantábrico’s operating investments in 2005 increased compared to 2004 due to the completion of the Las Lomillas (50 MW – 50% owned by Neo Energia) and La Sotonera (19 MW – 65% owned by Neo Energia) wind farms. The Boquerón (22 MW – 75% owned by Neo Energia), Belchite (50 MW – wholly owned by Neo Energia), and Brujula (73 MW – wholly owned by Neo Energia) wind farms started operations in the first half of 2006. In 2005, HidroCantábrico started the construction of the second 400 MW unit of the Castejón CCGT plant, which is forecasted to start operations by the end of 2007. When compared to 2003, investments in special regime generation were greater in 2004 due to the completion of the Albacete wind farm (124 MW), which began operations in November 2004. In 2003, 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 Naturgás, additional capital expenditures of €176.3 million were incurred (our proportional share of these expenditures being €70.5 million).

We currently expect to fund any future capital expenditures and investments in Brazil with cash flow generated by local operations and by reais-denominated debt.

As part of our capital expenditures in generation we made capital expenditures related to environmental matters of approximately €90.5 million in 2005, approximately €18 million in 2004 and approximately €10 million in 2003. We expect these capital expenditures to amount to approximately €405 million in period 2005-2008, of which €59 million will be related to new investments in emissions reduction equipment in the Sines, Aboño and Soto power plants, in order to adapt the facilities to the new environmental regulations relating to SO2 and NOx emissions.

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 and financial investment requirements develop. To learn more about our sources of funds and how the availability of those sources could be affected, see “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

 

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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. In this context, we acquired joint 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 in December 2004 acquired full control of HidroCantábrico by increasing our stake to 95.7%. See “—History and Business Overview—Energy—Iberian electricity.”

While expanding into the Spanish gas and electricity sectors, we are also strengthening our core electricity business and our 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 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 investments, as demonstrated by our sale in 2005 of a 60% stake in our information technology company Edinfor and by our sale in 2005 of a 99.93% stake in our Spanish telecommunications company Comunitel. We continue to selectively pursue other business activities that are complementary to our energy activities in Iberia. These other business activities include selectively pursuing international opportunities in electricity, specifically generation in Brazil and renewables in other European markets.

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 are developing our activities in the Portuguese natural gas distribution sector, mainly through Portgás and Setgás, in which we hold a direct and indirect stake of 72.0% and 19.8%, respectively. In Spain, we currently own 95.7% of HidroCantábrico, which holds a 56.18% stake in Naturcorp.

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 further integration with HidroCantábrico, the development of new conventional generation facilities and a significant expansion of our renewable capacity both in Portugal and Spain; 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 once MIBEL is fully operational. 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 the increasing liberalization within the EU, particularly in the Iberian electricity market; and

 

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    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 Comercial, S.A., or EDP Comercial);

 

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

 

    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; and

 

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

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:

 

    through HidroCantábrico, enhance management flexibility and further synergies between its operations and our existing ones, namely through the operation of a single energy trading unit for Iberia and the centralization of procurement in respect of our investment in wind and CCGT generation;

 

    position ourselves to benefit from the creation of an Iberian electricity market and pursue growth opportunities in Spain by leveraging 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 Portgás in connection with the expected liberalization of the Portuguese gas sector; and

 

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

Developing an Iberian gas business

We view the gas business as being highly complementary to the electricity business and of great strategic attractiveness. Both Portugal and Spain have gas and electricity consumption growth rates above the EU average and each country requires new capacity to be gradually added. 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 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

 

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flexibility of gas contracts. The natural 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 necessary 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 our existing electricity client base and the sharing of infrastructure and system costs.

Our current interest in the gas sector in Portugal consists of our 72.0% holding in Portgás and 19.8% holding in Setgás. Portgás distributes gas to more than 150,000 customers in the industrial northern region of Portugal. Our current interest in the gas sector in Spain is through HidroCantábrico’s 56.2% controlling stake in Naturcorp, which has more than 600,000 customers and approximately 10% of Spain’s regulated revenues for gas distribution, or 6% of gas distributed in Spain in terms of GWh.

INTERNATIONAL ACTIVITIES

Although our core business has historically been electricity in Portugal, it has evolved to include the Iberian energy market. However, international opportunities have arisen in the electricity 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. In July 2005, we finalized the initial public offering of Energias do Brasil following a reassessment of our Brazil strategy and rationalizing our Brazilian operations by making them more self-sustaining and independently managed. During the process, which resulted in a decrease of our stake in Energias do Brasil from 100% to 62.4%, we focused on the following initiatives:

 

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

 

    capital restructuring: assessment of the capital structure of Energias do Brasil and its subsidiaries;

 

    corporate governance: harmonization and alignment of the corporate governance structures and procedures of Energias do Brasil’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 of obtaining greater added value for shareholders and the establishment of strategic platforms for the development of future businesses; and

 

    generation of synergies: ensuring that Energias do Brasil 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, see “—Brazil” and “—Other Investments and International Activities” 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. In line with our strategic objective of increasingly focusing our activities in our electricity business, we sold our stake in Comunitel, the Spanish arm of ONI, to Tele2 in July 2005 and we announced that a process for the sale of our stake in ONI might be initiated in June 2006.

 

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

INFORMATION TECHNOLOGY

In April 2005, we completed the sale of a 60% stake in the share capital of Edinfor to LogicaCMG. This transaction involved the renegotiation of our existing contracts with Edinfor in order to ensure that we have access to the best international practices in the field of information technology at competitive prices and to ensure that our core information technology systems continue to be run by Edinfor, while benefiting from the worldwide positioning of LogicaCMG. As a result of this partnership with LogicaCMG, 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

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 see “—Subsidiaries, Affiliates and Associated Companies” below.

THE IBERIAN ENERGY MARKET

In 2005, total generation in the Iberian electricity market amounted to approximately 282.9 TWh, excluding special regime generation, of which EDP and HidroCantábrico were responsible for approximately 39.4 TWh.

Although there is not yet an integrated electricity market in operation in the Iberian Peninsula, governments from Portugal and Spain share the common vision of creating a single, integrated and competitive electricity market for Portugal and Spain, manifested by MIBEL, within the wider context of an envisaged European single electricity market, as provided for in Directives 96/92/EC and 2003/54/EC.

After several delays in the process, the international agreement entered into by the Portuguese and Spanish governments at the Iberian Summit at Santiago de Compostela on October 1, 2004 called for the beginning of operations of MIBEL on June 30, 2005. While commencement of MIBEL has not occurred yet, both governments have undertaken to create an Iberian electricity market based on the principles of free and fair competition, transparency, objectivity and efficiency.

Under the international agreement, MIBEL will operate with a spot market, which includes daily and intra-daily markets and will initially be managed by the current market operator of the Spanish market, OMEL, and a forward market, which will initially be managed by a market operator located in Portugal, OMIP. In addition, electricity transactions may also be negotiated by means of bilateral contracts with a term not less than one year. The international agreement also clarifies that the existence of two market operators, OMEL and OMIP, is temporary and that the two operators will eventually be merged into a single market operator. Pursuant to the international agreement, within one year from the implementation of MIBEL, each market operator is expected to limit the amount of its share capital held by any single shareholder to 5% and the shareholding of any system operator to a maximum of 3%. Within two years from the implementation of MIBEL, it is expected that both market operators will merge and create a single market operator designated as the Iberian Market Operator.

The development of interconnections between Spain and Portugal has been a priority in the implementation of MIBEL. Two such interconnections were put into operation in 2004, the Alqueva-Balboa 400kV line and a second 400 kV circuit in Alto-Cartelle-Lindoso. Additionally, the Douro Internacional-Aldeadavila interconnection is scheduled for completion in 2006, and will involve either the construction of a new 400kV interconnection or an increase of the existing interconnection capacity.

Within the context of MIBEL, the Portuguese government has mandated the early termination of the existing PPAs by means of adequate compensation mechanisms and changing REN’s single buyer status, as set forth in Decree law no. 240/2004. This Decree law sets out adequate compensation for the investments and commitments provided for in each PPA that are not achievable through the expected market revenues once the PPAs are terminated. It is also expected that both Portugal and Spain will take all necessary measures to open the market to all consumers and harmonize tariff structures through clear and transparent rules, particularly in Spain.

 

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PORTUGAL

ELECTRICITY SYSTEM OVERVIEW

The Portuguese electricity system

In the context of the liberalization of the Portuguese electricity sector, the creation of MIBEL and the termination of the PPAs, we expect the structure of the National Electricity System to be significantly altered with the implementation of Decree law no. 29/2006, of February 15, 2006, which Decree law implemented the provisions of Directive 2003/54/CE concerning common rules for the European internal electricity market. Although the basic principles of the new structure for the National Electricity System were defined by Decree Law no. 29/2006, the implementing legislation is still pending. Nevertheless, during 2005 the organization of the National Electricity System still remained unchanged due to the lack of regulations implementing Decree law no. 29/2006 and remained structured in accordance with previous legislation.

Although there have been no changes in the organizational structure of the sector in legislative terms, the legislative amendments introduced by Decree laws no. 184/2003 and no. 185/2003, of August 20, 2003, as transitory measures until the publication of the future basic law, have already brought new issues to the National Electricity System, by introducing new activities that became necessary with the deepening of the electricity market.

Since 1997, Portugal has had an electricity market structured pursuant to the legislation 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) CPPE was merged into EDP Produção in 2005. We own 11.11% of Tejo Energia and 40% of Turbogás.
(2) Began operations in early 1998.
(3) Including suppliers and external agents foreseen in Decree law no. 185/2003, of August 20, 2003 (EDP Comercial, Enel Viesgo, Iberdrola, Sodesa and Union Fenosa), which may buy electricity in organized markets or through bilateral contracts. The organized market presently includes the Spanish spot market, the Spanish Pool managed by OMEL and the MIBEL Derivatives Market, the Portuguese Pool managed by OMIP.

 

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(4) At the end of December 2005, approximately 5.9 million potential Qualifying Consumers, or “Eligible Consumers,” existed, of which 9,001 had become Qualifying Consumers during 2005, 4,838 were already in the Non-Binding Sector, and 613 left the Non-Binding Sector. 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. In early 2005, ERSE published the necessary codes that reflect the ability of normal low-voltage consumers to change suppliers. However, the full implementation of this new legal framework requires the enactment of further legislation and regulations that have not yet been published.

The National Electricity System consists of the PES and the IES. 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 IES 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 by decreasing the eligibility threshold in mainland Portugal to include all low-voltage customers. For more information on the liberalization of electricity sales see “—Distribution and Regulated Supply—Competition” below.

The Public Electricity System or Binding Sector

The PES includes the binding generation of our generation company, EDPP; 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 11.11% stake, and the Turbogás plant at Tapada do Outeiro, in which we have a 40% stake, after acquiring an additional 20% stake in 2005. All plants in the PES entered into PPAs with REN through which they commit to provide electricity exclusively to the PES through REN, acting as the single buyer in the PES and operator of the national transmission grid. For more information on REN’s activities, see “—Transmission” below.

Power plants in the PES 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. These binding licenses 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 PES 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 IES 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 EDPP’s CCGT plant in Ribatejo and our three wholly-owned embedded hydroelectric generators, which are small hydroelectric plants with more than 10 MW installed capacity that deliver all of the energy they produce directly to the distribution system. Although producers in the Non-Binding Sector are required to obtain licenses, they have no obligation to supply electricity to the PES and are free to contract directly with Qualifying Consumers. On August 17, 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. Therefore, in 2005, customers eligible to become Qualifying Customers, or Eligible Consumers, in Portugal represented 100% of total volume demand in mainland Portugal. During 2005, 9,001 Eligible Consumers exercised their right to become Qualifying Consumers, of which 613 returned to the Binding Sector or abandoned the market. Of the remaining 8,388 Qualifying Consumers, 5,596 entered into contracts with EDP Comercial and 2,792 entered into contracts with producers in the Spanish market. As of December 31, 2005, there were approximately 5.9 million Eligible Consumers and 13,226 of these opted to become Qualifying Consumers. Of the 13,226 existing Qualifying Consumers at the end of 2005, 9,212 were customers of EDP Comercial, representing approximately 15.6% of the electricity sold in Portugal in 2005 by us and 14% of our revenues in the electricity distribution and supply activity in Portugal in 2005. Two of the three tariff components relating to distribution are payable to EDPD by Eligible Consumers electing to become Qualifying Consumers. In addition, EDP Comercial has the opportunity to gain Qualifying Consumers as its customers, in which case the third distribution tariff component would be payable to EDP Comercial.

 

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Producers in the Non-Binding Sector, specifically generators and suppliers of special low-, medium-, high- and very high-voltage electricity, are able to use the national transmission grid and distribution system on an open-access basis to connect to Qualifying Consumers. Qualifying Customers pay regulated transmission and distribution charges to REN for transmission and EDPD or other companies for distribution, respectively. Our hydroelectric plants in the IES deliver all of the electricity they produce directly to the distribution system without going through the national transmission grid. These plants pay regulated transmission charges to REN. 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, see “—Distribution and Regulated Supply” below.

Size and composition of Portugal’s electricity market

During the period from 2001 through 2005, the total electricity distributed by EDPD (in both the Binding and Non-Binding Sectors) experienced an average growth rate of 5.0% 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 and 2004, the annual growth rate increased to 3.7% and 7.3%, respectively. In 2005, the annual growth rate decreased to 6.0%.

The primary factors that we believe have an impact on demand are the rate of gross domestic product growth, electricity connections to new households and changes in electricity consumption per capita. After the period from 1999-2001, during which consumption in the PES experienced an average growth rate of 2.1% above growth in Portugal’s gross domestic product, or Portugal’s GDP, there was a reduction to 0.7% above the growth rate in Portugal’s GDP in the year 2002 due to a slowdown in the economy. In 2005, Portugal’s GDP grew by 0.3%, compared with growth of 1.0% in 2004 and a decline of 1.0% in 2003. We estimate that overall consumption in the National Electricity System will increase at an average of 3.6% per year in 2006, 2007 and 2008. Low-voltage consumption is expected to increase each year by an average of 2.8%, very high-voltage by an average of 3.8%, and high-voltage and medium-voltage by an average of 26.1%.

Peak demand as a percentage of the total installed capacity, which is the sum of the total installed capacity of PES and the total installed capacity of the Non-Binding Sector, or NBES, has remained stable since 2001, except in 2003 when demand increased slightly due to an extremely cold winter and installed capacity in the PES decreased following the decommissioning of the Alto Mira power plant (132 MW). In 2005, EDP’s available capacity as a percentage of the total installed capacity was 76.6%, compared with 77.8% in 2004 and 74.7% in 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 from 2001 through 2005. We are addressing this situation by adding new generation capacity. The first two units of the Ribatejo CCGT plant began operation in 2004 and the third unit began operation in 2005, five months before the expected date. Also, new CCGT and hydroelectric capacity is planned for future years.

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 Sector and peak demand to EDP’s available capacity for the periods indicated. Peak demand includes demand satisfied by generation from Other Independent Producers.

 

     Year ended December 31,  
      2001     2002     2003     2004     2005  
     (in MW, except percentages)  

Installed capacity of the PES(1)

   8,758     8,758     8,626     8,626     8,738  

Installed capacity of the NBES(2)

   255     255     647     1,268     1,660  
                              

Total installed capacity (PES plus NBES)

   9,013     9,013     9,273     9,893     10,398  

Peak demand (PES plus NBES)

   7,466     7,394     8,046     8,261     8,528  

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

   82.8 %   82.0 %   86.8 %   83.5 %   82.0 %

EDP:

          

EDP’s average available capacity (PES)

   6,801     6,841     6,695     6,761     6,822  

EDP’s average available capacity (NBES)

   247     226     228     936     1,147  

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

   78.2 %   78.4 %   74.7 %   77.8 %   76.6 %

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

   105.9 %   104.6 %   116.2 %   107.3 %   107.0 %

 

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(1) The Public Electric System in 2005 includes Frades power station (192 MW) and the effect of the decommissioning of the thermal power station of Tapada do Outeiro (46.9 MW) and the termination of the PPA of the two oldest units of Tunes (32 MW). These units were kept in operation under a system services agreement with REN.
(2) Non-Binding Sector, which consists of generation in the IES other than the “other independent producers.” All of the Non-Binding Sector 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 2005 includes the third operational unit (392 MW) of the Ribatejo CCGT.

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 in this annual report 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.

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. The Portuguese government purchased a 70% interest in REN from us in late 2000. We currently hold a 30% interest in REN. For more information on this purchase, you should read “Item 5. Operating and Financial Review and Prospects—Overview.”

