20-F 1 elpform20f_2011.htm FORM 20F 2011 elpform20f_2011.htm - Generated by SEC Publisher for SEC Filing

As filed with the Securities and Exchange Commission on April 27, 2012

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 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, 2011

Commission file number: 001-14668

COMPANHIA PARANAENSE DE ENERGIA – COPEL

(Exact Name of Registrant as Specified in its Charter)

 

Energy Company of Paraná

(Translation of Registrant’s Name into English

The Federative Republic of Brazil

(Jurisdiction of Incorporation or Organization)

Rua Coronel Dulcídio, 800

80420-170 Curitiba, Paraná, Brazil

(Address of Principal Executive Offices)

Lindolfo Zimmer

+55 41 3222 2027 – ri@copel.com

Rua Coronel Dulcídio, 800, 3rd floor – 80420 – 170 Curitiba, Paraná, 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

Preferred Class B Shares, without par value*

New York Stock Exchange

American Depositary Shares (as evidenced by American Depositary Receipts),

each representing one Preferred Class B Share

New York Stock Exchange

 

* Not for trading, but only in connection with the listing of American Depositary Shares on the New York Stock Exchange.

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

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

Indicate the number of outstanding shares of each of the Issuer’s classes of capital or common stock as of December 31, 2011:

145,031,080 Common Shares, without par value

384,150 Class A Preferred Shares, without par value

128,240,145 Class B Preferred Shares, without par value

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).

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 Securities Exchange Act of 1934. (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.

N/A

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 Securities Exchange Act of 1934).

Yes ¨      No


 

Table of Contents

Presentation of Financial and Other Information

2

Forward-Looking Statements

2

Item 1 

Identity of Directors, Senior Management and Advisers

4

Item 2

Offer Statistics and Expected Timetable

4

Item 3 

Key Information

4

Selected Financial Data

4

Exchange Rates

7

Risk Factors

8

Item 4 

Information on the Company

 17

The Company

17

The Brazilian Electric Power Industry

38

Item 4A 

Unresolved Staff Comments

51

Item 5

Operating and Financial Review and Prospects

51

Item 6

Directors, Senior Management and Employees

 70

Item 7 

Major Shareholders and Related Party Transactions

76

Related Party Transactions

78

Item 8

Financial Information

79

Legal Proceedings

79

Dividend Payments

81

Item 9

The Offer and Listing

84

Item 10

Additional Information

86

Memorandum and Articles of Association

86

Material Contracts

90

Exchange Controls

 90

Taxation

91

Dividends and Paying Agents

 96

Documents on Display

97

Item 11

Quantitative and Qualitative Disclosures about Market Risk

97

Item 12 

Description of Securities Other than Equity Securities

97

Item 12A 

Debt Securities

97

Item 12B

Warrants and Rights

97

Item 12C

Other Securities

97

Item 12D 

American Depositary Shares

97

Item 13 

Defaults, Dividend Arrearages and Delinquencies

98

Item 14 

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

98

Item 15 

Controls and Procedures

98

Item 16A 

Audit Committee Financial Expert

99

Item 16B

Code of Ethics

99

Item 16C

Principal Accountant Fees and Services

99

Item 16D

Exemption from the Listing Standards for Audit Committees

100

Item 16E 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

100

Item 16F

Changes in Registrant’s Certifying Accountant  

100

Item 16G

Corporate Governance  

100

Item 17

Financial Statements

101

Item 18

Financial Statements

101

Item 19 

Exhibits 

101

Technical Glossary

102

Signatures

105

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PRESENTATION OF FINANCIAL AND OTHER INFORMATION

In this annual report, we refer to Companhia Paranaense de Energia ‒ Copel, and, unless the context otherwise requires, its consolidated subsidiaries as “Copel,” the “Company,” “we” or “us.”

References to (i) the “real,” “reais” or “R$” are to Brazilian reais (plural) and the Brazilian real (singular) and (ii) “U.S. dollars,” “dollars” or “US$” are to United States dollars. We maintain our books and records in reais.

Our consolidated financial statements at December 31, 2011, 2010 and 2009 and for each of the three years ended December 31, 2011 have been audited, as stated in the report appearing herein, and are included in this annual report.

We prepared our consolidated financial statements included in this annual report in accordance with International Financial Reporting Standards, or IFRS, as issued by the International Accounting Standards Board, or IASB.

References in this annual report to the “Common Shares”, “Class A Shares” and “Class B Shares” are to our common shares, class A preferred shares and class B preferred shares, respectively. References to “American Depositary Shares” or “ADSs” are to American Depositary Shares, each representing one Class B Share. The ADSs are evidenced by American Depositary Receipts (“ADRs”).

Certain terms are defined the first time they are used in this annual report. As used herein, all references to “GW” and “GWh” are to gigawatts and gigawatt hours, respectively, references to “kW” and “kWh” are to kilowatts and kilowatt hours, respectively, references to “MW” and “MWh” are to megawatts and megawatt hours, respectively, and references to “kV” are to kilovolts. These and other technical terms are defined in the “Technical Glossary” that begins on page 102.

 

FORWARD-LOOKING STATEMENTS

This annual report contains forward-looking statements. We may also make written or oral forward-looking statements in our annual report to shareholders, in our offering circulars and prospectuses, in press releases and other written materials and in oral statements made by our officers, directors or employees. These statements are not historical facts and are based on management’s current view and estimates of future economic circumstances, industry conditions, company performance and financial results. The words “anticipates,” “believes,” “estimates,” “expects,” “plans” and similar expressions, as they relate to the company, are intended to identify forward-looking statements. Statements regarding the declaration or payment of dividends, the implementation of principal operating and financing strategies and capital expenditure plans, the direction of future operations and the factors or trends affecting financial condition, liquidity or results of operations are examples of forward-looking statements. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to update publicly any of them in light of new information or future events.

Forward-looking statements involve only the current view of management and are subject to a number of inherent risks and uncertainties. There is no guarantee that the expected events, trends or results will actually occur. We caution you that a number of important factors could cause actual results to differ materially from those contained in any forward-looking statement. Such factors include, but are not limited to:

·               Brazilian political and economic conditions;

·               economic conditions in the State of Paraná;

·               developments in other emerging market countries;

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·               our ability to obtain financing;

·               lawsuits; 

·               technical and operational conditions related to the provision of electricity services;

·               changes in, or failure to comply with, governmental regulations;

·               competition; 

·               electricity shortages; and

·               other factors discussed below under “Item 3. Key Information―Risk Factors.”

All forward-looking statements are expressly qualified in their entirety by this cautionary statement, and you should not place undue reliance on any forward-looking statement contained in this annual report.

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Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

SELECTED FINANCIAL DATA

The tables below contain selected financial data prepared in accordance with IFRS for the years ended December 31, 2011, 2010 and 2009. The data for the years ended December 31, 2010 and 2009 is derived from our consolidated financial statements which were audited by Deloitte Touche Tohmatsu Auditores Independentes, as stated in their auditor report included in this annual report. The data for the year ended December 31, 2011 is derived from our consolidated financial statements, which were audited by KPMG Auditores Independentes, as stated in their auditor report included in this annual report. The information set forth in this section should be read in conjunction with our consolidated annual financial statements (including the notes thereto) and “Presentation of Financial and Other Data” and “Item 5. Operating and Financial Review and Prospects.”

We have included information with respect to the dividends and interest attributable to shareholders’ equity paid to holders of our common shares and preferred shares since January 1, 2009 under “Item 8. Financial Information - Dividends and Dividend Policy - Payment of Dividends.”

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As of and for the year ended December 31,

 

2011

2010

2009

 

(R$ million)

Statement of Income Data:

 

 

 

Operating Revenues

7,776

6,901

6,250

Cost of sales and services provided

(5,457)

(4,976)

(4,629)

Gross profit

2,319

1,925

1,621

Operational expenses / income

(960)

(893)

(564)

Profit before financial results and taxes

1,359

1,032

1,057

Financial results

225

348

7

Profit before tax and social contribution

1,584

1,380

1,064

Income tax and social contribution on profit

(407)

(370)

(252)

Net income for the year

1,176

1,010

812

Balance Sheet Data:

 

 

 

Current assets

3,702

4,158

3,612

Recoverable rate deficit (CRC)(1)

1,346

1,341

1,255

Non-current assets

5,940

4,805

3,807

Property, plant and equipment, net

7,209

6,664

6,660

Total assets

19,122

17,859

16,313

Loans and financing and debentures (current)

116

704

136

Current liabilities

2,059

2,537

1,723

Loans and financing and debentures (long-term)

2,058

1,281

1,538

Non-current liabilities

4,993

4,027

4,065

Shareholders Equity

12,070

11,296

10,524

Attributable to controlling shareholders

11,827

11,030

10,296

Attributable to non-controlling interest

243

266

228

Share capital

6,910

6,910

4,460

 

 (1) Amounts due from the State of Paraná that were included in current assets totaled R$65.9 million in 2011 and R$58.8 million in 2010. Amounts due from the State of Paraná that were included in long-term assets totaled R$1,280.6 million in 2011 and R$1,282.4 million in 2010. See Note 6 to our consolidated financial statements. This item includes both current and non-current CRC account receivables.

 

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2011

2010

2009

 

(R$ except number of shares)

Basic and diluted earnings per share:

 

 

 

Common Shares

4.04

3.45

2.76

Class A Preferred Shares

5.33

5.20

3.70

Class B Preferred Shares

4.44

3.79

3.04

Dividends per share at year end:

 

 

 

Common Shares

1.47

0.98

0.87

Class A Preferred Shares

2.53

2.53

1.63

Class B Preferred Shares

1.62

1.08

0.96

Number of shares outstanding at year end (weighted average in thousands):

 

 

 

Common Shares

145,031

145,031

145,031

Class A Preferred Shares

384

390

395

Class B Preferred Shares

128,240

128,234

128,229

Total

273,655

273,655

273,655

       

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Exchange Rates

While the Banco Central do Brasil (the “Central Bank”) allows the real/U.S. dollar exchange rate to float freely, it has intervened occasionally to control unstable movements in foreign exchange rates. The real may depreciate or appreciate against the U.S. dollar substantially in the future. For more information on these risks, see “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.

 

Exchange rate of Brazilian currency per US$1.00

Year

Low

High

Average(1)

Year-end

2007

1.7325

2.1556

1.9300

1.7713

2008

1.5593

2.5004

1.8335

2.3370

2009

1.7024

2.4218

1.9905

1.7412

2010

1.6554

1.8811

1.7589

1.6662

2011

1.5345

1.9016

1.6709

1.8758

 

Source: Central Bank.

(1)  Represents the average of the exchange rates on the last day of each month during the relevant period.

 

 

Month

Low

High

December 2011

1.7830

1.8758

January 2012

1.7389

1.8683

February 2012

1.7024

1.7376

March 2012

1.7152

1.8334

April 2012 (until April 20, 2012)

1.8256

1.8867

 

Source: Central Bank.

We have translated some of the U.S. dollar amounts contained in this annual report into reais. The rate used to translate such amounts was R$1.8758 to US$1.00, which was the rate for the selling of U.S. dollars in effect as of December 31, 2011, as published by the Central Bank. The U.S. dollar equivalent information presented in this annual report is provided solely for the convenience of investors and should not be construed as implying that the U.S. dollar amounts represent, or could have been converted into, reais

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Risk Factors

Risks Relating to Brazil

Brazilian political and economic conditions could affect our business and the market price of the ADSs and our common shares. In addition, uncertainty regarding such changes could affect our business and the market price of the ADSs and our common shares.

The Brazilian government’s economic policies have in the past involved, among other measures, price controls, currency devaluations, capital controls and limits on imports. Our business, financial condition and results of operations may be adversely affected by these economic policies in case they are reinstated. These and other measures could also affect the market price of the ADSs and our common shares.

The Brazilian government has exercised, and continues to exercise, significant influence over the Brazilian economy. Frequent and significant intervention by the Brazilian government has often changed monetary, tax, credit, tariff and other policies to influence the course of Brazil’s economy. The Brazilian government’s actions to control inflation and implement other policies have at times involved wage and price controls, devaluation of the real in relation to the U.S. dollar, changes in tax policies as well as other interventionist measures, such as nationalization, raising interest rates, freezing bank accounts, imposing capital controls and inhibiting international trade in Brazil. Changes in policy involving tariffs, exchange controls, regulations and taxation could have an adverse effect on our business and financial results of the ADSs and our common shares.

Fluctuations in the value of the Brazilian real against foreign currencies may result in uncertainty in the Brazilian economy and the Brazilian securities market, and they could have a material adverse effect on our net income and cash flow.

In recent years, the Brazilian real has fluctuated against foreign currencies, and the value of the real may rise or decline substantially from current levels. For instance, 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 also creates additional inflationary pressures in Brazil that may negatively affect us. Depreciation generally curtails access to international capital markets and may prompt government intervention. It also reduces the U.S. dollar value of our dividends and the U.S. dollar equivalent of the market price of our common shares and the ADSs. For additional information about historical exchange rates, see “Exchange Rates.”

If Brazil experiences substantial inflation in the future, our margins and the market price of the Class B Shares and ADSs may be reduced.

Brazil has in the past experienced extremely high rates of inflation. More recently, Brazil’s annual rates of inflation, measured in accordance with the variation of the Índice Geral de Preços—Disponibilidade Interna (“IGP-DI”) index, were (1.4)% in 2009, 11.3% in 2010, 5.0% in 2011 and 0.93% for the three months ended March 31, 2012. The Brazilian government has in the past taken measures to combat inflation, and public speculation about possible future government actions has had significant negative effects on the Brazilian economy. Although our concession contracts provide for annual readjustments based on inflation indices, if Brazil experiences substantial inflation in the future, and the Brazilian government adopts inflation control policies similar to those adopted in the past, our costs may increase faster than our revenues, our operating and net margins may decrease and, if investor confidence lags, the price of the Class B Shares and ADSs may fall. Inflationary pressures may also curtail our ability to access foreign financial markets and could lead to further government intervention in the economy, including the introduction of government policies that may adversely affect the overall performance of the Brazilian economy.

 

8


 

Negative developments in other national economies, especially those in developing countries, may negatively impact foreign investment in Brazil and the country’s economic growth.

International investors generally consider Brazil to be an emerging market. Historically, adverse developments in the economies of emerging markets have resulted in investors’ perception of greater risk from investments in such markets. Such perceptions regarding emerging market countries have significantly affected the market value of securities of Brazilian issuers. Furthermore, although economic conditions are different in each country, investors’ reactions to developments in one country can impact the prices of securities in other countries, including those in Brazil and this may diminish investors’ interest in securities of Brazilian issuers, including ours.

Changes in Brazilian tax policies may have an adverse effect on us.

The Brazilian government has changed its tax policies in ways that affect the electricity sector, and it may do so again in the future. These changes include increases in the tax rates affecting energy companies and, occasionally, the collection of temporary taxes related to specific governmental purposes. If we are unable to adjust our tariffs accordingly, we may be adversely affected.

 

Risks Relating to Our Operations

We are controlled by the State of Paraná, the policies and priorities of which directly affect our operations and may conflict with the interests of our investors.

We are controlled by the State of Paraná, which holds 58.6% of our outstanding common voting shares as of the date of this annual report, and whose interests may differ from other shareholders. As a major shareholder, the State of Paraná has the power to control all of our operations, including the power to elect a majority of the members of our Board of Directors and determine the outcome of any action requiring common shareholder approval, including transactions with related parties and corporate reorganizations.

The operations of the Company have had and will continue to have an important impact on the commercial and industrial development of the State of Paraná. In the past, the State of Paraná has used, and may in the future use, its status as our controlling shareholder to decide whether we should engage in certain activities and make certain investments aimed, principally, to promote its political, economic or social objectives and not necessarily to meet the objective of improving our business and/or operational results.

We are largely dependent upon the economy of the State of Paraná.

Our distribution market for the majority of our sales of electricity is located in the State of Paraná. Although a more competitive market involving possible sales to customers outside Paraná might develop in the future, our business depends and is expected to continue to depend to a very large extent on the economic conditions of Paraná. We cannot assure you that economic conditions in Paraná will be favorable to us in the future. The GDP (Gross Domestic Product) of the State of Paraná increased 4.0% in 2011, while Brazil’s GDP increased 2.7% during the same period.

We are involved in several lawsuits that could have a material adverse effect on our business if their outcome is unfavorable to us.

As a result of our operating activities in the electric energy sector, our contractual relationships and our investments, we are the defendant in several legal actions, mainly relating to civil, administrative, labor and tax claims. The outcome of these proceedings is uncertain and, if determined against us, may result in obligations that could materially affect our results of operations. At December 31, 2011 our reserves for probable and reasonably estimated losses were R$1,000.8 million. For additional information, see “Item 8. Financial Information - Legal Proceedings.”

9


 

The development of transmission and power generation projects is subject to substantial risks.

In connection with the development of transmission and generation projects, we generally must obtain feasibility studies, governmental concessions or authorizations, permits and approvals, condemnation agreements, equipment supply agreements, engineering, procurement and construction contracts, sufficient equity and debt financing and site agreements, each of which involves the consent of third parties over which we have no control. In addition, project development is subject to environmental, engineering and construction risks that can lead to cost overruns, delays and other impediments to timely complete within a project’s budget. We cannot assure you that all required permits and approvals for our projects will be obtained, that we will be able to secure private sector partners for any of our projects, that we or any of our partners will be able to obtain adequate financing for our projects or that financing will be available on a non-recourse basis to us. If we are unable to complete a project, whether at the initial development phase or after construction has commenced, we may not be able to recover our investment in such a project, which investment may be substantial.

We are subject to limitations regarding the amount and use of public sector financing, which could prevent us from obtaining financing and implanting our investment plan.

 

As a State controlled company, we are subject to certain CMN and Central Bank limitations regarding the level of credit financial institutions may offer to public sector entities. As a result, we may have difficulty in obtaining financing from Brazilian financial institutions, which could create difficulties in the implementation of our investment plan. Brazilian legislation also establishes that a state-controlled company may generally use commercial bank debt only to refinance financial obligations. As a result of these regulations, our capacity to incur debt is limited, which could negatively affect the implementation of our investment plan.

Security breaches and other disruptions could compromise our data centers and expose us to liability, which would cause our business and reputation to suffer.

In our ordinary course of business, we collect and store personal data of our customers in our data centers. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings under Brazilian laws that protect the privacy of personal information and damage our reputation, a fact that could adversely affect our results of operations.

Risks Relating to the Brazilian Electricity Sector

We are uncertain as to the renewal of our concessions, some of which are due to expire in 2015.

We carry out our generation, transmission and distribution activities pursuant to concession agreements entered into with the Brazilian federal government. Our current concessions range in duration from 20 to 35 years, with the first set to expire in 2015.

Of the eighteen generation concessions that we wholly own for assets already in operation, thirteen have already been renewed once and are therefore not entitled to further renewal without undergoing a new public bidding process. The concessions for three of our generation facilities, which were already renewed in 1995, will expire in 2015 (namely, the Capivari Cachoeira, Mourão and Chopim I facilities). Our generation concessions that have not yet been renewed may be renewed for an additional 20-year period, except for the concessions of the Mauá and Colíder facilities, which are subject to non-renewable concessions.

Of the four transmission concessions and one distribution concession  that we wholly own for assets already in operation, the main transmission and our distribution concessions will expire in July 2015 (although may be extended another 20 years, at the discretion of the granting authority). Our other transmission concessions may be renewed for 30 years.

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The Brazilian constitution requires that all concessions relating to public services, such as electricity, 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, provided that the concessionaire has met minimum performance standards and that the proposal is otherwise acceptable to the federal government. For public service concessions, the federal government decides whether to renew contracts or to require a new bidding process based on, among other things, if such renewal is in the public’s interest. Therefore, there can be no assurance that our concessions will be extended, and, if they are extended, if the conditions under which such extension are granted will be favorable to us. If our concessions are not extended, or are extended under less favorable conditions, our operations and financial results may be adversely affected.

The tariffs that we charge for sales of electricity to captive customers are determined pursuant to a concession agreement with the Brazilian government through the Brazilian Electricity Regulatory Agency, the Agência Nacional de Energia Elétrica (“ANEEL”), and our  operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are unfavorable to us. Moreover, ANEEL’s decisions may be contested in judicial or administrative proceedings initiated by public authorities or customers.

ANEEL has substantial discretion to establish the tariff rates we charge our customers, which are determined pursuant to a concession agreement with ANEEL and in accordance with ANEEL’s regulatory decision-making authority.

Our distribution concession agreement and Brazilian law establish a price cap mechanism that permits three types of tariff adjustments: (i) annual readjustment (reajuste anual), (ii) periodic revision (revisão periódica), and (iii) extraordinary revision (revisão extraordinária). We are entitled to apply each year for the annual readjustment, which is designed to offset some effects of inflation on tariffs and pass through to customers certain changes in our cost structure that are beyond our control, such as the cost of electricity we purchase from certain sources and certain other regulatory charges, including charges for the use of transmission facilities. In addition, ANEEL carries out a periodic revision every four 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 readjustments, the effect of which is to ensure that we share the benefits of improved economies of scale with our customers. At any time, we may also request an extraordinary revision of our tariffs in the case of a significant and unexpected event, including if such an event significantly alters our cost structure.

We cannot assure you that ANEEL will establish tariffs at rates that are favorable to us. To the extent that any of our requests for adjustments are not granted by ANEEL in a timely manner, our financial condition and results of operations may be adversely affected. In addition, ANEEL’s decisions relating to our tariffs may be contested by public authorities or by our customers. Administrative and judicial decisions resulting from these challenges may modify ANEEL’s decisions in a manner that is unfavorable to us, which may adversely affect our financial condition and results of operations.

Certain customers in our concession area may cease to use our distribution system.

Our distribution business generates a large portion of its revenues by charging customers a tariff to use our distribution system. Large electricity customers within the geographic area of our concession that meet certain regulatory requirements may qualify as free customers (“Free Customers”). A Free Customer, under some circumstances, is entitled to connect directly to the main national transmission network known as the Interconnected Transmission System (“Interconnected Transmission System”), in which case that Free Customer would cease to pay our distribution tariff. This loss would adversely affect our revenues and results of operations.

In addition, some customers in our concession area produce their own energy. Although many of these customers continue to use our distribution system to transport the energy they produce, we cease to collect a distribution tariff if a self-producing customer discontinues its use of our distribution system. Our results of operations will be adversely affected if the number of self-producing customers that do not pay our distribution tariff were to increase.

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Our operating results depend on prevailing hydrological conditions and the availability of natural gas. 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. According to data from ANEEL, approximately 70% of Brazil’s installed capacity currently comes from hydroelectric generation facilities. Our region is subject to unpredictable hydrological conditions because of non-cyclical deviations in average rainfall. The most recent period of low rainfall was in the years prior to 2001, when the Brazilian government instituted the Rationing Program (the “Rationing Program”), a program to reduce electricity consumption that was in effect from June 1, 2001 to February 28, 2002. 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.

In addition, if a shortage of natural gas were to occur, this would increase the general demand for energy in the market and therefore increase the risk that a rationing program would be instated.

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 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 growth strategy, as well as our day-to-day operations may be adversely affected by governmental actions such as changes to current legislation, the termination of federal or state concession programs, changes in the public energy auction process, 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 the regulation of the electric power industry under the 2004 legislation known as the New Industry Model Law (Lei do Novo Modelo do Setor Elétrico). 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, it would have 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 they could have an adverse impact on the entire energy sector, including our business and results of operations.

We may be forced to purchase energy in the spot market at higher prices if our forecasts for energy demand are not accurate, and we may not be entitled to pass on any increased costs to our Final Customers.

Under the New Industry Model Law, electric energy distributors, including us, must contract to purchase, through public bids conducted by ANEEL, 100% of the forecasted electric energy demand for their respective distribution concession areas, up to five years prior to the actual delivery of electric energy. We cannot guarantee that our forecasts for energy demand in our distribution concession area will be accurate. If our forecasts fall short of actual electricity demand, we may be forced to make up for the shortfall by entering into short-term agreements to purchase electricity in the spot market where we may pay significantly more for energy. In addition, if we underestimate our distribution energy needs, we may be subject to penalties imposed by the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica, or “CCEE”). In addition, if our forecasts surpass actual demand by more than the allowed margin, we will not be able to pass on to our Final Customers the cost of the excess energy that we acquire.

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We generate a portion of our  operating revenues from Free Customers who may seek other energy suppliers upon the expiration of their contracts with us.

