CPFL Energy (CPL) 20-F 2010 FY Annual report (foreign)

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

FORM 20-F

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

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

CPFL ENERGIA S.A.

(Exact name of registrant as specified in its charter)

CPFL ENERGY INCORPORATED	The Federative Republic of Brazil
(Translation of registrant’s name into English)	(Jurisdiction of incorporation or organization)

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

Lorival Nogueira Luz Junior
+55 19 3756 8704 – lorival.luz@cpfl.com.br
Rodovia Campinas Mogi Mirim, km 2,5 – Campinas, São Paulo - 13088 900
Federative Republic of Brazil
(Name, telephone, e-mail and/or facsimile
number and address of company contact person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class:	Name of each exchange on which registered:
Common Shares, without par value* American Depositary Shares (as evidenced by American Depositary Receipts), each representing 3 Common Shares	New York Stock Exchange

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

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

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

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

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

Yes T   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 T 

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 T   No £ 

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

Yes £   No £   N/A T 

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

Large Accelerated Filer T   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 T   Other £ 

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

Item 17£   Item 18 £ 

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

Yes £   No T 

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		Page
FORWARD-LOOKING STATEMENTS		1
CERTAIN TERMS AND CONVENTIONS		1
PRESENTATION OF FINANCIAL INFORMATION		2
ITEM 1.	Identity of Directors, Senior Management and Advisers	2
ITEM 2.	Offer Statistics and Expected Timetable	2
ITEM 3.	Key Information	2
	Selected Financial and Operating Data	2
	Exchange Rates	5
	RISK FACTORS	6
	Risks Relating to Our Operations and the Brazilian Power Industry	6
	Risks Relating to Brazil	11
	Risks Relating to the ADSs and Our Common Shares	13
ITEM 4.	Information on the Company	14
	Overview	14
	Our Strategy	18
	Our Service Territory	20
	Distribution	20
	Purchases of Electricity	23
	Consumers and Tariffs	24
	Generation of Electricity	27
	Electricity Commercialization and Services	32
	Competition	33
	Our Concessions and Authorizations	33
	Properties	36
	Environmental	36
	The Brazilian Power Industry	37
	Principal Regulatory Authorities	37
	Concessions and Authorizations	38
	The New Industry Model Law	40
	Tariffs for the Use of the Distribution and Transmission Systems	44
	Distribution Tariffs	45
	Government Incentives to the Energy Sector	46
	Regulatory Charges	47
	Energy Reallocation Mechanism	48
ITEM 4B.	UNRESOLVED STAFF COMMENTS	48
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	49
ITEM 6.	Directors, Senior Management and Employees	68
ITEM 7.	Major Shareholders and Related Party Transactions	75
ITEM 8.	Financial Information	78
ITEM 9.	The Offer and Listing	80
ITEM 10.	Additional Information	82
	Material Contracts	88
ITEM 11.	Quantitative and Qualitative Disclosures about Market Risk	98
ITEM 12.	Description of Securities Other than Equity Securities	99
	Reimbursement of Fees and Direct and Indirect Payments by the Depositary	99
ITEM 13.	Defaults, Dividend Arrearages and Delinquencies	99
ITEM 14.	Material Modifications to the Rights of Security Holders and Use Of Proceeds	100
ITEM 15.	Controls and Procedures	100
	Internal Control over Financial Reporting	100
ITEM 16.		100
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	100
ITEM 16B.	CODE OF ETHICS	101

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ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	101
	Audit and Non-Audit Fees	101
	Audit Committee Approval Policies and Procedures	101
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	102
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	102
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	102
ITEM 16G.	CORPORATE GOVERNANCE	102
ITEM 17.	Financial Statements	103
ITEM 18.	Financial Statements	103
ITEM 19.	Exhibits	103
GLOSSARY OF TERMS		103
SIGNATURES		107

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FORWARD-LOOKING STATEMENTS

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

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

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

·electricity shortages;

·changes in tariffs;

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

·potential disruption or interruption of our services;

·inflation and exchange rate variation;

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

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

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

·changes in consumer demand;

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

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

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

CERTAIN TERMS AND CONVENTIONS

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

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PRESENTATION OF FINANCIAL INFORMATION

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

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

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

ITEM 1.Identity of Directors, Senior Management and Advisers

Not applicable.

ITEM 2.Offer Statistics and Expected Timetable

Not applicable.

ITEM 3.Key Information

Selected Financial and Operating Data

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

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

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

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STATEMENT OF OPERATIONS DATA

	For the year ended December 31,
	2010	2010	2009
	US$	R$	R$
	(in millions, except per share and per ADS data)
IFRS
Net operating revenue	7,216	12,024	11,358
Cost of electric energy services:
Cost of electric energy	3,734	6,222	6,015
Operating cost	641	1,068	1,054
Services rendered to third parties	631	1,051	621
Gross operating income	2,210	3,683	3,668
Operating expenses
Sales expenses	181	301	255
General and administrative expenses	266	443	403
Other operating expense	120	200	227
Income from electric energy service	1,643	2,739	2,783
Financial income (expense):
Income	290	483	351
Expense	(502)	(837)	(661)
	(212)	(354)	(310)
Income before taxes	1,431	2,385	2,473
Social contribution	(133)	(221)	(208)
Income tax	(363)	(604)	(576)
	(496)	(825)	(784)
Net income	935	1,560	1,689
Net income attributable to controlling shareholders	922	1,538	1,657
Net income attributable to non controlling shareholders	13	22	32
Net income per share	1.92	3.20	3.45
Net income per ADS	5.76	9.60	10.36
Dividends(1)	756	1,260	1,227
Weighted average of number of common shares	481	481	480
Dividends per share(1)	1.57	2.62	2.56
Dividends per ADS(1)	4.72	7.86	7.67

BALANCE SHEET DATA

	For the year ended December 31,
	2010	2010	2009
	US$	R$	R$
	(in millions)
IFRS
Current assets:
Cash and cash equivalents	938	1,563	1,487
Accounts receivable	1,090	1,816	1,753
Other current assets	312	519	409
Total current assets	2,340	3,898	3,649
Non-current assets:
Accounts receivable	117	196	225
Financial asset of concession	561	935	674
Property, plant and equipment	3,473	5,786	5,213
Intangible Assets	3,952	6,585	6,063
Other non-current assets	1,595	2,657	2,666
Total non-current assets	9,698	16,159	14,841
Total assets	12,038	20,057	18,490
Current liabilities:
Short-term debt(2)	1,351	2,251	1,364
Other current liabilities	1,307	2,177	2,059
Total current liabilities	2,658	4,428	3,423
Long-term liabilities:
Long-term debt(2)	4,302	7,167	6,548
Other long-term liabilities	1,027	1,712	1,983
Total long-term liabilities	5,329	8,879	8,531
Noncontrolling interest	154	256	267
Shareholders’ equity	3,897	6,494	6,269
Total liabilities and shareholders’ equity	12,038	20,057	18,490

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OPERATING DATA(*)

	For the year ended December 31,
	2010	2009	2008	2007	2006
Energy sold (in GWh):
Residential	12,983	12,346	11,649	10,766	9,489
Industrial	15,413	14,970	16,066	16,692	16,882
Commercial	7,695	7,297	6,938	6,509	5,779
Rural	2,100	2,256	2,449	2,511	1,966
Public administration	1,112	1,074	1,027	972	862
Public lighting	1,444	1,408	1,355	1,284	1,152
Public services	1,742	1,664	1,634	1,590	1,472
Own consumption	33	33	32	30	25
Total energy sold to Final Consumers	42,522	41,048	41,150	40,354	37,627
Electricity sales to wholesalers (in GWh)	12,737	12,925	9,551	8,731	7,461
Total consumers (in thousands)(3)	6,748	6,567	6,425	6,257	5,749
Installed capacity (in MW)	2,309	1,737	1,704	1,588	1,072
Assured energy (in GWh)	7,786	7,485	7,134	6,698	4,962
Energy generated (in GWh)	9,142	5,984	6,659	6,382	3,407

(*)           Unaudited.

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

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

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

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Exchange Rates

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

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

	Year-end	Average for period(1)	Low	High
	(reais per U.S. dollar)
Year ended:
December 31, 2006	2.138	2.168	2.059	2.371
December 31, 2007	1.771	1.930	1.733	2.156
December 31, 2008	2.337	1.833	1.559	2.500
December 31, 2009	1.741	1.990	1.702	2.422
December 31, 2010	1.666	1.759	1.655	1.881

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

	Month-end	Average for period(1)	Low	High
	(reais per U.S. dollar)
Month ended:
December 2010	1.666	1.693	1.666	1.712
January 2011	1.673	1.675	1.651	1.691
February 2011	1.661	1.668	1.661	1.678
March 2011	1.629	1.659	1.629	1.676
April 2011	1.573	1.586	1.565	1.619
May 2011	1.580	1.613	1.575	1.634
June (through June 3rd,2011)	1.574	1.581	1.574	1.588

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

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RISK FACTORS

Risks Relating to Our Operations and the Brazilian Power Industry

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

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

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

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

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

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

We are uncertain as to the renewal of our concessions.

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

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

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

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

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

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

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

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

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

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

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

·warning notices;

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

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

·restrictions on the operation of existing facilities and equipment;

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

·termination of the concession.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

·the inability to obtain required governmental permits and approvals;

·the unavailability of equipment;

·supply interruptions;

·work stoppages;

·labor unrest;

·social unrest;

·weather and hydrological interferences;

·unforeseen engineering and environmental problems;

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

·construction and operational delays, or unanticipated cost overruns;

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

·unavailability of adequate funding.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Relating to Brazil

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

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

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·interest rates;

·monetary policy;

·currency fluctuations;

·inflation; 

·liquidity of domestic capital and lending markets;

·tax policies;

·changes in labor laws;

·regulatory environment of our sector;

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

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

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

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

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

Depreciation of thereal 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 thereal against the U.S. dollar could create inflationary pressures in Brazil and cause increases in interest rates, which could negatively affect the growth of the Brazilian economy as a whole and harm our financial condition and results of operations, may curtail access to foreign financial markets and may prompt government intervention, including recessionary governmental policies.  Depreciation of thereal against the U.S. dollar can also lead to decreased consumer spending, deflationary pressures and reduced growth of the economy as a whole.  On the other hand, appreciation of thereal relative to the U.S. dollar and other foreign currencies could lead to a deterioration of the Brazilian foreign exchange current accounts, as well as dampen export-driven growth.  Depending on the circumstances, either depreciation or appreciation of thereal could materially and adversely affect the growth of the Brazilian economy and our business, financial condition and results of operations.

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

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

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

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

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

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

Risks Relating to the ADSs and Our Common Shares

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

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

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

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

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

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

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

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

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

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

ITEM 4.Information on the Company

Overview

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our core businesses are:

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

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

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

Capital Expenditures

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

Our Strategy

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

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

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

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

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

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

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

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

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

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Our Service Territory 

Distribution

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

² The 15% decrease as compared to 2009 was due to the fact that certain cooperatives within RGE concession distribution area have been classified by ANEEL as permissionaries (and, as such, they are now considered as distributors).  However, this decrease did not  impact our revenues and results of operations.

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Distribution Companies

We have eight distribution subsidiaries:

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

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

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

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

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

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

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

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

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Distribution Network

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

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

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

System Performance

Electricity Losses

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

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

Power Outages

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

	Year ended December 31, 2010
	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Jaguari	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista
FEC1	5.05	5.22	9.66	6.52	7.81	4.52	7.69	7.75
DEC2	5.65	6.88	14.71	5.49	9.24	4.59	8.28	9.21

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

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

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	Year ended December 31, 2009
	CPFL Paulista*	CPFL Piratininga*	RGE	CPFL Santa Cruz*	CPFL Jaguari*	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista
FEC1	5.77/5.07*	6.41/5.35*	8.80	7.55/7.27*	6.06/5.07*	8.27	10.75	7.37
DEC2	7.62/5.76*	11.02/6.68*	14.45	5.47/5.34*	10.61/6.07*	8.18	11.31	8.94

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

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

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

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

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

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

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

Purchases of Electricity

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

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

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

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

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

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

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

	Year Ended December 31,
	2010	2009	2008
	(in GWh)
Electricity purchased in the regulated market:
Itaipu	10,835	11,084	11,085
Tractebel Energia S.A	7,482	6,827	7,128
Petrobrás – Petróleo Brasileiro S.A	1,717	1,721	1,718
Furnas Centrais Elétricas S.A	1,673	1,649	1,261
Electric Energy Trading Chamber – CCEE	3,373	3,101	2,820
Companhia Energética de São Paulo – CESP	1,759	1,808	1,711
Companhia Hidro Elétrica do São Francisco – CHESF	1,343	1,318	1,255
Companhia Energética de Minas Gerais – CEMIG	1,036	1,357	723
TermoRio S.A	454	248	341
Copel Geração S.A	694	713	343
PROINFA	1,133	958	629
Other	5,123	5,710	4,134
Total	36,622	36,494	33,148
Electricity purchased in the free market	15,762	16,180	16,183
Total	52,384	52,674	49,331

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

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

Consumers and Tariffs

Consumers

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

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

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

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

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

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

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

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

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

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

	Year ended December 31, 2010
	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari	CPFL Mococa
	(R$/MWh)
Residential	400.76	394.42	509.89	432.07	458.09	452.57	379.55	507.27
Industrial	311.90	295.54	346.97	323.89	342.95	287.54	275.80	330.85
Commercial	339.05	347.41	491.23	395.70	428.93	432.77	344.44	428.78
Rural	181.49	213.16	235.64	212.40	232.12	243.18	198.59	243.94
Other	250.07	246.31	231.00	184.17	303.61	295.12	246.49	294.39
Total	334.34	335.74	380.34	323.59	352.11	353.03	296.27	376.04

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	Year ended December 31, 2009
	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari	CPFL Mococa
	(R$/MWh)
Residential	398.32	395.34	491.34	429.88	484.73	430.10	360.57	490.49
Industrial	327.86	295.26	336.76	339.46	339.35	263.53	250.56	299.13
Commercial	354.52	347.04	475.34	397.54	452.73	420.92	321.30	414.27
Rural	187.99	213.20	190.49	214.15	261.68	238.05	113.10	245.44
Other	259.81	246.29	272.76	185.74	316.43	284.78	246.81	285.03
Total	343.05	335.52	366.56	328.62	373.34	330.25	268.99	360.55

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

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

Billing Procedures

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

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

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

Customer Service

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

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

Generation of Electricity

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

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

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

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

	Installed capacity	Assured energy	Placed in service	Facility upgraded	Concession expires
	(MW)	(GWh/year)
Hydroelectric plants:
Serra da Mesa............................................................	1,275.0	5,878.0	1998		(1)
Our share of Serra da Mesa (51.54%)...................	657.1	3,029.5
Monte Claro..............................................................	130.0	516.8	2004		2036
Our share of Monte Claro (65%)..........................	84.5	335.9
Barra Grande.............................................................	690.0	3,334.1	2005		2036
Our share of Barra Grande (25.01%)....................	172.5	833.7
Campos Novos..........................................................	880.0	3,310.4	2007		2035
Our share of Campos Novos (48.72%).................	428.8	1,612.9
Castro Alves..............................................................	130.0	560.6	2008		2036
Our share of Castro Alves (65%)..........................	84.5	364.4
14 de Julho................................................................	100.0	438.0	2008		2036
Our share of 14 de Julho (65%)............................	65.0	284.7
Luis Eduardo Magalhães...........................................	902.5	4,613.0	2001		2032
Our share of Luis Eduardo Magalhães (6.93%)....	62.5	319.7
Foz do Chapecó.........................................................	855.0	3,784.3	2010		2036
Our share of Foz do Chapecó (51%).....................	436.1	1,930.0
Subtotal (our share only).......................................	1,991.1	8,710.8

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Small hydroelectric power plant	Installed capacity	Assured energy	Placed in service	Facility upgraded	Concession expires
	(MW)	(GWh/year)
Americana	30.0	78.8	1949	2002	2027
Andorinhas	0.5	4.0	1937	(2)	(4)
Buritis	0.8	7.9	1922	2027
Capão Preto	4.3	20.0	1911	2008	2027
Cariobinha	1.3	0	1936	(3)	2027
Chibarro	2.6	14.8	1912	2008	2027
Dourados	10.8	68.0	1926	2002	2027
Eloy Chaves	19.0	106.9	1954	1993	2027
Esmeril	5.0	25.2	1912	2003	2027
Gavião Peixoto	4.8	33.5	1913	2007	2027
Guaporé	0.7	5.4	1950	(2)	(4)
Jaguari	11.8	78.8	1917	2002	2027
Lençóis	1.7	14.7	1917	1988	2027
Monjolinho	0.6	2.7	1893	2003	2027
Pinhal	6.8	32.4	1928	1993	2027
Pirapó	0.7	5.6	1952	(4)
Saltinho	0.8	6.4	1950	(4)
Salto do Pinhal	0.6	0	1911	(3)	2027
Salto Grande	4.6	23.8	1912	2003	2027
Santana	4.3	25.4	1951	2002	2027
São Joaquim	8.1	49.3	1911	2002	2027
Socorro	1.0	5.3	1909	1994	2027
Três Saltos	0.6	5.3	1928	2027
Ponte do Silva	0.1	0	1956	(4)
Lavrinha	0.3	(5)	1947	(4)
Macaco Branco	2.4	(5)	1911	2015
Pinheirinho	0.6	(5)	1911	(4)
Rio do Peixe I	3.1	(5)	1925	2015
Rio do Peixe II	15.0	(5)	1998	2015
Santa Alice	0.6	(5)	1907	(4)
São José	0.8	(5)	1934	(4)
São Sebastião	0.7	(5)	1925	(4)
Turvinho	0.8	(5)	1912	(4)
Diamante	4.2	15.5
Sub total	150.0	629.8
Thermoelectric power plants:
Carioba	36.0	93.7	1954	2027
EPASA
Termonordeste	170.8	1,804.5
Our share Termonordeste (51%)	87.1	553.1
Termoparaíba	170.8	1,804.5
Our share Termoparaiba (51%)	87.1	553.1
Baldin	45.0	112.4
Sub total (our share only)	255.2	1,312.3
TOTAL (our share only)	2,396.2	10,652.9

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

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

(3)           Power plants that are not active.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Expansion of Installed Capacity

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

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

	Estimated Installed Capacity	Estimated Assured Energy	Estimated Construction Cost	Start of Construction	Expected Start of Operations	Our Ownership	Estimated Installed Capacity Available	Estimated Assured Energy Available to us
	(MW)	(GWh/yr)	(R$ million)			(%)		(GWh/yr)
CPFL Bio Formosa	40	140.2	127	March 2010	2011	100.0	40	140.2
CPFL Bio Buriti	50	184.1	135	September 2010	2011	100.0	50	184.1
CPFL Bio Ipê	25	71.7	26	July 2010	2011	100.0	25	71.7
CPFL Bio Pedra	70	213.9	205	October 2010	2012	100.0	70	213.9
Santa Clara wind farms	188	665.8	801	August 2010	2012	100.0	188	665.8
Campo dos Ventos II wind farm	30	122.6	127	Second quarter 2011	2013	100.0	30	122.6
Campo dos Ventos I, III, IV, V and Eurus V wind farms	150	543.1	600	Awaiting approval from ANEEL	2013	100.0	150	543.1
Total	553	1,941.4	2,021				553	1,941.4

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

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

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

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

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

Electricity Commercialization and Services

Commercialization Operations

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

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

·reselling electricity to Free Consumers;

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

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

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

Electricity-Related Services

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

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

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

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

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

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

Competition

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

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

Our Concessions and Authorizations

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

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

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

Concessions

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

Concession no.	Concessionaire	State	Term
014/1997	CPFL Paulista	São Paulo	30 years from November 1997
09/2002	CPFL Piratininga	São Paulo	30 years from October 1998
013/1997	RGE	Rio Grande do Sul	30 years from November 1997
021/1999	CPFL Santa Cruz	São Paulo and Paraná	16 years (from February 1999 to July 2015)
015/1999	CPFL Jaguari	São Paulo	16 years (from February 1999 to July 2015)
017/1999	CPFL Mococa	São Paulo and Minas Gerais	16 years (from February 1999 to July 2015)
018/1999	CPFL Leste Paulista	São Paulo	16 years (from February 1999 to July 2015)
019/1999	CPFL Sul Paulista	São Paulo	16 years (from February 1999 to July 2015)

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

Concession no.	Independent Producers	Plant	State	Term	Maximum renewal period
128/2001	Foz do Chapecó	Foz do Chapecó	Santa Catarina andRio Grande do Sul	35 years fromNovember 2001	At the discretionof ANEEL
036/2001	Barra Grande	Barra Grande	Rio Grande do Sul	35 years fromMay 2001	At the discretionof ANEEL
008/2001	CERAN	14 de Julho, Castro Alves andMonte Claro	Rio Grande do Sul	35 years fromMarch 2001	At the discretionof ANEEL
043/2000	ENERCAN	Campos Novos	Santa Catarina	35 years fromMay 2000	At the discretionof ANEEL
005/1997	Investco	Luiz EduardoMagalhães Our 19 smallhydroelectricpower plants andone thermoelectricfacility	Tocantins	35 years fromDecember 1997	At the discretionof ANEEL
015/1997	CPFL Geração		São Paulo	30 years fromNovember 1997	30 years
Decree No.85,983/81	CPFL Geração	Serra da Mesa	Goiás	(1)	20 years
09/1999	CPFL Jaguari	Macaco Branco (small hydroelectric power plant)	São Paulo	16 years (from February 1999 to July 2015)	20 years
10/1999	CPFL Leste Paulista	Rio do Peixe I and II (small hydroelectric power plant)	São Paulo	16 years (from February 1999 to July 2015)	20 years

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

Authorizations

Authorization no.	Independent Producers	Plant	State	Term	Maximum  renewal period
2106/2009	CPFL Bioenergia S.A.	Baldin thermoelectric power plan	São Paulo	30 years fromSeptember 24, 2009	-
2277/2010	Centrais Elétricas da Paraíba S.A. - EPASA	Termoparaíba thermoelectric power plant	Paraíba	35 years fromDecember 7, 2007	At the discretion of MME
2277/2010	Centrais Elétricas da Paraíba S.A. - EPASA	Termonordeste thermoelectric power plant	Paraíba	35 years fromDecember 12, 2007	At the discretion of MME
259/2002	CPFL Bio Formosa S.A.	Baía Formosa thermoelectric power plant	Rio Grande do Norte	30 years fromMay 15, 2002	At the discretion of ANEEL
2643/2010	CPFL Bio Buriti	Buriti thermoelectric power plant	São Paulo	30 years fromDecember 7, 2010	At the discretion of ANEEL
2375/2010	CPFL Bio Ipê	Ipê thermoelectricpower plant	São Paulo	30 years from May 3, 2010	At the discretion of ANEEL
129/2010	CPFL Bio Pedra	Pedra thermoelectric power plant	São Paulo	35 years from February 28, 2010	At the discretion of ANEEL
609/2010	Santa Clara I Energias Renováveis	Santa Clara I	Rio Grande doNorte	35 years from July 1, 2010	At the discretion of ANEEL
683/2010	Santa Clara II Energias Renováveis	Santa Clara II	Rio Grande doNorte	35 years from August 4, 2010	At the discretion of ANEEL
610/2010	Santa Clara III Energias Renováveis	Santa Clara III	Rio Grande doNorte	35 years from July 1, 2010	At the discretion of ANEEL
672/2010	Santa Clara IV Energias Renováveis	Santa Clara IV	Rio Grande doNorte	35 years from July 29, 2010	At the discretion of ANEEL
838/2010	Santa Clara V Energias Renováveis	Santa Clara V	Rio Grande doNorte	35 years from October 8, 2010	At the discretion of ANEEL
670/2010	Santa Clara VI Energias Renováveis	Santa Clara VI	Rio Grande doNorte	35 years from July 29, 2010	At the discretion of ANEEL
749/2010	Eurus VI Energias Renováveis	Eurus VI	Rio Grande doNorte	35 years from August 24, 2010	At the discretion of ANEEL

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Independent Producers

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

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Concessionaires

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

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

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

Properties

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

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

Environmental

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

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

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

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

The Brazilian Power Industry

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

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

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

Principal Regulatory Authorities

Ministry of Mines and Energy — MME

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

National Energy Policy Council — CNPE

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

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

National Electrical System Operator — ONS

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

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Electric Energy Trading Chamber — CCEE

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

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

Energy Research Company — EPE

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

Energy Industry Monitoring Committee — CMSE

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

Concessions, Permissions and Authorizations

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

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

Concessions

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

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

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

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

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

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

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

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

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

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

Permissions

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

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Authorizations

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

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

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

The New Industry Model Law

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

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

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

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

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

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

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

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

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

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

Parallel Environment for the Trading of Electric Energy

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

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

The Regulated Market

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

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

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

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

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The Free Market

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

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

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

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

Auctions on the Regulated Market

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

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

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

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

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

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

The Annual Reference Value

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

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

Electric Energy Trading Convention

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

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

Restricted Activities of Distributors

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

Elimination of Self-Dealing

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

Challenges to the Constitutionality of the New Industry Model Law

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

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

Ownership Limitations

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

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

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

Tariffs for the Use of the Distribution and Transmission Systems

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

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TUSD

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

TUST

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

Distribution Tariffs

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

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

·costs of electricity purchased from Itaipu;

·costs of electricity purchased pursuant to bilateral agreements that are freely negotiated between the parties;

·costs of electricity purchased pursuant to CCEARs;

·certain other charges for use and connection to the transmission and distribution systems;

·the cost of regulatory charges; and

·the costs associated with research and development and energy efficient consumption.

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

·a rate of return on investments in energy distribution assets;

·the depreciation on those assets;

·the operating expenses related to the operation of those assets; and

·non‑recoverable receivables;

each as established and periodically revised by ANEEL.

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The tariffs are established taking into consideration Parcel A and Parcel B costs and certain market components used by ANEEL as reference for adjusting the tariffs.

Electricity distribution concessionaires are entitled to periodic revisions of their tariffs 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 the services within the scope of each such company’s concession and (ii) determining the “X factor”, which is based on three components:  (a) expected gains of productivity from increase in scale, (b) labor costs, and (c) investments.  The X factor calculated in the tariff review will be recalculated in the next tariff cycle by changing only the sum of investments carried out, that is, the investments made in permanent service assets.  If the sum of investments is smaller in the next tariff cycle, the recalculated X factor is compared against the previous one and the difference between them is multiplied in a way that reflects the cost of the resources allocated to the tariff and not used by the concessionaire.  The X factor is used to adjust the proportion of the change in the IGP-M index that is used in the annual adjustments.  Accordingly, upon the completion of each periodic revision, application of the X factor requires distribution companies to share their productivity gains with Final Consumers.

Each distribution company’s concession agreement also provides for an annual adjustment.  In general, Parcel A costs are fully passed through to consumers.  Parcel B costs, however, are mostly restated for inflation in accordance with the IGP-M index.

In addition, electricity distribution concessionaires are entitled to an extraordinary tariff review (revisão extraordinária) on a case-by-case basis, to ensure their financial stability and compensate them for unpredictable costs, including taxes that significantly change their cost structure.

With the introduction of the New Industry Model Law, the MME has acknowledged that the variable costs associated with the purchase of electric energy may be included by means of the Parcel A Account or CVA, an account created to recognize some of our costs when ANEEL adjusts the tariffs of our distribution subsidiaries.  See “Item 5—Operating and Financial Review and Prospects—Overview—Recoverable Costs Variations—Parcel A Costs.”

In October 2006, ANEEL established the methodology and procedures applicable to the periodic revisions for 2007 through 2010 for distribution concessionaires, based on the practices developed during a previous round of the periodic tariff reviews.  Currently, new regulation from ANEEL aiming at improving the revision process is under public consideration.  For information on the new methodology applicable to the third periodic revision cycle, see “Item 3.  Risk Factors—The tariffs that we charge for sales of electricity to captive consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us.”

Government Incentives to the Energy Sector

In 2000, a Federal decree created the Thermoelectric Priority Program,Programa Prioritário de Termeletricidade (“PPT”) for purposes of diversifying the Brazilian energy matrix and decreasing its strong dependency on hydroelectric plants.  The incentives granted to the thermoelectric power plants included in the PPT are:  (i) guaranty of gas supply for twenty years, pursuant to MME regulations, (ii) an assurance that the costs related to the acquisition of the electric energy produced by thermoelectric power plants will be transferred to tariffs up to the normative value established by ANEEL and (iii) guaranteed access to a special financing program for the electric energy industry from the Brazilian Economic and Social Development Bank (“BNDES”).

In 2002, the Federal Government established the Proinfa Program.  Under the Proinfa Program, Eletrobrás purchases the energy generated by alternative energy sources for a period of up to 20 years, and this energy is to be acquired by distribution companies for delivery to Final Consumers.  In its initial phase, the Proinfa Program is limited to a total contracted capacity of 3,300 MW.  The objective of this initiative is to reach a contracted capacity of up to 10.0% of the total annual consumption of electricity in Brazil within 20 years from 2002.  Energy to be sold in the program will not be produced by generation concessionaires, like us, nor by IPPs, but by an autonomous independent producer, which may not be controlled by or affiliated with a generation concessionaire or an IPP, or affiliated with their controlling entities.  Pursuant to Provisional Measure No. 512/2010, the initial phase of the Proinfa Program will end on December 31, 2011.

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In order to create incentives for alternative generators, the Federal Government has established that a reduction of not less than 50.0% must be applied to TUSD amounts owed by (i) small hydroelectric power plants with capacity between 1,000 kW and 30,000 kW, (ii) generators with capacity equal to 1,000 kW and (iii) alternative energy generators (solar, eolic and biomass generators) with capacity equal to 30,000 kW.  The reduction is applicable to the TUSD due by the generation source and also by its consumer.  The amount of the TUSD reduction will be included as “financial components” in the tariff readjustment or tariff revision.

Regulatory Charges

EER

The Reserve Energy Charge,Encargo de Energia de Reserva (“EER”) is a regulatory charge assessed on a monthly basis designed to raise funds for energy reserves contracted by CCEE.  These energy reserves will be used to increase the safety of the energy supply in the Interconnected Power System.  The EER is collected from Final Consumers of the Interconnected Power System on a monthly basis.  Exceptionally, in 2009, the EER was collected in a single installment in March.

RGR Fund and UBP

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 funds for such compensation (“RGR Fund”).  Public-industry electric companies must 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 3.0% of total operating revenues in any year.  The amount of this fee was most recently revised by ANEEL in February, 1999.  In recent years, no concessions have been revoked or have failed to be renewed, and the RGR has been used principally to finance generation and distribution projects.  The RGR should be phased out by 2010.  However, Provisional Measure No. 517/2010 was enacted, aiming at extending the imposition of this fee until 2035.  On March 28, 2011, the Provisional Measure was extended by 60 days.  During this period, the Brazilian Congress should vote whether to convert the Provisional Measure into law or not.  Additionally,theBrazilian government is currently discussing the possibility of gradually suppressing the RGR Fund.

The Federal Government has imposed a fee on IPPs similar to the fee levied on public-industry generation companies in connection with the RGR.  IPPs are required to make contributions for using a public asset,Uso de Bem Público(“UBP”) according to the rules set out in the relevant concession’s public bidding process.  Eletrobrás received the UBP payments until December 31, 2002.  All payments related to the UBP since December 31, 2002 have been paid directly to the Federal Government.

CCC Account

Distribution companies (and also some transmission companies responsible for Free Consumers) must contribute to theConta de Consumo de Combustível (“CCC Account”).  The CCC Account was created in 1973 to generate financial reserves to cover fossil fuel costs in thermoelectric power plants in the event of a rainfall shortage which would require increased use of thermal plants.  The CCC currently subsidizes the distribution systems in isolated areas where distribution costs are higher than in the Interconnected Power System.  The annual CCC Account contributions are calculated on the basis of estimates of the cost of fuel needed by the thermoelectric power plants in the succeeding year.  The CCC Account is administered by Eletrobrás.  The CCC Account, in turn, reimburses electric companies for a substantial portion of the fuel costs of their thermoelectric power plants.

In February 1998, the Federal Government provided for the phasing out of the CCC Account.  During the 2003‑2006 period, subsidies from the CCC Account were phased out for thermal power plants constructed prior to February 1998 and belonging to the Interconnected Power System.  Thermal power plants constructed after that date were not entitled to subsidies from the CCC Account.  In April 2002, the Federal Government established that subsidies from the CCC Account would continue to be paid, for a period of 20 years, to those thermoelectric power plants located in isolated systems.  As of January 2010, according to Law No. 12,111, the CCC Account reimburses electric companies not only for fuel costs in the isolated systems but also for costs incurred with power, operational activities, maintenance, social contribution and taxes related to the generation of energy.

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CDE Account

In 2002, the Federal Government instituted the Electric Energy Development Account,Conta de Desenvolvimento Energético (“CDE Account”), which is funded through annual payments made by concessionaires for the use of public assets, penalties and fines imposed by ANEEL and the annual fees paid by agents offering electric energy to Final Consumers, by means of a charge to be added to the tariffs for the use of the transmission and distribution transmission 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 universalization of electric energy services throughout Brazil.  The CDE Account will be in effect for 25 years from 2002 and is regulated by the executive branch and managed by Eletrobrás.

ESS

Resolution no. 173 of November 28, 2005 established a provision for the System Service Charge,Encargo de Serviço do Sistema (“ESS”), which since January 2006 has been included in price and fee readjustments for distribution concessionaires that are part of the National Interconnected Grid, Sistema Interligado Nacional.  This charge is based on the annual estimates made by ONS on October 31 of each year.

Fee for the Use of Water Resources

The New Industry Model Law requires that holders of a concession and authorization to use water resources must pay a fee of 6.75% of the value of the energy they generate by using such facilities.  This charge must be paid to the federal district, states and municipalities where the plant or the plant’s reservoir is located.

ANEEL Inspection Fee (TFSEE)

The ANEEL Inspection Fee is an annual fee due by the holders of concessions, permissions or authorizations in the proportion of their dimension and activities.  Currently, the ANEEL Inspection Fee is deducted from the RGR Fund.

Default on the Payment of Regulatory Charges

The New Industry Model Law provides that failure to pay required contributions to the RGR Fund, Proinfa Program, CDE Account, CCC Account, or certain other payments, such as those due from the purchase of electric energy in the regulated market or from Itaipu, will prevent the defaulting party from proceeding with readjustments or reviews of its tariffs (except for extraordinary reviews) and will also prevent the defaulting party from receiving funds from the RGR Fund, CDE Account or CCC Account.

