As filed with the Securities and Exchange Commission on July 3, 2003

 

 

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

 


 

Form 20-F

 

ANNUAL REPORT PURSUANT TO SECTION 13 OF THE
SECURITIES EXCHANGE ACT OF 1934,

for the fiscal year ended December 31, 2002

 

Commission File Number: 1-14648

 


 

EDP—Electricidade de Portugal, S.A.

(Exact name of registrant as specified in its charter)

 

EDP—Electricity of Portugal

 

Republic of Portugal

(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*
American Depositary Shares (as evidenced by American
Depositary Receipts), each representing 10 Ordinary Shares

 

New York Stock Exchange
New York Stock Exchange

 


*  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:

 

At December 31, 2002, there were outstanding:

 

3,000,000,000 Ordinary Shares, with nominal value of € 1 per share

 

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  ý

 

No  o

 

Indicate by check mark which financial statement item the registrant has elected to follow:

 

Item 17 o

 

Item 18 ý

 

 



 

TABLE OF CONTENTS

 

PART I

 

6

 

 

 

Item 1.

Identity of Directors, Senior Management and Advisers

6

 

 

 

Item 2.

Offer Statistics and Expected Timetable

6

 

 

 

Item 3.

Key Information

6

 

 

 

 

SELECTED FINANCIAL DATA

6

 

EXCHANGE RATES

9

 

CAPITALIZATION AND INDEBTEDNESS

10

 

REASONS FOR THE OFFER AND USE OF PROCEEDS

10

 

RISK FACTORS

10

 

 

 

Item 4.

Information on the Company

15

 

 

 

 

HISTORY AND BUSINESS OVERVIEW

15

 

STRATEGY

22

 

IBERIAN ELECTRICITY MARKET

25

 

PORTUGAL

26

 

Electricity System Overview

26

 

Generation

30

 

Transmission

39

 

Distribution

41

 

Tariffs

45

 

Competition

47

 

SPAIN

48

 

History and Overview

48

 

Generation

49

 

Distribution and Supply

53

 

Other Activities

55

 

BRAZIL

55

 

Overview

55

 

Generation

57

 

Distribution and Related Activities

58

 

TELECOMMUNICATIONS

61

 

OTHER INVESTMENTS AND INTERNATIONAL ACTIVITIES

65

 

SUBSIDIARIES, AFFILIATES AND ASSOCIATED COMPANIES

65

 

REGULATION

66

 

Portugal

66

 

Spain

72

 

EU Legislation

74

 

Brazil

78

 

Telecommunications

82

 

 

 

Item 5.

Operating and Financial Review and Prospects

85

 

 

 

 

OVERVIEW

85

 

CRITICAL ACCOUNTING POLICIES

87

 

RESULTS OF OPERATIONS

90

 

2002 COMPARED WITH 2001

91

 

2001 COMPARED WITH 2000

95

 

LIQUIDITY AND CAPITAL RESOURCES

99

 

1



 

 

PENSIONS AND BENEFITS

101

 

INFLATION

101

 

PORTUGUESE GAAP COMPARED WITH U.S. GAAP

101

 

IMPACT OF RECENTLY ISSUED U.S. ACCOUNTING STANDARDS

104

 

 

 

Item 6.

Directors, Senior Management and Employees

105

 

 

 

 

BOARD OF DIRECTORS

105

 

SENIOR MANAGEMENT

110

 

COMPENSATION OF DIRECTORS AND SENIOR MANAGEMENT

112

 

SHARE OWNERSHIP

112

 

EMPLOYEES

113

 

EMPLOYEE BENEFITS

114

 

 

 

Item 7.

Major Shareholders and Related Party Transactions

114

 

 

 

 

MAJOR SHAREHOLDERS

114

 

RELATED PARTY TRANSACTIONS

115

 

INTERESTS OF EXPERTS AND COUNSEL

115

 

 

 

Item 8.

Financial Information

115

 

 

 

 

CONSOLIDATED STATEMENTS

115

 

OTHER FINANCIAL INFORMATION

115

 

Legal Proceedings

115

 

Dividends and Dividend Policy

116

 

SIGNIFICANT CHANGES

116

 

 

 

Item 9.

The Offer and Listing

116

 

 

 

 

TRADING MARKETS

116

 

MARKET PRICE INFORMATION

116

 

THE PORTUGUESE SECURITIES MARKET

117

 

TRADING BY US IN OUR SECURITIES

120

 

PLAN OF DISTRIBUTION

121

 

SELLING SHAREHOLDERS

121

 

DILUTION

121

 

EXPENSES OF THE ISSUE

121

 

 

 

Item 10.

Additional Information

121

 

 

 

 

SHARE CAPITAL

121

 

ARTICLES OF ASSOCIATION

121

 

MATERIAL CONTRACTS

128

 

EXCHANGE CONTROLS

128

 

PORTUGUESE TAXATION

129

 

UNITED STATES TAXATION

131

 

DIVIDENDS AND PAYING AGENTS

132

 

STATEMENT BY EXPERTS

132

 

DOCUMENTS ON DISPLAY

132

 

SUBSIDIARY INFORMATION

133

 

 

 

Item 11.

Quantitative and Qualitative Disclosure About Market Risk

133

 

 

 

Item 12.

Description of Securities Other Than Equity Securities

134

 

 

 

GLOSSARY OF TERMS

135

 

 

 

PART II

 

137

 

 

 

Item 13.

Defaults, Dividend Arrearages and Delinquencies

137

 

2



 

Item 14.

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

137

 

 

 

Item 15.

Controls and Procedures

137

 

 

 

Item 16.

[Reserved]

137

 

 

 

PART III

 

137

 

 

 

Item 17.

Financial Statements

137

 

 

 

Item 18.

Financial Statements

137

 

 

 

Item 19.

Exhibits

138

 

3



 

Defined terms

 

In this annual report, “EDP” refers to EDP—Electricidade de Portugal, S.A. and the terms “we”, “us” and “our” refer to EDP and, as applicable, its direct and indirect subsidiaries as a group. Unless we specify otherwise or the context otherwise requires, references to “US$,” “$” and “U.S. dollars” are to United States dollars, references to “escudo(s)” or “PTE” are to Portuguese escudos, references to “real” or “reais” are to Brazilian reais, references to “£” or “GBP” are to British Pounds Sterling and references to “€” or “euro” are to the euro, the single European currency established pursuant to the European Economic and Monetary Union, or EMU.  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 within the meaning of the United States Private Securities Litigation Reform Act of 1995 with respect to our financial condition, results of operations, business strategies, operating efficiencies, competitive positions, growth opportunities for existing services, plans and objectives of management, markets for stock and other matters. Statements in this annual report that are not historical facts are “forward-looking statements” for the purpose of the safe harbor provided by Section 21E of the Exchange Act and Section 27A of the Securities Act.

 

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;

 

                  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;

 

                  future capital expenditures and investments;

 

                  the timely development and acceptance of our new services;

 

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

 

                  our success at managing the risks of the foregoing.

 

We undertake no obligation to update publicly or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this annual report or to reflect the occurrence of unanticipated events.

 

4



 

Presentation of financial information

 

Unless we indicate otherwise, we have prepared the financial information contained in this annual report in accordance with generally accepted accounting principles in Portugal, or Portuguese GAAP, which differs in significant respects from generally accepted accounting principles in the United States, or U.S. GAAP. We describe these differences in “Item 5.  Operating and Financial Review and Prospects—Portuguese GAAP Compared with U.S. GAAP” and in note 33 to our consolidated financial statements.  Unless we indicate otherwise, any reference in this annual report to our consolidated financial statements is to the consolidated financial statements, including the related notes, included in this annual report.

 

Beginning in 2002 (for fiscal year 2001 and thereafter), we published our consolidated financial statements in euros.  Unless we indicate otherwise, we have translated amounts stated in U.S. dollars from euros at an assumed rate solely for convenience.  By including these currency translations in 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 indicate otherwise, we have translated the U.S. dollar amounts from euros at the noon buying rate in The City of New York for cable transfers in foreign currencies as announced by the Federal Reserve Bank of New York for customs purposes (the “Noon Buying Rate”) on June 20, 2003 of $1.1616 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.”  In addition, for convenience only and except where we specify otherwise, we have translated certain reais figures into euro at the fixed rate of exchange between the real and euro of 3.3489 reais = €1.00.   The rate of exchange between reais and euros represents the euro equivalent of the U.S. dollar/real fixed rate of exchange, calculated by translating reais into U.S. dollars using the Noon Buying Rate on June 20, 2003 of 2.8830 reais = $ 1.00 and then translating U.S. dollars into euros using the rate of exchange between U.S. dollars and euros of $1.1616 = €1.00, which was the applicable Noon Buying Rate on June 20, 2003.  By including convenience currency translations in this annual report, we are not representing that the reais amounts actually represent the euro amounts shown or could be converted into euros at the rates indicated.

 

Prior to January 1, 2001, our reporting currency was Portuguese escudos.  For convenience and to facilitate a comparison, our consolidated financial statements included in Item 18 and all other escudo-denominated financial data for periods prior to January 1, 2001 included in this annual report have been restated from escudos to euros at the fixed rate of exchange as of January 1, 1999 of PTE 200.482 = €1.00.  Where escudo-denominated amounts for periods prior to January 1, 2001 have been rounded, the restated euro amounts have been calculated by converting the rounded escudo-denominated amounts into euros.  The comparative balances for prior years now reported in euros depict the same trends as would have been presented had we continued to report such amounts in Portuguese escudos.  Our consolidated financial statements and other financial data for periods prior to January 1, 1999 may not be comparable to that of other companies reporting in euros if those companies had restated from a reporting currency other than Portuguese escudos.

 

5



 

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 audited consolidated financial statements for each of the five years ended December 31, 2002 and as of December 31, 1998, 1999, 2000, 2001 and 2002 and the related notes, which appear elsewhere in this annual report. The audited consolidated financial statements have been prepared in accordance with Portuguese GAAP, which differ in certain significant respects from U.S. GAAP. See “Item 5. Operating and Financial Review and Prospects—Portuguese GAAP compared with U.S. GAAP,” note 33 to our consolidated financial statements for a discussion of the principal differences between Portuguese GAAP and U.S. GAAP with respect to our audited consolidated financial statements.

 

In 1999, 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 1999 consolidated financial statements were audited by PricewaterhouseCoopers, Lda.  Fiscal years prior to 1999 were audited by Ernst & Young.