As of December 31, 2011, we had eight Free Customers, representing approximately 1.3% of our consolidated operating revenues and approximately 1.9% of the total quantity of electricity sold by us. Through February 2012, we have reached agreements with four additional Free Customers, three of which were previously captive customers of us. Our contracts with Free Customers are typically for periods of greater than two and less than five years.

Approximately 38% of the megawatts sold under contracts to such customers are set to expire in 2012. In addition, as of December 31, 2011, we had 42 customers that were eligible to purchase energy as Free Customers. These customers represented approximately 7.7% of the total volume of electricity we sold in 2011, and approximately 4.5% of our operating revenues from energy sales for that year. There can be no assurance that Free Customers will enter into contracts or extend their current contracts to purchase energy from us.

Our equipment, facilities and operations are subject to numerous environmental and health regulations, which may become more stringent in the future and may result in increased liabilities and increased capital expenditures.

Our distribution, transmission and generation activities are subject to comprehensive federal, state and local 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 and with requirements established for the maintenance of our environmental licenses. These actions could result in, among other things, the imposition of fines and revocation of licenses, which could have a material adverse effect on our financial condition or results of operations. It is also possible that enhanced environmental and health regulations will force us to allocate capital towards compliance, and consequently, divert funds away from planned investments. Such a diversion could have a material adverse effect on our financial condition and results of operations.

ANEEL could penalize us for failing to comply with the terms of our concessions or with applicable laws and regulations, and we may not recover the full value of our investment in the event that any of our concessions are terminated.

Our concessions are for terms of 20 to 35 years and may be extended if certain conditions are met. In the event that we fail to comply with any term of our concessions or applicable law or regulation, ANEEL may impose penalties on us, which may include warnings, the imposition of potentially substantial fines (in some instances, up to 2% of our revenues in the fiscal year immediately preceding the assessment) and restrictions on our operations, among others. ANEEL may also terminate our concessions prior to the expiration of their terms if we fail to comply with their provisions or if ANEEL determines, through an expropriation proceeding, that terminating our concession would be in the public interest. If ANEEL terminates any of our concessions before their expiration, we would not be able to operate the segment(s) of our business that had been authorized by the concession. Furthermore, any compensation that we may receive from the federal government for the unamortized portion of our investment may not be sufficient for us to recover the full value of our investment. The early termination or non-renewal of any of our concessions or the imposition of severe fines or penalties by ANEEL could have a material adverse effect on our financial condition and results of operations. See “Item 4. Information on the Company - The Brazilian Power Industry - Concessions.”

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The construction, expansion and operation of our generation, transmission and distribution facilities and equipment involve significant risks that may cause loss of revenues or increase of expenses.

The construction, expansion and operation of our generation, transmission and distribution of electricity facilities and equipment involve many risks, including the inability to obtain required governmental permits and approvals, supply interruptions, strikes, climate and hydrological interference, unexpected environmental and engineering problems, increase in losses of electricity (including technical and commercial losses), the unavailability of adequate financing and the unavailability of equipment

In the event we experience these or other problems, we might not be able to generate, transmit and distribute electricity in favorable quantities and on favorable terms, which may adversely affect our financial condition and the results of our operations.

If we are unable to conclude our investment program on schedule, the operation and development of our business could be adversely affected.

In 2012, we plan to invest approximately R$1,069.9 million in our generation and transmission activities (including HPP Mauá and HPP Colíder), R$1,105.0 million in our distribution activities and R$82.5 million in our telecommunications activities. Our ability to complete this investment program depends on multiple factors, including our ability to charge sufficient fees for our services and a variety of regulatory and operational contingencies. There is no assurance that we will have the financial resources to complete our proposed investment program, and our inability to do so may adversely affect the operation and development of our business leading to the imposition of fines levied by ANEEL as well as reduction in tariff levels.

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

We are strictly liable under Brazilian law for damages resulting from the inadequate provision of electricity distribution services. In addition, our distribution and generation utilities may be held liable for damages caused to others as a result of interruptions or disturbances arising from the Brazilian generation, transmission or distribution systems, whenever these interruptions or disturbances are not attributed to an identifiable member of the National Electric System Operator, the Operador Nacional do Sistema Elétrico (“ONS”). We cannot assure you that our insurance policies will fully cover damages resulting from inadequate rendering of electricity services, which may have an adverse effect on us.

Risks Relating to the Class B Shares and ADSs

As a holder of ADSs you will generally not have voting rights at our shareholders’ meetings.

In accordance with Brazilian Corporate Law and our bylaws, holders of the Class B Shares, and thus of the ADSs, are not entitled to vote at our shareholders’ meetings except in limited circumstances. That means, among other things, that you, as a holder of the ADSs, are not entitled to vote on corporate transactions, including any proposed merger.

In addition, in the limited circumstances where the holders of Class B Shares are entitled to vote, holders may exercise voting rights with respect to the Class B Shares represented by ADSs only in accordance with the provisions of the deposit agreement relating to the ADSs. There are no provisions under Brazilian Corporate Law or under our bylaws that limit ADS holders’ ability to exercise their voting rights through the depositary bank (the “Depositary”) with respect to the underlying Class B Shares. However, the procedural steps involved create practical limitations on the ability of ADS holders to vote. For example, holders of our Class B Shares will be able to exercise their voting rights by either attending the meeting in person or voting by proxy. In accordance with the deposit agreement, we will provide the notice to the Depositary, which will in turn, as soon as practicable thereafter, mail to holders of ADSs the notice of such meeting and a statement as to the manner in which instructions may be given by holders. To exercise their voting rights, ADS holders must then instruct the Depositary how to vote their shares. Because of this extra procedural step involving the Depositary, the process for exercising voting rights will take longer for ADS holders than for direct holders of Class B Shares. ADSs for which the Depositary does not receive timely voting instructions will not be voted.

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As a holder of ADSs you will have fewer and less well-defined shareholders’ rights in Brazil than in the United States and certain other jurisdictions.

Our corporate affairs are governed by our bylaws and Brazilian Corporate Law, which may differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States or in certain other jurisdictions outside Brazil. Under Brazilian Corporate Law you and the holders of the Class B Shares may have fewer and less well-defined rights to protect your interests in connection with actions taken by our Board of Directors or the holders of Common Shares than under the laws of the United States and certain other jurisdictions outside Brazil.

Although Brazilian law imposes restrictions on insider trading and price manipulation, the Brazilian securities markets are not as highly supervised as the United States securities markets or markets in certain other jurisdictions outside Brazil. For instance, rules and policies against self-dealing and regarding the preservation of minority shareholder interests may be less developed and not as robustly enforced in Brazil as in the United States and certain other jurisdictions outside Brazil, which could potentially disadvantage you as a holder of the preferred shares and ADSs. In addition, shareholders in Brazilian companies must hold 5% of the outstanding share capital of a corporation in order to have standing to bring shareholders’ derivative suits, and shareholders in Brazilian companies ordinarily do not have standing to bring a class action suit.

You may be unable to exercise preemptive rights relating to the preferred shares.

You will not be able to exercise the preemptive rights relating to the Class B Shares underlying your ADSs unless a registration statement under the United States Securities Act of 1933, as amended (the “Securities Act”) is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available. Therefore, the Depositary will not offer rights to you as a holder of the ADSs unless the rights are either registered under provisions of the Securities Act or are subject to an exemption from the registration requirements. We are not obligated to file a registration statement with respect to the shares or other securities relating to these rights, and we cannot assure you that we will file any such registration statement. Accordingly, you may receive only the net proceeds from the sale of your preemptive rights by the Depositary or, if the preemptive rights cannot be sold, they will be allowed to lapse. If you are unable to participate in rights offerings, your holdings may also be diluted.

If you exchange your ADSs for Class B Shares, you risk increased taxes and the inability to remit foreign currency abroad.

Brazilian law requires that parties obtain a certificate of registration from the Central Bank in order to be allowed to remit foreign currencies, including U.S. dollars, abroad. For the ADSs, the Brazilian custodian for the Class B Shares has obtained the necessary certificate from the Central Bank for the payment of dividends or other cash distributions relating to the preferred shares or upon the disposition of the preferred shares. If you exchange your ADSs for the underlying Class B Shares, however, you may only rely on the custodian’s certificate for five business days from the date of exchange. Thereafter, you must obtain your own certificate of registration or register in accordance with Central Bank and CVM rules in order to obtain and remit U.S. dollars abroad upon the disposition of the Class B Shares or distributions relating to the preferred shares. If you do not obtain a certificate of registration, you may not be able to remit U.S. dollars or other currencies abroad and may be subject to less favorable tax treatment on gains with respect to the preferred shares. Pursuant to Central Bank rules, obtaining this registration requires exchange transactions, which are subject to taxes in Brazil. For more information, see “Item 10. Additional Information - Taxation - Brazilian Tax Considerations - Other Brazilian Taxes.”

If you attempt to obtain your own certificate of registration, you may incur expenses or suffer delays in the application process, which could delay your ability to receive dividends or distributions relating to the preferred shares or the return of your capital in a timely manner. The custodian’s certificate of registration and any certificate of foreign capital registration you obtain may be affected by future legislative changes. Additional restrictions may be imposed in the future on the disposition of the underlying Class B Shares or the repatriation of the proceeds from disposition.

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The Brazilian government may impose exchange controls and restrictions on remittances abroad which may adversely affect your ability to convert funds in reais into other currencies and to remit other currencies abroad.

In the past, the Brazilian government has imposed restrictions on the remittance to foreign investors of the proceeds of their investments in Brazil and the conversion of Brazilian currency into foreign currencies. The Brazilian government could again choose to impose this type of restriction if, among other things, there is deterioration in Brazilian foreign currency reserves or a shift in Brazil’s exchange rate policy. Reimposition of these restrictions would hinder or prevent your ability to convert dividends, distributions or the proceeds from any sale of Class B Shares, as the case may be, from reais into U.S. dollars or other currencies and to remit those funds abroad. We cannot assure you that the Brazilian government will not take similar measures in the future.

The relative volatility and illiquidity of the Brazilian securities markets may impair your ability to sell the Class B Shares underlying the ADSs.

The Brazilian securities markets are substantially smaller, less liquid, more concentrated and more volatile than major securities markets in the United States and certain other jurisdictions outside Brazil, and are not as highly regulated or supervised as some of these other markets. The illiquidity and relatively small market capitalization of the Brazilian equity markets may cause the market price of securities of Brazilian companies, including our ADSs and Class B Shares, to fluctuate in both the domestic and international markets, and may substantially limit your ability to sell the Class B Shares underlying your ADSs at a price and time at which you wish to do so.

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Item 4. Information on the Company

The Company

We are engaged in the generation, transmission, distribution and sale of electricity mainly in the Brazilian State of Paraná, pursuant to concessions granted by the Brazilian regulatory agency for the electricity sector, ANEEL. We also provide telecommunications and other services.

At December 31, 2011, we generated electricity at 17 hydroelectric plants and one thermoelectric plant, for a total installed capacity of 4,549.6 MW, approximately 99.6% of which is hydroelectric. Including the installed capacity of generation companies in which we have an ownership interest, our total installed capacity is 5,158.5 MW. Our electric power business is subject to comprehensive regulation by ANEEL.

We hold concessions to distribute electricity in 395 of the 399 municipalities in the State of Paraná and in the municipality of Porto União in the State of Santa Catarina. At December 31, 2011, we owned and operated 2,028.9 km of transmission lines and 184,418.1 km of distribution lines, constituting one of the largest distribution networks in Brazil. Of the electricity volume we supplied to our Final Customers during 2011:

·         35.8% was to industrial customers;

·         26.6% to residential customers;

·         20.4% to commercial customers; and

·         17.1% to rural and other customers.

Key elements of our business strategy include the following:

·         expanding our power generation, transmission, distribution, and telecommunication systems;

·         expanding our generation business’ sales to Free Customers both inside and outside the State of Paraná;

·         seeking productivity improvements in the short term and sustained growth in the long term;

·         striving to keep customers satisfied and our workforce motivated and prepared;

·         seeking cost efficiency and innovation;

·         achieving excellence in data, image, and voice transmission; and

·         researching new technologies in the energy sector in order to expand power output with renewable and non-polluting sources.

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Historical Background

We were formed in 1954 by the State of Paraná to engage in the generation, transmission and distribution of electricity, as part of a plan to bring the electric energy sector under state control. We acquired the principal private power companies located in the State of Paraná in the early 1970s. During the period from 1970 to 1977, we significantly expanded our transmission and distribution network and worked to increase the connectivity of our network to networks in other Brazilian states. In 1979, a change in state law permitted us to extend our generating activities to include production from sources other than hydroelectric and thermal power plants.

Currently, we are the largest energy company in the State of Paraná. We are a corporation incorporated and existing under the laws of Brazil, with the legal name Companhia Paranaense de Energia – Copel. Our head offices are located at Rua Coronel Dulcídio, 800, CEP 80420-170 Curitiba, Paraná, Brazil. Our telephone number at the head office is (55-41) 3322-3535 and our website is www.copel.com.

Relationship with the State of Paraná

The State of Paraná owns 58.6% of our Common Shares and, consequently, has the ability to control the election of the majority of the members of our Board of Directors, the appointment of senior management and our direction, future operations and business strategy.

Corporate Structure

Prior to 2001, we operated as a single corporation engaged in the generation, transmission and distribution of electricity and in certain related activities. In compliance with the changed regulatory regime, we transferred our operations to four wholly-owned subsidiaries one each for generation, transmission, distribution and telecommunications and our investments in other companies to a fifth wholly-owned subsidiary. This corporate restructuring was completed in July 2001.

In 2007, to comply with energy sector legislation, we divided the assets of our transmission business (“Copel Transmissão”) between our distribution business (“Copel Distribuição”) and our generation business, (“Copel Geração”). As a result, we changed the name of the latter entity to Copel Geração e Transmissão S.A. We also liquidated Copel Participações S.A. and distributed the equity interests it held in our controlled companies between Copel Geração e Transmissão and our holding company. The current organization of the group as of December 31, 2011 is as described below:

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Business

In the past, our generation and distribution businesses were integrated, and we sold most of the electricity we generated to the customers of our distribution business. This changed as a result of the implementation of the New Industry Model Law, enacted in 2004. Today, open auctions on the regulated market are the primary channel by which our generation business sells energy, and they are one of the primary channels by which our distribution business purchases energy to resell to captive customers. Our generation business only sells energy to our distribution business through auctions in the regulated market. Our distribution business, like certain other Brazilian distribution companies, is also required to purchase energy from Itaipu Binacional (“Itaipu”), a hydroelectric facility equally owned by Brazil and Paraguay, in an amount determined by the Brazilian government based on our proportionate share in the Brazilian electricity market. Itaipu has an installed capacity of 14,000 MW. Pursuant to a 1973 treaty between Brazil and Paraguay, Brazilian companies purchase the substantial majority of the electricity generated by Itaipu. For more information, see “Item 4. Information on the Company - The Brazilian Power Industry.”

The following table sets forth the total electricity we generated and purchased in each of the last five years, by showing the total amount of electricity generated and purchased by Copel Geração e Transmissão and the total amount of electricity purchased by Copel Distribuição.

 

Year ended December 31,

 

2011

2010

2009

2008

2007

 

(GWh)

Copel Geração e Transmissão

 

 

 

 

 

Electricity generated

25,789

24,321

18,321

20,372

18,134

Electricity purchased from others(1)

953

696

4,093

1,700

2,616

Total electricity generated and purchased by Copel Geração e Transmissão

26,742

25,017

22,414

22,072

20,750

Copel Distribuição

 

 

 

 

 

Electricity purchased from Itaipu(2)

5,278

5,306

5,379

5,468

4,666

Electricity purchased from Auction – CCEAR – affiliates

1,328

1,230

1,488

1,229

1,203

Electricity purchased from Auction – CCEAR – other

17,027

15,405

14,185

12,746

11,850

Electricity purchased from other(3)

2,870

3,090

2,901

3,414

4,016

Total electricity purchased by Copel Distribuição

26,503

25,031

23,953

22,857

21,735

Total electricity generated and purchased by Copel Geração e Transmissão and Copel Distribuição

53,245

50,048

46,367

44,929

42,485

           

   

(1) Includes capacity made available but not fully delivered (including energy from MRE and CCEE).

(2) Distribution companies operating under concessions in the Midwest, South and Southeast regions of Brazil purchase electricity generated by Itaipu.

(3) Includes capacity made available but not fully delivered (including energy from Elejor and CCEE).

 

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The following table sets forth the total electricity we sold to Free Customers, captive customers, distributors, energy traders and other utilities in the south of Brazil through the Interconnected Transmission System that links the states in the south and southeast of Brazil, by showing the total amount of electricity sold by Copel Geração e Transmissão and Copel Distribuição in the last five years.

 

Year ended December 31,

 

2011

2010

2009

2008

2007

 

(GWh)

Copel Geração e Transmissão

 

Electricity delivered to Free Customers

919

1,054

1,044

1,185

1,461

Electricity delivered to bilateral agreements

1,051

1,455

1,051

3,538

3,945

Electricity delivered to Auction – CCEAR – affiliates

1,328

1,230

1,488

1,229

1,203

Electricity delivered to Auction – CCEAR – other

14,139

13,405

13,478

11,435

10,737

Electricity delivered to the Interconnected System(1)

8,624

7,233

4,874

4,151

2,926

Total electricity delivered by Copel Geração e Transmissão

26,061

24,377

21,935

21,538

20,272

Copel Distribuição

 

Electricity delivered to captive customers

22,454

21,304

20,242

19,633

18,523

Electricity delivered to distributors in the State of Paraná

600

568

524

495

474

Spot Market – CCEE

344

61

266

0

161

Total electricity delivered by Copel Distribuição

23,398

21,933

21,032

20,128

19,158

Subtotal

49,459

46,310

42,967

41,666

39,430

Losses by Copel Geração e Transmissão and Copel Distribuição

3,786

3,738

3,400

3,263

3,055

Total electricity delivered by Copel Geração e Transmissão and Copel Distribuição , including losses

53,245

50,048

46,367

44,929

42,485

 

(1) Includes capacity made available but not fully delivered.

 

Generation

 

Generation Facilities

 

At December 31, 2011, we operated 17 hydroelectric plants and one thermoelectric plant, with a total installed capacity of 4,549.6 MW. If we include the installed capacity of the generation companies in which we have an ownership interest, our total installed capacity is 5,158.5 MW. We produce electricity almost exclusively through our hydroelectric plants. Our assured energy totaled 1,958.6 average MW in 2011. Our generation varies year by year as a result of hydrological conditions and other factors. We generated 25,789 GWh in 2011, 24,321 GWh in 2010, 18,321 GWh in 2009, 20,372 GWh in 2008 and 18,134 GWh in 2007.

The generation of electrical energy at our hydroelectric plants is supervised and coordinated by our Generation Operation Center in the city of Curitiba. This operation center is responsible for coordinating the operations related to approximately 99.4% of our total installed capacity, including some of the plants in which we hold participatory interests.

The following table sets forth certain information relating to our main plants in operation at December 31, 2011.

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Type

Plant

Installed capacity

Assured energy (1)

Placed in service

Concession expires

 

 

(MW)

(GWh/yr)

 

 

Hydroelectric

Foz do Areia

1,676

5,045

1980

2023

Hydroelectric

Segredo

1,260

5,282

1992

2029

Hydroelectric

Salto Caxias

1,240

5,300

1999

2030

Hydroelectric

Capivari Cachoeira

260

955

1970

2015

 

(1) Values used to determine volumes committed for sale.

Governador Bento Munhoz da Rocha Netto (the “Foz do Areia” Plant). The Foz do Areia Hydroelectric Plant is located on the Iguaçu River, approximately 350 kilometers southwest of the city of Curitiba. The plant began full operations in 1981.

Governador Ney Aminthas de Barros Braga (the “Segredo” Plant). The Segredo Hydroelectric Plant is located on the Iguaçu River, approximately 370 kilometers southwest of the city of Curitiba. The plant began full operations in 1993.

Governador José Richa (the “Salto Caxias” Plant). The Salto Caxias Hydroelectric Power Plant is located on the Iguaçu River, approximately 600 kilometers southwest of the city of Curitiba. The plant began full operations in 1999.

Governador Pedro Viriato Parigot de Souza (the “Capivari Cachoeira Plant”). The Capivari Cachoeira Hydroelectric Plant is the largest underground hydroelectric plant in Brazil. The reservoir is located on the Capivari River, approximately 50 kilometers north of the city of Curitiba, and the power station is located on the Cachoeira River, approximately 110 kilometers northeast of the city of Curitiba. The plant began full operations in 1972.

In addition to our generation facilities, we have ownership interests in several other generation companies. Between 2004 and 2010, we were required by law to retain a majority of the voting shares of any company in which we obtained an ownership interest. Starting in 2010, it became possible for us to hold minority interests in companies.

The following table sets forth information regarding the generation plants in which we had a partial ownership interest as of December 31, 2011:

Type

Plant

Installed

capacity

Assured

energy

Placed in service

Our ownership

Concession

expires

 

 

(MW)

(GWh/yr)

 

(%)

 

Thermal

Araucária

484.1

3,419.0 (1)

September 2006

80.0

2029

Hydroelectric

Elejor Facility (Santa Clara and Fundão)

246.4

1,229.0    

July 2005
June 2006

70.0

2036

Hydroelectric

Dona Francisca

125.0

683.3   

February 2001

23.0

2033

Hydroelectric

Foz do Chopim

29.1

188.0   

October 2001

35.8

2030

Hydroelectric

Lajeado

902.5

4,613.0   

December 2001

0.8

2032

 

(1) The assured energy of thermal plants such as Araucária varies depending on the price of natural gas, according to criteria established  by the Ministry of Mines and Energy (“MME”).

 

 

Araucária. We have an 80.0% interest in UEG Araucária Ltda., which owns the Araucária Thermoelectric Plant. In December 2006, UEG Araucária Ltda. entered into a lease agreement under which it leased the plant to Petrobras, and Petrobras entered into an operation and maintenance agreement with our subsidiary Copel Geração e Transmissão under which Copel Geração e Transmissão agreed to operate and maintain the plant. Both agreements have been extended through December 2012.

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Elejor Facility. The Elejor Facility consists of the Santa Clara and Fundão Hydroelectric Plants, both of which are located on the Jordão River in the State of Paraná. The aggregate total installed capacity of the units is 246.4 MW, which includes two smaller hydroelectric generation units installed in the same location. Centrais Elétricas do Rio Jordão S.A. (“Elejor”) signed a concession agreement with a term of 35 years for the Santa Clara and Fundão plants in October 2001. As of December 31, 2011, we own 70.0% of the common shares of Elejor, and PaineraPar owns the remaining 30.0%.

Elejor is required to make monthly payments to the federal government for the use of hydroelectric resources, with total annual payments of R$19.0 million. This amount is adjusted on an annual basis by the Brazilian General Market Price Index, Índice Geral de Preços do Mercado (“IGP-M Index”). In 2011, the aggregate amount of concession payments paid by Elejor to the federal government was R$41.2 million.

We have a power purchase agreement with Elejor that provides that we will purchase all of the energy produced by the Santa Clara and Fundão facilities at a set rate until 2015, to be adjusted annually in accordance with the IGP-M Index. In 2011, Elejor’s net revenues and net profits were R$196 million and R$15.6 million, respectively, while in 2010 its net revenues and net profits were R$181.0 million and R$13.4 million, respectively.

Dona Francisca. We own 23.03% of the common shares of Dona Francisca Energética S.A. (“DFESA”). The other shareholders are Gerdau S.A. with a 51.82% interest, Celesc S.A. with a 23.03% interest and Desenvix S.A. with a 2.12% interest. Dona Francisca Hydroelectric Power Plant is located on the Jacuí River in the State of Rio Grande do Sul. The plant began full operations in 2001. As of December 31, 2011, DFESA had loans and financing in the total amount of R$ 46.3 million, R$ 41.4 million of which reflects loans extended to it by Banco Bradesco S.A. and Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”), a Brazilian development bank wholly owned by the Brazilian government. The debt is secured by a pledge of shares of DFESA. We have a power purchase agreement with DFESA, valued at R$61.2 million annually, which will terminate in October 2015 and which obligates Copel Geração e Transmissão to purchase 100% of its assured energy. In 2011, DFESA’s net revenues and net profits were R$84.6 million and R$34.5 million, respectively, while in 2010 its net revenues and net profits were R$59.0 million and R$24.7 million, respectively.