Energy Reallocation Mechanism

Centrally dispatched hydrogenerators are protected against certain hydrological risks by the MRE, which attempts to mitigate the risks involved in the generation of hydrological energy by mandating that hydrogenerators share the hydrological risks of the Interconnected Power System.  Under Brazilian law, each hydroelectric plant is assigned an “assured energy”, which is determined in each relevant concession agreement, irrespective of the volume of electricity generated by the facility.  The MRE transfers surplus electricity from those generators that have produced electricity in excess of their assured energy to those generators that have produced less than their assured energy.  The effective generation dispatch is determined by ONS, which takes into account nationwide electricity demand and hydrological conditions.  The volume of electricity actually generated by the plant, whether less than or in excess of the assured energy, is priced pursuant to a tariff denominated “Energy Optimization Tariff” which covers the operation and maintenance costs of the plant.  This revenue or additional expense must be accounted for monthly by each generator.

ITEM 4B.UNRESOLVED STAFF COMMENTS

None.

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ITEM 5.OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion should be read in conjunction with our audited consolidated financial statements and the notes thereto included elsewhere in this annual report.

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

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

Overview

We are a holding company and, through subsidiaries, we (i) distribute electricity to consumers in our concession areas, (ii) generate electricity and develop generation projects and (iii) engage in electricity commercialization and the provision of electricity-related services.  The most important drivers of our financial performance are the operating income margin and cash flows from our regulated distribution business.  In recent years, this business has produced reasonably stable margins, and its cash flows, while sometimes subject to short‑term variability, have been stable over the medium term.

We account for four of our generation subsidiaries (BAESA, ENERCAN, Foz do Chapecó and Centrais Elétricas da Paraíba – EPASA) using the proportionate consolidation method.  Upon adoption of IFRS, our generation subsidiary CERAN has become fully consolidated.  The first generation unit of Foz do Chapecó became operational in October 2010, the second generation unit became operational in November 2010, the third generation unit became operational in December 2010 and the fourth and final generation unit became operational in March 2011.  The thermoelectric power plants Termoparaíba and Termonordeste, both powered by fuel oil from the EPASA complex, became operational in December 2010 and January 2011, respectively.

In September 2009, we acquired seven generation subsidiaries (Santa Clara I, Santa Clara II, Santa Clara III, Santa Clara IV, Santa Clara V, Santa Clara VI and Eurus VI), which are fully consolidated.  They are scheduled to start operations in the third quarter of 2012.  In July 2010, we acquired other six generation subsidiaries (Campo dos Ventos I, II, III, IV and V and Eurus V), which are also fully consolidated.  They are scheduled to start operations in the third quarter of 2013.  All of the thirteen generation subsidiaries were acquired to invest in and act as independent producers of electric energy from alternative sources, mainly wind power.

Additionally, in October 2009, we established CPFL Bio Formosa, which is fully consolidated in our financial statements.  The main purpose of CPFL Bio Formosa is the generation of thermoelectric energy through co‑generation plants powered by sugar-cane bagasse and straw.  It is scheduled to start operations in the third quarter of 2011. 

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

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In 2011, we entered into a Sale and Purchase Agreement for the acquisition of 100% of the shares of Jantus, a company engaged in generation of energy through renewable sources, especially wind power, and into a Joint Venture Agreement with ERSA to combine assets and projects relating to renewable energy sources.  Both the acquisition of Jantus and the joint venture with ERSA are still subject to certain conditions, including approval by the regulatory authorities. 

We have three broad initiatives to improve our financial performance:  the expansion of our installed capacity, the acquisition of additional distributors and the development of our commercialization and electricity‑related services business.  We have a portfolio of new hydroelectric generation projects that are becoming operational.  Of this new generation capacity, taking into account our share of jointly-owned projects, approximately 32.5 MW became operational in 2009, approximately 572 MW became operational in 2010 and approximately 202 MW are expected to become operational by the end of 2011.  We expect a further 294.2 MW of new generation capacity to become operational by the end of 2013.

There are factors beyond our control that can have a significant impact, positive or adverse, on our financial performance.  We face periodic changes in our rate structure, resulting from the periodic revision of our rates.  For instance, the second cycle of periodic revisions, which took effect during 2007 and 2008 at each of our distribution companies, resulted in the reduction of our average rates.  For information on the new methodology applicable to the third periodic revision cycle (2011 to 2014), see “Item 3.  Risk Factors—The tariffs that we charge for sales of electricity to captive consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us.”

Background

Regulated Distribution Tariffs

Our results of operations are significantly affected by changes in regulated tariffs for electricity.  In particular, most of our revenues are derived from sales of electricity to captive Final Consumers at regulated tariffs.  In 2010, sales to captive consumers represented 71.0% of the volume of electricity we delivered and 76.1% of our operating revenues, compared to 70.1% and 78.6%, respectively, in 2009.  These proportions may decline if consumers migrate from captive to free status.

Our operating revenues and our margins depend substantially on the tariff-setting process, and our management focuses on maintaining a constructive relationship with ANEEL, the Brazilian government and other market participants so that the tariff-setting process fairly reflects our interests and those of our consumers and shareholders.  For a description of tariff regulations, see “Item 4.  Information on the Company—The Brazilian Power Industry—Distribution Tariffs” and “Item 4.  Information on the Company—Consumers, Analysis of Demand and Tariffs.”

Tariffs are determined separately for each of our eight distribution subsidiaries as follows:

·Our concession agreements provide for an annual adjustment to take account of changes in our costs, which for this purpose are divided into costs that are beyond our control (known as Parcel A costs) and costs that we can control (known as Parcel B costs).  Parcel A costs include, among other things, increased prices under long‑term supply contracts, and Parcel B costs include, among others, the return on investment related to our concessions and their expansion, as well as maintenance and operational costs.  Our ability to fully pass through our electricity acquisition costs to Final Consumers is subject to:  (a) our ability to accurately forecast our energy needs and (b) a ceiling linked to a reference value, the Annual Reference Value.  The Annual Reference Value is the weighted average of electricity acquisition costs resulting from electricity prices of all public auctions carried out by ANEEL and CCEE in the regulated market for electricity to be delivered five and three years from any such auction and only applies during the first three years following the commencement of delivery of the acquired electricity.  See “The Brazilian Power Industry—The New Industry Model Law” for a more detailed description of all the limitations on the ability of distribution companies to fully pass through their electricity acquisition costs to Final Consumers.  Under agreements that were in force before the enactment of these regulatory reforms, we pass through the costs of acquired electricity subject to a        ceiling determined by the Brazilian government.  The annual adjustment of tariffs occurs every April for CPFL Paulista, every June for RGE, every October for CPFL Piratininga and every February for CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari.  There is no annual adjustment in a year with a periodic revision.

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·Our concession agreements provide for a periodic revision (revisão periódica), every five years for CPFL Paulista and RGE and every four years for CPFL Piratininga, CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari, to restore the financial equilibrium of our tariffs as contemplated by the concession agreements and to determine a reduction factor (known as the X factor) in the amount of Parcel B cost increases passed on to our consumers.  ANEEL has submitted the methodology applicable to the third periodic revision cycle (2011 to 2014) to a public hearing, which is expected to be concluded in 2011.  For additional information, see “Item 3.  Risk Factors—The tariffs that we charge for sales of electricity to captive consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us” and “Item 4.  Information on the Company—The Brazilian Power Industry—Distribution Tariffs.”

·Brazilian law also provides for an extraordinary revision (revisão extraordinária) to take account of unforeseen changes in our cost structure.  Since January 2009, our distribution companies no longer collect the extraordinary revision that was instituted as a result of the national energy rationing process that occurred in 2001.

Annual Adjustment

Tariff increases apply differently to different consumer classes, with generally higher increases for consumers using higher voltages, to reduce the effects of historical cross-subsidies in their favor that were mostly eliminated in 2007.  The following table sets forth the average percentage increase in our tariffs resulting from each annual adjustment from 2008 through the date of this annual report.  Rates of tariff increase should be evaluated in light of the Brazilian inflation rate.  See “—Background—Brazilian Economic Conditions.”

	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari
2008
Economic adjustment(1)	(3)	10.92%	(3)	(3)	(3)	(3)	(3)	(3)
Regulatory adjustment(2)	(3)	5.62%	(3)	(3)	(3)	(3)	(3)	(3)
Total adjustment	(3)	16.54%	(3)	(3)	(3)	(3)	(3)	(3)
2009
Economic adjustment(1)	13.58%	2.81%	10.44%	10.69%	10.52%	10.58%	11.80%	11.01%
Regulatory adjustment(2)	7.64%	3.17%	8.51%	13.40%	0.66%	2.36%	-0.16%	0.35%
Total adjustment	21.22%	5.98%	18.95%	24.09%	11.18%	12.94%	11.64%	11.36%
2010(4)
Economic adjustment(1)	1.55%	8.59%	1.72%	1.90%	4.15%	-6.32%	4.30%	5.81%
Regulatory adjustment(2)	1.15%	1.52%	10.65%	8.19%	-0.17%	-6.89%	1.36%	-0.65%
Total adjustment	2.70%	10.11%	12.37%	10.09%	3.98%	-13.21%	5.66%	5.16%
2011
Economic adjustment(1)	6.11%	(5)	(5)	8.01%	6.84%	6.42%	6.57%	5.22%
Regulatory adjustment(2)	1.27%	(5)	(5)	15.60%	2.66%	1.34%	1.45%	0.25%
Total adjustment	7.38%	(5)	(5)	23.61%	9.50%	7.76%	8.02%	5.47%

(1)           This portion of the adjustment primarily reflects the inflation rate for the period and is used as a basis for the following year’s adjustment.

(2)           This portion of the adjustment reflects settlement of regulatory assets and liabilities we record on an accrual basis, primarily the CVA, and is not considered in the calculation of the following year’s adjustment.

(3)           The periodic revision occurred in February 2008 for CPFL Santa Cruz, CPFL Mococa, CPFL Leste Paulista, CPFL Sul Paulista and CPFL Jaguari; and April 2008 for CPFL Paulista and RGE.  Only CPFL Piratininga was subject to an annual adjustment in 2008.

(4)           The 2010 annual adjustment is based on the “Addendum to the Concession Contracts”, described below.

(5)           The annual adjustment will occur in June 2011 for RGE.  The third periodic revision will occur in October 2011 for CPFL Piratininga.

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On February 2, 2010, ANEEL approved a proposal for an addendum to the concession contracts for electric energy  distributors (the “Addendum to the Concession Contracts”).  The Addendum to the Concession Contracts changes the methodology for calculating the annual tariff adjustment, excluding the effect of market variations resulting from the difference between the projected and actual energy sold (mainly related to regulatory charges) from the calculation base when calculating tariff adjustments.  See “The Brazilian Power Industry – Distribution Tariffs” for further information on the calculation of our tariffs.  We do not expect the new calculation methodology to materially affect our future results or financial condition.

The new methodology was applied in calculating the tariff adjustments as of February 2010 for our eight distribution subsidiaries.

Periodic Revisions

The following table sets forth the percentage change in our tariffs resulting from the first and second cycles of periodic revisions.  The third cycle of periodic revisions will begin in 2011 and remains subject to the outcome of public hearing No. 040/2010.

	First cycle		Second cycle
	Adjustment	Total	Adjustment	Economic	Regulatory	Total
	date	adjustment	date	adjustment	adjustment	adjustment
		(%)		(%)	(%)	(%)
CPFL Paulista	April 2003	20.66	April 2008	-14.07	0.07	-14.00
CPFL Piratininga	October 2003	10.14	October 2007	-13.50	0.73	-12.77
RGE	April 2003	27.96	April 2008	-8.11	10.45	2.34
CPFL Santa Cruz	February 2004	17.14	February 2008	-17.05	2.64	-14.41
CPFL Mococa	February 2004	21.73	February 2008	-10.41	2.81	-7.60
CPFL Leste Paulista	February 2004	20.10	February 2008	-3.22	1.04	-2.18
CPFL Sul Paulista	February 2004	12.29	February 2008	-4.59	-0.60	-5.19
CPFL Jaguari	February 2004	- 6.17	February 2008	-3.79	-1.38	-5.17

Sales to Potentially Free Consumers

The Brazilian government has introduced regulatory changes intended to foster the growth of open-market energy transactions by permitting qualifying consumers to opt out of the system of tariff regulation and become “free” consumers entitled to contract freely for electricity.  See “The Brazilian Power Industry—The Free Market.”  To date, as compared to the total number of our captive consumers, the number of potentially Free Consumers is relatively small, but they account for a significant amount of our electricity sales and revenues.  In 2009 and 2010, approximately 22.9% and 22.6%, respectively, of our electricity sales were to supply potentially Free Consumers.  Most of our potentially Free Consumers have not elected to become Free Consumers.  We believe this is because (i) they consider the advantages of negotiating for a long‑term contract at rates lower than the regulated tariff are outweighed by the need to bear additional costs (particularly transmission costs) and the long‑term price risk and (ii) some of our potentially Free Consumers, who entered into contracts before July 1995, may only change to suppliers that purchase from renewable energy sources, such as small hydroelectric power plants or biomass.  Even if a consumer decides to migrate from the regulated tariff system and become a Free Consumer, it still has to pay us network usage charges, and such payments would mitigate the loss in operating income from any such migration.  We do not expect to see a substantial number of our consumers become Free Consumers, but the prospects for migration between the different markets (captive and free) over the long term, and its implications for our financial results, are difficult to predict.

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Prices for Purchased Electricity

The prices of electricity purchased by our distribution companies under long‑term contracts executed in the regulated market are (i) approved by ANEEL in the case of agreements entered into before the New Industry Model Law and (ii) determined in auctions for agreements entered into thereafter, while the prices of electricity purchased in the free market are agreed by bilateral negotiation based on prevailing market rates.  In 2010, we purchased 52,384 GWh, compared to 52,674 GWh in 2009.  Prices under long‑term contracts are adjusted annually to reflect increases in certain generation costs and inflation.  Most of our contracts have adjustments linked to the annual adjustment in distribution tariffs, so that the increased costs are passed through to our consumers in increased tariffs.  Since an increasing proportion of our energy is purchased at public auctions, the success of our strategies in these auctions affects our margins and our exposure to price and market risk, as our ability to pass through costs of electricity purchases depends on the successful projection of our expected demand.

We also purchase a substantial amount of electricity from Itaipu under take-or-pay obligations at prices that are governed by regulations adopted under an international agreement.  Electric utilities operating under concessions in the Midwest, South and Southeast regions of Brazil are required by law to purchase a portion of Brazil’s share of Itaipu’s available capacity.  In 2010, we purchased 10,835 GWh of electricity from Itaipu (20.7% of the electricity we purchased in terms of volume), as compared to 11,084 GWh of electricity from Itaipu (21.0% of the electricity we purchased) in 2009.  See “Item 4.  Information of the Company—Purchases of Electricity—Itaipu.”  The price of electricity from Itaipu is set in U.S. dollars to reflect the costs of servicing its indebtedness.  Accordingly, the price of electricity purchased from Itaipu increases in Brazilianreaiswhen thereal depreciates against the U.S. dollar (and decreases when therealappreciates).  The change in our costs for Itaipu electricity in any year is subject to the Parcel A cost recovery mechanism described below.

In 2010, our installed capacity reached 2,309 MW.  CPFL Bioenergia, Foz do Chapecó and Termonordeste power plants started operations in August, October and December 2010, respectively.  In July 2010, we acquired Campo dos Ventos wind farms in the state of Rio Grande do Norte.  Also in 2010, we constituted CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra to develop electric energy generation projects from sugar cane bagasse in partnership with Grupo Pedra Agroindustrial.  In January 2011, Termoparaíba plant started operations.  As a result of our electric energy generation projects in progress (excluding the acquisition of Jantus and the joint venture with ERSA), our installed capacity will increase 27.7% by 2013.

We expect our margins to be higher to the extent our distribution companies resell electricity generated by our generation subsidiaries, because we will benefit from the generating companies’ margins.

Most of the electricity we acquired in the free market was purchased by our commercialization subsidiary CPFL Brasil, which resells electricity to Free Consumers and other concessionaries and licensees (including our subsidiaries).  In 2010, we acquired 15,762 GWh in the free market, or 30.1% of the electricity we purchased compared to 16,180 GWh in 2009, or 30.7% of the electricity we purchased.  See “—The Brazilian Power Industry—The Free Market.”

Recoverable Cost Variations—Parcel A Costs

We use the CVA or the Parcel A account to recognize some of our costs in the distribution tariff, referred to as “Parcel A” costs, that are beyond our control.  When these costs are higher than the forecasts used in setting tariffs, we are generally entitled to recover the difference through subsequent annual tariff adjustments.  Brazilian Accounting Principles, which was our accounting practice until December 2009, allowed us to account for such difference in our financial statements.

Under IFRS, regulatory assets and liabilities cannot be accounted for because they do not comply with assets and liabilities requirements established by the Framework for the Preparation and Presentation of Financial Statements (Estrutura Conceitual para Elaboração e Apresentação das Demonstrações Contábeis) issued by IASB and the Brazilian Securities Commission,Comissão de Valores Mobiliários(“CVM”).  Therefore, we only account for rights or compensations when our captive clients effectively pay us.

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The costs of electricity purchased from Itaipu are indexed to the U.S. dollar exchange variation.  If the U.S. dollar appreciates against thereal, our costs will increase and, consequently, our revenues will decrease in the same period.  These losses will be offset in the future, when the next annual tariff adjustments occur.

Operating Segments

As in previous years, our three reportable segments are distribution, generation and commercialization.  See note 31 to our audited consolidated financial statements.  Our generation and commercialization segments currently represent a small percentage of our net revenues:  4.5% and 8.4% in 2010, and 4.0% and 10.0% in 2009, respectively.  However, the contribution of our generation and commercialization segments to our net income was higher (16.5% and 13.2% in 2010 for the generation and commercialization segments, respectively).

The profitability of our segments differs.  Our distribution segment reflects primarily sales to captive consumers at prices determined by the regulatory authority.  The volume sold varies according to external factors such as weather, income level and economic growth.  This segment represents 87.1% of our net operating revenue, but its contribution to our net income is smaller.  In 2010, 74.9% of our net income was derived from our distribution activities.

Our generation segment consists in substantial part of new hydroelectric plants, wind farms and thermoelectric projects which require a high level of investment in fixed assets, and in the early years there is typically a high level of construction financing.  Since these projects became operational, they have resulted in higher margin (operating income as a percentage of revenue) than the distribution segment, but have also contributed to higher interest expenses and other financing costs.  For example, in 2010 and 2009 our generation segment provided 22.5% and 23.3%, respectively, of our operating income, but due to the relative significance of the financial expenses incurred to finance these projects, the segment’s contribution to net income was lower.  In 2010, 16.5% of our net income was derived from our generation activities.

Our commercialization segment sells electricity and provides value-added services to Free Consumers and other concessionaries or licensees.  In 2010, 13.2% of our net income was derived from our commercialization activities.

Our segments also purchase and sell electricity and value-added services to and from one another.  In particular, our generation and commercialization segments sell electricity and provide services to our distribution segment.  In order to avoid duplication of revenue and expense amounts, the results by segment in our consolidated financial statements eliminate revenues and expenses that relate to sales from one subsidiary to another.  However, the analysis of results by segment would be inaccurate if the same eliminations were carried out with respect to sales between segments.  As a result, sales from one segment to another have not been eliminated in the discussion of results by segment below.  See below:

	Distribution	Generation	Commercialization	Other(*)	Elimination	Total
2010
Net Revenue	10,471,192	538,217	1,012,525	1,795	-	12,023,729
(-) Intersegment Revenues	13,904	650,571	766,922	-	(1,431,397)	-
Income from electric energy service	1,852,867	616,416	302,981	(32,949)	-	2,739,315
Financial income	316,020	53,725	22,389	90,981	-	483,115
Financial expense	(394,999)	(323,441)	(22,311)	(96,307)	-	(837,058)
Income before taxes	1,773,749	345,914	302,024	(36,315)	-	2,385,372
Income tax and social contribution	(604,865)	(88,731)	(95,840)	(35,899)	-	(825,335)
Net Income	1,168,884	257,183	206,184	(72,214)	-	1,560,037
Total Assets(**)	11,689,503	7,568,600	349,047	449,655	-	20,056,805
Capital Expenditures and other intangible assets	1,127,637	645,040	27,853	10	-	1,800,540
Depreciation and Amortization	352,806	188,981	4,553	145,453	-	691,793
2009
Net Revenue	9,764,670	453,711	1,139,621	4	-	11,358,006
(-) Intersegment Revenues	14,127	611,335	644,620	-	(1,270,082)	-
Income from electric energy service	1,860,801	649,561	292,543	(20,222)	-	2,782,683
Financial income	262,914	30,884	20,113	37,449	-	351,360
Financial expense	(361,852)	(222,990)	(9,764)	(66,460)	-	(661,066)
Income before taxes	1,761,863	457,455	302,892	(49,233)	-	2,472,977
Income tax and social contribution	(602,761)	(125,711)	(93,300)	37,663	-	(784,109)
Net Income	1,159,102	331,744	209,592	(11,570)	-	1,688,868
Total Assets(**)	10,696,228	6,761,330	422,816	610,385	-	18,490,759
Capital Expenditures and other intangible assets	667,614	550,565	9,789	131	-	1,228,099
Depreciation and Amortization	344,499	175,825	3,882	148,867	-	673,073

(*)           Other – Refers basically to the CPFL Energia figures after eliminations of balances with related parties

(**)         The goodwill created in an aquisition and recorded in CPFL Energia was allocated to the respective segments

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We also derive non‑material income at parent company level that is not related to or included in the results of our reportable segments.  General expenses and overhead are generally allocated to the relevant subsidiary and are reflected in the operating results of our reporting segments.  Other expenses incurred by the parent company that can be directly allocated to a specific segment, such as the posting of an intangible asset relating to a concession, and the amortization thereof, are also allocated to our reporting segments.

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 since 2004.

The following table shows inflation, the change in gross domestic product (inreais) and the variation of thereal against the U.S. dollar for the years ended December 31, 2010, 2009, 2008, 2007 and 2006.

	Year ended December 31,
	2010	2009	2008	2007	2006
Inflation (IGP-M)(1)	11.3%	-1.7%	9.8%	7.8%	3.8%
Inflation (IPCA)(2)	5.9%	4.3%	5.9%	4.5%	3.1%
Growth (contraction) in gross domestic product (inreais)	7.5%	-0.2%	5.1%	5.4%	3.8%
Depreciation (appreciation) of thereal vs. U.S. dollar	-4.3%	-25.5%	31.9%	-17.2%	-8.7%
Period-end exchange rate–US$1.00	R$1.666	R$1.741	R$2.337	R$1.771	R$2.138
Average exchange rate–US$1.00(3)	R$1.759	R$1.990	R$1.833	R$1.930	R$2.168

Source: Fundação Getúlio Vargas,the Instituto Brasileiro de Geografia e Estatística and the Central Bank.

(1)           Inflation (IGP-M) is the general market price index measured by the Fundação Getúlio Vargas.

(2)           Inflation (IPCA) is a broad consumer price index measured by the Instituto Brasileiro de Geografia e Estatística and the reference for inflation targets set forth by the CMN.

(3)           Represents the average of the commercial selling exchange rates on the last day of each month during the period.

Inflation primarily affects our business by increasing operating costs and financial expenses to service our inflation-indexed debt instruments.  We are able to recover a portion of these increased costs through the Parcel A cost recovery mechanism, but there is a delay in time between when the increased costs are incurred and when the increased revenues are received following our annual tariff adjustments.  The amounts owed to us under Parcel A are indexed to the variation of the SELIC rate until they passed through to our tariffs.

Depreciation of thereal 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.

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Some external factors may significantly affect our businesses depending on the category of consumers:

·Residential and Commercial Consumers.  These classes are highly affected by weather conditions and income distribution.  Elevated temperatures and increases in income levels cause an increased demand for electricity and, therefore, increase our sales.

·Industrial consumers.  Consumption for industrial consumers is related to economic growth, amongst other factors, correlated mostly to GDP.  During periods of financial crisis, this class suffers the strongest impact.

Results of Operations—2010 compared to 2009

In 2010, our performance progressed significantly, reflecting the current growth cycle in Brazil; the growth potential of the Brazilian internal market, which is reflected in the increase in the consumption of energy in our distribution concession areas; the results of our strategy of expanding and diversifying our business; and our undertaking to improve our operating efficiency.

Our net income in 2010 was lower than in 2009 because our revenues in 2009 reflected tariff adjustments following losses we incurred in 2008 due to the global financial crisis.

Net Operating Revenues

Our net operating revenues were R$12,024 million in 2010, a 5.9% increase compared to 2009.  Excluding revenues relating to the construction of concession infrastructure (which does not affect the result due to corresponding costs in the same amount), net operating revenues would be R$10,980 million, a 2.2%, or R$238 million, increase.  The increase in our net operating revenues primarily reflected higher revenues from our distribution companies attributable to an increase in sales to our captive clients and in revenues from TUSD paid by Free Consumers. 

The following discussion describes changes in our net operating revenues by destination and by segment, based on the items comprising our gross revenues.

Sales by Destination

Sales to final consumers

Our gross operating revenues from sales to Final Consumers were R$13,929 million in 2010, a 3.2% increase compared to 2009.  Average prices in 2010 varied by consumer category.  While average prices increased among residential and rural consumers, they decreased among industrial, commercial, public administration and public services consumers.  Tariffs are adjusted each year, and the month in which the tariff adjustment takes effect varies, with the increases in the largest subsidiaries taking effect in April (CPFL Paulista), June (RGE), and October (CPFL Piratininga).

The increase in sales in 2010 reflected the economic recovery.  Volumes sold to residential and commercial consumers increased 5.2% and 5.5%, respectively.  Volumes sold to industrial consumers increased 3.0%, reflecting an increase of 0.5% in sales to captive Final Consumers and 10% in sales in the free market.  Industrial customers in our distribution concession areas who purchase from other suppliers in the free market also pay us a fee for the use of our network, and this revenue is reflected in our financial statements under “Other Operating Revenues.”  Average prices to Final Consumers in 2010 varied by the consumer category:

·Industrial and Commercial Consumers.  For industrial and commercial consumers that are captive consumers (which represent 82.1% of the total volume sold to this category), average prices decreased by 1.4% and 1.7%, respectively.  For those that are Free Consumers, average prices decreased by 4.5% and 2.8%, respectively.

·Residential Consumers.  Average prices increased by 1.0% due to tariff adjustments for our eight distribution subsidiaries.

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Sales to wholesalers

Our gross operating revenues from sales to wholesalers were R$1,196 million in 2010 (6.8% of our gross operating revenues), a decrease of 7.9% compared to 2009.  The decrease was due to the 1.5% decrease in the volume of electricity sold and the 6.6% decrease in average prices.

Other operating revenues

Our other gross operating revenues were R$1,387 million in 2010 (11.5% of our net operating revenues), compared to R$1,036 million in 2009.  The increase was mainly due to the favorable impact of TUSD revenues from our Free Consumers and tariff adjustments.

Deductions from operating revenues

We deduct certain taxes and regulatory charges from our gross operating revenues to calculate our net revenues.  One of these taxes is the value-added tax, or ICMS, levied by Brazilian states, and PIS/COFINS taxes levied by the Brazilian federal government.  These deductions amounted to 31.5% of our gross operating revenues in 2010 and 31.1% in 2009.  Most of these taxes and charges are based on the amount of gross operating revenues, while others vary depending on regulatory effects reflected in our tariffs.  See note 27 to our consolidated financial statements.

Sales by segment

Distribution 

Net operating revenues from our distribution segment in 2010 amounted to R$10,485 million, an increase of 7.2% compared to R$9,779 million in 2009.  Excluding revenues relating to the construction of concession infrastructure (which was totally offset by construction costs), net operating revenues would be R$9,441 million, a 3.0%, or R$278 million, increase.  This increase was mainly due to the 42% increase in TUSD revenues collected from Free Consumers and the 2.7% increase in sales in our captive market. 

Generation 

Net operating revenues from our generation segment in 2010 amounted to R$1,189 million, an increase of 11.6% compared to R$1,065 million in 2009.  This increase was mainly due to the fact that the Baldin, Foz do Chapecó and EPASA plants became commercially operational in 2010.

Commercialization 

Net operating revenues from our commercialization segment in 2010 amounted to R$1,779 million, a slight decrease of 0.3% compared to R$1,784 million in 2009.  The decrease was mainly due to a 3.6% decrease in volume sold, partially compensated by the increase in average prices.

Income from Electric Energy Service

                Cost of Electric Energy

Electricity purchased for resale.  Our costs to purchase electricity were R$5,050 million in 2010 (75.2% of our total operating costs and operating expenses).  The cost was 1.4% higher than in 2009, primarily due to (i) a 2.0% increase in the average price for electricity offset by (ii) a reduction of 0.6% due to a decrease in the volume of electricity we purchased.

The average price for electricity purchased from Itaipu by our distribution companies, which represented 20.7% of the total volume we purchased in 2010, was on average 10.7% lower in 2010 than in 2009, because of a 1.6% decrease in the tariffs established by ANEEL and a 11.6% decrease in the average rate of the dollar in 2009.

The average prices of electricity sold from other generation facilities increased 4.8%.  The volume of electricity sold at these facilities remained constant.

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Electricity network usage charges. Our costs for electricity network usage charges were R$1,172 million in 2010.  This was 13.3% higher than in 2009 due to the increase in the ESS and EER.  This increase mainly refers to the apportionment of costs relating to reserve energy and to the commencement of operations of thermoelectric power plants in 2010.  These charges are reimbursed to our distribution companies through tariff adjustments when the actual charges are higher than forecasts used in setting tariffs.  A large proportion of these charges (97.0% in 2010) is attributable to our distribution segment.

                Other costs and operating expenses

Our other costs and operating expenses comprise our operating cost, services rendered to third parties, sales expenses, general and administrative expenses and other operating expenses, excluding costs related to construction of concession infrastructure.

Our other costs and operating expenses were R$2,018 million in 2010, a 3.8% increase from 2009.  This was due primarily to:  (i) a 7.3%, or R$41 million, increase in personnel costs, mainly due to salary increases resulting from collective bargaining agreements negotiated in 2009 and 2010, and (ii) a 20.2%, or R$78 million, increase in third‑party services costs due to adjustments in contractual prices and an increase in the number of outside service providers, as well as maintenance costs for our electricity network, telephone services, new personnel hirings and system consultancy.  These costs were partially offset by the R$81 million actuarial gain relating to pension plans in 2010.  Actuarial gains or losses result from actuarial reports prepared by specialized companies and vary according to macroeconomic premises, particularly returns on assets.

                Income from Electric Energy Service

Our income from electric energy service was R$2,739 million in 2010.  This was 1.6% lower than in 2009 due to the 8.3% increase in operating expenses and electric utility service costs, although partially offset by the 5.9% increase in our net revenue.

Income from Electric Energy Service by Segment

Distribution

Operating income from our distribution segment in 2010 amounted to R$1,853 million, a slight decrease of 0.4% compared with 2009.  Our operating income from the segment reflected the 7.2% increase in our net revenue, which was more than offset by:

·Electricity costs:  Our electricity costs were R$6,023 million, a 4.6% increase compared to 2009.  This  reflects an increase of 2.4% in the volume of electricity purchased by us in 2010 compared to 2009 and an increase of 2.1% in the average prices due to energy prices adjustments.  However, this increase does not significantly affect our operating income since it is included in the 2010 tariffs.

·Other costs and operating expenses.  Our other costs and operating expenses (other than electricity utility service costs) for the distribution segment amounted to R$811 million, an increase of 3.1% compared to 2009.  This increase was primarily due to salary increases resulting from collective bargaining agreements negotiated in 2009 and 2010 and increase in costs with outside service providers.

Generation

Operating income from our generation segment in 2010 amounted to R$616 million, a decrease of 5.1% compared to 2009.  The main reason for the decrease in operating income from the segment was the increase in costs relating to the purchase of electricity in the market to comply with contractual obligations assumed by EPASA and Chapecoense before they started operations.

Commercialization

Operating income from our commercialization segment in 2010 amounted to R$303 million, an increase of 3.6% compared to 2009.  This increase was mainly due to the 3.4% decrease in electricity costs, resulting from a

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3.8% decrease in the volume of electricity purchased by us.  This decrease was partially offset by the 0.5% increase in the average price of electricity.

Net Income

Net Financial Expense

Our net financial expense was R$354 million in 2010, compared to R$310 million in 2009.  The R$44 million increase is mainly due to:  (i) the increase in the level of our indebtedness and (ii) the commencement of operations of Foz do Chapecó, which started accounting for the monetary restatement of the debt and charge for the use of public utilities as financial expenses.  The increase in revenues from financial investments resulted from the cash margins and equivalents in 2010 as compared with 2009.

At December 31, 2010, we had R$8,937 million in debt denominated inreais, which accrued both interest and monetary correction based on a variety of Brazilian indices and money market rates.  We also had the equivalent of R$470 million of debt denominated in foreign currencies (U.S. dollars and Japanese yen).  In order to reduce the risk of exchange losses with respect to these foreign-denominated debts, we entered into long‑term currency swaps for a significant portion of this debt.  The rates of index variation posted a slight decrease in 2010 when compared to 2009, with the average CDI rate for the year at 9.8% in 2010 compared to 9.9% in 2009 and the TJLP decreasing by 6.0% in 2010 compared to 6.1% in 2009.

Income and Social Contribution Taxes

We recorded a net charge of R$825 million for income and social contribution taxes in 2010, compared to R$784 million in 2009.  Our effective tax rate of 34.6% on pretax income in 2010 was approximately equal to the combined statutory rate of 34.0%.

Net Income

Due to the factors mentioned above, our net income was R$1,560 million in 2010, a decrease of 7.6%, or R$129 million, compared to 2009.

Net Income by Segment

In 2010, 74.9% of our net income was derived from our distribution segment, 16.5% from our generation segment and 13.2% from our commercialization segment.  Our other non‑reportable segments represented a net loss of 4.6%.