 

6



 

 

 

Year  ended December 31,

 

 

 

1998

 

1999

 

2000

 

2001

 

2002

 

2002

 

 

 

Euro

 

Euro

 

Euro

 

Euro

 

Euro(1)

 

US$(1)

 

 

 

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

 

Statement of income:

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts in accordance with Portuguese GAAP

 

 

 

 

 

 

 

 

 

 

 

 

 

Electricity sales

 

2,951

 

2,966

 

3,676

 

5,201

 

5,876

 

6,826

 

Other sales(2)

 

19

 

38

 

61

 

98

 

112

 

130

 

Services(3)

 

40

 

68

 

110

 

351

 

398

 

463

 

Total revenues

 

3,010

 

3,072

 

3,846

 

5,650

 

6,387

 

7,419

 

Raw materials and consumables

 

714

 

901

 

1,731

 

3,080

 

3,687

 

4,283

 

Personnel costs

 

430

 

463

 

439

 

592

 

625

 

726

 

Depreciation and amortization

 

611

 

616

 

614

 

665

 

740

 

859

 

Other external supplies and services

 

227

 

287

 

369

 

651

 

675

 

784

 

Own work capitalized(4)

 

(194

)

(214

)

(229

)

(233

)

(242

)

(281

)

Concession and power-generation rental costs(5)

 

123

 

129

 

133

 

149

 

158

 

184

 

Hydrological correction(6)

 

0

 

(60

)

(35

)

0

 

0

 

0

 

Other operating expenses, net

 

38

 

43

 

102

 

73

 

95

 

110

 

Total operating costs and expenses

 

1,949

 

2,166

 

3,122

 

4,977

 

5,738

 

6,665

 

Operating income

 

1,061

 

906

 

724

 

674

 

649

 

754

 

Net interest expense(7)

 

204

 

140

 

175

 

205

 

223

 

259

 

Other non-operating expenses (income), net

 

(57

)

(56

)

(289

)

(126

)

139

 

161

 

Income before income taxes

 

914

 

822

 

838

 

594

 

287

 

333

 

Provision for income taxes

 

(395

)

(308

)

(313

)

(203

)

(172

)

(199

)

Minority interest

 

3

 

0

 

23

 

60

 

220

 

256

 

Net income

 

523

 

514

 

549

 

451

 

335

 

389

 

Net income from operations per ordinary share(8)

 

0.35

 

0.30

 

0.24

 

0.22

 

0.22

 

0.25

 

Net income from operations per ADS

 

3.54

 

3.02

 

2.41

 

2.25

 

2.16

 

2.51

 

Basic and diluted net income per ordinary share(8)

 

0.17

 

0.17

 

0.18

 

0.15

 

0.11

 

0.13

 

Basic and diluted net income per ADS(8)

 

1.75

 

1.72

 

1.83

 

1.50

 

1.12

 

1.30

 

Dividends per ordinary share(9)(11)

 

0.13

 

0.14

 

0.14

 

0.11

 

0.09

 

0.11

 

Dividends per ADS(9)(11)

 

1.30

 

1.40

 

1.40

 

1.13

 

0.90

 

1.05

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts in accordance with
U.S. GAAP (12)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

704

 

644

 

405

 

519

 

300

 

348

 

Basic and diluted net income per ordinary  share(9)

 

0.23

 

0.21

 

0.14

 

0.17

 

0.10

 

0.12

 

Basic and diluted net income per ADS(9)

 

2.34

 

2.14

 

1.35

 

1.74

 

1.00

 

1.16

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flow data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts in accordance with Portuguese GAAP

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash from operating activities

 

1,358

 

985

 

1,122

 

1,221

 

898

 

1,043

 

Net cash used in investing activities

 

1,110

 

1,294

 

914

 

1,243

 

1,141

 

1,326

 

Net cash used in (from) financing activities

 

279

 

(385

)

482

 

96

 

297

 

345

 

 

7



 

 

 

Year  ended December 31,

 

 

 

1998

 

1999

 

2000

 

2001

 

2002

 

2002

 

 

 

Euro

 

Euro

 

Euro

 

Euro(1)

 

Euro(1)

 

US$(1)

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance sheet data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts in accordance with Portuguese GAAP

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

1

 

16

 

58

 

34

 

214

 

249

 

Other current assets

 

580

 

707

 

1,162

 

1,496

 

1,863

 

2,165

 

Total current assets

 

581

 

723

 

1,220

 

1,530

 

2,077

 

2,413

 

Fixed assets, net(10)

 

10,550

 

10,477

 

9,540

 

9,844

 

11,204

 

13,015

 

Other assets

 

1,265

 

2,510

 

4,128

 

4,901

 

4,844

 

5,626

 

Total assets

 

12,396

 

13,710

 

14,887

 

16,233

 

18,125

 

21,054

 

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

 

737

 

598

 

1,807

 

1,744

 

1,887

 

2,192

 

Other current liabilities

 

501

 

621

 

890

 

1,286

 

1,631

 

1,895

 

Total current liabilities

 

1,238

 

1,219

 

2,697

 

3,030

 

3,518

 

4,087

 

Long-term debt, less current portion

 

2,734

 

3,770

 

3,205

 

4,055

 

6,107

 

7,094

 

Hydro account

 

388

 

339

 

366

 

388

 

324

 

376

 

Other long-term liabilities

 

1,908

 

2,319

 

2,377

 

2,423

 

2,616

 

3,039

 

Total liabilities

 

6,267

 

7,648

 

8,645

 

9,896

 

12,566

 

14,596

 

Minority interest

 

1

 

2

 

37

 

241

 

65

 

76

 

Shareholders’ equity

 

6,127

 

6,060

 

6,205

 

6,097

 

5,494

 

6,382

 

Amounts in accordance with
U.S. GAAP (12)

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed assets, net(10)

 

8,594

 

8,750

 

5,316

 

5,929

 

6,602

 

7,668

 

Total assets

 

11,464

 

12,940

 

14,010

 

15,455

 

16,922

 

19,657

 

Total current liabilities

 

1,257

 

1,238

 

2,714

 

3,052

 

2,551

 

2,963

 

Total long-term liabilities

 

6,046

 

7,415

 

6,776

 

7,721

 

10,420

 

12,104

 

Total liabilities

 

7,303

 

8,653

 

9,489

 

10,773

 

12,970

 

15,066

 

Shareholders’ equity

 

4,161

 

4,287

 

4,483

 

4,441

 

3,886

 

4,511

 

 


(1)          For 1998, 1999 and 2000, escudos are translated into euro at the fixed rate of exchange established at the commencement of the third stage of European Monetary Union on January 1, 1999 by the European Council of Ministers between the euro and escudo of PTE 200.482 = € 1.00.  For 2002, euros are translated into U.S. dollars at the rate of exchange of  $1.1616 = € 1.00, which was the U.S. Federal Reserve Bank of New York noon buying rate on June 20, 2003.

 

(2)          Consists of sales of steam, ash, information technology products 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)          Our consolidated income statements present expenses in accordance with their nature rather than their function. Therefore, costs incurred by us for self-constructed assets are capitalized as part of fixed assets and included as a reduction of total expenses under “Own work capitalized” when the related costs have been included in the relevant expense items.

 

(5)          Substantially all of these amounts relate to rent expenses paid to municipalities for the right to distribute electricity in the relevant municipal areas.

 

(6)          As required by government regulation, we record charges and credits to operating income, depending on hydrological conditions in a given year, to smooth the effect on our earnings and customer prices that result from changes in hydrological conditions. The difference between the economic costs of generating electric energy and the economic reference costs based on an average hydrological year are included in this item. The imputed interest on the accumulated balance of the hydro account and other adjustments are included in “Other non-operating expenses (income).”

 

(7)          Includes interest and related expenses and interest and related income. See “Item 5.  Operating and Financial Review and Prospects—2002 compared with 2001—Other expenses (income).”

 

(8)   Basic and diluted earnings per ordinary share are based on our historical average number of ordinary shares outstanding after giving effect to a 5 for 1 stock split and our average number of ordinary shares outstanding after giving effect to the 5 for 1 stock split plus the effect of the exercise of employee stock options, respectively. Basic and diluted earnings per ADS are based upon basic and diluted earnings per ordinary share multiplied by 10 as each ADS is equivalent to 10 ordinary shares on a post-split basis.

 

(9)          Based on 3,000,000,000 ordinary shares issued and outstanding.

 

(10)   Substantially all of these assets are subject to reversion to the Republic or the municipalities. See “Item 4. Information on the Company—Regulation—Reversionary assets.”

 

(11)   Dividends per ordinary share in US$, translated at the prevailing rate of exchange at the date of payment between the dollar and the escudo for 1998, amount to US$ 0.14 in 1998, US$ 0.13 in 1999, US$ 0.12 in 2000, US$ 0.10 in 2001 and US$ 0.11 in 2002 and dividends per ordinary share in euro, translated at the fixed rate of exchange between the euro and the escudo for 1998, amount to € 0.11 in 1998, € 0.14 in 1999,  € 0.14 in 2000, € 0.11 in 2001 and € 0.09 in 2002.

 

(12) U.S. GAAP amounts for 1998, 1999, 2000, 2001, and 2002 are not comparable due to the implementation of SFAS 142.

 

8



 

EXCHANGE RATES

 

Effective January 1, 1999, Portugal and 11 other member countries of the European Union, or EU, adopted the euro as their common currency.  The euro was traded on currency exchanges and was available for non-cash transactions during the transition period between January 1, 1999 and December 31, 2001.  During this transition period, the national currencies remained legal tender in the participating countries as denominations of the euro, and public and private parties paid for goods and services using either the euro or the participating countries’ existing currencies.  On January 1, 2002, the euro entered into cash circulation.  Between January 1, 2002 and February 28, 2002 both the euro and the escudo were in circulation in Portugal.  From March 1, 2002, the euro became the sole circulating currency in Portugal.  As of January 1, 2002, we ceased to use the escudo.

 

The vast majority of our revenues, assets, expenses and liabilities have historically been denominated in escudos, and we prepared and published our consolidated financial statements in escudos through the 2000 fiscal year.  Beginning in 2002 (for fiscal year 2001 and thereafter), our consolidated financial statements have been 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.

 

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 escudo could have been, or that the euro could be, converted into U.S. dollars at these rates or at any other rate.

 

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

 

U.S. dollar per euro(1)
Year ended December 31,

 

End of Period

 

Average

 

1998

 

1.17

 

1.11

 

1999

 

1.01

 

1.06

 

2000

 

0.94

 

0.92

 

2001

 

0.89

 

0.89

 

2002

 

1.05

 

0.95

 

 

U.S. dollar per euro(1)
Period

 

High

 

Low

 

2002

 

1.05

 

0.86

 

December

 

1.05

 

0.99

 

2003

 

 

 

 

 

January

 

1.09

 

1.04

 

February

 

1.09

 

1.07

 

March

 

1.11

 

1.05

 

April

 

1.12

 

1.06

 

May

 

1.19

 

1.12

 

 


(1)          Amounts for 1998 are based on noon buying rates for the escudo, converted into euros at the fixed escudo/euro conversion rate of PTE 200.482 = € 1.00 and then based on the U.S. Federal Reserve Bank of New York noon buying rate on January 4, 1999 of € 1.00 = $1.18.  For 1999, 2000, 2001 and 2002, euros 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 June 20, 2003, the exchange rate between the euro and the U.S. dollar was $1.1616 = € 1.00.