Foz do Chopim. The Foz do Chopim Hydroelectric Plant is located on the Chopim River in the State of Paraná. We own 35.77% of the common shares of Foz do Chopim Energética Ltda., the entity that owns the Foz do Chopim Hydroelectric Plant. Silea Participações Ltda. owns the remaining 64.23%. The operation and maintenance of Foz do Chopim Hydroelectric Plant is performed by Copel Geração e Transmissão S.A. Were executed energy supply agreements with Free Costumers at an average tariff of R$202.56/MWh. This Foz do Chopim Energética Ltda also has the authorization to operate SHP Bela Vista, a hydropower plant which is located in the same river and has similar capacity. The process for obtaining the necessary environmental license is ongoing. In 2011, Foz do Chopim’s net revenues and net profits were R$35.1 million and R$29.1 million, respectively, while in 2010 its net revenues and net profits were R$34.2 million and R$28.2 million, respectively.

Expansion of Generating Capacity

We expect to spend R$848.4 million in 2012 to expand our generation capacity, of which R$562.4 million will be invested in the Colíder Hydroelectric Power Plant, R$89.1 million will be invested in the Mauá Hydroelectric Power Plant and R$50.6 million will be invested in the Cavernoso II Small Hydroelectric Power Plant. The remaining amount will be spent on equipment maintenance, the modernization of the Foz de Areia Plant and feasibility studies for the Rio Piquiri and Rio Tibagi plants, among other projects.

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We have interests in several generation projects. The following table sets forth information regarding our planned major generation projects.

Facility

Installed capacity

Estimated

assured energy (1)

Budgeted completion cost

Beginning of operation (expected)

Our ownership

Status

 

(MW)

(GWh/year)

(R$ million)

 

(%)

 

Mauá HPP

361.0

1,732

1,069

2012  

51.0

Concession granted

São Jerônimo HPP

331.0

1,560

1,131

To be determined

41.2

Concession granted

Colíder HPP

300.0

1,573

1,570

2014

100.0

Concession granted

Cavernoso II SHP

19.0

93

120

2012

100.0

Concession granted

São Bento Energia

94.0

418.7

382.4

2013

49.9

Authorization granted

 

(1) Values used to determine volumes committed for sale.

 

Mauá. In October 2006, a consortium in which we hold a 51% stake and Centrais Elétricas do Sul do Brasil S.A. –  Eletrosul (“Eletrosul”) holds a 49% stake was awarded a concession to construct and operate the Mauá Hydroelectric Power Plant on the Tibagi River in the State of Paraná. The Mauá facility will have an installed capacity of 361.0 MW and will be located between the municipalities of Telêmaco Borba and Ortigueira. Construction began on July 21, 2008. From the facility’s assured energy of 197.7 average MW, 192.0 average MW are committed under a 30-year contract to distributors at a price of R$112.96/MWh, as of November 1, 2006, adjusted annually in accordance to the variation of the IPCA inflation index. Due to legal disputes and delays in obtaining environmental authorizations, the initiation of commercial operations has been delayed. We currently expect operations to begin in 2012.  

São Jerônimo. The São Jerônimo Hydroelectric Power Plant will be located between the municipalities of Tamarana and São Jerônimo da Serra on the Tibagi River in the State of Paraná. The plant will have two generation units, with a total installed capacity of 331 MW. It is unclear when the construction of the facility will begin. There are a number of issues that must be resolved before construction can begin, the most significant being that we must obtain permission from the Brazilian Congress to start construction because the future plant’s reservoir will be partially located in an indigenous area.

Colíder. In July 2010, we won an ANEEL auction for a 35-year concession to construct and operate the Colíder Hydroelectric Power Plant on the Teles Pires River in the State of Mato Grosso. The Colíder facility will have an installed capacity of 300.0 MW and will be located in the municipalities of Nova Canaã do Norte, Colíder, Itaúba and Cláudia. Construction began in 2011 and commercial generation is scheduled to begin in 2014. From the facility’s assured energy of 179.6 average MW, since July 1, 2010 125.0 average MW are committed under a 30-year contract to distributors at a price of R$103.40/MWh (adjusted annually in accordance with the IPCA inflation index), with supply starting in January 2015. The remaining 54.6 average MW power not sold under this contract has yet to be contracted for and is still available for sale to large customers in the free market.

Cavernoso II. The Cavernoso II Small Hydroelectric Power Plant will be located in the municipalities of Virmond and Candói on the Cavernoso River in the State of Paraná. Construction began in 2011 and commercial generation is scheduled to begin in 2012. The plant will have 19.0 MW of installed capacity and 10.6 average MW of assured power. At an ANEEL auction in August 1, 2010, at we sold 7.6 average MW of assured power from the Cavernoso II SHP to distributors, at a price of R$146.99/MWh (adjusted annually in accordance with the IPCA inflation index). Supply under these contracts will begin in January 2013 and will continue for 30 years. The remaining 3 average MW power not sold under these contracts has yet to be contracted for and is still available for sale to large customers in the free market.

São Bento Energia. In the last quarter of 2011, we acquired 49.9% of São Bento Energia, Investimentos e Participações, a company that owns four wind farm special purposes entities (GE Olho d´Água, GE Boa Vista, GE Farol e GE São Bento do Norte) located in the State of Rio Grande do Norte, with total installed capacity of 94 MW. In August 2010, an average of 43.7 MW of energy generated at a weighted average price of 134.49/ MW/h (annually adjusted by IPCA index) were sold in ANEEL public auctions. The energy to be generated was sold through 20-year contracts in the auction, term which will begin counting as from September 1, 2013. The wind farms are scheduled to start operating in 2013.

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Cutia Empreendimentos Eólicos. In the last quarter of 2011, we acquired 49.9% of Cutia Empreendimentos Eólicos SPE S.A., with the purpose to participate in the development 5 wind farm projects located in the State of Rio Grande do Norte (Maria Helena, Jangada, Pedra Grande, Cutia e Guajiru), with an indicated capacity of 137.40 MW. This project is in the initial phase of development, and there is currently no estimated date at which the wind farms will become operational.

Proposed Projects

We are involved in various initiatives to study the technical, economic and environmental feasibility of certain hydroelectric generation projects. These proposed generation projects would have a total of 206.2 MW of installed capacity. The following table sets forth information regarding our proposed generation projects.

Hydroelectric Project

Estimated Installed

Capacity

Estimated Assured

Energy

Our ownership

 

(MW)

(GWh/yr)

(%)

SHP BelaVista

29.0

157.4

36

SHP Dois Saltos

25.0

119.1

30

SHP Pinhalzinho

10.9

52.1

30

SHP Burro Branco

10.0

45.1

30

SHP Foz do Turvo

8.8

41.2

30

SHP Foz do Curucaca

29.5

142.2

15

SHP Salto Alemã

29.0

139.7

15

SHP São Luiz

26.0

125.3

15

SHP Alto Chopim

20.3

98.0

15

SHP Rancho Grande

17.7

85.3

15

 

In 2012, we plan to bid for concessions to construct and operate new hydroelectric power plants in power auctions in the regulated market for new generation projects. We are studying the feasibility of our participation in the hydroelectric projects planned to be listed in the “A-5” auctions of 2012. We also will conduct studies of new hydroelectric power plants planned to be constructed on the Piquiri River and the Tibagi River in the State of Paraná.

In addition, we also are conducting studies related to future government auctions for wind farms, in which we may eventually participate. Other renewable energy projects under study or development include the use of municipal solid waste in power generation, cultivation of micro algae for energy production, wind energy, solar photovoltaic energy, energy from the crude vegetable oil and biogas production from micro algae.

Transmission and Distribution

General

Electricity is transferred from power plants to customers through transmission and distribution systems. Transmission is the bulk transfer of electricity from generating facilities to the distribution system by means of the Interconnected Transmission System, in tension greater than or equal to 230 kV. Distribution is the transfer of electricity to Final Customers, in tension lesser or equal to 138 kV.

The following table sets forth certain information concerning our transmission and distribution systems at the dates presented.

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At December 31,

 

2011

2010

2009

2008

2007(1)

Transmission lines (km):

 

 

 

 

 

230 kV and 500 kV

2,016.3

1,900.4

1,929.4

1,822.0

1,822.0

138 kV

7.2

7.2

7.2

7.8

7.8

69 kV(2)

5.4

5.4

5.4

5.4

_

Distribution lines (km):

 

 

 

 

 

230 kV

66.1

66.1

66.1

138 kV

4,705.3

4,586.3

4,578.8

4,495.7

4,290.7

88 kV(3)

58.2

58.2

69 kV

1,003.5

981.5

967.2

1,185.0

1,173.2

34.5 kV

80,662.2

79,496.2

78,357.4

76,903.0

76,524.7

13.8 kV

97,981.0

96,863.6

95,381.6

96,545.7

94,999.7

Transformer capacity (MVA):

 

 

 

 

 

Transmission and distribution substations (69 kV – 500 kV) (4)

19,415.3

18,398.6

18,112.8

17,855.8

16,702.2

Generation (step up) substations

5,006.8

5,006.8

5,004.1

5,004.1

5,004.1

Distribution substations (34.5 kV)

1,539.6

1,533.7

1,507.6

1,624.0

1,624.0

Distribution transformers

9,961.6

9,312.4

8,934.7

8,565.0

8,216.4

Total energy losses

7.1%

7.5%

7.3%

7.3%

7.2%

 

(1) In December 2007, to comply with energy sector legislation, we transferred the assets of Copel Transmissão to Copel Distribuição (69 kV – 138 kV) and to Copel Geração (a small portion of our assets of 138 kV and all our assets of 230 kV and above), changing the name of the latter to Copel Geração e Transmissão.

(2) As approved by ANEEL in 2008, these 69 kV transmission lines held by Copel Distribuição were transferred to Copel Geração e Transmissão, since they were part of our transmission business segment.

(3) Reclassified to 138 kV in 2009.

(4) This figure includes transformers with primary tensions of 69 kV and 138 kV which belong to Copel Distribuição but are implemented in 230 kV and 525 kV substations, which belong to Copel Geração e Transmissão.

 

Transmission

Our transmission system consists of all our assets of 230 kV and greater and a small portion of our 69 kV and 138 kV assets, which are used to transmit the electricity we generate and the energy we receive from other sources. In addition to using our transmission lines to provide energy to customers in the State of Paraná, we also transmit energy through the Interconnected Transmission System. Two companies owned by the federal government, Eletrosul and Furnas Centrais Elétricas S.A. –  Furnas (“Furnas”), also maintain significant transmission systems in the State of Paraná. Furnas is responsible for the transmission of electricity from Itaipu, while Eletrosul’s transmission system links the states in the south of Brazil. Copel, like the other utilities that own transmission facilities, is required to give other parties access to its transmission facilities for compensation at a level set by ANEEL.

The construction of new transmission facilities of 230 kV and higher must be awarded in a bidding process or otherwise authorized by ANEEL. We are permitted by ANEEL to make minor improvements to some of the existing 230 kV and 500 kV facilities.

In June 2010, Copel won a public auction for the construction and operation of two facilities, both located in the State of São Paulo. The first concession is a 356 km transmission line of 500 kV and the second is a 230 kV substation.

In September 2011, SPE Costa Oeste, a consortium between Copel (51%) and Eletrosul (49%), won an ANEEL public auction for the construction and operation of the 143 km Cascavel Oeste - Umuarama transmission line (230 kV) and the Umuarama substation (230/138 kV), both located in the State of Paraná. The consortium is currently managing the process of obtaining all necessary licenses for the beginning of the transmission line construction.

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In December 2011, we concluded the construction of 115 km of 500 kV transmission lines to connect the municipalities of Foz do Iguaçu and Cascavel.

In December 2011, consortia among Copel, Eletrosul and Elecnor won part of a large ANEEL public auction for the construction and operation of transmission assets. The lots won by the consortia is for the construction and operation of a total of 1,327 km of new transmission lines and four new substations in the States of Paraná, Santa Catarina, Rio Grande do Sul and Maranhão.

In March 2012, Copel, together with State Grid Brazil Holding, won an ANEEL public auction for the construction and operation of 1,605 km of new transmission lines and four new substations that will transmit energy produced by five new hydroelectric plants that are planned to be constructed in Teles Pires River, in the North of Mato Grosso State, to the Southeast region of Brazil.

Distribution

Our distribution system consists of a widespread network of overhead lines and substations with voltages up to 138 kV and a small portion of our 230 kV assets. Higher voltage electricity is supplied to bigger industrial and commercial customers and lower voltage electricity is supplied to residential, small industrial, commercial customers and other customers. At December 31, 2011, we provided electricity in a geographic area encompassing approximately 98% of the State of Paraná and served 3.9 million customers.

Our distribution network includes 184,418.1 km of distribution lines, 364,920 distribution transformers and 235 distribution substations of 34.5 kV, 35 substations of 69 kV and 87 substations of 138 kV. During 2011, 157,535 new customers were connected to our network, including customers connected through the rural and urban electrification programs. We are continuing to implement compact grid design distribution lines in urban areas where there is a large concentration of trees in the vicinity of the distribution grid.

We have 45 customers that are directly supplied with energy at a high voltage (69 kV and above) through connections to our distribution lines. These customers accounted for approximately 6.9% of the total volume of electricity sold by Copel Distribuição or 3.3% of our total volume of electricity sold in 2011.

We are responsible for expanding the 138 kV and 69 kV distribution grid within our concession area.

System Performance

We determine the energy losses of our distribution system separately from those of our transmission system. The total losses from our distribution system are calculated by taking the difference between the energy allocated to the system and the energy supplied to the customers.

Our energy losses totaled 7.1% of our available energy in 2011 and include losses from the basic transmission grid and Itaipu.

Information regarding the duration and frequency of outages for our customers is set forth in the following chart for the years indicated.

 

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Year ended December 31,

Quality of supply indicator

2011

2010

2009

2008

2007

DEC – Duration of outages per customer per year (in hours)

10h38min

11h28min

12h55min

12h11min

13h32min

FEC – Frequency of outages per customer per year (number of outages)

8.26

9.46

11.04

10.69

12.41

 

We outperformed the quality target indicators established by ANEEL for 2011, which penalize power outages (i) in excess of an average number of hours per customer and (ii) in excess of an average frequency of outages, in each case calculated on an annual basis. These limits vary depending on the geographic region, and the average limit established by ANEEL for our distribution company was 13.53 hours of outages per customer per year, and a total of 11.94 outages per customer per year. Failure to comply with these predetermined standards with a final customer results in a reduction of the amount we can charge such final customers in future periods.

In addition, quality target indicators are taken into consideration by ANEEL during distribution concession renewal proceedings, and also influence ANEEL’s calculation of our tariff adjustments. For more information, see “Distribution Tariffs.”

Purchases

The following table contains information concerning volume, costs and average tariffs for the main sources of the electricity we purchased in the last three years.

Source:

2011

2010

2009

Itaipu

 

 

 

Volume (GWh)

5,278

5,306

5,379

Cost (R$ millions)

459.6

468.3

521.0

Average tariff (R$/MWh)

87.1

88.3

96.9

Auctions in the regulated market

 

 

 

Volume (GWh)

17,027

15,418

14,514

Cost (R$ millions) (1)

1,570.1

1,370.3

1,184.9

Average tariff (R$/MWh)

92.2

88.9

81.6

 

(1) These numbers do not include short-term energy purchased through the Electric Energy Trading Chamber ‒ CCEE.

Itaipu

We purchased 5,278 GWh of electricity from Itaipu in 2011, which constituted 9.9% of our total available electricity in 2011 and 19.9% of Copel Distribuição’s total available electricity in 2011. Our purchases represented approximately 5.7% of Itaipu’s total production. Distribution companies operating under concessions in the Midwest, South and Southeast regions of Brazil are required by law to purchase Brazil’s portion of the energy generated by Itaipu in a proportion that correlates with the volume of electricity that they provide to customers. The rates at which these companies are required to purchase Itaipu’s energy are fixed to cover Itaipu’s operating expenses and payments of principal and interest on Itaipu’s U.S. dollar-denominated borrowings, as well as the cost of transmitting the power to their concession areas. These rates are denominated in U.S. dollars, and have been set for 2012 at US$24.88 per kW per month.

In 2011, we paid an average tariff of R$87.1 per MWh for energy from Itaipu, compared to R$88.3 per MWh during 2010. These figures do not include the transmission tariff that distribution companies must pay for the transmission of energy from Itaipu.

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Auctions in the Regulated Market

In 2011, we purchased 17,027GWh of electricity through auctions in the regulated market. This energy represents 64.2% of the total electricity we purchased. For more information on the regulated market and the free market, see “The Brazilian Power Industry - The New Industry Model Law.”

Sales to Final Customers

During 2011, we supplied approximately 97% of the energy distributed directly to captive customers in the State of Paraná. Our concession area includes 3.9 million customers located in the State of Paraná and in one municipality in the State of Santa Catarina, located south of the State of Paraná. We also sold energy to a total of 8 Free Customers, one of which was located outside of our concession area. During 2011, the total power consumption of our captive customers and Free Customers was 23,373 GWh, a 4.5% increase as compared to 22,359 GWh during 2010. The following table sets forth information regarding our volumes of energy sold to different categories of purchasers for the periods indicated.

Year ended December 31,

Categories of purchaser

2011

2010

2009

2008

2007

 

(GWh)

Industrial customers

8,377

8,146

7,748

7,955

7,740

Residential

6,224

5,925

5,664

5,379

5,143

Commercial

4,778

4,466

4,200

3,967

3,722

Rural

1,872

1,774

1,680

1,606

1,522

Other(1)

2,123

2,048

1,994

1,911

1,858

Total(2)

23,374

22,359

21,286

20,818

19,985

 

(1)  Includes public services such as street lighting, electricity supply for municipalities and other governmental agencies, as well as our own consumption.

(2)  Total GWh does not include our energy losses.

 

The following table sets forth the number of our Final Customers in each category at December 31, 2011.

Category

Number of Final Customers

Industrial

80,778

Residential

3,089,619

Commercial

319,668

Rural

374,819

Other(1)

52,058

Total

3,916,942

 

(1)  Includes street lighting, as well as electricity for municipalities and other governmental agencies, public services and own consumption.

 

Industrial and commercial customers accounted for approximately 31% and 22%, respectively, of our total revenues from energy sales during 2011. In 2011, 33% of our total revenues from energy sales were from sales to residential customers.

Tariffs

Retail Tariffs. We classify our customers in two groups (“Group A Customers” and “Group B Customers”), based on the voltage level at which electricity is supplied to them and on whether they are considered as industrial, commercial, residential or rural customers. Each customer falls within a certain tariff level defined by law and based on the customer’s classification, although some flexibility is available according to the nature of each customer’s demand. Under Brazilian regulation, low voltage customers such as residential customers (other than Low Income Residential Customers, as defined below) pay the highest tariff rates, followed by 13.8 kV and 34.5 kV voltage customers, usually commercial customers and 69 kV and 138 kV voltage customers, usually industrial customers.

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Group A Customers receive electricity at 2.3 kV or higher and the tariffs applied to them are based on the actual voltage level at which energy is supplied and the time of year and the time of day the energy is supplied. Tariffs are comprised 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 and (ii) power capacity actually used. The energy charge, expressed in reais per MWh, is based on the amount of electricity actually consumed as evidenced by our metering.

Group B Customers receive electricity at less than 2.3 kV, and the tariffs applied to them are comprised solely of an energy charge and are based on the classification of the customer.

ANEEL modifies our tariffs annually, generally in June. For more information about the distribution tariff adjustments that have been made by ANEEL in recent years, see “Item 5. Operating and Financial Review and Prospects - Overview - Rates and Prices.”

The following table sets forth the average tariffs for each category of Final Customer in effect in 2011 and 2010.

Tariffs

2011

2010

2009

 

(R$/MWh)

Industrial

170.41

159.24

148.67

Residential

250.25

233.78

221.07

Commercial

217.78

202.68

191.35

Rural

154.29

143.04

134.80

Other customers

167.83

156.07

145.62

All Final Customers

199.83

186.09

174.98

 

Low Income Residential Customers. Under Brazilian law, we are required to provide discounted rates to certain low income residential customers (“Low Income Residential Customers”). In 2011, we served 356,844 low income residential customers. For servicing these customers, in 2011 we received a R$70.6 million grant, which was approved by ANEEL, from the Brazilian Federal Government.

The following table sets forth the current minimum discount rates approved by ANEEL for each category of Low Income Residential Customer.

Consumption

Discount from base tariff

Up to 30 kWh per month

65%

From 31 to 100 kWh per month

40%

From 101 to 220 kWh per month

10%

 

Special Customers. A customer of our distribution business that consumes at least 500 kV (a “Special Customer”) may choose its energy supplier if that supplier derives its energy from alternative sources, such as small hydroelectric plants, wind plants or biomass plants. A Special Customer that chooses to purchase energy from a supplier other than Copel Geração e Transmissão continues to use our distribution system and pay our distribution tariff. However, as an incentive for Special Customers to purchase from alternative sources, we are required to reduce the tariff paid by Special Customers by 50%. This discount does not impact the revenues of our distribution business, since ANEEL allows us to increase the tariffs of our other distribution customers to compensate for this discount.

Transmission Tariffs. A transmission concessionaire is entitled to annual revenues based on the transmission network it owns and operates. These revenues are annually readjusted according to criteria stipulated in the concession contract. We are directly a party to six transmission concession contracts, four of which are in the operational stage and two of which are in construction. Not all of the transmission concession contracts employ the same revenue model.

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Under our main transmission concession, which involves our main transmission facilities and accounted for 94% of our gross transmission revenues in 2011, 38% of the transmission revenues are updated on an annual basis by the IGPM and the other 62% are subject to the tariff review process.

The first periodic revision related to our main transmission concession scheduled for 2005 was only carried out in 2007, at which point ANEEL reduced the tariffs we receive by 15.08%. This adjustment was applied retroactively to July 2005, and was passed on to our Final Customers until June 2009. The remainder of our annual revenues was subject to adjustment by IGP-M or IPCA, as applicable.

In addition, we have five concession agreements for transmission lines and substations, which correspond to an aggregate of 8% of our transmission revenues. Under one of these agreements, the revenues are updated on an annual basis by the IGPM and the revenues are not subject to the tariff review process, but the annual revenue will be reduced in 50% from the 16 year on, as of 2016. The other four agreements revenues are subject to the tariff review process.

In 2010, the transmission tariffs of two of our contracts were readjusted by the IGPM, resulting in an increase of 4.2% and one was readjusted by the IPCA, and has increased by 5.2%. In addition, in July 2010 pursuant to a second periodic revision of our principal concession, ANEEL granted provisional approval of a reduction in our transmission tariff by 22.88%, applied to the revenues of new installations in the Interconnected Transmission System, and applied retroactively from July 1, 2009 onward. In June 2011, ANEEL reviewed the figures of the second periodic revision and changed the annual revenues reduction to 19.94%.

Other Businesses

Telecommunications

Copel Telecomunicações S.A. Pursuant to an authorization from the Brazilian National Telecommunication Agency, Agência Nacional de Telecomunicações (“ANATEL”), we provide corporate telecommunication services within the State of Paraná and international long-distance services. We have been offering these services since August 1998 through the use of our fiber optics network (totaling 21.8 thousand km of fiber optic cables by the end of 2011). In 2011, we served 302 of the 399 municipalities in the State of Paraná and two additional municipalities in the State of Santa Catarina. In addition to our commercial services, we have also been involved in an educational project aimed at providing public elementary and middle schools in the State of Paraná with broadband Internet access.

We provide services to most of the major Brazilian telecommunication companies that operate in the State of Paraná. In total, we have 1,442 corporate clients, which include supermarkets, universities, banks, internet service providers and television networks. We also provide a number of different telecommunication services to our subsidiaries.

Sercomtel. We own 45.0% of the stock of Sercomtel Telecomunicações S.A. and Sercomtel Celular S.A. (together, “Sercomtel”). Sercomtel holds concessions to provide fixed and mobile telephone services in the municipalities of Londrina and Tamarana in the State of Paraná and has obtained ANATEL’s authorization to provide telephone services to all other cities in the State of Paraná. Currently, Sercomtel operates under an authorization regime in the cities of Cambé, Ibiporã and Arapongas. The city of Rolândia has been serviced since April 2009, and the cities of Apucarana and Maringá have been served since November 2008 and May 2010, respectively. Sercomtel has concessions from ANATEL to provide cable television in São José in the State of Santa Catarina and Osasco in the State of São Paulo and radio-wave television transmission in Maringá in the State of Paraná.

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The merger of Sercomtel Celular S.A. into Sercomtel S.A. Telecomunicações is currently ongoing. This transaction aims to reduce costs and to potentially generate higher revenues by offering complementary services to customers (for example, landlines, mobile phones, broadband internet and television).