Distribution

Net income from our distribution segment in 2010 amounted to R$1,169 million, a slight increase of 0.8% compared with 2009.  The increase in this segment reflected mainly the R$20 million decrease in net financial expenses, which were partially offset by the R$8 million decrease in our operating income and the R$2 million increase in expenses for income tax and social contributions.

Generation

Net income from our generation segment in 2010 amounted to R$257 million, a decrease of 22.5% compared with 2009.  This decrease was mainly due to:  (i) a 5.1% decrease in our operating income due to an increase in purchases of electricity to comply with supply agreements entered into by our subsidiaries that had not yet started operations, (ii) an increase in our indebtedness due to new financings and (iii) the monetary restatement of the public utilities.

Commercialization

Net income from our commercialization segment in 2010 amounted to R$207 million, a decrease of 1.5%.  The decrease in this segment reflected the compensation of the increase of 3.6% of operating income by our net financial expenses.

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Capital Expenditures

Our principal capital expenditures in the past several years have been for the maintenance and upgrading of our distribution network and for our generation projects.  The following table sets forth our capital expenditures for the years ended December 31, 2010 and 2009.

	Year ended December 31,
	2010	2009
	(in millions ofreais)
Distribution:
CPFL Paulista	R$527	R$344
CPFL Piratininga	285	132
RGE	237	215
Other distributors	79	55
Total distribution	1,128	746
Generation	645	570
Commercialization and other investments	29	40
Total	R$1,802	R$ 1,356

We plan to make capital expenditures aggregating approximately R$2,092 million in 2011 and approximately R$1,633 million in 2012.  Of total budgeted capital expenditures over this period, R$2,144 million are expected to be invested in our distribution segment and R$1,474 million in our generation segment³.  Part of these expenditures, particularly in generation projects, is already contractually committed.  See “—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments.” Planned capital expenditures for development of our generation capacity, and the related financing arrangements, are discussed in more detail under “Business—Generation of Electricity.” 

Liquidity and Capital Resources

Funding Requirements and Contractual Commitments

Our capital requirements are primarily for the following purposes:

·We make capital expenditures to continue improving and expanding our distribution system and to complete our generation projects.  See “—Capital Expenditures” above for a discussion of our historical and planned capital expenditures;

·Repayment or refinancing maturing debt.  At December 31, 2010, we had outstanding debt maturing during the following 12 months aggregating R$2,251 million (including derivatives and interest);

·Dividends on a semiannual basis.  We paid R$1,424 million in 2010 and R$1,173 million in 2009.  See “Item 10.  Additional Information—Interest Attributable to Shareholders’ Equity;” and

·Funding for acquisitions.

On December 31, 2010, our working capital reflected a deficit (excess of current liabilities over current assets) of R$530 million.  The main cause of this deficit is the maturity of R$2,251 million debentures and financings (including derivative and interest) in 2011.  We expect that this deficit will be funded by financings obtained through 2011.  In the first quarter of 2011, we refinanced a significant part of this deficit.

³These numbers do not consider the acquisition of Jantus and the joint venture with ERSA.

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The following table summarizes our contractual obligations in IFRS as of December 31, 2010.  The table does not include accounts payable reported on our balance sheet.

	Payments due by period
	Total	Less than 1 year	1-3 years	4-5 years	After 5 years
	(in millions ofreais)
Contractual obligations as of December 31, 2010:
Debt obligations(1)	R$9,224	R$2,089	R$3,147	R$2,349	R$1,639
Purchase obligations:
Electricity purchase agreements(2)	104,285	7,154	14,772	13,771	68,588
Generation projects	1,180	494	264	59	363
Supplies	682	438	108	131	5
Pension funding(3)	631	39	77	77	438
Total	R$116,002	R$10,214	R$18,368	R$16,387	R$71,033

(1)           Not including interest payments on debt or payments under swap agreements.  For the year ended December 31, 2011, we expect that the interest payments on debt and debentures will amount to R$159 million and payments under swap agreements will amount to R$4 million.  This is the contractual amount and is presented net of Fair Value adjustments and borrowing costs.  We expect to pay approximately R$644 million in interest payments in 2011.  Interest payments on debt for years following 2011 have not been estimated.  We are not able to determine such future interest payments because we cannot accurately predict future interest rates, our future cash generation, or future business decisions that could significantly affect our debt levels and consequently this estimate.  For an understanding of the impact of a change in interest rates applicable to our long‑term debt obligations, see “—Market Risk—Risk of Index Variation.” For additional information on the terms of our outstanding debt, see “—Terms of Outstanding Debt.”

(2)           Amounts payable under long‑term energy purchase agreements, which are subject to changing prices and provide for renegotiation under certain circumstances.  The table represents the amounts payable for the contracted volumes applying the year-end 2010 price.  See “—Background—Prices for Purchased Electricity” and note 28 to our consolidated financial statements.

(3)           Amounts due under a contract with the pension plan administrator (see note 19 to our consolidated financial statements).

Sources of Funds

Our main sources of funds derive from our operating cash generation and financings.

Cash Flow

Net cash provided by operating activities was R$2,209 million in 2010, as compared to R$2,439 million in 2009.  The decrease mainly reflected (i) the increase in tariff adjustments in 2009, which included positive regulatory adjustments that offset net losses incurred in 2008 and (ii) the effects of these tariff adjustments in current taxes.  Because we recovered our losses in 2009, those effects were not considered in the 2010 tariff adjustment.

Net cash used for investment was R$1,802 million in 2010, as compared to R$1,239 million in 2009.  This R$563 million increase mainly reflects:  (i) enlargement of the distribution concession infrastructure in the amount of R$487 million for expansion, improvement and maintenance of our networks and (ii) acquisition of fixed assets for the construction and maintenance of generation plants in the amount of R$86 million.

Net cash used for financing activities was R$152 million in 2010 and R$472 million in 2009.  This decrease is mainly due to refinancing of our debt to long‑term liabilities.

Indebtedness

The following table sets forth indebtedness in IFRS for the year ended December 31, 2010:

	2010
	Current	Non-Current
	(in thousands ofreais)
Secured debt	262,060	2,046,943
Unsecured debt	4,166,264	6,831,882
Total	R$4,428,324	R$8,878,825

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Our total indebtedness increased R$1,511 million, or 19.6%, from December 31, 2009 to December 31, 2010, mainly as result of:

·financings of R$202 million for our generation subsidiaries under construction (Foz do Chapecó, EPASA, CPFL Bioenergia) and for CPFL Geração (to finance the construction of the Santa Clara and Campo dos Ventos wind farms),

·financings of R$209 million for expansion and improvements in our distribution subsidiaries through BNDES and BNDES’ programs Fund for Financing the Acquisition of Industrial Machinery and Equipment (“FINEM”) and Financing and Endeavors (“FINAME”), as well as fund raisings through rural instruments from Banco do Brasil, and

·the issuance of debentures in a total amount of R$1,058 million, which we used for refinancing and to extend the maturity of our indebtedness and ownership interest on investments.

During 2011 and 2012, we expect to raise funding mainly to finance our scheduled investments, funding the acquisitions and the refinancing of our debts.

We expect our main source of new financing in 2011 to be working capital instruments for our distribution companies, loans from BNDES as FINEM/FINAME credits, loans from Banco do Nordeste, loans for working capital and issuance of debentures. On May 23, 2011, our Board of Directors approved the issuance of debentures by certain of our subsidiaries in the total amount of R$2,778 million. Of this total amount, R$484 million will be issued by CPFL Paulista, R$680 million by CPFL Geração, R$160 million by CPFL Piratininga, R$70 million by RGE and R$65 million by CPFL Santa Cruz. We intend to use the proceeds from these offerings for working capital and to repay part of our indebtness. CPFL Brasil will issue debentures in the total amount of R$1,320 million. We intend to use the proceeds from this offering to fund new investments.

These financings will have the purpose of:  (i) funding capital expenditures of our distribution subsidiaries, (ii)  raising capital for investments in the thirteen wind farms we acquired in 2009 and 2010 and in four thermoelectric plants (CPFL Bio Formosa, CPFL Bio Buriti, CPFL Bio Ipê and CPFL Bio Pedra) and (iii) raising capital for operations of EPASA thermoelectric plants.

Terms of Outstanding Debt

Total debt outstanding at December 31, 2010 (excluding accrued interest and derivative transactions) was R$9,219 million.  Of the total amount, approximately R$461 million, or 5.0%, was denominated in U.S. dollars and Japanese yen.  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations.  R$2,089 million of our total outstanding debt is due in 12 months.

Our major categories of indebtedness are as follows:

·BNDES.  At December 31, 2010, we had R$3,578 million outstanding under a number of facilities provided through BNDES.  These loans are denominated inreais.  The most significant part of these loans relates to (a) loans to our generation projects, especially Foz do Chapecó, CERAN and ENERCAN (R$2,190 million), and (b) financing of investment programs of our subsidiaries, primarily CPFL Paulista, CPFL Piratininga and RGE, through lines of credit under the BNDES – FINEM loan facility (R$1,061 million).  We also had financings relating to working capital in the amount of R$212 million.

·Debentures.  At December 31, 2010, we had indebtedness of R$3,722 million outstanding under several series of debentures issued by CPFL Energia, CPFL Paulista, CPFL Piratininga, EPASA, CPFL Geração, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari, CPFL Brasil, BAESA, ENERCAN and RGE.  The terms of these debentures are summarized in note 18 to our audited consolidated financial statements.

·Working capital.  At December 31, 2010, we had R$1,361 million outstanding (net of tax effects) under a number of loan agreements relating to (i) working capital for CPFL Geração and CPFL Santa        Cruz indexed to the CDI amounting to R$156 million, (ii) working capital for CPFL Geração and CPFL Paulista, which were previously indexed to foreign currencies and are currently indexed to the CDI, amounting to R$718 million (R$615 million for CPFL Geração and R$103 million for CPFL Paulista) and (iii) rural credits, amounting to R$487 million (net of tax effects) for CPFL Paulista, CPFL Piratininga, RGE, CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa,  all of them indexed to 98.5% of CDI.

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·Otherreal-Denominated Debt.  As of December 31, 2010, we had R$96 million outstanding under a number of otherreal-denominated facilities secured by the revenues of the borrower.  The majority of these loans are restated based on CDI or IGP-M, and bear interest at various rates.

·Yen-Denominated Debt.  CPFL Paulista entered into bilateral loans denominated in yen and converted toreais through swap agreements based on CDI.  As of December 31, 2010, the total outstanding principal amounts for these loans were R$416 million.

·Other Foreign-DenominatedDebt.  At December 31, 2010, we had R$45 million outstanding under other loans denominated in U.S. dollars.  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations.  In addition, we have U.S. dollar- denominated long‑term receivables, which amounted to R$21 million at December 31, 2010, which also mitigate our exposure to exchange rates.  For more details on our loans, debentures and derivatives, please see notes 17, 18 and 34 to our audited consolidated financial statements.

Financial and Operating Covenants

We are subject to financial and operating covenants under our financial instruments and those of our subsidiaries.  These covenants include the following:

·We have limitations on our ability to sell or pledge assets or to make investments in third parties.

·Under the BNDES credit facilities:

·CERAN, ENERCAN, BAESA and Foz do Chapecó must first pay the amounts due under the loans before paying dividends to CPFL Geração in an amount higher than the mandatory dividends under Brazilian law.  In addition, before making these dividend payments and before paying interest on shareholders’ equity, BNDES must give its prior approval, and the respective subsidiary must be in compliance with all of its financial covenants.

·CPFL Bioenergia is not allowed to pay dividends for the years 2009 through 2012.  CPFL Bioenergia may pay dividends beginning in 2013 only if CPFL Bioenergia complies with all of the following conditions:  (i) fulfillment of its contractual obligations; (ii) maintaining a debt coverage ratio equal to or higher than 1.0 and (iii) maintaining total indebtedness ratio equal to or lower than 0.8.

·Under the Banco do Brasil rural instruments, we must maintain a ratio of net indebtedness to EBITDA of less than 3.0.

·Under the issuance of CPFL Paulista debentures, CPFL Paulista must maintain a ratio of net indebtedness to EBITDA of less than 3.0 and a ratio of EBITDA to financial income (expense) of at least 2.25, with the ratios calculated as defined in the CPFL Paulista debentures.

·Under the RGE debentures, RGE must maintain a ratio of net indebtedness to EBITDA of less than 3.0, and a ratio of EBITDA to financial expenses of at least 2.0, with the ratios calculated as defined in the RGE debentures.

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·Under the CPFL Piratininga debentures, CPFL Piratininga must maintain a ratio of net indebtedness to EBITDA of less than 3.0 and a ratio of EBITDA to financial income (expense) of at least 2.25, with the ratios calculated as defined in the CPFL Piratininga debentures.

We are currently in compliance with our financial and operating covenants.  A breach of any of these covenants would give our lenders the right to accelerate our repayment obligations.

In addition, a number of the financing instruments of our subsidiaries are subject to acceleration if, as a result of changes in our structure or in the structure of our subsidiaries, our current shareholders cease to own a majority of CPFL Energia’s voting equity or control over management.

For more information on our financial covenants, see notes 17 and 18 to our audited consolidated financial statements.

Research and Development and Electricity Efficiency Programs

In accordance with applicable Brazilian law, since June 2000 companies holding concessions, permissions and authorizations for distribution, generation and transmission of electricity have been required to dedicate a minimum of 1.0% of their net operating revenue each year to research and development and electricity efficiency programs.  Small hydroelectric power plants and wind, sun and biomass energy projects are not subject to this requirement.  Beginning in April 2007, our distribution concessionaires dedicated 0.5% of their net operating revenue to research and development and 0.5% to electricity efficiency programs, while our generation concessionaries dedicated 1.0% of their net operating revenue to research and development.

Our electricity efficiency program is designed to foster the efficient use of electricity by our consumers, to reduce technical and commercial losses and offer products and services that improve satisfaction and loyalty and enhance our corporate image.  Our research and development programs utilize technological research to develop products, which may be used internally, as well as sold to the public.  We carry out certain of these programs through strategic partnerships with national universities and research centers, and the vast majority of our resources are dedicated to innovation and development in new technologies applicable to our business.

Our disbursements on research and development projects in 2008, 2009 and 2010 totaled R$79 million, R$156 million and R$179 million, respectively.

Off-Balance Sheet Arrangements

We have guaranteed some of the debt of our proportionately consolidated subsidiaries.  These guarantees generally relate to a proportion of the debt that is no greater than our proportionate ownership share of the subsidiary.  However, we have guaranteed amounts payable under credit facilities of some of our subsidiaries in an amount greater than our proportionate ownership share of these subsidiaries.

All relevant items are included in our financial statements.

Trend Information

We seek to promote growth in each of our three business segments:  distribution, generation and commercialization.

The growth of our distribution segment derives from organic market growth and the acquisition of new companies.  Market growth is heavily influenced by economic growth, in particular, an increase in employment, income, retail sector sales and industrial production.  In addition, the market is also influenced by the entry of new clients and changes in weather and rainfall volume.

We intend to continue to expand our distribution segment, either through market growth or through the acquisition of energy distribution companies (if there are companies in the market with characteristics and at a price that will be beneficial to us).

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The market shows positive signs of growth for 2011.  According to projections from the FOCUS report, published on April 15 by the Central Bank, GDP is expected to grow 4.0% in 2011 and 4.25% in 2012.  This growth should be sustained in particular by the recovery of the industry, which was highly affected by the global financial crisis between the end of 2008 and beginning of 2009.  Since the second half of 2009, the Brazilian power industry has shown signs of recovery and is expected to grow 4.0% in 2011 and 4.7% in 2012, according to the FOCUS report.  Employment, income and sales levels are also expected to increase in 2011, based on the expected growth of the economy as well as due to the weaker levels in 2009.

In addition to our growth strategy, we also intend to increase our operational efficiency and invest in innovation and technology, which are our permanent goals.

Our generation segment has shown high levels of growth in the last few years, with the acquisition and construction of new plants.  We have attempted to increase the number of hydroelectric projects and to expand our projects from renewable energy, including wind, biomass and small hydroelectric power plants.

As of December 31, 2010 we had an installed capacity of 2,200.1 MW, which should reach 2,511.2 MW by the end of 2011, with the opening of the Termoparaíba, Bio Formosa, Buriti and Ipê thermoelectric power plants and the last generation unit of the Foz do Chapecó plant, which represents a growth of 14%.  In 2012 and 2013, we expect to reach an installed capacity of 2,769.2 MW and 2,805.4 MW, respectively, when the Pedra plant, the Santa Clara and Eurus VI wind farms (2012) and the Campo dos Ventos II wind farm (2013) begin operations.

In the commercialization segment, our main objective is to maintain our leading position, in terms of market share, in the commercialization of energy in the Free Market.  In addition, we expect to expand our portfolio of services, retain the loyalty of our free customers and expand our services to new markets.

We have constantly followed a growth strategy since our establishment, and we plan to continue this in the future, seeking to maintain synergies, financial discipline, corporate governance, and business sustainability in order to consolidate our strong position in the energy industry.

IFRS

In compliance with Laws 11,638/07 and 11,941/09 and CVM Decision 457/07, during 2009 and 2010, the CPC issued and the CVM approved a series of accounting Pronouncements and Instructions, the purpose of which was to bring Brazilian accounting practices into alignment with International Financial Reporting Standards (“IFRS”).  These Pronouncements applied as from fiscal years ending in December 2010 and to the financial statements of 2009 that are released together with the 2010 financial statements for comparison purposes.

The following describes the standards that had the greatest impact on our financial statements:

i.IFRIC 12 - Concession Contracts:  This Interpretation defines the form of accounting for the assets of concessions when certain conditions are met.  This Interpretation is applicable to our concessions relating to electric energy distribution services.  The impact on our financial statements was the derecognition of fixed assets and special obligations relating to our concessions, and their replacement by (a) recording an intangible asset, referring to the right to charge consumers a tariff (the right to exploit the concession), and/or (b) recording a financial asset, representing our unconditional right to receive payment.

ii.IAS 16 - Property, plant and equipment.  Items of property, plant and equipment are measured at acquisition, construction or formation cost less accumulated depreciation and, if applicable, accumulated impairment losses.  Property, plant and equipment were measured at the transition date in accordance with the IFRS rules by segregation into two groups:

·Assets measured at deemed cost at the transition date:  we adopted this model for assets built and put into long‑term service where it is not possible to reconstruct the cost formation or where the cost of the survey is of no benefit in presentation of the financial statements.  The cost of these items at the transition date was therefore determined in accordance with market prices (“deemed cost”).  The effects of the deemed cost increased property, plant and equipment against equity, net of related taxeffects.  We opted to recognize the property, plant and equipment of the subsidiaries CPFL Sul Centrais and CPFL Geração at market value at the transition date.

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·Assets measured at historic cost:  we adopted this model for recently built assets where the basis for cost formation can be easily confirmed and the values at historic cost approximate the respective market values.  In such cases, the subsidiaries performed an analysis to ensure that the cost formation is in accordance with IFRS.

iii.IAS 19 - Employee Benefits.  We opted to recognize all accumulated actuarial gains and losses at January 1, 2009.  The adjustment of R$ 294,939 (R$ 194,660 net of tax effects) corresponds to recognition of the accumulated actuarial loss at the transition date for all the defined benefit plans of the subsidiaries CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE.

iv.IAS 37 – Charges for the use of public utilities.  Certain generation concessions were granted upon payment  to the federal government of charges for the use of public utilities.  This obligation was registered on the date of the execution of the respective concession agreements, at present value, against intangible assets.  These amounts, capitalized by interest incurred from the execution of the agreement to the start-up date, are amortized on a straight-line basis over the remaining term of the concession.

For further details about the first adoption of IFRS and accounting policies, see notes 3 and 5 to our financial statements.

Use of Estimates in Certain 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.  In the discussion below, we have identified several other matters that would materially affect our financial presentation if either (i) we used different estimates that we could reasonably have used or (ii) in the future we change our estimates in response to changes that are reasonably likely to occur.

The discussion 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 the notes to our audited consolidated financial statements included herein for a more detailed discussion of the application of these and other accounting policies.

Impairment of Long-lived Assets

Long-lived assets, which include property, plant and equipment, purchased intangible assets and investments, comprise a significant amount of our total assets and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  We carry balances on our balance sheet that are evaluated at (i) fair value, for assets that fulfill certain conditions established in  “First‑time Adoption of International Financial Reporting Standards” and (ii) historical costs net of accumulated depreciation and amortization, for assets that have not been subject to relevant price index variations since their acquisition.  We carry balances on our balance sheet that are based on historical costs net of accumulated depreciation and amortization.  We are required under IFRS to evaluate periodically whether these assets are impaired, that is, whether their future capacity to generate cash does not justify maintaining them at their carrying values.  If they are impaired, we are required to recognize a loss by writing off part of their value.  The analysis we perform requires that we estimate the future cash flows attributable to these assets, and these estimates require us to make a variety of judgments about our future operations, including judgments concerning market growth and other macroeconomic factors as well as the demand for electricity.  Changes in these judgments could require us to recognize impairment losses in future periods.  Our evaluations in 2010 and 2009 did not result in any significant impairment of our property, plant and equipment or intangible assets and investments.

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Pension Liabilities

We sponsor pension plans and disability and death benefit plans covering substantially all of our employees.  We account for these benefits in accordance with IFRS.  The determination of the amount of our obligations for pension benefits depends on certain actuarial assumptions.  For further information about the actuarial assumption see note 19 to our audited consolidated financial statements. 

Deferred Tax Assets and Liabilities

We account for income taxes in accordance with IFRS, which requires an asset and liability approach to recording current and deferred taxes.  Accordingly, the effects of differences between the tax basis of assets and liabilities and the amounts recognized in our financial statements have been treated as temporary differences for the purpose of recording deferred income tax.

We regularly review our deferred tax assets for recoverability.  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.

Reserves for Contingencies

We and our subsidiaries are party to certain legal proceedings in Brazil arising in the normal course of business regarding tax, labor, civil and other issues.

We account for contingencies in accordance with IFRS.  Such accruals are estimated based on historical experience, the nature of the claims, and the current status of the claims.  The evaluation of these contingencies is performed by various specialists, inside and outside of the company.  Accounting for contingencies requires significant judgment by management concerning the estimated probabilities and ranges of exposure to potential liability.  Management’s assessment of our exposure to contingencies could change as new developments occur or more information becomes available.  The outcome of the contingencies could vary significantly and could materially impact our consolidated results of operations, cash flows and financial position.

Financial instruments

We account for our financial instruments in accordance with IFRS.  Financial instruments can be  measured at fair values or at recognized costs, depending on certain factors.  Those measured at fair value were recognized based on quoted prices in an active market, or assessed using pricing models, applied individually for each transaction, taking into consideration the future payment flows, based on the conditions contracted, discounted to present value at market interest rate curves, based on information obtained from the BM&FBOVESPA and the National Association of Financial Market Institutions,Associação Nacional das Instituições do Mercado Financeiro – ANDIMA websites, when available. Accordingly, the market value of a security corresponds to its maturity value (redemption value) marked to present value by the discount factor (relating to the maturity date of the security) obtained from the market interest graph in Brazilianreais. 

Financial assets classified as available-for-sale refer to the right to compensation to be paid by the Federal Government on reversion of the assets of the distribution concessionaires (financial asset of concession).  The methodology adopted for marking these assets to market is based on the tariff review process for distributors.  This review, conducted every four or five years according to the concessionaire, consists of revaluation at market price of the distribution infrastructure.  This valuation basis is used for pricing the tariff, which is increased annually up to the next tariff review, based on the parameter of the main inflation indices.

Although the Federal Government has not yet defined the methodology and criteria for valuation of the compensation on reversion of the assets, our management believes that it will be based at least on the tariff pricing model.  Accordingly, at the time of the tariff review, each concessionaire adjusts the position of the financial asset base for compensation at the amounts ratified by the regulatory authority and uses the IGP-M as best estimate for adjusting the original base to the fair value at subsequent dates, in conformity with the tariff review process.

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Depreciation and Amortization of Intangible Assets

We account for depreciation using the straight-line method, at annual rates based on the estimated useful life of assets, as established by ANEEL, in accordance with practices adopted in Brazil.  Amortization of intangible assets varies according to the way they are acquired:

·Intangible assets acquired in a business combination:  We account for the amortization of the premium corresponding to the concession rights using the concessionaire’s projected net profit curve for the remaining concession term.

·Investments in infrastructure (application of IFRIC 12 – Concession Agreements):  Since the concession term is contractually defined, intangible assets acquired as investment in infrastructure have a pre‑determined useful life.  We account for the amortization of these assets using a curve that reflects the consumption standard as compared to the expected profits.

·Public utilities:  We account for the amortization of intangible assets relating to our use of a public asset using the straight-line method for the remaining term of the concession.

ITEM 6.Directors, Senior Management and Employees

Directors and Senior Management

Board of Directors

Our Board of Directors is responsible for determining our overall strategic guidelines and, among other things, for establishing our general business policies and for electing our executive officers and supervising their management.  According to our bylaws, our Board of Directors consists of a minimum of seven members and a maximum of nine members.  Currently, our Board of Directors consists of seven members, of which one is independent (in accordance with the listing regulations of the New Market of the BM&FBOVESPA, or theNovo Mercado, and our bylaws).  In the event of a tie, the chairman will have the deciding vote.  The Board of Directors meets at least once a month, or whenever requested by the chairman in accordance with our bylaws.

Under Brazilian Corporate Law, each director must hold at least one of our common shares.  Under our bylaws, the board members are elected by the holders of our common shares at the annual general meeting of shareholders.  Board members serve one-year terms, re-election being permitted provided that they may be removed at any time by our shareholders at an extraordinary general meeting of shareholders.  Our current directors were elected at our Board of Directors’ meeting held on May 25, 2011.  Their terms will expire at our next annual shareholders’ meeting, scheduled to take place April 2012.  Our bylaws do not provide for a mandatory retirement age for our directors.

Under Brazilian Corporate Law, if a director or an executive officer has a conflict of interest with the company in connection with any proposed transaction, the director or executive officer may not vote in any decision of the Board of Directors, or of the board of executive officers, regarding such transaction, and must disclose the nature and extent of the conflicting interest for transcription in the minutes of the meeting.  A director or an executive officer may not transact any business with the company, including accepting any loans, except on reasonable or fair terms and conditions that are identical to the terms and conditions prevailing in the market or offered by third parties.  Any transaction entered into between our shareholders or related parties and us that exceeds R$8.1 million, as adjusted annually by the IGP-M index, must be previously approved by our Board of Directors.  As of this date, there are no relevant agreements or other obligations between us and our directors.

Under Brazilian Corporate Law, combined with a recent decision by CVM, noncontrolling shareholders have the right to designate at least one member of our board of directors for election to the board, provided that they hold at least 10.0% of the outstanding voting shares.  Noncontrolling shareholders that own greater than 5.0% of voting shares may requestvoto múltiplo (multiple voting).

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The following table sets forth the name, age and position of each current member of our Board of Directors.  A brief biographical description of each of our directors follows the table.

Name	Age	Position
Murilo Cesar Lemos dos Santos Passos	63	Chairman
Claudio Borin Guedes Palaia	36	Director
Francisco Caprino Neto	51	Director
Renê Sanda	47	Director
Ivan de Souza Monteiro	50	Director
Carlos Alberto Cardoso Moreira	51	Director
Ana Dolores Moura Carneiro de Novaes	49	Independent Director

Murilo Cesar Lemos dos Santos Passos - Mr. Passos graduated in Chemical Engineering from the Federal University of Rio de Janeiro (UFRJ) in 1971.  Between 1970 and 1977, he held positions at the Ministry of Industry and Commerce – Industrial Development Council (CDI).  Between 1977 and 1992, he worked at Companhia Vale do Rio Doce and subsequently became the CEO and Head of Forestry Products, Environment and Metallurgy Area of Celulose Nipo-Brasileira S.A (CENIBRA) and Florestas Rio Doce S.A..  Between 1993 and 2006, he was an executive officer of Bahia Sul Celulose S.A. and Suzano Papel e Celulose S.A.  He was a member of the Board of Directors of Brasil Agro Cia. Brasileira de Propriedades Agrícolas between 2007 and 2010.  Currently, he is a member of the Management Committee of the Board of Directors of Suzano Papel e Celulose S.A., Vice President of the Trustee Council of the Foundation for the National Quality Award (FNPQ), a member of the Superior Concil of Ecofuturo Institute and a member of the Advisory Council of the Pulp and Paper Producers’ Association - BRACELPA.  He is also a member of the Board of Directors of São Martinho S.A., Odontoprev S.A. and Tegma Gestão Logística S.A.  Since 2010, he has been the Chairman of the Board of Directors of CPFL Energia S.A.

Claudio Borin Guedes Palaia - Mr. Palaia graduated in Business Administration from Fundação Getúlio Vargas Business School of São Paulo in 1997.  He obtained an MBA degree from The Wharton School of the University of Pennsylvania in 2002.  He worked as an analyst of mergers and acquisitions at JP Morgan Bank in São Paulo and in New York from 1997 to 1998.  From 2002 to 2005, he was project leader in Camargo Corrêa Energia S.A., Camargo Corrêa S.A. (CCSA) and São Paulo Alpargatas.  From 2005 to 2007, he was an executive officer of Hormigón da Loma Negra C.I.A.S.A in Buenos Aires, Argentina.  Since 2008, he has been an executive officer of Camargo Corrêa Cimentos.  He is also a sitting member of the Board of Directors of São Paulo Alpargatas.  In 2009, he was an alternate member of the Board of Directors of CPFL Energia S.A.  Since 2010, he has been a sitting member of the Board of Directors of CPFL Energia S.A.

Francisco Caprino Neto - Mr. Caprino Neto graduated in Metallurgical Engineering from the Polytechnic School of the University of São Paulo (USP) in 1983 and completed a master’s degree program in the same area at the same institution in 1992.  He was the chairman of the Processes Engineering Department and advisor for the Control and Planning Department of Siderúrgica J.L. Aliperti S.A., as well as the coordinator of metallurgical process of Aços Villares S.A.  He was a sitting member of the Board of Directors of CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE from 2005 to 2006.  Currently, he holds the position of executive officer and member of the Board of Directors of Camargo Corrêa Energia S.A. and Camargo Corrêa Investimentos em Infraestrutura (CCII).  He is also member of the Board of Directors of VBC Energia S.A., Usinas Siderúrgicas of Minas Gerais S.A. (USIMINAS), Companhia de Concessões Rodoviárias (CCR) and A-Port S.A.  Since April 2000, he has been a member of the Board of Directors of CPFL Energia.

Renê Sanda – Mr. Sanda graduated in Statistics from University of São Paulo (USP) in 1989 and completed a master’s degree program in Statistics at the same institution in 1989.  In 1992, he completed an MBA program in Finance from the Brazilian Institute of Capital Markets (IBMEC) and participated in the Commercial and Investment Banking Program Professional Development Center at Citibank, in Fort Lauderdale.  He was an assistant manager at BB New York between 2002 and 2006 and at Banco do Brasil Securities between 2005 and 2006.  From 2006 to 2010, he was the Risk Management Officer of Banco do Brasil. He was a member of the Fiscal Council of Tele Amazônia Celular Participações, Telemig Celular Participações, Companhia Paulista de Força e Luz and CPFL Geração S.A. He was a member of the Board of Directors of Petroflex S.A. Indústria e Comércio, Banco do Brasil Securities LLC – New York (USA), BB Securities Ltd. – London (UK) and Fundição Tupy. He is an

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associate at Instituto Brasileiro de Governança Corporativa – IBGC.  Since 2010, he has been the Investment Officer of Caixa de Previdência dos Funcionários do Banco do Brasil – PREVI. Mr. Sanda became a member of our Board of Directors in 2011.

Ivan de Souza Monteiro – Mr. Monteiro graduated in Electronic Engineering and Telecommunications from INATEL - MG in 1986.  He completed an MBA program in Finance from the Brazilian Institute of Capital Markets (IBMEC) in 1995 and an MBA program in Business Administration from Pontifical Catholic University of Rio de Janeiro (PUC‑RJ) in 2000.  Since 1983, he works at Banco do Brasil, where he was a local superintendent between 1996 and 1998, a state superintendent between 1998 and 1999, a commercial manager between 1999 and 2004, a commercial superintendent between 2004 and 2007 and the officer in charge of branches outside of Brazil between 2007 and 2009.  In May 2009, he was the Commercial Officer of Banco do Brasil and, since June 2009, he has been the Vice-President of Finance, Capital Markets and Investor Relations of Banco do Brasil.  Since 2009, he has been a member of the Decision Making Concil of Caixa de Previdência dos Funcionários do Banco do Brasil – PREVI.  He is also a member of the Board of Directors of Banco Votorantim and BV Participações.  He has been an alternate member of the Board of Directors of Brasil Veículos since January 2011.Mr. Monteiro became a member of our Board of Directors in 2011.

Carlos Alberto Cardoso Moreira – Mr. Moreira graduated in Business Administration from Pontifical Catholic University of São Paulo (PUC-SP) in 1984.  He completed several courses, seminars and workshops in Private Pension Plan and Capital Markets at IBMEC, IBC, Abrapp and Wharton School.  Since June 2000, he has been the Investment and Finance Officer of the Sistel de Seguridade Social Foundation - SISTEL.  From 1984 to 1988, he was an Senior Investment Analysit of Credibanco, São Paulo.  Between 1988 and 1992, he was Vice President of Citibank N.A in São Paulo.  He was the Institutional Clients Officer of Banco BMC S.A. in São Paulo from 1992 to 1999.  He was also a member of the National Investment Technical Commission (Comissão Técnica Nacional de Investimentos–CNTI) of Abrapp, an alternate member of the Board of Directors of EMBRAER, and a sitting member of the Board of Directors of GTD and BR Foods.  From 2009 to 2011, he was an alternate member of the Board of Directors of CPFL Energia S.A.  He has been an executive officer of Bonaire Participações S.A. since April 2008.  Since 2004, he has been a member of the Board of Directors of CPFL Energia S.A.