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 July 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 consistent with the majority of the European transmission systems. At year-end 2005, 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 as of December 31, 2005, approximately 2,282 km were 150 kV lines, 2,875 km were 220 kV lines and 1,500 km were 400 kV lines. At the end of 2005, REN had seven interconnection lines with Spain, three of which were 220 kV lines and three of which were 400 kV lines. Within the context of MIBEL, we understand that REN plans to establish an additional interconnection with Spain, Douro Internacional-Aldeadavila, consisting of a 220 kV line and 400 kV line scheduled for completion in 2008 and 2009, respectively.

In addition to the construction and operation of the national transmission grid, REN is also system operator of the National Electricity System and market operator of the PES. This involves 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
 

2001

   239    0.6 %

2002

   1,899    4.7 %

2003

   2,794    6.5 %

2004

   6,480    14.2 %

2005

   6,820    14.2 %

 

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ELECTRICITY REGULATION

EU legislation

Directive 2003/54/EC of the European Parliament and the Council, concerning common rules for the internal market in electricity and repealing Directive 96/92/CE, established the rules relating to the organization and functioning of the electricity sector, access to the market, the criteria and procedures applicable to calls for tenders and the granting of authorizations and the operation of the system. Member States were to implement this Directive by July 1, 2004.

On May 23, 2006, the European Commission adopted a decision exempting for an undefined period of time several provisions of Directive 2003/54/EC in relation to the Madeira Archipelago. According to the decision, Portugal faced serious problems in the functioning of its small isolated networks with respect to renovation, improvement and development of the existing capacity, thus the European Commission granted the exemption. Nevertheless, Portuguese authorities will monitor the evolution of the electricity sector in the Madeira Archipelago and convey to the European Commission any substantial change that may require a review of the granted exemption.

Directive 2003/87/EC established a scheme for greenhouse gas emission allowance trading within the EC. Member states were required to implement this Directive by December 31, 2003. The Emission Trading Scheme, or ETS, is the first international trading system for CO2 emissions. The ETS covers combustion plants, oil refineries, coke ovens, iron and steel plants, and factories making cement, glass, lime, brick, ceramics, pulp and paper. The primary task in preparing for the implementation of the ETS was the establishment of Natural Allocation Plans, or NAPs, by Member States. Each Member State was required to prepare and publish a NAP by March 31, 2004 (May 1, 2004 for the 10 new Member States). NAPs determine the total quantity of CO2 emissions that Member States will grant to their companies for the first trading period, 2005 to 2007. These CO2 emissions allowances can then be sold or bought by the companies themselves.

Beginning January 1, 2005, companies were required to monitor their emissions and produce annual reports on emissions that are verified by a third party. At the same time, companies must ensure that they possess a sufficient number of allowances to surrender each year in order to avoid being subject to financial sanctions. The first surrender date was April 1, 2006.

Member States must issue allowances by the end of February each year in accordance with the final allocation decisions, operate the national registry, collect verified emissions data and ensure that a sufficient number of allowance are surrendered by each company. Each Member state must also submit a regular annual report to the European Commission.

On December 7, 2005, the European Commission issued a Communication in support of electricity from renewable energy sources. This Communication served as the report that the European Commission is required to make under Article 4 of Directive 2001/77/EC, presenting an inventory of, and the experience gained from, the application and coexistence of the different mechanisms used in Member States for supporting electricity from renewable energy sources. The Communication also served as the report that the European Commission is required to make under Article 8 concerning administrative barriers, grid issues and the implementation of the guarantee of origin on renewable electricity. The Communication serves as a plan for coordination of the existing systems based on cooperation between countries and optimization of the national schemes, which will likely lead to a convergence of the systems.

Increasing the proportion of renewables generation in sources of EU electricity production has well-recognized benefits, thus Directive 2001/77/EC1 established as a target that renewable energy sources should provide 21% of the electricity by the year 2010. This directive also set differentiated targets for each Member State and further mandated that Member States provide better grid access for renewable energy generators, streamline and facilitate authorization procedures and establish a system of guarantees of origin.

Competition

All companies developing their activity within the EU, including EDP, are subject to the competition legislation adopted by the European Commission and the European Parliament. Under EU competition law, the European Directorate-General for Trade and Competition can evaluate price policies, internal procedures and merger and acquisition operations. These Community rules have also been adopted as national legislation by the Portuguese government.

 

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Portuguese electricity legislation and regulation

The basis and principles of the organization of the electricity sector in Portugal were set out in 1995 legislation that was partially revised in 1997 in accordance with the general principles of EU Directive 96/92/CE. Following the 1997 revisions, ERSE was appointed as the independent regulator in February 1997. On March 25, 2002, by Decree law no. 69/2002, ERSE’s authority with respect to the electric sector was extended to the autonomous regions of Madeira and Azores. On April 12, 2002, ERSE became the regulatory entity of energy services, and its authority was extended to the domain of natural gas regulation. The following description refers to the legal and regulatory environment applicable to our activities in Portugal during year 2005. However, a reform of the legal and regulatory framework is currently underway. For more information on this reform, see “—New national energy policy” and “—Recent developments in the liberalization of the Portuguese electricity system” below.

The responsibilities for regulation of the electricity sector in Portugal are now generally split between Direcção Geral de Geologia e Energia, or DGGE, ERSE and the Competition Authority.

Direcção Geral de Geologia e Energia

DGGE has the primary responsibility for planning and developing the PES, including approving the issuance, modification and revocation of generation and distribution licenses and preparing expansion plans for the PES every two years, in conjunction with REN, for the approval of the Portuguese Ministry of Economy. DGGE is also responsible for regulations applicable to the transmission grid and the distribution network and service quality.

Entidade Reguladora dos Serviços Energéticos

ERSE has clearly defined regulatory duties, powers and objectives established by law, including the responsibility to approve the main regulations that are published in the form of the following:

 

    the tariff code and the values for the tariffs and prices to be implemented;

 

    the commercial relations code governing relations between entities in the Portuguese electricity system;

 

    the dispatch code; and

 

    the access to the national grids and to the interconnections code.

In January 2005, ERSE revised the codes as a result of the expansion of the eligibility threshold to all consumers pursuant to Decree law no. 192/2004, of August 17, 2004.

Following the publication of the Decree law no. 240/2004, of December 27, 2004, which established the conditions for the phase-out of the PPAs, and the probability of an early starting of operation of a wholesale market, it was necessary for ERSE to revise the Tariff Code, the Commercial Relation Code and the Access to the National Grids and to the Interconnections Code. Accordingly, in August 2005, ERSE undertook a complete overhaul of the regulations governing the electricity sector. It was first submitted to public consultation, and brought existing regulations into line with the Portuguese and European legal framework.

For more information on these codes, see “—ERSE and DGGE Codes” and for more information on tariffs, see “Distribution and Regulated Supply—Portugal—Tariffs.”

ERSE and DGGE Codes

The first Tariff Code was enacted in December 1998, establishing a periodic definition of regulatory parameters for allowed revenues and a methodology for setting tariffs. Between 1999 (the first year ERSE published tariffs) and 2001, prices were set annually according to a series of formulas based primarily upon what is deemed to be an appropriate return on assets in transmission, a return fixed by price cap in distribution and supply activities. Since 2002, prices are based on a return on assets and agreed costs in commercialization, or the activity of supply, measurement and billing of energy sales to final clients. From the beginning of ERSE regulation, REN has been acting as the single buyer of electricity for Portugal, although EDPD may buy electricity directly from producers. ERSE revised the Tariff Code in August 2005 to conform to Decree law no. 240/2004, which established the conditions for the phase-out of the PPAs. As soon as MIBEL enters into operation, REN will lose its status as the single buyer, and all suppliers (including EDPP) will be responsible for the wholesale purchases. The promotion of electricity efficiency through tariffs was revised with the goal of achieving better results, in order to contribute to the Portuguese commitments at the EC level. Also, the promotion of environmental and quality of service issues was changed to make it more efficient.

The Commercial Relations Code, enacted in December 1998, was revised on September 1, 2001 and is intended to govern the commercial relations between entities within the Binding Sector as well as the commercial relations between the Binding Sector and the Non-Binding Sector. This code also governs the access to the Non-Binding Sector by Qualifying Consumers and the rules applicable to the purchase and sale of electricity within a system established for the Non-Binding

 

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Sector. ERSE has also enacted the rules of access to this system and the rights and obligations of the system’s participants, including Qualifying Consumers who have elected to participate in the Non-Binding Sector, their agents and REN as the manager of the system. The Commercial Relations Code was recently amended in April 2004, in light of the regulatory regime set out in Decree law no. 36/2004, of February 26, 2004, and again in January 2005, in light of the regime set out in Decree law no. 192/2004 of August 17, 2004. This Code was further revised in August 2005, to introduce the necessary adaptations towards a fully market-oriented system, both at the wholesale level and at the retail level. The revised Code defines the entities acting in a commercial level, the respective functions, load profiling, client’s switching procedures, and the purchase of electricity by the regulated supplier (at the spot and futures markets and through bilateral arrangements). It has also established that the frequency of invoicing to low voltage customers up to 41.4kVA supplied by the regulated supplier is every two months.

The Dispatch Code, enacted in December 1998, revised on September 1, 2001 and amended in December 2001, establishes the rules of dispatch that are applicable to REN based on principles of equality of treatment and opportunity and safeguarding the public interest in the Binding Sector.

The Access to the Grid and Interconnections Code, enacted in December 1998 and revised on September 1, 2001, is based on the same general principle as the Dispatch Code. Access to the grid is subject to the execution of an agreement in accordance with a model provided by ERSE. This Code was further amended pursuant to the approval of the Decree law no. 36/2004, of February 26, 2004 and again pursuant to the approval of Decree law no. 192/2004 of August 17, 2004. This Code was also revised in August 2005 to define the agents that have the right to the access to the grids and interconnections and to define the rules of network planning. Terms for network use were specified that provide for simplified procedures.

On January 1, 2001, DGGE issued a quality of service code. Under this code, DGGE seeks to enhance the quality of service with a system of penalties assessed against electricity companies based on their performance. DGGE has defined benchmarks against which a company’s performance can be measured if requested by the company’s customers. Fines are imposed against electricity companies in the event of power failures or any disturbances in power supply that, in each case, cause an operator’s performance to fall below DGGE’s benchmarks. These benchmarks were effective as of July 1, 2001.

In February 2003, DGGE approved and published a new quality of service code that clarifies and tightens quality standards imposed on electricity companies as well as the compensation amounts to be paid to costumers. In November 2003, DGGE also approved and published the complementary rules to the Quality of Service Code, by Dispatch no. 23705/2003.

In March 2006, DGGE published a new Quality of Service Code, by Dispatch no. 5255/2006 promoting the full opening of the market by revoking the previous platform and foreseeing a platform that establishes the relations among the different market participants.

The Competition Authority

The Portuguese Competition Authority is an independent and financially autonomous institution whose mission is to ensure compliance in Portugal with national and European Community competition laws, specifically with respect to mergers, state aid and restrictive practices. It has regulatory powers on competition over all sectors of the economy, including the regulated sectors, such as electricity, in coordination with the relevant sector regulators.

Reversionary assets

Our assets held under concession agreements with the Portuguese government or municipalities or licenses issued by the government for generation and distribution of electricity are treated either as being within the public domain of the Portuguese Republic or municipalities (for assets used in low voltage distribution) or dedicated to public service. We use assets that are part of the public domain and own and use assets that are dedicated to public service subject to limitations on their disposal.

Assets within the public domain that by their nature are replaceable may be replaced by another asset performing the same function, subject to prior authorization in certain cases. Any asset that has been replaced will thereafter be treated as a private asset. Other assets held by us, including land and buildings not held under concessions or license, are our private property.

 

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Under Portuguese law, assets under public domain cannot be sold, pledged or otherwise encumbered and are not available for enforcement of judgments. The same regime applies to assets dedicated to public service, subject to specified exceptions.

The reversion of different assets is subject to different termination and payment terms:

Licenses for generation. Assets held by EDPP for generation revert to REN, as concessionaire for the national transmission grid, at the termination of the relevant PPA, subject to payment of the residual value of assets, in accordance with the relevant PPA, provided that the assets are considered by REN to be necessary for generation in the PES according to the expansion plan for the PES in place at the time. If not considered necessary by REN, EDPP is entitled to purchase those assets for use in the Non-Binding Sector.

Licenses for distribution. Our assets held under a binding license for distribution of high voltage and medium voltage revert to REN, as concessionaire for the national transmission grid, when the license terminates. If the termination occurs by revocation or resolution of the license, payments are due as established in the binding agreements entered into between the parties. If the license terminates for any other reason, the payment due will be the average of the net book value of the assets and value of lost profits.

Concessions with municipalities. Assets held by EDPD in low voltage revert to municipalities at the end of the term of concession, subject to payment of the net value of assets as determined by a commission of three members, one appointed by each party and a third appointed by the Portuguese government. Both the expiration and early termination of these concessions can only take place if the municipalities meet specified conditions regarding the viability of the proposed distribution arrangements and the transfer of assets and workers.

Environmental matters

In 1994, our board of directors adopted an Environmental Policy Declaration, which sets forth our principles for environmental policy and activities. Our policy is aimed at minimizing or, where possible, eliminating negative environmental impacts. We believe we are in material compliance with all existing EU, Portuguese, Spanish and Brazilian government environmental regulations, and expect that we will materially comply with proposed changes in EU and other applicable regulations.

In March 2004, our board of directors approved the Principles for Sustained Development for the EDP Group, a set of eight principles relating to the economic, environmental and social aspects of our operations.

We have been implementing an Environmental Management System, or EMS, for our electricity activities, as a fundamental aspect of our environmental policy. Pursuant to the EMS, 33% and 13% of our installed capacity in Portugal and Spain, respectively, have been certified under ISO 14001. In July 2006, this figure will increase to 46% in Portugal, with the certification of Central Termoeléctrica do Ribatejo, the new CCGT plant at Ribatejo.

Our main environmental focus is reducing the emission of atmospheric pollutants, namely SO2, NOX emissions and particles. Pursuant to environmental laws and regulations, we have been using fuel with progressively lower sulfur levels and have introduced NOX primary reduction measures in the Sines thermal power station. In order to comply with new emission levels established by EU legislation, in 2003 we initiated the installation of the necessary emissions abatement equipment (fuel gas desulphurization and additional NOX primary reduction measures) at Sines and are introducing similar equipment to control SO2 and NOX emissions at our thermal plants in Spain. The Barreiro, Carregado and Setúbal power plants in Portugal are expected to be exempt from compliance with new emission limit requirements.

CO2 emissions have been considered in our risk model. Monitoring mechanisms were studied and adapted to the requirements of the Emissions Trading Directive. Our fuel purchases include, since January 2005, the cost of CO2 allowances, and the risk model for our electricity trading was altered to accommodate the risk inherent in price fluctuations of CO2 allowances. In 2005, we invested €44 million in carbon funds. These investments give CO2 emission credits that we can use in Portugal and Spain.

In 2005, emission trading allowances were allocated to our facilities in Spain and Portugal. We were allocated a total of 68.7 MtCO2, for the period spanning 2005 to 2007.

 

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     Emissions allowances allocated to the EDP Group
     2005    2006    2007
     (tCO2e)(1)

Portugal

        

Carregado

   1,088,575    1,088,575    1,088,575

Setúbal

   2,505,210    2,505,210    2,505,210

Sines

   7,837,380    7,837,380    7,837,380

Barreiro

   253,048    253,048    253,048

Tunes

   5,000    5,000    5,000

Ribatejo

   2,019,570    2,019,570    2,019,570

Mortágua

   1,510    1,510    1,510

Soporgen

   239,942    239,942    239,942

Energin

   199,250    199,250    199,250

Spain

        

Aboño

   5,542,000    4,976,000    4,338,000

Soto de Ribera

   3,404,000    3,057,000    2,666,000

Castejón

   898,000    692,000    709,000
              

Total

   23,993,485    22,874,485    21,862,485

(1) Tons of Carbon Dioxide Equivalent.

We incur significant expenses in repair and prevention measures to fulfill the demands of environmental regulations. We made capital expenditures related to environmental matters in 2005, 2004 and 2003 of approximately €90.5 million, €18 million and €10 million, respectively. Our aggregate estimate of capital expenditures to control emissions of SO2 and NOX in the period 2005 to 2008 is €405 million, of which approximately half we expect to incur at our thermoelectric plants in Spain.