As of December 31, 2011, Sercomtel Telecomunicações, in its concessions area for fixed telephone services, had a total of 231,746 telephone lines installed, of which 186,751 were in operation. As of December 31, 2011, Sercomtel Celular had an installed capacity of 105,115 terminals in its Global System for Mobil Communications (“GSM”) system, of which 76,098 were in operation. In December 2009, Sercomtel started providing 3G services with a capacity of 20,000 lines, of which 4,726 are currently installed. Sercomtel Telecomunicações’  2011 net revenues were R$138.6 million, with net loss of R$4.7 million, and Sercomtel Celular’s 2011 net revenues were R$27.1 million, with net income of R$2.4 million. As of December 31, 2011, our investment in Sercomtel Telecomunicações was R$70.3 million.

Water and Sewage

In January 2008, Copel bought the 30% stake in Dominó Holdings S.A. (“Dominó Holdings”) held by Sanedo Ltda., a wholly-owned subsidiary of Grupo Veola, for R$110.2 million. We now own 45.0% of the total outstanding share capital of Dominó Holdings, which in turn owns 39.7% of the voting stock or 34.7% of the total capital of Companhia de Saneamento do Paraná –  Sanepar (“Sanepar”), a public utility company that provides 345 urban and rural municipalities and approximately 9.5 million people in the State of Paraná with water distribution services and 6.0 million with sewage services. The State of Paraná owns 60.0% of the outstanding voting capital of Sanepar. Dominó Holdings’ net income in 2011 was R$81.3 million. The other shareholders of Dominó Holdings are Andrade Gutierrez Concessões S.A. and Daleth Participações S.A., each with 27.5%.

Gas

We are engaged in the distribution of natural gas through Companhia Paranaense de Gás (“Compagas”), the company that holds the exclusive rights to supply piped gas in the State of Paraná. Compagas’s customers include thermoelectric plants, cogeneration plants, gas stations, other businesses and residences. Compagas is focusing its business strategy on marketing the benefits of substituting gas for fuel oil and other fuels as a means of achieving greater energy efficiency, as well as on enhancing its market share.

As of December 31, 2011, we owned 51.0% of the capital stock of Compagas and accounted for this interest through consolidation, since we control this company. The minority shareholders of Compagas are Petrobras and Mitsui Gas, each of which owns 24.5% of the capital stock of Compagas.

Compagas recorded an increase of 4.9% in the volume of natural gas distributed, from 960,681 cubic meters per day in 2010 to 1,007,324 cubic meters per day in 2011. Its number of customers increased 29.5%, from 9,288 in 2010 to 12,025 in 2011. In 2011, Compagas distributed 16.0 million cubic meters to the Araucária Thermoelectric Plant a decrease of 93.7%. Demand from the Araucária Thermoelectric Plant decreased because sufficient energy was being provided by hydroelectric power plants in Brazil. Compagas owns a gas distribution network in the State of Paraná, covering 574 kilometers in 2011, an increase from the 546 kilometers covered in 2010. In 2011, Compagas’s net revenues were R$291.4 million, an increase of 8.8%, and its net income was R$32.4 million, a reduction of 20.0%.

Services

We own 40.0% of the share capital of ESCO Electric Ltda. (“ESCO”), a company that assists customers with their electricity needs through the provision of consulting services, planning and project implementation, automation services, operation, maintenance, training and technical assistance. The Instituto de Tecnologia para o Desenvolvimento – LACTEC owns the remaining 60.0% of the share capital. ESCO also markets products and services aimed at obtaining greater energy efficiency and energy conservation. During 2011, ESCO recorded a net loss of R$0.1 million. All operations of this company were discontinued in 2008 and we expect it to be liquidated during 2012.

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Concessions

We operate under concessions granted by the Brazilian government for our generation, transmission and distribution businesses.

In the generation segment, as from 2003 there is no longer any practical difference between a concessionaire and an independent producer. However, all concession agreements that were in effect prior to 2003 establish that the concessionaire has the right to renew the contract for an additional 20-year period. Concessions granted to independent producers between 1995 and 2003 can be renewed for an additional 20 years at ANEEL’s discretion, a process which can no longer be carried out with generation concessions granted after 2003, as is the case with the Mauá Hydroelectric Plant. After the final expiration date of a generation concession, as indicated in the table below, the concession will be subject to a competitive bidding process.

In the transmission and distribution segments, for the concessions auctioned after 1995, concessionaires have the right to request for their concessions agreements to be renewed for an additional period of 35 years. Our distribution and our main transmission concessions were auctioned before 1995 and renewed in 1995. Although these concessions expire in 2015 and are by their terms renewable for an additional 20 years, we are not assured of our ability to effectively renew these concessions due to uncertainty surrounding the renewal process. For more details see Note 7 to our consolidated financial statements.

Generation

Since 1999, 13 of our generation plants have had their concessions extended by Brazilian authorities, in each case for the 20-year term allowed by law. According to applicable law, these concessions are not eligible for a second extension. For each of our generation facilities for which the concession has not yet been extended, we will have the option to request a 20-year extension. The Rio dos Patos renewal was requested in January 2011 and the Marumbi renewal request is currently being reviewed by ANEEL.

Concessions for new generation projects, granted after 2003, such as the Mauá Hydroelectric Plant, are non-renewable, meaning that upon expiration, a further concession will be granted pursuant to a competitive bidding process.

The following table sets forth information relating to the terms as well as the renewals of our main generation concessions.

Hydroelectric Plants

Initial concession date

First expiration date

Extension date

Final expiration date

Foz do Areia

May 1973

May 2003

January 2001

May 2023

São Jorge

December 1974

December 2004

April 2003

December 2024

Apucaraninha

October 1975

October 2005

April 2003

October 2025

Guaricana

August 1976

August 2006

August 2005

August 2026

Chaminé

August 1976

August 2006

August 2005

August 2026

Segredo

November 1979

November 2009

September 2009

November 2029

Derivação do Rio Jordão

November 1979

November 2009

September 2009

November 2029

Salto Caxias

May 1980

May 2010

September 2009

May 2030

Cavernoso

January 1981

January 2011

September 2009

January 2031

Rio dos Patos

February 1984

February 2014

Renewal requested in January 2011. Still under ANEEL analysis.

If renewed, likely February 2044.

Capivari Cachoeira

April 1965

May 1995

June 1999

July 2015

Mourão

January 1964

January 1994

June 1999

July 2015

Chopim I

March 1964

March 1994

June 1999

July 2015

Figueira

March 1969

March 1999

June 1999

March 2019

Marumbi

March 1956

Under review by ANEEL

Under review by ANEEL

Under review by ANEEL

In addition to the concessions set forth in the table above, we have also been granted generation concessions for the Cavernoso II and Colíder Hydroelectric Plants, which are still under construction but are expected to begin operations in January 2013 and January 2015, respectively.

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We have ownership interests in five other generation projects, through generation partnerships established with certain other companies. The following table sets forth information relating to the terms of the concessions of the other generation plants in which we had an ownership interest as of December 31, 2011.

Generation Facility

Consortium

Initial concession date

Expiration date

Extension

Dona Francisca

Dona Francisca Energética SA ‒ DFESA

July 1979

August 2033

Possible

Santa Clara and Fundão

Elejor

October 2001

October 2036

Possible

Araucária

UEG Araucária Ltda.

December 1999

December 2029

Possible

Foz do Chopim

Foz do Chopim Energética

April 2000

April 2030

Possible

São Bento

São Bento Energia

August 2010

August 2030

Not Possible

Mauá

Consórcio Energético Cruzeiro do Sul

June 2007

July 2042

Not Possible

 

Transmission

Under our transmission concession contracts, we have the right to request 30-year extensions of the concessions from ANEEL, provided that such request is delivered within 36 months prior to the expiration of the contract in question. Our principal transmission concession, which corresponds to 92% of our transmission revenues, expires on July 7, 2015, and may not be renewed.

In addition, we have three other concession agreements for transmission lines and substations that are currently in operation, which correspond to an aggregate of 8% of our transmission revenues, which can be approved for an additional 30 years. We plan on applying for, and receiving, extensions for all of our transmission concessions, which may be renewed for an additional 30 years.

The following table sets forth certain information relating to the terms and renewal of our main transmission concessions:

Transmission

Facility

Initial concession

date

First expiration

Date

Possibility of extension

Expected final expiration date

Main transmission concession

July 2001

July 2015

Possible (1)

July 2035

Bateias – Jaguariaíva Transmission Line

August 2001

August 2031

Possible

August 2061

Bateias – Pilarzinho Transmission Line

March 2008

March 2038

Possible

March 2068

Foz do Iguaçu – Cascavel Oeste Transmission Line

November 2009

November 2039

Possible

November 2069

Araraquara 2 – Taubaté (2)

October 2010

October 2040

Possible

October 2070

Cerquilho III(2)

October 2010

October 2040

Possible

October 2070

 

(1) Although the concession contract contains a clause allowing for its extension, the Federal Government of Brazil is considering disallowing such extension for all such concession contracts granted prior to 1995.

(2) Facility under construction.

Distribution

We operate our distribution business pursuant to a concession granted to us on June 24, 1999, which expires on July 7, 2015. We will have the right to request a 20-year extension of this concession from ANEEL, 36 months prior to its expiration according to the concession agreement.

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Competition

We have concessions to distribute electricity in substantially all of the State of Paraná, and we do not face competition from the five utilities that have been granted concessions for the remainder of the state. As a result of legislation passed in 2004, however, other suppliers are able to offer electricity to our existing Free Customers at prices lower than those we currently charge. However, when a captive customer becomes a Free Customer, it is still required to pay to use our distribution system. The reduction in net revenue of our distribution business is therefore compensated with a reduction in our costs for energy that we would otherwise acquire to sell to these customers.

Furthermore, under certain circumstances, Free Customers may be entitled to connect directly to the Interconnected Transmission System rather than our distribution system. Unlike a Free Customer’s choice of another energy supplier, in which case that customer must still use our distribution network and thus pay us the appropriate tariff, our distribution business ceases to collect tariffs from a customer that connects directly to the Interconnected Transmission System. The migration of customers from the distribution network to the transmission network therefore results in the loss of revenues for our distribution business.

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.

Free Customers are limited to:

  • existing customers (those connected to the distribution network before July 1995) with demand of at least 3 MW and supplied at voltage levels equal to or greater than 69 kV;

  • new customers (those connected to the distribution network after July 1995) with demand of at least 3 MW at any voltage; and

  • customers with demand of at least 500 kW that opt to be supplied energy by means of alternative sources, such as wind power projects, small hydroelectric power plants or biomass projects.

As of December 31, 2011, we had eight Free Customers, representing approximately 1.3% of our consolidated operating revenue and approximately 1.9% of the total quantity of electricity sold by us. Through February 2012, we have reached agreements with four additional Free Customers, three of which were our previously captive customers. Our contracts with Free Customers are typically for periods of greater than two and less than five years.

Approximately 38% of the megawatts sold under contracts to such customers are set to expire in 2012. In addition, as of December 31, 2011, we had 42 customers that were eligible to purchase energy as Free Customers. These customers represented approximately 7.7% of the total volume of electricity we sold in 2011, and approximately 4.5% of our total operating revenue from energy sales for that year.

In the generation business, any producer may be granted a concession to build or manage thermoelectric and small hydroelectric generating facilities in the State of Paraná. Brazilian law provides for competitive bidding for generation concessions for hydroelectric facilities with capacity higher than 30 MW.

In the transmission business, Brazilian law provides for competitive bidding for transmission concessions for facilities with voltage of 230 kV or greater that will form part of the Interconnected Transmission System.

Brazilian law requires that all of our generation, transmission and distribution concessions be subject to a competitive bidding process upon their expiration. We intend to apply for the extension of each concession 36 months prior to its expiration. We may face significant competition from third parties in bidding for renewal of such concessions or for any new concessions. The loss of certain concessions could adversely affect our results of operations.

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    Environment

    Our construction and operation activities for the generation, transmission and distribution of electric energy, distribution of natural gas and our telecommunications operations are subject to federal, state and municipal environmental regulations.

    All of our activities are subject to our Sustainability and Corporate Citizenship Policy, which integrates corporate planning and sustainability management in order to optimize our financial, social and environmental performance.

    We renew our environmental licenses in accordance with the procedures of the competent Brazilian environmental authorities. We are in compliance with all material environmental regulations and our more recent (post-1986) generation, transmission and distribution projects are in compliance with federal, state and municipal regulations. To remedy compliance issues for environmental licenses of transmission facilities predating the 1986 environmental licensing requirements, Copel initiated negotiations in 2009 with the environmental regulator for the State of Paraná (the “Instituto  Ambiental do Paraná – IAP”). 

    In 2011, fifteen compulsory environmental audits (Auditorias Ambientais Compulsórias – AACs) were performed, four of which were of Hydroelectric Plants (Salto Caxias, Segredo, Foz de Areia and Guaricana), five of which were of Small Hydroelectric Plants (Chopim I, Pitangui, Chaminé, Rio dos Patos and Marumbi), three of which were of our 230 kV transmission lines (Bateias-Pilarzinho, HPP GPS-Posto Fiscal and Posto Fiscal-Uberaba), two of which were in 138 kV transmission lines (Apucarana-Cristo Rei and Cristo Rei-Mandaguari) and one of which was in a transmission substation (SE 230 kV Posto Fiscal). These compulsory environmental inspections are required by law as a condition for the renewal of environmental licenses. These inspections also allow us to obtain an independent assessment of our environmental policies and compliance with laws and regulations.

    The construction of Cavernoso II Small Hydroelectric Plant began in April 2011. To comply with all the requirements of the environmental authorities necessary for the licensing of the project, we drafted a Basic Environmental Plan (Plano Básico Ambiental – PBA), consisting of sixteen social and environmental programs, which are in the process of implementation.

    In December 2010, we received the site licenses to begin construction of the Colíder Hydroelectric Plant. These licenses were granted after we received approval of Colíder Basic Environmental Plan, which contains thirty-two programs and sub-programs designed to prevent, mitigate and offset any negative environmental and social impact of this project, while enhancing the positive effects of the project.

    We are involved in environmental and social programs including the “Education for Sustainability” (Educação para a Sustentabilidade) program and the “Social and Environmental Reservoirs Management Program” (Programa de Gestão Socioambiental de Reservatórios).  

    The goal of our socio-environmental education for sustainability programs is to promote discussion and raise awareness toward daily sustainability, processes and activities developed by the Company in its daily relations, emphasizing that each individual is an agent of transformation, responsible for cultural change at Copel and society.

    The Social and Environmental Reservoirs Management Program aims to improve the quality and availability of water in Copel’s reservoirs through managing and monitoring of watersheds

    To reinforce our commitment to environmental, social and economic sustainability, we are signatories to the United Nations Global Compact, and we actively seek to implement the principles of the Global Compact in our daily activities and our corporate culture.

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    Plant, Property and Equipment

    Our principal properties consist of the generation and telecommunications facilities described in “Business - Generation and Purchasers of Energy”. Of the net book value of our total property, plant and equipment at December 31, 2011 (including construction in progress), generation facilities represented 82.8%, telecommunications represented 3.8%, Elejor represented 6.9% and Araucária Thermoelectric Plant represented 6.5%. We believe that our facilities generally are adequate for our present needs and suitable for their intended purposes.

    The Expropriation Process

    Although we receive concessions from the Brazilian government to construct hydroelectric facilities, we do not receive title to the land on which the facilities are to be located. In order for us to construct, the land must be expropriated. The land required for the implementation of a hydroelectric facility may only be expropriated pursuant to specific legislation. We generally negotiate with communities and individual owners occupying the land so as to resettle such communities in other areas and to compensate individual owners. Our policy of resettlement and compensation generally has resulted in the settlement of expropriation disputes. At December 31, 2011, we estimated our liability related to the settlement of such disputes to be approximately R$30.3 million. This amount is in addition to amounts for land expropriation included in each of our hydroelectric facility budgets.

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    The Brazilian eLECTRIC Power Industry

    General

    In November 2010, the MME approved a ten-year expansion plan under which Brazil’s installed power generation capacity is projected to increase to 167.0 GW by 2019, of which 70.0% is projected to be hydroelectric, 15.0% is projected to be thermoelectric, 2.0% is projected to be nuclear and 13.0% is projected to be from alternative energy sources such as wind, biomass and small hydroelectric plants.  

    Approximately 36% of the installed power generating capacity of Brazil is currently owned by Eletrobras (including its wholly-owned subsidiary Eletronuclear and its 50.0% participation interest in Itaipu). Through its subsidiaries, Eletrobras is also responsible for 56% of the installed transmission capacity equal or above 230 kV within Brazil. In addition, some Brazilian states control entities involved in the generation, transmission and distribution of electricity. They include Companhia Energética de São Paulo – CESP, Companhia Energética de Minas Gerais – CEMIG and us, among others.

    Principal Regulatory Authorities

    Ministry of Mines and Energy – MME

    The MME is the primary regulator of the power industry and acts as the Brazilian governmental authority empowered with policymaking, regulatory and supervisory powers.

    National Energy Policy Council – CNPE

    The National Energy Policy Council (Conselho Nacional de Política Energética) (“CNPE”), council created in August 1997, provides advice to the President of the Republic of Brazil regarding the development and creation of a national energy policy. The CNPE is chaired by the MME and is composed of six ministers of the Federal Government and three members chosen by the President of Brazil. The CNPE was created in order to optimize the use of energy resources in Brazil and ensure the national supply of electricity.

    National Electric Energy Agency – ANEEL

    The Brazilian power industry is regulated by ANEEL, an independent federal regulatory agency. ANEEL’s primary responsibility is to regulate and supervise the power industry in accordance with the policies set forth by the MME and to respond to matters which are 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 utilization of energy sources, including the use of hydroelectric power, (iv) promoting, monitoring and managing the public bidding process for new concessions, (v) settling administrative disputes among electricity sector entities and electricity purchasers, and (vi) defining the criteria and methodology for the determination of transmission and distribution tariffs.

    National Electric System Operator – ONS

    The ONS (Operador Nacional do Sistema Elétrico) is a non-profit, private entity comprised of electric utilities engaged in the generation, transmission and distribution of electric energy, in addition to other private participants such as importers, exporters and Free Customers. The primary role of the ONS is to coordinate and regulate the generation and transmission operations in the Interconnected Transmission System, subject to the ANEEL’s regulation and supervision. The objectives and principal responsibilities of the ONS include, among others, operational planning for the generation industry, organizing the use of the domestic Interconnected Transmission System and international interconnections, ensuring that industry participants 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 Interconnected Transmission System, and formulating regulations regarding the operation of the transmission system for ANEEL’s approval.

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    Electric Energy Trading Chamber – CCEE

    The CCEE (Câmara de Comercialização de Energia Elétrica) is a non-profit, private entity subject to authorization, inspection and regulation by ANEEL. The CCEE is responsible for, among other things, (i) registering all energy purchase agreements in the regulated market, Contratos de Comercialização de Energia no Ambiente Regulado (“CCEAR”), and registering the agreements resulting from market adjustments and the volume of electricity contracted in the free market, and (ii) accounting for and clearing short-term transactions. The CCEE is composed of holders of concessions, permissions and authorizations in the electricity industry and Free Customers, and its board of directors is composed of four members appointed by these agents and one by the MME, who is the chairman of the board of directors.

    Energy Sector Monitoring Committee – CMSE

    The CMSE (Comitê de Monitoramento do Setor Elétrico) was created by the New Industry Model Law to monitor service conditions and to recommend preventative measures to ensure energy supply adequacy, including demand-side action and contracting of energy reserves.

    Energy Research Company – EPE

    On August 2004, the Brazilian government created the Energy Research Company (Empresa de Pesquisa Energética) ("EPE"), a federal public company responsible for conducting strategic studies and research in energy sector, including the industries of electric power, petroleum, natural gas, coal and renewable energy sources. The studies and research conducted by the EPE subsidize the formulation of energy policy by the MME.

    Eletrobras

    Eletrobras serves as a holding company for the following federally-owned energy companies: Companhia Hidro Elétrica do São Francisco – CHESF, Furnas, Eletrosul, Centrais Elétricas do Norte do Brasil S.A. – Eletronorte, Companhia de Geração Térmica de Energia Elétrica – CGTEE and Eletrobras Termonuclear S.A. –  Eletronuclear. Eletrobras manages funds generated by some of the regulatory charges, as well as the commercialization of energy from Itaipu and from alternative energy sources, under the Proinfa Program.

    Historical Background of Industry Legislation

    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. Since 1995, the Brazilian government has taken a number of measures to reform the Brazilian electric energy industry. in general, these measures were aimed at increasing the role of private investment and eliminating foreign investment restrictions in order to increase overall competition and productivity in the industry.

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    The following is a summary of the principal developments in the regulatory and legal framework of the Brazilian electricity sector:

    • In 1995: (i) the Brazilian constitution was amended to authorize foreign investment in power generation; (ii) the Concessions Law was enacted, requiring that all concessions for energy related services be granted through public bidding processes, providing for the creation of independent producers and Free Customers and granting electricity suppliers and Free Customers open access to all distribution and transmission systems; and (iii) a portion of the controlling interests held by Eletrobras and various Brazilian states in generation and distribution companies were sold to private investors.

    • In 1998, the Power Industry Law was enacted, providing for, among other things, the creation of the ONS and the appointment of BNDES as the financing agent of the power industry, especially to support new generation projects.

    • In 2001, Brazil faced a serious energy crisis that lasted through February 2002. During this period, the Brazilian government implemented an energy-rationing program in the most adversely affected regions, namely the southeast, central-west and northeast regions of Brazil. In April 2002, the Brazilian government for the first time implemented the extraordinary tariff readjustment to compensate the electricity suppliers for financial losses incurred as a result of the rationing period.

    • In 2004, the Brazilian government enacted the New Industry Model Law, in an effort to further restructure the power industry with the ultimate goal of providing customers with a stable supply of electricity at reasonable prices.

    Concessions

    The companies or consortia that wish to build or operate facilities for generation, transmission or distribution of electricity in Brazil must participate in a competitive bidding process or must apply to the MME or to ANEEL for a concession, permission or authorization, as the case may be. Concessions grant rights to generate transmit or distribute electricity in a specific concession area for a specified period. 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, except in some specific cases provided by law.

    The Concessions Law establishes, among other things, the conditions that the concessionaire must comply with when providing electricity services, customers’ rights and the respective rights and obligations of the concessionaire and the granting authority. In addition to the Concessions Law, the concessionaire must also comply with the general regulations governing the electricity sector. The main provisions of the Concessions Law and related ANEEL regulations are summarized as follows:

    Adequate service. The concessionaire must render adequate service to all customers in its concession and must maintain certain standards with respect to regularity, continuity, efficiency, safety and accessibility.

    Use of land. The concessionaire may use public land or request that the granting authority expropriate necessary private land for the benefit of the concessionaire. In the latter case, the concessionaire must 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 the concessionaire’s controlling interest.

    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 the full compliance with applicable contractual and regulatory provisions. Within 30 days of such a decree, the granting authority’s representative must commence an administrative proceeding in which the concessionaire is entitled to contest the intervention. During the term of the administrative proceeding, the granting authority shall appoint a third party to manage the concession. If the administrative proceeding is not completed within 180 days of the issuance of the decree, the intervention will be stopped and the concession will be 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 has not yet expired.

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      Termination of the concession. The termination of the concession agreement may occur by means of expropriation and/or forfeiture. Expropriation is the early termination of a concession for reasons related to the public interest. An expropriation must be specifically approved by law or decree. 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 comply with an 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.

      A concession agreement may also be terminated (i) through the mutual agreement of the parties, (ii) upon the bankruptcy or dissolution of the concessionaire, or (iii) following a final, non-appealable judicial decision rendered in a proceeding filed by the concessionaire.

      When a concession agreement is terminated, all assets, rights and privileges that are materially related to the rendering of electricity services revert to the Brazilian government. Following termination, the concessionaire is entitled to indemnification for its investments in assets that have not been fully amortized or depreciated, after deduction of any amounts due by the concessionaire related to fines and damages.

      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 electricity sector participants and determine the appropriate penalties based on the nature and importance of the breach (including warnings, fines, temporary suspension from the right to participate in bidding procedures for new concessions, licenses or authorizations and forfeiture). For each infraction, the fines can be up to 2% of the revenue (net of value-added tax and services tax) of the concessionaire in the 12-month period preceding any penalty notice. Some infractions that may result in fines relate to the failure to request ANEEL’s approval to, among other things: (i) execute certain contracts between related parties; (ii) sell or assign the assets related to services rendered as well as impose any encumbrance (including any security, bond, guaranty, pledge and mortgage) on these or any other assets related to the concession or the revenues from electricity services; (iii) effect a change in the controlling interest of the holder of the authorization or concession; and (iv) make certain changes to the bylaws. In the case 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, require that the contract be rescinded.

