Company Quick10K Filing
CPFL Energy
20-F 2019-12-31 Filed 2020-04-24
20-F 2018-12-31 Filed 2019-04-22
20-F 2017-12-31 Filed 2018-04-24
20-F 2016-12-31 Filed 2017-04-17
20-F 2015-12-31 Filed 2016-04-15
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20-F 2013-12-31 Filed 2014-04-04
20-F 2012-12-31 Filed 2013-04-17
20-F 2011-12-31 Filed 2012-03-30
20-F 2010-12-31 Filed 2011-06-06
20-F 2009-12-31 Filed 2010-04-05

CPL 20F Annual Report

Item 17 £ Item 18 £
Item 1. Identity of Directors, Senior Management and Advisers
Item 2. Offer Statistics and Expected Timetable
Item 3. Key Information Selected Financial and Operating Data
Item 4. Information on The Company Overview
Item 4B. Unresolved Staff Comments
Item 5. Operating and Financial Review and Prospects
Item 6. Directors, Senior Management and Employees Directors and Senior Management Board of Directors
Item 7. Major Shareholders and Related Party Transactions Major Shareholders
Item 8. Financial Information Consolidated Statements and Other Financial Information
Item 9. The Offer and Listing Trading Markets
Item 10. Additional Information Memorandum and Articles of Incorporation Corporate Purpose
Item 11. Quantitative and Qualitative Disclosures About Market Risk
Item 12. Description of Securities Other Than Equity Securities American Depositary Shares Fees and Expenses
Item 13. Defaults, Dividend Arrearages and Delinquencies
Item 14. Material Modifications To The Rights of Security Holders and Use of Proceeds
Item 15. Controls and Procedures
Item 16. Item 16A. Audit Committee Financial Expert
Item 16B. Code of Ethics
Item 16C. Principal Accountant Fees and Services Audit and Non‑Audit Fees
Item 16D. Exemptions From The Listing Standards for Audit Committees
Item 16E. Purchases of Equity Securities By The Issuer and Affiliated Purchasers
Item 16F. Change in Registrant's Certifying Accountant
Item 16G. Corporate Governance
Item 17. Financial Statements
Item 18. Financial Statements
Item 19. Exhibits
Note 5 Shows The Main Differences Between The Accounting Practices Adopted Previously in Brazil and The Current and Effective Standards Presented Herein.
EX-1.1 exhibit11.htm
EX-3.1 exhibit31.htm
EX-8.1 exhibit81.htm
EX-12.1 exhibit121.htm
EX-12.2 exhibit122.htm
EX-13.1 exhibit131.htm
EX-13.2 exhibit132.htm

CPFL Energy Earnings 2010-12-31

Balance SheetIncome StatementCash Flow

20-F 1 cplform20f20102.htm FORM 20-F 2010 cplform20f20102.htm - Generated by SEC Publisher for SEC Filing

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 20-F

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

for the fiscal year ended December 31, 2010
Commission File Number 1-32297

CPFL ENERGIA S.A.

(Exact name of registrant as specified in its charter)

CPFL ENERGY INCORPORATED

The Federative Republic of Brazil

(Translation of registrant’s name into English)

(Jurisdiction of incorporation or organization)

 

Rua Gomes de Carvalho, 1,510, 14th floor - Suite 1402
CEP 04547-005 Vila Olímpia - São Paulo, São Paulo
Federative Republic of Brazil
+55 11 3841-8507
(Address of principal executive offices)

Lorival Nogueira Luz Junior
+55 19 3756 8704 – lorival.luz@cpfl.com.br
Rodovia Campinas Mogi Mirim, km 2,5 – Campinas, São Paulo - 13088 900
Federative Republic of Brazil
(Name, telephone, e-mail and/or facsimile
number and address of company contact person)
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:

Common Shares, without par value*
American Depositary Shares (as evidenced by American Depositary Receipts), each representing 3 Common Shares

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 

As of December 31, 2010, there were 481,137,130 common shares, without par value, outstanding

 


 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes    No  £ 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934.

Yes  £   No 

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    No  £ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  £   No  £   N/A 

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

Large Accelerated Filer    Accelerated Filer  £   Non‑accelerated Filer  £ 

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP  £   IFRS    Other  £ 

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 £   Item 18  £ 

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act).

Yes  £   No 

ii


 

 

Table of Contents

Page
FORWARD-LOOKING STATEMENTS 1
CERTAIN TERMS AND CONVENTIONS 1
PRESENTATION OF FINANCIAL INFORMATION 2
ITEM 1. Identity of Directors, Senior Management and Advisers 2
ITEM 2. Offer Statistics and Expected Timetable 2
ITEM 3. Key Information 2
Selected Financial and Operating Data 2
Exchange Rates 5
RISK FACTORS 6
Risks Relating to Our Operations and the Brazilian Power Industry 6
Risks Relating to Brazil 11

 

Risks Relating to the ADSs and Our Common Shares 13
ITEM 4. Information on the Company 14
Overview 14
Our Strategy 18
Our Service Territory 20
Distribution 20
Purchases of Electricity 23
Consumers and Tariffs 24
Generation of Electricity 27
Electricity Commercialization and Services 32
Competition 33
Our Concessions and Authorizations 33
Properties 36
Environmental 36
The Brazilian Power Industry 37
Principal Regulatory Authorities 37
Concessions and Authorizations 38
The New Industry Model Law 40
Tariffs for the Use of the Distribution and Transmission Systems 44
Distribution Tariffs 45
Government Incentives to the Energy Sector 46
Regulatory Charges 47
Energy Reallocation Mechanism 48
ITEM 4B. UNRESOLVED STAFF COMMENTS 48
ITEM 5.  OPERATING AND FINANCIAL REVIEW AND PROSPECTS 49
ITEM 6. Directors, Senior Management and Employees 68
ITEM 7.  Major Shareholders and Related Party Transactions 75
ITEM 8. Financial Information 78
ITEM 9.  The Offer and Listing 80
ITEM 10. Additional Information 82
Material Contracts 88
ITEM 11.  Quantitative and Qualitative Disclosures about Market Risk 98
ITEM 12.  Description of Securities Other than Equity Securities 99
Reimbursement of Fees and Direct and Indirect Payments by the Depositary 99
ITEM 13.  Defaults, Dividend Arrearages and Delinquencies 99
ITEM 14. Material Modifications to the Rights of Security Holders and Use Of Proceeds 100
ITEM 15. Controls and Procedures 100
Internal Control over Financial Reporting 100
ITEM 16. 100
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT 100
ITEM 16B. CODE OF ETHICS 101

iii


 

 

FORWARD-LOOKING STATEMENTS

This annual report contains information that constitutes forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995.  Many of the forward-looking statements contained in this annual report can be identified by the use of forward-looking words, such as “believe,” “may,” “aim,” “estimate,” “continue,” “anticipate,” “will,” “intend,” “expect” and “potential,” among others.  Forward-looking statements include information concerning our possible or assumed future results of operations, business strategies, financing plans, competitive position, industry environment, potential growth opportunities, the effects of future regulation and the effects of competition.  Those statements appear in a number of places in this annual report, principally under the captions “Item 3.  Key Information—Risk Factors,” “Item 4.  Information on the Company” and “Item 5.  Operating and Financial Review and Prospects.”  We have based these forward-looking statements largely on our current beliefs, expectations and projections about future events and financial trends affecting our business.  Many important factors, in addition to those discussed elsewhere in this annual report, could cause our actual results to differ substantially from those anticipated in our forward-looking statements.  These factors include:

·         general economic, political, demographic and business conditions in Brazil and particularly in the markets we serve;

·         changes in applicable laws and regulations, as well as the enactment of new laws and regulations, including those relating to environmental, tax and employment matters;

·         electricity shortages;

·         changes in tariffs;

·         our inability to generate electricity due to water shortages, transmission outages, operational or technical problems or physical damages to our facilities;

·         potential disruption or interruption of our services;

·         inflation and exchange rate variation;

·         the early termination of our concessions to operate our facilities;

·         increased competition in the power industry markets in which we operate;

·         our inability to implement our capital expenditure plan, including our inability to arrange financing when required and on reasonable terms;

·         changes in consumer demand;

·         existing and future governmental regulations relating to the power industry; and

·         the risk factors discussed under “Item 3.  Key Information—Risk Factors,” beginning on page 6.

Forward-looking statements speak only as of the date they were made, and we undertake no obligation to update or to revise them after we distribute this annual report because of new information, future events or other factors.  In light of these limitations, you should not place undue reliance on forward-looking statements contained in this annual report.

CERTAIN TERMS AND CONVENTIONS

A glossary of electricity industry terms is included in this annual report, beginning on page 103.

 

1


 

PRESENTATION OF FINANCIAL INFORMATION

We maintain our books and records in reais.  We prepared our consolidated financial statements included in this annual report in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).  Our consolidated annual financial statements as of and for the year ended December 31, 2010 are our first financial statements prepared in accordance with IFRS.  IFRS 1 – “First‑time Adoption of International Financial Reporting Standards” has been applied in preparing these financial statements.  Until December 31, 2009, our consolidated financial statements were prepared in accordance with accounting practices adopted in Brazil (“Brazilian Accounting Principles”), and reconciled to generally accepted accounting principles in the United States.

Brazilian Accounting Principles differ in certain significant respects from IFRS.  When preparing our 2010 consolidated financial statements under IFRS, management amended certain accounting methods in the Brazilian Accounting Principles financial statements to comply with IFRS.  The comparative figures in respect of 2009 have been restated to reflect these adjustments.  Reconciliations and descriptions of the effect of the transition from Brazilian Accounting Principles to IFRS are presented in note 5 to our consolidated financial statements included elsewhere in this annual report.

We have translated some of the real  amounts contained in this annual report into U.S. dollars.  The rate used to translate such amounts was R$1.666 to US$1.00, which was the rate for the selling of U.S. dollars in effect as of December 31, 2010 as reported by the Central Bank of Brazil (the “Central Bank”).  The U.S. dollar equivalent information presented in this annual report is provided solely for convenience of investors and should not be construed as implying that the real  amounts represent, or could have been or could be converted into, U.S. dollars at the above rate.  See “Item 3.  Key Information—Exchange Rates” for more information regarding the Brazilian foreign exchange rate system and historical data on the exchange rate between reais  and U.S. dollars.

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 and Operating Data

The tables below contain a summary of our financial data as of and for each of the periods indicated.  The summary of our financial data was derived from our consolidated annual financial statements, prepared in accordance with IFRS, as issued by the IASB.  You should read this selected financial data in conjunction with our consolidated financial statements and the related notes thereto included in this annual report.

The selected consolidated financial information as of and for the years ended December 31, 2009 and 2010, prepared in accordance with IFRS, has been derived from our audited consolidated financial statements, which appear elsewhere in this annual report.

The following tables present our selected financial data as of and for each of the periods indicated.

2


 

STATEMENT OF OPERATIONS DATA

 

For the year ended December 31,

 

2010

2010

2009

 

US$

R$

R$

 

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

IFRS

 

 

 

Net operating revenue

7,216

12,024

11,358

Cost of electric energy services:

 

 

 

Cost of electric energy

3,734

6,222

6,015

Operating cost

641

1,068

1,054

Services rendered to third parties

631

1,051

621

Gross operating income

2,210

3,683

3,668

 

 

 

 

Operating expenses

 

 

 

Sales expenses

181

301

255

General and administrative expenses

266

443

403

Other operating expense

120

200

227

Income from electric energy service

1,643

2,739

2,783

Financial income (expense):

 

 

 

Income

290

483

351

Expense

(502)

(837)

(661)

 

(212)

(354)

(310)

Income before taxes

1,431

2,385

2,473

Social contribution

(133)

(221)

(208)

Income tax

(363)

(604)

(576)

 

(496)

(825)

(784)

Net income

935

1,560

1,689

Net income attributable to controlling shareholders

922

1,538

1,657

Net income attributable to non controlling shareholders

13

22

32

Net income per share

1.92

3.20

3.45

Net income per ADS

5.76

9.60

10.36

Dividends(1)

756

1,260

1,227

Weighted average of number of common shares

481

481

480

Dividends per share (1)

1.57

2.62

2.56

Dividends per ADS (1)

4.72

7.86

7.67

 

BALANCE SHEET DATA

 

For the year ended December 31,

 

2010

2010

2009

 

US$

R$

R$

 

(in millions)

IFRS

 

 

 

Current assets:

 

 

 

Cash and cash equivalents

938

1,563

1,487

Accounts receivable

1,090

1,816

1,753

Other current assets

312

519

409

Total current assets

2,340

3,898

3,649

 

 

 

 

Non-current assets:

 

 

 

Accounts receivable

117

196

225

Financial asset of concession

561

935

674

Property, plant and equipment

3,473

5,786

5,213

Intangible Assets

3,952

6,585

6,063

Other non-current assets

1,595

2,657

2,666

Total non-current assets

9,698

16,159

14,841

Total assets

12,038

20,057

18,490

 

 

 

 

Current liabilities:

 

 

 

Short-term debt(2)

1,351

2,251

1,364

Other current liabilities

1,307

2,177

2,059

Total current liabilities

2,658

4,428

3,423

 

 

 

 

Long-term liabilities:

 

 

 

Long-term debt(2)

4,302

7,167

6,548

Other long-term liabilities

1,027

1,712

1,983

Total long-term liabilities

5,329

8,879

8,531

Noncontrolling interest

154

256

267

Shareholders’ equity

3,897

6,494

6,269

Total liabilities and shareholders’ equity

12,038

20,057

18,490

3


 

 

OPERATING DATA(*)

 

For the year ended December 31,

 

2010

2009

2008

2007

2006

Energy sold (in GWh):

 

 

 

 

 

Residential

12,983

12,346

11,649

10,766

9,489

Industrial

15,413

14,970

16,066

16,692

16,882

Commercial

7,695

7,297

6,938

6,509

5,779

Rural

2,100

2,256

2,449

2,511

1,966

Public administration

1,112

1,074

1,027

972

862

Public lighting

1,444

1,408

1,355

1,284

1,152

Public services

1,742

1,664

1,634

1,590

1,472

Own consumption

33

33

32

30

25

Total energy sold to Final Consumers

42,522

41,048

41,150

40,354

37,627

Electricity sales to wholesalers (in GWh)

12,737

12,925

9,551

8,731

7,461

Total consumers (in thousands)(3)

6,748

6,567

6,425

6,257

5,749

Installed capacity (in MW)

2,309

1,737

1,704

1,588

1,072

Assured energy (in GWh)

7,786

7,485

7,134

6,698

4,962

Energy generated (in GWh)

9,142

5,984

6,659

6,382

3,407

   

                                                               

(*)           Unaudited.

(1)           “Dividends” represent the total amount of dividends from net income for each period indicated, subject to approval of the shareholders at the general shareholders’ meeting to be held in the following year.

(2)           Short-term debt and long‑term debt include derivative and accrued interest.

(3)           Represents active consumers (meaning consumers who are connected to the distribution network), rather than consumers invoiced at period-end.

 

4


 

Exchange Rates

The Central Bank allows the real/U.S. dollar exchange rate to float freely, and it has intervened occasionally to control unstable movements in foreign exchange rates.  We cannot predict whether the Central Bank or the Brazilian government will continue to let the real  float freely or will intervene in the exchange rate market through a currency band system or otherwise.  The real  may substantially depreciate or appreciate against the U.S. dollar.  For more information on these risks, see “Item 3.  Additional Information—Risk Factors—Risks Relating to Brazil.”

The following table provides information on the selling exchange rate, expressed in reais  per U.S. dollar (R$/US$), for the periods indicated.

 

Year-end

Average for
period(1)

Low

High

 

(reais  per U.S. dollar)

Year ended:

 

 

 

 

December 31, 2006

2.138

2.168

2.059

2.371

December 31, 2007

1.771

1.930

1.733

2.156

December 31, 2008

2.337

1.833

1.559

2.500

December 31, 2009

1.741

1.990

1.702

2.422

December 31, 2010

1.666

1.759

1.655

1.881

 

   

                                                  

(1)           Year-end figures represent the average of the month-end selling exchange rates during the relevant period.

 

 

Month-end

Average for
period(1)

Low

High

 

(reais  per U.S. dollar)

Month ended:

 

 

 

 

December 2010

1.666

1.693

1.666

1.712

January 2011

1.673

1.675

1.651

1.691

February 2011

1.661

1.668

1.661

1.678

March 2011

1.629

1.659

1.629

1.676

April 2011

1.573

1.586

1.565

1.619

May 2011

1.580

1.613

1.575

1.634

June (through June 3rd, 2011)

1.574

1.581

1.574

1.588

 

   

                                            

(1)           The figures provided for months in 2010 and 2011, as well as for the month of June up to and including June 3, 2011, represent the average of the selling exchange rates at the close of trading on each business day during such period.

 

5


 

RISK FACTORS

Risks Relating to Our Operations and the Brazilian Power Industry

We are subject to comprehensive regulation of our business, which fundamentally affects our financial performance.

Our business is subject to extensive regulation by various Brazilian regulatory authorities, particularly the National Electric Energy Agency, Agência Nacional de Energia Elétrica (“ANEEL”).  ANEEL regulates and oversees various aspects of our business and establishes our tariffs.  If we are obliged by ANEEL to make additional and unexpected capital investments and are not allowed to adjust our tariffs accordingly, or if ANEEL modifies the regulations related to such adjustment, we may be adversely affected.

In addition, the implementation of our strategy for growth, as well as the ordinary carrying out of our business may be adversely affected by governmental actions such as changes to current legislation, the termination of federal and state concession programs, creation of more rigid criteria for qualification in public energy auctions, or a delay in the revision and implementation of new annual tariffs.

If we are required to conduct our business in a manner substantially different from our current operations as a result of regulatory changes, our operations and financial results may be adversely affected.

The regulatory framework under which we operate is subject to legal challenge.