 

9



 

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, affecting our electricity sales and operating margins.

 

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

 

While we currently face limited competition from independent power producers in generation, we expect that this competition will increase as the industry further liberalizes. Portuguese law requires that contracts for the construction of future power plants in Portugal in the Binding Sector be awarded through competitive tender processes, in which we expect to participate. In a competitive tender process, we may lose opportunities to generate electricity in the Binding Sector in Portugal.

 

In the context of liberalization of the electricity market within the EU, at the end of 2001 the Portuguese and Spanish governments entered into a cooperation protocol which sets forth the main principles for the creation of an Iberian electricity market — free competition, transparency, objectiveness and efficiency.  The stated intent of the cooperation protocol is to guarantee for 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 regulatory environments that allow producers in one country to execute bilateral agreements for electricity distribution to consumers in the other country.  The cooperation protocol also calls for the creation of an Iberian common electricity pool.  Although there have been advances as a result of the October 2002 Valência summit, there is currently no specific organizational model for an Iberian electricity market.  Accordingly, we cannot anticipate the specific organizational model that will be adopted nor can we anticipate the risks and advantages that may arise from such a model.  When further defined and implemented, the organizational model and resulting competition may materially and adversely affect our results of operations and financial condition.

 

The Portuguese regulatory structure now allows for competition in the supply of electricity, which could adversely affect our sales of electricity. In particular, as more electricity consumers qualify to participate in the market-based Non-Binding Sector in Portugal, more electricity will be sold in the competitive markets where prices may be lower than existing tariffs. Prior to 2002, consumers of electricity were eligible to participate in the Non-Binding Sector as Qualifying Consumers based on minimum annual consumption thresholds set by regulation, which declined annually over the 1999-2001 period. Pursuant to EU directives, the threshold was 20 GWh for 2000 and 9 GWh for 2001.  Since January 1, 2002, all electricity consumers other than low voltage consumers, which are generally residential and small commercial users, have been treated as Qualifying Consumers automatically upon notification to the Portuguese regulatory authority.  As of March 2003, there were approximately 21,000 consumers eligible to be Qualifying Consumers, which represented approximately 44.5% of our 2002 sales in volume and 28.6% of our 2002 sales in monetary terms.

 

10



 

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

 

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

 

In real terms, adjusted for inflation, both high and medium voltage tariffs, generally applied to industrial customers, have declined by an average of approximately 6.0% per year over the period 1998 to 2003. The tariffs for low voltage customers have also declined in real terms by an average of approximately 3.3% per year over the same period.  In 2002, in nominal terms, tariffs for all voltage levels increased, on average, by 2.2% from the 2001 levels.  At the end of 2002, the regulator established new tariffs for 2003.  Although the nominal final tariff charged to consumers increased, on average, across all voltage levels in 2003 by 2.8% from the 2002 levels, the component of the final tariff charged by EDP Distribuicão, or EDPD, our distribution company, decreased for the second regulatory period, covering the years 2002-2004, from the tariff charged in the first regulatory period, covering the years 1999-2001.  During the first regulatory period, the annual decrease in the tariff charged by EDPD was calculated on the basis of the Portuguese consumer price index, or CPI, less approximately 5%.  During the second regulatory period, the figure subtracted from CPI, referred to as the “efficiency factor,” increased to approximately 7%.  The net tariffs to be charged by EDPD in 2003 are lower than in 2002, which could adversely affect our profitability in 2003.

 

In addition, the Portuguese government has implemented selected measures to encourage the development of various forms of electricity production, including autoproduction (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. These alternative producers compete with us in the supply of electricity in the Binding Sector.

 

The Portuguese government’s recently announced intention to renegotiate or terminate the PPAs could eventually adversely affect our revenues.

 

According to the Resolution of the Council of Ministers no. 63/2003 of April 28, relating to the promotion of liberalization of the electricity and gas markets in furtherance of the organizational structure of the Iberian Electricity Market, the Portuguese government intends to renegotiate the existing power purchase agreements, or PPAs.  Although the Portuguese government expressly declared that it intends to adequately compensate operators for the loss of the economic benefit of the PPAs, the amount of compensation has not yet been defined and our generation revenues could otherwise be adversely affected if our generation companies do not sufficiently replace electricity purchases previously made by Rede Eléctrica Nactional, S.A. or REN.

 

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 amounts would be paid to us with respect to these assets, the loss of these assets may adversely affect our operations.

 

11



 

Our cash flow is affected by variable hydrological conditions.

 

Hydroelectric plants, which are powered by water, account for approximately 55% of our generation capacity in mainland Portugal.  Our hydroelectric generation in Portugal is dependent on the amount and location of rainfall and river flows from Spain, all of which vary widely from year to year. Consequently, there is a high degree of variation in levels of hydroelectric production.

 

In years of less favorable hydrological conditions, we generate less hydroelectricity and must rely more heavily on thermal production to meet demand for electricity. Thermal generation, which is fired by coal, fuel oil, natural gas or a combination of fuels, is more expensive in terms of variable costs than hydroelectric generation. Our total variable production costs and costs of purchased electricity in a very dry year can vary from those in a very wet year by approximately € 200 million. These increased costs in a dry year could have an adverse impact on our operational cash flow.

 

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

 

                Our electricity business is subject to extensive environmental regulations. These include regulations under Portuguese law, laws adopted to implement EU regulations and directives and international agreements on the environment. Environmental regulations affecting our business primarily relate to air emissions, water pollution, waste disposal and electromagnetic fields. The principal waste products of fossil-fueled electricity generation are sulfur dioxide, or SO2, nitrogen oxides, or NOX, carbon dioxide, or CO2, and particulate matters such as dust and ash. A primary focus of environmental regulation applicable to our business is to reduce these emissions.

 

                We incur significant costs to comply with environmental regulations requiring us to implement preventive or remediation measures.  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.

 

                We have made capital expenditures to minimize the impact of our operations on the environment, including measures to comply with applicable law. Major expenditures so far include capital expenditures to limit SO2 and NOX emissions in generation and to install underground cables in our distribution network.  In October 2002 we initiated the use of fuel with a 1% sulphur content in order to comply with environmental regulations requiring us to reduce the level of sulfur in the fuel oil we consume, and as a result we have incurred higher fuel costs.

 

RISKS RELATED TO OUR OTHER BUSINESSES

 

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

 

Although we have not recently made new investments in our Brazilian electricity business, we have significant investments in electricity-related projects in Brazil and other international investments. 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.  Given the size of our operations in Brazil relative to that of our other international investments, these risks are particularly relevant to our Brazilian operations where, for example, we have experienced adverse currency fluctuations and an uncertain regulatory regime.  Risks associated with our investments in Brazil and other international investments include, but are not limited to:

 

                  increased economic volatility;

 

                  exchange rate fluctuations and exchange controls;

 

                  stronger inflationary pressures;

 

                  greater government involvement in the domestic economy;

 

12



 

                  less political stability;

 

                  higher potential for civil unrest; and

 

                  unanticipated changes in regulatory or legal regimes.

 

There can be no assurance that we will successfully manage our operations in Brazil and other international operations.

 

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 2002, our distribution activities in Brazil were adversely affected by regulatory, hydrological and infrastructure conditions in Brazil.  Our generation projects in Brazil were also adversely affected by these conditions.  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 will continue to contribute to, shortages of electricity to meet demand in some regions of Brazil.  Additionally, drought conditions in Brazil have limited and will in the future limit the supply of electricity available for our distribution companies in Brazil.  A lack of capacity in the electricity transmission system has limited and continues to limit the ability of generation plants operating in geographical areas with abundant rainfall to transmit generated electricity to distribution companies operating in areas experiencing drought conditions.  Sales by these distribution businesses are and will continue to be affected by these conditions that limit the supply of electricity available for distribution.

 

As a result of a shortage of electricity and lack of transmission capacity, the Brazilian federal government implemented an electricity rationing plan in June 2001.  Although the rationing program ended on February 28, 2002, its implementation had an adverse effect not only on electricity consumption, which decreased significantly during the period the program was in effect, but on consumption habits in affected areas.  As a result, we anticipate that a recovery in consumption to pre-rationing levels may take some time.  The lower demand from consumers has affected and will continue to affect demand for electricity from our distribution businesses in Brazil.  While the period up to and during the rationing period was characterized by electricity shortages, the post-rationing period was characterized by surplus electricity as a result of decreased consumption combined with abundant rainfall after a long drought.  Consequently, in 2002 our Brazilian operations could only dispose of surplus electricity at depressed prices.

 

The regulatory delays and lack of transmission capacity are also affecting our investment in generation projects in Brazil.  These delays pose problems for the development of generation facilities, and the lack of transmission capacity will affect the ability of our generation businesses, once established, to transmit their generated electricity to distribution companies in Brazil.

 

We face new risks and uncertainties related to our new non-electricity businesses.

 

We have limited experience operating a large-scale telecommunications business and limited experience in gas. In entering and operating these business areas we face managerial, commercial, technological and other risks, as well as regulatory regimes, including fees and licensing requirements and operating restrictions, that are different from the ones we have faced in the past.  If we fail to manage these risks and operate these businesses effectively, our ability to develop successfully and achieve profitability in these business areas would be affected.

 

We face increasing competition from various types of providers in our telecommunications business.

 

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

 

13



 

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

 

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

 

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

 

OTHER RISKS

 

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

 

The Portuguese government may sell all or a portion of its shareholding in us at any time through formal privatization stages, either through a public offering or by direct sales of our shares to third parties.  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 price 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 and on shareholdings, as well as special rights granted to the Portuguese government, may impede an unauthorized change in control and may limit our shareholders’ ability to influence company policy.

 

Under our Articles of Association, no holder of ordinary shares, except the Republic of Portugal and equivalent entities, may exercise voting rights that represent more than 5% of our voting share capital. In addition, specific notification requirements are triggered under our Articles of Association when shareholders purchase 5% of our ordinary shares and under the Portuguese Securities Code, or Cod.VM, when purchases or sales of our ordinary shares cause shareholders to own or cease to own specified percentages of our voting rights.  Under Portuguese law currently in force, no person may acquire more than 10% of our ordinary shares without prior approval of the Portuguese Ministry of Finance.   Such law may be amended or revoked in response to a June 4, 2002 judgment of the Court of Justice of the European Community.  For more information on this law, please see “Item 10.  Additional Information—Articles of Association—Limitations on the purchase and transfer of ordinary shares; special rights of the Portuguese government.”  These limitations may impede an unauthorized change in control of EDP, and a failure to comply with these limitations could result in restrictions on the ability to exercise voting rights attaching to ordinary shares or the denial of registration of record ownership for ordinary shares.  Holders of ADSs will be treated as holders of ordinary shares for purposes of the foregoing limitations.