      The New Industry Model Law

      The New Industry Model Law introduced material changes to the regulation of the electric energy industry, in order to (i) provide incentives to private and public entities to build and maintain generation capacity, and (ii) ensure the supply of electricity in Brazil at low tariffs through a competitive electricity public bidding process. The key elements of the New Industry Model Law include:

      • Ensuring the existence of two markets: (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 Customers and energy-trading companies), called the free market, that permits a certain degree of competition vis-à-vis the regulated market.

      • Restrictions on certain distribution activities, including requiring distributors to focus on their core business of distribution activities in order to promote more efficient and reliable services to captive customers.

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      • Elimination of self-dealing by providing an incentive for distributors to purchase electricity at the lowest available prices rather than buying electricity from related parties.

      • Upholding contracts executed 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 Eletrobras and its subsidiaries from the National Privatization Program, which was created by the Brazilian government in 1990 to promote the privatization process of state-owned companies.

      Parallel Environment for the Trading of Electric Energy

      Under the New Industry Model Law, the purchase and sale of electricity is carried out in two different segments: (i) the regulated market, which contemplates that distribution companies will purchase by public auction all the electricity they need to supply their customers; and (ii) the free market, which provides for the purchase of electricity by non-regulated entities (such as the Free Customers and energy traders).

      However, the electricity arising from the following is subject to specific rules different from the rules applicable to the regulated market and to the free market (i) low capacity generation projects located near consumption points (such as certain co-generation plants and small hydroelectric power plants), (ii) plants qualified under the Proinfa Program, an initiative established by the Brazilian government to create incentives for the development of alternative energy sources, such as wind power projects, small hydroelectric power plants and biomass projects, (iii) Itaipu and (iv) Angra 1 and 2.

      The electricity generated by Itaipu will continue to be sold by Eletrobras to the distribution concessionaires operating in the South, Southeast and Midwest portions of the Interconnected Transmission System. The rates at which 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 real/U.S. dollar 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.”

      Beginning January 2013, the energy generated by nuclear plants Angra 1 and 2 will be sold by Eletronuclear to the distribution concessionaires at a rate that will be calculated by ANEEL.

      The New Industry Model Law does not affect bilateral agreements entered into before 2004.

      The Regulated Market

      In the regulated market, distribution companies must purchase their expected electricity requirements for their captive customers in the regulated market through a public auction process. The auction process is administered by ANEEL, either directly or through the CCEE, under certain guidelines provided by the MME.

      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 case, the generator would be required to purchase 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.

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        Under the New Industry Model Law, the estimate of demand from distributors is the principal factor in determining how much electricity the system as a whole will contract. A distributor is obligated to contract all of its projected electricity needs, as opposed to 95.0% under the previous regime. A deviation in actual demand from projected demand could result in penalties to distributors. In the event of under-contracting, the distributor is penalized directly in an amount that increases as the difference between the amount of energy contracted for and actual demand increases. An under-contracting distributor must also pay to meet its demand by purchasing energy in the spot market.

        In the event of over-contracting, where the contracted volume falls between 100% and 103% of actual demand, the distributor is not penalized and the additional costs are compensated for through increases in its customers’ tariffs. Where the contracted volume is over 103% of actual demand, the distributor must sell energy in the spot market. If the contract price proves lower than the current spot market price, the distributor sells its excess energy for a profit. On the other hand, if the contract price is higher than the spot market price, the distributor sells its excess energy at a loss.

        With respect to the granting of new concessions, the newly enacted regulations provide that bids for new hydroelectric generation facilities may include, among other things, the minimum percentage of electricity to be supplied in auctions in the regulated market. Concessions for new generation projects, such as Mauá, in our case, are non-renewable, meaning that upon expiration, the concessionaire must again complete a competitive bidding process.

        The Free Market

        The free market covers transactions between generation concessionaires, Independent Power Producers – IPPs, self-generators, energy traders, exporters and importers of electric energy and Free Customers. The free market also covers bilateral agreements between generators and distributors signed under the old model, 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 may only do so upon the expiration of its contract with the local distributor and with advance notice or, in the case of a contract with no expiration date, upon 15 days notice in advance of the date on which the distributor must provide MME with its estimated electricity demand for the year. In the latter case, the contract will only be terminated in the following year. Once a consumer has chosen the free market, it may only return to the regulated system only with five years prior notice to its regional distributor, provided that the distributor may reduce such term at its discretion. This extended period of notice seeks to assure that, if necessary, the distributor can buy additional energy in auctions in the regulated market without imposing extra costs on the captive market.

        Private generators may sell electricity directly to Free Costumers. State-owned generators may sell electricity directly to Free Customers but are obligated to do so only through private auctions carried out by the state-owned generators exclusively to Free Customers or by the Free Customers.

        Regulation under the New Industry Model Law

        A July 2004 decree governs the purchase and sale of electricity in the regulated market and the free market, as well as the granting of authorizations and concessions for electricity generation projects. This decree includes, among other items, regulations relating to auction procedures, the form of power purchase agreements and the mechanism for passing costs through to Final Customers.

        These regulations establish the guidelines under which electricity-purchasing agents must contract their electricity demand. Electricity-selling agents must show that the energy to be sold comes from existing or planned power generation facilities. Agents that do not comply with such requirements are subject to penalties imposed by ANEEL.

        These regulations also require electricity distribution companies to contract for 100% of their energy needs primarily through public auctions. In addition to these auctions, distribution companies can purchase limited amounts (up to 10% of their demand) from: (i) generation companies that are connected directly to the distribution company (except for hydroelectric power plants with capacity higher than 30 MW and certain thermoelectric power plants) (ii) electricity generation projects participating in the initial phase of the Proinfa Program, (iii) power purchase agreements entered into before the New Industry Model Law was enacted, and (iv) the Itaipu Power Plant.

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        The MME establishes the total amount of energy that will be contracted in the regulated market and the number and type of generation projects that will be auctioned each year.

        All electricity generation, distribution and trading companies, independent producers and Free Customers are required to notify 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. In advance of each electricity auction, each distribution company is also required to inform MME of the amount of electricity that it intends to contract in the auction. In addition, distribution companies are required to specify the portion of the contracted amount they intend to use to supply potentially Free Customers.

        Auctions in the Regulated Market

        Electricity auctions for new generation projects are held (i) in the fifth year before the initial delivery date of electricity (as “A-5” auctions), and (ii) in the third year before the commencement of commercial operation (“A-3” auctions). Existing power generators hold auctions (i) in the year before the initial delivery date (“A-1” auctions), and (ii) up to four months before the delivery date (“market adjustments”).

        New and existing power generators may participate in the reserve energy auctions as long as these generators increase the power system capacity or they did not achieve commercial operation by January 2008. Invitations to bid in the auctions are prepared by ANEEL in accordance with guidelines established by the MME, including the requirement that the lowest bid wins the auction. Each generation company that participates in the 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, except for the market adjustment and reserve energy auctions.

        The contracts for both A-5 and A-3 auctions have a term of between 15 and 30 years, and the contracts for A-1 auctions have a term between 5 and 15 years. Contracts arising from market adjustment auctions are limited to a two-year term. The reserve energy contracts are limited to a 35-year term.

        The quantity of energy contracted from existing generation facilities may be reduced for three reasons: (i) to compensate for captive customers that become Free Customers; (ii) to compensate for market deviations from the estimated market projections (up to 4% per year of the annual contracted amount, beginning two years after the initial electricity demand is estimated); and (iii) to adjust the quantity of contracted energy in bilateral agreements entered into prior to the enactment of the New Industry Model Law.

        With regard to (i) above, the reduction in net revenue caused when a captive customer becomes a Free Customer is compensated by the increased amounts that Free Customers are required to pay to use our distribution system. However, a Free Customer may disconnect from our distribution system (and therefore cease to pay us a distribution tariff) if it chooses to connect directly to the Interconnected Transmission System or if it generates energy for self-consumption and transports this energy without using our distribution system. Because a Free Customer that connects directly to the Interconnected Transmission System no longer pays us a distribution tariff, we might not be able to fully recover this loss in revenues.

        Since 2004, CCEE has conducted fifteen auctions for new generation projects, ten auctions for energy from existing power generation facilities, four auctions for reserve energy in order to increase energy supply security and twelve auctions for market adjustments. No later than August 1 of each year, the generators and distributors provide their estimated electricity generation or estimated electricity demand for the five subsequent years. Based on this information, MME establishes the total amount of electricity to be traded in the auction and determines which generation companies will participate in the auction. The auction is carried out electronically in two phases.

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        After the completion of the auction (except in the case of reserve energy auction), generators and distributors execute the CCEAR, in which the parties establish the price and amount of the energy contracted in the auction. The price is adjusted annually based on price variations published by the IPCA. The distributors grant financial guarantees to the generators (mainly receivables from the distribution service) to secure their payment obligations under the CCEAR.

        Also after completion of the auction, the generation concessionaire and the CCEE execute the Contrato de Energia de Reserva (“CER”), in which the parties establish the price and amount of the energy contracted for in the auction. The distributors, free customers and self-producing customers then execute the Contrato de Uso da Energia de Reserva (“CONUER”) with CCEE, in order to provide for the terms of the use of the reserve energy. The reserve energy customers grant financial guarantees to CCEE to secure their payment obligations under CONUER.

        The Annual Reference Value

        Brazilian regulation establishes a mechanism (the “Annual Reference Value”) that limits the costs that can be passed through to Final Customers. The Annual Reference Value corresponds to the weighted average of the electricity prices in the A-5 and A-3 auctions (excluding alternative energy auctions), calculated for all distribution companies.

        The Annual Reference Value encourages distribution companies to contract their expected electricity needs in the A-5 and A-3 auctions, where the prices are expected to be lower. The Annual Reference Value is applied during the first three years of the power purchase agreements for new power generation projects. Beginning in the fourth year, 100.0% of the electricity acquisition costs from these projects is passed through to customers.

        The regulation establishes the following permanent limitations on the ability of distribution companies to pass-through costs to customers: (i) no pass-through of costs for electricity purchases that exceed 103% of actual demand; (ii) limited pass-through of costs of the acquisition of electricity in the A-3 auctions, if the amount of purchased energy exceeds 2% of the amount of electricity contracted in the A-5 auctions; (iii) if the volume contracted from existing generation projects decreases by over 4%, new contracts from new generation projects are afforded limited pass-through.

        The MME establishes the maximum acquisition price for electricity generated by existing projects. If distributors do not comply with the obligation to fully contract their demand, the pass-through of costs from energy acquired in the short-term market is the lower of the spot market price and the Annual Reference Value.

        Electric Energy Trading Convention

        The Electric Energy Trading Convention (Convenção de Comercialização de Energia Elétrica) regulates the organization and functioning of the CCEE and defines, among other things, (i) the rights and obligations of CCEE participants, (ii) the penalties to be imposed on defaulting agents, (iii) the means of dispute resolution, (iv) trading rules in the regulated and free markets, and (v) the accounting and clearing process for short-term transactions.

        Restricted Activities of Distributors

        Distributors in the Interconnected Transmission System are not permitted to (i) engage in activities related to the generation or transmission of electric energy, (ii) sell electric energy to Free Customers, except for those in their concession area and under the same conditions and tariffs maintained with respect to captive customers, (iii) hold, directly or indirectly, any interest in any other company, corporation or partnership, or (iv) engage in activities that are unrelated to their respective concessions, except for those permitted by law or the relevant concession agreement. A generator is not allowed to hold more than a 10% equity interest in any distributor.

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        Elimination of Self-Dealing

        Since the purchase of electricity for captive customers is now performed through auctions in the regulated market, “self-dealing” (under which distributors were permitted to meet up to 30.0% of their energy needs using energy that was either self-produced or acquired from affiliated companies) is no longer permitted. As of 2004, all of a distributors demand must be met through purchases made in public auctions.

        Challenges to the Constitutionality of the New Industry Model Law

        The New Industry Model Law is currently being challenged on constitutional grounds before the Brazilian Supreme Court. The Brazilian government moved to dismiss the actions, arguing that the constitutional challenges were moot because they related to a provisional measure that had already been converted into law. To date, the Supreme Court has not reached a final decision and we do not know when such a decision may be reached. While the Supreme Court is reviewing the law, its provisions have remained in effect. Regardless of the Supreme Court’s final decision, certain portions of the New Industry Model Law relating to restrictions on distributors performing activities unrelated to the distribution of electricity, including sales of energy by distributors to Free Customers and the elimination of self-dealing, are expected to remain in full force and effect.

        Tariffs for the Use of the Distribution and Transmission Systems

        ANEEL regulates access to the distribution and transmission systems and establishes tariffs for the use of 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 Interconnected Transmission System and its ancillary facilities (“TUST”).

        TUSD

        Users of a distribution system pay the distribution concessionaire a tariff known as the TUSD (Tarifa de Uso dos Sistemas Elétricos de Distribuição). The TUSD is divided into two parts: one related to the contracted power in R$/kW and other related to the regulatory charges in R$/kWh. The amount paid by the users of a distribution system is calculated by multiplying the maximum contracted power for each of the customer’s points of connection to the concessionaire’s distribution system, by the tariff in R$/kW, plus the product of the power consumption by the tariff in R$/kWh, per month.

        In relation to the captive customers, the TUSD is part of the supply tariff that is calculated based on the voltage used by each customer.

        TUST

        The TUST (Tarifa de Uso do Sistema de Transmissão) is paid by distribution companies, generators and Free Customers to transmission companies for the use of the Interconnected Transmission System (electrical transmission system with voltage equal or higher than 230 kV). This tariff is revised annually according to (i) the location of the user of the Interconnected Transmission System and (ii) the annual revenues that a transmission company is permitted to collect for the use of its assets in the Interconnected Transmission System. The ONS, an entity that represents all transmission companies that own assets in the Interconnected Transmission System, coordinates the payment of transmission tariffs to these transmission companies. Users of the Interconnected Transmission System sign contracts with the ONS, which allows them to use the transmission grid in return for paying TUST.

        Distribution Tariffs

        Distribution tariff rates to Final Customers (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 into (i) costs that are beyond the control of the distributor, or (“Parcel A costs”), and (ii) costs that are under control of distributors (“Parcel B costs”). ANEEL’s tariff readjustment formula treats these two categories differently.

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        Parcel A costs include, among others, the following:

        • costs of electricity purchased in ANEEL public auctions;

        • costs of electricity purchased from Itaipu;

        • costs of electricity purchased pursuant to bilateral agreements by small distribution companies;

        • charges for connection to and use of the transmission and distribution systems; and

        • energy sector regulatory charges.

        Parcel B costs include, among others, the following:

        • a component designed to compensate the distributor for the investments made by the distributor on the concession assets;

        • depreciation costs; and

        • a component designed to compensate the distributor for its operating and maintenance costs.

        • Each distribution company’s concession agreement provides for an annual readjustment (reajuste anual). In general, Parcel A costs are fully passed through to customers. Parcel B costs, however, are only adjusted for inflation in accordance with the IGP-M index, minus the X factor.

        Electricity distribution concessionaires are also entitled to periodic tariff revisions (revisão periódica) every four or five years. These revisions are aimed at (i) assuring necessary revenues to cover efficient Parcel B operational costs and adequate compensation for investments deemed essential for services provided within the scope of each such company’s concession and (ii) determining the “X factor”.

        The X factor for each distribution company is calculated based on the following components:

        • Xa, based on the application of the IPC-A to the personnel portion of the concessionaire’s operational costs;

        • P, based on the concessionaire’s productivity, which is measured in terms of increases in assets, total volume of energy sold, and the number of Final Customers to which energy is sold;

        • T, based on the trajectory of the concessionaire’s operating costs, measured as the difference between the cost benchmarks established by ANEEL and the concessionaire’s actual operating costs; and

        • Q, based on quality target indicators that measure the interruption of energy supply to Final Customers.

        In addition, ANEEL recently enacted new regulations under which distribution companies will be required to comply under penalty of law with minimum pre-established targets measured by a new quality of service indicator related to customer satisfaction.

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              In addition, a distribution concessionaire is entitled to an extraordinary tariff review (revisão extraordinária) on a case-by-case basis, to ensure its financial stability and compensate it for unpredictable costs, including taxes, which significantly change its cost structure. Extraordinary tariff adjustments were granted (i) in June 1999 to compensate for increased costs of electricity purchased from Itaipu as a result of the devaluation of the real  against the dollar, (ii) in 2000 to compensate for the increase in Contribuição para o Financiamento da Seguridade Social - COFINS (Social Security Financing Contribution) from 2% to 3%, and (iii) in December 2001 to compensate for losses caused by the Rationing Program.

              Since October 2004, on the date of a subsequent tariff readjustment or tariff revision, whichever occurs earlier, distribution companies have been required to execute separate contracts for the connection and use of the distribution system and for the sale of electricity to their potentially Free Customers.

              Incentives

              In 2000, a Federal decree created the Thermoelectric Priority Program, Programa Prioritário de Termoeletricidade (“PPT”), for purposes of diversifying the Brazilian energy matrix and decreasing Brazil’s strong dependence on hydroelectric plants. The incentives granted to the thermoelectric plants included in the PPT are: (i) guarantee of gas supply for 20 years, as per a MME regulation, (ii) assurance that the costs related to the acquisition of the electric energy produced by thermoelectric plants will be passed on to customers through tariffs up to the normative value established by ANEEL, and (iii) guarantee of access to a special BNDES financing program for the electric energy industry.

              In 2002, the Brazilian government established the Proinfa Program to encourage the generation of alternative energy sources. Under the Proinfa Program, Eletrobras shall purchase the energy generated by alternative sources for a period of 20 years. In its initial phase, the Proinfa Program is limited to a total contracted capacity of 3,300 MW. In its second phase, which will start after the 3,300 MW cap has been reached, the Proinfa Program intends to purchase up to 10% of Brazil’s annual electric energy consumption from alternative sources. The first phase of the Proinfa program commenced in 2004.

              Energy Sector Regulatory Charges

              State and Municipal ICMS Compensation

              From January 1, 2010 to December 31, 2012, distributors are required to pay a levy in the amount of 0.3% of their annual  operating revenues, which will be transferred to certain states and municipalities in compensation with losses in tax revenues that these states and municipalities suffered when they became connected to the Interconnected Transmission System, due to the fact that they no longer receive energy from locally-generated sources. These funds must be used by the states and municipalities to provide increased access to electricity, to finance social and environmental projects, and to conduct research and development and support energy efficiency initiatives.

              EER

              The Encargo de Energia de Reserva (“EER”) is a regulatory charge designed to raise funds for energy reserves that have been contracted through CCEE. These energy reserves, which are mandatory, were created in order to attempt to ensure a sufficient supply of energy in the Interconnected Transmission System. The EER shall to be collected from Final Customers of the Interconnected Transmission System. Beginning in 2010, this charge has been collected on a monthly basis.

              RGR Fund

              In certain circumstances, electric energy companies are compensated for certain assets used in connection with a concession if the concession is revoked or is not renewed. In 1971, the Brazilian Congress created a reserve fund designed to provide these compensatory payments (the “RGR Fund”). In February 1999, ANEEL established a fee requiring public-industry electric companies to make monthly contributions to the RGR Fund at an annual rate equal to 2.5% of the company’s fixed assets in service, not to exceed 3% of total operating revenues in any year. In recent years, no concessions have been revoked or have failed to be renewed, and the RGR Fund has been used principally to finance generation and distribution projects.

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              UBP

              Independent Power Producers – IPPs reliant on hydrological resources (except small hydroelectric power plants) are required to make contributions for using a public asset, Uso de Bem Público (“UBP”) according to the rules of the corresponding public bidding process for the granting of concessions. Eletrobras receives the UBP payments in a specific account.

              CCC

              Distribution companies (and also some transmission companies responsible for Free Customers) must contribute to the Fuel Consumption Account, Conta de Consumo de Combustível (“CCC Account”). The CCC Account was created in 1973 to generate financial reserves to cover fossil fuel costs in order to reduce tariffs to be paid by customers supplied by thermoelectric power plants. However, since July 2009 the CCC reserves have been used to cover the difference of the cost of generation in the isolated systems (supplied only by thermoelectric power plants) and the cost of generation in the Interconnected Transmission System. The CCC Account is administered by Eletrobras. The CCC Account, in turn, reimburses electric companies for a substantial portion of the power generation costs of their thermoelectric power plants in the isolated systems.

              In February 1998, the Brazilian government provided for the phasing out of the CCC Account. During the 2003-2005 period, subsidies from the CCC Account were phased out for thermal power plants that are connected to the Interconnected Transmission and that were constructed prior to February 1998 system. Thermal power plants constructed after that date will not be entitled to subsidies from the CCC Account. In April 2002, the Brazilian government established that subsidies from the CCC Account would continue to be paid, for a period of 20 years, to thermoelectric plants located in isolated systems. However, in December 2009, the Brazilian government revoked this provision and the CCC is therefore no longer set to expire.

              CDE

              In 2002, the Brazilian government instituted the Electric Energy Development Account, Conta de Desenvolvimento Energético (“CDE Account”). The CDE Account is funded by (i) monthly payments made by concessionaires for the use of public assets, (ii) penalties and fines imposed by ANEEL and (iii) the annual fees paid by agents offering electric energy to Final Customers, by means of an additional charge added to the tariffs for the use of the transmission and distribution systems. These fees are adjusted annually. The CDE Account was created to support (i) the development of energy production throughout Brazil, (ii) the production of energy by alternative energy sources, and (iii) the provision of electric energy services to all of Brazil. The CDE will be in effect until 2027 and is regulated by the executive branch and managed by Eletrobras.

              Itaipu Transmission Fee

              The Itaipu Hydroelectric Plant has an exclusive transmission grid and is not part of the Interconnected Transmission System. Companies that are entitled to receive electricity from Itaipu pay a transmission fee in an amount equal to their proportional share of the Itaipu generated electricity.

              Use of Water Resources Tax

              Holders of concessions and authorizations that allow for the exploitation of water resources must pay a total tax of 6.75% of the value of the energy they generate, which for purposes of this calculation is based on a rate set by ANEEL. Beginning on January 1, 2012, ANEEL set this rate at R$72.87/MWh. The proceeds of this tax are shared among the states and municipalities where the plant or the plant’s reservoir is located, as well as with certain federal agencies.

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              ANEEL Inspection Fee (TFSEE)

              The ANEEL Inspection Fee is an annual fee due by the holders of concessions, permissions or authorizations equal to an ANEEL determined percentage of their revenues. The ANEEL Inspection Fee requires these holders to pay up to 0.5% of their annual revenue to ANEEL in 12 monthly installments.

              Default on the Payment of Regulatory Charges

              The New Industry Model Law provides that the failure to pay required contributions to the RGR Fund, Proinfa Program, CDE Account, CCC Account, or make certain payments, such as those due from the purchase of electric energy in the regulated market or from Itaipu, will prevent the defaulting party from receiving readjustments or reviews of their tariffs (except for an extraordinary review) and will also prevent the defaulting party from receiving funds from the RGR Fund, CDE Account or CCC Account. We comply with payment obligations related to Regulatory Charges.

              Energy Reallocation Mechanism

              The Energy Reallocation Mechanism (“MRE”) attempts to mitigate the risks borne by hydroelectric generators due to variations in river flows (hydrological risk).

              Under Brazilian law, each hydroelectric plant is assigned a determined amount of “assured energy,” according to an energy supply risk criteria defined by MME, based on historical river flow records. The assured energy also represents the maximum energy that can be sold by the generator, which is set forth in each concession agreement, irrespective of the volume of electricity actually generated by the facility.

              The MRE tries to guarantee that all participating plants receive the revenue corresponding to their assured energy, irrespective of the volume of electricity generated by them. In other words, the MRE effectively reallocates the electricity, transferring the surplus from those who have produced in excess of their assured energy to those that have produced less than their assured energy. The relocation, which occurs in the Interconnected Transmission System, is determined by the ONS, considering the nationwide electricity demand and hydrological conditions, regardless of the power purchase agreement of each individual generator. The volume of electricity actually generated by the plant, whether more or less than their assigned assured energy quotient, is priced pursuant to a tariff known as the “Energy Optimization Tariff,” designed to cover only the variable operation and maintenance costs of the plant, so that generators are largely unaffected by the actual dispatch of their plants.