The Brazilian government implemented fundamental changes in regulation of the power industry under 2004 legislation known as the Lei do Novo Modelo do Setor Elétrico, or New Industry Model Law.  Challenges to the constitutionality of the New Industry Model Law are still pending before the Brazilian Supreme Court.  If all or part of the New Industry Model Law were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework.  The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including our business and results of operations.

We are uncertain as to the renewal of our concessions.

We carry out our generation and distribution activities pursuant to concession agreements entered into with the Brazilian Federal Government.  Our concessions range in duration from 16 to 35 years, with the first expiration date in 2015.  Five of our distribution subsidiaries have concessions that expire in July 2015, with options to renew for an additional 20 years.  In 2010, these five distribution subsidiaries represented 5.4% of net operating revenues of our distribution companies and 5.7% of the energy distributed by our distribution companies.

The Brazilian constitution requires that all concessions relating to public services be awarded through a bidding process.  Under laws and regulations specific to the electric sector, the Federal Government may renew existing concessions for additional periods of up to 30 years without a bidding process, provided that the concessionaire has met minimum performance standards and that the proposal is otherwise acceptable to the Federal Government.  The Federal Government has considerable discretion under the Concessions Law and the concession contracts with respect to renewal of concessions.  Moreover, there is no extensive history of administrative renewal practice.  As a result, we cannot assure you that our concessions will be renewed at all, or that they will be renewed on the same terms.

The tariffs that we charge for sales of electricity to captive consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us.

 

ANEEL has substantial discretion to establish the tariff rates our distribution companies charge our consumers.  Our tariffs are determined pursuant to concession agreements with the Brazilian Federal Government, and in accordance with ANEEL’s regulations and decisions.

Our concession agreements and the Brazilian law establish a mechanism that permits three types of tariff adjustments:  (i) the annual adjustment (“reajuste anual”), (ii) the periodic revision (“revisão periódica”) and

6


 

Table of Contents

 

(iii) the extraordinary revision (“revisão extraordinária”).  We are entitled to apply each year for the annual adjustment, which is designed to offset some effects of inflation on tariffs and pass through to consumers certain changes in our cost structure that are beyond our control, such as the cost of electricity we purchase from certain sources and certain regulatory charges, including charges for the use of transmission and distribution facilities.  In addition, ANEEL carries out a periodic revision every four or five years that is aimed at identifying variations in our costs as well as setting a factor based on our operational efficiency that will be applied against the index of our ongoing annual tariff adjustments, the objective of which is to share any related gains with our consumers.  We are also subject to extraordinary revision of our tariffs that may affect (negatively or positively) our results of operations or financial position.

 

We cannot be sure if ANEEL will establish tariffs at rates that are favorable to us, due to changes in the methods in calculating the periodic revision adjustments.  In addition, to the extent that any of these adjustments are not granted by ANEEL in a timely manner, our financial condition and results of operations may be adversely affected.

The methodology applicable to the third periodic revision cycle (2011 to 2014) is under discussion at public hearing No. 40/2010, conducted by ANEEL.  For the third cycle, ANEEL has proposed a new method for recognizing the costs we pass through to our consumers.  ANEEL is currently receiving comments from players within the electricity sector and will disclose its conclusions up to the third quarter of 2011.  As initially suggested by ANEEL, the new methodology negatively affects our financial condition and results of operations.  However, the outcome of public hearing No. 40/2010 is still uncertain and we cannot predict how the new methodology will impact our financial condition.

Additionally, ANEEL suggested a change in the methodology for calculating the TUSD and other electricity tariffs, which is under discussion at public hearing No. 120/2010.  The outcome of public hearing No. 120/2010 is also uncertain and we cannot foresee how this methodology will impact our financial condition.

We could be penalized by ANEEL for failing to comply with the terms of our concession agreements, which could result in fines, other penalties and, depending on the gravity of the non‑compliance, in our concessions being terminated.

 

ANEEL may impose penalties on us in the event that we fail to comply with any provision of our concession agreements.  Depending on the gravity of the non‑compliance, these penalties could include the following:

·         warning notices;

·         fines per breach of up to 2.0% of the revenues from the relevant concession in the year ended immediately prior to the date of the relevant breach;

·         injunctions related to the construction of new facilities and equipment;

·         restrictions on the operation of existing facilities and equipment;

·         intervention by ANEEL in the management of the concessionaire; and

·         termination of the concession.

In addition, the Brazilian government has the power to terminate any of our concessions by means of expropriation for reasons related to the public interest.

We are currently in compliance with all of the material terms of our concession agreements.  However, we cannot assure you that we will not be penalized by ANEEL for breaching our concession agreements or that our concessions will not be terminated in the future.  The compensation to which we are entitled upon termination of our concessions may not be sufficient for us to realize the full value of certain assets.  If any of our concession agreements is terminated for reasons attributable to us, the effective amount of compensation by the granting authorities could be materially reduced through the imposition of fines or other penalties.  Accordingly, the

7


 

Table of Contents

 

imposition of fines or penalties on us or the termination of any of our concessions could have a material adverse effect on our financial condition and results of operations.

 

We may not be able to fully pass through the costs of our electricity purchases and, to meet demand, we could be forced to enter into short‑term agreements to purchase electricity at prices substantially higher than under our long‑term purchase agreements.

 

Under the New Industry Model Law, an electricity distributor must contract in advance, through public bids, for 100% of its forecasted electricity needs for its distribution concession areas.  Over- or under-forecasting demand can have adverse consequences.  If our forecasted demand is incorrect and we purchase less or more electricity than we need, we may be prevented from fully passing through the costs of our electricity purchases and we may also be forced to enter into short‑term agreements to purchase electricity at prices substantially higher than under our long‑term purchase agreements.  For instance, the New Industry Model Law provides, among other restrictions, that if our forecasts fall significantly short of actual electricity demand, we may be forced to make up the shortfall with shorter term electricity purchase agreements.  If our acquisitions of electricity in the public auctions are above the Annual Reference Value (Valor Anual de Referência) established by the Brazilian government, we may not be able to fully pass through the costs of our electricity purchases.  Our forecasted electricity demand may prove inaccurate, including as a result of consumers moving between the different markets (regulated and free).  If there are significant variations between our electricity needs and the volume of our electricity purchases, our results of operations may be adversely affected.  See “Item 4.  Information on the Company—The Brazilian Power Industry—The New Industry Model Law.”

ANEEL may limit distributions that our regulated subsidiaries may make to us.

The amounts that our regulated subsidiaries may distribute to us in the form of dividends in any given fiscal year depend on such subsidiaries making a profit, as calculated in accordance with the Brazilian Corporation Law.  Despite the significant cash flow generated by our regulated subsidiaries, their results are affected by depreciation and by the amortization of intangible assets arising from the acquisition of RGE and Semesa.  As a result, this limitation may eventually prevent some portion of the cash generated by our regulated subsidiaries from being distributed to us as dividends.

We generate a significant portion of our operating revenues from consumers that qualify as Free Consumers, and that are allowed to seek alternative electricity suppliers.  We may face other types of competition that could adversely affect our market share and revenues.

 

Within our concession areas, other electricity suppliers are permitted to compete with us in offering electricity to certain consumers that qualify as Free Consumers, to whom our distribution subsidiaries may supply electricity only at regulated tariffs.  Such consumers qualified as Free Consumers may elect to opt out of our regulated distribution system upon the expiration of their contracts with us, by providing six months’ prior notice, or by providing a year’s prior notice if their contract has no fixed termination date.  At December 31, 2010, we supplied energy to 72 consumers qualified as Free Consumers, which accounted for approximately 2.5% of our net operating revenues and approximately 4.3% of the total volume of electricity sold by our distributors during 2010.  In addition, other consumers meeting certain criteria may become Free Consumers if they move to energy from renewable energy sources, such as small hydroelectric power plants or biomass.  At December 31, 2010 we had a total of 1,637 of these consumers which accounted for approximately 14.6% of our net operating revenues and approximately 18.3% of the total volume of electricity sold by our distribution companies during 2010.  A decision by our consumers qualified as Free Consumers to become Free Consumers and purchase electricity from electricity suppliers serving Free Consumers located in our concession areas would adversely affect our market share and results of operations.

In addition, it is possible that our large industrial clients could be authorized by ANEEL to generate electric energy for self consumption or sale to other parties, in which case they may obtain an authorization or concession for the generation of electric power in a given area, which could adversely affect our results of operations.

 

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Our operating results depend on prevailing hydrological conditions.  The impact of an electricity shortage and related electricity rationing, as in 2001 and 2002, may have a material adverse effect on our business and results of operations.

 

We are dependent on the prevailing hydrological conditions in the geographic region in which we operate.  In 2009, according to data from the National Electrical System Operator, Operador Nacional do Sistema Elétrico (“ONS”), more than 93.3% of Brazil’s electricity supply came from hydroelectric generation facilities.  Our region is subject to unpredictable hydrological conditions, with non‑cyclical deviations from average rainfall.  The most recent period of low rainfall was between 2000 and 2001, when the Brazilian government instituted the Rationing Program, a program to reduce electricity consumption that was in effect from June 1, 2001 to February 28, 2002.  The Rationing Program established limits for energy consumption for industrial, commercial and residential consumers, which ranged from a 15.0% to a 25.0% reduction in energy consumption.  If Brazil experiences another electricity shortage, the Brazilian government may implement similar or other policies in the future to address the shortage that could have a material adverse effect on our financial condition and results of operations.  A recurrence of poor hydrological conditions that result in a low supply of electricity to the Brazilian market could cause, among other things, the implementation of broad electricity conservation programs, including mandated reductions in electricity consumption.  We cannot assure you that periods of severe or sustained below-average rainfall will not adversely affect our future financial results.

Construction, expansion and operation of our electricity generation and distribution facilities and equipment involve significant risks that could lead to lost revenues or increased expenses.

 

The construction, expansion and operation of facilities and equipment for the generation and distribution of electricity involves many risks, including:

·         the inability to obtain required governmental permits and approvals;

·         the unavailability of equipment;

·         supply interruptions;

·         work stoppages;

·         labor unrest;

·         social unrest;

·         weather and hydrological interferences;

·         unforeseen engineering and environmental problems;

·         increases in electricity losses, including technical and commercial losses;

·         construction and operational delays, or unanticipated cost overruns;

·         the inability to win electricity auctions promoted by ANEEL; and

·         unavailability of adequate funding.

If we experience these or other problems, we may not be able to generate and distribute electricity in amounts consistent with our projections, which may have an adverse effect on our financial condition and results of operations.  We do not have insurance for many of these risks.

 

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We are subject to environmental and health regulations that may become more stringent in the future and may result in increased liabilities and increased capital expenditures.

Our distribution and generation activities are subject to comprehensive federal and state legislation as well as supervision by Brazilian governmental agencies that are responsible for the implementation of environmental and health laws and policies.  These agencies could take enforcement action against us for our failure to comply with their regulations.  These actions could include, among other things, the imposition of fines and revocation of licenses.  It is possible that enhanced environmental and health regulations will force us to allocate capital expenditures to compliance, and consequently, divert funds from planned investments.  Such a diversion could have a material adverse effect on our financial condition and results of operations.

If we are unable to complete our proposed capital expenditure program in a timely manner, the operation and development of our business may be adversely affected.

 

We plan to invest approximately R$1,892 million in our generation activities, and R$4,779 million in our distribution activities during the period from 2011 through 2015.  Our ability to carry out this capital expenditure program depends on a variety of factors, including our ability to charge adequate tariffs for our services, our access to domestic and international capital markets and a variety of operating, regulatory and other contingencies.  We cannot be certain that we will have the financial resources to complete our proposed capital expenditure program, and failure to do so could have a material adverse effect on the operation and development of our business.

We are strictly liable for any damages resulting from inadequate provision of electricity services, and our contracted insurance policies may not fully cover such damages.

 

Under Brazilian law we are strictly liable for direct and indirect damages resulting from the inadequate provision of electricity distribution services.  In addition, our distribution facilities may, together with our generation utilities, be held liable for damages caused to others as a result of interruptions or disturbances arising from the generation, transmission or distribution systems, whenever these interruptions or disturbances are not attributed to an identifiable member of the ONS.  We cannot assure you that our contracted insurance policies will fully cover damages resulting from inadequate rendering of electricity services which may have an adverse effect on us.

We may not be able to create the expected benefits and return on investments from the new businesses we recently entered into.

 

We have entered into a number of new energy generation businesses (wind, thermoelectric and biomass energy) with substantial capital investments.  We have few operating history and track record in these industries and may not be able to foster the synergies with our traditional businesses.  In addition:

·         In the biomass business, we may suffer from a lack of sugar cane (a necessary input for the generation of this type of energy) in the market.  In addition, we depend to a certain extent on the performance of our partners in these projects in the construction and operation of the plants;

·         Among the significant uncertainties and risks with respect to our wind farms under construction, we have financial risk associated with the difference between the energy we generate and the energy contracted through the reserve energy contract (Contrato de Energia de Reserva – CER), in which we bear the risk of divergences arising from:  (a) wind intensity and duration different from that contemplated in the study phase of the project; (b) delay in commencement of operations of the wind farms under construction; and (c) unavailability of wind turbines at levels above the performance benchmarks;

If these new generation plants are not able to (i) generate the energy contracted by our clients, or (ii) generate the energy necessary to supply any clients in the free market, and (iii), the energy provided to us is insufficient to supply the contracted demand, we may be obliged to buy the shortfall in the spot market, in which the price per MWh is usually more volatile and may be higher than our price, resulting in an adverse effect on us.

Our growth, operating results and financial condition may be negatively affected by one or more of the above factors.

 

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We are controlled by a few shareholders acting together, and their interests could conflict with yours.

As of December 31, 2010, VBC Energia S.A. (“VBC”), PREVI (through BB Carteira Livre I FIA), and Bonaire Participações S.A. (“Bonaire”), owned 25.55%, 31.02% and 12.62%, respectively, of our outstanding common shares.  These entities are parties to a shareholders’ agreement, pursuant to which they share the power to control us.  Our controlling shareholders may take actions that could be contrary to your interests, and our controlling shareholders will be able to prevent other shareholders, including you, from blocking these actions.  In particular, our controlling shareholders control the outcome of decisions at shareholders’ meetings, and they can elect a majority of the members of our Board of Directors.  Our controlling shareholders can direct our actions in areas such as business strategy, financing, distributions, acquisitions and dispositions of assets or businesses.  Their decisions on these matters may be contrary to the expectations or preferences of our noncontrolling shareholders, including holders of our ADSs.  See “Item 7.  Major Shareholders and Related Party Transactions—Shareholders’ Agreement.”

We are exposed to increases in prevailing market interest rates, as well as foreign exchange rate risk.

As of December 31, 2010, approximately 95.0% of our total indebtedness was denominated in reais  and indexed to Brazilian money-market rates or inflation rates, or bore interest at floating rates.  The remaining 5.0% of our total indebtedness was denominated in U.S. dollars and Japanese yen and substantially subject to currency swaps that converted these obligations into reais.  In addition, the costs of electricity purchased from Itaipu are indexed to the U.S. dollar exchange variation.  Our tariffs are adjusted annually in order to contemplate the losses or gains’ effects from such electricity acquisition. Accordingly, if these indexation rates rise or the U.S. dollar/real  or Japanese yen/real  exchange rates appreciate, our financing expenses will increase. 

Our indebtedness and debt service obligations could adversely affect our ability to operate our business and make payments on our debt.

 

As of December 31, 2010, we had a debt of 9,219 million.  Our indebtedness increases the possibility that we may be unable to generate cash sufficient to pay when due the principal, interest or other amounts due in respect of our indebtedness.  In addition, we may incur additional debt from time to time to finance strategic acquisitions, investments, joint ventures or for other purposes, subject to the restrictions applicable under our existing indebtedness.  If we incur additional debt, the risks associated with our leverage would increase.

We may acquire other companies in the electricity business, as we have in the past, and these acquisitions could increase our leverage or adversely affect our consolidated performance.

 

We regularly analyze opportunities to acquire other companies engaged in activities along the entire electricity generation, transmission and distribution chain.  If we do acquire other electricity companies, it could increase our leverage or reduce our profitability.  Furthermore, we may not be able to integrate the acquired company’s activities and achieve the economies of scale and expected efficiency gains that often drive such acquisitions, and failure to do so could harm our financial condition and results of operations.

Risks Relating to Brazil

The Brazilian government has exercised, and continues to exercise, significant influence over the Brazilian economy.  This involvement, as well as Brazilian political and economic conditions, could adversely affect our business and the trading price of our ADSs and our common shares.

 

The Brazilian government frequently intervenes in the Brazilian economy and occasionally makes significant changes in policy and regulations.  The Brazilian government’s actions to control inflation and other policies and regulations have often involved, among other measures, increases in interest rates, changes in tax policies, price controls, currency devaluations, capital controls and limits on imports.  Our business, financial condition and results of operations may be adversely affected by changes in policy or regulations at the federal, state or municipal levels involving or affecting factors such as:

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·         interest rates;

·         monetary policy;

·         currency fluctuations;

·         inflation; 

·         liquidity of domestic capital and lending markets;

·         tax policies;

·         changes in labor laws;

·         regulatory environment of our sector;

·         exchange rates and exchange controls and restrictions on remittances abroad, such as those that were briefly imposed in 1989 and early 1990; and

·         other political, social and economic developments in or affecting Brazil.

We cannot assure you that the Brazilian government will continue with the current economic policies, or that any changes implemented by the Brazilian government will not, directly or indirectly, affect our business and results of operations.

Exchange rate instability may adversely affect our financial condition and results of operations and the market price of the ADSs and our common shares.