Ana Dolores Moura Carneiro de Novaes - Mrs. Novaes earned a Ph.D. in Economics from the University of California in 1990 and graduated in Law from the Pontifical Catholic University of Rio de Janeiro (PUC-RJ) in 2008.  In 1999, she obtained a CFA – Chartered Financial Analyst qualification awarded by the US Association for Investment and Management Research (AIMR).  She was an analyst of Equity Research at Banco de Investimentos Garantia between 1995 and 1997, and the Investment Officer at Pictet Modal Asset Management between 1998 and 2003.  She worked at the World Bank in Washington, D.C. from 1991 to 1994.  She was also macroeconomics professor at the Federal University of Pernambuco in the first half of 1991 and at the Pontifical Catholic University of Rio de Janeiro in 2003.  Since 2008, she has been a partner at Galanto Consultoria of Rio de Janeiro, for services and consulting in corporate governance.  She has been a member of the Board of Directors of Companhia de Concessões Rodoviárias (CCR) since May 2002, and of Metalfrio since May 2009.  She has also been a Consultant to the Auditing Committee of Companhia Siderúrgica Nacional since August 2006.  Since April 2007, she has been a member of the Board of Directors of CPFL Energia.

Executive Officers

Our executive officers are responsible for our day-to-day management.  Under our bylaws, our board of executive officers is comprised of seven members that are appointed by our Board of Directors for a two-year term, with the possibility of re-election.  Our current executive officers were elected at the Board of Directors meeting held onApril 28, 2011.

The following table sets forth the name, age and position of each current executive officer.  A brief biographical description of each of our executive officers follows the table.

Name	Age	Position
Wilson Ferreira Junior	52	Chief Executive Officer
Lorival Nogueira Luz Júnior	39	Chief Financial Officer and Head of Investor Relations
Wilson Ferreira Junior*	52	Vice-President of Distribution, Generation and Energy Management
José Marcos Chaves de Melo	48	Vice-President Administrative
Adriana Waltrick dos Santos	46	Vice-President of Business Development

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(*) Interim Vice-President of Distribution, Generation and Energy Management

Wilson Ferreira Junior - Mr. Ferreira Junior graduated from Mackenzie University in Electrical Engineering  in 1981, and in Business Administration in 1983.  He attended a master’s degree program in Energy at the University of São Paulo (USP), for which he did not complete the thesis requirements, and several specialization courses, including:  Occupational Safety and Health Engineering (Mackenzie University, 1982), Marketing (Getúlio Vargas Foundation – FGV, 1988), and Electricity Distribution Management (Swedish Power Co., 1992).  At Companhia Energética de São Paulo (CESP), he held several senior positions and served as the Distribution Officer from 1995 to 1998.  He served as the CEO of RGE from 1998 to 2000, Chairman of the Board of Directors of Bandeirante Energia S.A. from 2000 to 2001, and President of the Brazilian Association of Electric Power Distributors (ABRADEE) from 2009 to 2010.  From 2002 to 2010, he was a member of the Board of Directors of CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE.  Mr. Ferreira Junior is currently the Vice President of the Brazilian Association of Infrastructure and Basic Industry (ABDIB) and a member of the Board of Directors of the National Electrical System Operator (ONS).  In March 2000, he became CEO of CPFL Paulista, and later of CPFL Piratininga, CPFL Geração, CPFL Brasil, RGE, CPFL Santa Cruz, CPFL Jaguariúna, CPFL Bioenergia, and other subsidiaries of CPFL Energia.  Since 2002, he has been the CEO of CPFL Energia.  Mr. Ferreira Junior is currently the Vice-President of Distribution, Generation and Energy Management of CPFL Energia.

Lorival Nogueira Luz Júnior- Mr. Lorival Luz is a business administrator graduate from FAAP, São Paulo, in 1993 with various specialization courses on finance in Brazil and abroad, and 20 years experience in the financial industry. Until March 2011, Mr. Luz was the Corporate Treasurer and IR Officer at Votorantim Industrial, one of the largest Brazilian Conglomerates. Before joining Votorantim, in August 2008, Mr. Luz was elected Chief Financial and Investor Relations Officer by the Board of Directors of Estácio Participações S.A., a GP Investimentos Group’s Company and a Brazil-based holding company active in educational services. He was also the Executive Treasury Officer at Banco Citicard until July 2008. Earlier, he held the same position at Credicard, the leading credit card company in Brazil, where he played a key role in its conversion to a retail bank. During almost 17 years at Citibank, he served as Corporate Bank Chief of Staff, Senior Relationship Manager, Senior Treasury and Loan Products Manager, and as an analyst in the financial controllership department of Citibank in Brazil. Mr. Luz was elected Chief Finance Executive Officer and Head of Investor Relations of CPFL Energia S.A., CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE on March 21, 2011 and Chief Financial Officer of other subsidiaries of the CPFL Energia group.

José Marcos Chaves de Melo - In 1980, Mr. Melo graduated as an electronics technician from the Federal Center for Technological Education of Rio de Janeiro (CEFET-RJ).  In 1986, he graduated in Engineering from the University of Kansas.  Among his academic achievements, the following stand out:  Fulbright scholarship, American National Engineering Honor Society (Tau Beta Pi), the 2005 SAP Diamond Circle Award for Outstanding Business Contributions, and the 2006 Accenture World Innovation Award.  Mr. Melo worked at Accenture do Brasil from 1987 to 2008, serving as senior executive from 1998 to 2008.  He was responsible for the execution of several projects with companies of the electricity sector for 12 years, oil and gas sectors for 5 years, steel sector for 2 years, and in the manufacturing sector for 1 year.  He has experience in several functional areas, such as IT, supply chain, field work and assets management.  During his career he has worked for companies such as Neoenergia, Light, CEMIG, Duke Energy, Petrobrás, Repsol-YPF and CSN, the Electric Power Trade Board (CCEE) and ONS.  Mr. Melo is currently the Administrative Officer of CPFL Paulista, CPFL Piratininga, RGE, CPFL Santa Cruz, CPFL Jaguariúna, CPFL Geração, CPFL Bioenergia, and other subsidiaries of CPFL Energia.  Since 2008, he has been the Chief Administrative Officer of CPFL Energia.

Adriana Waltrick dos Santos - Mrs. Waltrick dos Santos graduated in Business Administration from the Vale do Rio dos Sinos University (UNISINOS) in the state of Rio Grande do Sul in 1989 and also holds an Executive MBA (1992) and Marketing Masters degree (1997) from the Federal University of Rio Grande do Sul (UFRGS).  She also holds a MIT Sloan MBA from the Massachusetts Institute of Technology (2009).  She has been part of the CPFL group since 1999, having served as the Director of Corporate Strategy and Mergers and Acquisitions of CPFL Energia S.A. from 2001 to 2008 and the Corporate Strategy Manager of RGE from 1999 to 2000.  Mrs. Waltrick dos Santos also served as the Corporate Strategy Manager of Rede Brasil Sul de Comunicação – Group RBS, from 1997 to 1998, and the International Business Manager of Group Petropar from 1990 to 1994. She was elected the Vice‑President of Business Development of CPFL Energia S.A. in January 27, 2010.

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Fiscal Council

Under Brazilian Corporate Law, theConselho Fiscal, or fiscal council, is a corporate body independent of the management and the company’s external auditors.  Our fiscal council is permanent, although Brazilian Corporate Law allows fiscal councils to be either permanent or non‑permanent and may be composed of a minimum of three and a maximum of five members.  The primary responsibility of the fiscal council is to review management’s activities and the company’s financial statements, and to report its findings to the company’s shareholders.  Brazilian Corporate Law requires fiscal council members to receive as remuneration at least 10.0% of the average annual amount paid to the company’s executive officers, excluding benefits and profit sharing.  Noncontrolling holders of common shares owning in aggregate at least 10.0% of the common shares outstanding may also elect one member of the fiscal council.

Under Brazilian Corporate Law, our fiscal council may not include members who are on our Board of Directors, are on the board of executive officers, are employed by us or a controlled company or a company of the same group, or are spouses or relatives of any member of our management or Board of Directors.  Our fiscal council elected at our shareholders’ meeting held on April 28, 2011, with a mandate of one year, is composed of five members:  Daniela Corci Cardoso (President), Adalgiso Fragoso de Faria, José Reinaldo Magalhães, Wilton de Medeiros Daher and Martin Roberto Glogowsky.

In accordance with the listed company audit committee rules of the NYSE and the SEC, on June 8, 2005 our Board of Directors designated and empowered our fiscal council to perform the role of the audit committee in reliance on the exemption set forth in Exchange Act Rule 10A-3(c)(3).

Advisory Committees

The chairperson of each of the following committees reports on activities at the Board of Directors’ monthly meetings.  However, the committees do not have decision-making authority and their recommendations are not binding upon the Board of Directors.

Management Processes Committee.  Our Management Processes Committee is responsible for assisting the Board of Directors by:  (i) evaluating the validity of the information disclosed to the Board of the Directors, (ii) preparing proposals to improve business management procedures, (iii) evaluating our risk profile and (iv) coordinating internal audits and preparing improvement proposals.  The members of this committee are Francisco Caprino Neto, Luiz Cláudio da Silva Barros and Martin Roberto Glogowsky.

Human Resources Management Committee.  Our Human Resources Management Committee is responsible for assisting the Board of Directors by:  (i) coordinating the CEO selection process, (ii) defining criteria for compensation of the executive officers, including long and short‑term incentive plans, (iii) defining performance goals of the executive officers, (iv) coordinating evaluation procedures of the executive officers, (v) preparation of the plan of succession for members of the executive officers and (vi) monitoring the execution of human resources policies and practices and preparing improvement proposals when necessary.  The members of this committee are Francisco Caprino Neto, Ivan de Souza Monteiro and Carlos Alberto Cardoso Moreira.

Related Parties Committee.  Our Related Parties Committee is responsible for assisting the Board of Directors by:  (i) evaluating the selection procedures of suppliers and third-party construction and other services from related parties and ensuring these transactions are conducted fairly and consistent with market practice and (ii) evaluating energy purchase or sale agreements with related parties ensuring these transactions are conducted fairly and consistent with market practice.  The members of this committee are Daniela Corci Cardoso, Luiz Cláudio da Silva Barros and Susana Hanna Stiphan Jabra.

In addition to the advisory committees, our Board of Directors has created seven ad hoc commissions since 2006 (Corporate Governance Commission, Strategy Commission, Budget Commission, Financial Services Commission, Energy Acquisition Commission, Projects Evaluation Commission and IFRS Commission) and may create others.

Strategy Commission.  Our Strategy Commission is responsible for assisting the Board of Directors with evaluating and improving our business strategy in order to meet our growth targets and long‑term objectives.

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Financial Services Commission.  Our Financial Activities Commission is responsible for ensuring compliance and efficiency in our existing financial practices, as well as evaluating new opportunities for financial transactions that could benefit the company. 

Corporate Governance Commission.  Our Corporate Governance Commission is responsible for monitoring the implementation of our new corporate governance model and for suggesting potential improvements to the Board.

Budget Commission.  Our Budget Commission is responsible for advising the Board of Directors on analyzing and setting our annual and long‑term budgets.

Energy Acquisition Commission.  Our Energy Acquisition Commission is responsible for advising the Board of Directors on analyzing the acquisition of energy originated from alternative and competitive sources by the subsidiaries of commercialization. 

Projects Evaluation Commission.  Our Project Commission is responsible for assisting the Board of Directors with evaluating new opportunities for distribution and generation of energy assets forecasted in the strategic planning.

IFRS Commission.  Our IFRS Commission is responsible for advising the Board of Directors on validating its decisions in relation to the implementation of new accounting rules applicable to our financial statements as from 2010.

Compensation

Under Brazilian Corporate Law, our shareholders are responsible for establishing the aggregate amount we pay to the members of our Board of Directors and our executive officers.  Once our shareholders establish an aggregate amount of compensation for our Board of Directors and executive officers, the Human Resources Management Committee of our Board of Directors is then responsible for setting individual compensation levels.

For the year ended December 31, 2010, the aggregate compensation, including cash and benefits-in-kind, that we paid to the members of our Board of Directors, our executive officers and members of our fiscal council was approximately R$18 million, including R$6 million in variable compensation.  For the same period, the total amount set aside or accrued by the company to provide pension, retirement or similar benefits was approximately R$624,000.

The approved compensation for our board of directors, board of executive officers and fiscal council for 2011 is R$29 million.

The following tables set forth the compensation from CPFL Energia on a non‑consolidated basis of our management for the year ended December 31, 2010 and the approved compensation for 2011.  Our directors and officers receive additional compensation from our subsidiaries which is not reflected in these tables.

	Compensation for the year ended December 31, 2010
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	7 members	5 members	6,08 members(1)
Fixed annual compensation:	(in thousands ofreais)
Wage	785	537	1,148	2,470
Direct or indirect benefits	-	-	-	-
Compensation for participation in committees.	-	-	-	-
Others	155	100	223	478
Variable compensation:
Bonus	-	-	600	600
Profit sharing plan	-	-	-	-
Compensation for participation in meetings.....	-	-	-	-
Commissions	-	-	-	-
Others	-	-	41	41
Post-employment benefits	-	-	85	85
Compensation based on stock options	-	-	-	-
Compensation for each body(2)	940	637	2,097	-
Total compensation				3,674

(1)           Weighted average number of members.

(2)           Compensation amounts include charges and accruals.

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	Approved compensation for the year ended December 31,  2011
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	7 members	5 members	8 members
Fixed annual compensation:	(in thousands ofreais)
Wage	900	546	1,234	2,680
Direct or indirect benefits	-	-	6	6
Compensation for participation in committees	-	-	-	-
Others	180	109	187	476
Variable compensation:
Bonus	-	-	717	717
Profit sharing plan	-	-	-	-
Compensation for participation in meetings	-	-	-	-
Commissions	-	-	-	-
Others	-	-	727	727
Post-employment benefits	-	-	101	101
Compensation based on stock options	-	-	-	-
Compensation for each body(1)	1,080	655	2,972	-
Total compensation				4,707

(1)           Compensation amounts include charges and accruals.

The table below sets forth the compensation of our management received from our subsidiaries for the year ended December 31, 2010.

Year ended December 31, 2010 (1)
	Board of Directors	Fiscal Council	Executive Officers
Shareholders	-	-	-
Subsidiaries	-	-	13.273
Entities under common control	-	-	-

(1)           Compensation amounts include charges and accruals.

Share Ownership

The total number of common shares owned by our directors and executive officers as of April 30, 2011 was 3,286.  None of our directors or executive officers beneficially owns one percent or more of our common shares.

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Indemnification of Officers and Directors

Neither the laws of Brazil nor our bylaws provide for indemnification of directors or officers.  We have held directors’ and officers’ liability insurance since February 2006.

Employees

As of December 31, 2010, we had 7,924 full time employees (including the employees of our jointly‑controlled subsidiaries).  The following table sets forth the number of our employees and a breakdown of employees by category of activity as of the dates indicated in each area of our operations.

	As of December 31,
	2010	2009	2008
Distribution	6,040	5,653	5,717
Generation	351	275	271
Commercialization	616	662	242
Corporate staff	917	860	889
Total	7,924	7,450	7,119

Part of our employees are members of unions, with which we have collective bargaining agreements.  We renegotiate these agreements annually with the 16 principal unions that represent our various employee groups.  Salary increases are generally provided for on an annual basis.  We believe that we have good relationships with these unions as evidenced by the fact that we have not had any labor strikes during the last 22 years.

We provide a number of benefits to our employees.  The most significant is the sponsorship of Fundação CESP, in partnership with ten other electrical companies, which supplements the Brazilian government retirement and health benefits available to the employees of our subsidiaries CPFL Paulista, CPFL Piratininga, CPFL Geração and CPFL Brasil.

In accordance with Brazilian law and our compensation policy, our employees are eligible for our profit sharing program.  This amount is set in the collective bargaining agreements of each company, which are adjusted annually.  In 2010, we reserved R$38 million for our employee profit sharing program.

In addition, part of each employee’s compensation is linked to performance goals.  Employees are evaluated based on criteria such as quality of work product, adherence to safety protocols and productivity.  Our performance evaluation system is designed to evaluate required skill as well, and enables us to evaluate the development of our employees.

ITEM 7.Major Shareholders and Related Party Transactions

Major Shareholders

The following table sets forth information relating to the beneficial ownership of our common shares by our major shareholders (beneficial owners of 5.0% or more of our common shares) as of December 31, 2010.  Percentages in the following table are based on 481,137,130 outstanding common shares.

	Common Shares	(%)
BB Carteira Livre I FIA(1)	149,233,727	31.02
VBC Energia S.A.(2)	122,948,720	25.55
Bonaire Participações S.A.(3)	60,713,511	12.62
Bradespar S.A.(4)	25,270,900	5.25
BNDES Participações S.A.(5)	40,526,739	8.42
Executive officers and directors as a group	2,466	0.00
Total	398,696,063	82.86

(1)           BB Carteira Livre I – Fundo de Investimentos em Ações is an investment fund that belongs to PREVI, a pension fund sponsored by Banco do Brasil S.A.  The Brazilian government owns a majority of the voting capital of Banco do

                Brasil.  During 2009, the shareholder 521 Participações S.A., in compliance with the decision of its final controlling shareholder (Caixa de Previdência dos Funcionários do Banco do Brasil – “PREVI”), restructured its equity interests in order to reduce the administrative and financial costs on its indirect investments and transferred all its shares in the Company to its controlling shareholder, Fundo BB Carteira Livre I – Fundo de Investimento em Ações.

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(2)           VBC Energia S.A. is controlled by the Brazilian group Camargo Corrêa through several companies:  (i) Atila Holdings S.A., controlled by Construções e Comércio Camargo Corrêa S.A. and Camargo Corrêa Energia S.A.; (ii) Camargo Corrêa Energia S.A.; and (iii) Camargo Corrêa S.A. VBC Energia S.A. was also controlled by Votorantim Energia S.A. until January 2009.

(3)           Bonaire Participações S.A. is a holding company controlled by Energia São Paulo Fundo de Investimento em Participações, whose ownership interest is controlled by four pension funds:  (i) Fundação CESP, primarily for employees of CPFL Energia, Companhia Energética de São Paulo (CESP), Eletropaulo Metropolitana Eletricidade de São Paulo S.A., Bandeirante Energia S.A. and Elektro Eletricidade e Serviços S.A., among other Brazilian electricity companies; (ii) Fundação SISTEL de Seguridade Social, primarily for employees of CPqD (Centro de Pesquisa e Desenvolvimento), Telecomunicações Brasileiras S.A. – Telebrás, Telemig Celular S.A., Tele Norte Celular Participações S.A., Amazônia Celular S.A.; among others telecommunications companies; (iii) Fundação Petrobras de Seguridade Social - PETROS, primarily for employees of Petróleo Brasileiro S.A.; and (iv) Fundação SABESP de Seguridade Social — SABESPREV, primarily for employees of Companhia de Saneamento Básico do Estado de São Paulo — SABESP.

(4)           Bradespar S.A. is a beneficial owner of our common shares, which it indirectly holds through Antares Holdings Ltda. and Brumado Holdings S.A.

(5)           BNDES Participações S.A. is a subsidiary of BNDES, a federal public bank linked to the Brazilian Ministry of Development, Industry and External Trade.

Shareholders’ Agreement

Voting Rights.  Our shareholders’ agreement, among VBC, PREVI (through BB Carteira Livre I FIA), Bonaire and us, as intervening and consenting party, governs control of CPFL and our subsidiaries.  Under the shareholders’ agreement, certain actions require the approval of at least VBC and PREVI (at least 80.0% of the shares subject to the shareholders’ agreement), including:

·election of the CEO and removal of any executive officer (including the CEO);

·definition of the dividend policy;

·creation and dissolution of controlled companies;

·acquisition and sale of investments in other entities;

·approval of our budget;

·approval of our business plan;

·capital increase within our pre‑approved authorized capital and determination of the issuance price of shares;

·incurrence of indebtedness – including guarantees and collaterals in favor of controlled entities and invested companies – beyond the thresholds established in our budget or our business plan;

·execution of any agreement with a global amount in excess of R$32.4 million, if not included in our annual budget;

·granting of any kind of collateral or guarantee in favor of third parties;

·execution of agreements with related parties in an amount in excess of R$8.1 million;

·appointment of our independent auditors in certain specified cases;

·authorization for the acquisition of our own shares for cancellation or for treasury;

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·amendment of concession agreements of any controlled entity;

·approval of stock option plans; and

·acquisition, sale or encumbrance of any fixed assets in an amount equal or over R$32.4 million.

The terms of our shareholders’ agreement relating to voting rights apply to our controlled companies and, to the fullest extent possible, to our investee companies.

Corporate Governance.  Our Board of Directors consists of seven members, appointed as follows:

·three appointed by VBC;

·two appointed by PREVI;

·one appointed by Bonaire; and

·one independent, in accordance with the listing regulations of the Novo Mercado.

Our Fiscal Council consists of five members, appointed as follows:

·two appointed by VBC;

·two appointed by PREVI; and

·one appointed by Bonaire.

The number of members of the Board of Directors and the Fiscal Council nominated by each party to the shareholders’ agreement is related to the current stakes of the parties in the controlling shareholder block.  If a change in the stakes of any party in the enjoined shares occurs, the number of members for which such party has the right to nominate shall be adapted to reflect such modification so as to maintain unchanged the number of members nominated by the parties whose stakes relative to the total of enjoined shares have not been altered.

If the noncontrolling shareholders, exercising their rights under the corporate law, elect the independent director required by the BM&FBOVESPA’sNovo Mercado Regulations, VBC, PREVI and Bonaire must abstain from proposing a nominee for the position.  If the noncontrolling shareholders do not elect the independent director, VBC, PREVI and Bonaire shall by joint accord nominate such an independent director.

The shareholders’ agreement also establishes the framework of the Board of Directors and Board of Executive Officers of our subsidiaries.  According to the agreement, the executive officers of the Company must be part of the Board of Directors of our subsidiaries.

Transfer of Shares.  Our shareholders’ agreement provides for certain rights and obligations in the event of transfer of shares subject to the shareholders’ agreement, or subject shares, including:

·Right of First Refusal.  The parties to the shareholders agreement have a right of first refusal to acquire subject shares in the event one of them decides to sell its shares to a third party.

·Tag-along Rights.  A party that decides not to exercise its right of first refusal has the option to sell (pro rata), together with the selling party, its subject shares to the acquiring third party.  Tag‑along provisions do not apply to the disposition of subject shares by Bonaire while its stake within the controlling block is lower than 20.0%.

·Preemptive Rights.  The parties have pro rata preemptive rights to subscribe for shares in the event of a capital increase.

·Tag-along Rights of Bonaire.  In the event of a sale, assignment or transfer of subject shares by PREVI and VBC that results in an equity percentage lower than 20.0% and 30.0%, respectively, of theaggregate subject shares and, as long as Bonaire has not exercised its right of first refusal, it will have the right to sell its entire stake of subject shares together with PREVI or VBC, under the same terms and conditions.

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Change of Control.  In the event of direct or indirect change of control of any of the parties subject to the shareholders’ agreement, the remaining parties have the right to acquire all subject shares held, directly or indirectly, by the party undergoing the change of control, paying for such shares an amount to be determined by a recognized financial institution.

Option Agreement

Our controlling shareholders are also party to an agreement pursuant to which they have granted to each other options to purchase their respective shares in us.  In addition, this agreement provides for (i) certain notification requirements for secondary offerings of shares by such shareholders and (ii) priority to certain shareholders in the sale of shares in a secondary offering, if more than one shareholder participates in the offering and demand is less than the size of the offering.

Related Party Transactions

One of our principal shareholders is VBC.  The controlling shareholder of VBC currently is the Camargo Corrêa Group and prior to January 2009 both Camargo Corrêa and the Votorantim Group were controlling shareholders.  Camargo Corrêa Group is one of the largest privately-held industrial conglomerates in Brazil, with controlling equity interests in leading Brazilian engineering and construction, cement, footwear, and textiles companies.  Camargo Corrêa Group also shares equity control of important Brazilian steel and highway concession companies, and it has equity participations in a significant Brazilian financial conglomerate and in a global aluminum company.

We acquired our interest in Semesa from VBC in December 2001 for R$496 million.  The Semesa acquisition price is subject to adjustment, based on the assessment of Semesa’s assured energy.  According to MME, the earliest that this assessment will take place is 2015.

We also conduct transactions with the shareholders of VBC and their affiliates, including the following:

·Our distribution subsidiaries have entered into agreements for the supply of electricity with several entities affiliated with our shareholders.  All of these electricity supply agreements are regulated by ANEEL.

·Our commercialization subsidiaries have entered into agreements for the supply of electricity with several entities affiliated with our shareholders.

·CPFL Geração, through its subsidiaries BAESA, ENERCAN, CERAN and Foz do Chapecó, has entered into transactions with Construção e Comércio Camargo Corrêa S.A., a member of the Camargo Corrêa Group, for the provision and financing of construction services to our generation subsidiaries.

Our subsidiaries CPFL Paulista, CPFL Piratininga, CPFL Geração and CPFL Brasil are sponsors of a pension fund administered by Fundação CESP, a pension fund services company that has an indirect ownership interest in one of our shareholders, Bonaire.  See note 32 to our Financial Statements concerning “Transactions with Related Parties”.

ITEM 8.Financial Information

Consolidated Statements and Other Financial Information

See Item “Financial Statements.”

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Legal Proceedings

CPFL Paulista and CPFL Piratininga are parties to numerous lawsuits brought by industrial consumers alleging that certain tariff increases in the past were illegal in view of then prevailing economic regulations that had established a price freeze that included electricity tariffs.  The aggregate potential liability was approximately R$96 million as of December 31, 2010.  Superior courts have already decided many of these lawsuits partially against us, and as a result, we have provisioned the aggregate potential liability (approximately R$10 million) in respect of these suits.

CPFL Paulista is a defendant in a civil public action filed by the Campinas Consumer Protection Office (Promotoria de Defesa do Consumidor).  The purpose of this civil public action is to suspend the effects of the tariff readjustment authorized by ANEEL for the year ended December 31, 2009.  CPFL Paulista obtained a preliminary suspension of the effects.  The civil public action still awaits final decision and, until then, the effects from the tariff readjustment authorized by ANEEL remain in force.  We believe that the risk of loss is remote.

CPFL Piratininga received a tax infraction notice regarding improper tax deductions from payments made to the Fundação CESP’s pension fund.  These payments originated from an agreement executed to pay a debt from Fundação CESP’s pension fund.  An appeal still awaits decision.  We believe that the possibility of loss is possible.

CPFL Piratininga filed an annulment action concerning an ICMS fiscal debt against a notice of infraction and fee drawn by the state of São Paulo questioning the company’s tax calculation method regarding the energy supply to two cities in the state.  A decision in the first instance has not yet been reached.  The risk of loss is possible and the amount is of approximately R$123 million.

We are also subject to legal proceedings relating to the authorization of certain of our hydroelectric plants, including a class action proposed by the federal public attorney’s office of the Municipality of Caxias do Sul challenging the validity of the environmental licensing of the Rio das Antas Hydroelectric Complex, and requesting injunctive relief against the construction of these plants.  The federal public attorney’s injunction request was denied in the lower courts and the district attorney moved against the denial, requesting a new injunction from the higher courts.  The higher courts denied the injunction relief.  The claim was deemed groundless by the lower courts.  An appeal from the federal public attorney’s office still awaits final decision.  We believe that the possibility of a loss is remote.

Semesa and Furnas were named defendants in a legal proceeding that sought remedial measures and the establishment of a nature reserve because of alleged harm caused by the construction and operation of the Serra da Mesa plant.  The amount sought from Semesa totaled R$101 million.  CPFL Geração assumed all of the outstanding obligations and potential liabilities of Semesa in March 2007.  We believe that the risk of an adverse judgment with respect to this claim is possible.  We have not established a provision with regard to this claim.  If adverse judgment were entered against us, requiring us to purchase additional land and establish a preserve in the area surrounding our generation activities, the costs would be reflected in our property, plant and equipment.

CPFL Paulista is involved in a lawsuit challenging the deductibility of expenses recognized in 1997 related to a deficit from Fundação CESP’s pension fund.  Based on a favorable opinion that we received from the Brazilian Internal Revenue Office, CPFL Paulista deducted those expenses for purposes of income tax payments.  In 2007, we made a judicial deposit in the amount of R$360 million (adjusted to R$483 million in 2010), which allows CPFL Paulista to proceed with the lawsuit without assuming the risk of any asset seizure by the tax authority.  This deductibility also resulted in other lawsuits, and CPFL Paulista to raise defenses also entered into an agreement with a Brazilian bank to provide letters of credit through which the bank will guarantee an amount of R$228 million (adjusted to R$325 million in 2010).  We believe that the possibility of loss is remote.

We establish reserves in our balance sheets relating to potential losses from litigation based on estimates of such losses.  For this purpose, we classify such losses as remote, possible or probable.  IFRS practices and Brazilian law require us to establish reserves in connection with probable losses and therefore, it is our policy to establish reserves only in connection with those claims.  As of December 31, 2010, our reserves for contingencies were approximately R$291 million.  Our management believes that these proceedings will not have a material adverse effect on our financial condition, either individually or in the aggregate.  See note 22 to our audited consolidated financial statements for more information on the status of our litigation.

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Dividend Policy

For our policy on dividend distributions, see “Item 10.  Additional Information—Allocation of Net Income and Distribution of Dividends.”

Significant Changes

None

ITEM 9.The Offer and Listing

Trading Markets

Our common shares are listed on the BM&FBOVESPA, and our ADSs are listed on the New York Stock Exchange.  Each ADS represents three shares.  The ADSs commenced trading on the NYSE on September 29, 2004.  As of December 31, 2010, the ADSs represented 7.5% of our shares and 24.5% of our current global public float.

On February 23, 2011, our Board of Directors: (i) approved a change in the ratio of our ADSs, so that each ADS would represent two common shares of CPFL Energia and (ii) submitted aproposal for a simultaneousreverse stock split and forward stock split of our common shares to our shareholders. Our shareholders approved this proposal on our shareholders’ meeting of April 28, 2011.  Through the reverse stock split, 10 of our common shares will become one common shareand simultaneously,  through the forward stock split, each common share resulting from the reverse stock split will become 20 common shares .

The purpose of the change in the ADS ratio, as well as the reverse and forward stock splits, was to (a) adjust the share base, and consequently decrease the administrative and operational costs of CPFL Energia; (b) improve the efficiency of our systems for recording, controlling and disclosing information to shareholders; (c) adjust the price of our common shares and ADSs, allowing access to our stock by new investors; and (d) increase the liquidity of our shares and ADSs through a decrease in their individual value.

Theshares resulting from thereverse and forward stock splits will be credited on July 4, 2011, based on our shareholding position on June 28, 2011. The new ADSs resulting from the change of our ADSs’ ratio will be credited on July 5, 2011, based on our ADS holding position on July 1, 2011, resulting in the issuance of two additional ADSs for each existing ADS on July 1, 2011.

Price Information

The table below sets forth reported high and low closing sale prices inreais per common share for the periods indicated.  The table also sets forth prices in U.S. dollars per ADS based on information available from the New York Stock Exchange.  See “Item 3.  Key Information—Exchange Rates” for information with respect to exchange rates applicable during the periods indicated below.

	Reais per Common share		U.S. dollars per ADS
	High	Low	High	Low
2006	34.21	25.15	50.50	33.89
2007	40.44	27.80	67.28	38.70
2008	41.95	26.83	76.40	35.27
2009:
First Quarter	31.50	28.50	42.26	35.42
Second Quarter	34.50	31.06	51.86	41.95
Third Quarter	35.14	30.20	57.32	46.20
Fourth Quarter	37.50	30.40	66.29	52.28
2010:
First Quarter	38.48	35.36	65.55	58.30
Second Quarter	40.10	34.84	68.90	57.31
Third Quarter	44.00	38.66	76.70	67.07
October	40.78	39.33	74.03	71.59
November	41.35	39.30	73.53	70.15
December	41.31	40.09	76.91	71.64
2011:
January	43.26	41.04	78.55	74.96
February	43.27	39.70	79.23	73.35
March	46.39	42.49	87.41	77.66

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Corporate Governance Practices

In 2000, the BM&FBOVESPA introduced three special listing segments, known as Level 1, Level 2 and theNovo Mercado, aiming at fostering a secondary market for securities issued by Brazilian companies with securities listed on the BM&FBOVESPA, by prompting such companies to follow good practices of corporate governance.  The listing segments were designed for the trading of shares issued by companies voluntarily undertaking to abide by corporate governance practices and disclosure requirements in addition to those already imposed by Brazilian law.  These rules generally increase shareholders’ rights and enhance the quality of information provided to shareholders and stakeholders.  In order to maintain high standards of corporate governance, we have signed an agreement with the BM&FBOVESPA to list our securities on the Novo Mercado.

Our corporate governance guidelines apply to us and all of our subsidiaries and affiliated companies.  They aim at promoting interaction among our shareholders, Board of Directors, Fiscal Council and Board of Executive Officers.  Our managers have committed to focus on:

1.Disclosure (prompt and voluntary communication with market participants and our shareholders with respect to factors that guide our business and lead to the creation of value)

2.Fairness (fair treatment to our shareholders, our customers, suppliers, employees, creditors, government bodies, regulatory agencies, etc.) 

3.Accountability (accountability of our management to our shareholders, and responsibility for their acts while in office)

4.Compliance (commitment to the sustainability and continuity of our business in the long run, compliance with the legislation in force and observance of social and environmental matters)

We implemented this model in 2003 and redesigned it in 2006 in order to adjust our corporate governance structure to the current making-business scenario and decision-making process.

Our Board of Directors is our decision-making body, responsible for determining our overall guidelines.  Our Board of Directors can request advice on strategic matters from three of our committees, such as executive remuneration, related party transactions, corporate risk management, follow-up on internal audits and business management processes.  Whenever necessary,ad hoc commissions are installed to advise the Board of Directors on specific issues, such as corporate governance, strategies, budget, purchase of energy, new operations and financial policies.

A revision of these rules was under discussion between the companies listed in each segment and the BM&FBOVESPA, and it was approved during the second half of 2010 to provide for a further enhancement of the special corporate governance and disclosure rules.  The revised rules entered in force and effect on May 10, 2011, including those related to theNovo Mercado segment.  The main changes to the rules in the segment that we are listed include, among others:  (i) prohibition to include dispositions that restrict or create obligations to the shareholders which vote favorably to a suppression or amendment of dispositions of the by-laws; (ii) prohibition of the same individual to hold the positions of president of the board of directors and chief executive officer (or equivalent position as the main executive of the company); and (iii) obligation of the board of directors to issue a justified opinion on any tender offers for the acquisition of the shares representative of the corporate capital of the company.

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In accordance with Section 303A.11 of the NYSE Listed Company Manual, we have posted a summary of significant differences between the NYSE corporate governance standards and our corporate governance practices on our website, athttp://www.cpfl.com.br/ir. 