              Research and Development

              The companies holding concessions and permissions for distribution of electricity must invest a minimum of 0.50% of their annual net operational revenues in research and development and 0.50% in energy efficiency programs. Beginning on January 1, 2016, these percentages will become 0.75% and 0.25%, respectively.

              A company holding concessions and authorizations for generation and transmission of electricity must invest a minimum of 1% of its annual net operational revenues in research and development. A company that generates electricity exclusively from small hydroelectric power plants, cogeneration or alternative energy projects is not subject to this requirement.

              The amount to be invested in research and development must be distributed as follows:

              • 40% to the company research and development projects, under the supervision of ANEEL;

              • 40% to the Ministry of Sciences and Technology, to be invested in national research and development projects; and

              • 20% to the MME, to defray EPE.

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              Environmental Regulations

              The Brazilian constitution gives both the 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 a supplement to federal and state laws.

              A violator of an environmental law may be subject to administrative and criminal sanctions and will have an obligation to repair or provide compensation to the affected party for environmental damages. Administrative sanctions may include substantial fines and suspension of activities, while criminal sanctions may include fines and, for individuals, including for directors and employees of companies that commit environmental crimes, possible imprisonment.

              Our energy generation, distribution and transmission 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, their maintenance is still subject to the compliance with certain requirements. We were one of the first energy concessionaires in Brazil to provide an environmental impact assessment and report in connection with the construction of a power plant (Segredo Power Plant, 1987). The Salto Caxias Power Plant (1995-1999) was constructed in accordance with one of the most comprehensive environmental impact mitigation programs ever implemented in Brazil.

              The Law of Environmental Crimes, which took effect in 1998, establishes a general framework of liability for environmental crimes. Federal laws and statutes have established the National System for Management of Water Resources and the National Council of Water Resources to address the major environmental issues facing the hydroelectric sector and users of water resources. In 2000, the Brazilian government created an independent agency, the National Water Agency, to regulate and supervise the use of water resources.

              The Brazilian Forestry Code and related regulations deal with the maintenance and acquisition of areas affected by hydroelectric plant reservoirs. These regulations may result in increased maintenance, reforestation and condemnation costs to energy industry concessionaires. In addition, Paraná State law requires a mandatory environmental audit of companies whose activities may impact the environment within the state.

              Item 4A. Unresolved Staff Comments

              None.

              Item 5. Operating and Financial Review and Prospects

              The information derived from our consolidated statement of operations for the years ended December 31, 2011, 2010 and 2009 has been prepared in accordance with IFRS as issued by the IASB. For more information see “Presentation of Financial and Other Information” and Note 2 to our consolidated financial statements of our 2011 Form 20-F.

              Overview

              Brazilian Economic Conditions

              All of our operations are in Brazil, and we are affected by general Brazilian economic conditions. In particular, the general performance of the Brazilian economy affects demand for electricity, and inflation affects our costs and our margins. The Brazilian economic environment has been characterized by significant variations in economic growth rates, with very low growth from 2001 through 2003 and an economic recovery that has led to consistent growth since 2004. In 2009, Brazilian GDP decreased due to the global financial crisis. Since then, the Brazilian economy has shown a return to growth, growing 7.5% in 2010 and 2.7% in 2011.

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              The following table shows selected economic data for the periods indicated:

               

              Year ended December 31,

               

              2011

              2010

              2009

              Inflation (IGP-DI)

              5.0%

              11.3%

              (1.4)%

              Appreciation (depreciation) of the real vs. U.S. dollar

              (11.17)%

              4.5%

              34.2%

              Period-end exchange rate – US$1.00(1)

              1.8758

              1.6662

              1.7412

              Average exchange rate – US$1.00

              1.6709

              1.7589

              1.9905

              Change in real GDP 

              2.7%

              7.5%

              (0.2)%

              Average interbank interest rates(2)

              11.70%

              9.9%

              9.7%

               

              (1)  The real/U.S. dollar exchange rate at March 31, 2012 was R$1.82 per US$1.00.

              (2)  Calculated in accordance with Central Clearing and Custody House (“CETIP”) methodology (based on nominal rates).

              Sources: FGV ‒ Fundação Getúlio Vargas, the Brazilian Central Bank, the Brazilian Geography and Statistics Institute (“IBGE”) and Central Clearing and Custody House (“CETIP”).

              Rates and Prices

              Our results of operations are significantly affected by changes in the prices at which our generation business sells energy, and by the prices at which our distribution business buys energy in the regulated market and re-sells it to Final Customers at regulated tariffs.

              Our generation business sells energy at unregulated prices in the regulated market, in the Free Market and in the Spot Market. Our generation business allocates the amount of energy that it sells in each of these markets seeking to maximize returns, based on factors such as: (i) the requirements of its concession contracts, many of which set a minimum percentage of energy generated in a particular concession that must be sold in the regulated market; (ii) the volume of energy that we plan to sell to Free Customers for a given year; and (iii) the outlook of the short-term, medium-term and long-term for energy prices generally. Although sales in the Free Market and the Spot Market are not directly regulated, they are influenced by energy regulatory policy. The prices at which our generation business sells energy are not regulated.

              Our distribution business purchases enough energy to meet 100% of the demand we forecast for our Final Customers in auctions at unregulated prices in the regulated market. Our distribution business re-sells that energy to Final Customers at regulated tariffs that take into consideration the price at which the energy was purchased. If our forecasts fall short of the actual electricity demand of our Final Customers, we may be forced to make up for the shortfall by entering into short-term agreements to purchase electricity in the spot market. If our forecasts exceed the actual demand of our Final Customers, our distribution business sells the excess energy in the Spot Market. The margins in our distribution business tend to be relatively stable due to the regulated nature of the distribution business, while the margins in our generation business are typically larger but less stable.

              Sales to Final Customers (which include sales by our distribution business to captive customers and sales by our generation business to Free Customers) represented approximately 47.2% of the volume of electricity we delivered in 2011, and accounted for 71.5% of our energy sales revenues. Almost all of such sales were to captive customers. For more information, see “Item 4. Information on the Company - The Brazilian Electric Power Industry -  Distribution Tariffs.” In general, if our costs for energy increase, the tariff process permits us to recover these costs from our customers through higher rates in future periods. However, if we do not receive tariff increases to cover our costs, if the recovery is delayed, or if our Board of Directors elects to reduce the tariff increase awarded by ANEEL, our profits and cash flows may be adversely affected.

              ANEEL modifies our Retail Tariffs annually, generally in June. Since January 2009, the adjustments have been as follows.

              • In June 2009, ANEEL approved the annual readjustment of our Retail Tariffs, increasing them by an average of 18.04%, of which 11.42% related to the tariff increase and 6.62% referred to an increase in recovery of deferred regulatory assets (CVA). The readjustment became effective as of June 24, 2009. After giving effect to the recovery of Parcel A costs, the net effect of the above tariff readjustment on our captive customers was an increase on tariffs of 12.98%.

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              However, due to the global economic crisis, our Board of Directors, pursuant to instructions from our controlling shareholder, determined that the Retail Tariff readjustment set forth by ANEEL should have no effect on our captive customers. Consequently, on June 24, 2009, we submitted to ANEEL a formal request asking for the deferral of part of the annual readjustment to future periods. However, the requirement was not approved by ANEEL. Subsequently, at an extraordinary shareholders’ meeting, the implementation of a tariff adjustment was approved, which provided discount equivalent to the tariff increase approved by ANEEL for all Final Customers that pay their bills on time.

              • In February 2010, our distribution concession contract with ANEEL was amended. As a result, the subsequent increase in our distribution tariffs was reduced, causing a reduction of approximately 0.5% in our distribution revenues. Our Board of Directors approved the amendment in order to mitigate the possibility of a lawsuit or judicial proceeding. Nevertheless, we cannot assure you that no such action will be brought.
              • In June 2010, ANEEL approved the annual readjustment of our Retail Tariffs, increasing them by an average of 9.74%, of which 6.88% related to the tariff increase and 2.86% referred to an increase in recovery of deferred regulatory assets (CVA). The readjustment became effective as of June 24, 2010. After giving effect to the recovery of Parcel A costs, the average effect of this tariff readjustment on our captive customers was an increase of 2.46%.
              • In June 2011, ANEEL approved the annual readjustment of our Retail Tariffs, increasing them by an average of 5.55%, of which 5.77% related to the tariff increase and 0.22% referred to an decrease in recovery of deferred regulatory assets (CVA). The readjustment became effective as of June 24, 2011. After giving effect to the recovery of Parcel A costs, the average effect of this tariff readjustment on our captive customers was an increase of 2.99%.

              Purchase and Resale of Energy

              Our distribution business purchases energy from generation companies and resells this energy to Final Customers at regulated rates. For more information, see “Item 4. Information on the Company - Business - Generation” and “Item 4. Information on the Company - Business - Purchases.” Our major long-term contracts or purchase obligations are described below.

              • We purchase energy from Itaipu at prices that are determined based on the Itaipu project’s costs, including servicing its U.S. dollar-denominated debt. In 2011, our electricity purchases from Itaipu amounted to R$459.6 million.
              • Our distribution business is required to purchase a large portion of its energy needs from the regulated market. For more information, see “Item 4. Information on the Company - The Company - Distribution - Auctions in the Regulated Market.”

              Under current legislation, the amount that our distribution business charges Final Customers is composed of two fees: a fee for the actual energy consumed and a fee for the use of our distribution system. Since the regulated rates at which our distribution business sells energy to Final Customers are substantially the same as the rates at which it purchases energy (after accounting for deductions and the cost of energy purchased for resale), our distribution business does not generate operating profit from the sale of electricity to Final Customers. Rather, our distribution business generates operating profit principally by collecting tariffs for the use of our distribution system.

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              Impact of the CRC Account

              One of our most significant assets consists of the obligations of the State of Paraná under an agreement that was most recently amended in January 2005. These obligations derive from amounts we were entitled to recover under a prior regulatory regime, and as a result they are referred to as the recoverable rate deficit account or “CRC” account (Conta de Resultados a Compensar). As of December 31, 2011, the outstanding balance of the CRC Account was R$1,346.5 million. The balance is adjusted for IGP-DI, bears interest at 6.65%, and is payable in monthly installments through April 2025. If the State of Paraná fails to make payments on a timely basis, we may apply dividends we owe to the State of Paraná in its capacity as our shareholder against amounts it owes us under the CRC Account agreement. For additional information, see Note 6 to our consolidated financial statements.

              Special Obligations

              The contributions received from the federal government and our customers exclusively for investment in our distribution network are named as special obligations. We record the amount of these contributions on our balance sheet as a reduction of our intangible and financial assets, under the caption “special obligations,” and, upon the conclusion or termination of the operating concession granted to us, the amount of these contributions is offset against intangible and financial assets. The amount we recorded as special obligations as of December 31, 2011 was R$240.9 million as a reduction of intangible assets and R$1,592.3 million as a reduction of financial assets.

              Critical Accounting Policies

              In preparing our financial statements, we make estimates concerning a variety of matters. Some of these matters are highly uncertain, and our estimates involve judgments we make based on the information available to us. We have discussed in “Overview” above certain accounting policies relating to regulatory matters. In the discussion below, we have identified several other matters for which our financial information would be materially affected if either (i) we reasonably used different estimates or (ii) in the future we change our estimates in response to changes that are reasonably likely to occur.

              The discussion below addresses only those estimates that we consider most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate. There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation. Please see Note 2 to our consolidated financial statements included herein for a more detailed discussion of the application of these and other accounting policies.

              Property, Plant and Equipment

               

              We have adopted the deemed cost methodology to determine the fair value of Copel Geração e Transmissão’s property, plant and equipment, specifically for the generation business as of the date of transition of our financial statements to IFRS (January 1, 2009). These assets are depreciated according to the linear method based on annual rates set forth and reviewed periodically by ANEEL, which are used and accepted by the market as representative of the economic useful life of the assets related to concession’s infrastructure, limited to the term of said concession, when applicable. The estimated useful life, the residual amounts, and depreciation are reviewed as of the date of the balance sheets, and the effect of any changes in estimates is recorded prospectively.

              Internal studies have shown that the balances as of January 1, 2009 of assets related to telecommunications business were compatible with their fair values and supported by impairment tests. Costs directly attributable to construction work as well as interest and financial charges on loans from third-parties during construction are recorded under property, plant, and equipment in progress.

              Accounting for concession arrangements

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              We account for our concession agreements for transmission and distribution business in accordance with IFRIC 12 - Service Concession Agreements.

              IFRIC 12 establishes that electric energy utilities should record and measure revenues according to IAS 11 - Construction Contracts and IAS 18 - Revenues, even when governed by a single concession agreement. When we make investments in the infrastructure used in the power transmission and distribution services we perform pursuant to our concession agreements, we capitalize these investments as intangible assets and financial assets, and we recognize construction revenue and construction costs in connection with these investments. Intangible assets represent the right to access and to operate infrastructure that is provided to us or that we build or acquire as part of the concession agreement. The value of intangible assets is determined based on construction fair value, reduced by the corresponding estimated financial assets, described in greater detail below, and by any accumulated amortization and impairment losses, when applicable. The amortization pattern for intangible assets reflects our estimate of our future economic from these assets, limited to the term of the concession. We currently amortize these assets at approximately 29% per year, a rate that accelerates as we approach the end of a concession term.

              We calculate the value of financial assets related to our distribution business based on our distribution concession arrangements. These financial assets represent our understanding of our unconditional right to receive cash payments upon expiration of the concession from ANEEL, as set forth in our concession agreements. These cash payments are designed to compensate us for the investments we make in infrastructure and that are not recovered through the collection of tariffs from users.

              Financial assets related to our distribution business do not have determinable cash flows, since we operate under the assumption that the value of the cash payments we will receive from ANEEL upon expiration of a concession will be based on the replacement cost of the concession assets. Since these financial assets do not fit into any other category of financial assets under IFRS, they are classified as “available for sale.” The cash flows related to these assets are determined taking into account the replacement cost of PPE, which is known as the Regulatory Compensation Basis (Base de Remuneração Regulatória or BRR), and is defined by ANEEL. The return on these financial assets is based on the regulatory weighted average cost of capital approved by ANEEL in the periodic rate review process carried out every four years.

              We calculate the value of the financial assets related to our transmission business based on: (i) revenues from tariffs based on the construction of transmission infrastructure for use by system users; (ii) revenues from tariffs based on the operation and maintenance of infrastructure assets related to our concessions; and (iii) the financial return on these assets that is guaranteed by ANEEL and that is not otherwise recovered through tariffs by the end of the concession term. Because the aggregate transmission tariffs we collect are calculated entirely based on the infrastructure assets that we make available to system users as a whole, they are not subject to demand risk, and are therefore considered guaranteed revenues. These revenues, which are calculated considering the entire term of transmission concession, are known as Annual Permitted Revenues (Receita Anual Permitida or RAP). Users of this infrastructure are billed on a monthly basis for these amounts, pursuant to reports issued by the National System Operator (Operador Nacional do Sistema or ONS). Upon expiration of the concession, ANEEL is required to pay any uncollected amounts related to the construction, operation, and maintenance of infrastructure, as compensation for investments made and not recovered through tariffs. Because these financial assets do not have an active market and do not have present fixed and ascertainable cash flows, they are classified as “loans and receivables.” These financial assets are initially estimated based on their fair values, and are later measured according to the amortized cost calculated under the effective interest rate method.

              Generation concessions are deemed outside the scope of IFRIC 12 and are accounted for under other applicable IFRS.

              In addition to our financial assets and intangible assets, under IFRS we also recognize construction revenues and construction costs for construction activities we perform in connection with our distribution and transmission concessions. Our distribution business outsources power distribution infrastructure construction. As a result, under IFRS we recognize construction costs and revenues in roughly the same amounts. In contrast, since our transmission business performs much of our transmission infrastructure construction, we recognize construction revenue in amounts that exceed construction costs. The resulting margin for our transmission business’ construction revenue was 1.65% in both 2011 and 2010, and is calculated based on a methodology that takes into account business risk.

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              The recognition of fair value for intangible and financial assets in connection with our concession contracts is subject to assumptions and estimates, and the use of different assumptions could affect the amounts we recognize. The estimated useful lives of the underlying assets, as well as the rate of return of the financial assets also require significant assumptions and estimates. Different assumptions and estimates and changes in future circumstances could have a significant impact on our results of operations. Additional information on the accounting for intangible and financial assets arising from concession agreements is contained in Notes 2.14 and 2.27 to our consolidated financial statements.

              Revenue Recognition

              We recognize revenue on an accrual basis: we recognize revenue when persuasive evidence of an arrangement exists, delivery of goods has occurred or services have been rendered, our price to the customer has been fixed or is determinable and collection is reasonably assured. Under the accrual basis, we recognize revenue regardless of when the cash is received.

              We bill our residential, industrial and commercial customers monthly. Unbilled revenues from the billing date to month-end are estimated based on the prior month’s billing and recognized as revenue at the end of the month in which the service was provided. We read certain of our individual customers’ meters systematically throughout the month in order to estimate how much energy we have sold to individual customers as a group. At the end of each month, the amount of energy delivered to each customer since their last meter reading date is estimated and the corresponding unbilled revenue is determined based upon a customer’s daily estimated usage by class and applicable customer rates reflecting significant historical trends and experience. Differences between estimated and actual unbilled revenues, which have historically been insignificant, are recognized in the following month.

              Impairment of Long-Lived Assets

              Long-lived assets, primarily property, plants and equipment, comprise a significant amount of our total assets. We evaluate our long-lived assets and make judgments and estimates concerning the carrying value of these assets, including the amounts to be capitalized, the depreciation rates and useful lives of these long-lived assets. The carrying values of these assets are reviewed for impairment periodically or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of future revenues and costs related to the assets subject to review. These forecasts require assumptions about the demand for our products and services, future market conditions and regulatory developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.

              Electric Energy Trading Chamber – CCEE

              For accounting purposes, we recognize costs and revenues related to purchases and sales of energy in the spot market based on our internal estimates, which estimates are reviewed by the CCEE.

              We claimed a credit based on energy purchased from Itaipu during the energy rationing period that occurred in 2001, when there was a significant difference between the purchase price of Itaipu energy and energy sold at a loss in the spot market. We are contesting a determination by ANEEL that would require us to recognize approximately R$1,473.0 million in costs for energy we purchased for resale in the spot market during the electricity rationing period of 2000, 2001 and the first quarter of 2002. Our management believes that losses resulting from the final ruling of this claim are not probable and therefore we have no provision relating to this matter. However, we may be required to contribute to the amounts owed by other energy companies under similar lawsuits, and as of December 31, 2011, we had provisions of R$35.5 million to cover probably losses related to these other lawsuits.

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              Reserve for Risks (Labor, Civil, Tax and Environmental Claims)

              Our subsidiaries and we are party to certain legal proceedings in Brazil arising in the normal course of business regarding tax, labor, civil and environmental.

              We account for risks based on the determination that it is probable that a future event will confirm that an asset has been impaired or a liability has been incurred at the date of the financial statements, and the amount of loss can be reasonably estimated. By their nature, risks will only be resolved when a future event or events occur or fail to occur; typically such events will occur a number of years in the future. The evaluation of these risks is performed by our internal and external legal counsel. Accounting for risks requires significant judgment by management concerning the estimated probabilities and ranges of exposure to potential liability. Management’s assessment of our exposure to risks could change as new developments occur or more information becomes available. The outcome of the risks could vary significantly and could materially impact our consolidated results of operations, cash flows and financial position. The reserve for risks as of December 31, 2011 amounted to R$1,000.8 million, of which R$281.9 million was related to tax proceedings, R$484.0 million was related to civil claims, R$128.5 million was related to labor claims, R$58.1 million was related to employee benefits and R$48.1 million was related to regulatory proceedings and R$0.1 million was related to environmental claims.

              As of December 31, 2011, we estimate that the total amount of claims against us, excluding disputes involving non-monetary claims or claims that cannot be evaluated in the current stage of proceedings, classified as possible losses, was approximately R$2,016.5 million, of which R$176.4 million correspond to labor claims; R$37.8 million to employee benefits; R$12.9 million to regulatory claims; R$542.4 million to civil claims; and R$1,247.0 million to tax claims. For more information, see Note 26 to the consolidated financial statements.

              Employee Retirement and Health Benefits

              We sponsor a (i) defined-benefit pension plan and a (ii) defined-contribution pension plan covering substantially all of our employees. We have also established a health care plan for current and retired employees. We determine our funding obligations for these plans based on calculations performed by independent actuaries using assumptions that we provide about interest rates, investment returns, rates of inflation, mortality rates and future employment levels. These assumptions directly affect our liability for accrued pension costs.

              In 2011, we recorded expenses in the amount of R$150.8 million for our pension and health care plans. We estimate that we will incur expenses in the amount of R$71.7 million in 2012 (according to actuarial calculations), plus the monthly costs of these plans.

              Deferred Taxes

              We recognize deferred tax assets and liabilities based on the differences between the financial statement carrying amounts and the tax basis of assets and liabilities using prevailing rates. We regularly review our deferred tax assets for recoverability and establish a valuation allowance based on historical taxable income, projected future taxable income, and the expected timing of the reversals of existing temporary differences. If we are unable to generate sufficient future taxable income, or if there is a material change in the actual effective tax rates or time period within which the underlying temporary differences become taxable or deductible, we could be required to establish a valuation allowance against all or a significant portion of our deferred tax assets resulting in a substantial increase in our effective tax rate and a material adverse impact on our operating results. The deferred taxes balances subject to the federal taxing department inspection are those constituted over the 2007 to 2011 basis.

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              Analysis of Electricity Sales and Cost of Electricity Purchased

              The following table sets forth the volume and average rate components of electricity sales and purchases for the years ended December 31, 2011, 2010 and 2009:

               

               

              Year ended December 31,

               

              2011

              2010

              2009

              Electricity Sales

               

               

               

              Sales to Final Customers

               

               

               

              Average price (R$/MWh):(1)

               

               

               

              Industrial customers(2)

              170.41

              159.24

              148.67

              Residential customers

              250.25

              233.78

              221.07

              Commercial customers

              217.78

              202.68

              191.35

              Rural customers.

              154.29

              143.04

              134.80

              Other customers(3)

              167.83

              156.07

              145.62

              All customers(2)

              199.83

              186.09

              174.98

              Volume (GWh):

               

               

               

              Industrial customers(2)

              8,377

              8,146

              7,748

              Residential customers

              6,224

              5,925

              5,664

              Commercial customers

              4,778

              4,466

              4,200

              Rural customers

              1,871

              1,774

              1,680

              Other customers(3)

              2,123

              2,048

              1,994

              All customers(2)

              23,373

              22,359

              21,286

              Total revenues from sales to Final Customers (millions of R$)

              4,671

              4,160.8

              3,724.6

              Sales to distributors(4)

               

               

               

              Average price (R$/MWh)(1)

              88.13

              81.64

              77.05

              Volume (GWh)(5)

              16,339

              15,777

              15,692

              Total revenues (millions of R$)

              1,439.8

              1,288.0

              1,209.2

              Electricity Purchases

               

               

               

              Purchases from Itaipu

               

               

               

              Average cost (R$/MWh)(6)

              87.09

              88.26

              96.86

              Volume (GWh)

              5,278

              5,306

              5,379

              Percentage of total Itaipu production purchased

              6.3

              6.2

              8.0

              Total cost (millions of R$)(7)

              459.6

              468.3

              521.0

              Purchases from others(4)

               

               

               

              Average cost (R$/MWh)

              86.09

              83.50

              78.21

              Volume (GWh)(5)

              19,664

              18,011

              16,570

              Total cost (millions of R$)(7)

              1,692.9

              1,504.0

              1,295.8

               

              (1)  Average prices or costs have been computed by dividing (i) the corresponding revenues or expenses by (ii) MWh of electricity sold or purchased.

              (2)  Includes Free Customers outside Paraná.

              (3)  Includes public services such as street lighting, as well as supply of electricity to government agencies, and our own consumption.

              (4)  Energy traded between Copel’s subsidiaries not included.

              (5)  Energy Reallocation Mechanism not included.

              (6)  Our purchases of electricity generated by Itaipu are stated in reais and paid for on the basis of a capacity charge expressed in U.S. dollars per kW plus a “wheeling” (or transportation) charge expressed in reais per kWh.

              (7)  See “Item 4. Information on the Company - Business - Generation” and “Item 4. Information on the Company—Business—Purchases” for an explanation of our expenses relating to electricity purchases.