 

The Brazilian currency has during the last decades experienced frequent and substantial variations in relation to the U.S. dollar and other foreign currencies.  Between 2000 and 2002, the real  depreciated significantly against the U.S. dollar, reaching an exchange rate of R$3.53 per US$1.00 at the end of 2002.  Between 2003 and mid-2008, the real  appreciated significantly against the U.S. dollar due to the stabilization of the macro-economic environment and a strong increase in foreign investment in Brazil, with the exchange rate reaching R$1.56 per US$1.00 in August 2008.  In the context of the crisis in the global financial markets after mid-2008, the real  depreciated against the U.S. dollar over the year 2008 and reached R$2.337 per US$1.00 at year end 2008.  During 2009, the real  appreciated against the U.S. dollar 25.5% in the context of the economic recovery and reached R$1.741 per US$1.00 at year end 2009.  On December 31, 2010, the exchange rate of the real  against the U.S. dollar was R$1.666 per US$1.00.  On June 3, 2011, the exchange rate was R$1.574 per US$1.00.  Although the real  has appreciated against the U.S. dollar recently, reaching R$1.56 per US$1.00 in April 2011, we cannot assure that the real  will not depreciate against the U.S. dollar in the future.

Depreciation of the real  increases the cost of servicing our foreign currency denominated debt and the cost of purchasing electricity from the Itaipu power plant, a hydroelectric facility that is one of our major suppliers and that adjusts electricity prices based in part on its U.S. dollar costs.  Depreciation of the real  against the U.S. dollar could create inflationary pressures in Brazil and cause increases in interest rates, which could negatively affect the growth of the Brazilian economy as a whole and harm our financial condition and results of operations, may curtail access to foreign financial markets and may prompt government intervention, including recessionary governmental policies.  Depreciation of the real  against the U.S. dollar can also lead to decreased consumer spending, deflationary pressures and reduced growth of the economy as a whole.  On the other hand, appreciation of the real  relative to the U.S. dollar and other foreign currencies could lead to a deterioration of the Brazilian foreign exchange current accounts, as well as dampen export-driven growth.  Depending on the circumstances, either depreciation or appreciation of the real  could materially and adversely affect the growth of the Brazilian economy and our business, financial condition and results of operations.

Depreciation of the real  also reduces the U.S. dollar value of distributions and dividends on the ADSs and the U.S. dollar equivalent of the market price of our common shares and, as a result, the ADSs.

 

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Government efforts to combat inflation may hinder the growth of the Brazilian economy and could harm our business.

 

Brazil has in the past experienced extremely high rates of inflation and has therefore followed monetary policies that have resulted in one of the highest real  interest rates in the world.  Between 2005 and 2010, the base interest rate (“SELIC”) in Brazil varied between 9.8% p.a. and 19.1% p.a.  Inflation and the Brazilian government’s measures to fight it, principally through the Central Bank, have had and may have significant effects on the Brazilian economy and our business.  Tight monetary policies with high interest rates may restrict Brazil’s growth and the availability of credit.  Conversely, more lenient government and Central Bank policies and interest rate decreases may trigger increases in inflation, and, consequently, growth volatility and the need for sudden and significant interest rate increases, which could negatively affect our business.  In addition, if Brazil again experiences high inflation, we may not be able to adjust the rates we charge our consumers to offset the effects of inflation on our cost structure.

Developments and the perception of risk in other countries, including the United States and emerging market countries, may adversely affect the market price of Brazilian securities, including the ADSs and our common shares.

 

The market value of securities of Brazilian issuers is affected by economic and market conditions in other countries, including the United States, the European Union and emerging market countries.  Although economic conditions in those countries may differ significantly from economic conditions in Brazil, investor’s reactions to developments in other countries may have an adverse effect on the market value of securities of Brazilian issuers.  Crises in the United States, the European Union or emerging market countries may diminish investor interest in securities of Brazilian issuers, including ours.  This could adversely affect the trading price of the ADSs or our common shares, and could also make it more difficult for us to access the capital markets and finance our operations in the future on acceptable terms or at all.

The global financial crisis which started during the second half of 2008 has had significant consequences, including in Brazil, such as stock and credit market volatility, unavailability of credit, higher interest rates, a general economic slowdown, volatile exchange rates and inflationary pressure, among others, which may, directly or indirectly, adversely affect us and the market price of Brazilian securities, including the ADSs and our common shares.  The Brazilian government has adopted measures to combat the effects of the financial crisis, such as expansion of credit.  Although the scenario has improved significantly since the second half of 2009, it is still not clear how these measures will affect Brazilian economy in 2011.

Risks Relating to the ADSs and Our Common Shares

Holders of our ADSs may encounter difficulties in the exercise of voting rights.

Holders of our common shares are entitled to vote on shareholder matters.  You may encounter difficulties in the exercise of some of your rights as a shareholder if you hold our ADSs rather than the underlying common shares.  For example, you are not entitled to attend a shareholders’ meeting, and you can only vote by giving timely instructions to the depositary in advance of the meeting.

If you surrender your ADSs and withdraw common shares, you risk losing the ability to remit foreign currency abroad and certain Brazilian tax advantages.

 

As an ADS holder, you benefit from the electronic certificate of foreign capital registration obtained by the custodian for our common shares underlying the ADSs in Brazil, which permits the custodian to convert dividends and other distributions with respect to the common shares into non‑Brazilian currency and remit the proceeds abroad.  If you surrender your ADSs and withdraw common shares, you will be entitled to continue to rely on the custodian’s electronic certificate of foreign capital registration for only five business days from the date of withdrawal.  Thereafter, upon the disposition of or distributions relating to the common shares, you will not be able to remit abroad non‑Brazilian currency unless you obtain your own electronic certificate of foreign capital registration or you qualify under Brazilian foreign investment regulations that entitle some foreign investors to buy and sell shares on Brazilian stock exchanges without obtaining separate electronic certificates of foreign capital

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registration.  If you do not qualify under the foreign investment regulations you will generally be subject to less favorable tax treatment of dividends and distributions on, and the proceeds from any sale of, our common shares.

 

If you attempt to obtain your own electronic certificate of foreign capital registration, you may incur expenses or suffer delays in the application process, which could delay your ability to receive dividends or distributions relating to our common shares or the return of your capital in a timely manner.  The depositary’s electronic certificate of foreign capital registration may also be adversely affected by future legislative changes.

Holders of ADSs may be unable to exercise preemptive rights with respect to our common shares.

We may not be able to offer our common shares to U.S. holders of ADSs pursuant to preemptive rights granted to holders of our common shares in connection with any future issuance of our common shares unless a registration statement under the Securities Act is effective with respect to such common shares and preemptive rights, or an exemption from the registration requirements of the Securities Act is available.  We are not obligated to file a registration statement relating to preemptive rights with respect to our common shares, and we cannot assure you that we will file any such registration statement.  If such a registration statement is not filed and an exemption from registration does not exist, Deutsche Bank, as depositary, will attempt to sell the preemptive rights, and you will be entitled to receive the proceeds of such sale.  However, these preemptive rights will expire if the depositary does not sell them, and U.S. holders of ADSs will not realize any value from the granting of such preemptive rights.

The relative volatility and illiquidity of the Brazilian securities markets may substantially limit your ability to sell the common shares underlying the ADSs at the price and time you desire.

 

Investing in securities that trade in emerging markets, such as Brazil, often involves greater risk than investing in securities of issuers in the United States, and such investments are generally considered to be more speculative in nature.  The Brazilian securities market is substantially smaller, less liquid, more concentrated and can be more volatile than major securities markets in the United States.  Accordingly, although you are entitled to withdraw the common shares underlying the ADSs from the depositary at any time, your ability to sell the common shares underlying the ADSs at a price and time at which you wish to do so may be substantially limited.  There is also significantly greater concentration in the Brazilian securities market than in major securities markets in the United States.  The ten largest companies in terms of market capitalization represented 54,9% of the aggregate market capitalization of the BM&FBOVESPA S.A., Bolsa de Valores, Mercadorias & Futuros (“BM&FBOVESPA”), as of December 31, 2010.  The top ten stocks in terms of trading volume accounted for 58.3%, 53.7% and 50.0% of all shares traded on the BM&FBOVESPA in 2008, 2009 and 2010, respectively.

ITEM 4.                        Information on the Company

Overview

We are a corporation (sociedade por ações) incorporated and existing under the laws of Brazil with the legal name CPFL Energia S.A.  Our principal executive offices are located at Rua Gomes de Carvalho, 1,510, 14th floor – Suite 1402, Vila Olímpia, CEP 04547-005, in the City of São Paulo, state of São Paulo, Brazil and our telephone number is +55 11 3841-8507.

We are a holding company that, through our subsidiaries, distributes, generates and commercializes electricity in Brazil.  We were incorporated in 1998 as a joint venture among VBC, 521 Participações S.A. and Bonaire to combine their interests in companies operating in the Brazilian power sector.

We are one of the largest electricity distributors in Brazil, based on the 39,250 GWh of electricity we distributed to approximately 6.7 million consumers in 2010.  In 2010, our installed capacity was 2,309 MW.  We are also involved in building four biomass generation projects and thirteen wind farms, through which we expect to increase our installed capacity to 2,949 MW once they are completed over the next three years.

We also engage in electricity commercialization and provide electricity-related services to our affiliates as well as unaffiliated parties.  In 2010, the total amount of electricity sold by our commercialization services was 7,272 GWh and 8,806 GWh to affiliated and unaffiliated parties, respectively.

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In 2010 and through June 6, 2011, the following developments affected our corporate structure:

·         In June 2007, we acquired, through our subsidiary Perácio, all of the shares of CPFL Jaguariúna, representing 100% of its capital, for R$408 million in cash.  On March 2009, we merged Perácio into CPFL Jaguariúna and restructured CPFL Jaguariúna such that we now directly hold all of its subsidiaries.

·         In August 2008, we constructed a sugar cane bagasse-powered thermoelectric plant in partnership with Baldin Bioenergia in the city of Pirassununga, in the state of São Paulo.  Baldin plant started commercial operations on August 27, 2010, with installed capacity of 45 MW and assured energy of 112.4 GWh.

·         In August 2009, in order to obtain guarantees from Furnas Centrais Elétricas S.A. (“Furnas”), in the Foz do Chapecó plant, we conducted a restructuring of Foz do Chapecó Energia S.A., which no longer has our subsidiary CPFL Geração de Energia S.A. (“CPFL Geração”), Furnas and Companhia Estadual de Energia Elétrica (“CEEE”), as its shareholders but as its indirect holding companies.  CPFL Geração and CEEE became shareholders of Chapecoense Geração de Energia S.A., holding 51.0% and 9.0% of its capital stock, respectively, with the other 40.0% being held by Furnas.  This restructuring did not change the participation that the shareholders previously held in the plant.

·         In September 2009, we acquired 51.0% of the shares of EPASA Centrais Elétricas da Paraíba S.A., to invest in the generation of energy from fuel oil, with the construction of two thermoelectric power plants:  Termoparaíba and Termonordeste, which together have a total installed capacity of 341.6 MW and assured energy of 2,169.0 GWh.  Termonordeste started commercial operations on December 24, 2010 and Termoparaíba on January 13, 2011.

·         In September 2009, we acquired a complex of wind farms, in the state of Rio Grande do Norte, composed of the wind farms Santa Clara I, II, III, IV, V, VI and Eurus VI.  The wind farms are scheduled to start operations in the third quarter of 2012.  We expect to increase our installed capacity by 188 MW upon completion of these wind farms.

·         In October 20, 2009, we established our subsidiary Bio Formosa, for the generation of thermoelectric energy and water steam through co-generation plants powered by sugar cane bagasse and straw.  On November 6, 2009, CPFL Bio Formosa entered into an agreement for the construction of a thermoelectric power plant of 40 MW powered by sugar cane in the city of Baia Formosa in the state of Rio Grande do Norte.  It is scheduled to start operations in the third quarter of 2011.

·         On April 26, 2010, in a special shareholders’ meeting, our shareholders approved the merger of minority‑held shares of the following subsidiaries:  (i) Companhia Leste Paulista de Energia; (ii) Companhia Jaguari de Energia; (iii) Companhia Sul Paulista de Energia; (iv) Companhia Luz e Força de Mococa; (v) Companhia Jaguari de Geração de Energia; (vi) CPFL Serviços, Equipamentos, Indústria e Comércio S.A.; and (vii) Companhia Luz e Força Santa Cruz.  Therefore, we now hold 100% of these seven subsidiaries’ capital stock.

·         The wholly-owned subsidiaries Campo dos Ventos I, II, III, IV and V and Eurus V are closely-held companies that were acquired on July 16, 2010 to act as independent producers of electric energy from alternative sources, mainly wind power, in the state of Rio Grande do Norte.  On August 26, 2010, they participated in the wind power reserve auction promoted by ANEEL, in which Campo dos Ventos II entered into an agreement for the supply of 14 MW of electricity for a 20-year term beginning in 2013.  These subsidiaries are scheduled to start operations in the third quarter of 2013.  We expect to increase our installed capacity by 180 MW upon completion of these wind farms.

·         The wholy-owned subsidiaries CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra are closely-held companies that were established on January 27, 2010 with the main purpose of generating thermoelectric energy and water stream through co-generation plants powered by sugar-cane bagasse and straw.  On August 26, 2010, CPFL Bio Pedra participated in the wind power reserve auction promoted by ANEEL, in which it entered into an agreement for the supply of 24,3 MW of electricity for a 20-year term beginning in 2013.  CPFL Bio Buriti and CPFL Bio Ipê are scheduled to start operations in the second quarter of 2011 and CPFL Bio Pedra in the second quarter of 2012.

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·         On April 7, 2011, we entered into a Sale and Purchase Agreement for the acquisition of 100% of the shares of Jantus SL and/or a potential acquisition of 100% of the shares of Jantus II, a corporation that will be established by the sellers. Jantus has:  (i) four wind farms in operation in the state of Ceará with installed capacity of 210 MW and 20-year term agreements with Eletrobrás for the sale of energy, (ii) a wind farm project in the state of Rio de Janeiro with potential installed capacity of 135MW and an agreement with Eletrobrás for the sale of energy, and (iii) a portfolio of wind farm projects with total installed capacity of 732 MW in the states of Ceará and Piauí, of which 412 MW has already been certified and eligible for participation in the next electricity auctions.  The acquisition is subject to compliance with certain conditions provided for in the Sale and Purchase Agreement, including authorizations from regulatory authorities, and must be ratified by our shareholders.

·         On April 19, 2011, we entered into a Joint Venture Agreement with Energias Renováveis S.A. (“ERSA”) to combine assets and projects relating to renewable energy sources (wind, biomass and small hydroelectric power plants).  The joint venture will encompass:  (i) the transfer of wind, biomass and small hydroelectric plants currently owned and operated by CPFL Geração and CPFL Comercialização Brasil S.A. (“CPFL Brasil”) to certain companies, which will subsequently transfer the wind, biomass and small hydroelectric plants to a holding company (“New CPFL”); (ii) the establishment of New CPFL by CPFL Geração and CPFL Brasil; (iii) the incorporation of New CPFL by ERSA, of which CPFL Geração and CPFL Brasil will own 63.3%; and (iv) the change of ERSA’s corporate name to CPFL Energia Renováveis S.A.  The joint venture is subject to compliance with certain conditions provided for in the Joint Venture Agreement, including authorizations from regulatory authorities, the corporate restructuring of our subsidiaries and compliance with conditions provided for in the Sale and Purchase Agreement for the acquisition of Jantus.  The Joint Venture Agreement must also be ratified by our shareholders.

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The following chart provides an overview of our corporate structure, as of April 30, 2011:
 
1Includes 13 companies
Santa Clara Wind Farms (Santa Clara I, Santa Clara II, Santa Clara III, Santa Clara IV, Santa Clara V, Santa Clara VI, Eurus VI); and
Campo dos Ventos Wind Farms (Campo dos Ventos I, Campo dos Ventos II, Campo dos Ventos III, Campo dos Ventos IV, Campo dos Ventos V and Eurus V).

Our core businesses are:

·         Distribution.  In 2010, our eight fully-consolidated distribution subsidiaries delivered 39,250 GWh of electricity to approximately 6.7 million consumers primarily in the states of São Paulo and Rio Grande do Sul.

·         Generation.  As of December 31, 2010, we had installed capacity of 2,309 MW.  During 2010, we generated a total of 9,142 GWh of electricity, and we had 7,786 GWh of assured energy, the amount of energy representing our long‑term average electricity production, as established by ANEEL, which is         the primary driver of our revenues relating to generation activities.  We hold equity interests in eight hydroelectric plants (Serra da Mesa, Monte Claro, Barra Grande, Campos Novos, Luiz Eduardo Magalhães-Lajeado, Castro Alves, 14 de Julho and Foz do Chapecó).  Although the concession for Serra da Mesa hydroelectric generation facility is held by Furnas, we are entitled to 51.54% of its assured energy.  We also own 34 small hydroelectric power plants and three thermoelectric power plants, two of which were acquired in 2009 (Termoparaiba and Termonordeste) through the acquisition of EPASA and are already active.  In 2008, we entered into energy generation from biomass through Baldin (CPFL Bioenergia), a sugar cane bagasse‑powered plant, which started operations in August 2010 with installed capacity of 45 MW and assured energy of 112.4 GWh.  In 2009, we constituted CPFL Bio Formosa and, in 2010, we constituted CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra in the same segment.  In 2009 and 2010, we acquired Santa Clara and Campo dos Ventos wind farms, respectively, companies engaged in the construction of wind farms.  By 2013, once all of these facilities become fully operational, we estimate that our installed capacity will reach 2,949 MW.  In October 2010, Foz do Chapecó hydroelectric plant started operations, currently representing an installed capacity of 855 MW, of which we hold a share of 51%, or 436.1 MW.  In December 2010, Termonordeste thermoelectric plant started operations with installed capacity of 170.8 MW, in which we hold a share of 51%, or 87.1 MW.  We closed 2010 with total installed capacity of 2,309 MW.  We will use part of our increased installed capacity for our own distribution and commercialization activities.

17


 

·         Commercialization and Electricity-Related Services.  Our subsidiary CPFL Brasil handles our commercialization operations and electricity-related services.  CPFL Brasil procures electricity for our distribution operations, sells electricity to Free Consumers, other commercialization companies and distribution utilities, and provides electricity-related services.  In 2010, we sold 16,078 GWh of electricity of which 8,806 GWh was sold to unaffiliated third parties.