ITEM 10.Additional Information

Memorandum and Articles of Incorporation

Corporate Purpose

Our corporate purpose, as defined by our bylaws, includes:

·developing and fostering enterprises in the electricity generation, distribution, transmission, sale industry and related activities;

·providing services in the electricity, telecommunications and data transmission industries, as well as providing technical, operating, administrative and financial support services, especially to affiliated or subsidiary companies; and

·holding interest in the capital of other companies engaged in activities similar to those that we perform or which have as corporate purpose developing, fostering, building, and/or operating projects concerning electricity generation, distribution, transmission and related services.

Qualification of Directors

Brazilian law provides that only shareholders of a company may be appointed to its board of directors, but there is no minimum share ownership or residency requirement for qualification as a director.  Members of our board of executive officers must be Brazilian nationals and resident in Brazil.  Our directors and executive officers are prevented from voting on any transaction involving companies in which they hold more than 10.0% of the total capital stock or of which they have held a management position in the period immediately prior to their taking office.

Allocation of Net Income and Distribution of Dividends

The discussion below summarizes the provisions of Brazilian law regarding the establishment of reserves by corporations and the distribution of dividends, including interest attributed to shareholders’ equity.

Mandatory Distribution

Brazilian Corporate Law generally requires that the bylaws of each Brazilian corporation specify a minimum percentage of the amounts available for distribution by such corporation for each fiscal year that must be distributed to shareholders as dividends, also known as the mandatory distribution.

The mandatory distribution is based on a percentage of adjusted net income, not lower than 25.0%, rather than a fixed monetary amount per share.  Under our bylaws, at least 25.0% of our adjusted net income, as calculated under Brazilian Accounting Principles and adjusted under Brazilian Corporate Law (which differs significantly from net income as calculated under IFRS), for the preceding fiscal year must be distributed as a mandatory annual dividend.  Adjusted net income means the distributable amount after any deductions for statutory reserves and reserves for investment projects.

Brazilian Corporate Law permits the suspension of the mandatory distribution of dividends in any fiscal year in which the management bodies report to the shareholders’ meeting that the distribution would be inadvisable in view of the company’s financial condition.  The suspension is subject to approval by the shareholders meeting and review by members of the fiscal council.  The law does not establish the circumstances in which payment of the mandatory dividend would be “inadvisable” based on the company’s financial condition.  In the case of publicly-held corporations, the board of directors must file a justification for such suspension with the CVM within five days of the relevant general meeting.  If the mandatory distribution is not paid, the unpaid amount must be attributed to a special reserve account.  If not absorbed by subsequent losses, those funds must be paid out as dividends as soon as

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the financial condition of the company permits.  Under Brazilian Corporate Law, the shareholders of a publicly-held company may also decide to distribute dividends in an amount lower than the mandatory distribution.

Payment of Dividends

We are required by Brazilian Corporate Law to hold an annual general shareholders’ meeting by no later than April 30 of each year, at which the shareholders have to decide on the payment of an annual dividend.  Additionally, interim dividends may be declared by our Board of Directors.  Pursuant to our charter, we are required to pay a mandatory annual dividend of at least 25.0% of our adjusted net income.  Any holder of record of shares at the time of a dividend declaration is entitled to receive dividends.  Dividends on shares held through a depositary are paid to the depositary for further distribution to the shareholders.  Under Brazilian Corporate Law, dividends are generally required to be paid to the holder of record on a dividend declaration date within 60 days following the date the dividend was declared, unless a shareholders’ resolution sets forth another date of payment, which, in either case, must occur prior to the end of the fiscal year in which such dividend was declared.  Pursuant to our bylaws, unclaimed dividends do not bear interest, are not monetarily adjusted and revert to us three years after the date when we begin to pay such declared dividends.

In general, shareholders who are not residents of Brazil must register their equity investment with the Central Bank to have dividends, sales proceeds or other amounts with respect to their shares eligible to be remitted outside of Brazil.  The common shares underlying the ADSs are held in Brazil by Banco Bradesco S.A., as the custodian for the depositary, that is the registered owner on the records of the registrar for our shares.  The current registrar (since January 1, 2011) is Banco do Brasil S.A.  The depositary registers the common shares underlying the ADSs with the Central Bank and, therefore, is able to have dividends, sales proceeds or other amounts with respect to the common shares remitted outside Brazil.

Payments of cash dividends and distributions, if any, are made inreais to the custodian on behalf of the depositary, which then converts such proceeds into U.S. dollars for distribution to holders of ADSs.  In the event that the custodian is unable to convert immediately the Brazilian currency received as dividends into U.S. dollars, the amount of U.S. dollars payable to holders of ADSs may be adversely affected by depreciations of the Brazilian currency that occur before the dividends are converted.  Dividends paid to persons who are not Brazilian residents, including holders of ADSs, are not subject to Brazilian withholding tax, except for dividends declared based on profits generated prior to December 31, 1995, which are subject to Brazilian withholding income tax at varying tax rates.  See “Taxation—Brazilian Tax Considerations.”

Holders of ADSs have the benefit of the electronic registration obtained from the Central Bank, which permits the depositary and the custodian to convert dividends and other distributions or sales proceeds with respect to the common shares represented by ADSs into foreign currency and remits the proceeds outside of Brazil.  In the event the holder exchanges the ADSs for common shares, the holder will be entitled to continue to rely on the depositary’s certificate of registration for five business days after the exchange.  Thereafter, in order to convert foreign currency and remit outside Brazil the sales proceeds or distributions with respect to the common shares, the holder must obtain a new certificate of registration in its own name that will permit the conversion and remittance of such payments through the foreign exchange market.

If the holder is not a duly qualified investor and does not obtain an electronic certificate of foreign capital registration, a special authorization from the Central Bank must be obtained in order to remit from Brazil any payments with respect to the common shares through the foreign exchange market.  Without this special authorization, the holder may currently remit payments with respect to the common shares through the floating rate exchange market, although no assurance can be given that the floating rate exchange market will be accessible for these purposes in the future.

In addition, a holder who is not a duly qualified investor and who has not obtained an electronic certificate of foreign capital registration or a special authorization from the Central Bank may remit these payments by international transfer of Brazilian currency pursuant to CMN Resolution No. 3,265, dated March 4, 2005, and Central Bank Circular No. 3,280, dated March 9, 2005, as amended.  In order to effect the international transfer of Brazilian currency the holder must have a special non‑resident bank account in Brazil, through which the subsequent conversion of such Brazilian currency into U.S. dollars is effected.

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Under current Brazilian legislation, the Brazilian government may impose temporary restrictions of foreign capital abroad in the event of a serious imbalance or an anticipated serious imbalance of Brazil’s balance of payments (see “Item 3.  Key Information—Risk Factors—Risks Relating to the ADSs and Our Common Shares”).

Interest Attributable to Shareholders’ Equity

Under Brazilian tax legislation, Brazilian companies are permitted to pay “interest” to holders of equity securities and treat such payments as an expense for Brazilian income tax purposes and for social contribution purposes.  Payment of such interest may be made at the discretion of our Board of Directors, subject to the approval of the shareholders at a general shareholders’ meeting.  In order to calculate this interest on shareholders’ equity, the TJLP is applied to shareholders’ equity for the applicable period.  The amount of any such notional “interest” payment to holders of equity securities is generally limited in respect of any particular year to the greater of:

·50.0% of net income (after the deduction of the provisions for social contribution on net profits but before taking into account the provision for corporate income tax and the interest attributable to shareholders’ equity) for the period in respect of which the payment is made; or

·50.0% of the sum of retained earnings and profit reserves as of the beginning of the year in respect of which such payment is made.

For accounting purposes, although the interest charge must be reflected in the statement of operations to be tax‑deductible, the charge is reversed before calculating net income in the statutory financial statements and deducted from shareholders’ equity in a manner similar to a dividend.  Any payment of interest in respect of common shares (including the holders of the ADSs) is subject to Brazilian withholding tax at the rate of 15.0%, or 25.0% in the case of a shareholder domiciled in a tax haven.  See “Taxation—Brazilian Tax Considerations.”  If such payments are accounted for, at their net value, as part of any mandatory dividend, the tax is paid by the company on behalf of its shareholders, upon distribution of the interest.  If we distribute interest attributed to shareholder’s equity in any year, and that distribution is not accounted for as part of mandatory distribution, Brazilian income tax would be borne by the shareholders.  For IFRS accounting purposes, interest attributable to shareholders’ equity is reflected as a dividend payment.

Under our bylaws, interest attributable to shareholders’ equity may be treated as a dividend for purposes of the mandatory dividend.

We distributed R$1,260 million to our shareholders from our 2010 net income.  Of this amount, R$774 million, or R$1.609579599 per common share, was paid as an interim dividend on September 30, 2010 and R$486 million, or R$1.010190770 per common share, will be paid as supplemental dividend on April 29, 2011.

Dividend Policy

We intend to declare and pay dividends and/or interest attributed to shareholders’ equity in amounts of at least 50.0% of our adjusted net income, in semi-annual installments.  The amount of any of our distributions of dividends and/or interest attributed to shareholders’ equity will depend on a series of factors, such as our financial conditions, prospects, macroeconomic conditions, tariff adjustments, regulatory changes, growth strategies and other matters our Board of Directors and our shareholders may consider relevant.  In addition, covenants contained in our debt instruments may limit the amount of dividends and/or interest attributable to shareholders’ equity that we may make.  Within the context of our tax planning, we may in the future determine that it is to our benefit to distribute interest attributable to shareholders’ equity in lieu of dividends.

Our Board of Directors may approve the distribution of dividends and/or interest attributed to shareholders’ equity, calculated based on our annual or semi-annual financial statements or on financial statements relating to shorter periods, or also based on accrued profits recorded or on profits allocated to non‑profits reserve accounts in the annual or semi-annual financial statements.  The declaration of annual dividends, including dividends in excess of the mandatory distribution, requires approval by the vote of the majority of the holders of our common shares.

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Shareholder Meetings

Actions to be taken at our shareholders’ meetings

At our shareholder meetings, shareholders are generally empowered to take any action relating to our corporate purpose and to pass such resolutions as they deem necessary.  The approval of our financial statements and the determination of the allocation of our net profits with respect to each fiscal year takes place at the annual shareholder meeting immediately following such fiscal year.  The election of our directors and members of our fiscal council, if the requisite shareholders request its establishment, typically takes place at the annual shareholders’ meeting, although under Brazilian law it may also occur at a special shareholders’ meeting.

A special shareholders’ meeting may be held concurrently with the annual shareholders’ meeting.  The following actions may only be taken at a special shareholders’ meeting:

·amendment of our bylaws;

·cancellation of registration with the CVM as a publicly-held company;

·authorization of the issuance of debentures;

·suspension of the rights of a shareholder who has violated Brazilian Corporate Law or our bylaws;

·acceptance or rejection of the valuation of in-kind contributions offered by a shareholder in consideration for shares of our capital stock;

·approval of our transformation into a limited liability company (sociedade limitada) or any other corporate form;

·delisting of our common shares from theNovo Mercado; 

·appointment of a financial institution responsible for our valuation, in the event that a tender offer for our common shares is carried out in connection with a corporate transformation or delisting of our common shares fromthe Novo Mercado; 

·approval of any merger (fusão) or consolidation (incorporação) with another company or a spin-off (cisão); 

·approval of any dissolution or liquidation, the appointment and dismissal of the respective liquidator and the official review of the reports prepared by him or her;

·authorization to petition for bankruptcy or judicial or extrajudicial restructuring (recuperação judicial or extrajudicial); and

·approval of stock option plans to managers or employees of the Company and its subsidiaries.

According to Brazilian Corporate Law, neither a company’s bylaws nor actions taken at a shareholders’ meeting may deprive a shareholder of some specific rights, such as:

·the right to participate in the distribution of profits;

·the right to participate equally and ratably in any remaining residual assets in the event of liquidation of the company;

·the right to preemptive rights in the event of subscription of shares, convertible debentures or subscription warrants (bônus de subscrição), except in some specific circumstances under Brazilian law described in “—Preemptive Rights;” and

·the right to withdraw from the company in the cases specified in Brazilian Corporate Law, described in “Withdrawal Rights.”

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Quorum

As a general rule, Brazilian Corporate Law provides that a quorum at a shareholders’ meeting consists of shareholders representing at least 25.0% of a company’s issued and outstanding voting capital on the first call and, if that quorum is not reached, any percentage on the second call.  A quorum for the purposes of amending our bylaws consists of shareholders representing at least two-thirds of our issued and outstanding voting capital on the first call and any percentage on the second call.

As a general rule, the affirmative vote of shareholders representing at least the majority of our issued and outstanding common shares present in person or represented by proxy at a shareholders’ meeting is required to ratify any proposed action, with abstentions not taken into account.  However, the affirmative vote of shareholders representing one-half of our issued and outstanding voting capital is required to:

·reduce the percentage of mandatory dividends;

·change our corporate purpose;

·merge us with another company, if we are not the surviving company, or of our consolidation with another company;

·spin off a portion of our assets or liabilities;

·approve our participation in a group of companies (as defined in Brazilian Corporate Law);

·apply for cancellation of any voluntary liquidation; and

·approve our dissolution.

According to our bylaws and for so long as we are listed on theNovo Mercado, we may not issue preferred shares or founders’ shares and, to delist ourselves from theNovo Mercado, we will have to conduct a tender offer.

Notice of our Shareholders’ Meetings

Notice of our shareholders’ meetings must be published at least three times in theDiário Oficial do Estado de São Paulo, the official newspaper of the state of São Paulo, and in the newspaperValor Econômico.  The first notice must be published no later than 15 days before the date of the meeting on the first call, and no later than eight days before the date of the meeting on the second call.  However, in certain circumstances, the CVM may require that the first notice be published 30 days in advance of the meeting.

Documents and Information

The specific documents and information requested for the exercise of the voting rights of our shareholders shall be made available by electronic means at the Brazilian Securities Exchange Commission and the U.S. Securities and Exchange Commission websites, as well as at our investor relationship website.  The following matters require specific documents and information:

·matters with Interest of Related Parties;

·ordinary Shareholders’ Meeting;

·election of members of the Board of Directors;

·compensation of the Management of the Company;

·amendment to the Company’s By-laws;

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·capital Increase or Capital Reduction;

·issuance of Debentures or Subscription Bonuses;

·preferred Shares;

·change of the mandatory dividend distribution;

·acquisition of the control of another company;

·appointment of Evaluators; and/or

·any matter which entitles the shareholders to exercise their withdrawal right.

Location of our Shareholders’ Meetings

Our shareholders’ meetings take place at our head offices in the city of São Paulo, state of São Paulo.  Brazilian Corporate Law allows our shareholders to hold meetings outside our head offices in the event of force majeure, provided that the meetings are held in the City of São Paulo and the relevant notice contains a clear indication of the place where the meeting will occur.

Who May Call our Shareholders’ Meetings

In addition to our Board of Directors, shareholders’ meetings may also be called by:

·any shareholder, if our directors fail to call a shareholders’ meeting within 60 days after the date they were required to do so under applicable laws and our bylaws;

·shareholders holding at least five percent of our capital stock, if our directors fail to call a meeting within eight days after receipt of a request to call the meeting by those shareholders indicating the proposed agenda; and

·our fiscal council, if one is in place, if the Board of Directors delays calling an annual shareholders’ meeting for more than one month.  The fiscal council may also call a special shareholders’ meeting any time if it believes that there are important or urgent matters to be addressed.

Conditions of Admission

Shareholders attending our shareholders’ meeting must provide their identification cards and produce proof of ownership of the shares they intend to vote.

A shareholder may be represented at a shareholders’ meeting by a proxy, as long as the proxy is appointed less than a year before the shareholders’ meeting.  The proxy must be a shareholder, an officer of the corporation, a lawyer or a financial institution.  An investment fund must be represented by its investment fund officer.  The Company and/or its shareholders may also carry out a public proxy request directed to all shareholders with voting rights.

Since 2008, the Company has been adopting a Manual for Participation in General Shareholders’ Meetings to provide, in a clear and summarized form, information relating to the Company’s Shareholders General Meeting and to encourage and facilitate the participation of all shareholders.  This manual includes a standard power of attorney, which may be used by shareholders who are unable to be present at the meetings to appoint an attorney-in-fact to exercise their voting rights with regard to issues on the agenda.

Voting Rights of ADS Holders

ADS holders may instruct the depositary to vote the number of common shares that their ADSs represent.  The depositary will notify those holders of shareholders’ meetings and arrange to deliver our voting materials to them upon our request.  Those materials will describe the matters to be voted on and explain how the ADS holders

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may instruct the depositary how to vote.  For instructions to be valid, they must reach the depositary by a date set by the depositary.

We cannot assure ADS holders that they will receive the voting materials or otherwise learn of an upcoming shareholders’ meeting in time to ensure that they can instruct the depositary to vote their common shares.  In addition, the depositary and its agents are not responsible for failing to carry out voting instructions or for the manner of carrying out voting instructions. This means that ADS holders may not be able to exercise their right to vote and there may be nothing that they can do if their shares are not voted as they requested.

Preemptive Rights

Our shareholders have a general preemptive right to subscribe for shares in any capital increase according to the proportion of their shareholdings.  Our shareholders also have a general preemptive right to subscribe for any convertible debentures, rights to acquire our shares and subscription warrants that we may issue.  In accordance with our bylaws, a period of at least 30 days, in the case of a private placement, and 10 days, in the case of a public offering, following the publication of notice of the capital increase is allowed for the exercise of the preemptive right.  Under Brazilian Corporate Law, holders are permitted to transfer or dispose of their preemptive right for consideration.

In addition, Brazilian Corporate Law allows for companies’ bylaws to give the board of directors the power to exclude preemptive rights or reduce the exercise period of such rights with respect to the issuance of new shares, debentures convertible into shares and subscription warrants up to the limit of the authorized share capital if the distribution of those shares is effected through a stock exchange, through a public offering or through an exchange of shares in a public offering the purpose of which is to acquire control of another company.

Withdrawal Rights

Brazilian Corporate Law grants our shareholders the right to withdraw from the company in case they disagree with decisions taken in shareholder’s meetings concerning the following matters:  (i) the reduction of mandatory dividends; (ii) the merger of the company; (iii) the change of the corporate purpose of the company; or (iv) a spinoff of the company (if such spin-off changes the company’s corporate purpose, reduces mandatory dividends or results in the company joining a group of entities).  Even shareholders who did not vote or were not present at the relevant meeting may exercise this withdrawal right.

If our shareholders wish to withdraw from the company due to a merger, such right may only be exercised provided that the company’s shares have no liquidity in the market.

The withdrawal right entitles the shareholder to the reimbursement of the value of its shares, upon request within 30 days of the publication of notice of the shareholders meeting.  After such term, the company’s management bodies may choose to call a general meeting to ratify or reconsider the decision which triggered the withdrawal rights, should the payment of such rights threaten the financial stability of the company.

Material Contracts

For information concerning our material contracts, see “Item 4.  Information on the Company” and “Item 5.  Operating and Financial Review and Prospects.”

Exchange Controls and Other Limitations Affecting Security Holders

There are no restrictions on ownership of our capital stock by individuals or legal entities domiciled outside Brazil.  However, the right to convert dividend payments and proceeds from the sale of common shares into foreign currency and to remit such amounts outside Brazil is subject to restrictions under foreign investment legislation which generally requires, among other things, that the relevant investment be registered with the Central Bank.  These restrictions on the remittance of foreign capital abroad could hinder or prevent the custodian for the common shares represented by American Depositary Shares, or holders who have exchanged American Depositary Shares for common shares, from converting dividends, distributions or the proceeds from any sale of common shares into U.S. dollars and remitting such U.S. dollars abroad.  Delays in, or refusal to grant any required government approval for

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conversions of Brazilian currency payments and remittances abroad of amounts owed to holders of American Depositary Shares could adversely affect holders of American depositary receipts – ADRs.

Resolution No. 1,927/1992 of the National Monetary Council, which is the restated and amended Annex V to Resolution No. 1,289/1997, which we call the Annex V Regulations, provides for the issuance of depositary receipts in foreign markets in respect of shares of Brazilian issuers.  It provides that the proceeds from the sale of American Depositary Shares by holders of American depositary receipts outside Brazil are free of Brazilian foreign investment controls and holders of American Depositary Shares who are not resident in a tax haven jurisdiction (i.e. a country or location that does not impose taxes on income or where the maximum income tax rate is lower than 20.0%, or where the legislation imposes restrictions on disclosure of the shareholding composition or the ownership of the investment) will be entitled to favorable tax treatment.

An electronic registration has been issued by the custodian in the name of Deutsche Bank, the depositary, with respect to the American Depositary Shares.  Pursuant to this electronic registration, the custodian and the depositary are able to convert dividends and other distributions with respect to the common shares represented by American Depositary Shares into foreign currency and to remit the proceeds outside Brazil.  If a holder exchanges American Depositary Shares for common shares, the holder may continue to rely on the custodian’s electronic registration for only five business days after the exchange.  After that, the holder must seek to obtain its own electronic registration with the Central Bank under Law No. 4,131/1962 or Resolution No. 2,689/2000.  Thereafter, unless the holder has registered its investment with the Central Bank, such holder may not convert into foreign currency and remit outside Brazil the proceeds from the disposition of, or distributions with respect to, such common shares.  A holder that obtains an electronic registration generally will be subject to less favorable Brazilian tax treatment than a holder of American Depositary Shares.  See “—Taxation—Brazilian Tax Considerations.”

Under Brazilian law, whenever there is a serious imbalance in Brazil’s balance of payments or reasons to foresee a serious imbalance, the Brazilian government may impose temporary restrictions on the remittance to foreign investors of the proceeds of their investments in Brazil, and on the conversion of Brazilian currency into foreign currencies.  Such restrictions may hinder or prevent the custodian or holders who have exchanged American Depositary Shares for underlying common shares from converting distributions or the proceeds from any sale of such shares, as the case may be, into U.S. dollars and remitting such U.S. dollars abroad.

Taxation

The following summary contains a description of the material Brazilian and U.S. federal income tax consequences of the acquisition, ownership and disposition of common shares or ADSs, but it does not purport to be a comprehensive description of all the tax considerations that may be relevant to a decision to purchase common shares or ADSs.  The summary is based upon the tax laws of Brazil and regulations thereunder and on the tax laws of the United States and regulations thereunder as in effect on the date hereof, which are subject to change. Holders of common shares or ADSs should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common shares or ADSs.

Although there is at present no income tax treaty between Brazil and the United States, the tax authorities of the two countries have had discussions that may culminate in such a treaty.  No assurance can be given, however, as to whether or when a treaty will enter into force or how it will affect the U.S. holders (as defined below) of common shares or ADSs.  Prospective holders of common shares or ADSs should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common shares or ADSs in their particular circumstances.

Brazilian Tax Considerations

The following discussion summarizes the material Brazilian tax consequences of the acquisition, ownership and disposition of our common shares or ADSs by a holder that is not domiciled in Brazil for purposes of Brazilian taxation, or a Non‑Brazilian Holder.

Pursuant to Brazilian law, foreign investors may invest in the common shares under Resolution No. 2,689 of the National Monetary Council, or Resolution No. 2,689.

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Resolution No. 2,689 allows foreign investors to invest in almost all financial assets and to engage in almost all transactions available in the Brazilian financial and capital markets, provided that some requirements are fulfilled.  In accordance with Resolution No. 2,689, the definition of foreign investor includes individuals, legal entities, mutual funds and other collective investment entities, domiciled or headquartered abroad.

Pursuant to Resolution No. 2,689, foreign investors must:  (i) appoint at least one representative in Brazil with powers to perform actions relating to the foreign investment; (ii) complete the appropriate foreign investor registration form; (iii) register as a foreign investor with the CVM; and (iv) register the foreign investment with the Central Bank.

Securities and other financial assets held by foreign investors pursuant to Resolution No. 2,689 must be registered or maintained in deposit accounts or under the custody of an entity duly licensed by the Central Bank or the CVM.  In addition, securities trading is restricted to transactions carried out in the stock exchanges or organized over‑the-counter markets licensed by the CVM, except for transfers resulting from a corporate reorganization, occurring upon the death of an investor by operation of law or will or as a consequence of the delisting of the relevant shares from a stock exchange and the cancellation of the registration with the CVM.

Taxation of Dividends

Dividends, including dividends in kind, paid by us to the depositary in respect of the common shares underlying the ADSs or to a Non‑Brazilian Holder in respect of common shares generally will not be subject to Brazilian withholding income tax provided that they are paid out of profits generated as of or after January 1, 1996.  Dividends relating to profits generated prior to December 31, 1995 are subject to Brazilian withholding tax from 15.0% to 25.0% according to the tax legislation applicable to each corresponding year in which the profits have been earned.

Taxation of Gains

ADSs.  According to applicable Brazilian law (Law No. 10,833/2003), capital gains arising from transactions between two non‑resident parties, involving assets situated in Brazil, are subject to Brazilian withholding income tax, at a rate of 15.0% (25.0% in case the seller is situated in a tax haven jurisdiction).  Arguably, the gains realized by a Non‑Brazilian Holder on the disposition of ADSs to another non‑Brazilian resident should not be taxed in Brazil, based on the idea that ADSs would not constitute assets located in Brazil for purposes of Law No. 10,833/2003.  However, we cannot assure you of how Brazilian courts would interpret the definition of assets located in Brazil in connection with the taxation of gains realized by a Non‑Brazilian Holder on the disposition of ADSs to another non‑Brazilian resident.  Thus, the gain on a disposition of ADSs by a Non‑Brazilian Holder to a resident in Brazil (or possibly to a Non‑Brazilian Holder), in the event that courts determine that ADSs constitute assets located in Brazil, may be subject to income tax in Brazil according to the rules described below for the common shares. Non‑Brazilian Holders should consult their own tax advisor concerning the tax consequences of a sale of ADSs in Brazil. 

Although there are grounds to sustain otherwise, the deposit of common shares in exchange for ADSs may be subject to Brazilian withholding income tax, if the acquisition cost of the common shares is lower than (i) the average price per common share on a Brazilian stock exchange on which the greatest number of such shares were sold on the day of deposit; or (ii) if no common shares were sold on that day, the average price on the Brazilian stock exchange on which the greatest number of common shares were sold in the 15 trading sessions immediately preceding such deposit.  In such case, the difference between the acquisition cost and the average price of the common shares calculated as above will be considered to be a capital gain subject to income tax at a rate of 15.0% or 25.0% in the case of investors located in a tax haven jurisdiction (if the common shares are held by an investor registered under Resolution No.2,689 that is not resident in a tax haven jurisdiction, and the sale is performed at the stock exchange, however, any gain will be tax exempt from income tax in such transaction).

The withdrawal of common shares upon cancellation of ADSs is not subject to Brazilian income tax, as long as the regulatory rules are appropriately observed with respect to the registration of the investment before the Central Bank.

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Common Shares.  As a general rule, gains realized by Non‑Brazilian Holders on any disposition of common shares are subject to income tax at a rate of 15.0%, regardless of whether the sale or the disposition is made by the Non‑Brazilian Holder to a resident or non‑resident in Brazil, or if the transaction is conducted in Brazil or abroad, except for the specific cases described below.

Gains realized on any disposition of common shares by Non‑Brazilian Holders who are resident in a jurisdiction that is deemed to be a “tax haven jurisdiction” under Brazilian law (i.e., a country that does not impose any income tax or that imposes tax at a maximum rate of less than 20.0%, or which laws impose restrictions on disclosure of ownership composition or securities ownership such that the identification of the beneficial owner of income is not permitted) are subject to income tax at a rate of 25.0%.

Gains realized on sales or disposition of common shares carried out on the Brazilian stock exchange by Non‑Brazilian Holders who are not resident in a tax haven jurisdiction are exempt from income tax, if such Non‑Brazilian Holder is registered under Resolution No.2,689.  If the Non‑Brazilian Holder is a resident of a tax haven or is not registered under Resolution No.2,689, the gain realized on such sale or disposition of common shares is subject to income tax at a rate of 15.0%.  In these cases, a withholding income tax of 0.005% on the sale value shall be applicable and can be offset with the eventual income tax due on the capital gain.

Gains on the disposition of common shares are measured by the difference between the amount in Brazilian currency obtained from the sale or exchange of the shares and their acquisition cost in Brazilian currency, without any monetary adjustment.  However, for Non‑Brazilian Holders with a direct investment in common shares registered as foreign capital with the Central Bank, the acquisition cost should be measured in foreign currency, converted intoreais at the date of the sale⁴.

Exercise of Preemptive Rights.  Any exercise of preemptive rights relating to the common shares or ADSs will not be subject to Brazilian taxation.  Any gain on the sale or assignment of preemptive rights relating to common shares by the depositary on behalf of holders of ADSs will be subject to Brazilian income taxation according to the same rules applicable to the sale or disposition of common shares.

Interest Attributable to Shareholders’ Equity.  Payments of interest on shareholders’ equity to shareholders who are either Brazilian residents or non‑Brazilian residents, including holders of ADSs, are subject to Brazilian income withholding tax at the rate of 15.0%, or 25.0% for shareholders domiciled in a low tax jurisdiction.  The amounts paid as interest on equity (net of the withholding income tax) may be considered as payment of mandatory dividends.

The payment of interest on shareholders’ equity may be recommended by our Board of Directors and needs to be approved by our general shareholders’ meeting.  We cannot assure you that our Board of Directors will not recommend that future distributions of profits may be made by means of interest on shareholders’ equity instead of by means of dividends.

Tax on foreign exchange transactions

The conversion of foreign currency into Brazilianreais as well as the conversion of Brazilianreais into foreign currency are subject to a tax on foreign exchange transactions (“IOF/Exchange”).  The rate of such tax varies according to the nature of the transaction, such as:

·Inflow of funds from foreign investors for investment in the Brazilian financial and capital markets:  6%; except that the rate will be 2% for the following transactions:  (i) investments carried out on Brazilian stock, futures or commodities exchanges, as regulated by the National Monetary Council, except in case of derivative transactions with pre‑established earnings; (ii) purchase of shares in public offerings or subscription of shares of publicly-traded companies; (iii) purchase of quotas of private equity funds, emerging company funds or funds investing in emerging company funds, for transaction taking place as from January 1, 2011; (iv) cancellation of depositary receipts for investment in sharestraded on Brazilian stock exchanges, for transactions taking place as from January 1, 2011; and (v) change in the foreign investment regime from direct investment to investment in shares traded on Brazilian stock exchanges, as regulated by the National Monetary Council, for transaction taking place as from January 1, 2010.

⁴ This is our interpretation of the legislation in force.  This matter is still controversial, as there are recent rulings from the tax authorities providing that direct foreign investments registered with the Central Bank as RDE-IED (Registro Declaratório Eletrônico de Investimentos Estrangeiros Diretos) be converted into Brazilian currency at the date of the original investment.

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·Outflow of funds to foreign investors of the funds invested in the Brazilian financial and capital markets regarding the above-mentioned transaction:  0%;

·Remittances of dividends and interest on equity to foreign investors related to the above-mentioned transactions:  0%;

·Inflow of funds regarding loans contracted as from March 29, 2011, with an average maturity term equal or lower than 720 days:  6%; and

·Other foreign exchange transactions (subject to exceptions provided in the applicable legislation):  0.38%.

The IOF/Exchange may be changed at any time, up to 25.0%, upon the discretion of the President.  Any such increase, although immediately applicable, would only apply to future exchange transactions.

Tax on transactions involving bonds and securities

Brazilian law imposes a tax on transactions involving bonds and securities (the “IOF/Bonds Tax”), including those carried out on Brazilian stock, futures or commodities exchanges.  The IOF/Bonds Tax is currently reduced to zero in all transactions, except redemption of fixed yield investments lasting less than 30 days.  However, this rate may be increased at any time to up to 1.5% per day by the President, but only with respect to future transactions.  Currently, this tax is reduced to zero on all transactions involving stocks, except for shares underlying depositary receipts, in which case the IOF/Bonds Tax will apply at a 1.5% rate.

The transaction value to be considered for purposes of the IOF/Bonds Tax basis will be calculated by multiplying the number of shares by its closing quotation on the date prior to the transaction or, if no trades occurred on such date, by the last closing quotation available.  In the case of public offerings, the quotation to be considered for purposes of IOF/Bonds Tax basis will be the price established on the bookbuilding procedure or, if applicable, the price established by the seller on the documents of the public offering.

Other Relevant Brazilian Taxes

There are no Brazilian inheritance, gift or succession taxes applicable to the ownership, transfer or disposition of common shares or ADSs by a Non‑Brazilian Holder except for gift and inheritance taxes levied by certain Brazilian states on gifts or inheritance bestowed by individuals or entities not resident or domiciled in Brazil or not domiciled within that state, to individuals or entities resident or domiciled within in that Brazilian state.  There are no Brazilian stamp, issue, registration or similar taxes or duties payable by holders of common shares or ADSs.

U.S. Federal Income Tax Consequences

This discussion is a summary of the material U.S. federal income tax consequences of the ownership and disposition of common shares or ADSs.  This discussion is based on the U.S.  Internal Revenue Code of 1986, as amended (the “Code”), its legislative history, existing final, temporary and proposed Treasury regulations, administrative pronouncements by the U.S.  Internal Revenue Service (the “IRS”) and judicial decisions, in each case as of the date hereof, all of which are subject to change (possibly on a retroactive basis) and to different interpretations.

This discussion does not purport to be a comprehensive description of all of the U.S. federal income tax consequences that may be relevant to a particular holder (including tax considerations that arise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known by investors) and holders are urged to consult their own tax advisors regarding their specific tax situations.  Thisdiscussion applies only to holders of common shares or ADSs who hold the common shares or ADSs as “capital assets” (generally, property held for investment) under the Code and does not address the tax consequences that may be relevant to holders in special tax situations, including, for example:

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·brokers or dealers in securities or currencies;

·U.S. holders whose functional currency is not the U.S. dollar;

·holders that own or have owned stock constituting 10.0% or more of the Company’s total combined voting power (whether such stock is directly, indirectly or constructively owned);

·tax-exempt organizations;

·regulated investment companies;

·real estate investment trusts;

·grantor trusts;

·common trust funds;

·banks or other financial institutions;

·persons liable for the alternative minimum tax;

·securities traders who elect to use the mark-to-market method of accounting for their securities holdings;

·insurance companies;

·persons that acquired common shares or ADSs as compensation for the performance of services;

·U.S. expatriates; and

·persons holding common shares or ADSs as part of a straddle, hedge or conversion transaction or as part of a synthetic security, constructive sale or other integrated transaction.