Portuguese special regime for renewable electricity generation

In Portugal, the generation of electricity using renewable energy sources is governed by Decree law no. 189/88, of May 18, 1988 and its amendments. Renewable electricity generation is also impacted by Decree law no. 29/2006, of February 15, 2006, which governs the organization and functioning of the national electric system, as well as the activities, related to generation, transportation, distribution and commercialization of electricity.

The statutory and regulatory regime applicable to renewable electricity generation differs from the regime applicable to generation of electricity by other non-renewable sources only in licenses and tariffs.

Licenses

Decree law no. 189/88 sets forth a specific licensing regime applicable to power plants using renewable energy sources and integrated in the Non-Binding Sector. This regime is also complemented by Decree law no. 312/2001, of December 10, 2001, which revoked the provisions of Decree law no. 189/88 relating to the information, management, attribution and elapse of the grid reception points.

The licensing process begins with a request to DGGE to assess the capacity of the grid to receive electricity generated in a determined grid point. Should that capacity exist, a grid reception point is attributed to the requesting party. The requesting party must then obtain an establishment license from DGGE prior to the beginning of the construction of the power plant and, once the power plant construction is completed, an exploration license must also be obtained.

In parallel with the DGGE licensing process, there is a licensing process with the local authorities where the power plant is to be located is also be conducted. In particular, the requesting party must obtain a construction license and a utilization license for the power plant.

In some instances, an environmental impact evaluation is conducted and the Environmental Impact Authority must issue a favorable environmental impact declaration as a condition precedent for the issuance of the establishment license. Also, in instances were the power plant is to be located within the National Ecologic Reserve territory, a special Ministerial Order recognizing the public interest of the project will be required.

 

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Tariffs

Decree law no. 189/88 sets forth a specific formula for the tariffs to be paid to generators for the electricity generated by power plants using renewable energy. The most recent formula amendment was made by Decree law no. 33-A/2005, of February 16, 2005. The cost, with the remuneration to the generators, is allocated in accordance with Decree law no. 90/2006, of May 24, 2006.

Additionally, Decree law no. 312/2001, of December 10, 2001, establishes the obligation of certain entities, such as REN, to receive the electricity generated by power plants using renewable energy sources.

New national energy policy

On October 24, 2005, the Portuguese Council of Ministers passed a resolution establishing a new national strategy for the energy market. This Resolution no. 169/2005 replaced the previous national energy strategy announced by the Council of Ministers through Resolution no. 63/2003, of April 28, 2003. The new national strategy for energy promotes a revision of the legal and regulatory framework, establishes the extension of the scope of the activity of the companies in the sector, ensures a competitive environment where there may be more than one relevant integrated operator in the electricity and gas sectors, grants independence to regulated participants in the natural gas sector and implements its association with the companies operating the electricity transmission grid.

Recent developments in the liberalization of the Portuguese electricity system

With the progression of the liberalization process and taking into account the creation of MIBEL, as established in the agreements between Portugal and Spain, legislation has been enacted since 2003 to bring the structure of the National Electricity System and its operations into line with a competitive market regime. Pursuant to the national energy policy defined in Resolution of the Portuguese Council of Ministers no. 169/2005 of October 24, the legal framework has been significantly reviewed by the new “basis law” enacted by Decree law no. 29/2006 which sets out the basic principles for the new organization model of the National Electricity System. However, the full implementation of this new legal framework requires the enactment of further legislation and regulations that have not yet been published in order to develop the regime of the several electricity business activities, including the licensing and concession procedures.

Key principles for the new organization model of the sector

The activities of the electricity sector must be developed in accordance with the principles of rationality and efficiency in the use of resources throughout the full chain of value (i.e. from generation to consumption of electricity), as well as of competition and environmental sustainability, with the purpose of contributing for the increase of competition and efficiency in the National Electricity System, without prejudice to public service obligations.

Unlike the previous regime, the basis law establishes an integrated national electricity system in which generation, supply and management of the organized markets activities are competitive and just require compliance with a licensing or authorization process for the beginning of operations. The transmission and distribution activities continue to be provided through the award of a public service concession.

Electricity generation

Electricity generation under the new basis law is now divided in two classes: ordinary regime generation and the special regime generation. The ordinary regime generation comprises the generation of electricity, which is not subject to a special legal regime that benefits from incentives to the use of endogenous and renewable sources of generation or to the combined generation of heat, and electricity. The special regime generation refers to the generation of electricity in those special circumstances. The logic of centralized planning of the generation plants is abandoned; the initiative lies with the interested parties. Within a liberalized framework, the Portuguese State only intervenes supplementary to the private initiative, covering market failures and guaranteeing the electricity supply, through public tenders.

Electricity transmission

Electricity transmission activity is carried out through the national transmission grid for which REN has the exclusive concession. The current transmission concession contract will have to be adapted to the new basis law, while keeping REN as the concessionaire. In light of the continuity and security of supply and the need for an integrated and efficient operation of the system, the national transmission grid operation includes the technical global management of the system, ensuring the coordination of the distribution and transmission infrastructures.

 

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An electricity business performing transmission of electricity must have separate ownership and legal separation from businesses performing distribution and supply activities. The minimum criteria for ensuring this separation are set forth in the new basis law. For example, no person or entity may directly or indirectly hold more than 10% share capital of each of the concessionaires of the electricity transmission grid or 5% share capital of each of the entities that develop activities in the electricity sector, either in Portugal or abroad. The limitations are not applicable to entities controlled by the State or the concessionaire of the transmission grid.

Electricity distribution

Electricity distribution under the new basis law is operated through the national distribution grid, corresponding to the medium and high voltage network, and through the low voltage distribution grids. The national distribution grid is carried out as an exclusive concession, as a result of which the current license held by EDPD will be converted into a concession agreement, although the new basis law provides that the balance of the exploitation must be safeguarded. The low voltage distribution grids continue to be operated under concessions from the municipalities. This activity is legally separated from the transmission activity and from other activities unrelated to the distribution activity. For operators of distribution grids supplying less than 100,000 clients this legal separation does not apply, in accordance to the Directive 2003/54/CE.

Electricity supply

The electricity supply activity under the new basis law is open to competition, subject only to a license regime. Suppliers can openly buy and sell electricity. For this purpose, they have the right to access to the transmission and distribution grids through the payment of access charges set by ERSE. Under market conditions, consumers are free to choose their supplier, without any additional payment for the switching of suppliers. A new entity, whose activity will be regulated by ERSE, will be created to oversee the logistical operations of customer switching.

Under the basis law, universal service obligations are foreseen and involve the guarantee of quality and continuous supply, protection with respect to prices and access charges, and access to information in simple and understandable terms. The new basis law also created the last resort supplier, as foreseen in the Directive 2003/54/CE, subject to regulation by ERSE. This new role will be undertaken by EDPD as operator of the medium and high voltage distribution grid, which must create an independent entity for this purpose, and by the local low voltage distribution concessionaires. This new entity will be created as a temporary measure until the liberalized market is fully efficient and until the expiration of the respective concession contracts.

Regulation

Under the new basis law, ERSE retains responsibility for regulation of the electricity sector, regulating transmission and distribution, providing the last resort supply and logistical operations relating to switching and suppliers. ERSE also has the responsibility to present a report on the market functioning, to the government, and later to the Portuguese Parliament in order to be addressed to the European Commission.

DGGE will be required under the new basis law to monitor the security of supply with the assistance of the national transmission grid concessionaire. DGGE also has the responsibility to present a report on its monitoring activities to the government, the Portuguese Parliament and to the European Commission.

GAS SYSTEM OVERVIEW

The Portuguese natural gas system was developed beginning in 1993. It consists of a high-pressure gas transmission pipeline system connected to the Spanish grid at Badajoz and Tuy, a liquefied natural gas, or LNG, terminal at Sines, an underground storage unit at Carriço and several delivery points consisting of power plants, local distribution companies and large industrial clients. A gas reduction and metering station that is part of the high-pressure transmission grid serves each of these delivery points.

In 2005, natural gas consumption in Portugal was 4.04 billion cubic meters, or bcm. This volume consisted of consumption by power generation (1.97 bcm), consumption by large industrial clients (1.42 bcm) and regional distribution to households, the services sector and small industries (0.64 bcm). It is expected that the Portuguese market may grow to a level of between seven and eight bcm by 2012, mainly due to the development of gas-fired electricity generation capacity.

All high-pressure natural gas activities in Portugal are currently engaged in exclusively by Transgás, under a concession agreement granted by the Portuguese government. These activities include the importation of natural gas, the development and operation of the high pressure transmission grid, the development and operation of underground storage units, the development

 

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and operation of the LNG terminal and sales to large customers (power plants, distribution companies and large industrial clients with consumption above two million cubic meters per year). Transgás maintains its supply under long-term contracts with Sonatrach, an Algerian company, and with NLNG, a Nigerian company. Transgás is indirectly owned by Galp Energia, SGPS, S.A., or GALP, which is currently owned by the Portuguese government (17.711%); Parpública (12.293%); REN (18.3%); ENI Portugal Investment, S.p.A. (33.34%); Amorim Energia, B.V. (13.312%); Iberdrola, (4%); CGD, (1%); and Setgás (0.044%).

At the end of 2005, there were six regional distribution networks in Portugal, corresponding to six regional distribution companies:

 

    Portgás, based in Porto, covering the northern region;

 

    Lusitâniagás, based in Aveiro, covering the littoral center region;

 

    Lisboagás, based in Lisbon, covering the greater Lisbon region;

 

    Setgás, based in Almada, covering the Setúbal district;

 

    Tagusgás, based in Santarém, covering the inland region around the Tagus river course; and

 

    Beiragás, based in Viseu, covering the center inland region.

Each regional distribution company operates under an exclusive regional distribution concession agreement granted by the Portuguese government. The activities of each company consist of acquiring natural gas from Transgás, developing and operating the gas distribution grid and selling gas to customers within its region (except for clients with consumption above two million cubic meters per year).

Each regional distribution network connects at a number of points with the high-pressure transmission network through a gas reduction and metering station. Each regional grid is composed of medium pressure steel trunklines operating at pressures up to 16 barg (the primary grid) and polyethylene capillary grids operating at pressures up to four barg (the secondary grid). At the end of 2005, the six regional distribution networks accounted for a combined total of 10,367 km of grid lines. In 2005, the six regional distribution companies combined sold approximately 0.65 bcm of gas to 874 thousand customers.

GAS REGULATION

EU legislation

Gas Directive 2003/55/EC

The European Parliament and Council of Ministers adopted the Gas Directive 2003/55/EC, of June 26, 2003, or the Gas Directive, which contains common rules for the natural gas market. The Gas Directive became effective in August 2003, and Member States were requested to implement it by July 1, 2004. The Gas Directive requires legal unbundling of network activities from supply, establishes a regulator with well-defined functions in all Member States, requires that network tariffs be published, reinforces public service obligations and introduces measures to increase the security of supply.

However, “emergent markets” benefit from exceptions to several obligations established in the Gas Directive, including matters relating to the unbundling of transmission and distribution systems operators, third party access to both systems of transmission and distribution and provisions related to market opening and reciprocity. These exceptions automatically expire at the time that the Member State no longer qualifies as an emergent market. The Portuguese natural gas market will be considered an emergent market until 2007.

Safeguard security of natural gas supply Directive 2004/67/EC

On September 11, 2002, the Commission proposed a new package of measures to improve the security of oil and gas supply, a major concern during the gradual integration of national markets. Consequently, on April 26, 2004, the Council adopted Directive 2004/67/EC, that established measures to safeguard an adequate level for the security of gas supply. This directive establishes a common framework within which Member States must define general, transparent and non-discriminatory security of supply policies compatible with the requirements of a competitive internal gas market, clarifies the

 

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general roles and responsibilities of the different market players and implements specific non-discriminatory procedures to safeguard security of gas supply. Member States were required to bring into force the laws, regulations and administrative provisions necessary to comply with this Directive by May 19, 2006.

The main provisions established by the safeguard security of natural gas supply Directive are as follows:

 

    Member States must define a general policy on the security of gas supplies, including a clear definition of the roles and responsibilities of the various market players in contributing to the security of supply. This policy must be non-discriminatory and transparent.

 

    Member States must prepare reports at regular intervals describing the mechanisms put in place for emergencies and the levels of gas stocks in order to be considered by the Commission in its periodic reports on the overall assessment of the consequences of Directive 2003/55/EC and the overall efficiency and security of the internal gas market. Based on the Member States’ regular reports, the Commission will monitor the existence of adequate liquidity of gas supplies, the level of interconnection of Member States’ national gas systems and the foreseeable gas supply situation as a function of demand, supply autonomy and available supply sources at the Community level with regard to specific geographic areas in the Community.

 

    Member States must take the necessary measures to ensure that the supply to vital consumers, or those who are not in a position to replace gas with another fuel, is adequately guaranteed at least in the event of the single most important source of gas supply being disrupted or in the event of extremely low temperatures. The measures to be adopted should include ensuring that gas stocks make at least a minimum contribution to achieving the security of supply standards. Also, the level of stocks should take account of the geological conditions of the territory and the economic and technical feasibility in each Member State.

 

    Member States must prepare national emergency measures that ensure, where appropriate, that market players are given sufficient opportunity to provide an initial response to the emergency situation. These measures must be submitted in advance to the Commission and updated as appropriate.

 

    In the event of a serious interruption in gas supply, the Commission, assisted by a committee made up of representatives of the Member States, will draw up recommendations urging Member States to assist the countries most affected. If necessary, the Commission will adopt decisions requiring Member States to take the appropriate measures.

Regulation on the conditions for access to the natural gas transmission networks.

The European Parliament and Council of Ministers adopted Regulation (EC) No 1775/2005, of September 28, 2005, on the conditions for access to the natural gas transmission networks. The basis for this regulation was a second set of common rules entitled “the Second Guidelines for Good Practice” that was adopted at the meeting of the European Gas Regulatory Forum on September 24-25, 2003. This Regulation will apply beginning July 1, 2006, and its purpose is to set non-discriminatory rules for access conditions to natural gas transmission systems, taking into account the specificities of national and regional markets with a view to ensuring the proper functioning of the internal gas market.

This purpose will be fulfilled through the setting of harmonized principles for tariffs or the methodologies underlying their calculation and for access to the network, the establishment of third party access services, the setting of harmonized principles for capacity allocation and congestion management, the determination of transparency requirements, balancing rules and imbalance charges and the facilitation of capacity trading.

Portuguese gas regulation

The Council of Ministers adopted Decree law 30/2006, of February 15, 2006, that partially transposes Directive 2003/55/EC and establishes the general framework for the organization and functioning of the Natural Gas National System in Portugal, as well as the general framework for import, storage, transmission, distribution and commercialization of natural gas and the organization of the natural gas market. Regulations governing these activities, including the procedures for concessions and licenses, have not yet been approved. The main provisions of the Decree law are set forth below.

 

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General rules for the organization of the sector

Natural gas businesses must operate in accordance with the principles of the Gas Directive, with a view toward achieving a competitive, secure and environmentally sustainable market in natural gas.

Organization, definition and functioning of the activities

Natural gas business have been awarded exclusive concessions or licenses to develop facilities for reception, import storage and regasification of LNG and facilities for underground storage and transmission, which constitute overall management of the system. These companies will fulfill public service obligations, which are clearly defined, transparent, non-discriminatory and verifiable, guarantee equality of access for EU gas companies to national consumers and comply with the measures adopted for the protection of final customers.

Unbundling

A gas business performing transmission of natural gas must have separate ownership and legal separation from businesses performing distribution and supply activities. Similarly, gas businesses performing underground storage or LNG activities must have legal separation from businesses performing any of the other natural gas activities. The minimum criteria for ensuring this separation are set forth by the Decree law. For example, no person or entity may directly or indirectly hold more than 10% of the share capital of each of the concessionaires of the transmission network or 5% of the share capital of each of the entities that develop activities in the natural gas sector. The limitations are not applicable to entities controlled by the Portuguese state or the concessionaire of the transmission network. The limitations are also not applicable to the underground storage and the LNG terminal facilities that will be the object of future concessions.

Third party access to the system

Third party access to the transmission and distribution systems and to LNG facilities must be ensured by the concessionaires of the “Transmission, Underground Storage and Liquefied Natural Gas Network” based on published tariffs applicable to all eligible customers, including supply companies, and applied objectively and without discrimination between system users. This is without prejudice to both parties entering into long-term supply contracts, as long as these contracts comply with competition law provisions.