Capital Expenditures

For a description of our capital expenditures, see below "Item 5. Operating and Financial Review and Prospects – Capital Expenditures."

Our Strategy

Our overall objective is to continue to be a leading supplier of electricity distribution services in Brazil, while expanding our generation and commercialization activities and maximizing profitability and shareholder value.  We seek to achieve these goals by consistently pursuing operational efficiency, growth through business synergies, financial discipline, social responsibility and enhanced corporate governance standards.  More specifically, our approach involves the following key business strategies:

Complete the development of our existing generation projects, expand our generation portfolio by developing new generation projects and become the market leader in renewable energy sources.  We have been developing a portfolio of new hydroelectric generating facilities.  Between 2005 and 2010, seven new plants became operational, which, together with our prior facilities, have a total installed capacity of 2,309 MW.  In 2008, we entered into energy generation from biomass through CPFL Bioenergia (Baldin energy generation plant).  In 2009, we (i) acquired a 51.0% stake in Centrais Elétricas da Paraíba (EPASA), owner of the Termonordeste and Termoparaíba thermoelectric power plants; (ii) incorporated CPFL Bio Formosa, a company for the development of energy generation from biomass of CPFL Group; and (iii) acquired seven companies engaged in the construction of wind farms.  In 2010, we (i) incorporated CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra, companies engaged in the generation of energy from biomass of and (ii) acquired a company engaged in the construction of wind farms.  In 2011, we entered into a Sale and Purchase Agreement for the acquisition of 100% of the shares of Jantus, a company engaged in generation of energy through renewable sources, especially wind power, and into a Joint Venture Agreement with ERSA to combine assets and projects relating to renewable energy sources.  Both the acquisition of Jantus and the joint venture with ERSA are still subject to certain conditions, including approval by the regulatory authorities1.

By the end of 2011, when CPFL Bio Formosa, CPFL Bio Buriti and CPFL Bio Ipê are expected to become fully operational and, considering the installed capacity of Termoparaiba (operational since January 2011), we expect our installed capacity to reach 2,511 MW.  By the end of 2012, when CPFL Bio Pedra and Santa Clara wind farms are expected to become fully operational, this capacity may reach 2,769 MW and, by the end of 2013, when we expect the Campo dos Ventos wind farms to become operational and two small hydroelectric power plants located in the state of Rio Grande do Sul to be refurbished, it may reach 2,949 MW.  Part of these generation facilities have associated long‑term power purchase agreements (“PPAs”), approved by ANEEL, which we believe will ensure us an attractive rate of return on our investment.  As per capita consumption of electricity in Brazil increases, we believe that there will continue to be new opportunities for us to explore investments in additional generation projects.


1 For this reason, in this annual report, our projections as to our installed capacity for future periods do not reflect increases in our installed capacity due to the acquisition of Jantus and the joint venture with ERSA.

18


 

Focus on further improving our operating efficiency.  The distribution of electricity to captive consumers in our distribution concession areas is our largest business segment.  We continue to focus on improving our service and maintaining low operating costs by exploiting synergies across subsidiaries and investing in new systems that monitor our assets so that they are more efficiently managed.  We seek to create value for our shareholders by optimizing our debt portfolio and exercising shrewd financial judgment.  We also believe that a strong distribution business of sufficient scale will continue to provide a springboard for our strategies in electricity generation and commercialization.  We also make an effort to standardize and update our operations regularly, introducing automated systems where possible.  In 2008, we implemented the Six Sigma Quality process in our distribution processes.  In 2011, we started the Tauron project, aiming at an efficiency breakthrough in our distribution operations, based on new technologies, performance management, asset management and leadership.  We expect to fully implement Tauron project by 2013.

Expand and strengthen our commercialization business.  Free Consumers represent a significant segment of the electricity market in Brazil.  We strive to maintain our captive market.  However, where we face competition, we make an effort to retain those of our consumers that are Free Consumers by means of bilateral contracts with CPFL Brasil, our commercialization subsidiary, in addition to attracting additional Free Consumers from outside of our distribution companies’ concession areas.  In order to achieve this objective, we foster positive relationships with customers by providing electricity-related services, strategic advice and decision-making support.

Position ourselves to take advantage of consolidation in our industry by using our experience in successfully integrating and restructuring other operations.  We believe that with the stabilization of the regulatory environment in the Brazilian power industry, there may be substantial consolidation in the generation, the transmission and, particularly, the distribution sectors.  Given our financial strength and managerial expertise, we believe that we are well-positioned to take advantage of this consolidation.  If promising assets are available on attractive terms, we may make acquisitions that complement our existing operations and afford us further opportunities to take advantage of economies of scale.

Maintain a high level of social responsibility in the communities in which we operate.  We aim to hold our business operations to the highest standards of social responsibility and sustainable development in terms of our efforts to respect the environment.  We also support initiatives to advance the economic, cultural and social interests of the communities in which we operate and contribute effectively to their further development.

Follow enhanced corporate governance standards.  We are dedicated to maintaining the highest levels of management transparency, providing equitable shareholder rights and, through various measures, including the increase of our free float and the liquidity of our shares, generating value for our shareholders.

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Our Service Territory 

 

Distribution

We are one of the largest electricity distributors in Brazil, based on the amount of electricity we delivered in 2010.  Our eight distribution subsidiaries together supply electricity to a region covering 176,3102 square kilometers primarily in the States of São Paulo and Rio Grande do Sul.  Their service areas include 568 municipalities and a population of approximately 17.8 million people.  Together, they provided electricity to approximately 6.7 million consumers as of December 31, 2010.  Our eight subsidiaries distributed approximately 13% of the total electricity distributed in Brazil, calculated based on data from the Energetic Studies Company (Empresa de Pesquisas Energéticas - EPE).

 

The 15% decrease as compared to 2009 was due to the fact that certain cooperatives within RGE concession distribution area have been classified by ANEEL as permissionaries (and, as such, they are now considered as distributors).  However, this decrease did not  impact our revenues and results of operations.

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Distribution Companies

We have eight distribution subsidiaries:

·         CPFL Paulista.  Companhia Paulista de Força e Luz (“CPFL Paulista”) supplies electricity to a region covering 90,440 square kilometers in the state of São Paulo with a population of approximately 9.4 million people.  Its service area covers 234 municipalities, including the cities of Campinas, Bauru, Ribeirão Preto, São José do Rio Preto, Araraquara and Piracicaba.  CPFL Paulista had approximately 3.7 million consumers as of December 31, 2010.  In 2010, CPFL Paulista distributed 20,649 GWh of electricity, which accounts for approximately 16.5% of the total electricity distributed in the state of São Paulo, and 6.7% of the total electricity distributed in Brazil, during that period.

·         CPFL Piratininga.  Companhia Piratininga de Força e Luz (“CPFL Piratininga”) supplies electricity to a region covering 6,785 square kilometers in the southern part of the state of São Paulo with a population of approximately 3.5 million people.  Its service area covers 27 municipalities, including the cities of Santos, Sorocaba and Jundiaí.  CPFL Piratininga had approximately 1.4 million consumers as of December 31, 2010.  In 2010, CPFL Piratininga distributed 8,931 GWh of electricity, accounting for approximately 7.1% of the total electricity distributed in the state of São Paulo, and 2.9% of the total electricity distributed in Brazil, during that period.

·         RGE.  Rio Grande Energia S.A. (“RGE”) supplies electricity to a region covering 58,823 square kilometers in the state of Rio Grande do Sul with a population of approximately 3.7 million people.  Its service area covers 262 municipalities, including the cities of Caxias do Sul and Gravataí.  RGE had approximately 1.3 million consumers as of December 31, 2010.  In 2010, RGE supplied 7,446 GWh of electricity (6,740 GWh distributed to Final Consumers, and 706 GWh delivered principally to small electric concessionaires and small rural cooperatives), which accounts for approximately 33.0% of the total electricity distributed in the state of Rio Grande do Sul, and 2.0% of the total electricity distributed in Brazil, during that period.

·         CPFL Santa Cruz.  Companhia Luz e Força Santa Cruz (“CPFL Santa Cruz”) supplies electricity to an area covering 11,775 square kilometers, which includes 27 municipalities in the northwest part of the state of São Paulo and three municipalities in the state of Paraná.  In 2010, CPFL Santa Cruz distributed 918 GWh of electricity to approximately 178,000 consumers, accounting for approximately 0.7% of the total electricity distributed in the state of São Paulo, and 0.3% of the total electricity distributed in Brazil, during that period.

·         CPFL Jaguari.  Companhia Jaguari de Energia (“CPFL Jaguari”) supplies electricity to an area covering 252 square kilometers, which includes two municipalities of the state of São Paulo.  In 2010, CPFL Jaguari distributed 419 GWh of electricity to approximately 33,000 consumers.

·         CPFL Mococa.  Companhia Luz e Força de Mococa (“CPFL Mococa”) supplies electricity to an area covering 1,844 square kilometers, which includes one municipality of the state of São Paulo and three municipalities in the state of Minas Gerais.  In 2010, CPFL Mococa distributed 208 GWh of electricity to approximately 41,000 consumers.

·         CPFL Leste Paulista.  Companhia Leste Paulista de Energia (“CPFL Leste Paulista”) supplies electricity to an area covering 2,589 square kilometers, which includes seven municipalities of the state of São Paulo.  In 2010, CPFL Leste Paulista distributed 304 GWh of electricity to approximately 51,000 consumers.

·         CPFL Sul Paulista.  Companhia Sul Paulista de Energia (“CPFL Sul Paulista”) supplies electricity to an area covering 3,802 square kilometers, which includes five municipalities of the state of São Paulo.  In 2010, CPFL Sul Paulista distributed 375 GWh of electricity to approximately 72,000 consumers.

 

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Distribution Network

Our eight distribution subsidiaries own distribution lines with voltage levels ranging from 34.5 kV to 138 kV.  These lines distribute electricity from the connection point with the Basic Network to our power sub-stations, in each of our concession areas.  All consumers that connect to these distribution lines, such as Free Consumers or other concessionaires, are required to pay a tariff for using the system - Tarifa de Uso do Sistema de Distribuição (“TUSD”).

Each of our subsidiaries has a distribution network consisting of a widespread network of predominantly overhead lines and sub-stations having successively lower voltage ranges.  Consumers are classified in different voltage levels based on their consumption of, and demand for, electricity.  Large industrial and commercial consumers receive electricity at high voltage ranges (up to 138 kV) while smaller industrial, commercial and residential consumers receive electricity at lower voltage ranges (2.3 kV and below).

As of December 31, 2010, our distribution network consisted of 215,194 kilometers of distribution lines, including 262,983 distribution transformers.  Our eight distribution subsidiaries had 9,496 km of high voltage distribution lines between 34.5 kV and 138 kV.  At that date, we had 429 transformer sub-stations for transforming high voltage into medium voltages for subsequent distribution, with total transforming capacity of 13,035 mega-volt amperes.  Of the industrial and commercial consumers in our concession area, 282 had 69 kV, 88 kV or 138 kV high-voltage electricity supplied through direct connections to our high voltage distribution lines.

System Performance
Electricity Losses

We experience two types of electricity losses:  technical losses and commercial losses.  Technical losses are those that occur in the ordinary course of our distribution of electricity.  Commercial losses are those that result from illegal connections, fraud or billing errors and similar matters.  Electricity loss rates of our three largest distribution subsidiaries (CPFL Paulista, CPFL Piratininga and RGE) compare favorably to the average for other major Brazilian electricity distributors in 2009 according to the most recent information available from the Brazilian Association of Electric Energy Distributors, Associação Brasileira de Distribuidores de Energia Elétrica (“ABRADEE”), an industry association.

We are also actively engaged in efforts to reduce commercial losses from illegal connections, fraud, billing errors.  To achieve this, in each of our eight subsidiaries, we have deployed trained technical teams to conduct inspections, enhanced monitoring for irregular consumption, increased replacements for obsolete measuring equipment and developed a computer program to discover and analyze irregular invoicing.  Approximately 482,700 inspections were conducted during 2010, which we believe led to a recovery of receivables estimated at more than R$121 million.

Power Outages

The following table sets forth the frequency and duration of electricity outages per consumer for the years 2010 and 2009 for each of our distribution subsidiaries:

 

Year ended December 31, 2010

 

 

 

CPFL
Paulista

CPFL
Piratininga

RGE

CPFL
Santa Cruz

CPFL
Jaguari

CPFL
Mococa

CPFL Leste Paulista

CPFL Sul Paulista

 

 

 

 

 

 

 

 

 

FEC1

5.05

5.22

9.66

6.52

7.81

4.52

7.69

7.75

DEC2

5.65

6.88

14.71

5.49

9.24

4.59

8.28

9.21

 

     

(1)           Frequency of outages per consumer per year (number of outages).

(2)           Duration of outages per consumer per year (in hours).

22


 

 

 

Year ended December 31, 2009

 

 

 

 

 

 

 

 

 

 

CPFL
Paulista*

CPFL Piratininga*

RGE

CPFL Santa Cruz*

CPFL
Jaguari*

CPFL
Mococa

CPFL Leste Paulista

CPFL Sul Paulista

 

 

 

 

 

 

 

 

 

FEC1

5.77/5.07*

6.41/5.35*

8.80

7.55/7.27*

6.06/5.07*

8.27

10.75

7.37

DEC2

7.62/5.76*

11.02/6.68*

14.45

5.47/5.34*

10.61/6.07*

8.18

11.31

8.94

 

(1)           Frequency of outages per consumer per year (number of outages)

(2)           Duration of outages per consumer per year (in hours)

*              A power outage in Brazil on November 10, 2009, which interrupted the energy supply in 17 states and the Federal District, affected the FEC/DEC indexes in four of our distribution subsidiaries (CPFL Paulista, CPFL Piratininga, CPFL Jaguari and CPFL Santa Cruz), responsible for 66.0% of our supply.  Similar events occurred in 2002, 1999 and 1985 in Brazil.  The numbers presented after the slash sign do not consider the effects of the interruptions.

We seek to improve the quality and reliability of our power supply, as measured by the frequency and duration of our power outages.  According to data from ABRADEE for 2009, our frequency and duration of interruptions per consumer in the past few years compare favorably to the averages for other Brazilian distribution companies.

Based on data published by ANEEL, the duration and frequency of outages at CPFL Paulista and CPFL Piratininga are among the lowest in Brazil compared to companies of similar size.  The duration of outages at RGE are comparatively higher than those at CPFL Paulista and CPFL Piratininga, but they remain in line with the average rate for power companies in Southern Brazil mainly as a result of the lack of redundancies in its distribution system, the use of medium voltage lines and a lower level of automation in the network.

Our distribution subsidiaries have construction and maintenance technology that allows for repairs of the electricity network without interruption in electricity service, which allows us to have low levels of scheduled interruption, amounting to approximately up to 14% of total interruptions.  Unscheduled interruptions due to accidents or natural causes, including lightning storms, fire and wind represented the remainder of our total interruptions.  In 2010, we invested a total of R$999 million in improvements of (i) the logistics of our operations, (ii) our systems, and (iii) our infrastructure to support operations, across our different business segments.  We expect to invest an additional R$1,161 million for such purposes in 2011.

We strive to improve response times for our repair services.  The quality indicators for the provision of energy by CPFL Paulista and CPFL Piratininga have maintained levels of excellence while complying with regulatory standards.  This was also mainly the result of our efficient operational logistics, including the strategic positioning of our teams and the technology and automation of our network and operation centers, together with a preventive maintenance and conservation plan.

Purchases of Electricity

Most of the electricity we sell is purchased from unrelated parties, rather than generated by our facilities.  In 2010, 10.2% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries.  Of the total energy that we purchased in 2010, 69.9% was purchased in the regulated market and 30.1% was purchased in the free market.

In 2010, we purchased 10,835 GWh of electricity from the Itaipu power plant, amounting to 20.7% of the total electricity we purchased.  Itaipu is located on the border of Brazil and Paraguay and is subject to a bilateral treaty between the two countries pursuant to which Brazil has committed to purchasing specified amounts of electricity.  This treaty will expire in 2023.  Electric utilities operating under concessions in the Midwest, South and Southeast regions of Brazil are required by law to purchase a portion of the electricity that Brazil is obligated to purchase from Itaipu.  The amounts that these companies must purchase are governed by take-or-pay contracts with tariffs established in US$/kW.  ANEEL annually determines the amount of electricity to be sold by Itaipu.  We pay for energy purchased from Itaipu in accordance with the ratio between the volume established by ANEEL and our statutorily established share, regardless of whether Itaipu generates such amount of electricity, at a price of

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Table of Contents

 

 

US$24.63/kW.  Our purchases represent approximately 16.9% of Itaipu’s total supply to Brazil.  This share was fixed by law according to the amount of electricity sold in 1991.  The rates at which companies are required to purchase Itaipu’s electricity are established pursuant to the bilateral treaty, and fixed to cover Itaipu’s operating expenses and payments of principal and interest on Itaipu’s U.S. dollar‑denominated debts, as well as the cost of transmitting the power to their concession areas.

 

The Itaipu plant has an exclusive transmission grid.  Distribution companies pay a fee for the use of this grid.

In 2010, we paid an average of R$93.23 per MWh for purchases of electricity from Itaipu, as compared to R$104.41 during 2009 and R$88.10 during 2008.  These figures do not include the transmission fee.

We purchased 41,549 GWh of electricity in 2010 from generating companies other than Itaipu, representing 79.3% of the total electricity we purchased.  We paid an average of R$109.47 per MWh for purchases of electricity from generating companies other than Itaipu, as compared to R$104.44 per MWh in 2009.  For more information on the regulated market and the free market, see “—The Brazilian Power Industry—The New Industry Model Law.”

The following table shows amounts purchased from our suppliers in the regulated market and in the free market, for the periods indicated.