 

In connection with the offering by the Portuguese government of our ordinary shares in October 2000, and pursuant to Article 13 of Decree Law 14/2000 of July 15, 2000, known as the Privatization Decree Law, special rights were granted to the Portuguese government. The government will have these rights so long as it is an EDP shareholder. These rights provide that, without the favorable vote of the government, no resolution can be adopted at our general meeting of shareholders relating to:

 

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

 

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

 

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

 

14



 

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

 

Item 4.    Information on the Company

 

HISTORY AND BUSINESS OVERVIEW

 

History

 

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.

 

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.  Following the sale by the Republic of Portugal in October 2000 of 20% of our outstanding ordinary shares, after a period that started in 1997 of privatization in four phases of our share capital, we are approximately 26.1% owned, directly or indirectly, by the Republic of Portugal and an additional 4.75% of our shares are held by Caixa Geral de Depósitos, a state-owned bank.  Other significant shareholders include Banco Comercial Português, or BCP (5.05%), Iberdrola (5%) and, indirectly, Brisa Autoestradas de Portugal, or Brisa (2%).

 

15



 

The  following chart shows our current structure and a list of the primary companies within the investments of the EDP Group.  For a more detailed listing, please see note 2 to our consolidated financial statement.

 

 

General Note

 

The percentages are rounded. Some ownership percentages indicated above reflect indirect ownership.

 

(1) For a more detailed listing and description, please see “Subsidiaries, Affiliates and Associated Companies” below.

(2) EDP Energia S.A., or EDP Energia, is an electric trading comapny operating in the independent electricity system that operates five small hydroelectric plants

 

 

16



 

Business Overview

 

Iberian Energy

 

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

 

As the largest producer and distributor of electricity in Portugal, we currently hold the leading position in the Portuguese market.  In 2002, we accounted for approximately 82% of the installed generation capacity in the Public Electricity System and 99% of the distribution in the Public Electricity System.  REN, in which we hold a 30% equity interest, accounted for 100% of the transmission in the Public Electricity System. Our 2002 operating revenues amounted to € 6,386.6 million (US$ 7,418.6 million), approximately 92% of which represented electricity sales, yielding operating income of € 648.7 million (US$ 753.5 million).  At December 31, 2002, our total assets were € 18,125.2 million (US$ 21,054.2 million), and shareholders’ equity was € 5,494.2 million (US$ 6,382.0 million).

 

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

 

 

 

Year ended December 31,

 

 

 

2000

 

2001

 

2002

 

 

 

(millions of EUR)

 

Energy (1)

 

 

 

 

 

 

 

Portugal

 

3,701

 

4,530

 

4,898

 

Spain

 

0

 

0

 

321

 

Brazil

 

0

 

691

 

669

 

Telecommunications

 

 

 

 

 

 

 

Portugal

 

17

 

126

 

190

 

Spain

 

0

 

62

 

131

 

Information Technology

 

22

 

150

 

107

 

All Other

 

106

 

93

 

72

 

Total

 

3,846

 

5,650

 

6,387

 

 


(1)   Consists of electricity in Portugal and electricity and gas in Spain

 

In Portugal, we create power for consumption in both the Public Electricity System and the Independent Electricity System.  In 2002, our generating facilities in Portugal had a total installed capacity of 7,654 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.  In our distribution function, EDPD carries out Portugal’s local electricity distribution almost exclusively.  EDPD provided more than 5.6 million customers with 35,973 GWh of electricity in 2002.

 

We expect regional markets for electricity to develop in Europe as an initial stage in the development of an integrated and liberalized electricity market with the EU. For geographical and regulatory reasons, we anticipate that an Iberian electricity market will be the regional market for our core electricity business in the near future.  Accordingly, we consider our core electricity business to include our operations in the Portuguese and Spanish electricity markets.  In a process that took place during 2001 and 2002, we expanded our energy operations with the acquisition of a 40% interest in Hidroeléctrica del Cantábrico S.A., or Hidrocantábrico, a Spanish electricity and gas utility company.  Hidrocantábrico operates electricity generation plants and distributes and supplies electricity and gas in the Iberian Peninsula, mainly in the region of Asturias in Spain.  Beginning in June 2002, we have

 

17



 

consolidated on a proportional basis 40% of Hidrocantábrico.  In March 2003, Hidrocantábrico won the privatization auction process that will lead to the acquisition of Naturcorp, the major gas distribution company operating in the Basque region of Spain.

 

Telecommunications and Information Technology

 

In 2000, taking into consideration our existing resources and expertise, we decided to pursue the telecommunications and information technology businesses.

 

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

 

In addition, we pursue the information technology business through our wholly owned subsidiary EDINFOR—Sistemas Informáticos, S.A., or EDINFOR, which holds a 60% interest in ACE—Holding SGPS, S.A., or ACE.  ACE owns 100% of CASE—Concepção e Arquitectura de Soluções Informáticas Estruturadas, S.A., or CASE.  CASE provides consulting and information systems services to us and to third parties.

 

Group capital expenditures and investments
 

Our total capital expenditures in the electricity business in Portugal were € 666.1 million, € 409.2 million and € 351.0 million in 2002, 2001 and 2000, respectively. One of our strategic goals in recent years has been to reduce the overall level of capital expenditures in our core electricity business.  However, we had higher capital expenditures in 2002 compared with 2001 primarily as a result of expenditures in generation relating to the TER CCGT plant and the Venda Nova hydroelectric plant, operational and financial expenditures relating to Hidrocantábrico that are discussed below, telecommunications expenditures and the acquisition of U.S. dollar denominated notes that had been issued by Escelsa.  We expect lower total capital expenditures in 2003 since the investment related to the acquisition of Hidrocantábrico has been completed, the operational investment in Hidrocantábrico in 2003 is expected to be lower than in 2002, expenditures in telecommunications will decrease as a result of our divestment of the UMTS business and, having reduced the exchange rate risk relating to U.S. dollar debt of our Brazilian subsidiaries, we do not forsee the need for further debt acquisition programs.  We do expect a similar level of operational investment in generation in Portugal in 2003.

 

Our acquisition of a 40% interest in Hidrocantábrico involved a total investment of € 783 million, of which € 262.4 million was invested in 2001.  For more information about our Hidrocantábrico investment, you should read “—Spain—History and Overview” below.  In 2002, we also consolidated Hidrocantábrico’s capital expenditures relating to generation and distribution.

 

The following table sets forth our capital expenditures and investments for the years 2000 through 2002.  Capital expenditures in electricity in Portugal are broken into two categories:  technical and financial costs.  Technical costs refer to all amounts expended other than interest.  Expenditures in Spain, Brazil, telecommunications and information technology are broken into two categories: operational investment, which generally refers to the development and acquisition of fixed assets, and financial investment, which generally refers to the acquisition of equity interests in companies.

 

18



 

 

 

Year ended December 31,

 

 

 

2000

 

2001

 

2002

 

 

 

(thousands of EUR)

 

Energy:

 

 

 

 

 

 

 

Portugal:

 

 

 

 

 

 

 

Generation:

 

 

 

 

 

 

 

Thermal/Hydro

 

56,406

 

109,646

 

204,979

 

Renewable: wind

 

11,190

 

6,574

 

11,397

 

Renewable: biomass(1)

 

0

 

0

 

35,205

 

Cogeneration

 

25,459

 

13,142

 

9,619

 

Engineering (2) and Operations and Maintenance

 

1,051

 

2,371

 

15,262

 

Total Generation

 

94,106

 

131,733

 

276,462

 

Transmission(3)

 

15,079

 

0

 

0

 

Distribution(4)

 

232,310

 

260,636

 

365,961

 

Supply(5)

 

1,970

 

980

 

8,337

 

Total technical costs

 

343,422

 

393,352

 

650,759

 

Financial costs

 

7,622

 

15,867

 

15,361

 

Total Portugal

 

351,087

 

409,217

 

666,121

 

Spain:

 

 

 

 

 

 

 

Operational Investment:

 

 

 

 

 

 

 

Hidrocantábrico

 

 

 

0

 

211,938

 

Financial Investment:

 

 

 

 

 

 

 

Hidrocantábrico(6)

 

0

 

262,388

 

520,591

 

Total Spain

 

0

 

262,388

 

732,529

 

Total Energy Portugal and Spain

 

351,087

 

671,605

 

1,398,649

 

Brazil:

 

 

 

 

 

 

 

Operational Investment:

 

 

 

 

 

 

 

Generation

 

25,703

 

40,836

 

55,600

 

Distribution:

 

 

 

 

 

 

 

Bandeirante

 

63,828

 

47,226

 

25,413

 

Escelsa

 

0

 

0

 

16,208

 

Enersul

 

0

 

0

 

25,152

 

EDP Brasil

 

0

 

1,608

 

261

 

Total Operational Investment

 

89,531

 

89,670

 

122,634

 

Financial Investment:

 

 

 

 

 

 

 

Bandeirante

 

206,023

 

1,077

 

0

 

Escelsa

 

0

 

209,011

 

0

 

Total Financial Investment

 

206,023

 

210,088

 

0

 

Total Brazil

 

295,555

 

299,758

 

122,634

 

Telecommunications(7) and Information Technology:

 

 

 

 

 

 

 

Operational Investment:

 

 

 

 

 

 

 

Telecommunications

 

219,601

 

239,019

 

311,962

 

Information Technology

 

29,998

 

70,977

 

41,833

 

Total Operational Investment

 

249,599

 

309,996

 

353,795

 

Financial Investment:

 

 

 

 

 

 

 

Telecommunications

 

130,690

 

69,554

 

0

 

Information Technology

 

66,146

 

2,913

 

1,961

 

Total Financial Investment

 

196,836

 

72,467

 

1,961

 

Total Telecommunications and Information Technology

 

446,434

 

382,463

 

355,756

 

Other:

 

 

 

 

 

 

 

Other Operational Investment(8)

 

33,040

 

29,529

 

45,364

 

Other Financial Investment:

 

 

 

 

 

 

 

EDA — Electricidade dos Açores

 

5,726

 

813

 

0

 

Geoterceira

 

0

 

0

 

499

 

GALP Energia

 

317,974

 

0

 

0

 

BCP

 

502,918

 

0

 

30,636

 

Turbogás

 

0

 

0

 

20,986

 

Affinis

 

0

 

0

 

13,757

 

Other International Investments

 

72,500

 

7,525

 

0

 

Escelsa Notes(8)

 

0

 

0

 

379,964

 

Others

 

219,182

 

0

 

0

 

Total Other Financial Investment

 

1,118,300

 

8,338

 

445,843

 

Total Other

 

1,151,340

 

37,867

 

491,207

 

Total Capital Expenditures and Investments

 

2,244,416

 

1,391,693

 

2,368,246

 

 

19



 


(1)          Renewable — biomass investment in 2002 includes € 35.2 million relating to an internal transfer of the Mortágua biomass power plant, from EDP S.A. to EDP Produção Bioeléctrica. As such, this does not affect our cashflow in 2002.