Liberalization of the markets

According to Article 23 of Directive 2003/55/EC, Member States must ensure that the eligible customers include all non-household customers beginning July 1, 2004, and all customers beginning July 1, 2007. Contracts for supply with an eligible customer in the system of another Member State must not be prohibited if the customer is eligible in both systems involved. Nevertheless, because Portugal is an emergent market, Article 64 of the Decree law provides that eligibility should be implemented gradually. In Portugal, beginning in 2007, the definition of eligible customers will result in an opening of the market equal to at least 33% of the total annual gas consumption of the national gas market; two years thereafter, all non-household customers must be eligible customers, and three years thereafter, all customers must be eligible.

Even though Portugal benefits from a temporary exemption from the obligations provided for in the Directive, Decree law 30/2006 already anticipates several obligations imposed by the Directive, such as the unbundling of the transmission and distribution system.

Decree law 30/2006 ERSE requires ERSE to present a report to the Ministry of Economy and Innovation, on a date to be fixed by further regulation, on the functioning of the natural gas market and the degree of effective competition, with an indication of the measures either already adopted or still to be adopted to strengthen the efficiency of the market. ERSE must publish this report and send it to the Parliament and to the European Commission.

Directive 2004/67/EC, of April 24, 2004, on the safeguard security of natural gas supply has not yet been implemented by Portugal as a separate statute. Decree law 30/2006 only establishes some principles concerning the security of natural gas supply of the Natural Gas National System. Ensuring this security is the responsibility of the Portuguese Government, while monitoring the security of supply is the responsibility of DGGE, with the cooperation of the concessionaire of the Natural Gas Transmission System. DGGE will issue a proposal of periodic report on the security of supply to be presented to the Minister of Economy and Innovation and subsequently to be sent to the Parliament and to the European Commission.

Under Article 16 of Regulation (EC) No 1775/2005, while the Portuguese natural gas market is considered an emergent market, the Regulation is not applicable to the Portuguese natural gas network. Portugal may apply to the Commission for a temporary exemption from the application of this Regulation, for a period of up to two years from the date at which the exemption expires.

 

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SPAIN

ELECTRICITY SYSTEM OVERVIEW

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 since 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, (ii) at tariffs linked to pool prices plus a premium, that vary depending on the type of generation and are generally higher than regulated tariffs (transitory regime), or (iii) 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 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), 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 end of each year, the Spanish government sets both the final and access tariffs for the incoming year. By Royal Decree no. 2392/2004, the Spanish government established the electricity tariffs for 2005.

Liberalized suppliers are free to negotiate the electricity price with 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.

In 2005, annual demand was 246,873 GWh, a 4.8% increase from 2004 and the installed capacity was 73,690 MW, a 7.7% increase from 2004. This installed capacity increase was due to the commissioning of eight new combined cycle power plants and additional wind farm development in 2005.

ELECTRICITY REGULATION

The enactment of Law no. 54/1997, of November 27, 1997, has gradually changed the Spanish electricity sector from a state-controlled system to a free-market system with elements of free competition and liberalization. With this change, the Spanish government intends to guarantee the electricity supply at the highest quality and at the lowest possible price. The current regulatory framework provides for:

 

    the unbundling of activities so that no operator can simultaneously carry out regulated activities (transmission, distribution, technical management of the system and economic management of the wholesale market) and liberalized activities (generation, trading and international/intra-community exchanges);

 

    a wholesale generation market, or electricity pool;

 

    freedom of entry for new operators with liberalized activities in the electricity sector;

 

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    liberalized activities to take place in a competitive environment, although transmission, distribution, technical management of the system and economic management of wholesale market activities will continue to be regulated as their particular characteristics impose limitations on the possibility of introducing competition;

 

    as of January 1, 2003, all consumers may select their suppliers and the method of supply, either at market prices or with a set tariff fixed by the Spanish government;

 

    all operators and consumers have the right to access the transmission and distribution grid by paying access tariffs previously approved by the Spanish government; and

 

    environmental protection.

Royal decree law no. 3/2006, of February 24, 2006, modifies the matching process of the selling and buying offers presented by companies that are within the same industrial group in the day-ahead and intra-day markets:

 

    Energy acquired by electricity distribution companies will be matched to the sales of electricity in the ordinary regime by generation companies that are within the same industrial group.

 

    The price that will be used to settle the purchases of distribution companies will be set by the Spanish government based on transparent market prices, although provisionally the price has been fixed at €42.35 per MWh.

 

    Beginning on March 2, 2006, electricity generation companies in the ordinary regime became subject to a tariff deficit calculation. Under this calculation, there is a reduction in company’s retribution in an amount equal to the market value of the emission allowances allocated to the company under the NAP. Between January 1, 2006 and March 2, 2006, there was a reduction related to the amount of eventual estimated shortfall in income from regulated activities to which such group is entitled and the to the market value of emission allowances granted in this period.

The Industry Ministry has not published yet the regulatory framework needed to fully evaluate the economic and financial consequences of this Royal decree law.

Royal decree law 7/2006, of June 23, 2006, modifies several aspects of Law 54/1997 by establishing the end of the recovery of the Cost of Transition to Competition and setting a new methodology for calculating regulated tariff, which allows government to establish tariff maximums and costs to be considered in average tariff.

Royal decree 809/2006, of June 30, 2006, fixed the tariffs beginning July 1, 2006, providing for an average increase of 1.38% on the 2006 tariff. The tariff for household customers has increased 0.8% since January 2006 and the tariff for large customers has increased 6% for large consumers since January 2006. This increase was adopted to recover 2005 tariff deficit, which will be recovered until year 2020. The access tariffs were unchanged.

Technical and economic management of the system

Prior to the enactment of Law no. 54/1997, operation of the electricity system in Spain was a public service provided by the government through Red Eléctrica de España, S.A., or REE, a state controlled entity. Under Law no. 54/1997, REE continues to serve as the system operator, but some of its dispatching functions have been taken over by the market operator, Operador del Mercado Ibérico de Energía – Polo Español, S.A., or OMEL. Accordingly, OMEL is responsible for the economic management of the wholesale market and REE is responsible for the technical management of the transmission grid and the balancing mechanism that ensures that energy supply is equal to energy demand. The Spanish government no longer controls REE, although it still retains a 20% interest in the company through Sociedad Estatal de Participaciones Industriales, or SEPI. To ensure that REE and OMEL are guaranteed the highest levels of independence and transparency, the maximum stake that can legally be held in REE has been reduced to 3% (except for SEPI) or to 1% (for electricity operators or for those companies or individual who hold more than 5% on the share capital of an electricity operator). In the case of OMEL, the maximum stake that can be held on its share capital is 5%, except that economic managers of other electricity systems may hold stakes of up to 10% in OMEL until June 30, 2006.

Supervision of the system

The National Energy Commission is the public authority in charge of supervision of the electricity, hydrocarbons and natural gas industries in Spain.

Generation

Law no. 54/1997 seeks to create a competitive electricity generation market where power generation plants are dispatched based on the results of a competitive bidding process administered by OMEL. It also provides for a transitional period until 2010 during which power generation companies that were subject to the Stable Legal Framework on December 31, 1987 will be entitled to partial compensation for the costs they incurred in connection with the transition to the competitive market regime, or stranded costs. This compensation is paid from amounts collected from consumers, as part of the tariffs, and settled by the National Energy Commission. Law 54/1997 also provides that the installation of new power generation plants be completely liberalized and not subject to government planning, subject only to the authorizations required by the applicable laws and regulations (town planning and environmental protection, for example). New electricity generators will be entitled to the same rights and payments as other generators.

On March 11, 2005, Royal Decree law no. 5/2005 was adopted to increase productivity, and provides for:

 

    limitation of activities of “dominant players,” such as a prohibition on importing electricity into the MIBEL from any outside country. Dominant players are defined as those companies that hold market shares in the Iberian generation and supply market above 10%. This limitation will be fully in force upon the publication of the dominant players list by the Spanish authorities and as from the commencement of MIBEL activities;

 

    implementation of measures at the wholesale level in order to comply with MIBEL requirements; and

 

    the cost of activities related to the second part of the nuclear fuel cycle, including the dismantling of nuclear facilities, has been excluded from the tariff and now it must be paid directly by the nuclear plants.

On August 27, 2004, Royal Decree law no. 5/2004 established a scheme for greenhouse gas emission allowance trading, implementing Directive 2003/87 of the European Commission. This Royal Decree law was replaced by Royal Decree law no. 1/2005,

 

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of March 9, 2005, which, with respect to energy generation, applies to any plant with a thermal capacity above 20 MW. As of January 1, 2005, an authorization for gas emissions is needed. The NAP, approved by the European Commission on December 27, 2004, sets forth the total quantity of allowances to be allocated for the 2005-2007 period. On January 21, 2005, a final allowance allocation list for electricity plants was published under Royal Decree no. 60/2005.

Transmission and distribution

Under some of the provisions of the current regulatory scheme, electricity transmission and distribution activities will continue to be regulated as their particular characteristics impose limitations on the possibility of introducing competition. However, in order to promote efficiency and quality of service, the current regulatory framework has changed the manner in which electricity businesses receive payments.

The regulations take into account the investment and operational costs related to transmission activities. Fixed payment for distribution is based on investment, on a reference network model as well as distribution areas, incentives for the quality of supply, loss reduction and commercial management costs. In the future, consideration of investments and operational and maintenance costs will also be included.

In order to promote the liberalization of the electricity sector, the government is preparing the substitution of the current regulated-unregulated market scheme by an unregulated-last resort supply scheme. Under the latter scheme, a last resort operator appointed by the government will be the only one able to supply domestic and small consumers under a last resort tariff. The rest of consumers will be supplied under market prices. These changes are expected to take place before 2011.

Supply

Supply (or retailing) in Spain was created by Law no. 54/1997. Suppliers are companies that have access to the transmission and distribution networks and whose function is to sell electricity to eligible consumers or other agents in the system. The parties concerned freely agree to the economic terms of retailing transactions, therefore, this type of supply is not subject to fixed tariffs.

Tariffs

Spanish electricity tariffs are fixed annually by the government through Royal Decree. Royal Decree no. 1432/2002, of December 2002, established a new method of calculation for the period 2003-2010. The new method of calculation allows tariffs to be fixed under more objective, transparent and predictable conditions.

Royal Decree no. 1556/2005, of December 23, 2005, fixed the tariffs for 2006 and provided for an average rise of 4.48% on the 2005 average tariff (or reference tariff, which includes all applicable tariffs and costs). The 2006 average tariff will be confirmed or updated, if necessary, on July 1, 2006.

The 2006 tariff for regulated customers increased 4.68% from 2005, and the 2006 access tariffs also increased 2.86% from 2005.

Competition

On January 1, 2003, the Spanish electricity market was fully liberalized allowing million of consumers access to the market to negotiate their consumption of electricity.

The consolidation of low voltage customers in the liberalized market continued in 2005. During 2005, an average of 1.76 million low voltage-consumers purchased electricity in the market. Among these consumers, approximately 123 thousand were small and medium enterprises, or SMEs, and the remaining were household consumers. In terms of electricity, this represents 17,170 GWh consumed by SMEs. By December 2005, the number of SMEs and household consumers operating in the market exceeded 1.95 million consumers, 8.3% of the total consumers of electricity in mainland Spain.

At high-voltage, the number of customers in the liberalized market increased 3.3%, on average. The number of high-voltage customers in market at the end of the year was 34,600. This represented consumption of 69,262 GWh, a 9.6% increase from the 63,171 GWh consumption in 2004 (calculated from average supplies billed during the period). Some large customers returned to the tariff market during the last months of 2005 because of better prices. High voltage-customers in market represent about 30% of the total consumption in Spain.

 

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Special regime

The special regime in Spain includes all renewable energy generation, such as solar thermoelectric, solar photovoltaic, wind, biomass, biogas, biofuel or mini-hydroelectric, as well as cogeneration facilities. All the plants or generation facilities included in the special regime must have less than 50 MW of installed capacity. Due to increasing concern over environmental matters, generation activities included in the special regime have become increasingly important. Renewable energy sources are also helping to reduce the energy dependence of Spain and increase the security of supply.

Development of renewable energy in Spain began twenty five years ago, when Law 82/1980, of December 30, 1980, started an ambitious promotion of this kind of energy. After 1980, several laws and regulations have intensively developed the renewable energy sector, primarily Royal Decree 436/2004, of March 12, 2004. This intense development has transformed Spain in one of the most advanced countries in the use of renewable energy. Moreover, as a signatory of the Kyoto Protocol, Spain is highly involved in increasing the use of renewable energy. On August 26, 2005, the Spanish Government approved the new Renewable Energy Plan, according to which 12% of the primary energy consumption and 29.4% of the gross energy generation should come from renewable energy by 2010.

Royal Decree 436/2004, of March 12, 2004, superseded the former regulations on renewable energy and established a new legal and financial framework for special regime generation activities. The main purposes of this Royal Decree are the establishment of a stable, predictable and transparent remuneration system for the special regime and the promotion of clean energy such that it will constitute approximately 30% of total electricity consumption by 2010.

The new financial framework established by Royal Decree 436/2004 allows special regime generators to choose between selling their energy at market prices (in the electricity pool, the long-term pool or through bilateral agreements, in all cases, plus certain premiums and incentives) or at set tariffs (to distributors). These incentives, premiums and tariffs are calculated as a percentage over the average tariff. The update of the mentioned premiums, incentives and tariffs takes place every 4 years from 2006. The new remuneration system only affects the new plants while the currently operating plants enjoy a transitional period to be adapted to the new remunerations system.

Environmental activities

During 2005, increased development of renewable energy and a strategic focus on CO2 emissions were key drivers of HidroCantábrico’s performance. HidroCantábrico also applied considerable efforts to minimize the environmental impact of processes required to assure energy supply. As an example of this commitment, flue gas desulphurization and NOx emission reduction systems are currently being installed in thermal units in order to reduce acidification.

Climate change

An emissions trading scheme was established in Spain during 2005, including the creation of the National Emission Allowance Registry. An account has been assigned for each industrial plant where the balance of both allocated and purchased allowances will be registered.

In 2005, the growth in energy demand together with low hydroelectric generation resulted in intensive use of thermal power plants in the Spanish electricity system. Consequently, HidroCantábrico coal and natural gas power plants operated above expectations for an average year.

The Aboño thermal unit, one of the most efficient in Spain, is a multi-fuel station that burns a mix of fuels including imported coal and blast furnace gases produced by the nearby Arcelor steelworks factory. As a result, its emissions are increased with transferred CO2. This activity is an example of valorization of a pollutant by-product, which decreases environment impacts to a large extent through the cooperation between two companies.

Efforts against climate change by HidroCantábrico include recurrent programs to increase efficiency in generation units. Examples include projects for reducing unburned fuel, the reduction of fuel consumed in start-ups, and the upgrading of turbine blades.

HidroCantábrico is developing a position in clean development mechanisms, participating in projects and developing mechanisms to reduce emissions through a presence in the Community Development Carbon Fund to which HidroCantábrico contributed $2.5 million. This fund has signed four projects amounting to 0.8 MtCO2e, has approved 13 projects amounting to 5.1 MtCO2e and is analyzing 34 other projects that will contribute an additional 18.8 MtCO2e.

 

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Environmental impact control

One of the main aspects of the environmental management system of HidroCantábrico is the identification of all relevant environmental aspects, defined as those activities, products or services in the organization that can impact the environment. Controlling and reducing these impacts is one of the key objectives for HidroCantábrico.

HidroCantábrico is working on several projects to reduce pollutant emissions in thermal power plants in order to comply with the National Emission Reduction Plan for Large Thermal Units, which implements Royal Decree no. 430/2004, of March 12, 2004, the transposition of EU Directive 2001/80/CE related to Large Combustion Plants. Equipment is being installed in the Aboño and Soto units for removing sulfur in emission gases, based on wet technology, and low NOx burners are also being installed that will reduce the emission of such gasses by around 95% and will reduce the particles in the flue gas by 50%.

Waste management

The largest amount of waste generated by HidroCantábrico facilities is flying ash and slag from coal plants. In 2005, 73% of this waste produced was recycled for cement production, road construction and other uses, reducing final waste volume and environmental impact.

Environmental management system

HidroCantábrico has adopted the Integrated Environmental Management System that involves all organization levels. It is implemented through working groups and committees and eases the processes for further environmental certifications in operating units. Under the Integrated Environmental Management System, HidroCantábrico worked during 2005 to prepare for UNE/EN/ISO 14001 certification in all thermal units.