 

Year Ended December 31,

 

2010

2009

2008

 

(in GWh)

Electricity purchased in the regulated market:

 

 

 

Itaipu

10,835

11,084

11,085

Tractebel Energia S.A

7,482

6,827

 7,128 

Petrobrás – Petróleo Brasileiro S.A

1,717

1,721

1,718

Furnas Centrais Elétricas S.A

1,673

1,649

1,261

Electric Energy Trading Chamber – CCEE

3,373

3,101

2,820

Companhia Energética de São Paulo – CESP

1,759

1,808

1,711

Companhia Hidro Elétrica do São Francisco – CHESF

1,343

1,318

1,255

Companhia Energética de Minas Gerais – CEMIG

1,036

1,357

723

TermoRio S.A

454

248

341

Copel Geração S.A

694

713

343

PROINFA

1,133

958

629

Other

5,123

5,710

4,134

Total

36,622

36,494

33,148

Electricity purchased in the free market

15,762

16,180

16,183

Total

52,384

52,674

49,331

 

The provisions of our electricity supply contracts are governed by ANEEL regulations.  The main provisions of each contract relate to the amount of electricity purchased, the price, including adjustments for various factors such as inflation indexes, and the duration of the contract.

Transmission Tariffs.  In 2010, we paid a total of R$1,172 million in tariffs for the use of the transmission network, including Basic Network tariffs, connection tariffs and transmission of high-voltage electricity from Itaipu at rates set by ANEEL.

Consumers and Tariffs

Consumers

We classify our consumers into five principal categories.  See note 27 to our audited consolidated financial statements for a breakdown of our sales by category.

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·         Industrial consumers.  Sales to final industrial consumers accounted for 29.6% of our revenue of electricity sales in 2010.

·         Residential consumers.  Sales to final residential consumers accounted for 38.9% of our revenue of electricity sales in 2010.

·         Commercial consumers.  Sales to final commercial consumers, which include service businesses, universities and hospitals, accounted for 20.1% of our revenue of electricity sales in 2010.

·         Rural consumers.  Sales to final rural consumers accounted for 3.1% of our revenue of electricity sales in 2010.

·         Other consumers.  Sales to other consumers, which include public and municipal services such as street lighting, accounted for 8.3% of our revenue of electricity sales in 2010.

Retail Distribution Tariffs.  We classify our consumers into two different groups, Group A consumers and Group B consumers, based on the voltage level at which the electricity is supplied to them.  Each consumer is placed in a certain tariff level defined by law and based on its respective classification, although some volume-based discounts are available.  Group B consumers pay higher tariffs.  Tariffs in Group B vary by type of consumer (industrial, residential, commercial or rural).  Consumers in Group A pay lower tariffs, decreasing from A4 to Al, because they are supplied electricity at higher voltages, which requires lower use of the energy distribution system.  The tariffs we charge for sales of electricity to Final Consumers are determined pursuant to our concession agreements and regulations established by ANEEL.  These concession agreements and related regulations establish a cap on tariffs that provides for annual, periodic and extraordinary adjustments.  For a discussion of the regulatory regime applicable to our tariffs and their adjustment, see “—The Brazilian Power Industry.”

Group A consumers receive electricity at 2.3 kV or higher.  Tariffs for Group A consumers are based on the voltage level at which electricity is supplied, and the time of year and the time of day electricity is supplied, although consumers may opt for a different tariff applicable in peak periods in order to optimize the use of the electric network.  Tariffs for Group A consumers consist of two components:  a “capacity charge” and an “energy charge.”  The capacity charge, expressed in reais  per kW, is based on the higher of (i) contracted firm capacity or (ii) power capacity actually used.  The energy charge, expressed in reais  per MWh, is based on the amount of electricity actually consumed.  Group A consumers are those that will likely qualify as Free Consumers under the New Industry Model Law.  See “—The Brazilian Power Industry—The New Industry Model Law.”

Group B consumers receive electricity at less than 2.3 kV (220V and 127V).  Tariffs for Group B consumers consist solely of an energy consumption charge and are based on the classification of the consumer.

The following tables sets forth our average retail prices for each consumer category for 2010 and 2009.  These prices include taxes (ICMS, PIS and COFINS) and were calculated based on our revenues and the volume of electricity sold in 2010 and 2009.

 

Year ended December 31, 2010

 

 

 

 

 

 

 

 

 

 

CPFL Paulista

CPFL Piratininga

RGE

CPFL Santa Cruz

CPFL Leste Paulista

CPFL Sul Paulista

CPFL Jaguari

CPFL Mococa

 

 

 

 

 

 

 

 

 

 

(R$/MWh)

Residential

400.76

394.42

509.89

432.07

458.09

452.57

379.55

507.27

Industrial

311.90

295.54

346.97

323.89

342.95

287.54

275.80

330.85

Commercial

339.05

347.41

491.23

395.70

428.93

432.77

344.44

428.78

Rural

181.49

213.16

235.64

212.40

232.12

243.18

198.59

243.94

Other

250.07

246.31

231.00

184.17

303.61

295.12

246.49

294.39

Total

334.34

335.74

380.34

323.59

352.11

353.03

296.27

376.04

 

25


 

 

 

Year ended December 31, 2009

 

 

 

 

 

 

 

 

 

 

CPFL
Paulista

CPFL
Piratininga

RGE

CPFL
Santa Cruz

CPFL Leste Paulista

CPFL Sul Paulista

CPFL
Jaguari

CPFL
Mococa

 

 

 

 

 

 

 

 

 

 

(R$/MWh)

Residential

398.32

395.34

491.34

429.88

484.73

430.10

360.57

490.49

Industrial

327.86

295.26

336.76

339.46

339.35

263.53

250.56

299.13

Commercial

354.52

347.04

475.34

397.54

452.73

420.92

321.30

414.27

Rural

187.99

213.20

190.49

214.15

261.68

238.05

113.10

245.44

Other

259.81

246.29

272.76

185.74

316.43

284.78

246.81

285.03

Total

343.05

335.52

366.56

328.62

373.34

330.25

268.99

360.55

 

Under current regulations, residential consumers may be classified as low income residential consumers depending on the amount of energy they consume.  Regulations define low income residential consumers as consumers who utilize less than 80 kWh per month, or other volume of electricity up to 220 kWh per month, depending on the region in which they live.  Low income residential consumers may apply to receive benefits under some of the Brazilian government’s social programs.  One such benefit afforded to low income residential consumers is that they are not required to pay emergency capacity and emergency acquisition charges or any extraordinary tariff approved by ANEEL.

TUSD.  Under applicable laws and regulations, we are required to allow other consumers to use our high‑voltage distribution lines, including Free Consumers within our distribution concession areas that are supplied by other distributors.  All of our consumers must pay a fee for the use of our network.  In 2010, tariff revenues for the use of our network by Free Consumers amounted to R$1,128 millions.  The average tariff for the use of our network was R$88.15/MWh and R$73.45/MWh in 2010 and 2009, respectively, including the TUSD we charge to other distributors connected to our distribution network.

Billing Procedures

The procedure we use for billing and payment for electricity supplied to our consumers is determined by consumer category.  Meter readings and invoicing take place on a monthly basis for low voltage consumers, with the exception of rural consumers, whose meters are read in intervals varying from one to three months, as authorized by relevant regulation.  Bills are prepared from meter readings or on the basis of estimated usage.  Low voltage consumers are billed within three business days after the meter reading, with payment required within five business days after the invoice date.  In case of nonpayment, we send the consumer a notice of nonpayment with the following month’s invoice and we allow the consumer 15 days to settle the amount owed to us.  If payment is not received within three business days after that 15-day period, the consumer’s electricity supply is suspended.

High voltage consumers are billed on a monthly basis with payment required within five business days after the invoice date.  In the event of nonpayment, we send the consumer a notice four business days after the due date, giving a deadline of 15 days to make payment.  If payment is not made within three business days after that 15‑day period, the consumer’s service is discontinued.

According to data from ABRADEE for 2009, the percentage of customers in default of our three largest distribution subsidiaries compare favorably to the average for other major Brazilian electricity distributors.  For this purpose, consumers in default are consumers whose bills are one to 89 days due.  Bills due for over 89 days are deemed not recoverable.

Customer Service

We strive to provide high-quality customer service to our distribution consumers.  We operate call centers at each of our distribution subsidiaries providing customer service 24 hours a day, 7 days a week.  In 2010, our call centers responded to approximately 10.3 million calls.  We also provide customer service through our Internet website, which handled approximately 10.1 million customer requests in 2010, and through our branch offices, which handled approximately 1.8 million customer requests in 2010.  The growth in electronic requests has allowed us to reduce our customer service costs and provide customer service through our call center to a larger number of

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customers without access to the Internet.  Following receipt of a customer service request, we dispatch our technicians to make any necessary repairs.

 

Generation of Electricity

We are actively expanding our generating capacity.  In accordance with Brazilian regulation, revenues from generation are based mainly on assured energy of each facility, rather than its installed capacity or actual output.  Assured energy is a fixed output of electricity established by the Brazilian government in the relevant concession agreement.  For certain companies, actual output is determined periodically by the ONS in view of demand and hydrological conditions.  Provided generators have sold their electricity and participate in the Energy Reallocation Mechanism, Mecanismo de Realocação de Energia (“MRE”), they will receive at least the revenue amount corresponding to the assured energy, even if they do not actually generate all of it.  Conversely, if a generating facility’s output exceeds its assured energy, its incremental revenue is equal only to the costs associated therewith.  Most of our hydroelectric plants are members of the MRE, which mitigates hydrologic risks.

At December 31, 2010, CPFL Geração owned a 51.54% interest in the assured energy from the Serra da Mesa power plant.  Through our generation subsidiaries CERAN, BAESA, ENERCAN and Chapecoense, CPFL Geração also owned interests in the Monte Claro, Barra Grande, Campos Novos, Castro Alves, 14 de Julho and Foz do Chapecó plants, which have been operational since December 2004, November 2005, February 2007, March 2008, December 2008 and October 2010, respectively.  Through CPFL Jaguariúna, we owned a 6.93% interest in the Luis Eduardo Magalhães power plant.  We also operated 34 small hydroelectric power plants and three thermoelectric power plants, two of which were acquired in 2009 (Termonordeste and Termoparaíba) through the acquisition of EPASA.  Termonordeste started operations on December 24, 2010 and Termoparaíba, on January 13, 2011.  On August 27, 2010, our first sugarcane bagasse-powered plant started operations, through CPFL Bioenergia (Baldin energy generation plant).

Our total installed capacity from all of these facilities was 2,309 MW as of December 31, 2010.  We produce electricity almost exclusively through our hydroelectric plants.  We generated 9,142 GWh in 2010, 5,984 GWh in 2009 and 6,659 GWh in 2008.  We are also currently involved in the construction of CPFL Bio Formosa, CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra co‑generation plants, in the construction of the Santa Clara and Campo dos Ventos wind farms.  We expect to refurbish two small hydroelectric power plants in the state of Rio Grande do Sul in 2013.  Upon completion of these facilities, we expect to have a total installed capacity of 2,949 MW by the end of 2013.

The following table sets forth certain information relating to our principal facilities in operation as of April 30, 2011:

 

Installed capacity

Assured energy

Placed in service

Facility upgraded

Concession expires

 

 

 

 

 

 

 

(MW)

(GWh/year)

 

 

 

Hydroelectric plants:

 

 

 

 

 

Serra da Mesa............................................................

1,275.0

5,878.0

1998

 

(1)

Our share of Serra da Mesa (51.54%)...................

657.1

3,029.5

 

 

 

Monte Claro..............................................................

130.0

516.8

2004

 

2036

Our share of Monte Claro (65%)..........................

84.5

335.9

 

 

 

Barra Grande.............................................................

690.0

3,334.1

2005

 

2036

Our share of Barra Grande (25.01%)....................

172.5

833.7

 

 

 

Campos Novos..........................................................

880.0

3,310.4

2007

 

2035

Our share of Campos Novos (48.72%).................

428.8

1,612.9

 

 

 

Castro Alves..............................................................

130.0

560.6

2008

 

2036

Our share of Castro Alves (65%)..........................

84.5

364.4

 

 

 

14 de Julho................................................................

100.0

438.0

2008

 

2036

Our share of 14 de Julho (65%)............................

65.0

284.7

 

 

 

Luis Eduardo Magalhães...........................................

902.5

4,613.0

2001

 

2032

Our share of Luis Eduardo Magalhães (6.93%)....

62.5

319.7

 

 

 

Foz do Chapecó.........................................................

855.0

3,784.3

2010

 

2036

Our share of Foz do Chapecó (51%).....................

436.1

1,930.0

 

 

 

Subtotal (our share only).......................................  

1,991.1

8,710.8

 

 

 

 

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Small hydroelectric power plant

Installed capacity

Assured energy

Placed in service

Facility upgraded

Concession expires

 

(MW)

(GWh/year)

 

 

 

Americana

30.0

78.8

1949

2002

2027

Andorinhas

0.5

4.0

1937

(2)

(4)

Buritis

0.8

7.9

1922

2027

 

Capão Preto

4.3

20.0

1911

2008

2027

Cariobinha

1.3

0

1936

(3)

2027

Chibarro

2.6

14.8

1912

2008

2027

Dourados

10.8

68.0

1926

2002

2027

Eloy Chaves

19.0

106.9

1954

1993

2027

Esmeril

5.0

25.2

1912

2003

2027

Gavião Peixoto

4.8

33.5

1913

2007

2027

Guaporé

0.7

5.4

1950

(2)

(4)

Jaguari

11.8

78.8

1917

2002

2027

Lençóis

1.7

14.7

1917

1988

2027

Monjolinho

0.6

2.7

1893

2003

2027

Pinhal

6.8

32.4

1928

1993

2027

Pirapó

0.7

5.6

1952

(4)

 

Saltinho

0.8

6.4

1950

(4)

 

Salto do Pinhal

0.6

0

1911

(3)

2027

Salto Grande

4.6

23.8

1912

2003

2027

Santana

4.3

25.4

1951

2002

2027

São Joaquim

8.1

49.3

1911

2002

2027

Socorro

1.0

5.3

1909

1994

2027

Três Saltos

0.6

5.3

1928

2027

 

Ponte do Silva

0.1

0

1956

(4)

 

Lavrinha

0.3

(5)

1947

(4)

 

Macaco Branco

2.4

(5)

1911

2015

 

Pinheirinho

0.6

(5)

1911

(4)

 

Rio do Peixe I

3.1

(5)

1925

2015

 

Rio do Peixe II

15.0

(5)

1998

2015

 

Santa Alice

0.6

(5)

1907

(4)

 

São José

0.8

(5)

1934

(4)

 

São Sebastião

0.7

(5)

1925

(4)

 

Turvinho

0.8

(5)

1912

(4)

 

Diamante

4.2

15.5

 

 

 

Sub total

150.0

629.8

 

 

 

Thermoelectric power plants:

 

 

 

 

 

Carioba

36.0

93.7

1954

2027

 

EPASA

 

 

 

 

 

Termonordeste

170.8

1,804.5

 

 

 

Our share Termonordeste (51%)

87.1

553.1

 

 

 

Termoparaíba

170.8

1,804.5

 

 

 

Our share Termoparaiba (51%)

87.1

553.1

 

 

 

Baldin

45.0

112.4

 

 

 

Sub total (our share only)

255.2

1,312.3

 

 

 

TOTAL (our share only)

2,396.2

10,652.9

 

 

 

 

   

                                               

(1)           The concession for Serra da Mesa is held by Furnas.  We have a contractual right to 51.54% of the assured energy of this facility, under a 30-year rental agreement, expiring in 2028.

(2)           Power plants that will be upgraded by 2013.

(3)           Power plants that are not active.

(4)           Hydroelectric projects with an installed capacity equal to or less than 1,000 kW that are registered with the regulatory authority and the administrator of power concessions, but do not require concession or authorization processes for operating.

(5)           Power plants that currently do not have assured energy approved by the MME.  The energy that they produce is used by our distribution subsidiaries, reducing our energy purchases.  We have applied for the assignment of a total of 78.6 GWh per year of assured energy for these nine small hydroelectric power plants and are waiting for MME and ANEEL approval.

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Serra da Mesa.  Our largest hydroelectric facility in operation is the Serra da Mesa facility, which we acquired in 2001 from VBC, one of our controlling shareholders.  Furnas began construction of the Serra da Mesa facility in 1985.  In 1994, construction was suspended due to a lack of resources, which led to a public bidding procedure in order to resume construction.  Serra da Mesa currently consists of three hydroelectric facilities located on the Tocantins River in the state of Goiás.  The Serra da Mesa facility began operations in 1998 and has an installed capacity of 1,275 MW.  The concession for the Serra da Mesa facility is owned by Furnas, which is also the operator, and we own part of the facility.  Under Furnas’ rental agreement with us, which has a 30-year term commencing in 1998, we have the right to 51.54% of the assured energy of the Serra da Mesa facility until 2028, irrespective of the actual electricity produced by the facility, even if, during the term of the concession, there is an expropriation or forfeiture of the concession or the term of the concession expires.  We sell all of such electricity to Furnas under an electricity purchase contract that expires in 2014 at a price that is adjusted annually based on the IGP-M.  After the expiration of this electricity purchase arrangement with Furnas, we will retain, until 2028, the right to 51.54% of the assured energy of Serra da Mesa.  We will be allowed to commercialize it in accordance with regulations applicable at such time.  Our share of the installed capacity and assured energy of the Serra da Mesa facility is 657 MW and 3,030 GWh/year, respectively.  On May 5, 2008, Furnas requested the renewal of the plant concession term for an additional 29 years.  On February 15, 2011, ANEEL forwarded Furna’s request to MME, which approval is still pending.