Except where specifically described below, this discussion assumes that the Company is not a passive foreign investment company (a “PFIC”) for U.S. federal income tax purposes.  In addition, this discussion does not address tax considerations applicable to persons that hold an interest in a partnership or other pass-through entity that holds common shares or ADSs, or any U.S. federal estate and gift, state, local or non‑U.S. tax consequences of the ownership and disposition of common shares or ADSs.  Each holder should consult such holder’s own tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common shares or ADSs.

As used herein, the term “U.S. holder” means a beneficial owner of common shares or ADSs that is, for U.S. federal income tax purposes, (i) an individual who is a citizen or resident of the United States; (ii) a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia; (iii) an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or (iv) a trust if (A) it is subject to the primary supervision of a court within the United States and one or more U.S. persons have the authority to control all of the substantial decisions of the trust or (B) it has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.  As used herein, the term “non‑U.S. holder” means a beneficial owner of common shares or ADSs that is neither a U.S. holder nor a partnership (or an entity treated as a partnership for U.S. federal income tax purposes).

If a partnership (or other entity classified as a partnership for U.S. federal income tax purposes) owns common shares or ADSs, the tax treatment of a partner in such partnership will generally depend on the status of the

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partner and the activities of the partnership holding common shares or ADSs.  Partnerships that are beneficial owners of common shares or ADSs, and partners in such partnerships, should consult their own tax advisors regarding the U.S. federal, state, local and non‑U.S. tax considerations applicable to them with respect to the ownership and disposition of common shares or ADSs.

For U.S. federal income tax purposes, a holder of an ADS will generally be treated as the beneficial owner of the common shares represented by the ADS.  However, see the discussion below under “Taxation of Distributions” regarding certain statements made by the U.S. Treasury Department concerning depositary arrangements.

Taxation of Distributions

The gross amount of any distributions of cash or property made with respect to common shares or ADSs (including distributions characterized as interest on shareholders’ equity for Brazilian law purposes and any amounts withheld to reflect Brazilian withholding taxes) generally will be taxable as dividends for U.S. federal income tax purposes to the extent of the Company’s current or accumulated earnings and profits, as determined under U.S. federal income tax principles.

A U.S. holder will generally include such dividends in gross income as ordinary income on the day such dividends are actually or constructively received.  Distributions in excess of the Company’s current and accumulated earnings and profits will be treated first as a non‑taxable return of capital, thereby reducing the U.S. holder’s adjusted tax basis (but not below zero) in common shares or ADSs, as applicable, and thereafter as either long‑term or short‑term capital gain (depending on whether the U.S. holder has held common shares or ADSs, as applicable, for more than one year as of the time such distribution is actually or constructively received).

If any cash dividends are paid inreais, the amount of a distribution paid inreais will be the U.S. dollar value of thereais received, calculated by reference to the exchange rate in effect on the date of actual or constructive receipt.  If thereais received as a dividend are not converted into U.S. dollars on the date of actual or constructive receipt, a U.S. holder will have a tax basis in thereais equal to their U.S. dollar value on the date of receipt.  If anyreais actually or constructively received by a U.S. holder are later converted into U.S. dollars, such U.S. holder may recognize foreign currency gain or loss, which would be treated as ordinary gain or loss.  Such gain or loss generally will be treated as gain or loss from sources within the United States for U.S. foreign tax credit purposes.  U.S. holders should consult their own tax advisors concerning the possibility of foreign currency gain or loss if any suchreais are not converted into U.S. dollars on the date of actual or constructive receipt.

Dividends paid by the Company will not be eligible for the dividends received deduction allowed to corporations under the Code.  Subject to the below-mentioned concerns by the U.S. Treasury Department regarding certain inconsistent actions taken by intermediaries and certain exceptions for short‑term and hedged positions, the U.S. dollar amount of dividends received by certain U.S. holders (including individuals) in a taxable year beginning on or before December 31, 2012 with respect to the ADSs will be subject to taxation at a maximum rate of 15.0% if the dividends represent “qualified dividend income.”  Dividends paid on the ADSs will be treated as qualified dividend income if (i) the ADSs are readily tradable on an established securities market in the United States and (ii) the Company was not, in the year prior to the year in which the dividend was paid, and is not, in the year in which the dividend is paid, a PFIC.  The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed.  However, no assurances can be given that the ADSs will be or will remain readily tradable.  See below for a discussion regarding the Company’s PFIC determination.

Based on existing guidance, it is not entirely clear whether dividends received with respect to the common shares will be treated as qualified dividend income, because the common shares are not themselves listed on a U.S. exchange.  In addition, the U.S. Treasury Department has announced its intention to promulgate rules pursuant to which holders of common shares or ADSs and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to establish that dividends are treated as qualified dividends.  Because such procedures have not yet been issued, it is not clear whether the Company will be able to comply with them. U.S. holders of common shares or ADSs should consult their own tax advisors regarding the availability of the reduced dividend tax rate in the light of their own particular circumstances.

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Subject to certain limitations (including a minimum holding period requirement), a U.S. holder may be entitled to claim a U.S. foreign tax credit in respect of any Brazilian income taxes withheld on dividends received with respect to the common shares or ADSs.  A U.S. holder that does not elect to claim a credit for any foreign income taxes paid or accrued during a taxable year may instead claim a deduction in respect of such Brazilian income taxes, provided that the U.S. holder elects to deduct (rather than credit) all foreign income taxes paid or accrued for the taxable year.  Dividends received with respect to the common shares or ADSs generally will be treated as dividend income from sources outside of the United States and generally will constitute “passive category income” for U.S. foreign tax credit limitation purposes for most U.S. holders.  The rules governing foreign tax credits are complex and U.S. holders should consult their own tax advisors regarding the availability of foreign tax credits in their particular circumstances.  The U.S. Treasury Department has expressed concern that intermediaries in connection with depositary arrangements may be taking actions that are inconsistent with the claiming of foreign tax credits by U.S. persons who are holding depositary shares.  Accordingly, U.S. holders should be aware that the discussion above regarding the ability to credit Brazilian withholding tax on dividends and the availability of the reduced tax rate for dividends received by certain non‑corporate holders above could be affected by actions taken by parties to whom the ADSs are released and the IRS.

Distributions of additional shares to holders with respect to their common shares or ADSs that are made as part of a pro rata distribution to all the Company’s shareholders generally will not be subject to U.S. federal income tax.

Non‑U.S. holders generally will not be subject to U.S. federal income tax or withholding tax on distributions with respect to common shares or ADSs that are treated as dividend income for U.S. federal income tax purposes unless such dividends are effectively connected with the conduct by such holders of a trade or business in the United States (and, if required by an applicable income tax treaty, are attributable to a U.S. permanent establishment or fixed base).

Taxation of Sales, Exchanges or Other Taxable Dispositions

Deposits and withdrawals of common shares by U.S. holders in exchange for ADSs will not result in the realization of gain or loss for U.S. federal income tax purposes.

Upon the sale, exchange or other taxable disposition of common shares or ADSs, a U.S. holder will generally recognize gain or loss for U.S. federal income tax purposes in an amount equal to the difference between the amount realized in consideration for the disposition of the common shares or ADSs (including the gross amount of the proceeds before the deduction of any Brazilian tax) and the U.S. holder’s adjusted tax basis in the common shares or ADSs.  The initial tax basis of common shares or ADSs held by a U.S. holder will be the U.S. dollar value of thereais-denominated purchase price determined on the date of purchase.  Such gain or loss generally will be treated as capital gain or loss and will be long‑term capital gain or loss if the common shares or ADSs have been held for more than one year at the time of the sale, exchange or other taxable disposition.  Although the Company does not believe that U.S. holders will be entitled to a credit or deduction with respect to any IOF/Exchange paid on common shares or ADSs (as discussed in “—Brazilian Tax Considerations—Taxation of Gains—Tax on foreign exchange transactions”), U.S. holders should be entitled to include the amount of the IOF/Exchange paid as part of their initial basis in such common shares or ADSs.  Under current law, certain non‑corporate U.S. holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long‑term capital gains.  The deductibility of capital losses is subject to limitations under the Code.

If Brazilian income tax is withheld on the sale, exchange or other taxable disposition of common shares or ADSs, the amount realized by a U.S. holder will include the gross amount of the proceeds of that sale, exchange or other taxable disposition before deduction of the Brazilian income tax withheld.  Capital gain or loss, if any, realized by a U.S. holder on the sale, exchange or other taxable disposition of common shares or ADSs generally will be treated as U.S. source gain or loss for U.S. foreign tax credit purposes.  Consequently, in the case of a gain from the disposition of common shares or ADSs that is subject to Brazilian income tax (see ��—Brazilian Tax Considerations—Taxation of Gains”), the U.S. holder may not be able to benefit from the foreign tax credit for that Brazilian income tax (i.e., because the gain from the disposition would be U.S. source), unless the U.S. holder can apply the credit against U.S. federal income tax payable on other income from foreign sources.  Alternatively, the U.S. holder may take a deduction for the Brazilian income tax, provided that the U.S. holder elects to deduct all foreign income taxes paid or accrued for the taxable year.

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A non‑U.S. holder will not be subject to U.S. federal income tax or withholding tax on gain realized on the sale or other taxable disposition of common shares or ADSs unless (i) such non‑U.S. holder is an individual who is present in the United States of America for 183 days or more in the taxable year of the sale and certain other conditions are met or (ii) such gain is effectively connected with the conduct by the non‑U.S. holder of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment or fixed base).  If the first exception (i) applies, the non‑U.S. holder generally will be subject to tax at a rate of 30% on the amount by which the gains derived from the sales that are from U.S. sources exceed capital losses allocable to U.S. sources.  If the second exception (ii) applies, the non‑U.S. holder generally will be subject to U.S. federal income tax with respect to the gain in the same manner as U.S. holders, as described above.  In addition, in the case of (ii), if such non‑U.S. holder is a foreign corporation, it may be subject to a branch profits tax equal to 30% (or such lower rate provided by an applicable treaty) upon the actual or deemed repatriation of its effectively connected earnings and profits for the taxable year, subject to certain adjustments.

Passive Foreign Investment Company Rules

Special U.S. federal income tax rules apply to U.S. persons owning shares of a PFIC.  In general, a non‑U.S. corporation will be classified as a PFIC for any taxable year during which, after applying relevant look through rules with respect to the income and assets of subsidiaries, either (i) 75.0% or more of the non‑U.S. corporation’s gross income is “passive income” or (ii) on average 50.0% or more of the gross value of the non‑U.S. corporation’s assets produce passive income or are held for the production of passive income.  For these purposes, passive income generally includes, among other things, dividends, interest, rents, royalties, gains from the disposition of passive assets and gains from commodities and securities transactions, other than certain active business gains from the sale of commodities (the “Active Commodities Business exception”).  In determining whether a non‑U.S. corporation is a PFIC, a pro rata portion of the income and assets of each corporation in which it owns, directly or indirectly, at least 25.0% interest (by value) is taken into account.

The determination as to whether a non‑U.S. corporation is a PFIC is based on the composition of the income, expenses and assets of the non‑U.S. corporation from time to time and the application of complex U.S. federal income tax rules, which are subject to different interpretations.  In particular, the Company’s PFIC status for any taxable year will likely depend upon the extent to which the Company’s revenue from the sale of electricity qualifies under the Active Commodities Business exception, an analysis that raises uncertainties in application and interpretation.  Further, the relevant Treasury regulations addressing the Active Commodities Business exception have yet to be revised to reflect statutory changes with regard to this exception.  There can be no assurances that the Company would qualify under the Active Commodities Business exception if and when the relevant Treasury regulations were revised.  Based on the Company’s audited financial statements, the nature of the Company’s business, and relevant market and shareholder data, the Company believes that it would not be classified as a PFIC for its last taxable year or its current taxable year (although the determination cannot be made until the end of such taxable year), and the Company does not expect to be classified as a PFIC in the foreseeable future, based on its current business plans and its current interpretation of the Code and Treasury regulations that are currently in effect.

If, contrary to the discussion above, the Company is treated as a PFIC, a U.S. holder would be subject to special rules (and may be subject to increased U.S. federal income tax liability and filing requirements) with respect to (a) any gain realized on the sale, exchange or other disposition of common shares or ADSs and (b) any “excess distribution” made by the Company to the U.S. holder (generally, any distribution during a taxable year in which distributions to the U.S. holder on the common shares or ADSs exceed 125% of the average annual distributions the U.S. holder received on the common shares or ADSs during the preceding three taxable years or, if shorter, the U.S. holder’s holding period for the common shares or ADSs).  Under those rules, (a) the gain or excess distribution would be allocated ratably over the U.S. holder’s holding period for the common shares or ADSs, (b) the amount allocated to the taxable year in which the gain or excess distribution is realized and to taxable years before the first day on which the Company became a PFIC would be taxable as ordinary income, (c) the amount allocated to each prior year in which the Company was a PFIC would be subject to U.S. federal income tax at the highest tax rate in effect for that year and (d) the interest charge generally applicable to underpayments of U.S. federal income tax would be imposed in respect of the tax attributable to each prior year in which the Company was a PFIC.

If the Company is treated as a PFIC and, at any time, the Company invests in non‑U.S. corporations that are classified as PFICs (each, a “lower-tier PFIC”), U.S. holders generally will be deemed to own, and also would be subject to the PFIC rules with respect to, their indirect ownership interest in that lower-tier PFIC.  If the Company istreated as a PFIC, a U.S. holder could incur liability for the deferred tax and interest charge described above if either (i) the Company receives a distribution from, or disposes of all or part of its interest in, the lower-tier PFIC or (ii) the U.S. holder disposes of all or part of its common shares or ADSs.

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In general, if the Company is treated as a PFIC, the rules described above can be avoided by a U.S. holder that elects to be subject to a mark-to-market regime for stock in a PFIC.  A U.S. holder may elect mark-to-market treatment for its common shares or ADSs, provided the common shares or ADSs, for purposes of the rules, constitute “marketable stock” as defined in Treasury regulations.  The ADSs will be “marketable stock” for this purpose if they are regularly traded on the New York Stock Exchange, other than in de minimis quantities on at least 15 days during each calendar quarter.  A U.S. holder electing the mark-to-market regime generally would compute gain or loss at the end of each taxable year as if the common shares or ADSs had been sold at fair market value.  Any gain recognized by the U.S. holder under mark-to-market treatment, or on an actual sale, would be treated as ordinary income, and the U.S. holder would be allowed an ordinary deduction for any decrease in the value of common shares or ADSs as of the end of any taxable year, and for any loss recognized on an actual sale, but only to the extent, in each case, of previously included mark-to-market income not offset by previously deducted decreases in value.  Any loss on an actual sale of common shares or ADSs would be a capital loss to the extent in excess of previously included mark-to-market income not offset by previously deducted decreases in value.  A U.S. holder’s adjusted tax basis in common shares or ADSs would increase or decrease by gain or loss taken into account under the mark-to-market regime.  A mark-to-market election is generally irrevocable.  In addition, a mark-to-market election with respect to common shares or ADSs would not apply to any lower-tier PFIC, and a U.S. holder would not be able to make such a mark-to-market election in respect of its indirect ownership interest in that lower-tier PFIC.  Consequently, the PFIC rules could apply with respect to income of a lower-tier PFIC, the value of which would already have been taken into account indirectly via mark-to-market adjustments in respect of common shares or ADSs.

A U.S. holder that owns common shares or ADSs during any taxable year that the Company is treated as a PFIC generally would be required to file IRS Form 8621.  U.S. holders should also be aware that recently enacted legislation would impose an additional annual filing requirement for U.S. persons owning shares of a PFIC.  The legislation does not describe what information would be required to be included in the additional annual filing, but grants the Secretary of the U.S. Treasury Department power to make this determination.  U.S. holders should consult their independent tax advisors regarding the application of the PFIC rules to common shares or ADSs, the availability and advisability of making an election to avoid the adverse tax consequences of the PFIC rules should the Company be considered a PFIC for any taxable year and the application of the recently-enacted legislation to their particular situation.

Backup Withholding and Information Reporting

Dividends paid on, and proceeds from the sale, exchange or other taxable disposition of, common shares or ADSs to a U.S. holder generally may be subject to the information reporting requirements of the Code and may be subject to backup withholding of U.S. federal income tax (currently at a rate of 28.0%) unless the U.S. holder (i) provides an accurate taxpayer identification number and certifies that it is a U.S. person and that no loss of exemption from backup withholding has occurred or (ii) is an exempt recipient.  The amount of any backup withholding collected from a payment to a U.S. holder will be allowed as a credit against the U.S. holder’s U.S. federal income tax liability and may entitle the U.S. holder to a refund, provided that certain required information is timely furnished to the IRS.

In addition, U.S. holders should be aware that recently-enacted legislation imposes new reporting requirements with respect to the holding of certain foreign financial assets, including stock of foreign issuers which is not held in an account maintained by certain financial institutions, if the aggregate value of all such assets exceeds US$50,000.  U.S. holders should consult their own tax advisors regarding the application of the information reporting rules to common shares or ADSs and the application of the recently-enacted legislation to their particular situations.

Non‑U.S. holders generally will not be subject to information reporting and backup withholding tax, but may be required to comply with certain certification and identification procedures in order to establish their eligibility for such exemption.

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Documents on Display

Statements contained in this annual report regarding the contents of any contract or other document are not necessarily complete, and, where the contract or other document is an exhibit to the annual report, each of these statements is qualified in all respects by the provisions of the actual contract or other documents.

We are subject to the information requirements of the Securities Exchange Act of 1934, as amended, applicable to a foreign private issuer, and accordingly, we file or furnish reports, information statements and other information with the SEC. Reports and other information filed by us with the SEC can be inspected at, and subject to the payment of any required fees, copies may be obtained from, the public reference facilities of the SEC, 100 F Street, N.E., Washington, D.C. 20549.  Our filings will also be available at the SEC’s website at http://www.sec.gov.

Reports and other information may also be inspected and copied at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.  As a foreign private issuer, however, we are exempt from the proxy requirements of Section 14 of the Exchange Act and from the short-swing profit recovery rules of Section 16 of the Exchange Act.

Our website is located at http://www.cpfl.com.br and our investor relations website is located at http://www.cpfl.com.br/ir.  (These URLs are intended to be an inactive textual reference only.  They are not intended to be an active hyperlink to our website.  The information on our website, which might be accessible through a hyperlink resulting from this URL is not, and shall not be deemed to be, incorporated into this annual report.)

ITEM 11.Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk from changes in both foreign currency exchange rates and rates of interest and indexation.  We have foreign exchange rate risk with respect to our debt denominated in U.S. dollars and Japanese yens.  We are subject to market risk deriving from changes in rates which affect the cost of our financing.

Exchange Rate Risk

At December 31, 2010, we had outstanding approximately R$470 million of indebtedness denominated in foreign currencies, including U.S. dollars and Japanese yen, and R$94 million of indebtedness denominated in Brazilianreais, but partially indexed to the U.S. dollar.  Also at December 31, 2010, we had swap agreements that offset the exchange rate risk with respect to R$529 million of those amounts.  The potential loss to us that would result from a hypothetical unfavorable 10.0% change in foreign currency exchange rates, after giving effect to the swaps, would be approximately R$3 million, primarily due to the increase, in Brazilianreais, in the principal amount of our foreign currency indebtedness.  The total increase in our foreign currency indebtedness would be reflected as an expense in our income statement.

Risk of Index Variation

We have indebtedness and financial assets that are denominated inreais and that bear interest at variable rates or, in some cases, are fixed.  We also have swaps that convert some U.S. dollar-denominated indebtedness toreais at variable interest rates.  The interest or indexation rates include several different Brazilian money-market rates and inflation rates.  At December 31, 2010, the amount of such liabilities, net of such assets and after giving effect to swaps, was R$7,266 million.

A hypothetical, instantaneous and unfavorable change of 100 basis points in rates applicable to floating rate financial assets and liabilities held at December 31, 2010, would result in a net additional cash outflow of approximately R$73 million.  This sensitivity analysis is based on the assumption of an unfavorable 100 basis point movement of the interest rates applicable to each homogeneous category of financial assets and liabilities.  A homogeneous category is defined according to the currency in which financial assets and liabilities are denominated and assumes the same interest rate movement within each homogeneous category (e.g., U.S. dollars).  As a result, our interest rate risk sensitivity model may overstate the impact of interest rate fluctuations for such financial instruments asconsistently unfavorable movements of all interest rates are unlikely.

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ITEM 12.Description of Securities Other than Equity Securities

American Depositary Shares

Fees and Expenses

The following table summarizes the fees and expenses payable by holders of ADSs:

Persons depositing common shares or ADS holders must pay:	For:
US$5.00 (or less) per 100 ADSs (or portion of 100 ADSs)	Issuance of ADSs, including issuances resulting from a distribution of common shares or rights or other property Cancellation of ADSs for the purpose of withdrawal, including if the deposit agreement terminates
US$2.00 (or less) per 100 ADS (to the extent not prohibited by the rules of any stock exchange on which the ADSs are listed for trading)	Any cash distribution to you
US$2.00 (or less) per 100 ADS (to the extent the depositary has not collected a cash distribution fee of US$2.00 per 100 ADS during the year)	Depositary services
Registration or transfer fees	Transfer and registration of common shares on our common share register to or from the name of the depositary or its agent when you deposit or withdraw common shares.
Expenses of the depositary	Cable, telex and facsimile transmissions (when expressly provided in the deposit agreement) Converting foreign currency to U.S. dollars
Taxes and other governmental charges the depositary or the custodian have to pay on any ADS or common share underlying an ADS, for example, stock transfer taxes, stamp duty or withholding taxes	As necessary
Any charges incurred by the depositary or its agents for servicing the deposited securities	No charges of this type are currently made in the Brazilian market

Reimbursement of Fees and Direct and Indirect Payments by the Depositary

The depositary collects its fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them.  The depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees.  The depositary may collect its annual fee for depositary services by deduction from cash distributions or by directly billing investors or by charging the book-entry system accounts of participants acting for them.  The depositary may generally refuse to provide fee-attracting services until its fees for those services are paid.

In 2010, we received the following payments from the depositary:  US$15,000, US$550,000 and US$30,000 for expenses incurred by us relating to the ADR program, including global shareholder identification, expenses relating to the second year of the agreement between the depositary and us and legal expenses, respectively.

ITEM 13.Defaults, Dividend Arrearages and Delinquencies

None.

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ITEM 14.Material Modifications to the Rights of Security Holders and Use Of Proceeds

None.

ITEM 15.Controls and Procedures

We have evaluated, with the participation of our chief executive officer and chief financial officer, the effectiveness of our disclosure controls and procedures as of December 31, 2010.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon our evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.  Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  Our internal control over financial reporting includes those policies and procedures that:  (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, and that the degree of compliance with the policies or procedures may deteriorate.

Our management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2010 based on the criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).  Based on such assessment and criteria, our management has concluded that our internal control over financial reporting was effective as of December 31, 2010.

The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by KPMG Auditores Independentes, an independent registered public accounting firm, as stated in their report included on page 108 of this report.

There has been no change in our internal control over financial reporting during 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 16.

ITEM 16A.AUDIT COMMITTEE FINANCIAL EXPERT

As described in Item 16D below, we have given our fiscal council the necessary powers to qualify for the exemption from the audit committee requirements set forth in Exchange Act Rule 10A-3(c)(3).  Our Board ofDirectors recognizes that one member of our fiscal council, Daniela Corci Cardoso, qualifies as an audit committee financial expert and meets the applicable independence requirements for fiscal council membership under Brazilian law.  She also meets the New York Stock Exchange independence requirements that would apply to audit committee members in the absence of our reliance on the exemption set forth in Exchange Act Rule 10A-3(c)(3).  Some of the members of our fiscal council are currently employed by some of our principal shareholders or their affiliates.

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ITEM 16B.CODE OF ETHICS

We have adopted a Code of Ethics applicable to our employees and our directors and executive officers, which addresses such matters as conflicts of interest, corporate opportunities, confidentiality, fair dealing, protection and proper use of company assets, compliance with laws, rules and regulations (including insider trading laws) and encouraging the reporting of any illegal or unethical behavior.  Our Code of Ethics is available on our website at:  http://www.b2i.cc/Document/986/CPFL_CodEtica_20061227_eng.pdf. (This URL is intended to be an inactive textual reference only.  It is not intended to be an active hyperlink to our website.  The information on our website, which might be accessible through a hyperlink resulting from this URL, is not and shall not be deemed to be, incorporated into this annual report).  If we amend the provisions of our code of ethics that apply to our chief executive officer, our chief financial officer, our principal accounting officer and persons performing similar functions, or if we furnish a waiver to any such persons, we will disclose such amendment or waiver on our website at the same address.

ITEM 16C.PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit and Non‑Audit Fees

The following table sets forth the fees billed to us by our independent registered and public accounting firm during the years ended December 31, 2010 and 2009.  Our independent accounting firm is KPMG Auditores Independentes beginning in June 2007.

In thousand ofreais	Year ended December 31,
	2010		2009
Audit fees	R$	3,092	R$	2,658
Audit-related fees	491		499
Tax fees	143		139
All other fees	-		-
Total	R$	3,726	R$	3,296

“Audit Fees” are the aggregated fees billed by KPMG Auditores Independentes for the audit of our consolidated and annual financial statements, reviews of interim financial statements and attestation services that are provided in connection with statutory and regulatory filings or engagements for the fiscal years of 2010 and 2009, respectively.

“Audit-related fees” are fees charged by KPMG Auditores Independentes for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements.

“Tax fees” in the above table are for services related to tax compliance.

Audit Committee Approval Policies and Procedures

Our fiscal council currently serves as our audit committee for purposes of the Sarbanes-Oxley Act of 2002.  Our fiscal council has not established pre‑approval policies or procedures for recommending the engagement of our independent auditors for services to our Board of Directors.  Pursuant to Brazilian law, our Board of Directors is responsible for the engagement of independent auditors.  Brazilian law prohibits our independent auditors from providing any consulting services to our subsidiaries, or to us, that may impair their independence.

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ITEM 16D.EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Under the listed company audit committee rules of the NYSE and the SEC, we must comply with Exchange Act Rule 10A-3, which requires that we establish an audit committee composed of members of the Board of Directors that meets specified requirements.  We have designated and empowered our fiscal council to perform the role of the audit committee in reliance on the exemption set forth in Exchange Act Rule 10A-3(c)(3).  In our assessment, our fiscal council acts independently in performing the responsibilities of an audit committee under the Sarbanes-Oxley Act and satisfies the other requirements of Exchange Act Rule 10A-3.

ITEM 16E.PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

None.

ITEM 16F.CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

None.

ITEM 16G.CORPORATE GOVERNANCE

The following chart summarizes the ways that our corporate governance practices differ from those followed by domestic companies under the listing standards under the New York Stock Exchange:

Section of the New York Stock Exchange Listed Company Manual	New York Stock Exchange Listing Standard	Ways that CPFL’s Corporate Governance Practices Differ from Those Followed by Domestic Companies Listed on the New York Stock Exchange
303A.01	A company listed on the New York Stock Exchange (a “listed company”) must have a majority of independent directors on its Board of Directors.  “Controlled companies” are not required to comply with this requirement.	CPFL is a controlled company, because more than a majority of its voting power is controlled by VBC Energia, PREVI (through BB Carteira Livre I Fundo de Investimento em Ações) and Bonaire Participações S.A.  As a controlled company, CPFL would not be required to comply with the majority of independent directors requirements if it were a U.S. domestic issuer.  CPFL has one independent director, as defined by BM&FBOVESPA rules.
303A.03	The non-management directors of a listed company must meet at regularly scheduled executive sessions without management.	The non-management directors of CPFL do not meet at regularly scheduled executive sessions without management.
303A.04	A listed company must have a Nominating/Corporate Governance Committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties.  “Controlled companies” are not required to comply with this requirement.	As a controlled company, CPFL would not be required to comply with the Nominating/Corporate Governance Committee requirements if it were a U.S. domestic issuer.  Nonetheless, in order to improve its corporate governance practices, CPFL constituted the Corporate Governance Commission.  It has four members:  the CEO and three members of the Board of Directors.  This Commission is responsible for evaluating the effectiveness of CPFL’s corporate governance practices, proposing improvements to CPFL’s governance practices, and monitoring the implementation of CPFL’s corporate governance practices.
303A.05	A listed company must have a compensation committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties.  “Controlled companies” are not required to comply with this requirement.	As a controlled company, CPFL would not be required to comply with the compensation committee requirements.  The Human Resources Management Committee of CPFL is an advisory committee of the Board of Directors.  It has three members who are all directors, none of whom is independent.  According to its charter, this committee is responsible for assisting the Board of Directors by:  (i) coordinating the CEO selection process, (ii) defining criteria for compensation of the executive officers, including long and short-term incentive plans, (iii) defining performance goals of the executive officers, (iv) coordinating evaluation procedures of the executive officers, (v) preparation of the plan of succession for executive officers and (vi) monitoring the execution of human resources policies and practices and preparing improvement proposals when necessary.
303A.06 and 303A.07	A listed company must have an audit committee with a minimum of three independent directors that satisfy the independence requirements of Rule 10A-3 under the Exchange Act, with a written charter that covers certain minimum specified duties.	In lieu of appointing an audit committee composed of independent members of the Board of Directors, CPFL has a permanent conselho fiscal, or fiscal council, in accordance with the applicable provisions of the Brazilian Corporate Law, and CPFL has granted the fiscal council with additional powers that meet the requirements of Exchange Act Rule 10A-3(c)(3).  Under Brazilian Corporate Law, which enumerates standards for the independence of the fiscal council from CPFL and its management, none of the members of the fiscal council may be:  (i) members of the Board of Directors; (ii) members of the board of executive officers; (iii) employed by CPFL or an affiliate or company controlled by CPFL or (iv) a spouse or relative of any member of the company’s management or Board of Directors.  Members of the fiscal council are elected at the company’s general shareholders meeting for a one-year term of office.  The fiscal council of CPFL currently has five members, all of whom comply with standards (i) to (iv) above.  The responsibilities of the fiscal council, which are set forth in its charter, includes reviewing management’s activities and the company’s financial statements, and reporting findings to the company’s shareholders.
303A.08	Shareholders must be given the opportunity to vote on all equity-compensation plans and material revisions thereto, with limited exemptions set forth in the NYSE rules.	Under Brazilian Corporate Law, shareholder pre-approval is required for the adoption of any equity compensation plans.
303A.09	A listed company must adopt and disclose corporate governance guidelines that cover certain minimum specified subjects.	CPFL has formal corporate governance guidelines that address all of the matters specified in the NYSE rules.
303A.10	A listed company must adopt and disclose a code of business conduct and ethics for directors, officers and employees, and promptly disclose any waivers of the code for directors or executive officers.	CPFL has a formal Code of Ethics that applies to its directors, officers, employees and controlling shareholders.  CPFL’s Code of Ethics has a scope that is similar, but not identical, to that required for a U.S. domestic company under the NYSE rules.  CPFL reports each year under Item 16B of our annual report on Form 20-F any waivers of the code of ethics in favor of our chief executive officer, our chief financial officer, our principal accounting officer and persons performing similar functions.  We will disclose such amendment or waiver on our website.
303A.12	Each listed company CEO must certify to the NYSE each year that he or she is not aware of any violation by the company of NYSE corporate governance listing standards.	CPFL’s CEO provides to the NYSE a Foreign Private Issuer Annual Written Affirmation, and he will promptly notify the NYSE in writing after any executive officer of CPFL becomes aware of any material non-compliance with any applicable provisions of the NYSE corporate governance rules.

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ITEM 17.Financial Statements

Not applicable.

ITEM 18.Financial Statements

See pages F-1 through F-86, incorporated herein by reference.

ITEM 19.Exhibits 

No.	Description
1.1	Amended and Restated Bylaws of CPFL Energia S.A. (together with an English version).
3.1	Shareholders Agreement dated March 22, 2002 as amended on August 27, 2002, November 5, 2003 and December 6, 2007 among VBC Energia S.A., 521 Participações S.A., Bonaire Participações S.A. and CPFL Energia S.A.
8.1	List of subsidiaries, their jurisdiction of incorporation and names under which they do business.
12.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
12.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
13.1	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

The amount of long‑term debt securities of CPFL Energia or its subsidiaries authorized under any outstanding agreement does not exceed 10.0% of CPFL Energia’s total assets on a consolidated basis.  CPFL Energia hereby agrees to furnish the SEC, upon its request, a copy of any instruments defining the rights of holders of its long‑term debt or of its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed.

GLOSSARY OF TERMS

ABRADEE:  Brazilian Association of Electric Energy Distributors (Associação Brasileira de Distribuidores de Energia Elétrica).

ANEEL:  National Electric Energy Agency (Agência Nacional de Energia Elétrica).

Annual Reference Value:  Mechanism which limits the amounts of costs that can be passed through to Final Consumers.  The Annual Reference Value corresponds to the weighted average of electricity acquisition costs resulting from electricity prices of all public auctions carried out by ANEEL and CCEE in the regulated market for electricity to be delivered five and three years from any such auction and only applies during the first three years following the commencement of delivery of the acquired electricity.

Assured energy:  Amount of energy that generators are allowed to sell in long‑term contracts.

Basic Network:  Interconnected transmission lines, dams, energy transformers and equipment with voltage equal to or higher than 230 kV, or installations with lower voltage as determined by ANEEL.

Capacity Agreement:  Agreement under which 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.

CCC:  Fuel Usage Quota.

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CCEAR:  Regulated Market (Contratos de Comercialização de Energia no Ambiente Regulado).

CCEE:  Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica). The short‑term electricity market, established in 1998 through the Power Industry Law, which replaced the prior system of regulated generation prices and supply contracts, formerly known as the Wholesale Energy Market.

CMCE:  Energy Industry Monitoring Committee (Comitê de Monitoramento do Setor Elétrico).

CNPE:  National Energy Policy Council (Conselho Nacional de Política Energética).

DistributionNetwork:  Electric network system that distributes energy to end consumers within a concession area.

Distributor:  An entity supplying electric energy to a group of consumers by means of a distribution network.

EnergyAgreement:  Agreement under which 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, which could interrupt the supply of electricity.  In such a case, the generator would be required to purchase electricity elsewhere in order to comply with its supply commitments.