GAS SYSTEM OVERVIEW

The development of the natural gas infrastructure in Spain reflects its extremely low national production of natural gas and its geographical position far from European gas fields. Currently, the Spanish natural gas system consists of the following physical components:

 

    a high pressure network, consisting of 7,500 km, with four international connections, one with France, one with Morocco and two with Portugal, and approximately 340 gas regulation and measurement stations;

 

    four operating regasification plants and two under construction;

 

    three small gas deposits for national production;

 

    two underground storage units, located at Serrablo and Gaviota;

 

    a national dispatch center that oversees the entire high pressure system, including its terminal and underground storage units; and

 

    a distribution network, consisting of more than 31,000 km of gas pipelines, which connects each consumer to the high-pressure transportation network.

As national production in Spain is limited, natural gas supply relies mainly on imports, either through international gas pipelines or regasification terminals within Spain that receive LNG transport vessels. Imported gas in 2005 totaled 389.7 TWh. Algeria was the main supplier and the Persian Gulf countries, Nigeria and Egypt were other significant suppliers.

Natural gas consumers in Spain can choose from three types of supply:

 

    Tariff supply through a distributor, which is the traditional relationship model between a customer and a gas company. The customer buys gas from the distributor, to whom it pays the regulated price or tariff.

 

    Supply through a trader, for which a qualified customer enters into a supply contract with a trading company to pay a freely negotiated, competitive price. The trading company enters into gas purchase contracts on international markets and access contracts with the transporter and distributor.

 

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    Direct purchase by a qualified consumer, for which the consumer buys the gas directly on the international market and enters into a contract for access to the gas transportation and distribution installations. This option is only practical for large consumers.

In 2005, natural gas consumption in Spain was 375.7 TWh. This volume consisted of consumption by industrial customers (53.8%), electric power stations (29.6%) and commercial customers (14.9%).

Competition

At the end of 2005, there were 2,081,172 consumers operating in the liberalized market, representing 34% of the total gas consumers in Spain. Taking into account that at the end of 2004 there were a total of 1,218,785 consumers in the liberalized market, the increase during 2005 has been more than 70%. In terms of energy, 83%, or 314,827 GWh, was sold in the liberalized market.

Most consumers in groups 1 and 2, industrial customers, were in the liberalized market and these liberalized customers accounted for 98% of the total consumption in groups 1 and 2. Liberalized consumers comprise 92% and 93% of groups 1 and 2, respectively.

With respect to group 3, residential and commercial customers, 37% of energy consumed was purchased in the liberalized market and 34% of customers were in the liberalized market.

GAS REGULATION

Law no. 34/1998, of October 7, 1998, began the liberalization process of the Spanish natural gas sector and has been amended several times in recent years in order to improve this liberalization process. The main features of the current regulatory framework are as follows:

 

    the unbundling of activities so that no operator can simultaneously carry out regulated activities (regasification, strategic storage, transmission, distribution and supplying at set tariffs) and liberalized activities (trading at market prices) simultaneously;

 

    as of January 1, 2003, all consumers, regardless of their consumption, are fully eligible to select their suppliers as well as the method of supply, either at market prices (unregulated market) or with a set tariff (regulated market); In order to promote liberalization of the gas sector, the government is preparing the substitution of the current regulated-unregulated market scheme by an unregulated-last resort supply scheme. Under the latter scheme, a last resort operator appointed by the government will be the only one able to supply domestic and small consumers under a last resort tariff. The rest of consumers will be supplied under market prices. These changes are expected to take place in 2008.

 

    all operators and consumers have the right to access the transmission and distribution grids by paying access tariffs previously approved by the Spanish government. This right is based on principles of free access, objectivity and transparency. Access to the grid can only be denied under circumstances set forth in certain laws and regulations in cases where there is a lack of capacity or reciprocity;

 

    all tariffs, tolls and royalties are based on costs that are transferred to consumers of natural gas. The tariff is based on levels of pressure and consumption rather than by type of use. The tolls and royalties for transport and distribution are based on the level of pressure at which the network is connected to the consumers’ installation and on the volume of annual consumption rather than on distance; In order to avoid asymmetries between the regulated market and the unregulated market, some tariffs for big consumers have been eliminated in 2006. It is expected that all the tariffs will be substituted in 2008 by a last resort tariff just for domestic and small consumers. The rest of consumers will be supplied under market prices.

 

    to ensure that ENAGAS, S.A., the current technical manager of the system, as well as the owner of the majority of the high-pressure transmission grid, is guaranteed the highest level of independence, the maximum stake that can be legally held in it, directly or indirectly, by any shareholder has been reduced to 5%. Any necessary reductions must take place before December 31, 2006;

 

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    Royal Decree no. 1434/2002, of December 27, 2002, specifically regulating transmission, distribution, trading and supply activities, as well as the process of authorizing natural gas plants and installations, regulates relations between gas companies and their customers, both in the regulated and unregulated markets; and

 

    Royal Decree no. 1716/2004, of July 23, 2004, sets forth obligations concerning minimum security reserves and natural gas supply diversification.

Spanish law prescribes the following roles for participants in the Spanish gas system:

 

    Producers, who carry out exploration, research and mining of hydrocarbon deposits.

 

    Transporters, who own natural gas storage facilities, regasification plants or high-transportation pipelines with pressure above 16 barg. Transporters purchase natural gas on the international market for sale to distributors for the tariff market. They also allow third parties (transporters, traders and qualified consumers) to access their facilities upon application and payment of a toll.

 

    Distributors, who own natural gas distribution facilities that have pressure below 16 barg and supply just one consumer. Distributors buy gas from transporters at a regulated transfer price and sell it at a regulated price to tariff customers. Like transporters, distributors must also allow third party access to their facilities.

 

    Traders, who purchase natural gas from producers or other traders and sell it to their qualified customers or other traders under freely negotiated terms and conditions. Traders use the installations belonging to transporters and distributors to transport and supply gas to their customers in exchange for the payment of a toll.

 

    Qualified consumers, who can choose between purchasing gas from their distributor at a regulated tariff or purchasing gas from any trader under freely negotiated terms and conditions. Since January 1, 2003, all Spanish gas consumers have been able to choose their supplier.

 

    Tariff consumers, who have entered into a supply contract with a distribution company to which they pay the regulated tariff.

 

    The Technical System Manager, who is responsible for the technical management of the primary and secondary natural gas transportation networks. This role, as well as coordination of agents in the system, has been assigned to ENAGAS as the leading transporter.

The National Energy Commission is the public agency assigned the task of ensuring effective competition in energy systems and the objective, transparent functioning of those systems for the benefit of all agents operating in those systems as well as consumers. To do so, it acts as an advisory body to the Spanish Government, participates in the process of developing regulations and authorizing installations and acts as an arbitration body in disputes between different agents in the energy systems.

GENERATION

PORTUGAL

As of December 31, 2005, our Portuguese electricity generation facilities consisted of hydroelectric, thermal (coal, fuel oil, natural gas and gas oil), biomass, cogeneration and wind generation facilities, and had a total installed capacity of 8,921 MW (including an additional 392 MW unit of the Ribatejo CCGT plant, which began commercial operation in October 2005, five months ahead of schedule, and the new two-unit hydroelectric power station of Frades with a total of 192 MW, which is a reinforcement of the power station of Vila Nova/Venda Nova), 7,164 MW of which was in the PES and 1,757 MW of which was in the IES. As of December 31, 2005, approximately 49.4% of our generation capacity was represented by hydroelectric facilities, 34.4% by thermal facilities, 13.2% by CCGT facilities and 3.0% by wind-driven, biomass and cogeneration facilities. We do not own or operate any nuclear-powered facilities in Portugal.

We currently hold most of our generation assets in EDPP, which in 2005 accounted for approximately 97% of our generation in Portugal. Our other companies that own or operate generation assets in Portugal are EDP Comercial, Enernova and EDP Bioeléctrica. EDPP 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.

 

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Our installed capacity in the PES of 7,164 MW represents approximately 82.0% 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. At the end of 2004, we decommissioned the last unit at the Tapada do Outeiro plant (46.9 MW), and the PPA between EDPP and REN for the two old generating units of Tunes (32 MW) also reached maturity. However, in this case, these two units were considered useful for system services by REN. EDPP and REN entered into a contract pursuant to which EDPP maintains the plant and keeps it in operation only for the purpose of the supply of system services. Our smaller hydroelectric plants, wind generating facilities and cogeneration and biomass plants are part of the IES. In the IES, in addition to the three Ribatejo CCGT units, one of which entered into service in 2005, there was a capacity increase resulting from the entering into service of the Alqueva hydroelectric power plant in 2004 owned by EDIA-Empresa de Desenvolvimento e Infra-estruturas de Alqueva, S.A., or EDIA, a company wholly-owned by the Portuguese Republic that is developing a multi-purpose hydroelectric project for irrigation and the production of electricity.

In 2005, our net electricity generation in Portugal was approximately 24.1 TWh, excluding special regime production. According to REN, total net generation in Portugal in 2005 was approximately 48.0 TWh.

On March 16, 2005, we exercised a call option for a total consideration of €52 million for the purchase from National Power International Holdings BV, or IPBV, of a 20% shareholding and related shareholder loans in Turbogás and a 26.667% shareholding and related shareholder loans in Portugen. Following the completion of this transaction, we now hold a 40% shareholding in Turbogás and a 26.667% shareholding in Portugen. Turbogás was incorporated in 1994 with the sole purpose of developing, constructing and operating a CCGT plant at Tapada do Outeiro, in Portugal, with a total installed capacity of 990 MW. Turbogás currently sells all of its production to REN, within the PES under a long term PPA. Since 2002, Turbogás has generated 24,970 GWh, of which 6,287 GWh were generated in 2005. For more information on these transactions, see “—Other Investments and International Activities.” In addition, we have also reached an agreement with International Power Portugal Holdings S.G.P.S., S.A., or 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.

 

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The following maps set forth EDP’s power plants in Portugal, the PES and in the IES, as of December 31, 2005.

LOGO

 

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LOGO

 

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The following table sets forth our total installed capacity by type of facility at year-end for the years 2001 through 2005.

 

     As of December 31,

Type of Facility

   2001    2002    2003    2004    2005
     (in MW)

Hydroelectric:

              

Public System hydroelectric plants(1)

   3,903    3,903    3,903    3,903    4,094

Independent System hydroelectric plants(2)

   309    309    311    310    310
                        

Total hydroelectric

   4,212    4,212    4,214    4,213    4,404

Thermal(3)

   3,281    3,281    3,149    3,149    3,070

Wind(4)

   41    41    65    136    151

Biomass

   9    9    9    9    9

Cogeneration

   67    111    111    111    111

CCGT(5)

   0    0    392    784    1,176
                        

Total

   7,610    7,654    7,939    8,402    8,921

(1) In 2005, the Frades hydroelectric power station (192 MW) entered into operation as a reinforcement of the power station of Vila Nova/Venda Nova.
(2) In 2004, the Ermal power station began operations as a special regime producer with 9.9 MW instead of its previous 11.2 MW in the NBES.
(3) On June 30, 2003, the PPA of the Alto de Mira plant, and on December 31, 2005, the PPA of Tapada do Outeiro plant expired and the plants were decommissioned. The PPA of the two older generating units of Tunes also expired on December 31, 2005. Those units are kept in operation under a contract of system services with REN but we do not consider their capacity in this table.
(4) The new wind facilities that began operation in 2005 were Pena Suar (16 MW), Vila Nova (26 MW), Fonte da Quelha (13.5 MW) and Alto do Talefe (13.5 MW).
(5) The Ribatejo CCGT plant was in testing at the end of 2003. The first 392 MW unit of this plant began commercial service on February 14, 2004, the second 392 MW unit on November 2, 2004, and the third on October1, 2005.

Hydroelectric generation is dependent upon hydrological conditions. In years of less favorable hydrological conditions, less hydroelectricity is generated, and the PES depends on 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 approximately 11 TWh and can reach about 15 TWh in a wet year and may fall to less than 7 TWh in a dry year. Between 1995 and 2005, our hydroelectric production ranged from a low of 4.5 TWh in 2005, a very dry year, to a high of 14.9 TWh in 2003, a record wet year.

The following table summarizes our net electricity production (excluding internal losses and consumption of the plants) by type of generating facility from 2001 through 2005 and also sets forth our hydroelectric capability factor for the same period:

 

     As of December 31,

Type of Facility

   2001    2002    2003    2004    2005
     (in GWh, except hydroelectric capability factor)

Hydroelectric:

              

Public System hydroelectric plants(1)

   12,607    6,764    13,964    8,718    4,280

Independent System hydroelectric plants(2)

   790    573    901    539    254
                        

Total hydroelectric

   13,397    7,336    14,865    9,257    4,534

Thermal:

              

Coal

   8,677    9,532    9,473    9,530    9,590

Fuel oil and natural gas

   5,613    7,892    3,119    2,215    4,937

Gas oil

   50    13    26    5    18

Cogeneration

   423    590    679    656    671

CCGT(2)

   0    0    203    3,419    5,088
                        

Total thermal

   14,763    18,027    13,500    15,825    20,304

Wind

   90    113    128    237    348

Biomass

   18    37    38    49    51
                        

Total

   28,269    25,513    28,532    25,368    25,237

Hydroelectric capability factor(3)

   1.19    0.75    1.33    0.83    0.41

(1) Includes the following amounts of our own consumption for hydroelectric pumping: 485 GWh in 2001, 670 GWh in 2002, 485 GWh in 2003, 408 GWh in 2004 and 564 GWh in 2005.

 

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(2) The Ribatejo CCGT plant was in testing at the end of 2003. The first unit of this plant began commercial service on February 14, 2004, the second unit on November 2, 2004, and the third unit on October 1, 2005.
(3) The hydroelectric coefficient varies based on the hydrological conditions in a given year. A hydroelectric capability factor of one corresponds to an average year, a factor less than one corresponds to a dry year and a factor greater than one corresponds to a wet year.

The average availability for production of EDPP’s plants remained at favorable levels from 2001 to 2005. For thermal plants it remained relatively stable, decreasing slightly from 94.4% in 2004 to 93.5% in 2005. For hydroelectric plants, it increased from 94.8% in 2001 to 97.1% in 2004 and decreased slightly to 96.6% in 2005.

A forced outage is unplanned non-availability at a power plant caused by trips, critical repairs or other unexpected occurrences. Non-availability results from planned maintenance and forced outages. EDPP is reducing planned maintenance outages through more efficient maintenance techniques. EDPP’s generating facilities have achieved 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 2001 through 2005, forced outages of EDPP’s thermal plants have ranged between 2.1% (2003) and 4.1% (2005). During the same period, forced outages of EDPP’s hydroelectric plants ranged between 0.3% (2005) and 1.0% (2001). In 2005, forced outages of EDPP’s thermal plants were 4.1% and hydroelectric plants were 0.3%.

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 EDPP 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)

Year ended December 31,

   

Average availability factor

Year ended December 31,

 

Type of Facility

   2001     2002     2003     2004     2005     2001     2002     2003     2004     2005  

Hydroelectric

   36.9 %   19.8 %   40.8 %   25.4 %   12.5 %   94.8 %   95.9 %   96.8 %   97.1 %   96.6 %

Thermal:

                    

Coal

   83.1 %   91.3 %   90.7 %   91.0 %   91.8 %   90.5 %   94.0 %   94.2 %   92.9 %   93.8 %

Fuel oil and natural gas

   36.4 %   51.2 %   20.2 %   14.3 %   32.9 %   96.6 %   93.9 %   90.9 %   94.9 %   92.7 %

Gas oil(2)

   1.7 %   0.4 %   1.2 %   0.3 %   1.0 %   98.4 %   99.1 %   98.0 %   98.8 %   99.5 %
                                                            

Total weighted average thermal(3)

   49.9 %   60.7 %   44.8 %   42.5 %   53.5 %   94.6 %   94.4 %   92.7 %   94.4 %   93.5 %

(1) The average capacity utilization is defined as actual production as a percentage of theoretical maximum production.
(2) Increase in average capacity utilization in 2003 was due to the need to use the fuel stock of the Alto de Mira power plant in the context of its decommissioning.
(3) Weighted average is based on total installed capacity of the thermal system.

During the period from 2001 through 2005, EDPP had operating and maintenance costs, excluding fuel and depreciation costs, below the limits contained in the relevant PPAs over that time period. Although management expects to continue maintaining these costs below the PPA limits in 2006, we expect most of the PPAs to terminate as a result of the provisions of Decree law no. 240/2004. On June 30, 2003, the PPA of our 132 MW Alto de Mira plant terminated on the scheduled expiration date. The three-unit Tapada do Outeiro plant was progressively decommissioned until the end of 2004, and the last unit was decommissioned on December 31, 2004. The gas oil Tunes plant, with four units, had the PPA relating to its first two (32 MW) units terminated on December 31, 2004. Since that PPA termination, the affected units at Tunes are serving the national grid, providing ancillary services pursuant to an agreement with REN.