 

(2)          In 2001, expenditures in engineering and O&M includes the expenditures made by Tergen, HidrOeM and EDP Produção, which companies were created in 2001.

 

(3)          Transmission capital expenditures in 2000 only includes the first six months of 2000 due to the sale of a 70% interest in REN.

 

(4)          Distribution includes capital expenditures made prior to 2000 by three departments within EDP that worked exclusively on the distribution business and that in 2000 were transferred to EDPD.

 

(5)          Supply comprises the capital expenditures of EDP Energia, our company operating in the liberalized market.

 

(6)          Total investment in the acquisition of Hidrocantábrico amounts to € 782.9 million, of which € 262.4 million was invested in 2001.

 

(7)          Investments for telecommunications include primarily infrastructure and, in 2000, organizational costs relating to ONI.

 

(8)          Other Operational 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.

 

(9)          In 2002 we acquired certain notes issued by Escelsa.  For more information on this transaction please see “Item 11. Quantitative and Qualitative Disclosures About Market Risk.”

 

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,

 

 

 

2000

 

2001

 

2002

 

 

 

(thousands of EUR)

 

Total Capital Expenditures and Investments:

 

2,244,416

 

1,391,693

 

2,368,246

 

Internal Transfers:

 

 

 

 

 

 

 

IT Systems (from EDINFOR to EDP Distribuição)

 

 

 

 

 

(80,500

)

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

 

 

 

 

 

(35,180

)

Divestments:

 

 

 

 

 

 

 

ESSEL

 

 

 

(77,800

)

 

 

REN(1)

 

(976,200

)

 

 

 

 

Redal

 

 

 

 

 

(26,905

)

Optep (Optimus)

 

 

 

 

 

(315,000

)

Total Internal Transfers and Divestments

 

(976,200

)

(77,800

)

(457,585

)

Adjusted Total Capital Expenditures and Investments

 

1,268,173

 

1,313,895

 

1,910,661

 

 


(1)               Our divestment of a 70% interest in REN involved our receipt of an extraordinary dividend of € 392.6 million, € 106.2 million for intra group debt repayment and € 477.4 million for the equity sold.

 

In recent years, a significant part of our capital expenditures on electricity projects in Portugal has been in distribution. Since EDPD is obligated by law to connect all customers who wish to be supplied by the Public Electricity System, 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 obligated to meet government standards for meter control, which requires us to make further investments in new meters. Our investment in distribution in Portugal in 2002 totalled  € 366.0 million compared with € 260.6 million in 2001 and € 232.3 million in 2000, and mainly consisted of recurring capital expenditures necessary for the operation, improvement and expansion of our distribution network in Portugal, including expansion to accommodate growth in consumption and maintenance.  In keeping with our strategic goal of reducing recurring capital expenditures in our core electricity business, capital expenditures in distribution have declined since 1998 due to decreased costs in materials and services, and a reduced allocation of these costs to capital expenditures. In 2002, the increase in EDPD capital expenditures reflects the internal transfer from EDINFOR to

 

20



 

EDPD of € 80.5 million worth of assets that relate to non-recurring investments made in a commercial and administrative IT system based on the SAP platform. As such, this transfer does not affect our cashflow in 2002.

 

Under current regulations in Portugal, we receive contributions directly from customers for a portion of our capital expenditures for new connections to the transmission and distribution networks.  The total amount of contributions from customers in 2002 was approximately  € 111 million compared with approximately € 148 million in 2001.

 

During 2002, we invested € 276.5 million in generation, compared with € 131.7 million in 2001. This increase was mainly due to a € 143.0 million investment in initiating construction of the TER CCGT power plant and a € 25.7 million investment in additional capacity of the Venda Nova hydro power plant.

 

In Spain, apart from the our capital expenditure for the acquisition of a 40% stake in Hidrocantábrico, there were capital expenditures of € 211.9 million during 2002 focused on generation (including the completion of the Castejón CCGT plant), electric distribution (including expansion to Madrid, Valência and Alicante) and on special regime generation projects (including a 34 MW wind farm near Burgos).

 

We expect to focus future capital expenditures in Portugal in distribution on connecting new clients and improving the quality of the electricity service through a more efficient network. We expect to concentrate generation capital expenditures in future periods on the development of new hydroelectric projects and in the construction of the new TER CCGT power plant.  Future capital expenditures in generation may also include special projects such as co-generation and wind power generation opportunities.  While the actual amount of our future investments will depend on factors that cannot be currently foreseen, we expect to incur recurring capital expenditures of approximately € 300 million annually in our core electricity generation and distribution businesses  in Portugal during this period.

 

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

 

We believe that cash generated from operations and existing credit facilities are 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 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.”

 

International investments

 

We have made a number of international investments in the electricity and water sectors in Brazil, Cape Verde, Guatemala and Macau. We have actively sought opportunities outside of Portugal in which we could capitalize on our existing strengths. To date in 2003, we have not initiated any new international investment projects.  In accordance with our strategy of shareholder value creation, we have divested in non-strategic holdings in Chile and Morocco.

 

Complementary businesses/other utilities

 

We also have investments in activities that we regard as complementary to our core business, specially in gas utilities.

 

Since July 2000, we hold a 14.27% ownership interest in GALP Energia, or Galp, a holding company with interests in Gás de Portugal, S.A., and Transgás, companies that transport and supply natural gas throughout

 

21



 

Portugal, and Petrogal, a company involved in oil refining and distribution and the production of petroleum products.

 

In March 2003, Hidrocantábrico won the auction privatization process that will lead to the acquisition of Naturcorp, the leading natural gas company in the Basque region of Spain. In April 2003, the Portuguese government made public its view and recommendations concerning the restructuring of the Portuguese energy sector, as a result of which we may become the major company in the Iberian combined gas and electricity sector. According to these recommendations, the gas and electricity economic activities should be combined and developed by us in order to strengthen our position in a competitive market. The terms and conditions under which such reorganization shall be put in place have yet to be clearly defined. The Portuguese government also recommended that Transgás should be integrated in REN, in order to form a single company for the transport of gas and electricity. In addition, the government intends to sell 18.3% of Galp to REN.

 

STRATEGY

 

Our principal strategic objective is the creation of shareholder value through the achievement of sustained real earnings growth.

 

Primary strategic focus on core energy activities in the Iberian Peninsula

 

Our primary strategic focus is the Iberian energy market. We are the leading electricity company in Portugal and have operating control of Hidrocantábrico, the fourth largest electricity company in Spain.  In Hidrocantábrico we maintain a successful partnership with Energie-Baden-Württemberg AG, or En BW, a German utility company, and Cajastar — Caja de Ahorros de Asturias, a Spanish savings bank, or Cajastar.  EDP and Hidrocantábrico combined comprise a significant share of generation capacity and energy and distribution supply in the Iberian market.  In March 2003, as a result of the privatization process launched by the Ente Vasco de Energia, the energy authority of the Basque region in Spain, Hidrocantábrico will acquire 62% of Naturcorp, the second largest Spanish gas distribution and transmission company.  Our other interests in the gas sector consist of a 14% stake in Galp and, through Hidrocantábrico, operating control of Gas de Asturias.

 

In the Iberian energy market our objectives are to preserve the value of our domestic electricity business in light of the liberalization of the Portuguese electricity market and the creation of an integrated Iberian market, grow our electricity Iberian platform through Hidrocantábrico and develop a gas business leveraging on our existing assets.

 

Preserving the value of our domestic electricity business

 

In our domestic electricity business, we face increasing competition arising from the liberalization of the electricity market in Portugal, in the Iberian Peninsula market and throughout the EU. Additionally, we face increasing pressure on operating margins of our electricity distribution business in Portugal due to the regulation of electricity tariffs in the Public Electricity System.

 

In response to these challenges, we plan to:

 

                  continue efforts to enhance earnings by capitalizing on our competitive position and on anticipated growth in demand in the Portuguese electricity market and now in an Iberian electricity market consisting of Portugal and Spain;

 

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

 

                  continue in Portugal our program to increase the efficiency of our core electricity operations, 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.

 

22



 

In pursuing these objectives, we intend to:

 

                  pursue effective marketing to both new and existing customers, particularly those that are, or will be, subject to competitive alternatives in the Non-Binding Sector;

 

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

 

                  further centralize our corporate structure, as we have done with the merger of our four distribution companies into EDPD and the centralization of all our generation companies under EDP Produção’s umbrella;

 

                  continue to centralize our back office activities, such as administration and accounting, as well as procurement and suppliers relationship management, with the aim of achieving cost savings in supplies of goods and services and personnel reduction, to which end we created EDP Valor;

 

                  improve our procurement process for new equipment and the terms of business with subcontractors, particularly through continued renegotiations with suppliers and development of benchmark standards for procurement, also through EDP Valor;

 

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

 

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

 

Growing our Iberian electricity platform

 

In light of the intended integration of the Spanish and Portuguese electricity sectors, the definition of our core market, which was traditionally focused in Portugal, has widened to embrace the Iberian Peninsula. Following the acquisition of a 40% interest in Hidrocantábrico at the end of 2001, we became the first Iberian company to own 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 this regard we intend to:

 

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

 

                  grow our customer base incrementally, capitalizing on full electricity market liberalization from 2003 onwards; and

 

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

 

Developing an Iberian gas strategy

 

In April 2003, the Portuguese government made public its views and recommendations concerning the restructuring of the energy sector, as a result of which we have the opportunity to become the major company in the Iberian combined gas and electricity sector. According to the government’s recommendations, gas and electricity economic activities should be combined and developed by us in order to take advantage of synergy and flexibility that will result from integrated management of the activities.   The terms and conditions under which such

 

23



 

reorganization will be put in place have yet to be clearly defined.  The government also recommended that Transgás, a Portuguese gas transport company, should eventually be integrated into REN in order to form a single company for the transmission/transport of energy.  In addition, the government intends to sell 18.3% of Galp to REN.  Our current interests in the gas sector in the Iberian Peninsula include a 14.27% stake in Galp and, through Hidrocantábrico, full operating control of Gas de Asturias and Naturcorp.