FinalConsumer:  A party that uses electricity for its own needs.

FreeConsumers:  (i) Existing consumers with demand of at least 10 MW and supplied at voltage level equal to or greater than 69 kV; (ii) new consumers with demand of at least 3 MW at any voltage; (iii) groups of consumers subject to agreement with the local distribution concessionaire; (iv) consumers who do not receive supply for more than 180 days from a local distribution concessionaire; and (v) certain others.

FreeMarket:  Market segment that permits a certain degree of competition.  The free market specifically contemplates purchase of electricity by non‑regulated entities such as Free Consumers and energy traders.

Gigawatt (GW):  One billion watts.

Gigawatthour (GWh):  One gigawatt of power supplied or demanded for one hour, or one billion watt hours.

Highvoltage:  A class of nominal system voltages equal to or greater than 100,000 volts (100 kVs) and less than 230,000 volts (230 kVs).

Hydroelectricplant or hydroelectric facility:  A generator that uses water power to drive the electric generator.

InitialSupply Contracts:  Initial energy supply agreements at prices and volumes approved by ANEEL, that distribution and generation companies are required to enter into per the 1998 Power Industry Law.

Installed capacity:  The level of electricity which can be delivered from a particular generator on a full-load continuous basis under specified conditions as designated by the manufacturer.

Interconnected Power System:  Systems or networks for the transmission of energy, connected together by means of one or more links (lines and/or transformers).

Independent Power Producer:  A legal entity or consortium holding a concession or authorization for power generation for sale for its own account to public utility concessionaires.

Kilovolt (kV):  One thousand volts.

Kilowatt (kW):  One thousand watts.

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Kilowatthour (kWh):  One kilowatt of power supplied or demanded for one hour, or one thousand watt hours.

Megawatt (MW):  One million watts.

Megawatthour (MWh):  One megawatt of power supplied or demanded for one hour, or one million watt hours.

MME:  Ministry of Mines and Energy (Ministério de Minas e Energia). 

MRE:  Energy Reallocation Mechanism (Mecanismo de Realocação de Energia). 

ONS:  National System Operator (Operador Nacional do Sistema), an entity responsible for operational planning, administration of generation and transmission and planning of transmission investments in the power industry.

Parcel A costs:  Costs that include, among others, the following:  (i) costs of electricity purchased for resale pursuant to Initial Supply Contracts; (ii) costs of electricity purchased from Itaipu; (iii) costs of electricity purchased pursuant to bilateral agreements that are freely negotiated between parties; and (iv) certain other charges for the transmission and distribution systems.

Parcel B costs:  Costs that are under control of distributors.  Such costs are determined by subtracting all of the Parcel A costs from the distribution company’s revenues, excluding ICMS and PIS/COFINS, a state and federal tax levied on sales.  Parcel B costs include, among others, the return on investment related to concessions and their expansion, as well as maintenance and operational costs.

Rationing Program:  The Brazilian government program to reduce electricity consumption that was in effect from June 1, 2001 to February 28, 2002 as a result of poor hydrological conditions that threatened the country’s electricity supply.

Regulated market:  Market segment in which distribution companies purchase all the electricity needed to supply customers through public auctions.  The auction process is administered by ANEEL, either directly or through CCEE, under certain guidelines provided by the MME.  The regulated market is generally considered to be more stable in terms of supply of electricity.

Retail Distribution Tariff:  Revenue charged by distribution companies to its 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.  Retails tariffs are subject to annual readjustments by ANEEL.

RTE:  Extraordinary Tariff Adjustment (reajuste tarifário extraordinário). 

Small hydroelectric power plants:  Power projects with capacity from 1 MW to 30 MW.

Special consumer:  A group of consumers that uses at least 500 kV.  Special Consumers may only purchase energy from (i) small hydroelectric power plants with capacity between 1,000 kW and 30,000 kW, (ii) generators with capacity limited to 1,000 kW, and (iii) alternative energy generators (solar, wind and biomass enterprises) with capacity injected in the system not greater than 30,000 kW.  A Special Consumer may terminate its contract with the local distributor with 180 days prior notice for contracts with indefinite terms.

Substation:  An assemblage of equipment which switches and/or changes or regulates the voltage of electricity in a transmission and distribution system.

Thermoelectric power plant:  A generator which uses combustible fuel, such as coal, oil, diesel natural gas or other hydrocarbon as the source of energy to drive the electric generator.

Transmission:  The bulk transfer of electricity from generating facilities to the distribution system at load center station by means of the transmission grid (in lines with capacity between 69 kV and 525 kV).

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Transmission Tariff:  Revenue charged by a transmission concessionaire based on the transmission network it owns and operates.  Transmission tariffs are subject to periodic revisions by ANEEL.

Volt:  The basic unit of electric force analogous to water pressure in pounds per square inch.

Watt:  The basic unit of electrical power.

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SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant, CPFL Energia S.A., hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Campinas, state of São Paulo, Brazil, on June 6, 2011.

	CPFL ENERGIA S.A.
By:	/s/ Wilson Ferreira,  Junior
Name:	Wilson Ferreira, Junior
Title:	Chief Executive Officer
	(principal executive officer)
By:	/s/ Lorival Nogueira Luz Júnior
Name:	Lorival Nogueira Luz Júnior
Title:	Chief Financial Officer
	(principal financial officer)

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	KPMG Auditores Independentes	Central Tel	55 (19) 2129-8700
	Av. Barão de Itapura, 950 - 6º andar	Fax	55 (19) 2129-8728
	13020-431 - Campinas, SP - Brasil	Internet	www.kpmg.com.br
	Caixa Postal 737
	13012-970 - Campinas, SP – Brasil

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

CPFL Energia S.A.

We have audited the accompanying consolidated balance sheets of CPFL Energia S.A. and subsidiaries (the “Company”) as of December 31, 2010, 2009 and January 1, 2009, and the related consolidated statements of income, changes in shareholders’ equity, comprehensive income and cash flows for each of the years in the two-year period ended December 31, 2010.  We also have audited the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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CPFL Energia S.A.
Report of independent registered public accounting firm

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the CPFL Energia S.A. and subsidiaries as of December 31, 2010, 2009 and January 1, 2009, and the results of their operations, cash flows, changes in their shareholders’ equity and comprehensive income for each of the years in the two-year period ended December 31, 2010, in conformity with International Financial Reporting Standards. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG Auditores Independentes

São Paulo, Brazil
June 6, 2011

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CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2010 AND 2009 AND JANUARY 1, 2009
(In thousands of Brazilian reais – R$)

ASSETS	Dec 31,  2010	Dec 31, 2009	Jan 01, 2009
CURRENT ASSETS
Cash and cash equivalents (note 6)	1,562,895	1,487,243	758,454
Consumers, Concessionaires and Licensees (note 7)	1,816,091	1,752,858	1,603,155
Financial Investments (note 8)	42,533	39,253	38,249
Recoverable Taxes (note 9)	193,025	192,278	175,967
Derivatives (note 34)	244	795	36,520
Materials and Supplies	25,234	17,360	23,230
Leases (note 11)	4,754	2,949	1,133
Other credits (note 13)	253,412	156,560	118,397
TOTAL CURRENT ASSETS	3,898,188	3,649,296	2,755,105
NONCURRENT ASSETS
Consumers, Concessionaires and Licensees (note 7)	195,739	224,887	278,330
Escrow Deposits (note 22)	890,684	794,177	749,974
Financial Investments (note 8)	72,822	79,835	96,786
Recoverable Taxes (note 9)	138,969	113,235	105,167
Derivatives (nota 34)	82	7,881	396,875
Deferred Tax Credits (note 10)	1,183,458	1,286,805	1,594,131
Leases (note 11)	26,314	21,243	5,256
Financial asset of concession (note 12)	934,646	674,029	582,241
Private pension fund (note 19)	5,800	9,725	-
Investment at cost	116,654	116,477	116,249
Other Credits (note 13)	222,106	237,029	288,461
Property, Plant and Equipment (note 14)	5,786,466	5,213,039	4,706,537
Intangible assets (note 15)	6,584,877	6,063,101	6,052,144
TOTAL NONCURRENT ASSETS	16,158,617	14,841,463	14,972,151
TOTAL ASSETS	20,056,805	18,490,759	17,727,256

The accompanying notes are an integral part of these consolidated financial statements.                  

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CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2010 AND 2009 AND JANUARY 1, 2009
 (In thousands of Brazilian reais – R$)

LIABILITIES AND SHAREHOLDERS’ EQUITY	Dec 31,  2010	Dec 31, 2009	Jan 01, 2009
CURRENT LIABILITIES
Suppliers (note 16)	1,047,392	1,021,452	985,904
Accrued Interest on Debts (note 17)	40,519	27,662	30,018
Accrued Interest on Debentures (note 18)	118,066	101,284	102,113
Loans and Financing (note 17)	578,867	728,914	556,205
Debentures (note 18)	1,509,960	499,025	580,076
Private pension fund (note 19)	40,103	44,484	45,257
Regulatory charges (note 20)	123,542	63,750	94,530
Taxes and Social Contributions Payable (note 21)	455,243	498,610	456,672
Dividends and Interest on Equity	23,815	25,284	17,512
Accrued liabilities	58,688	50,898	46,384
Derivatives (note 35)	3,981	7,012	53,443
Charge for the use of public utilities (note 23)	17,287	15,697	15,228
Other accounts payable (note 24)	410,861	338,861	279,688
TOTAL CURRENT LIABILITIES	4,428,324	3,422,933	3,263,030
NONCURRENT LIABILITIES
Suppliers (note 16)	-	42,655	85,311
Accrued Interest on Debts (note 17)	29,144	62,427	74,104
Loans and Financing (note 17)	4,917,853	3,729,042	4,086,139
Debentures (note 18)	2,212,314	2,751,169	2,026,890
Private pension fund (note 19)	570,878	723,286	801,964
Taxes and Social Contributions Payable (note 21)	959	1,639	2,243
Deferred tax debits (note 10)	277,767	282,010	274,842
Reserve for contingencies (note 22)	291,266	300,644	382,527
Derivatives (note 34)	7,883	5,694	961
Charge for the use of public utilities (note 23)	429,631	405,837	408,887
Other accounts payable (note 24)	141,130	226,644	269,512
TOTAL NONCURRENT LIABILITIES	8,878,825	8,531,047	8,413,380
SHAREHOLDERS’ EQUITY (note 25)
Capital	4,793,424	4,741,175	4,741,175
Capital Reserves	16	16	16
Profit Reserves	418,665	341,751	277,428
Additional dividend proposed	486,040	655,017	606,105
Revaluation Reserve	795,563	765,667	799,870
Retained earnings	-	(234,278)	(631,911)
	6,493,708	6,269,348	5,792,683
Net equity attributable to noncontrolling shareholders	255,948	267,431	258,163
TOTAL SHAREHOLDERS' EQUITY	6,749,656	6,536,779	6,050,846
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	20,056,805	18,490,759	17,727,256

The accompanying notes are an integral part of these consolidated financial statements.

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CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS
ENDED DECEMBER 31, 2010 and 2009
(In thousands of Brazilian reais – R$, except for share and per share amounts)

	2010	2009
NET OPERATING REVENUE (note 27)	12,023,729	11,358,006
COST OF ELECTRIC ENERGY SERVICES
Cost of Electric Energy  (note 28)	(6,222,490)	(6,014,509)
Operating Cost (note 29)	(1,067,493)	(1,053,938)
Services Rendered to Third Parties (note 29)	(1,050,980)	(620,944)
GROSS OPERATING INCOME	3,682,766	3,668,615
Operating expenses (note 29)
Sales expenses	(300,435)	(255,199)
General and Administrative expenses	(443,212)	(403,390)
Other Operating Expense	(199,804)	(227,343)
	(943,451)	(885,932)
INCOME FROM ELECTRIC ENERGY SERVICE	2,739,315	2,782,683
FINANCIAL INCOME (EXPENSE) (note 30)
Income	483,115	351,360
Expense	(837,058)	(661,066)
	(353,943)	(309,706)
INCOME BEFORE TAXES	2,385,372	2,472,977
Social contribution (note 10)	(221,235)	(208,348)
Income tax (note 10)	(604,100)	(575,761)
	(825,335)	(784,109)
NET INCOME	1,560,037	1,688,868
Net income attributable to controlling shareholders	1,538,281	1,657,297
Net income attributable to noncontrolling shareholders	21,756	31,571
WEIGHTED AVERAGE NUMBER OF SHARES	480,747,436	479,910,938
EARNINGS PER SHARE	3.20	3.45

The accompanying notes are an integral part of these consolidated financial statements.

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CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

(In thousands of Brazilian reais – R$, except for share)

					Other Comprehensive Income
	Capital	Capital Reserve	Legal Reserve	Additional Dividend Proposed	Deemed, cost	Financial instruments	Retained earnings	Total	Noncontrolling Shareholders’ interest	Total Shareholders’ equity
Balance at January 1, 2009	4,741,175	16	277,428	606,105	661,975	137,895	(631,911)	5,792,683	258,163	6,050,846
Net income for the period							1,657,297	1,657,297	31,571	1,688,868
Prescribed dividend							4,541	4,541		4,541
Additional dividend aproved				(606,105)				(606,105)	(14,244)	(620,349)
Changes in Other Other Comprehensive Income:
- Gain (Loss) in financial instruments						(11,208)		(11,208)	(174)	(11,382)
- Tax on financial instruments						3,811		3,811	59	3,870
- Realization of financial instruments						(702)	702
- Realization of deemed cost of fixed assets					(39,552)		39,552
- Tax on deemed cost realization					13,448		(13,448)
Allocation of income
-Statutory reserve			64,323				(64,323)
- Interim dividend							(571,671)	(571,671)	(6,767)	(578,438)
- Dividend proposed				655,017			(655,017)
Other changes in noncontrolling shareholders							-	-	(1,177)	(1,177)
Balance at December 31, 2009	4,741,175	16	341,751	655,017	635,871	129,796	(234,278)	6,269,348	267,431	6,536,779
Capital Increase	52,249							52,249		52,249
Net income for the period							1,538,281	1,538,281	21,756	1,560,037
Prescribed dividend							6,406	6,406		6,406
Additional dividend aproved				(655,017)				(655,017)	(10,967)	(665,984)
Changes in Other Other Comprehensive Income:
- Gain (Loss) in financial instruments						86,167		86,167	(3,531)	82,636
- Tax on financial instruments						(29,297)		(29,297)	1,201	(28,096)

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- Realization of financial instruments						(835)	835
- Realization of deemed cost of fixed assets					(39,605)		39,605
- Tax on deemed cost realization					13,466		(13,466)
Allocation of income
-Statutory reserve			76,914				(76,914)
- Interim dividend							(774,429)	(774,429)	(6,181)	(780,610)
- Dividend proposed				486,040			(486,040)
Other changes in noncontrolling shareholders									(13,761)	(13,761)
Balance at December 31, 2010	4,793,424	16	418,665	486,040	609,732	185,831	-	6,493,708	255,948	6,749,656

The accompanying notes are an integral part of these consolidated financial statements.

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CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

(In thousands of Brazilian reais – R$)

	2010		2009
OPERATING CASH FLOW
Income (Loss) for the period, before income tax and social contribution	2,385,372		2,472,977
ADJUSTMENT TO RECONCILE INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES
Depreciation and amortization	691,793		673,073
Reserve for contingencies	(29,598)		(13,623)
Interest and monetary restatement	613,946		572,470
Pension plan costs	(80,629)		(3,066)
Equity in subsidiaries	-		-
Losses on the write-off of noncurrent assets	1,142		(686)
Deferred taxes (PIS and COFINS)	2,153	��	75,649
Other	536		-
REDUCTION (INCREASE) IN OPERATING ASSETS
Consumers, concessionaires and licensees	(34,085)		(96,260)
Dividend and interest on equity received	-		-
Recoverable taxes	3,146		9,265
Lease	(2,945)		(2,276)
Escrow deposits	(52,109)		948
Intercompany loans with subsidiaries and associated companies	-		-
Other operating assets	(78,202)		1,165
INCREASE (DECREASE) IN OPERATING LIABILITIES
Suppliers	(16,714)		(7,853)
Taxes and social contributions paid	(705,366)		(524,248)
Other taxes and social contributions	(88,996)		47,212
Other liabilities with employee pension plans	(72,235)		(86,110)
Interest on debts – paid	(573,170)		(546,705)
Regulatory charges	59,792		(30,780)
Other operating liabilities	5,382		(101,891)
CASH FLOWS PROVIDED (USED) BY OPERATIONS	2,029,213		2,439,361
INVESTMENT ACTIVITIES
Increase in investments on subsidiaries	(5,752)		(31,922)
Acquisition of property, plant and equipment	(634,931)		(549,045)
Financial investments	17,777		65,527
Energy purchase in advance	(10,077)		(29,972)
Additions to intangible assets	(1,165,609)		(679,054)
Lease	(3,931)		(15,527)
Sale of noncurrent assets	828		1,092
Other	(192)		-
GENERATION (UTILIZATION) OF CASH IN INVESTMENTS	(1,801,887)		(1,238,901)

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CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

(In thousands of Brazilian reais – R$)

FINANCING ACTIVITIES
Loans, financing and debentures obtained	2,571,002	2,552,433
Payments of Loans, financing and debentures, and derivatives	(1,280,290)	(1,843,792)
Dividend and interest on equity paid	(1,440,094)	(1,178,365)
Sale of treasury stocks	137	-
Other	(2,429)	(1,847)
GENERATION (UTILIZATION) OF CASH IN FINANCING	(151,674)	(471,571)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	75,652	728,789
OPENING BALANCE OF CASH AND CASH EQUIVALENTS	1,487,243	758,454
CLOSING BALANCE OF CASH AND CASH EQUIVALENTS	1,562,895	1,487,243

The accompanying notes are an integral part of these consolidated financial statements

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CPFL ENERGIA S.A. AND SUBSIDIARIES

STATEMENT OF COMPREHENSIVE INCOME FOR THE PERIOD ENDED IN DECEMBER 31, 2010 AND 2009

 (In thousands of Brazilian reais – R$)

	2010	2009
NET INCOME	1,560,037	1,688,868
Other comprehensive income
- Gain / (Loss) in financial instruments	86,167	(11,208)
- Realization of financial instruments	(835)	(702)
- Tax on financial instruments	(29,297)	3,811
Comprehensive income  for the year	1,616,072	1,680,769

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CPFL ENERGIA S.A.

NOTES TO THE FINANCIAL STATEMENTS

FOR THE YEARS ENDED ON DECEMBER 31, 2010 AND 2009

(Amounts stated in thousands of Brazilian reais, except where otherwise indicated)

( 1 ) OPERATIONS  

CPFL Energia S.A. (“CPFL Energia” or “Company”) is a publicly quoted corporation incorporated for the principal purpose of acting as a holding company, participating in the capital of other companies primarily dedicated to electric energy distribution, generation and sales activities in Brazil.

The Company’s headquarters are located at Rua Gomes de Carvalho, 1510 - 14º floor - Cj 2 - Vila Olímpia - São Paulo - SP - Brasil.

The Company has direct and indirect interests in the following operational subsidiaries (information on the concession area, number of consumers, energy production capacity and associated data not examined by the independent auditors):

Energy distribution	Company Type	Equity Interest	Location (State)	Number of municipalities	Approximate number of consumers (in thousands)	Concession term	End of the concession
Companhia Paulista de Força e Luz ("CPFL Paulista")	Publicly-quoted corporation	Direct 100%	Interior of S. Paulo	234	3,661	30 years	November 2027
Companhia Piratininga de Força e Luz ("CPFL Piratininga")	Publicly-quoted corporation	Direct 100%	Interior of S. Paulo	27	1,439	30 years	October 2028
Rio Grande Energia S.A. ("RGE")	Publicly-quoted corporation	Direct 100%	Interior of Rio Grande do Sul	262	1,272	30 years	November 2027
Companhia Luz e Força Santa Cruz ("CPFL Santa Cruz")	Private corporation	Direct 100%	Interior of São Paulo and Paraná	27	180	16 years	July 2015
Companhia Leste Paulista de Energia ("CPFL Leste Paulista")	Private corporation	Direct 100%	Interior of S. Paulo	7	51	16 years	July 2015
Companhia Jaguari de Energia ("CPFL Jaguari")	Private corporation	Direct 100%	Interior of S. Paulo	2	33	16 years	July 2015
Companhia Sul Paulista de Energia ("CPFL Sul Paulista")	Private corporation	Direct 100%	Interior of S. Paulo	5	72	16 years	July 2015
Companhia Luz e Força de Mococa ("CPFL Mococa")	Private corporation	Direct 100%	Interior of São Paulo and Minas Gerais	4	41	16 years	July 2015

					Installed power
Energy generation - operational	Company Type	Equity Interest	Location (State)	Number of plants / type of energy	Total	CPFL participation
CPFL Geração de Energia S.A. ("CPFL Geração")	Publicly-quoted corporation	Direct 100%	São Paulo,  Goiás and Minas Gerais	1 Hydroelectric, 20 PCHs e 1 Thermal*	812 MW	812 MW
Foz do Chapecó Energia S.A. ("Foz do Chapecó")	Private corporation	Indirect 51%	Santa Catarina and Rio Grande do Sul	1 Hydroelectric	855 MW	436 MW
Campos Novos Energia S.A. ("ENERCAN")	Private corporation	Indirect 48,72%	Santa Catarina	1 Hydroelectric	880 MW	429 MW
CERAN - Companhia Energética Rio das Antas ("CERAN")	Private corporation	Indirect 65%	Rio Grande do Sul	3 Hydroelectric	360 MW	234 MW
BAESA - Energética Barra Grande S.A. ("BAESA")	Publicly-quoted corporation	Indirect 25,01%	Santa Catarina and Rio Grande do Sul	1 Hydroelectric	690 MW	173 MW
Centrais Elétricas da Paraíba S.A. ("EPASA")	Private corporation	Indirect 51%	Paraíba	2 Thermals	342 MW	174 MW
Paulista Lajeado Energia S.A. ("Paulista Lajeado")	Private corporation	Indirect 59,93%**	São Paulo	1 Hydroelectric	903 MW	63 MW
CPFL Bioenergia S.A. ("CPFL Bioenergia")	Private corporation	Indirect 100%	São Paulo	1 Thermal (Biomass)	45 MW	45 MW
CPFL Sul Centrais Elétricas Ltda. ("CPFL Sul Centrais Elétricas")	Limited company	Indirect 100%	Rio Grande do Sul	4  Small Hydroelectric Plants (RS)	2,65 MW	2,65 MW
(*) PCH - Small Hydropower Plant Central Hidrelétrica
(**) Paulista Lajeado has a 7% participation in the installed power of Investco S.A.

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Energy generation - under development	Company Type	Equity Interest	Location	Number of plants / type of energy	Scheduled start-up date	Projected installed power
CPFL Bio Formosa S.A. ("CPFL Bio Formosa")	Private corporation	Indirect 100%	Rio Grande do Norte	1 Thermal (Biomass)	2011	40 MW
CPFL Bio Buriti S.A. ("CPFL Bio Buriti")	Private corporation	Indirect 100%	São Paulo	1 Thermal (Biomass)	2011	50 MW
CPFL Bio Ipê S.A. ("CPFL Bio Ipê")	Private corporation	Indirect 100%	São Paulo	1 Thermal (Biomass)	2011	25 MW
CPFL Bio Pedra S.A. ("CPFL Bio Pedra")	Private corporation	Indirect 100%	São Paulo	1 Thermal (Biomass)	2012	70 MW
Santa Clara I Energias Renováveis Ltda. ("Santa Clara I")	Limited Company	Indirect 100%	Rio Grande do Norte	1 Wind power	2012	30 MW
Santa Clara II Energias Renováveis Ltda. ("Santa Clara II")	Limited Company	Indirect 100%	Rio Grande do Norte	1 Wind power	2012	30 MW
Santa Clara III Energias Renováveis Ltda. ("Santa Clara III")	Limited Company	Indirect 100%	Rio Grande do Norte	1 Wind power	2012	30 MW
Santa Clara IV Energias Renováveis Ltda. ("Santa Clara IV")	Limited Company	Indirect 100%	Rio Grande do Norte	1 Wind power	2012	30 MW
Santa Clara V Energias Renováveis Ltda. ("Santa Clara V")	Limited Company	Indirect 100%	Rio Grande do Norte	1 Wind power	2012	30 MW
Santa Clara VI Energias Renováveis Ltda. ("Santa Clara VI")	Limited Company	Indirect 100%	Rio Grande do Norte	1 Wind power	2012	30 MW
Eurus VI Energias Renováveis Ltda. ("Eurus VI")	Limited Company	Indirect 100%	Rio Grande do Norte	1 Wind power	2012	30 MW
Campo dos Ventos I Energias Renovaveis S.A. ("Campo dos Ventos I")	Private corporation	Indirect 100%	Rio Grande do Norte	1 Wind power	2013	30 MW
Campo dos Ventos II Energias Renovaveis S.A. ("Campo dos Ventos II")	Private corporation	Indirect 100%	Rio Grande do Norte	1 Wind power	2013	30 MW
Campo dos Ventos III Energias Renovaveis S.A. ("Campo dos Ventos III")	Private corporation	Indirect 100%	Rio Grande do Norte	1 Wind power	2013	30 MW
Campo dos Ventos IV Energias Renovaveis S.A. ("Campo dos Ventos IV")	Private corporation	Indirect 100%	Rio Grande do Norte	1 Wind power	2013	30 MW
Campo dos Ventos V Energias Renovaveis S.A. ("Campo dos Ventos V")	Private corporation	Indirect 100%	Rio Grande do Norte	1 Wind power	2013	30 MW
Eurus V Energias Renovaveis S.A. ("Eurus V")	Private corporation	Indirect 100%	Rio Grande do Norte	1 Wind power	2013	30 MW
(*) The predicted installed power for the Santa Clara Wind Power complex is 188 MW.
(**) The projected installed power for the Campo dos Ventos Wind Power complex is 160 MW.

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Commercialization of Energy and Services	Company Type	Core activity	Equity Interest
CPFL Comercialização Brasil S.A. ("CPFL Brasil")	Private corporation	Energy commercialization, consultancy and advisory services to agents in the energy sector	Direct 100%
Clion Assessoria e Comercialização de Energia Elétrica Ltda. ("CPFL Meridional")	Limited company	Commercialization and provision of energy services	Indirect 100%
CPFL Comercialização Cone Sul S.A. ("CPFL Cone Sul")	Private corporation	Energy commercialization	Indirect 100%
CPFL Planalto Ltda.  ("CPFL Planalto")	Limited company	Energy commercialization	Direct 100%
CPFL Serviços, Equipamentos, Industria e Comércio S.A. ("CPFL Serviços")	Private corporation	Manufacturing, commercialization, rental and maintenance of electro-mechanical equipment and service provision	Direct 100%
Chumpitaz Serviços S.A. ("Chumpitaz")	Private corporation	Provision of administrative services	Direct 100%
CPFL Atende Centro de Contatos e Atendimento Ltda.  ("CPFL Atende")	Limited company	Provision of telephone answering services	Direct 100%
Other	Company Type	Core activity	Equity Interest
CPFL Jaguariuna S.A.  ("CPFL Jaguariuna")	Private corporation	Venture capital company	Direct 100%
Companhia Jaguari de Geração de Energia  ("Jaguari Geração")	Private corporation	Venture capital company	Direct 100%
Chapecoense Geração S.A. ("Chapecoense")	Private corporation	Venture capital company	Indirect  51%
CPFL Bio Anicuns S.A. ("Anicuns")	Private corporation	Energy generation studies and projects	Indirect 100%
CPFL Bio Itapaci S.A ("Itapaci")	Private corporation	Energy generation studies and projects	Indirect 100%
Sul Geradora Participações S.A. ("Sul Geradora")	Private corporation	Venture capital company	Indirect 99.95%

Subsidiaries that started its operations in 2010

CPFL Bioenergia S.A.

The main objective of CPFL Bioenergia S.A., which started operations on August 27, 2010, is the thermal and steamgeneration of electric energy using co-generation plants powered by sugarcane waste and straw.

Centrais Elétricas da Paraíba S.A.

The objective of Epasa is to develop, implement, operate and exploit two thermoelectric plants, “UTE Termoparaíba” and “UTE Termonordeste”, both powered by fuel oil. UTE Termonordeste started its operations on December 24, 2010 and UTE Termoparaíba on January 13, 2011.

Chapecoense Geração S.A.

The objective of the jointly-controlled subsidiary Chapecoense Geração is to build, operate and exploit the Foz do Chapecó Hydropower Plant. Three (3) generator units, with installed power of 213.75 MW each, started operations in 2010, on October 14, November 23 and December 30.  The last generator unit is scheduled to start operations by the end of the first quarter of 2011.

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( 2 ) PRESENTATION OF THE FINANCIAL STATEMENTS

2.1 Basis of preparation

The consolidated financial statements were prepared and are presented in full conformity with the International Financial Reporting Standards – IFRS. These are the first consolidated statements prepared in accordance with this international practice.

Note 5 shows the main differences between the accounting practices adopted previously in Brazil and the current and effective standards presented herein.

The consolidated financial statements were authorized for issue by the Board of Directors on June6, 2011.

2.2 Basis of measurement

The financial statements have been prepared on the historic cost basis except for the following material items recorded in the balance sheets: i) derivative financial instruments measured at fair value, ii) financial instruments at fair value through profit or loss, iii) available-for-sale financial assets  measured at fair value, iv) property, plant and equipment adjusted to reflect the “deemed cost” on the transition date, and v) actuarial assets, recognition of which is limited to the present value of the economic benefits available in the form of reimbursements or future reductions in contributions to the plan.

2.3 Use of estimates and judgments

The preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses.

By definition, the resulting accounting estimates are rarely the same as the actual results. Accordingly, Company Management reviews the estimates and assumptions on an ongoing basis. Adjustments derived from revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. 

Information about assumptions and estimate that are subject to a greater degree of uncertainty and involve the risk of resulting in a material adjustment if these assumptions and estimates suffer significant changes during the next financial year is included in the following notes:

·Note 10 – Deferred tax credits and debits;

·Note 12 – Financial asset of concession;

·Note 15 – Intangible assets;

·Note 19 – Private Pension Fund;

·Note 22 – Provision for contingency, and

·Note 34 – Financial instruments.

2.4 Functional currency and presentation currency

The consolidated financial statements are presented in thousands of Brazilian reais, which is the Company's functional currency.

2.5 Basis of consolidation:

(i) Business combinations

- Acquisitions made after January 1, 2009

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In the case of acquisitions made after January 1, 2009, the Company measures goodwill as the fair value of the consideration transferred including the recognized amount of any non-controlling interest in the acquiree, less the net recognized amount (generally fair value) of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date. If the excess is negative, a gain arising from the purchase agreement is recognized immediately in profit or loss for the period.

- Acquisitions prior to January 1, 2009

As part of the transition to the IFRS, the Company opted not to re-present business combinations prior to January 1, 2009. In relation to acquisitions prior to January 1, 2009 the goodwill represents the amount recognized under the accounting practices adopted previously. This goodwill was tested for impairment at the transition date, in accordance with Note 3.6.

(ii) Subsidiaries and jointly-owned entities:

The financial statements of subsidiaries and jointly-owned entities (joint ventures) are included in the consolidated financial statements from the date that total or shared control commences until the date that control ceases.

A jointly controlled operation is a venture directly or indirectly controlled together with other investors, established by contractual agreement and requiring unanimous consent for strategic financial and operating decisions. 

The accounting policies of subsidiaries and jointly controlled entities taken into consideration in consolidation are aligned with the Company's accounting policies.

The financial information of subsidiaries and jointly controlled entities and of the associates is accounted for using the equity method.

Intra-group balances and transactions, and any income and expenses derived from these transactions, are eliminated in preparing the consolidated financial statements.  Unrealized gains arising from transactions with equity accounted investees are eliminated against the investment to the extent of the Group's interest in the investee. Unrealized losses are eliminated in the same way as unrealized gains, but only to the extent that there is no evidence of impairment.

Observing the conditions described above, the amount related to non-controlling interests is shown in shareholders' equity after the statement of income for the year in each year presented.

(iii) Acquisition of non-controlling interest

Accounted for as transactions within equity holders and therefore no goodwill is recognized as a result of such transactions.

2.6 Segment information:

An operating segment is a component of the Company (i) that engages in operating activities from which it may earn revenues and incur expenses, (ii) whose operating results are regularly reviewed by Management to make decisions about resources to be allocated and assess the segment's performance, and (iii) for which discrete financial information is available.

Company Management bases strategic decisions on reports, segmenting the business into: (i) electric energy distribution activities (“Distribution”); (ii) electric energy generation activities (“Generation”); (iii) energy commercialization and service provision activities (“Commercialization”); and (iv) other, basically corresponding to corporate services and other activities not listed in the previous items.

Presentation of the operating segments includes items directly attributable to them, such as allocations required, including intangible assets.  

2.7 Information on Corporate Interests

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The interests directly or indirectly held by the Company in the subsidiaries and jointly-owned entities are described in Note 1. Except for the (i) jointly-owned entities ENERCAN, BAESA, Foz do Chapecó and EPASA, which are consolidated proportionately, and (ii) the investment in Investco recorded at cost by the subsidiary Paulista Lajeado, the other units are fully consolidated.

As of December 31, 2010, the participation of non-controlling interests stated in the consolidated statements refers to the third-party interests in the subsidiaries CERAN and Paulista Lajeado.

2.8 Value added statements:

The Company prepared consolidated value added statements (“DVA”)  as additional financial information.

( 3 ) SUMMARY OF THE SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements.

3.1 Concession agreements:

IFRIC 12 “Concession Agreements” establishes general guidelines for the recognition and measurement of obligations and rights related to concession agreements and applies to situations in which the granting power controls or regulates which services the concessionaire should provide with the infrastructure, to whom the services should be provided and at what price, and controls any significant residual interest in the infrastructure at the end of the concession period.

These definitions having been attended to, the infrastructure of distribution concessionaires is segregated and rollforwarded from the time of construction, complying with the provisions of the IFRSs, so that the financial statements record (i) an intangible asset corresponding to the right to operate the concession and collect from the users of public utilities, and (ii) a financial asset corresponding to the unconditional contractual right to receive cash (compensation) by reversing the assets at the end of the concession.