Hydroelectric plants

As of December 31, 2005, we owned and operated 26 hydroelectric generating facilities in the Binding System, with 65 total units and an aggregate installed capacity of 4,095 MW.

In the IES, EDPP now owns and operates 224.9 MW. EDPP also operates 84.9 MW owned by EDP Comercial and 240 MW owned by EDIA (the Alqueva plant). As a result, the total maximum capacity operated by EDPP was approximately 4,645 MW as of December 31, 2005.

 

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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, ordered by installed capacity as of December 31, 2005, 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

EDPP 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

Carrapatelo

   201.0    Run of river    1971   

Picote

   195.0    Run of river    1958    1969

Frades

   191.6    Reservoir    2005   

Pocinho

   186.0    Run of river    1983   

Régua

   180.0    Run of river    1973   

Castelo de Bode(1)

   159.0    Reservoir    1951    2003

Vila Nova (Venda Nova/Paradela)

   144.0    Reservoir    1951/56    1994

Torrão

   140.0    Reservoir    1988   

Fratel

   132.0    Run of river    1974    1997

Vilarinho Furnas

   125.0    Reservoir    1972/87   

Crestuma-Lever

   117.0    Run of river    1985   

Cabril

   108.0    Reservoir    1954    1986

Alto Rabagão

   68.0    Reservoir    1964   

Caniçada

   62.0    Reservoir    1954    1979

Tabuaço

   58.0    Reservoir    1965   

Bouçã

   44.0    Reservoir    1955    1988

Salamonde

   42.0    Reservoir    1953    1989

Pracana

   41.0    Reservoir    1950/93    1993

Caldeirão

   40.0    Reservoir    1994   

Raiva

   24.0    Reservoir    1982   

Touvedo

   22.0    Reservoir    1993   
             

Total

   4,094.6         

Independent System Hydroelectric Plants:

           

EDPP plants:(2) (3)

   224.9    Various    Various   

EDP Comercial plants(4)

   84.9    Various    Various   
             

Total maximum capacity

   4,404.4         

(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) As a result of recent reorganizations, EDPP integrated 28 plants owned by HDN and Hidrocenel with capacities ranging from 0.1 MW to 44.1 MW and dates of entry into service from 1906 to 2004.
(3) In 2004, the Ermal power station began operations as a special regime power station with 9.9 MW instead of the previous 11.2 MW.
(4) EDP Comercial owns four plants with capacities ranging from 0.72 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 of EDPP’s hydroelectric power plants operating under PPAs for the last three years, as well as the end date of each PPA.

 

          Annual net generation

Hydroelectric plants

   End of PPA    2003    2004    2005
     (in GWh)

Alto Lindoso

   2024    948    532    268

Touvedo

   2024    72    46    23

Alto Rabagão

   2015    145    89    57

Vila Nova (Venda Nova/Paradela)

   2015    720    484    188

Venda Nova 2/Frades(1)

   2027    —      —      112

Salamonde

   2015    261    199    108

Vilarinho Furnas

   2022    181    162    57

Caniçada

   2015    347    263    139

Miranda

   2013    1,365    797    420

Picote

   2013    1,121    879    493

Bemposta

   2013    1,374    913    488

Pocinho

   2024    681    388    167

Valeira

   2024    1,049    617    271

Vilar-Tabuaço

   2024    178    88    19

Régua

   2024    891    576    253

Carrapatelo

   2024    1,092    765    334

Crestuma-Lever

   2024    513    309    139

Torrão

   2024    314    208    126

Caldeirão

   2024    76    17    16

Aguieira

   2024    614    351    354

Raiva

   2024    66    31    13

Cabril

   2015    491    236    59

Bouçã

   2015    230    128    30

C. Bode

   2015    608    266    46

Pracana

   2024    99    33    22

Fratel

   2020    528    339    77
                 

Total Hydro

      13,964    8,718    4,279

(1) This plant, a power reinforcement of Venda Nova, started industrial service in August 2005.

Thermal plants

EDPP operates all our conventional thermal power plants in the PES, with total installed capacity, as of December 31, 2005, of 3,069.6 MW and installed capacity per generating unit ranging from 27 MW to 298 MW. The following table sets forth, as of December 31, 2005, 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

   Year 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(2)

   165.0    Gas oil    28.3    2    1982

Barreiro

   56.0    Fuel oil    34.1    2    1978
                

Total maximum capacity

   3,069.6            

(1) These units began burning natural gas in 1997.
(2) The PPA for the first two units (32 MW) terminated on December 31, 2004, and these units now have a system service agreement with REN (the company that operates the national grid).

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

The following table presents the net generation of EDPP’s thermal power plants operating under PPAs for the last three years, as well as the expected end date of each PPA and the fuel costs per power station.

 

          Annual Net Generation    Annual Fuel Costs

Thermal plants

   End of PPA    2003    2004    2005    2003    2004    2005
          (GWh)    (thousands of EUR)

Sines

   2017    9,473    9,530    9,590    131,771    179,818    209,402

Setúbal

   2012    1,834    1,683    3,556    71,333    64,405    172,617

Carregado (I and II)

   2010    1,091    327    1,162    51,075    17,063    57,851

Barreiro

   2009    195    200    220    16,971    15,573    22,643

Tunes (III and IV)

   2007    26    10    18    2,757    877    2,196
                                

Total

      12,619    11,750    14,545    273,908    277,736    464,709

 

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Energy sources

Fuel

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

EDPP fuel consumption costs, including transportation costs, were €666.3 million in 2005 and €380.3 million in 2004. The increase in the total cost of fuel consumed from 2004 to 2005 resulted primarily from 2005 being a drier year than 2004, the higher cost of fuel in 2005 and the added consumption in 2005 of the new Ribatejo CCGT plant

The table below shows the costs of fuel consumed by EDPP from 2001 through 2005.

 

     As of December 31,

Type

   2001    2002    2003    2004    2005
     (thousands of EUR)

Imported coal

   142,810    148,773    130,531    179,062    208,570

Fuel oil(1)

   193,867    259,816    117,716    86,336    248,188

Gas oil(2)

   4,618    1,526    2,744    586    2,196

Natural gas

   12,260    24,497    22,917    114,354    207,310
                        

Total

   353,555    434,612    273,908    380,337    666,264

(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 EDPP in each of the last five years.

 

     As of December 31,

Type

       2001            2002            2003            2004            2005    
     (thousands of metric tons, except natural gas)

Imported coal

   3,108    3,587    3,593    3,562    3,559

Fuel oil(1)

   1,237    1,941    716    422    1,339

Gas oil

   26    3    10    1    7

Natural gas(2)

   60    150    131    632    861

(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 entering into commercial service of two units of the Ribatejo CCGT power plant. The increase in 2005 is due to the entering into commercial service of the third unit of the of the Ribatejo CCGT power plant.

Coal

As the Sines power plant is a base load, or continuous operation power plant, EDPP has 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 is defined by REN based on the forecasts for coal consumption for a wet year. The Target Contract Quantity is the basis for long-term supply and shipping contracts, which are negotiated by EDPP, subject to REN approval. In addition, EDPP makes spot-market purchases as necessary. In 2005, EDPP purchased 98% of its coal through long-term contracts and 2% of its coal on the spot market. In 2004, EDPP purchased 63% of its coal through long-term contracts and 37% of its coal on the spot market. In 2003 and 2002, EDPP purchased 78% of its coal through long-term contracts and 22% of its coal on the spot market.

 

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The following table shows the evolution of EDPP’s coal purchases from 2001 to 2005 by geographic markets as a percentage of total purchases for that year.

 

     As of December 31,  

Region

   2001     2002     2003     2004     2005  

South Africa

   28.0 %   28.9 %   34.6 %   29.5 %   34.0 %

United States

   17.0 %   3.2 %   9.9 %   13.1 %   10.6 %

Australia

   13.0 %   23.2 %   18.6 %   3.7 %   0.0 %

South America

   27.0 %   16.3 %   32.9 %   41.1 %   39.2 %

Southeast Asia

   15.0 %   16.9 %   0.0 %   4.4 %   4.0 %

Europe

   0.0 %   11.3 %   4.0 %   8.2 %   12.2 %
                              

Total

   100 %   100 %   100 %   100 %   100 %

In 2005, the average cost of coal consumed was €56.7 per ton. In 2004, the average cost of coal consumed was €50.3 per ton. In 2003 and 2002, the average cost of coal consumed for imported coal was €36.7 per ton and €41.4 per ton, respectively. The increase in 2005 reflects the high prices associated with a long-term contract entered into in 2004.

Fuel oil and gas oil

Fuel oil purchases by EDPP are made in the spot market and pursuant to contracts. EDPP purchases fuel oil from refineries in Europe, primarily in northwestern Europe and also in Portugal, 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 2005 was €201.2 per ton, compared with €154.1 and €164.8 in 2004 and 2003, respectively. The value in 2004 was due to the low market prices, which did not follow the crude prices, resulting from low demand and of the favorable exchange rate (USD/Euro). The increase in 2005 was due to change in the market prices at the end of 2004, which began to reflect the high crude prices. To reduce the emissions impact of our operations on the environment, EDPP has shifted its fuel oil purchases to lower sulfur fuel oil, which has increased the cost of consumed fuel oil. In 2005, the average sulfur content of fuel oil purchased by EDPP was approximately 0.9%, compared with 0.8% in 2004. The use of lower sulfur fuel oil has increased, and will increase in the future, the average cost of fuel oil consumed.

EDPP 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 EDPP, as required by REN.

Natural gas

EDPP has had access to natural gas as a source of primary energy since Transgás began importing natural gas from Algeria into Portugal in 1997. EDPP converted two units of Carregado into dual-fired (fuel oil and natural gas) units in late 1997. In 2005, EDPP purchased 861 million cubic meters of natural gas for a total of €207.3 million compared to 632 million cubic meters of natural gas in 2004 for a total of €114.4 million. For more information on our activities related to natural gas you should read “—Gas.”

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 in which we are participating.

 

Facility

  

Type of

Generation

  

Developing

entity

  

Planned capacity

(MW)

  

Target

year

   Status

Picote II

   Hydroelectric    EDPP    236    2011    Licensing

Bemposta II

   Hydroelectric    EDPP    178    2012    Licensing

Baixo Sabor

   Hydroelectric    EDPP    180    2013    Licensing

Small hydro

   Hydroelectric    EDPP    20    2006/2010    Planning

New CCGT plants

   CCGT    EDPP    4 x 400    2009/2014    Planning

Sines

   Super critical coal    EDPP    750    2013/2014    Planning

Foz Tua

   Hydroelectric    EDPP    208    2014    Planning

 

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Capital expenditures

In 2005, we spent €237.2 million in capital expenditures in technical costs for our generation facilities, compared with €246.9 million in 2004 and €261.1 million in 2003. 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 2005, investing €81.4 million in the new Ribatejo CCGT (combined cycle gas turbine) power plant and €42.6 million in wind energy farms.

The following table sets forth our capital expenditures in technical costs from 2001 through 2005 on plants by type and status of generating plant.

 

     Year ended December 31,

Plant type and status

   2001    2002    2003    2004    2005
     (thousands of EUR)

Thermal/Hydro

              

Public Electricity System

              

Hydroelectric plants under construction

   16,877    25,690    34,359    24,127    3,558

Hydroelectric plants in operation

   10,289    12,756    11,732    11,849    13,604

Thermal plants in operation

   14,764    16,261    20,340    12,955    75,659

Plants under study

   1,450    1,011    349    729    4,653
                        

Total PES

   43,380    55,718    66,780    49,659    97,473

Independent Electricity System

              

Hydroelectric plants

   4,964    4,137    3,849    1,018    2,141

Ribatejo CCGT

   58,535    142,946    142,350    128,329    81,317

Wind

   6,521    11,159    38,389    53,667    46,030

Cogeneration facilities

   13,083    9,602    255    129    249

Biomass(1)

   0    35,180    614    155    0
                        

Total IES

   83,103    203,024    185,456    183,298    129,736

Others(2)

   0    0    312    2,854    2,711

Non-specific investment(3)

   5,250    17,721    8,599    11,089    3,108
                        

Total Generation

   131,733    276,463    261,147    246,900    233,029

(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 “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

Early termination of the PPAs

The generation capacity of EDPP plants in the PES is bound to the PES under PPAs between EDPP and REN. Under the PPAs, EDPP is guaranteed a monthly fixed revenue component (capacity charge) that remunerates, at an 8.5% real rate of return on assets, the net asset value of EDPP’s power plants. The revenue amount EDPP 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 EDPP to 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 will be terminated in connection with the creation of MIBEL.

Pursuant to Law no. 52/2004, of October 29, 2004, enacted by the Portuguese parliament, Decree law no. 240/2004 establishes the conditions for the early termination of the PPAs and defines compensatory measures for the respective contracting parties through the pass-through of charges to all electric energy consumers as permanent components of the Global Use of System Tariff. The early termination of the PPAs set forth in the Decree law is subject to certain conditions, which include the ministerial approval of termination agreements between EDP and REN, (ii) the entry into force of MIBEL under conditions that allow the sale of electricity produced and (iii) the granting of non-binding generation licenses to the

 

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relevant producers. The first of these conditions was met on March 4, 2005 when the Ministry of Economy approved the termination agreements entered into by us and REN on January 27, 2005 for all of EDPP’s power plants operating in the PES. Although the MIBEL forward sale market managed by OMIP began operations on July 3, 2006, it is still unclear whether the conditions have been met to allow the sale of the electricity produced by EDP in MIBEL.

The termination of each PPA grants to the producer a right to cash compensation as a way to guarantee economic benefits equal to the portion of the benefit that is not otherwise sufficiently guaranteed to be received as future revenue under a free market regime. The gross value of the compensation corresponds to the difference between the present value of each PPA and the present value of the forecasted market revenues, net of fuel and variable O&M costs.

For the purposes of calculating this compensation, the value of each PPA includes the depreciation and remuneration of the relevant initial net asset value and the additional investment value, the fixed and variable operation costs and the forecasted market revenues, net of fuel and variable O&M costs, which must correspond to the expected production for the relevant power plant multiplied by the reference market price, reduced by the corresponding variable operating charges. These amounts are to be updated at a rate (as of a date closer to the entry into force of MIBEL and the effective termination dates of the PPAs) equal to the yield of Portuguese public debt with a maturity date close to the average life of all PPAs of each generator, plus 25 basis points. The reference average annual price, as defined in Decree law no. 240/2004, is €36/MWh.

The termination agreements that were signed on January 27, 2005 set the estimated amount of compensation to be granted to us as a result of the early termination of all of our PPAs. These termination agreements contemplate, among other things, the commencement of MIBEL operations by June 30, 2005, which did not occur. The termination agreements contemplated a present value of the compensation as of July 1, 2005 of at €3,356 million. This compensation, designed to ensure economic benefits equivalent to those delivered by the PPAs to all parties to these contracts, was calculated based on a number of economic assumptions and parameters including the present value of the existing PPAs, the forecasted revenues of these power plants operating under market conditions and a discount rate of 3.78%. However, the actual amount of compensation granted to us as a result of the early termination of all our PPAs will be different because the commencement of MIBEL operations did not occur as anticipated.

The compensation value for the early termination of the PPAs was deemed adequate by two independent entities, the investment bank Rothschild and the consulting firm Deloitte & Touche, based upon the applicable legal framework, market valuation and a set of data and assumptions provided by, among others, EDP.

During the first ten years after termination, the initial amount of the compensation relating to each PPA termination agreement is subject to annual positive or negative adjustments, based on the real net revenue obtained in a market regime, so as to ensure appropriate economic benefits equivalent to the PPAs. At the end of the tenth year, the compensatory amount must be subject to a final adjustment to be calculated based on a new forecast of the net revenues for the remaining period. However, the amount of compensation is subject to a global maximum amount per producer and is calculated based on the values set forth in Decree law no. 240/2004, updated by a rate equal to the yield of Portuguese public debt and assuming an inflation rate of 2% a year.

The Decree law sets forth a tax neutrality regime that allows for the inclusion of the compensation amounts in the taxable income of producers only when such amounts are recovered through energy tariffs.

The Decree law also allows securitization of compensation amounts, establishing a set of rules concerning billing and collection of such compensation that assure the rights of producers and third parties to cash flows. We are considering securitizing the compensation amounts and using the proceeds for the partial redemption of our financial indebtedness, although we cannot assure you that this securitization will occur.