 

We view the gas business as being highly complementary to electricity and of great strategic attractiveness.  Both Portugal and Spain have gas and electricity consumption growth rates above the EU average.  Each requires new capacity to be gradually added and CCGTs are clearly the best option to meet the Iberian system expansion requirements because of their lower investment costs required per MW, greater efficiencies, lower operating and maintenance costs and lower emission levels than other thermal generation technologies.  Since new gas fired generation capacity is expected to be added to the Iberian electricity system, power generators, which are already among the largest gas consumers in the Iberian Peninsula, are and will continue to be the facilitators of the development and sustainability of the gas business in the Iberian Peninsula, although their competitive position will increasingly depend on gas prices and the flexibility of gas contracts.

 

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

 

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

 

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

 

Developing our telecommunications and information technology businesses

 

Our telecommunications activities are centered on ONI, our telecommunications company comprised of various business units.  ONI, which is primarily focused on corporate clients, is a fixed line telecommunications operator that provides voice and data services at a significant level in Portugal and Spain.  Our information technology activities are focused on EDINFOR, our information technology subsidiary.

 

We plan to build on our existing operations in order to pursue a competitive role in the corporate fixed line telecommunications sector in Portugal and Spain, which we regard as attractive markets of suitable size with high growth potential. We based our decision to enter and develop this business on our ability to capitalize on our existing infrastructure, including access to an extensive fiber optic backbone, to leverage our existing resources, including a large base of customers and suppliers, and to use our existing telecommunications and information technology operations as a foundation for expanded activities.

 

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

 

                  infrastructure operations, including alliances with partners to construct a nationwide telecommunications network in Portugal;

 

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

 

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

 

                  business solutions, building on EDINFOR’s experience and expertise in systems integration.

 

24



 

We also have allied and expect to ally ourselves with other partners who may bring resources and synergies to facilitate our efforts to develop a presence in each of these business areas. For a more detailed discussion of our telecommunications activities, you should read “—Telecommunications” below.

 

Pursuit of international activities

 

Our core electricity business has historically been in Portugal and is now in an Iberian electricity market.  However, international opportunities arise in the electricity business and related businesses through which we believe we can achieve attractive returns. In international investments, we have looked particularly toward Brazil, where we believe we can play an active role in managing the electricity operations in which we are involved and where potential returns may be attractive. In the future, we may pursue attractive opportunities abroad, particularly generation projects in Brazil that complement our existing activities in Brazilian distribution. We regularly review our international investments and may change their focus consistent with our strategic objectives. In this regard, we continuously monitor our investment portfolio in order to capitalize on our ability to manage efficiently electricity operations through significant influence or control. For a more detailed discussion of our international activities, you should read “—Brazil” and “—Other International Activities and Strategic Investments”.

 

Developing of complementary business activities/other utilities

 

Consistent with our multi-utility 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.

 

We expect that our purchase of an interest in Affinis will provide us with the opportunity to become involved in additional commercial activities related to the supply of electricity and gas, such as the provision and servicing of appliances and the installation of utility infrastructure in homes and businesses.  For more information on our complementary business activities you should read “—Subsidiaries, Affiliates and Associated Companies” below.

 

IBERIAN ELECTRICITY MARKET

 

On November 14, 2001, in accordance with the liberalization objectives contained in EU Directive 96/92/EC, the Portuguese and Spanish governments signed a “Protocol for Cooperation between the Spanish and Portuguese governments for the Creation of the Iberian Electricity Market”, or the Protocol, in which they undertook to create an Iberian electricity market based on the principles of free and fair competition, transparency, objectivity and efficiency.  In particular, the Protocol was intended to:

 

                  guarantee consumers in Portugal and Spain access to the electricity  network from either country and to interconnections with third countries on equal terms; and

 

                  give electricity operators in an Iberian electricity market the freedom to contract with consumers, to engage in distribution activities in both countries and to participate in a common Iberian electricity pool.

 

In late December 2001, the regulators from Spain and Portugal, (respectively, Comision Nacional de Energia, or CNE, and Entidade Reguladora dos Serviços Energéticos, or ERSE) presented a paper for public discussion on the Iberian Electricity Market (MIBEL) organizational model. In March 2002, based on that public discussion, they presented a compromise structure for MIBEL. As determined in the Protocol, the model took into consideration the principles stated in the Protocol, the applicable EU legislation, the recent experience of both countries’ electricity markets and regulatory best practices. The model also introduced ideas to allow for the development of a competitive and efficient market, equipped with the necessary supervision and control mechanisms, in order to guarantee the satisfaction of consumers’ needs, to provide for the security of electricity supply in the short and long term and to be fully compatible with the objectives of energy efficiency and the promotion of renewable energy in both countries. This general model constitutes the basis for both countries to present a detailed plan for the implementation of technical and organizational measures necessary for the functioning of an Iberian Electricity Market.

 

25



 

Although MIBEL was expected to come into force by January 2003, representatives of the Portuguese and Spanish governments at the October 2002 Valência summit established a new schedule for MIBEL’s implementation.  The revised timeframe was created in recognition of the fact that MIBEL would be delayed not only due to a change in the Portuguese government, but also because of the need for the harmonization of the Spanish tariff structure.  Among other commitments achieved at the summit, a decision was reached to implement MIBEL in phases beginning in January 2003 and ending in 2006.  According to the proposal presented at the Valência summit, it is expected that the new model will function with only one operator divided into two specialized establishments with separate management, one in Portugal operating the forwards market for electricity and one in Spain operating the daily and intra-daily market for electricity.  It is also expected that there will only be one wholesale energy market that will function in parallel with bilateral contracts.

 

For the purpose of developing MIBEL, the Protocol contains a timetable for the development of the following interconnections between Spain and Portugal that was not amended at the Valência summit: Alqueva-Balboa, a 400kV line scheduled for completion in 2004; Douro Internacional-Aldeadavila, either the construction of a new 400kV interconnection or an increase of the existing interconnection capacity scheduled for completion in 2006; and Cartelle-Lindoso, a second interconnection for the purpose of increasing transmission efficiency scheduled for completion in 2006.

 

Within this context, changes introduced to the Portuguese energy policy in April 2003 resulted in the redefinition of the Portuguese government’s main objectives in the energy sector, which comprise, among others: the liberalization of the market, improvement of the quality of service, security of supply and reinforcement of the productivity of the national economy. However, the main revision to the restructuring of the energy sector is the promotion of the combination of the management and supply of the gas and electricity businesses into a single company in line with dominant international practices and with Spanish utilities’ practice.

 

By the end of 2003, Portugal, among other measures, intends to initiate the restructuring of the Portuguese electricity system, which includes renegotiating or terminating the existing PPAs through adequate compensation mechanisms and changing REN’s single buyer status. It is also understood that both Portugal and Spain should take all the necessary measures to open the market to all consumers and harmonize both tariff structures through clear and transparent rules, particularly in Spain.  For more information on the Portuguese energy policy see “—Regulation¾Portugal”.

 

PORTUGAL

 

ELECTRICITY SYSTEM OVERVIEW

 

Portuguese Electricity System

 

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

 

26



 

 

 


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

 

(1)          We own 10% of Tejo Energia and 20% of Turbogás.

 

(2)          Began operations in early 1998.

 

(3)          As of June 2003, none existed.

 

(4)          As of March 2003, approximately 21,000 Eligible Consumers existed, of which 1,657 have become Qualifying Consumers and 899 were already in the Non-Binding Sector.  As of 2003, all consumers except low-voltage consumers may elect to become Qualifying Consumers.

 

27



 

The National Electricity System consists of the Public Electricity System, or the Binding Sector, and the Independent Electricity System. The Public Electricity System is responsible for ensuring the security of electricity supply within Portugal and is obligated to supply electricity to any consumer who requests it. Within the Independent Electricity System is the Non-Binding Sector and other independent producers (including autoproducers). 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, as of May 15, 2003, Eligible Consumers, i.e., all consumers other than low voltage consumers, automatically become Qualifying Consumers after communicating their intention to the regulator to be treated as such.  For more information on the liberalization of electricity sales you should read “—Competition”.

 

The National Electricity System is intended to improve transparency in the costs associated with the supply of electricity and to prepare for a more market-based and competitive electricity supply system in Portugal that continues to fulfill EU requirements.

 

The Public Electricity System or Binding Sector

 

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

 

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

 

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

 

The Independent Electricity System

 

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

 

The Non-Binding Sector

 

At present, the only producers in the Non-Binding Sector are our three wholly-owned embedded hydroelectric generators, which are small hydroelectric plants with more than 10MW installed capacity that deliver all of the energy they produce directly to the distribution system.  Although producers in the Non-Binding Sector are required to obtain licenses, they have no obligation to supply electricity to the Public Electricity System. These entities are free to contract directly with Qualifying Consumers.  In 2002, the total number of Eligible Consumers in Portugal represented 44.5% of our 2002 sales in volume and 28.6% of our 2002 sales in monetary terms. As of March 2003, out of approximately 21,000 Eligible Consumers, only 889 have become Qualifying Customers, of which 652 had entered into contracts with EDP Energia and 237 had entered into contracts with producers in the Spanish market.  The total of 889 Qualifying Consumers represented approximately 7% of the total amount of energy sold and 1.2% of the revenues during the first quarter of 2003.  We expect little impact on our earnings in 2003 as a result of competition in the Non-Binding Sector.

 

28



 

Producers in the Non-Binding Sector are able to use the national transmission grid and distribution system on an open-access basis to connect to Qualifying Consumers, which pay regulated transmission and distribution charges to REN for transmission and EDPD or other companies for distribution, respectively. Our hydroelectric plants in the Independent Electricity Systems deliver all of the electricity they produce directly to the distribution system without going through the national transmission grid. 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 autoproducers (entities that generate electricity for their own use and may sell surplus electricity to REN), cogenerators, small hydroelectric producers and other producers using renewable sources. REN is currently required by law to purchase the excess electricity produced by these independent producers at a regulated price based on avoidable costs, defined as the costs REN avoids by receiving power from these producers rather than dispatching plants in the Binding Sector and/or investing in new plants to increase installed capacity, plus an environmental premium, referred to as the “green tariff”.  For more information on our electricity sales, you should read “—Distribution” below.

 

Size and composition of Portugal’s electricity market

 

During the period from 1998 through 2001, the total electricity supplied by EDPD (in both the Binding and Non-Binding Electricity Sectors) experienced an average growth rate of 5.6% per annum.  In 2002, there was a reduction in the annual growth rate to 2.4% due to a slowdown in the economy. We expect the previous trend of higher growth rates to resume in future years, assuming that the Portuguese economy recovers from the slowdown that occurred in 2002.