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              Results of Operations for the Years Ended December 31, 2011, 2010 and 2009

              The following table summarizes our results of operations for the years ended December 31, 2011, 2010 and 2009:

               

               

              Year ended December 31,

               

              2011

              2010

              2009

               

              (R$ million)

              Operating Revenues:

               

               

               

              Electricity sales to Final Customers:

              2,330.8

              2,213.4

              2,059.5

              Residential

              771.7

              723.5

              677.2

              Industrial

              757.3

              730.5

              673.9

              Commercial

              498.9

              467.7

              433.3

              Rural

              134.1

              126.9

              118.8

              Other classes

              168.8

              164.8

              156.3

              Electricity sales to distributors

              1,439.8

              1,288.0

              1,209.2

              Use of main distribution and transmission grid

              2,762.4

              2,272.4

              1,975.1

              Residential

              785.9

              661.7

              575.0

              Industrial

              670.2

              566.6

              477.9

              Commercial

              541.6

              437.5

              370.4

              Rural

              154.7

              126.9

              107.7

              Other classes

              187.5

              154.8

              134.0

              Other distribution and transmission revenue

              422.5

              325.0

              310.1

              Construction revenue

              741.7

              663.5

              601.9

              Telecommunications revenue

              117.1

              97.9

              80.2

              Distribution of piped gas

              273.9

              237.3

              205.2

              Other operating revenue

              110.4

              128.6

              119.0

               

              7,776.1

              6,901.1

              6,250.1

              Cost of sales and services provided:

               

               

               

              Electricity purchased for resale

              (2,152.5)

              (1,972.3)

              (1,816.8)

              Use of main distribution and transmission grid

              (632.5)

              (592.7)

              (553.2)

              Personnel and management

              (982.7)

              (811.5)

              (810.1)

              Pension and health care plans

              (150.9)

              (124.2)

              (109.7)

              Material and supplies

              (85.6)

              (84.1)

              (69.2)

              Raw materials and supplies for power generation business

              (25.0)

              (23.0)

              (21.2)

              Natural gas and supplies for gas business

              (186.9)

              (144.6)

              (128.9)

              Third-party services

              (391.4)

              (350.9)

              (321.1)

              Depreciation and amortization

              (553.1)

              (543.0)

              (539.8)

              Accruals and provisions

              (289.7)

              (362.8)

              (39.9)

              Construction costs

              (731.4)

              (662.9)

              (601.6)

              Other operating expenses

              (290.9)

              (296.1)

              (275.3)

               

              (6,472.6)

              (5,968.1)

              (5,207.0)

               

               

               

               

              Equity earnings of subsidiaries

              55.7

              99.3

              14.3

              Financial results

              224.8

              348.4

              6.7

              Profit before income tax and social contribution

              1,583.9

              1,380.7

              1,064.2

              Income tax and social contribution on profit

              (407.1)

              (370.5)

              (251.9)

              Net income for the year

              1,176.9

              1,010.3

              812.3

              Net income attributable to controlling shareholders

              1,157.7

              987.8

              791.8

              Net income attributable to non-controlling interest

              19.1

              22.5

              20.5

              Other comprehensive income

              0.9

              2.0

              11.5

              Comprehensive income

              1,177.7

              1,012.3

              823.7

              Comprehensive income attributable to controlling shareholders

              1,158.6

              989.8

              803.2

              Comprehensive income attributable to non-controlling interest

              19.1

              22.5

              20.5

               

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              Results of Operations for 2011 Compared with 2010

               

              Operating Revenues

              Our operating revenues increased by 12.7%, or R$875.0 million, in 2011 compared with 2010. Of this increase, R$117.4 million was due to electricity sales to Final Customers and R$490.0 million was due to charges for use of our main distribution and transmission grid. Revenues from electricity sales to distributors increased by 11.8%, or R$151.8 million and construction revenue increased by 11.8% or R$78.2 million.

              Electricity Sales to Final Customers. Our revenues from electricity sales to Final Customers increased by 5.3% or R$117.4 million in 2011. The average tariff for Final Customers increased by 7.4% as compared with 2010 average rate. The average tariff rates for the residential, industrial, commercial and rural classes of Final Customers increased by 7.0%, 7.0%, 7.4% and 7.9%, respectively. The variation in average price increases between different classes of customers reflects the fact that the tariffs established by ANEEL in 2011 and 2010 varied depending upon the voltage level received.

              The increase in the volume of energy sold to Final Customers in 2011 compared with 2010 reflected an increase in the number of Final Customers in each category.

              • The volume of electricity sold to residential customers increased by 5.0% in 2011 compared with 2010. Of this increase, 4.2% was due to an increased number of customers and 0.8% was due to an increased in average consumption per residential customer. This increase was driven mainly due to sales of energy consuming products as a consequence of a greater availability of credit.

              • The volume of electricity sold to industrial customers, including both captive customers and Free Customers, increased by 5.3% in 2011 compared with 2010. This increase resulted principally from the improved performance in the petroleum refining and ethanol industries, as well as increased activity in the automotive, machinery and equipment industries in the State of Paraná.

              • The volume of electricity sold to commercial customers increased by 7.0% in 2011 compared with 2010. Of this 7.0% increase, 3.4 percentage points can be attributed to an increase in average consumption per commercial customer and 3.5 percentage points can be attributed an increased number of commercial customers. We attribute these increases in the commercial segment to high employment in the State of Paraná and the increase in availability of consumer credit.

              • The volume of electricity sold to rural customers increased 5.5% in 2011 compared with 2010. Of this increase, 2.2% was due to an increased number of customers and 3.2% was due to an increased in average consumption per rural customer. This increase was mainly due to the strong performance of agriculture and cattle industries the State of Paraná in 2011.

              Electricity Sales to Distributors. Our revenues from electricity sales to distributors increased by 11.8%, or R$151.8 million, in 2011 compared with 2010. This increase was caused by: (i) increased prices under power purchase agreements, both in auctions in the regulated market and through agreements with Free Customers; and (ii) an increase in volume of energy sales in the spot market in 2011 compared to 2010. Our generation business sells energy at unregulated market prices, which generally increased in 2011 compared to 2010.

              Use of Main Distribution and Transmission Grid. Our revenues from the use of main distribution and transmission grid increased by 21.6% or R$490.0 million, to R$2,762.4 million in 2011 compared with R$2,272.4 million in 2010. This increase was principally due to: (i) the increase in use of the grid by all classes of customers, as explained in greater detail above; (ii) the upward adjustment to our distribution tariffs, which had the effect of increasing by 3.0% the average tariff charged to our final customers; and (iii) the effect of the 18.3% upward readjustment in our transmission tariffs, which was the principal cause of the increase of R$100.5 million in revenue related to transmission assets (classified as interest income under IFRS), from R$128.8 million in 2010 to R$229.3 million in 2011.

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              Construction revenues. Our revenues from constructions increased by 11.8% or R$78.2 million in 2011 compared with 2010. This increase was mainly due to improvements we made to our distribution and transmission infrastructure in 2011.

              Telecommunications revenues. Revenues from our telecommunications segment increased by 19.6% or R$19.2 million in 2011, primarily due to an increased number of clients, to 1,442 in 2011 from 980 in 2010. This increase in our number of clients was partially offset by reductions in the prices we charged to clients for telecommunications services, due to competitive pressures.

              Distribution of Piped Gas. Revenues from distribution of piped gas increased by 15.4%, or R$36.6 million, in 2011 compared to 2010, mainly due to an 8.5% upward tariff adjustment in August 2011, together with a 4.9% increase in sales volume in 2011.

              Other Operating Revenues. Other operating revenues decreased by 14.2% or R$18.2 million, in 2011. This reduction was mainly the result of decreased rent revenue from the Araucária Thermal Power Plant in the second half of 2011. Demand from the Araucária Thermal Power Plant decreased because sufficient energy was being provided by hydroelectric power plants in Brazil.

              Cost of sales and services provided

              The attached financial statements present our operating costs of sales and services provided by function. However, in accordance with IFRS, Note 29 to the consolidated financial statements presents this information according to the nature of the operating cost or expense. For ease of understanding, the analysis below reflects the information presented by nature.

              Our total operating costs of sales and services provided increased by 8.5% or R$504.5 million, to R$6,472.6 million in 2011 from R$5,968.1 million in 2010, including amounts recognized as other operating expenses. The following were the principal factors in the increase of our operating costs of sales and services provided:

              • Electricity Purchased for Resale. Our costs for the energy we purchased for resale increased by 9.1%, or R$180.2 million, to R$2,152.5 million in 2011 compared with R$1,972.3 million in 2010. This increase was mainly due to higher acquisition costs from auctions in the regulated market, which increased by R$199.4 million in 2011 compared to 2010. Our distribution business buys energy at unregulated market prices, which generally increased in 2011 compared to 2010.

              • Use of Main Distribution and Transmission Grid. Expenses we incurred for our use of the main distribution and transmission grid increased by 6.7%, or R$39.8 million, to R$632.5 million in 2011 compared with R$592.7 million in 2010. This increase was mainly due to (i) new infrastructure in operation and (ii) R$16.5 million in reserve energy costs imposed by the Brazilian government, due to reduced rainfall affecting hydroelectric production. We did not incur reserve energy costs in 2010. This was partially offset by a 73.2% decrease in system service charges imposed by ANEEL, from R$41.0 million in 2010 to R$10.1 million 2011.

              • Personnel and Management. Personnel and management expenses increased by 21.1%, or R$171.2 million, to R$982.7 million in 2011 compared with R$811.5 million in 2010, mainly due to: (i) a 5.5% increase in our number of employees; (ii) wage increases of 6.5% and 7.4% applied to beginning in October 2010 and October 2011, respectively; (iii) the compensations from the Program Permanent Voluntary Termination and Succession - PSDV (R$64.4 million in 2011 compared R$19.7 million in 2010); and (iv) a general human resources review that began in June 2011.

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              • Pension and Health Care Plans. Pension and Health Care expenses increased 21.5%, or R$26.7 million, to R$150.9 million in 2011, compared with R$124.2 million in 2010. This line item reflects the accrual of liabilities pursuant to the 2011 actuarial report on our healthcare plan.

              • Materials and supplies. Materials and supplies expenses increased by 1.8%, or R$1.5 million, to R$85.6 million in 2011 compared with R$84.1 million in 2010, substantially due to an increase in the volume of electric power system materials that we acquired in 2011.

              • Raw Material and Supplies for Power Generation Business. These expenses increased 8.7%, or R$2.0 million, to R$25.0 million in 2011, compared with R$23.0 million in 2010. This increase was mainly due to an increase in the unit cost of mineral coal purchased for the Figueira Thermoelectric Plant.

              • Natural Gas and Supplies for Gas Business. Expenses related to natural gas purchases increased by 29.3%, or R$42.3 million, to R$186.9 million in 2011 compared with R$144.6 million in 2010. This increase was mainly caused by a 4.9% increase in volume of natural gas acquired by Compagas to supply third-parties, along with an increase in price of natural gas purchased in 2011 under supply contracts, which are subject to contractual price adjustments.

              • Third-Party Services. Third-party services expenses increased 11.5%, or R$40.5 million, to R$391.4 million in 2011 compared with R$350.9 million in 2010, mainly due to the increase in civil maintenance of R$6.7 million, equipment maintenance and furniture of R$4.2 million, travel of R$5.0 million, telephone of R$3.5 million, maintenance of green spaces and pruning services of R$4.8 million and data processing of R$3.0 million.

              • Depreciation and Amortization. Depreciation and amortization expenses increased 1.9%, or R$10.1 million, to R$553.1 million in 2011 from R$543.0 million in 2010.

              • Provisions and Reversals. Provisions and reversals expenses decreased by 20.1% or R$73.1 million in 2011 compared with 2010, mainly due to the non-recurring nature of the R$234.6 million provision that was booked for COFINS liabilities in 2010. This decrease was offset in part by the establishment of an additional R$118.3 million provision related to a lawsuit by Ivaí Engineering Works SA.

              • Construction Costs. Construction costs increased 10.3%, or R$68.5 million, to R$731.4 million in 2011 from R$662.9 million in 2010. This increase reflects costs we incurred in connection with improvements we made to our distribution and transmission infrastructure in 2011.

              • Other Operating Expenses. Other operating expenses decreased by 1.8% or R$5.2 million to an expense of R$290.9 million in 2011, compared with an expense of R$296.1 million in 2010. This variation was mainly due by maintenance costs, partially offset by higher compensation financial resources for the use of water.

              Equity earnings of subsidiaries

              Equity earnings of subsidiaries was R$55.7 million in 2011, compared to R$99.3 million in 2010. Equity investment reflects the equity income or loss of our affiliates. In 2011, this net result was mainly due to: (i) income of R$39.7 million from Sanepar; (ii) income of R$10.2 million from Foz do Chopim; (iii) income of R$7.6 million from Dona Francisca Energética; and (iv) losses of R$2.1 million from Sercomtel Telecomunicações.

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              The 43.9% decrease in results of equity of earnings of subsidiaries, from R$99.3 million in 2010 to R$55.7 million in 2011, was primarily due to: (i) the decrease of R$34.1 million recognized from the results of Sercomtel Telecomunicações in 2011 compared to 2010, primarily reflecting the non-recurring nature of the R$17.8 million reversion in 2010 of the impairment provision related to Sercomtel, which was based on Sercomtel’s improving results in 2010; and (ii) the decrease of R$26.0 million recognized from the results of Dona Francisca Energética in 2011 compared with 2010, primarily reflecting the non-recurring nature of the adjustment to Dona Francisca Energéticas accounting policies to align these policies with Copel, which resulted in R$27.2 million in additional revenue recognized by us in 2010. This decrease was partially offset by an increase of R$17.6 million in revenue recognized from the results of Sanepar, which was primarily due to an increase in the tariffs charged by Sanepar in 2011. For more details see Note 14 to our consolidated financial statements.

              Financial Results

              We recognized R$224.8 million of net financial income in 2011, compared to net financial income of R$348.4 million in 2010. Financial revenue decreased by 11.5% or R$74.7 million in 2011 compared to 2010, mainly due to: (i) a decrease of R$72.1 million in the transfer of CRC, due to the fact that these amounts are indexed based on inflation, and inflation was relatively lower in 2011 than in 2010; (ii) a decrease of R$50.8 million on receivables related to our concessions, since these amounts are also indexed based on inflation; and (iii) an increase of R$60.8 million in revenue from financial investments, mainly due to an increase in capital, increased interest rates and improved portfolio profitability. Financial expenses increased by 16.1%, or R$49.0 million, in 2011 compared to 2010, mainly due to an increase in debt charges of R$36.2 million, mainly related to the industrial credit note we contracted in 2011.

              Income Tax and Social Contribution

              In 2011, we recognized income tax and social contribution expenses of R$407.1 million, reflecting an effective tax rate of 25.7% on our pretax income. In 2010, we recognized income tax and social contribution expenses of R$370.5 million, reflecting an effective tax rate of 26.8% on our 2010 pretax income. The decrease of 1.1 percentage points in our effective tax rate in 2011 was the net effect of a number of factors, including: (i) an increase of R$50.7 million in taxes related to interest on equity, which increased our effective tax rate by 3.2 percentage points; (ii) a decrease on equity in result of investees by R$20.0 million, which reduced our effective tax rate by 1.3 percentage points; (iii) a 2011 tax benefit we claimed relating to the reduction of penalties and interest, which reduced our effective tax rate by 0.5 percentage points; and (iv) the effects of the Transitional Tax Regime (RTT).

              Results of Operations for 2010 Compared with 2009

              Operating Revenues

              Our operating revenues increased by 10.4%, or R$651.0 million, in 2010 compared with 2009. Of this increase, R$153.8 million was due to electricity sales to Final Customers and R$297.3 million was due to charges for use of our main distribution and transmission grid. Revenues from electricity sales to distributors increased by 6.5%, or R$78.8 million and construction revenue increased by 10.2% or R$61.6 million.

              Electricity Sales to Final Customers. Our revenues from electricity sales to Final Customers increased by 7.5% or R$153.8 million in 2010. The average tariff for Final Customers increased by 6.4% as compared with 2009 average rate. The average tariff rates for the residential, industrial, commercial and rural classes of Final Customers increased by 5.8%, 7.1%, 5.9% and 6.1%, respectively. The variation in average price increases between different classes of customers reflects the fact that the tariffs established by ANEEL in 2009 and 2010 varied depending upon the voltage level received.

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              The increase in the volume of energy sold to Final Customers in 2010 compared with 2009 primarily reflected an increase in the number of Final Customers in each category.

              • The volume of electricity sold to residential customers increased by 4.6% in 2010 compared with 2009. Of this increase, 3.7% was due to an increased number of customers and 0.9% was due to an increased in average consumption per residential customer. This increase was driven mainly due to sales of energy consuming products as a consequence of a greater availability of credit.

              • The volume of electricity sold to industrial customers, including both captive customers and Free Customers, increased by 5.1% in 2010 compared with 2009. Of this increase 3.3% was due to an increased number of customers and 1.8% was due to an increase in average consumption per industrial customers, which in turn were caused the better performance of the food, automotive and machinery and equipment industries.

              • The volume of electricity sold to commercial customers increased by 6.3% in 2010 compared with 2009. Of this increase, 3.4% was due to an increase in average consumption per commercial customer and 2.9% was due to an increased number of customers. In 2010, the increase in commercial segment occurred due to the healthy job market and the increase in consumer credit.

              • The volume of electricity sold to rural customers increased 5.6% in 2010 compared with 2009. Of this increase, 3.9% was due to an increased number of customers and 1.7% was due to an increased in average consumption per industrial customers. This increase was driven mainly due to the Brazilian economy expansion.

              Electricity Sales to Distributors. Electricity sales to distributors include sales in auctions in the regulated market (77.3% of total revenues for sales to distributors in 2010), sales under bilateral agreements (14.6% of total revenues for sales to distributors in 2010) and sales in the spot market (8.1% of total revenues for sales to distributors in 2010).

              Our revenues from electricity sales to distributors increased by 6.5% or R$78.8 million, in 2010 compared with 2009. This increase was caused by: (i) increased prices under power purchase agreements in the regulated market (CCEAR) and bilateral contracts; and (ii) higher revenue from short-term electricity market (CCEE);

              Use of Main Distribution and Transmission Grid. Our revenues from the use of main distribution and transmission grid increased by 15.1% or R$297.3 million, in 2010 compared with 2009. This was principally caused by: (i) increased use of the grid; and (ii) the tariff adjustment.

              Telecommunications revenues. Revenues from our telecommunications segment increased by 22.0% or R$17.6 million in 2010, primarily due to an increase in both the number of clients and demand for new telecommunication services by existing clients.

              Distribution of Piped Gas. Revenues from distribution of piped gas increased by 15.7% or R$32.1 million in 2010, mainly due to the effect of the global economic recovery and the resulting increase in gas sales, particularly to the industrial segment, which increased by 11.0% in 2010 compared to 2009.

              Other Operating Revenues. Other operating revenues increased by 8.1% or R$9.6 million, in 2010 mainly due to greater dispatch at the Araucária Thermal Power Plant in the second half of 2010.

              Cost of sales and services provided

              The attached financial statements present our operating costs of sales and services provided by function. However, in accordance with IFRS, Note 31 to the consolidated financial statements presents this information according to the nature of the operating cost or expense. For ease of understanding, the analysis below reflects the information presented by nature.

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              Our total operating costs of sales and services provided increased by 14.6%, or R$761.1 million, to R$5,968.1 million in 2010 from R$5,207.0 million in 2009, including amounts recognized as other operating expenses. The following were the principal factors in the increase of our operating costs of sales and services provided:

              • Electricity Purchased for Resale. Our costs for the energy we purchased for resale increased by 8.6%, or R$155.5 million, to R$1,972.3 million in 2010 compared with R$1,816.8 million in 2009. This increase was mainly due to higher acquisition costs from auctions in the regulated market and from the Proinfa program, which were partially offset by the reduction in the cost of energy purchased from Itaipu. The average cost of energy we purchased in auctions in the regulated market increased from R$83.53/MWh in 2009 to R$88.90/MWh in 2010, and the volume we purchased in the regulated market increased from 14,185 GWh in 2009 to 15,418 GWh in 2010. The average cost of energy we purchased from Itaipu decreased from R$96.86/MWh in 2009 to R$88.26/MWh in 2010, and the volume we purchased from Itaipu decreased from 5,379 GWh in 2009 to 5,306 GWh in 2010.

              • Use of Main Distribution and Transmission Grid. Expenses we incurred for our use of the main distribution and transmission grid increased by 7.1%, or R$39.5 million, to R$592.7 million in 2010 compared with R$553.2 million in 2009. This increase was mainly due to new infrastructure in operation and due to the increase in system service charges (ESS).

              • Personnel and Management. Personnel and management expenses increased by 0.2%, or R$1.4 million, to R$811.5 million in 2010 compared with R$810.1 million in 2009, mainly due to wage increases that became effective in October 2009 (6.0%) and October 2010 (6.5%).

              • Pension and Health Care Plans. Pension and Health Care expenses increased 13.2%, or R$14.5 million, to R$124.2 million in 2010, compared with R$109.7 million in 2009. This line item reflects the accrual of liabilities pursuant to the 2010 actuarial report on our healthcare plan.

              • Materials and supplies. Materials and supplies expenses increased by 21.5%, or R$14.9 million, to R$84.1 million in 2010 compared with R$69.2 million in 2009, substantially due to an increase in the volume of electric power system materials that we acquired in 2010.

              • Raw Material and Supplies for Power Generation Business. These expenses increased 8.2%, or R$1.8 million, to R$23.0 million in 2010, compared with R$21.2 million in 2009. This increase mainly consists of the increased cost of mineral coal purchased for the Figueira Thermoelectric Plant from R$256.0 per ton in 2009 to R$263.7 per ton in 2010.

              • Natural Gas and Supplies for Gas Business. The expenses related to natural gas purchases increased by 12.2%, or R$15.7 million, to R$144.6 million in 2010 compared with R$128.9 million in 2009. This increase was mainly caused by the increased volume of natural gas acquired by Compagas to supply third-parties, from 809,076 cubic meters per day in 2009 to 960,681 cubic meters per day in 2010.

              • Third-Party Services. Third-party services expenses increased 9.3%, or R$29.8 million, to R$351.0 million in 2010 compared with R$321.1 million in 2009, largely due to increased expenses with power grid maintenance, as well as increased costs related to data processing and transmission.

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              • Depreciation and Amortization. Depreciation and amortization expenses increased 0.6%, or R$3.2 million, to R$543.0 million in 2010 from R$539.8 million in 2009.

              • Accruals and provisions. The provisions and reversals expenses increased by R$402.7 million in 2010 compared with 2009 mainly due to the provisions related to COFINS legal proceedings of R$234.6 million.

              • Construction Costs. Construction costs increased 10.2%, or R$61.3 million, to R$662.9 million in 2010 from R$601.6 million in 2009, primarily due to an increased number of energy transmission and distribution construction projects in progress.

              • Other Operating Expenses. Other operating expenses increased by R$20.8 million to an expense of R$296.1 million in 2010, compared with an expense of R$275.3 million in 2009. This variation due mostly to higher payments of financial compensation for the use of water resources, due to increased hydroelectric power output, and, to a lesser extent, was due to the recognition of losses due to asset impairment (impairment of goodwill of UEG Araucária in the amount of R$44.6 million) and the recognition of losses from the sale of assets.

              Equity Earnings of Subsidiaries

              Equity in earnings of subsidiaries was R$99.3 million in 2010. Equity investment reflects the equity income or loss of our affiliates. In 2010, the increase was mainly due to: (i) R$34.0 million was from Dona Francisca Energética (R$27.7 million of which resulted from the reversal of provisions); (ii) R$32.6 million was from Sercomtel Telecom (R$23.4 million of which resulted from the reversal of impairment losses); (iii) R$22.1 million from Sanepar; and (iv) R$10.1 million from Foz do Chopim Energética. For more details see Note 16 to our consolidated financial statements.

              In 2009, equity earnings of subsidiaries amounted to R$14.3 million, which was mainly caused by: (i) R$22.7 million of equity income from Sanepar; (ii) R$17.0 million of equity loss from Sercomtel –  Telecomunicações; and (iii) R$9.3 million of equity income from Dona Francisca Energética.

              Financial Results

              We recognized R$348.4 million of net financial income in 2010, compared to net financial income of R$6.7 million in 2009. Financial revenue increased by 93.3% or R$314.8 million in 2010 compared to 2009, mainly due to the result of the monetary variation on our financial assets from the distribution activities and on the assets related to CRC transferred to the State Government. Financial expenses decreased by 8.1%, or R$26.9 million in 2010 compared with 2009, mainly due to lower debt charges and the effects of joining the Tax Recovery Program (Refis) in 2009.