CERAN Complex.  We own a 65.0% interest in CERAN, a joint venture that was granted a 35-year concession in March 2001 to construct, finance and operate the CERAN hydroelectric complex.  The other shareholders are CEEE (30.0%) and Desenvix (5.0%).  The CERAN hydroelectric complex consists of three hydroelectric plants:  Monte Claro, Castro Alves and 14 de Julho.  The complex is located on the Antas River approximately 120 km north of Porto Alegre, near the city of Bento Gonçalves, in the state of Rio Grande do Sul.  The entire CERAN Complex has an installed capacity of 360 MW and estimated assured energy of 1,515.5 GWh per year, of which our share will be 985.1 GWh/year.  We sell our participation in the assured energy of this complex to affiliates in our group.  These facilities are operated by CERAN, under CPFL Geração’s supervision.

Monte Claro (CERAN Complex).  In 2004, Monte Claro’s first generator became operational, with an installed capacity of 65 MW and assured energy of 509.8 GWh a year, and in 2006, the second generator became operational, with an installed capacity of 65 MW and assured energy of 7.0 GWh per year.  The plant has a total of 130 MW in installed capacity and 516.8 GWh in assured energy per year.

Castro Alves (CERAN Complex).  In March 2008, the first generation unit of the Castro Alves plant became operational, with an installed capacity of 43.4 MW and annual assured energy of 353.0 GWh.  In April 2008, the second generation unit became operational, with an installed capacity of 43.4 MW and annual assured energy of 207.6 GWh.  This plant became fully operational in June 2008, with a total installed capacity of 130 MW and annual assured energy of 560.6 GWh. Castro Alves added 84.5 MW to our capacity and an annual assured energy of 364.4 GWh.

14 de Julho (CERAN Complex).  The first generation unit of the 14 de Julho plant became operational in December, 2008, and the second generation unit became fully operational in March, 2009.  This plant has a total installed capacity of 100 MW and an annual assured energy of 438.0 GWh. 14 de Julho added 65 MW to our capacity and an annual assured energy of 284.7 GWh.

Barra Grande.  This facility became fully operational on May 1, 2006 with a total installed capacity of 690 MW and total assured energy of 3,334.1 GWh per year.  CPFL Geração owns a 25.01% interest in this plant.  The other shareholders of the joint venture are Alcoa (42.18%), CBA (Companhia Brasileira de Alumínio) (15.00%), DME (Departamento Municipal de Eletricidade de Poços de Caldas) (8.82%), and Camargo Corrêa Cimentos S.A. (9.00%).  We sell our participation in the assured energy of this facility to affiliates in our group.

Campos Novos.  We own a 48.72% interest in ENERCAN, a joint venture formed by a consortium of private and public sector companies that was granted a 35-year concession in May 2000 to construct, finance and operate the Campos Novos hydroelectric facility.  The plant was constructed on the Canoas River in the state of Santa Catarina, and became fully operational on May 1, 2007 with a total installed capacity of 880 MW and assured energy of 3,310.4 GWh per year, of which our interest is 1,612.9 GWh per year.  The other shareholders of ENERCAN are CBA (24.73%), Votorantim Metais Níqueis S.A. (20.04%) and CEEE (6.51%).  The plant is operated by ENERCAN under CPFL Geração’s supervision.  This plant increased our installed capacity by 428.8 MW.  We sell our participation in the assured energy of this joint venture to affiliates in our group.

29


 

Foz do Chapecó.  We own a 51.0% interest in Chapecoense, a joint venture formed by a consortium of private and public sector companies that was granted a 35-year concession in November 2001 to construct, finance and operate the Foz do Chapecó hydroelectric facility.  The remaining 49.0% interest in the joint venture is divided among Furnas, which holds a 40% interest, and CEEE, which holds a 9.0% interest.  The Foz do Chapecó hydroelectric plant is located on the Uruguay River, on the border between the states of Santa Catarina and Rio Grande do Sul.  The first generating unit started commercial operations on October 14, 2010, the second one on November 23, 2010, the third one on December 30, 2010 and the fourth one on March 12, 2011.  The Foz do Chapecó hydroelectric plant has added 436.1 MW to our installed capacity.  Of our 51% share in the assured energy of this project, we sell 40% to affiliates in our group and 11% through CCEARs.

Luis Eduardo Magalhães Power Plant.  We own a 6.93% interest in the Luis Eduardo Magalhães power plant, also known as UHE Lajeado.  The plant is located on the Tocantins river in the state of Tocantins, and became fully operational in November, 2002 with a total installed capacity of 902.5 MW and assured energy of 4,613 GWh per year.  The plant was built by Investco S.A., a consortium comprised of Lajeado Energia, EDP (Energias de Portugal), CEB (Companhia Energética de Brasília) and Paulista Lajeado (which we acquired in 2007).  We sell our participation in the assured energy of this plant to affiliates in our group.

Small Hydroelectric Power Plants.  We operate 34 small hydroelectric power plants.  Since 1988, we have been investing in their renovation and automation to increase their output.  The program principally involves the replacement of existing turbines and upgrade of peripheral equipment and automated systems, as well as restoring infrastructure.  Through these initiatives, we hope to increase these plants’ assured energy and electricity production and reduce operational costs.

The automation of these power plants allows us to carry out control, supervision and operations remotely.  We have established an operational center for the management and monitoring of our power plants in Campinas, making it possible for the entire production cycle of the power plants to be remotely controlled in real time.

The costs of operation and maintenance of CPFL Geração’s plants decreased from R$26.47/MWh in 1997 to R$13.93/MWh in 2010.  The rate of availability of our power generation equipment increased from 82.0% in 1997 to 90.7% in 2010.  Through 2013 we expect to begin projects to refurbish two power plants:  Andorinhas and Guaporé.

In 2004, modernization projects were presented for Gavião Peixoto, Chibarro and Capão Preto.  The Gavião Peixoto project was approved by ANEEL in July of 2004 and the new assured energy level was approved by the Ministry of Mines and Energy, Ministério de Minas e Energia (“MME”) in June 2005, increasing from 19.3 GWh per year to 33.5 GWh per year.  Work on this project began in August 2005.  The first generator began commercial operations in June 2007 and renovation projects were completed in July 2007.  The renovation projects at the Capão Preto and Chibarro plants were approved by ANEEL in August and September 2005, respectively.  The MME approved an increase in assured energy at Capão Preto from 8.7 GWh per year to 19.9 GWh per year, and at Chibarro from 6.1 GWh per year to 14.8 GWh per year.  The modernization and renovation of these plants began in October 2006.  Chibarro and Capão Preto were completed in February 2008.

CPFL Bioenergia.  In partnership with Baldin Bioenergia, we have constructed a co-generation plant in the city of Pirassununga, in the state of São Paulo.  The total cost of the thermoelectric power plant was R$104 million, of which we were responsible for R$52 million.  The construction began in October 2008 and commercial operations started on August 27, 2010.  This co-generation plant has added 45.0 MW to our installed capacity.  All of this electricity has been sold to CPFL Brasil.

Thermoelectric Power Plants.  We operate three thermoelectric power plants.  The Carioba facility has an installed capacity of 36 MW and was constructed in 1954.  As of 2002, the Carioba facility was operating with 100% fuel‑subsidized oil.  Beginning in 2003, this subsidy was gradually reduced and contracted electricity was simultaneously decreased by 25.0% per year.  By the end of 2006, the subsidy was phased out entirely and, as a result, all assured energy at Carioba is now available to be contracted pursuant to PPAs.  Termonordeste and Termoparaíba are powered by fuel oil from the EPASA complex, with total installed capacity of 342 MW and assured energy of 2,169.0 GWh.  We own an aggregate 51.0% interest in Termonordeste and Termoparaíba.  The Termonordeste and Termoparaíba thermoelectric power plants are located in the city of João Pessoa, in the state of Paraíba.  The total cost of construction was R$627 million, of which we were responsible for R$320 million.  The construction of these plants began in October 2009.  Termonordeste started commercial operations on December 24, 2010, and Termoparaíba on January 13, 2011.  The electricity of these power plants was sold in CCEARs, and part of this energy was bought by our own distributors.

30


 
Expansion of Installed Capacity

Demand for electricity in our distribution concession areas continues to grow.  To address this increase in demand, and to improve our margins, we are expanding our installed capacity.  We are building the CPFL Bio Formosa, CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra co-generation plants and Santa Clara and Campo dos Ventos wind farms, which together will have an installed capacity of 553 MW.  By the end of 2013, we expect that the total generating capacity from these facilities will become fully operational.

The following table sets forth information regarding our current hydroelectric generation projects as of April 30, 2011:

 

Estimated Installed
Capacity

Estimated Assured
Energy

Estimated Construction Cost

Start of Construction

Expected Start of Operations

Our
Ownership

Estimated Installed
Capacity Available

Estimated Assured
Energy
Available to us

 

(MW)

(GWh/yr)

(R$ million)

 

 

(%)

 

(GWh/yr)

CPFL Bio Formosa

40

140.2

127

March 2010

2011

100.0

40

140.2

CPFL Bio Buriti

50

184.1

135

September 2010

2011

100.0

50

184.1

CPFL Bio Ipê

25

71.7

26

July 2010

2011

100.0

25

71.7

CPFL Bio Pedra

70

213.9

205

October 2010

2012

100.0

70

213.9

Santa Clara wind farms

188

665.8

801

August 2010

2012

100.0

188

665.8

Campo dos Ventos II wind farm

30

122.6

127

Second quarter 2011

2013

100.0

30

122.6

Campo dos Ventos I, III, IV, V and Eurus V wind farms

150

543.1

600

Awaiting approval from ANEEL

2013

100.0

150

543.1

Total

553

1,941.4

2,021

 

 

 

553

1,941.4

 

Project CPFL Bio Formosa.  In 2009, CPFL Brasil established the Baia Formosa power plant (CPFL Bio Formosa), with an installed capacity of 40 MW.  The construction of CPFL Bio Formosa plant began in March 2010 and the plant is expected to begin operations in the third quarter of 2011.  The total estimated cost of construction is R$127 million.  In 2006, our consulting group helped the Farias Group to sell approximately 11 MW in the A-5 auction (an auction held five years before the initial delivery date, see “Auctions on the Regulated Market”).  The success of the auction helped CPFL Brasil to establish Usina Baia Formosa (currently CPFL Bio Formosa) in 2009.

Project CPFL Bio Buriti, CPFL Bio Ipe and CPFL Bio Pedra.  In addition, on March 23, 2010, our subsidiaries CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra (which we formed to develop electric energy generation projects using sugar cane bagasse) executed a partnership agreement with Grupo Pedra Agroindustrial to develop three new biomass generation projects.  The aggregate potential installed capacity of these three projects is 145 MW and the investment is approximately R$366 million.  Operations are scheduled to start between June 2011 and April 2012.

Project Santa Clara Wind Farms.  During 2009, CPFL Geração developed and planned a number of wind power generation projects and, in September 2009, acquired a complex of additional wind farms.  The Santa Clara wind farms I, II, III, IV, V, VI and Eurus VI will have installed capacity of 188 MW and assured energy of 666 GWh.  The construction of the wind farm has already started and operations are scheduled to start in the third

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quarter of 2012.  The total estimated cost of construction is R$801 million.  The electricity from this wind farm has been sold through an auction, through CCEARs.

 

Project Campo dos Ventos Wind Farms.  In 2010, CPFL Geração acquired Campo dos Ventos I, II, III, IV, V and Eurus V wind farms.  Our project for construction of Campo dos Ventos II in the city of João Câmara and Parazinho, in the state of Rio Grande do Norte, is in progress.  We have also started the process of obtaining the respective licenses.  Operations of Campo dos Ventos II are scheduled to start in the third quarter of 2013.  The total estimated cost of construction is R$127 million.  This wind farm will have installed capacity of 30 MW and assured energy of 123 GWh.  The electricity from Campo dos Ventos II was sold through an auction, through CCEARs.  Construction of Campo dos Ventos I, III, IV, V and Eurus V wind farms is waiting for ANEEL’s authorization and operations are scheduled to start in the third quarter of 2013.  The total estimated cost of construction of these five wind farms is R$600 million.  They will have installed capacity of 150 MW and assured energy of 543.1 GWh.  We plan to sell the electricity from Campo dos Ventos I, III, IV, V and Eurus V wind farms in the next ANEEL auction, though CCEARs or in the free market.

Electricity Commercialization and Services

Commercialization Operations

Our subsidiary CPFL Brasil carries out our electricity commercialization operations.  Its key functions are:

·         procuring electricity for commercialization activities by entering into bilateral contracts with energy companies (including our generation subsidiaries and third parties) and purchasing electricity in public auctions;

·         reselling electricity to Free Consumers;

·         reselling electricity to distribution companies (including CPFL Paulista, CPFL Piratininga and RGE) and other agents in the electricity market through bilateral contracts; and

·         providing electricity-related services and consulting to Final Consumers and other agents.

The rates at which CPFL Brasil purchases and sells electricity in the free market are determined by bilateral negotiations with its suppliers and consumers.  The contracts with distribution companies are regulated by ANEEL.  In addition to marketing electricity to unaffiliated parties, CPFL Brasil resells electricity to CPFL Paulista, CPFL Piratininga and RGE, but profit margins from sales to related parties have been limited to an average of 10.0% by ANEEL regulations.  Prior to the New Industry Model Law, distribution companies were permitted to purchase up to 30.0% of their electricity requirements from affiliated companies.  The ability to sell electricity to affiliated companies has been eliminated under the New Industry Model Law, with the exception of those contracts approved by ANEEL prior to March 2004.  However, we are allowed to sell electricity to distributors through the open bidding process in the regulated market.

Electricity-Related Services

We offer our consumers a wide range of electricity-related services through CPFL Brasil.  These services are designed to help consumers improve the efficiency, cost and reliability of the electric equipment they use.  Our main electricity-related services include:

·         Electric energy management consultancy:  Our consulting and electrical power management services assist consumers in migrating to the free market.  CPFL Brasil’s contract management consulting services seek to support consumers’ decision-making with respect to electrical power and to strengthen our relation with consumers in the negotiation of price and electricity services;

·         Project design and construction:  CPFL Brasil plans, constructs, commissions and provides electricity to substations, transmission lines, transformer stations, load centers and electrical energy distribution lines, always in line with each consumer’s needs and growth expectations and in accordance with the most rigorous safety criteria, aiming for an optimal use of resources;

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·         Management of assets:  In the maintenance arena, CPFL Brasil develops solutions that contribute to the optimal operation of electro-energetic installations for companies of all sizes, ensuring that interruptions to the electrical energy supply, and resulting business losses, are minimized;

·         Energy efficiency:  CPFL Brasil aims to guide and assist its consumers’ businesses with the most energy efficient solutions, leading to reduced energy costs and allowing for greater investments in core business pursuits; and

·         Co-generation:  Energy co-generation is the simultaneous and sequential production of energy from two or more kinds of fuel.  The most common form of co-generation in Brazil is the production of electrical energy from natural gas and/or biomass.  CPFL Brasil offers feasibility studies, project design and installation of co-generation operation systems for companies for which co-generation is an appropriate solution.

Competition

We face competition from other generation and commercialization companies in the sale of electricity to Free Consumers.  Distribution and transmission companies are required to permit the use of their lines and ancillary facilities for the distribution and transmission of electricity by other parties upon payment of a tariff.

Brazilian law provides that all of our concessions can be renewed once with approval from the MME or ANEEL as the granting authority, provided that the concessionaire so requests and that certain requirements related to the rendering of public services are met.  We intend to apply for the extension of each concession upon its expiration.  We may face significant competition from third parties in bidding for renewal of such concessions or for any new concessions.  ANEEL has absolute discretion over whether to renew existing concessions, and the acquisition of certain concessions by competing investors could adversely affect our results of operations.

Our Concessions and Authorizations

Hydroelectric generation projects with a capacity greater than 1,000 kW operated by an independent producer can usually only be implemented through concessions granted by ANEEL through public biddings (and the execution of a concession agreement).  Requests to renew these concessions are examined by ANEEL on a case‑by‑case basis, according to the terms of the related agreement and public bidding note.  However, ANEEL retains the power to deny the request to extend the concession period.

Certain projects such as wind farms, small scale hydroelectric power plants and thermoelectric power plants are implemented through an authorization awarded by the granting authority without the need for a public bidding process (unlike concessions).  Renewal of these authorizations is also at the discretion of ANEEL and is decided on a case-by-case basis.  ANEEL must provide justification for its decisions and any renewal must further the public interest.

For further information about concessions and authorizations, see “The Brazilian Power Industry – Concessions.”

Concessions

We operate under concessions granted by the Brazilian government through ANEEL for our generation and distribution businesses.  We have the following concessions with respect to our distribution business:

Concession no.

Concessionaire

State

Term

014/1997

CPFL Paulista

São Paulo

30 years from November 1997

09/2002

CPFL Piratininga

São Paulo

30 years from October 1998

013/1997

RGE

Rio Grande do Sul

30 years from November 1997

021/1999

CPFL Santa Cruz

São Paulo and Paraná

16 years (from February 1999 to July 2015)

015/1999

CPFL Jaguari

São Paulo

16 years (from February 1999 to July 2015)

017/1999

CPFL Mococa

São Paulo and Minas Gerais

16 years (from February 1999 to July 2015)

018/1999

CPFL Leste Paulista

São Paulo

16 years (from February 1999 to July 2015)

019/1999

CPFL Sul Paulista

São Paulo

16 years (from February 1999 to July 2015)

 

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The table below summarizes the concessions relative to our generation business.  In addition to these concessions, CPFL Sul Centrais, as an Independent Producer with generating capacity of less than 1,000 kW, operates under a regulatory authorization rather than a concession agreement.

Concession no.