 

The primary factors that management believes 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 1998 through 2001, during which consumption in the Public Electricity System experienced an average growth rate of 2.1% above growth in Portugal’s gross domestic product, or 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. The previous growth trend is expected to resume in the future, assuming that the Portuguese economy recovers from the slowdown that occurred in 2002.  We anticipate that the Portuguese economy will recover and that overall consumption in the National Electricity System will increase at an average of 3.9% per year in 2003, 2004 and 2005.  Residential consumption is assumed to increase each year over the same period by an average of 3.2%, services by an average of 3.7%, and industrial by an average of 4.2%.

 

Peak demand as a percentage of the total installed capacity, which is the sum of the total installed capacity of the Public Electricity System and the total installed capacity of the Non-Binding System, has remained fairly constant in recent years.  Our available capacity as a percentage of the total installed capacity has maintained a value of approximately 80% from 1998 through 2002.  The ratio of peak demand to EDP’s average available capacity indicates that EDP has sufficient available capacity to cover the total peak demand.

 

29



 

The following table sets forth the ratios of peak demand to installed capacity, EDP’s available capacity to the installed capacity of the Public Electricity System and the Non-Binding System and peak demand to EDP’s available capacity.

 

 

 

As of December 31,

 

 

 

1998

 

1999

 

2000

 

2001

 

2002

 

 

 

(in MW, except percentages)

 

Installed capacity of the PES(1)

 

8,144

 

8,804

 

8,757

 

8,757

 

8,757

 

Installed capacity of the NBES (2)

 

270

 

270

 

270

 

310

 

255

 

Total installed capacity (PES plus NBES)

 

8,414

 

9,074

 

9,027

 

9,067

 

9,012

 

Peak demand (PES plus NBES)

 

6,079

 

6,122

 

6,557

 

7,142

 

6,766

 

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

 

72

%

67

%

73

%

79

%

75

%

EDP:

 

 

 

 

 

 

 

 

 

 

 

EDP’s average available capacity (PES)

 

6,860

 

6,837

 

6,795

 

6,904

 

6,980

 

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

 

224

 

196

 

215

 

247

 

226

 

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

 

84

%

78

%

78

%

79

%

80

%

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

 

86

%

87

%

94

%

100

%

94

%

 


(1)          Public Electricity System.

 

(2)          Non-Binding Electricity System, which consists of generation in the Independent Electricity System other than the “other independent procedures”.  All of the NBES hydroelectric plants with an installed capacity less than or equal to 10 MW became special regime producers in October 2002.  Special regime generation generally consists of small or renewable energy facilities, from which the electricity system must acquire all electricity offered, at tariffs fixed according to the type of generation.

 

(3)          Provisional values from 1998 to 2001 take into account the restructuring of the Vila Cova plant in 1999.

 

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

 

The term “installed capacity” in this 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.  In previous reports, installed capacity of a facility referred to the level of electricity emission to the transmission network based on the technical nominal specification of the units of such facility established by the manufacturer.  Referring to installed capacity in terms of maximum capacity is preferable because in Portugal the PPAs remunerate electricity producers based on this concept and this concept is widely used by other electricity companies in Europe.

 

GENERATION

 

As of December 31, 2002, our Portuguese electricity generation facilities consist of hydroelectric, thermal (coal, fuel oil, natural gas and gas oil), biomass, cogeneration and wind generation facilities, and had a total installed capacity of 7,654 MW, 7,184 MW of which was in the Public Electricity System and 470 MW of which was in the Independent Electricity System, and approximately 55% of which was represented by hydroelectric facilities, 23% by fuel oil/natural gas facilities, 16% by coal-fired facilities, 4% by gas oil facilities and 2% by wind-driven, biomass and cogeneration facilities.  We do not own or operate any nuclear-powered facilities in Portugal.

 

Our installed capacity in the Public Electricity System of 7,184 MW represents approximately 82% of the total installed capacity in the Public Electricity System.  The total installed capacity of the Public Electricity System increased from 1998 to 1999 due primarily to the Turbogás plant at Tapada do Outeiro. From 1999 to 2000, total installed capacity of the Public Electricity System decreased to a small degree as a result of the decommissioning of one unit at our Tapada do Outeiro plant.  From 2000 to 2002, the installed capacity of the Public Electricity System

 

30



 

remained constant.  Our smaller hydroelectric plants, wind generating facilities and cogeneration and biomass plants are part of the Independent Electricity System.

 

EDP Gestão da Produção de Energia, S.A., or EDP Produção, holds, among others, the following companies in the generation sector: CPPE – Companhia Portuguesa de Produção de Electricidade, S.A., which operates our plants in the Public Electricity System; HDN – Energia do Norte S.A. and Hidrocenel – Energia do Centro, S.A., which operate some of our smaller hydroelectric plants in the Independent Electricity System; TER – Termoeléctrica do Ribatejo, S.A., which is involved in the development of a new CCGT plant that will operate in the Non-Binding Sector; Enernova, which is involved in the development of renewable source energy projects and related services; EDP Produção Bioeléctrica, S.A., which develops and manages biomass projects and that presently operates our biomass plant at Mortágua; EDP Cogeração, which develops and manages cogeneration projects; EDP Produção EM – Engenharia e Manutenção, S.A., which undertakes hydroelectric and thermal engineering projects and studies, project management, engineering and consulting; HidrOeM – Gestão, Operação e Manutenção de Centrais Eléctricas, S.A., a management and O&M service company for all smaller EDP hydroelectric power plants owned by HDN, Hidrocenel and EDP Energia, an electric trading company operating in the Non-Binding Sector.

 

The following map sets forth the CPPE power plants in Portugal:

 

31



 

CPPE POWER PLANTS

 

 

32



 

Since its formation in 1994, CPPE has operated all of our conventional thermal plants and approximately 93% of our hydroelectric plants.  It has also been responsible for 100% of our fuel purchases.  On March 29, 2001, we announced the formation of EDP Produção, a subsidiary that began operations in July 2001 and now operates all of our Portuguese energy production-related units, including CPPE, as part of measures we are implementing to boost efficiency.  In 2002, CPPE accounted for approximately 95% of our electricity generation.

 

CPPE generation capacity is bound to the Public Electricity System under PPAs between the company and REN. Under the PPAs, CPPE is guaranteed a fixed revenue component (capacity charge) based on the contracted availability and installed capacity, regardless of the energy produced.  The PPAs also allow CPPE to pass-through to the final tariff its total fuel consumption through a variable revenue component (energy charge) that is invoiced monthly to REN. Pursuant to the Portuguese government’s policy for the energy sector, the PPAs are expected to be renegotiated or terminated as a step in the creation of an Iberian electricity market.  The Portuguese government has announced its intention that generators be adequately compensated for revision or termination of PPAs.  The following table sets forth our total installed capacity by type of facility at year-end for the years 1998 through 2002.

 

 

 

As of December 31,

 

Type of facility

 

1998

 

1999

 

2000

 

2001

 

2002

 

 

 

(MW)

 

Hydroelectric:

 

 

 

 

 

 

 

 

 

 

 

CPPE plants

 

3,903

 

3,903

 

3,903

 

3,903

 

3,903

 

Independent System hydroelectric plants

 

270

 

271

 

270

 

309

 

310

 

Total hydroelectric

 

4,173

 

4,174

 

4,173

 

4,212

 

4,213

 

Thermal

 

3,327

 

3,327

 

3,281

 

3,281

 

3,281

 

Wind

 

20

 

20

 

30

 

41

 

41

 

Biomass

 

0

 

9

 

9

 

9

 

9

 

Cogeneration

 

0

 

0

 

67

 

67

 

111

 

Total

 

7,520

 

7,530

 

7,560

 

7,610

 

7,654

 

 

Hydroelectric generation is dependent upon hydrological conditions.  In years of less favorable hydrological conditions, less hydroelectricity is generated and the Public Electricity System must depend upon increased thermal production.  In addition, in years of less favorable hydrological conditions, imports of electricity may increased.  For purposes of forecast models, our estimated annual hydroelectric production based on current installed capacity in an average year is 10.6 TWh and can reach about 15 TWh in a wet year and may fall to 7 TWh in a dry year.  Between 1992 and 2002, our actual hydroelectric production has ranged from a low of 4,870 GWh in 1992, a very dry year, to a high of 13,920 GWh in 1996, a moderate wet year.  In 2002, hydroelectric production was 7,336 GWh.

 

The following table summarizes our electricity production, excluding losses at our plants and our own consumption, by type of generating facility from 1998 through 2002, and also sets forth our hydroelectric capability factor for the same period.

 

 

 

Year ended December 31,

 

Type of facility

 

1998

 

1999

 

2000

 

2001

 

2002

 

 

 

(in GWh, except by hydroelectric capability factor)

 

Hydroelectric:

 

 

 

 

 

 

 

 

 

 

 

CPPE plants(1)

 

11,506

 

6,457

 

10,229

 

12,607

 

6,764

 

Independent System hydroelectric plants

 

718

 

447

 

624

 

790

 

573

 

Total hydroelectric

 

12,224

 

6,904

 

10,853

 

13,397

 

7,336

 

Thermal:

 

 

 

 

 

 

 

 

 

 

 

Coal

 

8,385

 

9,319

 

9,091

 

8,677

 

9,532

 

Fuel oil and natural gas

 

6,926

 

7,596

 

4,631

 

5,583

 

7,848

 

Gas oil

 

8

 

2

 

38

 

50

 

13

 

Coal and fuel oil(2)

 

73

 

85

 

11

 

30

 

44

 

Cogeneration

 

0

 

0

 

134

 

423

 

589

 

Total thermal

 

15,392

 

17,002

 

13,905

 

14,763

 

18,026

 

Wind

 

46

 

53

 

70

 

90

 

113

 

Biomass

 

0

 

2

 

5

 

18

 

37

 

Total

 

27,662

 

23,961

 

24,833

 

28,269

 

25,513

 

Hydroelectric capability factor(3)

 

1.04

 

0.68

 

1.08

 

1.19

 

0.75

 

 

33



 


(1)          Includes the following amounts of our own consumption for hydroelectric pumping, 100 GWh in 1998, 491 GWh in 1999, 558 GWh in 2000, 485 GWh in 2001 and 670 GWh in 2002.

 

(2)          Our existing plant at Tapada do Outeiro used only fuel oil from 1998 onwards.