Competition

The existing power stations of EDPP, which accounted for 97.3% of our generating capacity in Portugal in 2005, operate in the PES and in the IES. The earnings that EDPP derives from the power stations in the PES, in accordance with the terms of the PPAs, are dependent on the availability of capacity and are substantially unaffected by levels of actual output.

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 practices in the electricity generation sector. In addition to these two power stations, we have constructed

 

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plants to operate in the Independent Electricity System, such as the Ribatejo CCGT plant. The first unit of this plant entered commercial service in early 2004. In connection with the creation of MIBEL, the PPAs will be subject to early termination and the power stations operating in the PES will operate in a competitive market. For more information, see “—Early termination of the PPAs” above.

Because Portugal is contiguous only with Spain and there are limited connections between Spain and the rest of Europe, the Portuguese and Spanish governments entered into an agreement for the creation of MIBEL. This agreement calls for, among other things, the harmonization of tariff structures and a common pool for Portugal and Spain. Accordingly, once MIBEL is in operation, we expect to face increased competition in generation and wholesale supply from Spanish participants in the Iberian electricity market. See “—The Iberian Energy Market” and “—Spain.”

SPAIN

HidroCantábrico’s installed capacity represents 4.3% of Spain’s mainland generation capacity, or 5.1% excluding special regime facilities. In 2005, HidroCantábrico had a total installed capacity of 3,207 MW, approximately 48% of which was from coal-fired facilities, 12% from CCGT facility, 13% from hydroelectric facilities, 1% from cogeneration facilities, 2% from waste to energy facilities, 19% from renewable energy facilities other than special regime hydroelectric and 5% from nuclear facilities. HidroCantábrico holds a 15.5% interest in Central Nuclear Trillo I, A.I.E., which owns the Trillo nuclear power plant, corresponding to 165 MW of the plant’s total installed capacity of 1,066 MW.

The following table sets forth HidroCantábrico’s total installed capacity by type of facility at year-end 2003, 2004 and 2005.

 

     As of December 31,

Type of facility

   2003    2004    2005
     (MW) (1)

Hydroelectric:

        

Hydroelectric—Ordinary regime

   432    433    433

Hydroelectric—Special regime

   3    3    3
              

Total hydroelectric

   435    436    436

Thermal:

        

Coal

   1,605    1,605    1,605

CCGT

   393    393    393

Nuclear

   165    165    165
              

Total Thermal

   2,163    2,163    2,163

Cogeneration

   24    41    39

Wind(2)

   81    223    490

Biomass

   3    7    7

Waste

   33    72    72
              

Total

   2,738    2,941    3,207

(1) Capacity figures do not reflect the capacity of plants owned by companies that are consolidated by HidroCantábrico using the equity method of consolidation.
(2) Wind figures include 224 MW owned by DESA, the company bought by Neo Energia in December 2005.

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 / Blast furnace gas /
Fuel gas
   1974

Unit II

   556    Coal / Blast furnace gas /
Fuel gas
   1985

Soto de Ribera

        

Unit I

   68    Coal    1962

Unit II

   254    Coal    1967

Unit III

   361    Coal    1984

Nuclear

        

Trillo(1)

   165    Uranium    1988

CCGT

        

Castejón(2)

   393    Natural gas    2002
          

Total installed capacity

   2,163      

(1) Corresponding to 15.5% of Trillo’s capacity.
(2) The Castejón CCGT unit is operated by Elerebro, of which HidroCantábrico holds a 90.4% stake and EDP holds the remaining the 9.6%.

 

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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

   9.1    Reservoir    1917/24    2002

La Riera

   7.8    Run of river    1946/56    2001

Miranda

   73.2    Run of river    1962    2000

Proaza

   50.3    Reservoir    1968    2002

Priañes

   18.5    Reservoir    1952/67    2003

Salime

   79.7    Reservoir    1954    2003

Tanes (1)

   125.5    Reservoir    1978    1995

La Barca

   55.7    Reservoir    1967/74    2002

La Florida

   7.6    Reservoir    1952/60    1998

Laviana

   1.1    Run of river    1903    2001

Caño

   1.0    Run of river    1928    1996

San Isidro

   3.1    Run of river    1957    2002
             

Total

   432.7         

(1) Tanes is a pumped-storage facility with natural inflows. Pumping capacity is 110 MW.

The average remaining useful life of HidroCantábrico’s hydroelectric generation plants is approximately 45 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 730 GWh, ranging from a maximum of 950 GWh in a wet year to a minimum of 530 GWh in a dry year. These figures include only the electricity production from natural hydrological inflows.

Generation activity in 2005 was characterized by high availability and efficiency of HidroCantábrico’s power plants. Net production in the ordinary regime, which was 15,372 GWh in 2005, increased 6.7% from 14,408 GWh in 2004 (out of a total generation in the Spanish market in 2005 of approximately 213.4 TWh, according to REE). Hydroelectric generation represented 847 GWh in 2005, compared to 854 GWh in 2004. Coal-fired thermal generation amounted to 11,164 GWh in 2005, an increase of 7.8% from 10,356 GWh in 2004. Natural gas-fired thermal generation (combined cycle) amounted to 2,109 GWh in 2005, an increase of 7.5% from 1,961 GWh the previous year. Nuclear generation, corresponding to our 15.5% stake in the Trillo nuclear power plant was 1,252 GWh in 2005, a slight increase of 1.2% from 1,237 GWh in 2004.

 

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The following table summarizes HidroCantábrico’s electricity generation for 2003, 2004 and 2005, excluding losses at generation plants and HidroCantábrico’s own or ancillary consumption, and sets forth the hydroelectric coefficient at year-end 2003, 2004 and 2005.

 

     As of December 31,

Type of facility

   2003    2004    2005
    

(in GWh, except by hydroelectric

coefficient factor) (1)

Hydroelectric:

        

Hydroelectric—Ordinary regime(2)

   861    854    847

Hydroelectric—Special regime

   12    12    5
              

Total hydroelectric

   873    866    852

Thermal:

        

Coal

   10,491    10,356    11,164

Natural Gas

   1,546    1,961    2,109

Nuclear(3)

   1,257    1,237    1,252

Cogeneration

   87    129    212
              

Total thermal

   13,381    13,683    14,737

Wind(4)

   35    272    523

Biomass

   12    15    20

Waste

   86    198    387
              

Total

   14,387    15,035    16,519

Hydroelectric coefficient(5)

   1.07    1.08    1.01

(1) Generation figures do not reflect the generation of plants owned by companies that are consolidated by HidroCantábrico using the equity method of consolidation.
(2) Includes the following amounts generated by hydroelectric pumping: 89 GWh in 2003, 76 GWh in 2004 and 122.5 GWh in 2005.
(3) Corresponding to 15.5% of Trillo’s generation.
(4) Wind figures do not include DESA, the company bought by Neo Energia in December 2005.
(5) The hydroelectric coefficient varies based on the hydrological conditions in a given year. A hydroelectric coefficient of one corresponds to an average year, 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 decreased from 95.4% in 2004 to 94.7% in 2005 for thermal plants and increased from 96.4% in 2004 to 96.6% in 2005 for hydroelectric plants. HidroCantábrico’s forced outages in 2005 were 3.93% for thermal plants and 0.40% for hydroelectric plants.

The table below sets out for each type of HidroCantábrico generating facility the average capacity utilization and the average availability factor for 2003, 2004 and 2005.

 

    

Average capacity utilization (1)

Year ended December 31,

   

Average availability factor

Year ended December 31,

 

Type of Facility

   2003     2004     2005     2003     2004     2005  

Hydroelectric

   23.1 %   22.8 %   22.7 %   87.7 %   96.4 %   96.6 %

Thermal:

            

Coal

   78.8 %   77.7 %   84.0 %   95.7 %   95.0 %   94.0 %

Natural gas(2)

   46.6 %   58.8 %   62.5 %   96.3 %   98.4 %   97.6 %

Nuclear

   93.0 %   91.0 %   92.7 %   93.9 %   92.2 %   93.3 %
                                    

Total weighted average thermal(3)

   74.0 %   75.2 %   80.7 %   95.7 %   95.4 %   94.7 %

(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.

Similar to 2004, the availability and efficiency of HidroCantábrico power plants was high, leading to a 6.7% increase in generation in 2005. The new Castejón plant had an average availability factor of 97.6%. HidroCantábrico had maintenance outages at its Soto 2 and Castejón power plants in 2005, as well as a refueling outage in the Trillo nuclear power plant. HidroCantábrico’s generation facilities benefited from several environmental improvements and equipment upgrades.

Thermal generation consumed 4,102 thousand metric tons of coal in 2005, of which 81.2% was imported and 18.8% was domestic. Fuel consumption costs including transportation amounted to €323 million in 2005 and €293 million in 2004. HidroCantábrico’s fuel costs increased in 2005. The increase in the price of imported coal was mainly due to strong demand in China and India, while the cost of natural gas was influenced by the increase in the price of oil and its derivatives during 2005 due to the rising costs for coal and natural gas. Oil prices have risen steadily due to the growing demand for fuel worldwide, the continuing Iraq conflict, political instability in producing countries (Venezuela, Nigeria) and restrictions on production, refinery and transmission capacity.

 

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In 2005, capital expenditures on generating facilities amounted to €238 million, an increase of 8.0% from 2004. These expenditures are set forth below.

 

     Year ended December 31,

Plant type and status

   2003    2004    2005
     (thousands of EUR)

Hydroelectric plants in operation

   2,107    943    1,175

Thermal plants in operation

   20,151    32,170    57,254

Special regime:(1)

        

Hydroelectric plants in operation

   0    0    3

Wind

   49,047    140,685    176,371

Waste

   3,500    10,530    2,937

Biomass

   350    10,905    0

Cogeneration facilities

   18,720    5,880    0
              

Total Generation

   93,875    201,113    237,740

(1) Data corresponding to Neo Energia, a 42% owned subsidiary of HidroCantábrico as of December 31, 2005, and Genesa, an 80%-owned subsidiary of HidroCantábrico as of December 31, 2003 and 2004, represents 100% of capital expenditures.

HidroCantábrico is planning to develop five CCGT plants as set forth in the table below.

 

Type of Facility

  

Type of

generation

   Developing entity    Planned capacity
(MW)
   Target year    Status

Soto 4 and Soto 5

   CCGT    HidroCantábrico    2 x 400    2008-2009    Licensing Process

Castejón 2

   CCGT    Elerebro    400    2007    Under Construction

Aboño 3

   CCGT    HidroCantábrico    3 x 400    2010-2012    Licensing Process

Alange

   CCGT    HidroCantábrico    2 x 400    2010    Licensing Process

Barajas de Melo

   CCGT    HidroCantábrico    2 x 400    2012    Licensing Process

(1) At the end of 2005, HidroCantábrico signed a contract with Alstom, the leading gas turbine manufacturer, for the construction of Castejón 2 and Soto 4.

HidroCantábrico is currently analyzing other locations for new power plants.

Competition

HidroCantábrico competes with other generators in the wholesale electricity market. The wholesale market was characterized by three very different periods in 2005: January through May, June through August and September through December. In the first five months of 2005, the final prices were higher than those in 2004: €54.5 per MWh in 2005 compared to €31.39 per MWh for the same period in 2004. In the summer period, prices rose to €73.6 per MWh compared to €35.47 per MWh for the same period in 2004. In the last 4 months of 2005 prices remained high at €66.38 per MWh compared to €40.81 per MWh in the same period in 2004. Altogether, the final marginal pool price in 2005 was €62.04 per MWh, which represented a 74.0% increase compared to €35.65 per MWh in 2004. HidroCantábrico’s market share in the Spanish pool was approximately 7.1% in 2005, up from 7.4% in 2004. Including special regime and energy imports, the market share was 6.8% in 2005 and 6.9% in 2004.

This overall price increase in 2005 was caused by the increase in fuel costs, especially oil and gas, reduced hydro availability resulting from a drought, a decrease in nuclear production, the growing demand for electricity and the expenses associated with the CO2 emission rights deficit that began in 2005.

Research and development

Research and development activities carried out in 2005 were aimed at the reduction of emissions, treatment of by-products, maintenance and the extension of equipment life at various plants. They were conducted in coordination with various universities and industry groups and were partially subsidized by the Spanish government and EU entities.

RENEWABLE ENERGY

HISTORY AND OVERVIEW

In 2005, we were the fourth largest renewable energy operator in Iberia, with a total installed capacity at year-end of 1,270 MW, primarily through Neo Energia, which operates most of our special regime assets in Spain, through its subsidiaries Genesa and DESA, and all our wind energy assets in Portugal, through its subsidiary Enernova. We formed Neo Energia in 2005 and began consolidating our renewable energy business into it to take advantage of business development and growth opportunities in the Iberian and international renewable energy markets and to increase business efficiency, both through improved operations and effective synergy capture. The objective was to create an effective and consistent platform designed to promote growth of a business that presents significant potential for future value creation. Two EDP Group companies, Enernova, a 100% subsidiary of EDP, S.A. and Genesa, a 80% subsidiary of HidroCantábrico, operating in Portugal and Spain, respectively, were consolidated into Neo Energia.

 

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Neo Energia today participates in wind, hydroelectric, biomass, waste and cogeneration in both Portugal and Spain with a total installed capacity of 1,084 MW as of December 31, 2005, of which 808 MW is fully consolidated. Additionally, we hold 65.9 MW of special regime hydroelectric power plants and 111.1 MW of cogeneration plants in Portugal. We also hold 9 MW of a biomass power plant in Portugal through a joint venture with Celulose do Caima, SGPS, S.A., a company that focuses its activity on forestry management and production, and paper pulp production and supply.

Neo Energia has also been defining a strategy to capture opportunities in the international wind energy market, and has acquired three ready-to-build wind farm projects in France. Neo Energia has also been promoting opportunities related to solar and wave energy technology. Neo Energia believes that solar power is one of the most promising and mature new technologies, and that it can provide significant expertise to the promotion and operations of a solar power business.

In 2005, Neo Energia was active in the construction and promotion of wind farms for its own portfolio as well as in the acquisition of third party companies with wind farm licenses or wind farms in construction or operation. Five major acquisitions made by Neo Energia in 2005 are:

 

    Agreement for the acquisition of five Tecneira – Tecnologias Energéticas, S.A., or Tecneira, subsidiaries that are developers of wind farms in Portugal. The operation comprises a portfolio of 120.7 MW, of which 48.3 MW corresponds to existing installed capacity and 72.4 MW accounts for projects either under construction or at an earlier stage of development. Of these, 33.1 MW are expected to start operations during 2006 and 39.3 MW to be fully operational in the beginning of 2007. We have completed the acquisition of two of the five, which have a combined installed capacity of 48.3 MW. In accordance with the purchase agreement, we will complete each of the remaining subsidiaries upon the start of operations of their wind farms, subject to the conditions set forth in the purchase agreement.

 

    Acquisition of the Ortiga and Safra wind farms formerly owned by the companies Energía y Recursos Ambientales, S.A. and Vendaval Promociones Eólicas, S.A. This operation comprises two wind projects under development with a total capacity of 53.4 MW, which are expected to entry into service during 2006.

 

    Acquisition of Nuon España from Nuon International Renewables Projects B.V. Nuon España participates in the renewable energy sector in the Spanish market and has a portfolio of wind farm projects with a total capacity of 1,407 MW, out of which 221 MW are fully operational and 1,186 MW are in different stages of development. The wind farms are located in Galicia, Aragon, Andalusia and the Canary Islands and comprise assets with an average number of wind hours of 2,650 hours per year, above the average for the sector in Spain, which stands at 2,350 hours per year.

 

    Acquisition of three wind farms in Bretagne, France – Le Gollot (10.4 MW), Keranfouler (9.1 MW) and Plouvien (10.4 MW) – from Nuon France Holding SAS. The three wind farms, with a total capacity of 30.0 MW, are expected to work, an average number of wind hours of 2,250 hours per year. These projects will require an additional €32 million investment and are fully licensed. Construction of Le Gollot and Keranfouler began in the first quarter of 2006 and these wind farms are expected to be fully operational before the end of 2006. Plouvien is expected to be fully operational before the end of 2007.

 

    Acquisition of Investigación Y Desarollo de Energías Renovables S.L., or Ider, whose operations consist of four wind farms currently under construction totaling 114 MW located in the Spanish region of León. These wind farms are expected to be fully operational before the end of 2007 and to have an average number of wind hours of 2,250 hours per year.