Independent Producers

Plant

State

Term

Maximum renewal period

128/2001

Foz do Chapecó

Foz do Chapecó

Santa Catarina and Rio Grande do Sul

35 years from November 2001

At the discretion of ANEEL

036/2001

Barra Grande

Barra Grande

Rio Grande do Sul

35 years from May 2001

At the discretion of ANEEL

008/2001

CERAN

14 de Julho,

Castro Alves and Monte Claro

Rio Grande do Sul

35 years from March 2001

At the discretion of ANEEL

043/2000

ENERCAN

Campos Novos

Santa Catarina

35 years from May 2000

At the discretion of ANEEL

005/1997

Investco

Luiz Eduardo Magalhães
Our 19 small hydroelectric power plants and one thermoelectric facility

Tocantins

35 years from December 1997

At the discretion of ANEEL

015/1997

CPFL Geração

 

São Paulo

30 years from November 1997

30 years

Decree No. 85,983/81

CPFL Geração

Serra da Mesa

Goiás

(1)

20 years

09/1999

CPFL Jaguari

Macaco Branco

(small hydroelectric

power plant)

São Paulo

16 years (from

February 1999 to

July 2015)

20 years

10/1999

CPFL Leste

Paulista

Rio do Peixe I and

II (small hydroelectric

power plant)

São Paulo

16 years (from

February 1999 to

July 2015)

20 years

                                                           

(1)           We have the contractual right to 51.54% of the assured energy of this facility under a 30-year rental agreement, expiring in 2028.  The concession for Serra da Mesa is held by Furnas and expired on May 7, 2040 (subject to MME approval).  On May 5, 2008, Furnas requested renewal of the concession for Serra da Mesa plant for an additional term of 29 years.  On February 15, 2011, ANEEL forwarded Furna’s request to MME, which approval is still pending.

Authorizations

Authorization no.

Independent Producers

Plant

State

Term

Maximum  renewal period

2106/2009

CPFL Bioenergia S.A.

Baldin thermoelectric

power plan

São Paulo

30 years
from
September 24, 2009

-

2277/2010

Centrais Elétricas da

Paraíba S.A. - EPASA

Termoparaíba

thermoelectric power

plant

Paraíba

35 years
from
December 7, 2007

At the discretion
of MME

2277/2010

Centrais Elétricas da

Paraíba S.A. - EPASA

Termonordeste

thermoelectric power

plant

Paraíba

35 years
from
December 12, 2007

At the discretion
of MME

259/2002

CPFL Bio

Formosa S.A.

Baía Formosa

thermoelectric

power plant

Rio Grande do

Norte

30 years
from
May 15, 2002

At the discretion
of ANEEL

2643/2010

CPFL Bio Buriti

Buriti thermoelectric

power plant

São Paulo

30 years
from
December 7, 2010

At the discretion
of ANEEL

2375/2010

CPFL Bio Ipê

Ipê thermoelectric power plant

São Paulo

30 years
from 
May 3, 2010

At the discretion
of ANEEL

129/2010

CPFL Bio Pedra

Pedra thermoelectric

power plant

São Paulo

35 years
from February 28, 2010

At the discretion
of ANEEL

609/2010

Santa Clara I

Energias

Renováveis

Santa Clara I

Rio Grande do Norte

35 years
from July 1, 2010

At the discretion
of ANEEL

683/2010

Santa Clara II
Energias
Renováveis

Santa Clara II

Rio Grande do Norte

35 years
from August 4, 2010

At the discretion
of ANEEL

610/2010

Santa Clara III

Energias

Renováveis

Santa Clara III

Rio Grande do Norte

35 years

from July 1, 2010

At the discretion

of ANEEL

672/2010

Santa Clara IV

Energias

Renováveis

Santa Clara IV

Rio Grande do Norte

35 years


from July 29, 2010

At the discretion

of ANEEL

838/2010

Santa Clara V

Energias

Renováveis

Santa Clara V

Rio Grande do Norte

35 years

from October 8, 2010

At the discretion

of ANEEL

670/2010

Santa Clara VI

Energias

Renováveis

Santa Clara VI

Rio Grande do Norte

35 years

from July 29, 2010

At the discretion

of ANEEL

749/2010

Eurus VI Energias

Renováveis

Eurus VI

Rio Grande do Norte

35 years
from August 24, 2010

At the discretion

of ANEEL

 

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Independent Producers

A generation company classified as an independent producer under Brazilian law receives a concession or authorization to produce energy for its own consumption or for sale to local distribution companies, Free Consumers, and other types of consumers.  The price to be charged by Independent Producers for the sale of energy to certain types of consumer is subject to general criteria established by ANEEL, whereas the sale price to others can be freely negotiated between the parties.

 

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Concessionaires

A generation company classified as a concessionaire under Brazilian law receives a concession to distribute, transmit or generate electric energy.  Since concessions involve public services, they can only be granted through a public bidding procedure (licitação pública).  All tariffs charged by concessionaires are determined by ANEEL and concessionaires are not free to negotiate these rates with consumers.

The concession agreement and related documents establish the concession period and whether the related concession can be extended.  For concessions to generate electric energy, the amortization period for the related investment is 35 years, renewable once for a maximum period of 20 years.

Although concession agreements and applicable laws generally allow for the extension of the concession period, such extension is not a right.  The decision to extend a concession agreement is subject to the discretion of the granting authority, which must provide justification for its decision, and the decision must further the public interest.

Properties

Our principal properties consist of hydroelectric generation plants.  Due to the adoption of IFRS, we have reclassified our distribution companies’ fixed assets, comprised mainly of substations and distribution networks, partially as intangible assets and partially as financial assets of concession.  See note 5 to our audited consolidated financial statements for details on our transition to IFRS.  The net book value of our total property, plant and equipment as of December 31, 2010 was R$5,786 million.  No single one of our properties produces more than 10.0% of our total revenues.  Our facilities are generally adequate for our present needs and suitable for their intended purposes.

Pursuant to Brazilian law, the essential properties and facilities that we use in performing our obligations under our concession agreements cannot be transferred, assigned, pledged or sold to, or encumbered by, any of our creditors without prior approval from ANEEL.

Environmental

The Brazilian constitution gives both the Brazilian Federal and State Governments the power to enact laws designed to protect the environment.  A similar power is given to municipalities whose local interests may be affected.  Municipal laws are considered to be a supplement to federal and state laws.  A violator of applicable environmental laws may be subject to administrative and criminal sanctions, and will have an obligation to remediate and/or provide compensation for environmental damages.  Administrative sanctions may include substantial fines and suspension of activities, while criminal sanctions may include fines and, for individuals (including executive officers and employees of companies who commit environmental crimes), imprisonment.

Our energy distribution and generation facilities are subject to environmental licensing procedures, which include the preparation of environmental impact assessments before such facilities are constructed.  Once the respective environmental licenses are obtained, the holder of the license remains subject to compliance with specific requirements.

The environmental issues regarding the construction of new electricity generation facilities require specially-tailored oversight.  For this reason, CPFL Geração manages these matters in order to ensure that its policies and environmental obligations are given adequate consideration.  Decisions are made by environmental committees, whose members include representatives of each project partner and of each plant’s environmental management office.  Our environmental committees are constantly interacting with government agencies to assure environmental compliance and future electricity generation.  For example, in securing the operating license for Foz do Chapecó from IBAMA in August 2010, the project managers had a productive dialogue with representatives from the Federal Government which led to increases in the levels of both electricity generation and environmental protection.  In addition, we support local community programs that relocate rural families in collective resettlements and provide institutional support for families involved in the conservation of local biodiversity.

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In order to facilitate compliance with environmental laws, we use an environmental management system compliant with ISO 14001 that has been implemented in all of our segments.  We have established a system to identify, evaluate and update matters relating to applicable environmental laws, as well as other requirements applicable to our environmental management system.  Our generation and distribution of electricity is subject to internal and external audits that verify whether our activities are in compliance with ISO 14001.  Our environmental management processes take into consideration our budgets and realistic forecasts, and always aim to achieve improvements at the financial, social and environmental levels.

The Brazilian Power Industry

In 2010, the MME approved a ten-year expansion plan under which Brazil’s installed power generation capacity is projected to increase to 167.1 GW by 2019, of which 116.7 GW (69.8%) is projected to be hydroelectric, 28.9 GW (17.3%) is projected to be thermoelectric and nuclear and 21.5 GW (12.9%) is projected to be from renewable sources.

In 2010, Eletrobrás owned 37% of Brazilian generation assets.  Through its subsidiaries, Eletrobrás is also responsible for 56% of Brazil’s installed transmission capacity.  In addition, it holds interests in certain Brazilian state-controlled entities involved in the generation, transmission and distribution of electricity.  They include, among others, Companhia Hidroelétrica do São Francisco — CHESF and Furnas Centrais Elétricas.

In 2010, private companies represented 45% of the markets for generation activities, in terms of total capacity and demand, and 27.5% of the transmission market in terms of revenue. 

Principal Regulatory Authorities

Ministry of Mines and Energy — MME

The MME is the Brazilian government’s primary regulator the power industry.  Following the adoption of the New Industry Model Law, the Brazilian government, acting primarily through the MME, has assumed certain duties that were previously the responsibility of ANEEL, including drafting guidelines for the granting of concessions and issuing directives governing the bidding process for concessions that relate to public services and public assets.

National Energy Policy Council — CNPE

The National Energy Policy Council, Conselho Nacional de Política Energética (“CNPE”), a committee created in August 1997, advises the President of Brazil on the development of national energy policy.  The CNPE is chaired by the Minister of Mines and Energy and consists of six government ministers and three members selected by the President of Brazil.  The CNPE was created to optimize the use of Brazil’s energy resources and to guarantee national energy supply.

ANEEL is an independent federal regulatory agency whose primary responsibility is to regulate and supervise the power industry in accordance with policies set forth by the MME, together with other matters delegated to it by the Brazilian government and the MME.  ANEEL’s current responsibilities include, among others, (i) administering concessions for electric energy generation, transmission and distribution, including the approval of electricity tariffs, (ii) enacting regulations for the electric energy industry, (iii) implementing and regulating the exploitation of energy sources, including the use of hydroelectric power, (iv) promoting the public bidding process for new concessions, (v) settling administrative disputes among electricity generation entities and electricity purchasers and (vi) defining the criteria and methodology for the determination of transmission tariffs.

National Electrical System Operator — ONS

The ONS is a non‑profit organization that coordinates and controls electric utilities engaged in the generation, transmission and distribution of electric energy, and private market participants such as importers, exporters, and Free Consumers.  The primary role of the ONS is to oversee generation and transmission operations in the Interconnected Power System, or SIN; subject to regulation and supervision by ANEEL.  The ONS’ objectives and principal responsibilities include:  operational planning for the generation industry, organizing the use of the domestic Interconnected Power System and international interconnections, guaranteeing that all parties in the industry have access to the transmission network in a non‑discriminatory manner, assisting in the expansion of the electric energy system, proposing plans to the MME for extensions of the Basic Grid, and submitting rules for the operation of the transmission system for ANEEL’s approval.

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Electric Energy Trading Chamber — CCEE

The Electric Energy Trading Chamber, Câmara de Comercialização de Energia Elétrica (“CCEE”), is a nonprofit organization that is subject to authorization, inspection and regulation by ANEEL.  The CCEE replaced the Wholesale Energy Market, or MAE.

The CCEE is responsible, among other things, for (i) registering all the energy purchase agreements in the Regulated Market, Contratos de Comercialização de Energia no Ambiente Regulado (“CCEAR”), and registering agreements that result from market adjustments and the volume of electricity contracted in the free market, and (ii) accounting for and clearing of short‑term transactions.  The CCEE consists of holders of concessions and permissions, authorized entities within the electricity industry, and Free and Special Consumers.  Its board of directors is composed of four members appointed by these parties, together with one appointed by the MME.  The MME also acts as chairman of the board of directors.

Energy Research Company — EPE

On August 16, 2004 the Brazilian government created the Energy Research Company, Empresa de Pesquisa Energética (“EPE”), a state-owned company responsible for conducting strategic research on the energy industry, including with respect to electric energy, oil, gas, coal and renewable energy sources.  The research carried out by EPE is used by MME in its policymaking role in the energy industry.

Energy Industry Monitoring Committee — CMSE

The New Industry Model Law created the Energy Industry Monitoring Committee, Comitê de Monitoramento do Setor Elétrico (“CMSE”), which acts under the direction of the MME.  The CMSE is responsible for monitoring supply conditions within the system and for indicating steps to be taken to correct problems.

Concessions, Permissions and Authorizations

The Brazilian constitution provides that the development, use and sale of electric energy may be undertaken directly by the Brazilian government or indirectly through the granting of concessions, permissions or authorizations.  Historically, the Brazilian electric energy industry has been dominated by generation, transmission and distribution concessionaires controlled by the Federal or State governments.

Companies or consortia that wish to build or operate facilities for generation, transmission or distribution of electricity in Brazil must apply to the MME or to ANEEL, as representatives of the Brazilian government, for a concession, permission or authorization, as the case may be.

Concessions

Concessions grant rights to generate, transmit or distribute electricity in the relevant concession area for a specified period (as opposed to permissions and authorizations, which may be revoked at any time at the discretion of the MME, in consultation with ANEEL).  This period is usually 35 years for new generation concessions, and 30 years for new transmission or distribution concessions.  An existing concession may be renewed at the granting authority’s discretion.

The Concession Law establishes, among other things, the conditions that the concessionaire must comply with when providing electricity services, the rights of consumers, and the obligations of the concessionaire and the granting authority.  Furthermore, the concessionaire must comply with regulations governing the electricity sector.  The main provisions of the Concession Law are summarized below:

Adequate service.  The concessionaire must render adequate service equally with respect to regularity, continuity, efficiency, safety and accessibility.

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Use of land.  The concessionaire may use public land or request the granting authority to expropriate necessary private land for the benefit of the concessionaire.  In such case, the concessionaire shall compensate the affected private landowners.

Strict liability.  The concessionaire is strictly liable for all damages arising from the provision of its services.

Changes in controlling interest.  The granting authority must approve any direct or indirect change in controlling interests in the concessionaire.

Intervention by the granting authority.  The granting authority may intervene in the concession, by means of a presidential decree, to ensure the adequate performance of services, as well as full compliance with applicable contractual and regulatory provisions.  Within 30 days after the date of the decree, the granting authority’s representative is required to commence an administrative proceeding in which the concessionaire is entitled to contest the intervention.  During the term of the administrative proceeding, a person appointed pursuant to the granting authority’s decree becomes responsible for carrying on the concession.  If the administrative proceeding is not completed within 180 days after the date of the decree, the intervention ceases and the concession is returned to the concessionaire.  The concession is also returned to the concessionaire if the granting authority’s representative decides not to terminate the concession and the concession term has not yet expired.

Termination of the concession.  The termination of the concession agreement may be accelerated by means of expropriation and/or forfeiture.  Expropriation is the early termination of a concession for reasons related to the public interest that must be expressly declared by law.  Forfeiture must be declared by the granting authority after ANEEL or the MME has made a final administrative ruling that the concessionaire, among other things, (i) has failed to render adequate service or to comply with applicable law or regulation, (ii) no longer has the technical, financial or economic capacity to provide adequate service, or (iii) has not complied with penalties assessed by the granting authority.  The concessionaire may contest any expropriation or forfeiture in the courts.  The concessionaire is entitled to indemnification for its investments in expropriated assets that have not been fully amortized or depreciated, after deduction of any fines and damages due by the concessionaire.

Expiration.  When the concession expires, all assets, rights and privileges that are materially related to the rendering of the electricity services revert to the Brazilian government.  Following the expiration, the concessionaire is entitled to indemnification for its investments in assets that have not been fully amortized or depreciated as of the expiration.

Penalties.  ANEEL regulations govern the imposition of sanctions against the participants in the electricity sector and classify the appropriate penalties based on the nature and importance of the breach (including warnings, fines and forfeiture).  For each breach, the fines can be up to two per cent of the revenue (net of value-added tax and services tax) of the concessionaire in the 12-month period preceding any assessment notice.  Infractions that may result in fines relate to the failure of the agent to request ANEEL’s approval in the following cases among others:  (i) execution of contracts between related parties in the cases provided by regulation; (ii) sale or assignment of the assets related to services rendered as well as the imposition of any encumbrance (including any security, bond, guarantee, pledge and mortgage) on them or any other assets related to the concession or the revenues of the electricity services; and (iii) changes in controlling interests of the holder of the concession.  In cases of contracts executed between related parties that are submitted for ANEEL’s approval, ANEEL may seek to impose restrictions on the terms and conditions of these contracts and, in extreme circumstances, determine that the contract be rescinded.

Permissions

Permissions has a very limited use within  the  Brazilian electric sector.  Permissions are granted to rural power generation cooperatives, which supply power to their members and occasionally to consumers that are not part of the cooperative, in  areas not regularly  served  by  large  distributors.  Permissions represent an irrelevant share in the Brazilian power matrix.

 

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Authorizations

Authorizations are unilateral and discretionary acts carried out by the granting authority.  Unlike concessions, authorizations generally do not require a public bidding process.  As an exception to the general rule, authorizations may also be granted to potential power producers after specific bidding processes for the purchase of power conducted by ANEEL.

In the power generation sector, independent power producers (IPPs) and self generators hold an authorization as opposed to a concession.  IPPs and self-generators do not receive public service concessions or permits to render public services.  Rather, they are granted authorizations or specific concessions to explore water resources that merely allow them to produce, use or sell electric energy.  Each authorization granted to an IPP or self-power producer sets forth the rights and duties of the authorized company.  Authorized companies have the right to ask ANEEL to carry out expropriations on their benefit, are subject to ANEEL supervision and are subject to ANEEL’s prior approval in the event of a change in their controlling interests.  Moreover, early unilateral termination of the authorization entitles the authorized company to seek compensation from the granting authority for damages suffered.

An IPP may sell part or all of its output to customers on its own account and at its own and risk.  A self‑generator may, upon specific authorization by ANEEL, sell or trade any exceeding energy it is unable to consume.  IPPs and self‑generators are not granted monopoly rights and are not subject to price controls, with the exception of specific cases.  IPPs compete with public utilities and among themselves for large customers, pools of customers of distribution companies or any customers not served by a public utility.