 

(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, while 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 CPPE’s plants increased from 1998 through 2002 from 92.84% to 94.44% for thermal plants, and remained stable from 96.12% to 95.89% for hydroelectric plants. Non-availability results from planned maintenance and forced outages. CPPE is reducing planned maintenance outages through more efficient maintenance techniques.  Forced outage is unplanned availability at a power plant caused by trips, critical repairs or other unexpected occurrences.  CPPE’s generating facilities have experienced very low rates of forced outage over the past five years.  Management believes these low rates compare favorably with the European average.  In the period 1998 through 2002, forced outage of CPPE’s thermal plants has ranged from 2.13% to 2.91%.  During the same period, forced outage of hydroelectric plants ranged between a low of 0.3% in 1998 to a high of 1.0% in 2001. Forced outage of hydroelectric plants in 2002 was 0.47%.

 

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.  During 2002, a workgroup within CPPE studied and revised our computations of the “Average capacity utilization” and “Average availability factor” indicators, in order to make them comparable with other European utilities. The table below sets out for each type of CPPE generating facility the average capacity utilization and average availability factor, each calculated in accordance with our revised computational method, for the indicated years:

 

 

 

Average capacity utilization (1)
Year ended December 31,

 

Average availability factor
Year ended December 31,

 

Type of facility

 

1998

 

1999

 

2000

 

2001

 

2002

 

1998

 

1999

 

2000

 

2001

 

2002

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hydroelectric

 

33.655

%

18.88

%

29.84

%

36.87

%

19.78

%

96.12

%

95.12

%

95.02

%

94.76

%

95.89

%

Thermal:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal(2)

 

80.30

%

89.25

%

86.82

%

83.10

%

91.28

%

90.48

%

90.46

%

89.15

%

90.50

%

94.00

%

Fuel oil and natural gas

 

46.16

%

50.63

%

30.78

%

37.21

%

52.31

%

94.15

%

93.23

%

94.57

%

96.55

%

93.73

%

Coal and fuel oil

 

8.91

%

10.33

%

2.76

%

7.23

%

10.82

%

97.78

%

98.62

%

99.59

%

98.90

%

98.17

%

Gas oil

 

0.29

%

0.08

%

1.32

%

1.74

%

0.44

%

93.33

%

99.64

%

99.40

%

98.38

%

99.14

%

Total weighted average thermal (3)

 

52.81

%

58.33

%

47.79

%

49.90

%

60.68

%

92.84

%

93.02

%

93.15

%

94.57

%

94.44

%

 


(1)          The average capacity utilization is defined as actual production as a percentage of theoretical maximum production.

 

(2)          The average availability of the coal plants in 1998 and 1999 was affected by the installation of low NOX burners in each unit of the Sines plant, one per year, which required production from each unit to stop temporarily. In addition, there was a strike at the Sines plant in 1998.

 

(3)          Weighted average is based on total installed capacity of the thermal system.

 

During the period from 1998 through 2002, CPPE has had operating and maintenance costs, excluding fuel and depreciation cost, below the limits contained in the relevant PPAs over that time period. Management expects to continue to maintain these costs below the PPA limits in 2003.

 

CPPE’s power plants, because they are in the Binding Sector, are required to have binding licenses issued by DGE. CPPE received the requisite binding licenses in June 1997, which were effective from January 1, 1995.

 

34



 

Hydroelectric plants
 

As of December 31, 2002, we operated 25 hydroelectric generating facilities in the Binding System, with 63 total units and an aggregate installed capacity of 3,903 MW.

 

Based on an independent revaluation of our assets in 1992, management estimates that the average remaining useful life of our dams is approximately 45 years.  The table below sets out our hydroelectric plants, installed capacity as of December 31, 2002, 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)
(1)

 

River reservoir
plant type

 

Year entered
into service

 

Year of last major
refurbishment

 

CPPE Plants:

 

 

 

 

 

 

 

 

 

Alto Lindoso

 

630

 

Reservoir

 

1992

 

 

Miranda

 

369

 

Run of river

 

1960/95

 

1970

 

Aguieira

 

336

 

Reservoir

 

1981

 

 

Valeira

 

240

 

Run of river

 

1976

 

 

Bemposta

 

240

 

Run of river

 

1964

 

1969

 

Pocinho

 

186

 

Run of river

 

1983

 

 

Picote

 

195

 

Run of river

 

1958

 

1969

 

Carrapatelo

 

201

 

Run of river

 

1971

 

 

Régua

 

180

 

Run of river

 

1973

 

 

Torrão

 

140

 

Reservoir

 

1988

 

 

Castelo de Bode

 

159

 

Reservoir

 

1951

 

1986

(1)

Vilarinho Furnas

 

125

 

Reservoir

 

1972/87

 

 

Vila Nova (Venda Nova/Paradela)

 

144

 

Reservoir

 

1951/56

 

1994

 

Fratel

 

132

 

Run of river

 

1974

 

1997

 

Crestuma-Lever

 

117

 

Run of river

 

1985

 

 

Cabril

 

108

 

Reservoir

 

1954

 

1986

 

Alto Rabagão

 

68

 

Reservoir

 

1964

 

 

Tabuaço

 

58

 

Reservoir

 

1965

 

 

Caniçada

 

62

 

Reservoir

 

1954

 

1979

 

Bouçã

 

44

 

Reservoir

 

1955

 

1988

 

Salamonde

 

42

 

Reservoir

 

1953

 

1989

 

Pracana

 

41

 

Reservoir

 

1950/93

 

1993

 

Caldeirão

 

40

 

Reservoir

 

1994

 

 

Touvedo

 

22

 

Reservoir

 

1993

 

 

Raiva

 

24

 

Reservoir

 

1982

 

 

Total

 

3,903

 

 

 

 

 

 

 

Independent System Hydroelectric Plants:

 

 

 

 

 

 

 

 

 

Hidrocenel(2)

 

107

 

Various

 

Various

 

 

 

HDN(3)

 

118

 

Various

 

Various

 

 

 

EDP Energia(4)

 

85

 

Various

 

Various

 

 

 

Total

 

310

 

 

 

 

 

 

 

Total maximum capacity

 

4,213

 

 

 

 

 

 

 

 


(1)          We invested approximately € 12 million in the modernization of the electricity generating turbines and other dam equipment at Castelo de Bode. We expect this modernization to be completed by the end of 2003.

 

(2)          Hidrocenel operates 14 plants with capacities ranging from 0.1 MW to 24.4 MW and dates of entry into service from 1906 to 2001.

 

(3)          HDN operates 12 plants with capacities ranging from 0.9 MW to 44.1 MW and dates of entry into service from 1922 to 2001.

 

(4)          EDP Energia owns five plants with capacities ranging from 0.2 MW to 80.7 MW and dates of entry into service from 1927 to 1951.

 

35



 

Thermal plants
 

CPPE operates all seven of our conventional thermal power plants, with total installed capacity as of December 31, 2002 of 3,281 MW and installed capacity per generating unit ranging from 16 MW to 298 MW.  The following table sets forth, as of December 31, 2002, our conventional thermal plants by installed capacity, type of fuel, net efficiency at maximum output, number of units and year entered into service.

 

Thermal plants

 

Installed
Capacity (MW)

 

Fuel

 

Net efficiency
at maximum
output

 

Number of
units

 

Years entered
into service

 

Sines

 

1,192

 

Coal

 

36.9

 

4

 

1985-89

 

Setúbal

 

946

 

Fuel oil

 

38.3

 

4

 

1979-83

 

Carregado I

 

474

 

Fuel oil

 

37.4

 

4

 

1968/1974

 

II(1)

 

236

 

Fuel oil / Natural gas

 

37.7

 

2

 

1976

 

Tunes

 

197

 

Gas oil

 

28.4

 

4

 

1973/1982

 

Tapada do Outeiro (EDP facility)(2)

 

47

 

Coal / fuel oil

 

29.5

 

1

 

1967

 

Alto de Mira

 

132

 

Gas oil

 

25.5

 

6

 

1975-77

 

Barreiro

 

56

 

Fuel oil

 

34.3

 

2

 

1978

 

Total maximum capacity

 

3,281

 

 

 

 

 

 

 

 

 

 


(1)          These units began burning natural gas in 1997.

 

(2)          This three-unit plant is scheduled to be progressively decommissioned until the end of 2004. The first unit of 50 MW was decommissioned on December 31, 1997. The second unit of 50 MW was decommissioned on December 31, 1999. In 2000, 2001 and 2002, one unit was operational, with an installed capacity of 50 MW.  Since January 1, 1998, this facility has burned only fuel oil.

 

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

 

Other energy sources

 

In addition to our hydroelectric plants, we promote the use of renewable source energy with other types of facilities. Enernova, our subsidiary specializing in this area, concentrated its initial investments in wind sources (due to greater technological advances made to date). Our first wind facility commenced operation in 1996. We now have four wind facilities with a combined installed capacity of 41 MW.  In mid 2002, we created a new subsidiary for the biomass assets, EDP Produção Bioeléctrica, which owns the Mortágua biomass (forestry residue) power plant. This plant commenced operations in 1999 and has an installed capacity of 9 MW. Enernova activities are now focused solely on wind projects.

 

Fuel

 

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

 

CPPE fuel consumption costs including transportation were € 434.6 million in 2002 and € 353.6 million in 2001, which represented approximately 52.8% and 48.3%, respectively, of CPPE’s total operating expenses.  The increase in the total cost of fuel consumed from 2001 to 2002 resulted primarily from an increase in thermal production powered by fuel oil, explained by a dry 2002, as well as slightly higher prices for fuel oil.

 

 

36



 

The table below sets forth a breakdown of costs of fuel consumed by CPPE from 1998 through 2002.

 

 

 

Year ended December 31,

 

Type

 

1998

 

1999

 

2000

 

2001

 

2002

 

 

 

(thousands of EUR)

 

Imported coal

 

120,445

 

116,823

 

127,104

 

142,810

 

148,773

 

Fuel oil(1)

 

109,167

 

109,371

 

146,721

 

193,867

 

259,816

 

Gas oil(2)

 

549

 

219

 

1,895

 

4,618

 

1,512

 

Natural gas

 

16,670

 

42,163

 

25,364

 

12,260

 

24,497

 

Total

 

246,830

 

268,578

 

301,084

 

353,555

 

434,597

 

 


(1)          Includes consumption for the production of steam at the Barreiro power plant.

 

(2)          Small amounts of gas oil are consumed by the gas oil plants for the operation of these plants in synchronous compensation mode for purposes of voltage regulation and a very small amount of generation.

 

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

 

 

 

Year ended December 31,

 

Type

 

1998

 

1999

 

2000

 

2001

 

2002

 

 

 

(thousands of metric tons, except natural gas)

 

Imported coal

 

3,294

 

3,533

 

3,564

 

3,108

 

3,587

 

Fuel oil(1)

 

1,484

 

1,712

 

1,052

 

1,237

 

1,941

 

Gas oil

 

0

 

0

 

0

 

26