In 2005, Neo Energia, through its subsidiary Enernova, worked within a consortium composed of three additional wind promoters, Grupo GENERG, Endesa and TP – Térmica Portuguesa and a industrial partner, Enercon, to prepare a binding offer for the Portuguese Tender Process for 1,000 MW of new wind capacity for 2009-2012. The auction for this new capacity was launched by DGGE on July 28, 2005 and the consortium submitted its proposal on March 1, 2006.

 

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The table below presents the aggregated installed capacity and capacity under construction of Neo Energia as of December 31, 2005:

 

     As of December 31,  

Type of facility

   2003    2004    2005  
     (MW)(1)  

Hydroelectric—Special regime

   3    3    3  

Wind

   146    359    690 (2)

Biomass

   3    7    7  

Cogeneration

   24    41    39  

Waste

   33    68    69  
                

Total

   209    478    808  

(1) Capacity figures do not reflect the capacity of plants owned by associated companies.
(2) Includes 224 MW from Desa and 48.3 MW from Tecneira, acquired at year end.

The following map displays Neo Energia’s wind farms in Iberia as of May 2006:

LOGO

Neo Energia currently plans to develop 1,786 MW of wind farms in the period 2006-2008. As of May 2006, wind farms representing 83 MW are already in operation and 494 MW are currently under construction.

Wind energy production is dependent upon weather conditions. In years of less wind hours or wind speed, less wind energy is generated and the PES in Portugal depends on increased thermal production. Nevertheless, based on historical data the annual volatility of the wind ranges from 5% to 10%, and in the long term there are not significant variations. For forecasting purposes, the market practice consists of using an average number of wind hours estimate.

 

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Before the construction of a wind farm, an audit of the conditions of the site is performed for wind forecast purposes and to determine the equipment that most suits the location. Wind turbine suppliers estimate a useful life between 20 and 25 years for their equipment. The life of the equipment is the most important factor to determine the life of the wind farm as licenses are not consumable. Land rights usually extend from 25 to 35 years and therefore do not affect the estimated useful life of the wind farms.

In order to provide incentives for the production of renewable energy sources, renewable generators have dispatch priority over conventional generation in Portugal and Spain.

PORTUGAL

Neo Energia develops wind farms in Portugal through Enernova, which has the responsibility for the development and promotion of renewable energy in Portugal. Its first wind facility commenced operation in 1996. Enernova had a combined installed capacity of 151 MW in 2005 contributing to revenues and 212.9 MW of gross capacity, including wind farms bought from Tecneira.

The following table sets forth our wind capacity and net electricity production from wind farms in Portugal at year-end for the years 2001 through 2005.

 

     As of December 31,
     2001    2002    2003    2004    2005

Installed capacity (MW)(1)

   41    41    65    136    151

Net electricity production (GWh)(1)(2)

   90    113    128    237    348

(1) Does not include wind farms bought from Tecneira and the capacity of plants owned by associated companies.
(2) Excluding internal losses and consumption of the plants.

The following table identifies our wind farm facilities in operation at year-end 2005 although the wind farms acquired from Tecneira are included even though they were formally transferred to Enernova in March 2006.

 

Facility

   Gross Capacity
(MW)(1)
   Type of
Generation
   Year entered
into service
   Direct and
Indirect
Shareholding
 

Fonte da Mesa

   10.20    Wind    Pre-2003    100 %

Pena Suar

   10.00    Wind    Pre-2003    100 %

Cabeço da Rainha

   10.20    Wind    Pre-2003    100 %

Cadafaz

   10.20    Wind    Pre-2003    100 %

Serra do Barroso expansion

   18.00    Wind    2003    70 %

Cabeço da Rainha expansion

   6.00    Wind    2003    100 %

Bolores(2)

   5.20    Wind    2003    100 %

Fonte da Quelha

   12.00    Wind    2004    100 %

Alto do Talefe

   12.00    Wind    2004    100 %

Padrela/Soutelo

   7.50    Wind    2004    80 %

Vila Nova

   20.00    Wind    2004    100 %

Açor

   20.00    Wind    2004    100 %

Mosteiro(2)

   9.10    Wind    2004    100 %

Amaral 1(2)

   8.00    Wind    2004    100 %

Alagoa de Cima(3)

   13.50    Wind    2005    40 %

Vila Nova expansion

   6.00    Wind    2005    100 %

Fonte da Quelha and Alto do Talefe expansion

   3.00    Wind    2005    100 %

Pena Suar expansion

   6.00    Wind    2005    100 %

Caldas 1(2)

   10.00    Wind    2005    100 %

Fanhões 1(2)

   12.00    Wind    2005    100 %

Amaral 1 – 2nd phase(2)

   2.00    Wind    2005    100 %

Fanhões 2 – 1st phase(2)

   2.00    Wind    2005    100 %
             

Total

   212.90         

(1) Includes the capacity of plants owned by companies that are consolidated through the equity method of consolidation
(2) Acquired from Tecneira and transferred to Enernova in March 2006.
(3) Reflects 40% of total capacity corresponding to our 40% ownership interest.

 

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New projects are in progress, some of which are under construction and others are in licensing or development. The table below shows wind farms under construction as of December 31, 2005:

 

Facility

   Planned
Capacity
(MW)
   Type of
Generation
   Target
Year
   Current Status

Ortiga

   11.69    Wind    2006    Construction

Fanhões 2 – 2nd phase(1)

   2.00    Wind    2006    3rd party Construction

Madrinha

   10.00    Wind    2006    Construction

Safra – 1st phase

   26.72    Wind    2006    Construction

(1)

   9.10    Wind    2006    3rd party Construction

Sobral 2(1)

   10.00    Wind    2006    3rd party Construction

Arruda 1(1)

   6.00    Wind    2006    3rd party Construction

Serra D’El Rei

   21.71    Wind    2006    Construction

Abogalheria

   3.34    Wind    2006    Construction

Serra de Alvoça

   20.00    Wind    2006    Construction
             

Total

   120.56         

(1) These wind farms are being constructed by Tecneira and will be transferred to Enernova upon completion.

Neo Energia expects an additional gross capacity in Portugal of 380 MW in the period 2006-2008.

Capital Expenditures

In 2005, our capital expenditures in technical costs on wind farms in Portugal was €46.0 million, not including wind farms acquired from Tecneira and transferred to Enernova in March 2006. In 2004, our capital expenditures in technical costs on wind farms in Portugal was €53.7 million, compared with €38.4 million in 2003, €11.2 million in 2002, and €6.5 million in 2001.

SPAIN

Special regime generation in Spain was previously developed by HidroCantábrico through Genesa I, an 80%-owned subsidiary. In February 2006, Genesa was integrated into Neo Energia, with the objective of providing a basis for stable and sustained development focusing on the promotion, operation and management of renewable energy sources in Iberia. In December 2005, Neo Energia also bought DESA, which added an additional growth platform for the Spanish business.

The following table sets forth Neo Energia’s renewable installed capacity in Spain by type of facility at year-end 2003, 2004 and 2005.

 

     As of December 31,  

Type of facility

   2003    2004    2005  
     (MW)(1)  

Hydroelectric—Special regime

   3    3    3  

Wind

   81    223    490 (2)

Biomass

   3    7    7  

Cogeneration

   24    41    39  

Waste

   33    68    69  
                

Total

   144    342    608  

(1) Capacity figures do not reflect the capacity of plants owned by associated companies.
(2) Including 224 MW from DESA.

 

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The following table summarizes Neo Energia’s renewable electricity generation in Spain for 2003, 2004 and 2005.

 

     As of December 31,  

Type of facility

   2003    2004    2005  
     (GWh)(1)(2)  

Hydroelectric—Special regime

   12    12    5  

Wind

   35    272    523 (3)

Biomass

   12    15    20  

Cogeneration

   87    129    212  

Waste

   86    198    364  
                

Total

   232    626    1,124  

(1) Generation figures do not reflect the generation of plants owned by associated companies.
(2) Excluding losses and our own or ancillary consumption
(3) Generation figures do not include the 2005 generation of DESA´s plants (558 GWh).

The following table identifies the facilities in operation at December 31, 2005. The table sets forth the full capacity of plants owned by Neo Energia’s companies in Spain.

 

Facility

   Gross
Capacity
(MW)
   Type of
Generation
   Year entered
into service
   Neo Energia
Direct and
Indirect
Shareholding
 

EITO Bio

   3.20    Biomass    2001    72 %

Uniarte – Uniener

   3.58    Biomass    2004    80 %

Cog La Espina

   2.24    Cogeneration    1995    40 %

Cogeneración y mantenimiento

   7.94    Cogeneration    1995    40 %

Enercem

   1.99    Cogeneration    1995    16 %

Proenercam

   2.04    Cogeneration    1995    40 %

Cogeneración del Esla

   5.83    Cogeneration    2001    72 %

EITO Cogeneración Energía e Industria de Toledo

   10.86    Cogeneration    2001    72 %

CTI Cerámica Térmica de Illescas

   3.12    Cogeneration    2002    72 %

Renovamed

   1.54    Cogeneration    2002    60 %

Mazarrón

   6.21    Cogeneration    2004    72 %

Nestlé Sevares

   5.48    Cogeneration    2004    80 %

HidroAstur

   8.65    Hydroelectric    1987    20 %

Fuentehermosa

   0.37    Hydroelectric    1992    72 %

Gormaz

   0.45    Hydroelectric    1995    60 %

Rumblar

   2.00    Hydroelectric    1998    64 %

Intever

   16.32    Waste    2000    80 %

Sinova

   16.32    Waste    2003    67 %

Lorca (Sierra Tercia)

   16.32    Waste    2004    70 %

Sidergas

   20.40    Waste    2004    80 %

P.E. Juan Grande

   20.10    Wind    1996    45 %

P.E. Enix

   13.20    Wind    1997    4 %

P.E. Sierra Madero

   28.71    Wind    1998    34 %

P.E. Estrecho

   30.00    Wind    1998    100 %

P.E. Décor

   18.30    Wind    2000    95 %

P.E. Altos del Voltoya I

   55.44    Wind    2000    25 %

P.E. Buena Vista e Llanos de Esquina

   13.75    Wind    2001    100 %

P.E. Monte de las Navas

   48.84    Wind    2002    4 %

P.E. Sierra Cortado

   18.48    Wind    2003    34 %

P.E. Dega

   24.00    Wind    2003    97 %

P.E. Arlanzón

   34.00    Wind    2003    62 %

P.E. Cantábrico I (Cuesta, Lagos)

   46.68    Wind    2003    80 %

P.E. Altos del Voltoya II

   6.60    Wind    2004    25 %

P.E. Cantábrico II (Acebo)

   17.82    Wind    2004    80 %

P.E. Santa Quiteria

   36.00    Wind    2004    58 %

P.E. Monseivane y La Celaya

   70.20    Wind    2004    100 %

P.E. Campollano

   124.10    Wind    2004    60 %

P.E. La Sotonera

   18.90    Wind    2005    55 %

P.E. Rabosera

   31.35    Wind    2005    95 %

P.E. Pesur

   30.00    Wind    2002    17 %

P.E. Las Lomillas

   49.50    Wind    2005    40 %
             

Total

   870.83         

 

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New projects are in progress, some of which are under construction and others are in licensing or development. The table below shows wind farms under construction at the beginning of the year.

 

Facility

   Planned
Capacity
(MW)
   Type of
Generation
   Target Year    Current Status

P.E. Brújula

   73.50    Wind    2006    Construction

P.E. Boquerón

   21.80    Wind    2006    Construction

P.E. Belchite

   49.50    Wind    2006    Construction

P.E. Hoya Gonzalo

   49.50    Wind    2006    Construction
             

Total

   194.30         

Neo Energia expects an additional gross capacity in Spain of 1,397 MW in the period 2006-2008.

Capital Expenditures

In 2005, capital expenditures on renewable energy in Spain amounted to approximately €133.2 million, as set forth below.

 

     Year ended December 31,

Plant type and status

   2003    2004    2005 (1)
     (thousands of EUR)

Hydroelectric – Special Regime

   0    0    0

Wind

   49,047    140,685    130,290

Waste

   3,500    10,530    2,870

Cogeneration facilities

   18,720    5,880    0

Biomass

   350    10,905    0
              

Total Generation

   71,617    168,000    133,160

(1) Does not include DESA, acquired at year end.

RENEWABLE ENERGY OUTSIDE IBERIA

The acquisition of three wind farms in France in 2005, amounting to a capital expenditure of approximately €4.4 million, represents the first step of Neo Energia’s international expansion. By the end of 2010, Neo Energia expects an additional 500 MW of installed capacity to be developed in other European markets outside Iberia.

The following table presents the wind farms under construction outside of Iberia:

 

Facility

   Planned
Capacity
(MW)
   Country    Type of
Generation
   Target Year    Current Status

P.E. Le Gollot

   10.4    France    Wind    2006    Construction

P.E. Keranfouler

   9.1    France    Wind    2006    Construction

P.E. Plouvien

   10.4    France    Wind    2006    Promotion
                

Total

   29.9            

DISTRIBUTION AND REGULATED SUPPLY

PORTUGAL

Electricity distribution in Portugal is a regulated business and involves the transfer of electricity from the transmission system, its delivery across a distribution system to regulated consumers and Qualifying Consumers, meter reading, 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, EDP distributed electricity to approximately 5,907,000 consumers in 2005, out of a total of approximately 5,935,000 according to the DGGE. This amounted to 43,785 GWh, of which 9,621 GWh was distributed to Qualifying Consumers. As of December 31, 2005, EDPD had 4,613 employees.

 

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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 were 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.

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 IES 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. As of December 31, 2005, EDPD’s distribution lines spanned a total of approximately 205,327 kilometers. The only distribution lines in Portugal not owned by EDPD are those of 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, 2005.

 

Distribution lines

   Km

Overhead lines:

  

High-voltage (60/130kV)

   7,632

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

   55,240

Low-voltage (<1kV)

   100,380
    

Total overhead lines

   163,252

Underground cables:

  

High-voltage (60/130kV)

   420

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

   13,045

Low-voltage (1kV)

   28,610
    

Total underground cables

   42,075
    

Total

   205,327

Customers and sales

EDPD distributes electricity to approximately 5.9 million customers. Approximately 69% of electricity consumption in 2005 was along the coast, with approximately 18.7% in the Lisbon metropolitan region and 13.4% in the Oporto metropolitan region. EDPD classifies its customers by voltage level of electricity consumed. The following chart shows the number of customers as of December 31, 2005, 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 IES.

 

     Year ended December 31, 2005

Customers by voltage level

  

Binding

customers

  

Qualifying

consumers

   Total

High and very high-voltage(1)

   173    18    191

Medium-voltage(2)

   16,600    5,124    21,724

Special low-voltage(3)

   22,036    8,084    30,120

Low-voltage(4)

   5,855,330    0    5,855,330
              

Total

   5,894,139    13,226    5,907,365

(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 41.4 kW 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 customers in the Binding Sector and Qualifying Consumers, consumption has grown at an average annual growth rate of 5% from December 31, 2001 to December 31, 2005. The highest average annual growth rate during this period, 10.4%, was in demand from very high- and high-voltage customers. These voltage levels experienced a 17.5% increase in demand in 2005 due to a higher demand on the distribution grid from auto producers. Under

 

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current regulations, auto producers may purchase electricity at a price below that at which they may sell it to the National Electricity System. As a consequence, auto producers have increased their demand on the distribution grid. Demand by medium-voltage levels increased from 11,702 GWh in 2001 to 13,580 GWh in 2005, representing average annual growth of 3.8%.

Following the gradual decrease of the eligibility threshold between 2001 and 2005, 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 11,358 GWh in 2001 to 5,091 GWh in 2005, whereas electricity demand by medium-voltage qualifying consumers increased from 344 GWh in 2001 to 8,489 GWh in 2005. Consumption by low-voltage binding customers, typically residential and services, increased from 18,823 GWh in 2001 to 21,360 GWh in 2005, representing average annual growth of 3.2%. This growth is slightly lower than that in total low voltage (4.3% per annum) as 951 GWh were consumed by large low-voltage qualifying consumers. The growth in low-voltage consumption during this period resulted from the increase in the number of low-voltage customers from approximately 5.8 million to approximately 5.9 million, as well as an increase in annual consumption per consumer.

The following table shows electricity distributed in each of the last five years by type of consumer.

 

     Year ended December 31,

Electricity distributed

   2001    2002    2003    2004    2005
     (GWh)

Very high-voltage and high-voltage:

              

Binding customers

   4,259    4,271    4,795    5,562    6,413

Qualifying consumers

   176    182    114    49    182
                        

Total very high-voltage and high-voltage

   4,435    4,453    4,909    5,611    6,595

Medium-voltage:

  </