The New Industry Model Law

Since 1995, the Federal Government has taken a number of measures to reform the Brazilian electric energy industry.  These culminated, on July 30, 2004, in the enactment of the New Industry Model Law, which further restructured the power industry with the ultimate goal of providing consumers with a secure electricity supply at an adequate tariff.

The New Industry Model Law introduced material changes to the regulation of the power industry, with a view to (i) providing incentives to private and public entities to build and maintain generation capacity and (ii) assuring the supply of electricity within Brazil at adequate tariffs through competitive electricity public bidding processes.  The key features of the New Industry Model Law include:

·         Creation of a parallel environment for the trading of electricity, including:  (1) the regulated market, a more stable market in terms of supply of electricity; and (2) a market specifically addressed to certain participants (i.e., Free Consumers and commercialization companies), called the free market, that permits a certain degree of competition.

·         Restrictions on certain activities of distributors, so as to require them to focus on their core business of distribution, to promote more efficient and reliable services to captive consumers.

·         Elimination of self-dealing, in order to provide an incentive to distributors to purchase electricity at the lowest available prices rather then buying electricity from related parties.

·         Maintenance of contracts entered into prior to the New Industry Model Law, in order to provide regulatory stability for transactions carried out before its enactment.

The New Industry Model Law excludes Eletrobrás and its subsidiaries from the National Privatization Program, which is a program originally created by the Brazilian government in 1990 to promote the process of privatization of state-owned companies.

Regulations under the New Industry Model Law include, among other items, rules relating to auction procedures, the form of power purchase agreements and the method of passing costs through to Final Consumers.  Under these regulations, all electricity-purchasing agents must contract all of their electricity demand under the guidelines of the new model.  Electricity-selling agents must provide evidentiary support linking the allotted energy

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to be sold to existing or planned power generation facilities.  Agents that do not comply with such requirements are subject to penalties imposed by ANEEL.

 

Beginning in 2005, all electricity generation, distribution and trading companies, independent power producers and Free and Special Consumers are required to notify the MME, by August 1 of each year, of their estimated electricity demand or estimated electricity generation, as the case may be, for each of the subsequent five years.  Each distribution company is required to notify the MME, within the 60-day period preceding each electricity auction, of the amounts of electricity that it intends to contract in the auction.  Based on this information, the MME must establish the total amount of energy to be contracted in the regulated market and the list of generation projects that will be allowed to participate in the auctions.  Distribution companies will also be required to specify the portion of the contracted amount they intend to use to supply consumers qualified as Free Consumers.

Parallel Environment for the Trading of Electric Energy

Under the New Industry Model Law, electricity purchase and sale transactions are carried out in two different segments:  (i) the regulated market, which contemplates the purchase by distribution companies through public auctions of all electricity necessary to supply their consumers and (ii) the free market, which contemplates the purchase of electricity by non‑regulated entities (such as Free Consumers and energy traders).

Electricity distribution companies fulfill their electricity supply obligations primarily through public auctions.  In addition to these auctions, distribution companies will be able to purchase electricity outside the public bidding process from:  (i) generation companies that are connected directly to such distribution company, except for hydro generation companies with capacity higher than 30 MW and certain thermo generation companies, (ii) electricity generation projects participating in the initial phase of the Proinfa Program, a program designed to diversify Brazil’s energy sources, and (iii) the Itaipu power plant.  The electricity generated by Itaipu continues to be sold by Eletrobrás to the distribution concessionaires operating in the South/Southeast/Midwest Interconnected Power System, although no specific contract was entered into by such concessionaires.  The rates at which the Itaipu-generated electricity is traded are denominated in U.S. dollars and established pursuant to a treaty between Brazil and Paraguay.  As a consequence, Itaipu rates rise or fall in accordance with the variation of the U.S. dollar/real  exchange rate.  Changes in the price of Itaipu-generated electricity are, however, subject to the Parcel A cost recovery mechanism discussed below under “—Distribution Tariffs.”

The Regulated Market

In the regulated market, distribution companies purchase their expected electricity requirements for their captive consumers from generators through public auctions.  The auctions are administered by ANEEL, either directly or indirectly through the CCEE.

Electricity purchases are made through two types of bilateral agreements:  Energy Agreements (Contratos de Quantidade de Energia) and Capacity Agreements (Contratos de Disponibilidade de Energia).  Under an Energy Agreement, a generator commits to supply a certain amount of electricity and assumes the risk that its electricity supply could be adversely affected by hydrological conditions and low reservoir levels, among other conditions, which could interrupt the supply of electricity.  In such cases, the generator would be required to purchase the electricity elsewhere in order to comply with its supply commitments.  Under a Capacity Agreement, a generator commits to make a certain amount of capacity available to the regulated market.  In such case, the generator’s revenue is guaranteed and the distributors must bear the risk of a supply shortage.  Together, these agreements comprise the energy purchase agreements in the Regulated Market, Contratos de Comercialização de Energia no Ambiente Regulado - CCEAR.

According to the New Industry Model Law, electricity distribution entities will be entitled to pass through to their respective consumers all costs related to electricity they purchased through public auction as well as any taxes and industry charges.

With respect to the granting of new concessions, the newly enacted regulations require bids for new hydroelectric generation facilities to include, among other things, the minimum percentage of electricity to be supplied to the regulated market.

 

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The Free Market

The free market covers transactions between generation concessionaires, Independent Power Producers (“IPPs”), self-generators, energy traders, importers of electric energy, Free Consumers and Special Consumers, as defined below.  IPPs are generation entities that sell the totality or part of their electricity to Free Consumers, distribution concessionaires and trading agents, among others.  The free market will also include existing bilateral contracts between generators and distributors until they expire.  Upon expiration, such contracts must be executed under the New Industry Model Law guidelines.

A consumer that is eligible to choose its supplier (a potentially Free Consumer) may only rescind its contract with the local distributor and become a Free Consumer by notifying such distributor at least 15 days before the date such distributor is required to state its estimated electricity needs for the next auction.  Further, such consumer may only begin acquiring electricity from another supplier in the year following the one in which the local distributor was notified.  Once a potentially Free Consumer has opted for the free market, it may only return to the regulated system after giving the distributor of its region five years’ advance notice, provided that the distributor may reduce such notice period at its discretion.  This extended notice period seeks to assure that, if necessary, the distributor is able to buy the additional energy in the regulated market without imposing extra costs on the captive market.

In addition to Free Consumers, certain consumers with capacity equal to or greater than 500 kW may choose to purchase energy in the free market, subject to certain terms and conditions.  These consumers are called “Special Consumers”.  Special Consumers may only purchase energy from (i) small hydroelectric power plants with capacity between 1,000 kW and 30,000 kW, (ii) generators with capacity limited to 1,000 kW, and (iii) alternative energy generators (solar, wind and biomass enterprises) whose capacity supplied to the system does not exceed 30,000 kW.  A Special Consumer may terminate its contract with the local distributor on 180 days’ prior notice for contracts with indefinite terms.  For contracts with a definite term the consumer must fulfill the contract, and or for long‑term contracts the consumer may terminate its contract on three years’ prior notice.  The Special Consumer may return to the regulated system upon 180 days’ prior notice to the distributor of its region.

State-owned generators may sell electricity to Free Consumers; however, unlike private generators, they may only do so through an auction process.

Auctions on the Regulated Market

Electricity auctions for new generation projects in process are held (i) five years before the initial delivery date (referred to as “A-5” auctions) or (ii) three years before the initial delivery date (referred to as “A-3” auctions).  Electricity auctions from existing power generation facilities take place (i) one year before the initial delivery date (referred to as “A-1” auctions) or (ii) approximately four months before the delivery date (referred to as “market adjustments”).  Invitations to bid in the auctions are prepared by ANEEL, in compliance with guidelines established by the MME, which include a requirement to use the lowest bid as the criterion to determine the winner of the auction.

Each generation company that participates in an auction executes a contract for purchase and sale of electricity with each distribution company, in proportion to the distribution companies’ respective estimated demand for electricity.  The only exception to these rules relates to the market adjustment auction, where the contracts are between specific selling and distribution companies.  The CCEAR of both “A-5” and “A-3” auctions have a term of between 15 and 30 years, and the CCEAR of “A-1” auctions have a term between five and 15 years.  Contracts arising from market adjustment auctions are limited to a two-year term.  The total amount of energy contracted in such market adjustment auctions may not exceed 1.0% of the total amount of energy contracted by each distributor, except for the auctions held in 2008 and 2009, for which the total amount of contracted energy may not exceed 5.0%.

With respect to the CCEAR related to electricity generated by existing generation facilities, there are three alternatives for the permanent reduction of contracted electricity:  (i) compensation for the exit of potentially Free Consumers from the regulated market, (ii) a reduction, at the distribution company’s discretion, of up to 4.0% per year in the annual contracted amount due to market deviations from estimated market projections, beginning two

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years after the initial electricity demand was declared and (iii) adjustments to the amount of electricity established in energy acquisition contracts entered into before March 17, 2004.

 

Since 2005, CCEE has conducted eleven auctions for new generation projects, nine auctions for existing power generation facilities, two auctions for alternate generation projects and three auctions for biomass and wind power generation, qualified as “reserve energy.”  No later than August 1st of each year, generators and distributors must provide their estimated electricity generation or estimated electricity demand for the five subsequent years.  Based on this information, the MME establishes the total amount of electricity to be traded in the auction and decides which generation companies may participate in the auction.  The auction is carried out in two phases via an electronic system.  As a general rule, contracts entered into in an auction have the following terms (i) from 15 to 30 years from commencement of supply in cases of new generation projects, (ii) from five to 15 years beginning in the year following the auction in cases of existing power generation facilities, (iii) from 10 to 30 years from commencement of supply in cases of alternate generation projects, (iv) 15 years from commencement of supply in cases of biomass reserve energy and (v) 20 years from commencement of supply in cases of wind power reserve energy.

After the completion of the auction, generators and distributors execute the CCEAR, in which the parties establish the price and amount of the energy contracted in the auction.  The CCEAR provides that the price will be adjusted annually in accordance with the IPCA broad consumer price index (Indice Nacional de Preços ao Consumidor Amplo, calculated and published by Instituto Brasileiro de Geografia e Estatística – IBGE).  Distributors grant financial guaranties (principally receivables from the distribution service) to generators in order to secure their payment obligations under the CCEAR.

The Annual Reference Value

The regulation also establishes a mechanism, the Annual Reference Value, which limits the amounts of costs that can be passed through to Final Consumers.  The Annual Reference Value corresponds to the weighted average of electricity prices in the “A-5” and “A-3” auctions, calculated for all distribution companies.

The Annual Reference Value creates an incentive for distribution companies to contract for their expected electricity demands at the lowest price in “A-5” auctions and “A-3” auctions.  Distributors that buy electricity at a price lower than the Annual Reference Value in these auctions are allowed to pass through the full amount of the Annual Reference Value to consumers for three years.  The Annual Reference Value is also applied in the first three years of power purchase agreements for new power generation projects.  After the fourth year, the electricity acquisition costs from these projects are allowed to be fully passed through.  The regulation establishes the following limitations on the ability of distribution companies to pass through costs to consumers:  (i) no pass‑through of costs for electricity purchases that exceed 103.0% of actual demand; (ii) limited pass‑through of costs for electricity purchases made in an “A-3” auction, if the volume of the acquired electricity exceeds 2.0% of the demand for electricity purchased in the “A-5” auctions; (iii) limited pass-through of electricity acquisition costs from new electricity generation projects if the volume contracted under the new contracts related to existing generation facilities is lower than 96.0% of the volume of electricity provided for in the expiring contract; and (iv) full pass-through of costs for electricity purchases from existing facilities in the “A-1” auction is limited to 1% of the charge verified in the year prior to the distributor’s notification of estimated electricity demand to the MME.  If the acquired electricity in the “A-1” auction exceeds 1.0% of the charge, pass-through of costs related to the excess charge amount to Final Consumers is limited to 70.0% of the average value of such acquisition costs of electricity generated by existing generation facilities for delivery commencing in 2007 and ending in 2009.  The MME establishes the maximum acquisition price for electricity generated by existing projects that is included in auctions for the sale of electricity to distributors; and, if distributors do not comply with the obligation to fully contract their demand, the pass-through of the costs from energy acquired in the short‑term market will be the lower of the spot price, Preço de Liquidação de Diferenças (“PLD”) and the Annual Reference Value.

Electric Energy Trading Convention

ANEEL Resolutions No. 109, of 2004 and No. 210, of 2006, govern the Electric Energy Trading Convention (Convenção de Comercialização de Energia Elétrica).  This convention regulates the organization and administration of the CCEE as well as the conditions for trading electric energy.  It also defines, among other things, (i) the rights and obligations of CCEE participants, (ii) the penalties to be imposed on defaulting participants,

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(iii) the structure for dispute resolution, (iv) the trading rules in both regulated and free markets and (v) the accounting and clearing process for short‑term transactions.

 

Restricted Activities of Distributors

Distributors in the Interconnected Power System are not permitted to (i) conduct businesses related to the generation or transmission of electric energy, (ii) sell electric energy to Free Consumers, except for those in their concession area and under the same conditions and tariffs that are applied to captive consumers, (iii) hold, directly or indirectly, any interest in any other company, corporation or partnership or (iv) conduct businesses that are unrelated to their respective concessions, except for those permitted by law or in the relevant concession agreement. Generators are not allowed to hold equity interests in excess of 10.0% in distributors.

Elimination of Self-Dealing

Since the purchase of electricity for captive consumers is now performed through the regulated market, “self‑dealing” (under which distributors were permitted to meet up to 30.0% of their electric energy needs through energy that was either self-produced or acquired from affiliated companies) is no longer permitted, except in the context of agreements that were approved by ANEEL before the enactment of the New Industry Model Law.

Challenges to the Constitutionality of the New Industry Model Law

Political parties are currently challenging the New Industry Model Law on constitutional grounds before the Brazilian Supreme Court.  In October 2007, a decision of the Brazilian Supreme Court on injunctions presented on the matter was published, denying the injunctions by a majority of votes.  To date, the Brazilian Supreme Court has not reached a final decision, and we do not know when such a decision may be reached.  While the Brazilian Supreme Court is reviewing the New Industry Model Law, its provisions remain in effect.  Regardless of the Supreme Court’s final decision, certain portions of the New Industry Model Law relating to restrictions on distributors engaging in businesses unrelated to the distribution of electricity, including sales of energy by distributors to Free Consumers and the elimination of self-dealing, are expected to remain in full force and effect.

If all or a relevant portion of the New Industry Model Law is deemed unconstitutional by the Brazilian Supreme Court, the regulatory scheme introduced by the New Industry Model Law may become void, which will create uncertainty as to how and when the Brazilian government will be able to reform the electric energy sector.

Ownership Limitations

ANEEL had established limits on the concentration of certain services and activities within the electric energy industry, which it eliminated through Resolution No. 378 of November 10, 2009.

Pursuant to Resolution No. 378, ANEEL will submit potential antitrust violations within the electric energy sector for analysis by the Economical Law Department of the Ministry of Justice (Secretaria de Direito Econômico – SDE).  ANEEL can also, spontaneously or upon SDE’s request, analyze potential antitrust acts by identifying:  (i) the relevant markets, (ii) the influence of the agents involved in the exchange of energy on the submarkets where the parties operate, (iii) the actual exercise of market power in connection with market prices, (iv) the participation of the parties in the power generation market, (v) the transmission, distribution and commercialization of energy in all submarkets, and (vi) the efficiency gains of the distribution agents during the tariffs review processes.

In practical terms, ANEEL’s attribution is limited to supplying the SDE with technical information to support SDE’s technical opinion.  SDE, on its turn, will observe ANEEL’s comments and appointments and will only be able to disregard them upon a motivated decision.

Tariffs for the Use of the Distribution and Transmission Systems

ANEEL oversees tariff regulations that govern access to the distribution and transmission systems and establish tariffs for these systems.  The tariffs are (i) network usage charges, which are charges for the use of the proprietary local grid of distribution companies (“TUSD”) and (ii) tariffs for the use of the transmission system, which is the Basic Grid and its ancillary facilities (“TUST”).

 

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TUSD

The TUSD is paid by generators and Free and Special Consumers for the use of the distribution system of the distribution concessionaire to which the relevant generator or Free or Special Consumer is connected.  The amount to be paid by the agent connected to the distribution system is calculated by multiplying the amount of electricity contracted with the distribution concessionaire for each connection point, in kW, by the tariff in R$/kW which is set by ANEEL.  The TUSD has two components:  (i) the remuneration of the concessionaire for the use of the proprietary local grid, known as TUSD Service, which varies in accordance with each consumer’s energy peak load, and (ii) the regulatory charges applicable to the use of the local grid, known as TUSD Charges, which are set by regulatory authorities and linked to the quantity of energy consumed by each consumer.

TUST

The TUST is paid by distribution companies, generators and Free and Special Consumers for the use of the Basic Grid and is revised annually according to (i) an inflation index and (ii) the annual revenue of the transmission companies, as determined by ANEEL.  According to criteria established by ANEEL, owners of the different parts of the transmission grid were required to transfer the coordination of their facilities to the ONS in return for receiving regulated payments from the transmission system users.  Network users, including generation companies, distribution companies and free and special Consumers, have signed contracts with the ONS entitling them to the use of the transmission grid in return for the payment of certain tariffs.  Other parts of the grid that are owned by transmission companies but which are not considered part of the Basic Grid are made directly available to the interested users for a specified fee.

Distribution Tariffs

Distribution tariff rates (including the TUSD) are subject to review by ANEEL, which has the authority to adjust and review these tariffs in response to changes in energy purchase costs and market conditions.  When adjusting distribution tariffs, ANEEL divides the costs of distribution companies between (i) costs that are beyond the control of the distributor, or Parcel A costs, and (ii) costs that are under control of distributors, or Parcel B costs.  The readjustment of tariffs is based on a formula that takes into account the division of costs between the two categories.

Parcel A costs include, among others, the following factors:

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