              Income Taxes and Social Contribution

              In 2010, we recognized income tax and social contribution expenses of R$370.5 million, reflecting an effective tax rate of 26.8% on our pretax income. In 2009, we recognized income tax and social contribution expenses of R$251.9 million, reflecting an effective tax rate of 23.7% on our 2009 pretax income. The increase in the effective tax rate related to 2010 compared to 2009 was mainly caused by: (i) in 2010, we did not present the tax benefit related to the reduction of penalties and interests caused by the Law 11,941/2009, which represented an increase of 2.0% in the effective tax rate; (ii) the increase of equity in result of investees by R$29.5 million, which represented a reduction of 2.1%; (iii) reduction of R$10.7 million in interest on equity and dividends, which represented an increase of 1.0%; and (iv) the changes in accounting practices had tax effects that were compensated by the Transitional Tax Regime (RTT).

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              Liquidity and Capital Resources

              Our principal liquidity and capital requirements are to finance the expansion and improvement of our distribution and transmission infrastructure and to finance the expansion of our generation facilities. Our other principal uses of cash are to dividends payments and debt servicing. Capital expenditures were R$1,506.5 million in 2011 (including R$205.9 million investment in the Mauá Hydroelectric Plant) and R$1,059.9 million in 2010 (including R$168.7 million investment in the Mauá Hydroelectric Plant). The following table sets forth a breakdown of our capital expenditures for the periods indicated.

               

              Year ended December 31,

               

              2011

              2010

              2009

               

              (R$ million)

              Generation and transmission

              841.5

              275.6

              250.2

              Distribution

              516.4

              676.3

              655.2

              Telecom

              71.9

              75.4

              38.4

              Equity earnings of subsidiaries

              39.2

              0.2

              0.1

              Araucária Thermoelectric Plant

              15.8

              11.8

              10.1

              Compagas

              19.0

              15.7

              24.9

              Elejor

              2.7

              4.9

              0.1

              Total

              1,506.5

              1,059.9

              979.0

                     

               

              Our total budgeted capital expenditures for our wholly-owned subsidiaries for 2012 is R$2,257.4 million, of which:

              • R$1,069.9 million is for generation and transmission, including R$89.1 million for the construction of the Mauá Hydroelectric Plant and R$562.4 million for the construction of the Colíder Hydroelectric Plant;

              • R$1,105.0 million is for distribution; and

              • R$82.5 million is for our telecommunication business.

              Our following controlled companies also budgeted their own capital expenditures for 2012, as described below:

              • Compagas: R$62.6 million;

              • Araucária: R$9.3 million; and

              • Elejor: R$11.7 million.

              Historically, we have financed our liquidity and capital requirements primarily with cash provided by our operations and through external financing. Our principal source of funds in 2011 was our operating activities. Net cash provided by operating activities was R$1,147.9 million in 2011, compared with R$1,247.7 million in 2010. In 2012, we expect to finance our liquidity and capital requirements primarily with cash provided by our operations and through debt financing from BNDES and in the Brazilian capital markets.

              As in prior years, we plan to make significant investments in future periods to expand and upgrade our generation, transmission and distribution businesses. In addition, we may seek to invest in other existing electric utilities, in communications services or in other areas, each of which may require additional domestic and international financing. Our ability to generate cash sufficient to meet our planned expenditures is dependent upon a variety of factors, including our ability to maintain adequate tariff levels, to obtain the required regulatory and environmental authorizations, to access domestic and international capital markets, and a variety of operating and other contingencies. We anticipate that our cash provided by operations may be insufficient to meet these planned capital expenditures, and that we may require additional financing from sources such as BNDES and the Brazilian capital markets.  

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                ANEEL regulations require prior approval from ANEEL for any transfer of funds from our subsidiaries to us in the form of loans or advances. ANEEL approval is not required for cash dividends, as long as cash dividends do not exceed a dividend threshold (“Dividend Threshold”) equal to the greater of adjusted net income or income reserves available for distribution. The Dividend Threshold is established by Brazilian Corporate Law.

                The cash dividends we have received from our subsidiaries have been historically sufficient to meet our cash flow requirements without exceeding the Dividend Threshold. As a result, we have not sought approval from ANEEL to receive either loans or advances from our subsidiaries or cash dividends from our subsidiaries in excess of the Dividend Threshold. We do not expect these restrictions on loans and advances and on cash dividends exceeding the Dividend Threshold to impact our ability to meet our cash obligations, since we expect cash dividends below the Dividend Threshold to be sufficient in the future.

                In addition, Copel Geração e Transmissão has certain financing agreements with BNDES that contain clauses requiring BNDES approval for Copel Geração e Transmissão to pay cash dividends exceeding 30% of its adjusted net income established by Brazilian Corporate Law. Since BNDES has always approved Copel Geração e Transmissão requests to pay cash dividends in excess of 30% of its adjusted net income, this restriction has not affected the ability of Copel Geração e Transmissão to pay cash dividends or our ability to meet our cash obligations. As a result, we do not expect this restriction to affect our ability to meet our cash obligations in the future.

                Like other state-owned companies, we are subject to the National Monetary Council, Conselho Monetário Nacional (“CMN”) restrictions on our ability to obtain financing from certain domestic and international sources. CMN restrictions could limit our ability to accept external sources of funding, specifically bank financing. CMN restrictions do not affect our ability to access the Brazilian capital markets, and do not restrict our access to international capital markets for the purpose of repaying or refinancing debt.

                Our total outstanding loans and financing at December 31, 2011 were R$2,174.5 million. Approximately R$58.4 million of the total debt outstanding at December 31, 2011 was denominated in U.S. dollars. For more information on the terms of these loans and financings, see Note 19 to our consolidated financial statements. Our major loans and financing arrangements are:

                • Eletrobras – We have R$261.5 million in outstanding debt under government programs to finance new generation products.

                • Banco do Brasil S.A. – We have R$1,504.2 million of outstanding debt with Banco do Brasil, consisting of financings we contracted to pay debentures issued in 2002, 2005 and 2006, as well as a September 2010 fixed-rate credit agreement.

                • BNDES has provided a loan to Copel of R$339 million to finance the construction of the Mauá Hydroelectric Plant. Mauá is owned by Consórcio Energético Cruzeiro do Sul, in which Copel has a 51.0% interest and Eletrosul has a 49.0% interest. BNDES is providing 50.0% of the loan amount, and Banco do Brasil S.A. is providing the remaining 50.0%. All the receivables arising from this plant were pledged in favor of BNDES until full repayment of the loan. As of December 31, 2010, we had an aggregate of R$277.9 million and as of December 31, 2011, we had an aggregate of R$344.4 million in outstanding debt with BNDES and Banco do Brasil under this facility.

                • In December 2011 we entered into a financing contract with BNDES in the total value of R$44.7 million for the construction of Transmission Line Foz do Iguacu - Cascavel Oeste, with a 14 years term.

                • FINEP: in November 2010, a loan agreement in amount of R$52.2 million was signed by Copel Telecomunicações S.A. to partially support the BEL – Extra Broadband project.

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                In addition, we have obtained approval from the CMN to apply for BNDES financing in the amount of R$1,585.0 million for four projects (HPP Colíder, TL Araraquara II, Taubaté, SE Cerquilho III and SHP Cavernoso II). These loan requests are being analyzed by BNDES.

                We are party to several legal proceedings that could have a material adverse impact on our liquidity if the rulings are adverse to us. In addition, we are contesting a determination by ANEEL that would require us to pay additional amounts for energy we purchased for resale during the electricity-rationing period in 2001 and the first quarter of 2002. We are also involved in several lawsuits, including challenges to the legality of certain federal taxes, which have been assessed against us, claims by industrial customers that certain increases in electricity tariffs from March through November 1986 were illegal and several labor related claims. These contingencies are described in “Item 8. Financial Information - Legal Proceedings.” If any of these claims are decided against us either individually or in the aggregate, they could have a material adverse affect on our liquidity and our financial condition.

                Contractual Obligations

                In the table below, we set forth certain of our contractual obligations as of December 31, 2011, and the period in which such contractual obligations come due. The table below includes pension liabilities and estimated interest payments on all our contractual obligations.

                 

                Payments due by period

                 

                Total

                Less than
                1 year

                1-3 years

                3-5 years

                More than
                5 years

                 

                (R$ million)

                Contractual obligations:

                 

                 

                 

                 

                 

                Loans and financing 

                3,052.3

                215.5

                1,262.8

                1,049.3

                524.7

                Suppliers(1) 

                1,044.1

                772.7

                271.4

                -

                -

                Purchase obligations(2) 

                65,107.0

                3,641.1

                6,750.5

                4,645.2

                50,070.2

                Concession payments(3) 

                2,294.3

                45.4

                97.3

                110.7

                2,040.9

                Eletrobras – Itaipu 

                9,279.1

                514.6

                1,087.3

                1,339.0

                6,338.2

                Tax recovery programs(4) 

                247.3

                247.3

                -

                -

                -

                Post employment benefits(5) 

                3,733.1

                341.8

                621.7

                660.0

                2,109.6

                Total 

                84,757.2

                5,778.4

                10,091.0

                7,804.2

                61,083.6

                 

                (1)  Mainly consists of gas supplied by Petrobras to the Araucária Thermoelectric Plant.

                (2)  Consists of electric power purchase commitments pursuant to binding obligations which commitments include all significant terms, including fixed or minimum quantities purchased; fixed, minimum or variable price provisions and delivery dates.

                (3)  Payments to the federal government arising from Elejor, Mauá and Colíder facilities concession agreement.

                (4)  For more details, see Note 10 to our consolidated financial statements.

                (5)  For more details, see Note 21 to our consolidated financial statements.

                 

                We are also subject to risks with respect to tax, labor and civil claims and have provisioned R$1,008.0 million for accrued liabilities for legal proceedings related to these claims as of December 31, 2011. For more information, see “Item 8. Financial Information - Legal Proceedings” and Notes 10 and 26 to our consolidated financial statements.

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                Off-Balance Sheet Arrangements

                We have not engaged in any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

                Item 6. Directors, Senior Management and Employees

                We are managed by:

                • a Board of Directors, which may consist of seven to nine members and is currently composed of nine members; and

                • a Board of Executive Officers, which consists of nine members.

                Board of Directors

                The Board of Directors ordinarily meets once every three months and is responsible, among other things, for:

                • establishing our corporate strategy;

                • defining the general orientation of our business;

                • defining the responsibilities of members of our Board of Executive Officers; and

                • electing the members of our Board of Executive Officers.

                Meetings of the Board of Directors require a quorum of a majority of the directors and decisions are made by majority vote. The members of the Board of Directors are elected to serve for two-year terms and may be reelected. Among the current nine members of the Board of Directors:

                • seven are elected by the controlling shareholders;

                • one is elected by minority shareholders; and

                • one is elected by our employees.

                The member of our Board of Directors who is elected by the non-controlling shareholders has the right to veto (provided it is duly justified) the choice of the independent accountant made by the majority of the members of our Board of Directors.

                The State of Paraná and BNDES Participações S.A. –  BNDESPAR (“BNDESPAR”), acting through the Company and Paraná Investimentos, S.A., are parties to a shareholders’ agreement dated December 22, 1998, as amended on March 29, 2001 (the “Shareholders’ Agreement”). BNDESPAR is a wholly-owned subsidiary of BNDES. Under the Shareholders’ Agreement, the parties agree to exercise their voting rights so that:

                • the State of Paraná appoints five members to the Board of Directors; and

                • BNDESPAR appoints two members to the Board of Directors.

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                According to Brazilian Corporate Law, minority shareholders are entitled to appoint and remove a member of the Board of Directors, in a separate election, where such minority shareholders (i) hold at least 15% of the company’s voting shares or (ii) hold at least 10% of the company’s outstanding non-voting shares.

                The terms of the current members of the Board of Directors expire in April 2013. The current members are as follows:

                Name

                Position

                Since

                Mauricio Schulman

                Chairman

                2011

                Lindolfo Zimmer

                Director

                2011

                Pedro Luiz Cerize

                Director

                2011

                Paulo Procopiak de Aguiar

                Director

                2011

                José Richa Filho

                Director

                2011

                Fabiano Braga Côrtes

                Director

                2011

                Carlos Homero Giacomini

                Director

                2011

                Nilton Camargo Costa

                Director

                2011

                Ney Amiltom Caldas Ferreira

                Director

                2012

                The following are brief biographies of the current members of our Board of Directors:

                Maurício Schulman. Mr. Schulman is 80 years old. He received a degree in civil engineering from Universidade Federal do Paraná and a specialization degree in business administration. Mr. Schulman has also taken additional courses in electricity and economy in France. Previously, Mr. Schulman served as Chief Corporate Management Officer and Chief Executive Officer at Eletrobras; served as Chairman at Eletrobras, Light S.A. and of the Brazilian Committee at the Comissão de Integração Energética Regional - CIER; served as Chief Administrative Officer at Companhia de Desenvolvimento Econômico do Paraná – Codepar, Banco Nacional de Habitação – BNH and Federação Nacional dos Bancos ‒ Fenaban (National Bank Federation). He also was State Secretary of the Treasury in the State of Paraná. Mr. Maurício Schulman was appointed by the State of Paraná.

                Lindolfo Zimmer. Mr. Zimmer is 69 years old. He received a degree in economic engineering and industrial management from Universidade Federal do Rio de Janeiro and in mechanical engineering and economics from Universidade Federal do Paraná . He has MBA in marketing from Fundação Getúlio Vargas – FGV-PR. Previously, Mr. Zimmer served as Chief Executive Officer of Dobreve Energia S.A. – Desa, where he also was a member of its board of directors; advisor at Instituto de Engenharia do Paraná ‒ IEP (State Engineering Institute) and at Federação das Indústrias do Paraná – Fiep (Industries Federation of the State of Paraná) at the Social Responsibility Thematic Council; Chief Marketing Officer at Companhia Paranaense de Energia ‒ Copel (2000 to 2003); Chief Operation Officer at Copel (1995 to 1999); Chief Engineering and Construction Officer at Copel (1979 to 1982); Chairman of the Management Committee at Copel Telecomunicações and Copel Transmissão S.A.; member of the Management Committee at Copel Geração S.A. and Copel Distribuição S.A.; Chief Official for Special Works ‒ Foz do Areia Power Plant; manager of the Electromechanical Engineering Department at Foz do Areia Power Plant; manager of Mechanical Maintenance and Mechanical Engineering Divisions at Copel; engineer at Salto Osório Power Plant ‒ Copel; manager at Capivari-Cachoeira Power Plant; technical director at Inepar S.A.; department manager at Eletrobras S.A.; vice-president at Instituto Pró-Cidadania de Curitiba; and the Government Secretary for the Municipality of Curitiba. Mr. Zimmer was appointed by the State of Paraná.

                Pedro Luiz Cerize. Mr. Cerize is 42 years old. He received a degree in Business Management from EASP ‒ Fundação Getúlio Vargas (1991) and a master’s degree in Finance from IBMEC  (1993). Previously, Mr. Cerize was responsible for the variable income at Banco BBA-Creditanstalt S.A. (1997 to 2000) and was a member of the Board of Directors at Porto Seguro S.A. Mr. Cerize also serves as a member of the Board of Directors at Cosan S.A. Indústria e Comércio since 2008 and is a founding-partner of Skopos Administradora de Recursos S.C. Ltda. Mr. Cerize has been appointed by the minority shareholders.

                Paulo Procopiak de Aguiar. Mr. Aguiar is 71 years old. He received a degree in Civil Engineering from Universidade Federal do Paraná and specialization degrees in business administration for executives and theoretical and applied economics from Fundação Getúlio Vargas ‒ FGV-PR and in the economics of hydroelectric undertakings from Universidade Federal do Paraná . Mr. Aguiar also has a degree in hydrology and hydroelectric undertakings from Centro Internacional de Estudos, Paris. Previously, Mr. Aguiar served as Chief Executive Officer, Chief Technical Officer and Chief Financial Officer at Copel; Chief Financial and Economical Control Officer at Departamento Nacional de Águas e Energia Elétrica; Chief Financial Officer at Eletrobras; National Assistant Secretary of Energy; and a Member of the Board of Directors of Eletrobras  (1985 to 1989), Eletrosul  (1986 to 1989) and Light (1985 to 1989). Mr. Aguiar currently serves as Officer at Cimento Itambé Company and was appointed by the State of Paraná.

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                José Richa Filho. Mr. José Richa is 47 years old. He has a bachelor’s degree in civil engineering from Universidade Católica do Paraná and a graduate degree in public management from Sociedade Paranaense de Ensino e Informática. Previously, Mr. José Richa was Chief Administrative and Financial Officer at the Departamento de Estradas de Rodagem ‒ DER-PR (State Body for Roads); Chief Administrative and Financial Officer at Agência de Fomento do Paraná S.A. (State Development Agency); and Management Secretary of the Municipality of Curitiba. Mr. José Richa was appointed by the State of Paraná.

                Fabiano Braga Côrtes. Mr. Côrtes is 79 years old. He has a degree in Law from Faculdade de Direito de Curitiba. Mr. Côrtes was Chief Management Officer at Itaipu Binacional; Chairman at the Legislative Assembly of the State of Paraná and Chief of the Civil House; Congressman; and a State Representative. Mr. Côrtes  was appointed by the State of Paraná.

                Carlos Homero Giacomini. Mr. Giacomini is 57 years old. He has a master’s degree in Public Health form Universidade Estadual de Londrina – UEL; a specialization in Pediatrics, with residency at Hospital Evangélico do Paraná and a degree in Medicine from Faculdade Evangélica de Medicina do Paraná. Mr. Giacomini was Chairman of Instituto Municipal de Administração Pública - Imap; Municipal Secretary of Planning and Coordination at Curitiba Municipality; Director at Hospital Oswaldo Cruz; Director of Planning and Chief Official at Imap; Chairman at Instituto de Previdência dos Servidores do Município de Curitiba - IPMC; and Municipal Secretary of Human Resources at Curitiba Municipality. Mr. Giacomini was appointed by the State of Paraná.

                Nilton Camargo Costa. Mr. Costa is 50 years old. He has a Specialization Degree in Electrical Engineering from Faculdade de Engenharia de Bauru and in Electrical Control Systems from Universidade Federal de Santa Catarina – UFSC. Mr. Costa acted as Coordinator of the following teams at Copel: Maintenance of Substations and Transmission Lines; Electronics and Automation; and Substation Operation (1988-2008). Mr. Costa was elected by the Company’s employees

                Ney Amiltom Caldas Ferreira. Mr. Ferreira is 57 years old. He has a post-degree in business management from Universidade Católica do Paraná and has a bachelor degree in business management and foreign trade from Faculdade Positivo. Mr. Ferreira was chairman of the Civil House of the State of Paraná and representative of the Social Security National Institute – INSS at the State of Paraná and acted in several functions in the municipality of Guarapuava, including as interim mayor of the city. In the past seven years, Mr. Ferreira acted as the CEO of Companhia de Desenvolvimento Agropecuário do Paraná – CODAPAR. Mr. Ferreira was appointed by BNDES Participações S.A. – BNDESPAR

                Board of Executive Officers

                Our Board of Executive Officers meets weekly and is responsible for the daily management of the Company. Each Executive Officer also has individual responsibilities established by our bylaws.

                According to our bylaws, our Board of Executive Officers consists of eight members. The Executive Officers are elected by the Board of Directors for three-year terms but may be removed by the Board of Directors at any time. Under the Shareholders’ Agreement, BNDESPAR has the right to appoint one member to the Board of Executive Officers. The terms of the current members of the Board of Executive Officers expire in April 2014. The current members are as follows:

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                Name

                Position

                Since

                Lindolfo Zimmer

                Chief Executive Officer

                2011

                Yára Christina Eisenbach

                Chief Corporate Management Officer

                2011

                Julio Jacob Júnior

                Chief Legal Officer

                2011

                Pedro Augusto do Nascimento Neto

                Chief Distribution Officer

                2011

                Jaime de Oliveira Kuhn

                Chief Power Generation & Transmission and Telecommunications Officer

                2011

                Jorge Andriguetto Junior

                Chief Engineering Officer

                2011

                Ricardo Portugal Alves

                Chief Financial Officer, Investor Relations Officer and Investment Portfolio Manager

                2011

                Gilberto Mendes Fernandes

                Chief Environment and Corporate Citizenship Officer

                2011

                Henrique José Ternes Neto

                Chief Alternative Energy Officer

                2012

                 

                The following are brief biographies of the current members of our Board of Executive Officers:

                Lindolfo Zimmer. Mr. Zimmer is 69 years old. Mechanical Engineer and an Economist, Lindolfo Zimmer held important positions throughout his professional career at Copel: as Chief Marketing Officer (2000 to 2003), Chief Operation Officer (1995 to 1999), Chief Engineering and Construction Officer (1979 to 1982) and Chairman of the Management Committee at Copel Telecomunicações S.A. and Copel Transmissão S.A. He had been recently working in the private sector as Chief Executive Officer of Dobreve Energia S.A. - Desa

                Yára Christina Eisenbach. Ms. Eisenbach is 57 years old. Lawyer, Yára Christina Eisenbach held important positions throughout her professional career at Copel: as consultant advisor for the Ombudsman's Office (2006 to 2010). Elected by the employees, she took part of the Moral Harassment Commission (Comissão de Assédio Moral - CADAM) (2010 to 2011), also in the CENPLR Commission (2008 to 2010) and in the Company's Board of Directors (1991 to 1992). She was Chief Executive Officer at Urbanização de Curitiba S.A. - URBS (2003 to 2004), State Secretary for Planning and General Coordination (2002 to 2003), general coordinator at Centro de Coordenação de Programas do Governo do Paraná (1995 to 2002). She acted also as advisor to the World Bank and to UN International Agencies (Unesco, PNUD, IICA, among others). She has been Regional Chairwoman of the Associação Nacional de Transporte Público e Trânsito - ANTP (Brazilian Public Transport and Transit Association) since 2003.

                Julio Jacob Junior. Mr. Jacob is 36 years old. Lawyer, Julio Jacob Junior was Chief Legal Officer at Instituto Curitiba Saúde (2005 to 2007) and manager of the Legal Division at Companhia de Urbanização de Curitiba - URBS (2007). He also worked as a lawyer in Business Law, Administrative Law, Societary Law and Electoral Law, besides being advisor at Ordem dos Advogados do Brasil in Curitiba.

                Pedro Augusto do Nascimento Neto. Mr. Nascimento is 55 years old. Electrical Engineer, Pedro Augusto do Nascimento Neto held important positions throughout his professional career at Copel: as Chief Distribution Officer at Copel Distribuição S.A. (1999 to 2002), assistant to the Chief Distribution Officer (1998 to 1999), Regional Chief Distribution Official (1995 to 1998) and Manager of several areas related to the distribution segment at Copel.

                Jaime de Oliveira Kuhn. Mr. Kuhn is 49 years old. Electrical Engineer, Jaime de Oliveira Kuhn held important positions throughout his professional career at Copel: as Chief Official for Transmission Works (2008 to 2010), coordinating Copel's participation in transmission auctions, Chief Official for the Operation of Power Transmission System, Planning and Engineering (2007 to 2008); assistant engineer to the Chief Technical Officer at Centrais Elétricas do Rio Jordão - Elejor (2005 to 2006); and as assistant to the Chief Official for Generation Operation and Maintenance at Copel (2003 to 2005). As Chief Official and Technician, he worked in the operation and maintenance of GBM (Foz do Areia) and GNB (Segredo) Power Plants from 1987 and 2002.

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                Jorge Andriguetto Junior. Mr. Andriguetto is 59 years old. Civil Engineer, Jorge Andriguetto Junior held important positions throughout his professional career at Copel: as Chief Official for Expansion Planning, Engineering and Construction in Power Generation, coordinating Copel's participation in several energy auctions and in undertakings of interest to the Company (2006 to 2010). He has also developed, since 1975, professional activities in various management positions in the Company's hydraulic and civil construction areas.

                Ricardo Portugal Alves. Mr. Alves is 58 years old. Business Manager, Ricardo Portugal Alves held important positions throughout his professional career at Copel: as Chief Capital Market Official at Copel (from 1997 to 2001 and from 2009 to 2010), Chief Financial and Investor Relations Officer (2001 to 2003) and Chief Financial Planning Official (1995 to 1996), among other activities, always within the financial management.

                Gilberto Mendes Fernandes. Mr. Fernandes is 55 years old. Specialist in strategic planning, Gilberto Mendes Fernandes held the position of advisor to TVSBT Rio de Janeiro as representative of that organization at