The value of the concession financial assets is determined at fair value, based on the remuneration of the assets established by the regulatory authority. The financial asset is classified as available-for-sale and is restated and amortized annually in accordance with the adjustment of its fair value, against the revaluation reserve in equity.

The remaining amount is registered in intangible assets and corresponds to the right to charge consumers for electric energy distribution services, amortized in accordance with the consumption pattern that reflects the estimated economic benefit to the end of the concession.

Provision of infrastructure construction services is registered in accordance with IAS 11 – Construction Contracts, against a financial asset corresponding to the amount subject to compensation. Residual amounts are classified as intangible assets and will be amortized over the concession period in accordance with the economic pattern against which the revenue from consumption of electric energy is collected.

Because (i) the tariff model that does not provide for a profit margin for the infrastructure construction activity, (ii) the way in which the subsidiaries manage the building by using a high level of outsourcing, and (iii) there is no provision for gains on construction in the Company‘s business plans, management is of the opinion that the margins on this operation are irrelevant, and therefore no additional value to the cost is considered in the composition of the revenue. The revenue and construction costs are therefore presented in profit or loss for the year at the same amounts.

3.2 Financial instruments:

- Financial assets:

Financial assets are recognized initially on the date that they are originated or on trade date at which the Company or its subsidiaries become one of the parties to the contractual provisions of the instrument. Derecognition of a financial asset occurs when the contractual rights to the cash flows from the asset expire orwhen the risks and rewards of ownership of the financial asset are transferred. The Company and its subsidiaries hold the following main financial assets:

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i.Classified at fair value through profit or loss: these assets held for trading or designated as such upon initial recognition. The Company and its subsidiaries manage such assets and make purchase and sale decisions based on their fair value in accordance with their documented risk management or investment strategy. These financial assets are measured at fair value, and changes therein are recognized in profit or loss for the year.

The main financial assets classified by the Company and its subsidiaries in this category are: (i) bank balances and financial investments (Note 6), (ii) marketable securities (Note 8) and (iii) derivatives (Note 34.d).

ii.Held-to-maturity: these are assets that the Company and its subsidiaries have the positive intent and ability to hold to maturity. Held-to-maturity financial assets are recognized initially at fair value and subsequent to initial recognition are measured at recognized cost using the effective interest method, less any impairment losses.

The Company and its subsidiaries classify the following financial assets in this category: (i) security receivable from CESP (Note 8) and (ii) receivables of the subsidiary CPFL Paulista from CESP (Note 13).

iii.Loans and receivables: these are assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value and, subsequent to initial recognition, measured at recognized cost using the effective interest method, less any impairment losses.

The main financial assets of the Company and its subsidiaries classified in this category are: (i) consumers, concessionaires and licensees (Note 7),(ii) dividends and Interest on shareholders’ equity  and (iii) other credits (Note 13).

iv.Available-for-sale: these are non-derivative financial assets that are designated as available-for-sale or that are not classified in any of the previous categories. Subsequent to initial recognition, interest calculated by the effective rate method is recognized in profit or loss as part of the net operating income. Changes for registration at fair value are recognized in the revaluation reserve in equity. The accumulated result in other comprehensive income is transferred to profit or loss when the asset is realized.

The main asset of the Company and its subsidiaries classified in this category is the right to compensation at the end of the concession. The option to designate this instrument as available-for-sale is due to its non-classification in the previous categories described. Since Management believes that the compensation will be made at least in accordance with the current tariff pricing model, this instrument cannot be registered as loans and receivables as the compensation will not be fixed or determinable, due to the uncertainty in relation to impairment for reasons other than deterioration of the credit. The main uncertainties relate to the risk of non-recognition of part of these assets by the regulatory authority and their replacement values at the end of the concession (Note 4).

- Financial liabilities:

Financial liabilities are initially recognized on the date that they are originated or on the trade date at which the Company or its subsidiaries become a party to the contractual provisions of the instrument. The Company and its subsidiaries have the following main financial liabilities:

i.Measured at fair value through profit or loss: these are financial liabilities that are: (i) held for short-term trading, (ii) designated at fair value in order to evaluate the effects of recognition of income and expenses to obtain more relevant and consistent accounting information, or (iii) derivatives. These liabilities are registered at fair value and for any change in the subsequent measurement of the fair value, set through profit or loss.

The Company and its subsidiaries classified the following financial liabilities in this category: (i) certain foreign currency debts (Note 17) and (ii) derivatives (Note 34.d).

ii.Not measured at fair value through profit or loss: these other financial liabilities that are not classified in any of the previous categories. They are measured initially at fair value less any attributable transaction cost and subsequently measured at recognized cost by the effective interest method.

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The main financial liabilities classified in this category are: (i) suppliers (Note 16), (ii) loans and financing (Note 17), (iii) debt charges (Note 17); (iv) debenture charges (Note 18); (v) debentures (Note 18); (vi) charge for the use of public utilities (Note 23);  and (vii) other accounts payable (Note 24).

The Company accounts for warranties when these are issued to non-controlled entities or when the warranty is granted higher than the Company's proportionate interest. Such warranties are initially measured at fair value, by (i) a liability equivalent to the receipts to be appropriated, which will subsequently be recognized as the Company is released from the obligations and (ii) an asset equivalent to the right to compensation by the guaranteed party, subsequently amortized by receipt of cash or on a straight-line basis to profit or loss.

Financial assets and liabilities are offset and the net amount presented when, and only when, there is a legal right to offset the amounts and the intent to settle on a net basis or to realize the asset and settle the liability simultaneously.

- Capital

Common shares are classified as equity. Additional costs directly attributable to and share options are recognized as a deduction from equity, net of any tax effects.

3.3 Lease agreements:

It should be established at the inception of an agreement whether such arrangement is or contains a lease. A specific asset is the subject of a lease if fulfillment of the arrangement is dependent on the use of that specified asset. An arrangement conveys the right to use the asset if the arrangement conveys to the lessor the right to control the use of the underlying asset.

Leases in which substantially all the risks and rewards are with thelessor are classified as operating leases. Payments/receipts made under operating leases are recognized as expense/revenue in profit or loss on a straight-line basis, over the term of the lease.

Leases which involve not only the right to use assets, but also substantially transfer the risks and rewards to the lessee, are classified as finance leases.

In finance leases in which the Company or its subsidiaries act as lessee, the assets are capitalized to property, plant and equipment at the inception of the agreement against a liability measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. The property, plant and equipment is depreciated in accordance with the accounting policy applicable to that asset.

If the Company or its subsidiaries are the lessor in a finance lease, the investment is initially recognized at the construction/acquisition cost of the asset.

In both cases, the financial income/expense is recognized in profit or loss for the year over the term of the lease so as to produce a constant rate of interest on the remaining balance of the investment/liability.

3.4 Property, plant and equipment: 

Items of property, plant and equipment are measured at acquisition, construction or formation cost less accumulated depreciation and, if applicable, accumulated impairment losses. Cost also includes any other costs attributable to bringing the assets to the place and in a condition to operate as intended by management, the cost of dismantling and removing the items and restoring the site on which they are located and capitalized borrowing costs on qualifying assets.

The assets were measured at the transition date in accordance with the IFRS rules by segregation into two groups:

- Assets measured at deemed cost at the transition date: model adopted for assets built and put into long-term service when it is not possible to reconstruct the cost formation or where the cost of the survey is of no benefit in presentation of the financial statements. The cost of these items at the transition date was therefore determined in accordance with market prices (“deemed cost”) and the revalued amounts are presented for both cost andaccumulated depreciation. The effects of the deemed cost increased property, plant and equipment against equity, net of related tax effects.

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- Assets measured at historic cost: model adopted by the Company for recently built assets where the basis for cost formation can be easily confirmed and the values at historic cost approximate the respective market values. In such cases, the subsidiaries performed an analysis to ensure that the cost formation is in accordance with current accounting practices.

The replacement cost of items of property, plant and equipment is recognized if it is probable that it will involve economic rewards for the subsidiaries and if the cost can be reliably measured, and the value of the replaced item is written off. Maintenance costs are recognized in profit or loss as they are incurred.

Depreciation is calculated on a straight-line basis, at annual rates of 2% to 20%, taking into consideration the estimated useful life of the assets, as instructed and defined by the regulatory authority. In the case of generators subject to regulation by Decree 2003, of 1996, the assets are depreciated at the rates established by the regulatory authority, provided they do not exceed the term of the concession.

Gains and losses derived from disposal of an item of property, plant and equipment are determined by comparing the resources produced by disposal with carrying amount of the asset, and are recognized net together with other operating income/expense.

Assets and facilities used in the regulated activities are tied to these services and may not be removed, disposed of, assigned or pledged in mortgage without the prior and express authorization of ANEEL. ANEEL regulates the release of Public Electric Energy Utility concession assets, granting prior authorization for release of assets of no use to the concession, intended for disposal and determines that the proceeds of the disposal be deposited in a tied bank account for use in theconcession. 

3.5 Intangible assets: 

Includes rights related to non-physical assets such as goodwill, concession exploration rights, software and rights-of-way.

Goodwill that arises the acquisition of subsidiaries is measured at the difference between the amount paid and/or payable for acquisition of a business and the net fair value of the assets and liabilities of the subsidiary acquired.

Goodwill is measured at cost less accumulated impairment losses. Goodwill and other intangible assets with indefinite useful lives are not subject to amortization and tested annually for impairment.

Negative goodwill are registered as gains in profit or loss at the time of the acquisition.

Goodwill is included in the carrying amount of the investment, and stated as intangible in the consolidated financial statements.

Intangible assets corresponding to the right to operate concessions can have three separate origins, based on the following arguments:

i.Acquisitions through business combinations: the portion of goodwill arising from business combinations that corresponded to the right to operate the concession is stated as an intangible asset. Such amounts are amortized based on the net income curves projected for the concessionaires for the remaining term of the concession.

ii.Investments in infrastructure (Application of IFRIC 12 – Concession agreements): Under the electric energy distribution concession agreements with the subsidiaries, the intangible asset registered corresponds to the concessionaires' right to collection uses for use of the concession infrastructure. Since the exploration term is defined in the agreement, intangible assets with defined useful lives are amortized over the term of the concession in proportion to a curve that reflects the consumption pattern in relation to the anticipated economic rewards. For further information see Note 3.1.

iii.Charge for the use of public utilities: certain generation concessions were granted against payment to the federal government for use of a public utility. This obligation was registered on the date of signing the respective agreements, at present value, against the intangible assets account. These amounts, capitalizedby interest incurred on the obligation to the start-update, are amortized on a straight-line basis over the remaining term of the concession. 

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3.6 Impairment

- Financial assets:

A financial asset not measured at fair value through profit or loss is reassessed at each reporting date to determine whether there is objective evidence that it is impaired.  Impairment can occur after the initial recognition of the asset and have a negative effect on the estimated future cash flows.

The Company and its subsidiaries consider evidence of impairment of receivables and held-to-maturity investment securities at both a specific assets and collective level for all significant securities. Receivables and held-to-maturity investment securities that are not individually significant are collectively assessed for impairment by grouping together the securities with similar risk characteristics.

In assessing collective impairment the Company uses historical trends of the probability of default, timing of recoveries and the amount of loss incurred, adjusted for management's judgment as to whether the assumptions and current economic and credit conditions are such that the actual losses are likely to be greater or less than suggested by historic trends.

An impairment loss of a financial asset is recognized as follows:

·Amortized cost: as the difference between the carrying amount and the present value of the estimated future cash flows discounted at the assets original effective interest rate. Losses are recognized in profit or loss and reflected in an allowance account against receivables. Interest on the impaired asset continues to be recognized through the unwinding of the discount. When a subsequent event indicates the amount of impairment loss to decrease, the decrease in impairment loss is reversed through profit or loss.

·Available-for-sale: by reclassification of the cumulative loss that has been recognized in the revaluation reserve in equity, to profit or loss. This reclassified loss is the difference between the acquisition cost, net of any principal repayment and amortization of the principal, and the current fair value, less any impairment loss previously recognized in profit or loss. Changes in impairment provisions attributable to effective interest rate are reflected as a component of financial income.

If an increase (gain) is identified in periods subsequent to recognition of the loss, then the impairment loss is reversed, with the amount of the reversal recognized in profit or loss. However, any subsequent recovery in the fair value of an impaired available-for-sale financial asset is recognized in the revaluation reserve in equity.

- Non-financial assets:

Non-financial assets that have indefinite useful lives, such as goodwill, are tested annually to check that the asset's carrying amount does not exceed the recoverable value. Other assets subject to amortization are tested for impairment whenever events or changes in circumstance indicate that the carrying amount may be impaired.

An impairment loss is recognized if the carrying amount of an asset exceeds its estimated recoverable amount, which is the greater of its value in use or its fair value less costs to sell.

The methods used to assess impairment include tests based on the asset's value in use. In such cases, the assets (e.g. goodwill) are segregated and grouped together at the lowest level that generates identifiable cash flows (the "cash generating unit", or CGU). If there is an indication of impairment, the loss is recognized in profit or loss. Except in the case of goodwill, where the loss cannot be reversed in the subsequent period, impairment losses are assessed annually for any possibility to reverse the impairment.

Goodwill included in the carrying amount of an investment in an associate, as it is not recognized individually, is tested with the investment, as if it were a single asset.

3.7 Provisions

A provision is recognized if, as a result of a past event, there is a legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation.If applicable, provisions are determined by discounting the expected future cash flows at a rate that reflects current market assessment and the risks specific to the liability.

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3.8 Employee benefits

The subsidiaries have post-employment benefits and pension plans, recognized by the accrual method in accordance with IAS 19 “Employee benefits”. Although the plans have particularities, they have the following characteristics:

i.Defined distribution plan: a post-employment benefit plan under which the Company pays fixed contributions into a separate entity and will have no liability for the actuarial deficits of this plan. The obligations are recognized as an expense in profit or loss in the periods during which the services are rendered.

ii.Defined benefit plan: The net obligation is calculated as the difference between the present value of the actuarial obligation based on assumptions, biometric studies and interest rates in line with market rates, and the fair value of the plan assets of the reporting date. The actuarial liability is calculated annually by independent actuaries using the projected unit credit method. The subsidiaries use the corridor method to avoid fluctuations in the macroeconomic conditions distorting the profit or loss for the period. The accumulated differences between the actuarial estimates and the actual results are therefore not recognized in the financial statements unless they are in excess of 10% of the greater of the plan liabilities and assets. Unrecognized gains and losses in excess of this limit are recognized in profit or loss for the year over the estimated remaining service time of the employees. If the plan records a surplus and it becomes necessary to recognize an asset, recognition is limited to the total of any unrecognized past service costs and the present value of economic benefits available in the form of reimbursements or future reductions in contributions to the plan.

3.9 Dividends and Interest on shareholders’ equity

Under Brazilian law, the Company is required to distribute a mandatory minimum annual dividend of 25% of net income adjusted in accordance with the bylaws. To December 31, 2008, dividends in excess of the minimum of 25% had to be proposed and provision at each reporting date, subject to approval in an Annual General Meeting (AGM). According to IAS 10, , a provision may only be made for the minimum mandatory dividend, and dividends declared but not yet approved are only recognized as a liability in the financial statements after approval by the competent body. They will therefore be held in equity, in the “Additional dividend proposed” account, as they do not meet the criteria of present liability at the reporting date.

As established in the Company's bylaws and in accordance with current Corporate law, the Board of Directors is responsible for declaring interim dividends and interest on shareholders’ equity  determined in a half-yearly balance sheet. Interim dividends declared at the base date of June 30 is only recognized as a liability in the Company's financial statement after the date of the Board's decision.

Under previous accounting practices, interest on shareholders’ equity  was recorded in profit or loss and reversed for purposes of presentation of the statement of income for the year. In accordance with the new accounting practice, interest on shareholders’ equity  is no longer shown in the statement of income for the year and the effects are only stated in changes in equity and in the effective income tax and social contribution rates.

3.10 Revenue recognition

Operating income in the course of ordinary activities of the subsidiaries is measured at the fair value of the consideration received or receivable. Operating revenue is recognized when persuasive evidence exists that the most significant risks and rewards have been transferred to the buyer, when it is probable that the financial and economic rewards will flow to the entity, that the associated costs can be reliably estimated, and the amount of the operating income can be reliably measured.

Revenue from distribution of electric energy is recognized when the energy is billed. Unbilled income related to the monthly billing cycle is appropriated based on the actual amount of energy provided in the month and the annualized loss rate. Historically, the difference between the unbilled revenue and the actual consumption, which is recognized in the subsequent month, has not been material. Revenue from energy generation sales isaccounted for based on the assured energy and at tariffs specified in the terms of the contract or the current market price, as applicable. Energy commercialization revenue is accounted for based on bilateral contracts with market agents and duly registered with the Electric Energy Commercialization Chamber - CCEE. No single consumer represents 10% or more of the total billing.

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Service revenue is recognized when the service is effectively provided, under a service agreement between the parties.

Revenue from construction contracts is recognized by the percentage of completion method (“fixed-price”), and losses are recognized in profit or loss as incurred.

3.11 Income tax and Social contribution

Income tax and Social contribution expense for the period is calculated and recognized in accordance with the legislation in force and comprises current and deferred tax. Income tax is recognized in profit or loss except to the extent that it relates to an item recognized directly in equity or in the revaluation reserve in equity, which is recognized net of tax effects.

Current tax is the expected tax payable or receivable/to be offset on the taxable income or loss for the year. Deferred tax is recognized for temporary differences between the carrying amounts of assets and liabilities for accounting purposes and the equivalent amounts used for tax purposes.

The Company and certain subsidiaries recorded in their financial statements the effects of tax loss carryforwards and temporary non-deductible differences, based on projections of future taxable profits, approved by the Boards of Directors and examined by the Fiscal Council. The subsidiaries also recognized tax credits on merged goodwill, which is amortized in proportion to the individual projected net incomes for the remaining term of each concession agreement.

Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity.

Deferred income tax and social contribution assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

3.12 Earnings per share

Basic earnings per share is calculated by dividing the profit or loss attributable to the Company by the weighted average number of common and preferred shares outstanding during the period. Diluted earnings per share is determined by the above-mentioned weighted average number of shares outstanding, adjusted for the effects of all dilutive potential convertible notes for the reporting periods, in accordance with IAS 33.

3.13 Regulatory assets and liabilities

In accordance with the preliminary interpretation of IASB/IFRIC, regulatory assets and liabilities cannot be recognized in the Company's financial statements as they do not meet the requirements for assets and liabilities described in theFramework for the Preparation and Presentation of Financial Statements. The rights or offsetting are therefore only reflected in the financial statements at the time that the requirements for the liabilities and assets are met.

3.14 New standards and interpretations not yet adopted

Certain standards, amendments to the IFRS standards and interpretations issued by the IASB not yet effective for the year ended December 31, 2010, are listed below:

• Limited exemption from Comparative IFRS 7 Disclosures for First-time Adopters.

• Improvements to IFRS 2010;

• IFRS 9 Financial Instruments;

• Prepayment of a minimum fund requirement (Amendment to IFRIC 14);

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• Amendments to IAS 32 Classification of rights issues.

( 4 ) DETERMINATION OF FAIR VALUES

A number of the Group’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and / or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

- Property, plant and equipment and intangible assets

The fair value of property, plant and equipment and intangible assets recognized as a result of a business combination is based on market values. The market value of property is the estimated amount for which a property could be exchanged on the date of valuation between knowledgeable and willing parties under normal market conditions. The fair value of items of property, plant and equipment is based on the market approach and cost approaches using quoted market prices for similar items when available and replacement cost when appropriate.

- Financial instruments

Financial instruments measured at fair values were recognized based on quoted prices in an active market, or assessed using pricing models, applied individually for each transaction, taking into consideration the future payment flows, based on the conditions contracted, discounted to present value at market interest rate curves, based on information obtained from the BM&F, BOVESPA and ANDIMA websites, when available. Accordingly, the market value of a security corresponds to its maturity value (redemption value) marked to present value by the discount factor (relating to the maturity date of the security) obtained from the market interest graph in Brazilian reais.

Financial assets classified as available-for-sale refer to the right to compensation to be paid by the Federal Government on reversal of the assets of the distribution concessionaires. The methodology adopted for marking these assets to market is based on the tariff review process for distributors. This review, conducted every four or five years according to each concessionaire, consists of revaluation at market price of the distribution infrastructure. This valuation basis is used for pricing the tariff, which is increased annually up to the next tariff review, based on the parameter of the main inflation indices.

Although the methodology and criteria for valuation of the compensation on reversal of the assets has not yet been defined by the Federal Government, company management believes that it will be based at least on the tariff pricing model. Accordingly, at the time of the tariff review, each concessionaire adjusts the position of the financial asset base for compensation at the amounts ratified by the regulatory authority and uses the General Market Price Index - IGP-M as best estimate for adjusting the original base to the fair value at subsequent dates, in conformity with the Tariff Review process.

( 5 ) FIRST-TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS

As a result of the enactment of Laws 11.638/07 and 11.941/09, in 2008, the CPC issued and the CVM approved a series of accounting Pronouncements and Interpretations with the objective of bringing Brazilian accounting practices into line with the IFRS. These pronouncements have been fully applied, completing the first stage of the convergence.

In order to fully complete the process, further pronouncements were issued in the course of 2009 and 2010, so that the consolidated financial statements for the year ending December 31, 2010 would be in line with international standards.

These financial statements are the first to have been prepared in conformity with the IFRS. In order to make the accounting practices standardization process possilble, the Company applied IFRS 1, adopting January 1, 2009 as the transition date.  Consequently, the 2009 financial statements are re-presented with the adjustments on adoption of the above-mentioned IFRS and IAS identified.

According to the pronouncements referred to above, there are mandatory retroactive application exceptions andoptional exemptions.

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Procedures adopted by the Company:

- Employee benefits: Recognition of the defined benefit type pension plans. In view of the impracticality of retroactive application, the Company took advantage of the exemption and all past gains and losses were recognized at January 1, 2009 against the accrued loss account.

- IFRIC 12 – Concession agreements: Retroactive reconciliation of the financial assets and intangible assets accounted for in accordance with IFRIC 12. Accordingly, the Company did not use the exemption allowed by the transition rules.

- Business combinations: In accordance with the exemption permitted by IFRS 1, the Company opted not to apply the requirements of IFRS 3 – Business combinations retroactively in the transition to the IFRS. Accordingly, only business combinations occurring after January 1, 2009 reflect the requirements of this pronouncement.

- Deemed cost: IFRS 1 allows the option to measure an item of property, plant and equipment at the deemed cost at the transition date. The Company opted to recognize the property, plant and equipment of the subsidiaries CPFL Sul Centrais and CPFL Geração at market value at the transition date.

- The estimates used in preparation of these financial statements at January 1, 2009 and December 31, 2009 are consistent with the estimates made on the same dates in accordance with the practices previously adopted in Brazil.

The impact of the transition to the international accounting practices on the balance sheet and equity at January 1, 2009 and December 31, 2009, and the profit or loss for the year 2009 are described below.

5.1 Reconciliation of the adjustments and reclassifications on adoption of the new accounting practices:

a)Opening balance sheet at January 1, 2009:

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ASSETS	Reference	Previous	Reclassifications (see item 5.2)	Consolidation (see item 5.3.1)	Adjustments	New practices
CURRENT
Cash and cash equivalents		737,847	-	20,607	-	758,454
Consumers, Concessionaires and Licensees	5.3.2	1,721,028	(82,462)	6,121	(41,532)	1,603,155
Dividend and Interest on Capital		-	-	-	-	-
Financial investments		38,249	-	-	-	38,249
Tax credits		174,294	-	1,673	-	175,967
Derivatives		36,520	-	-	-	36,520
Provision for doubtful accounts		(82,462)	82,462	-	-	-
Inventories		15,594	7,636	-	-	23,230
Leasing		-	1,133	-	-	1,133
Deferred tax credits		220,144	(220,144)	-	-	-
Prepaid expenses	5.3.2	101,882	(14,065)	745	(88,562)	-
Deferral of tariff costs	5.3.2	638,229	-	-	(638,229)	-
Other		110,793	5,296	85	2,223	118,397
		3,712,118	(220,144)	29,231	(766,100)	2,755,105
NONCURRENT
Consumers, Concessionaires and Licensees	5.3.2	286,144	-	-	(7,814)	278,330
Associates, Subsidiaries and Parent Company		-	-	-	-	-
Escrow deposits		599,973	149,998	3	-	749,974
Financial investments		96,786	-	-	-	96,786
Tax credits		101,948	-	3,219	-	105,167
Derivatives		396,875	-	-	-	396,875
Deferred tax credits		1,132,736	220,144	-	241,251	1,594,131
Leasing		-	5,256	-	-	5,256
Financial asset of concession	5.3.3	-	-	-	582,241	582,241
Private pension fund		-	-	-	-	-
Other investments at cost		-	116,249	-	-	116,249
Prepaid expenses	5.3.2	99,210	(10,258)	-	(88,952)	-
Deferral of tariff costs	5.3.2	157,435	-	-	(157,435)	-
Other	5.3.8	221,330	5,002	15,891	46,238	288,461
Investments	5.3.8	103,598	(117,393)	-	13,795	-
Property, plant and equipment	5.3.3 / 5.3.4 / 5.3.6	6,614,347	-	398,467	(2,306,277)	4,706,537
Intangible assets	5.3.3 / 5.3.5	2,700,136	29,492	53	3,322,463	6,052,144
Deferred assets		20,536	(28,348)	7,812	-	-
TOTAL NONCURRENT ASSETS		12,531,054	370,142	425,445	1,645,510	14,972,151
TOTAL ASSETS		16,243,172	149,998	454,676	879,410	17,727,256

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LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES	Reference	Previous	Reclassifications (see item 5.2)	Consolidation (see item 5.3.1)	Adjustments	New practices
Suppliers		982,344	-	3,560	-	985,904
Interest on debt		29,081	-	937	-	30,018
Interest on debentures		102,112	-	1	-	102,113
Loans and financing		523,167	-	33,038	-	556,205
Debentures		580,076	-	-	-	580,076
Private pension fund	5.3.7	44,088	-	-	1,169	45,257
Regulatory charges		94,054	-	476	-	94,530
Taxes and contributions		464,339	-	437	(8,104)	456,672
Dividends and interest on equity	5.3.8	632,087	-	69	(614,644)	17,512
Estimated personnel costs		46,244	-	140	-	46,384
Provision for contingencies		15	(23)	8	-	-
Derivatives		53,443	-	-	-	53,443
Public utilities	5.3.5	-	-	-	15,228	15,228
Deferred tax debts		-	-	-	-	-
Deferral of tariff gains	5.3.2	165,871	-	-	(165,871)	-
Other accounts payable	5.3.2	524,898	(124,865)	978	(121,323)	279,688
TOTAL CURRENT LIABILITIES		4,241,819	(124,888)	39,644	(893,545)	3,263,030
NONCURRENT LIABILITIES
Suppliers		85,311	-	-	-	85,311
Interest on debt		74,104	-	-	-	74,104
Loans and financing		3,836,882	-	249,257	-	4,086,139
Debentures		2,026,890	-	-	-	2,026,890
Private pension fund	5.3.7	508,194	-	-	293,770	801,964
Taxes and contributions		2,242	-	1	-	2,243
Deferred tax debts		4,203	-	-	270,639	274,842
Provision for contingencies		107,642	274,886	(1)	-	382,527
Derivatives		961	-	-	-	961
Public utilities	5.3.5	-	-	-	408,887	408,887
Deferral of tariff gains	5.3.2	40,779	-	-	(40,779)	-
Other accounts payable	5.3.2 / 5.3.8	207,194	-	-	62,318	269,512
TOTAL NONCURRENT LIABILITIES		6,894,402	274,886	249,257	994,835	8,413,380
SHAREHOLDERS' EQUITY
Capital		4,741,175	-	-	-	4,741,175
Capital reserve		16	-	-	-	16
Revenue reserve		277,428	-	-	-	277,428
Additional dividend proposed	5.3.8	-	-	-	606,105	606,105
Revaluation reserve	5.3.8	-	-	-	799,870	799,870
Accumulated profit (loss)		-	-	-	(631,911)	(631,911)
Equity attributed to controlling shareholders		5,018,619	-	-	774,064	5,792,683
Equity attributed to noncontrolling shareholders		88,332	-	165,775	4,056	258,163
TOTAL SHAREHOLDERS' EQUITY		5,106,951	-	165,775	778,120	6,050,846
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		16,243,172	149,998	454,676	879,410	17,727,256

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b)Balance sheet at December 31, 2009

ASSETS	Reference	Previous	Reclassifications (see item 5.2)	Consolidation (see item 5.3.1)	Adjustments	New practices
CURRENT
Cash and cash equivalents		1,473,175	-	14,068	-	1,487,243
Consumers, Concessionaires and Licensees	5.3.2	1,840,107	(81,974)	6,250	(11,525)	1,752,858
Dividend and Interest on Capital		-	-	-	-	-
Financial investments		39,253	-	-	-	39,253
Tax credits		190,983	-	1,295	-	192,278
Derivatives		795	-	-	-	795
Provision for doubtful accounts		(81,974)	81,974	-	-	-
Inventories		17,360	-	-	-	17,360
Leasing		-	2,949	-	-	2,949
Deferred tax credits		162,779	(162,779)	-	-	-
Prepaid expenses	5.3.2	124,086	(14,354)	28	(109,760)	-
Deferral of tariff costs	5.3.2	332,813	-	-	(332,813)	-
Other		145,055	11,405	100	-	156,560
		4,244,432	(162,779)	21,741	(454,098)	3,649,296
NONCURRENT
Consumers, Concessionaires and Licensees	5.3.2	226,314	-	-	(1,427)	224,887
Associates, Subsidiaries and Parent Company		-	-	-	-	-
Escrow deposits		654,506	139,671	-	-	794,177
Financial investments		79,835	-	-	-	79,835
Tax credits		110,014	-	3,221	-	113,235
Derivatives		7,881	-	-	-	7,881
Deferred tax credits		1,117,736	162,779	-	6,290	1,286,805
Leasing		-	21,243	-	-	21,243
Financial asset of concession	5.3.3	-	-	-	674,029	674,029
Private pension fund	5.3.7	-	3,054	-	6,671	9,725
Other investments at cost		-	116,477	-	-	116,477
Prepaid expenses	5.3.2	64,201	(6,573)	-	(57,628)	-
Deferral of tariff costs	5.3.2	42,813	-	-	(42,813)	-
Other	5.3.8	160,760	(14,670)	12,826	78,113	237,029
Investments	5.3.8	104,801	(117,621)	-	12,820	-
Property, plant and equipment	5.3.3 / 5.3.4 / 5.3.6	7,487,216	-	399,445	(2,673,622)	5,213,039
Intangible assets	5.3.3 / 5.3.5	2,554,400	22,218	347	3,486,136	6,063,101
Deferred assets		15,081	(21,074)	5,993	-	-
TOTAL NONCURRENT ASSETS		12,625,558	305,504	421,832	1,488,569	14,841,463
TOTAL ASSETS		16,869,990	142,725	443,573	1,034,471	18,490,759

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LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES	Reference	Previous	Reclassifications (see item 5.2)	Consolidation (see item 5.3.1)	Adjustments	New practices
Suppliers		1,021,348	-	104	-	1,021,452
Interest on debt		26,543	-	1,119	-	27,662
Interest on debentures		101,284	-	-	-	101,284
Loans and financing		697,223	-	31,691	-	728,914
Debentures		499,025	-	-	-	499,025
Private pension fund		44,484	-	-	-	44,484
Regulatory charges		62,999	-	751	-	63,750
Taxes and contributions		489,976	-	8,634	-	498,610
Dividends and interest on equity	5.3.8	684,185	-	4,836	(663,737)	25,284
Estimated personnel costs		50,620	-	278	-	50,898
Derivatives	5.3.5	7,012	-	-	-	7,012
Public utilities		-	-	-	15,697	15,697
Deferred tax debts	5.3.2	2,258	(2,258)	-	-	-
Deferral of tariff gains	5.3.2	313,463	-	-	(313,463)	-
Other accounts payable		584,614	(122,792)	1,055	(124,016)	338,861
TOTAL CURRENT LIABILITIES		4,585,034	(125,050)	48,468	(1,085,519)	3,422,933
NONCURRENT LIABILITIES
Suppliers		42,655	-	-	-	42,655
Interest on debt		62,427	-	-	-	62,427
Loans and financing		3,515,236	-	213,806	-	3,729,042
Debentures	5.3.7	2,751,169	-	-	-	2,751,169
Private pension fund		425,366	3,054	-	�� 294,866	723,286
Taxes and contributions		1,639	-	-	-	1,639
Deferred tax debts		4,376	2,258	-	275,376	282,010
Provision for contingencies		38,181	262,463	-	-	300,644
Derivatives	5.3.5	5,694	-	-	-	5,694
Public utilities	5.3.2	-	-	-	405,837	405,837
Deferral of tariff gains	5.3.2 / 5.3.8	108,691	-	-	(108,691)	-
Other accounts payable		161,539	-	-	65,105	226,644
TOTAL NONCURRENT LIABILITIES		7,116,973	267,775	213,806	932,493	8,531,047
SHAREHOLDERS' EQUITY
Capital		4,741,175	-	-	-	4,741,175
Capital reserve		16	-	-	-	16
Revenue reserve	5.3.8	341,751	-	-	-	341,751
Additional dividend proposed	5.3.8	-	-	-	655,017	655,017
Revaluation reserve		-	-	-	765,667	765,667
Accumulated profit (loss)		-	-	-	(234,278)	(234,278)
Equity attributed to controlling shareholders		5,082,942	-	-	1,186,406	6,269,348
Equity attributed to noncontrolling shareholders		85,041	-	181,301	1,089	267,431
TOTAL SHAREHOLDERS' EQUITY		5,167,983	-	181,301	1,187,495	6,536,779
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		16,869,990	142,725	443,575	1,034,469	18,490,759

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c)Statement of income for the year– 2009

	Reference	Previous	Consolidation (see item 5.3.1)	Adjustments	New practices
NET OPERATING REVENUE	5.3.2 / 5.3.3 / 5.3.5 / 5.3.8	10,565,982	73,364	718,660	11,358,006
COST OF ELECTRIC ENERGY SERVICES
Cost of electric energy	5.3.2	(6,531,022)	(5,049)	521,562	(6,014,509)
Operating cost	5.3.2 / 5.3.3 / 5.3.4 / 5.3.5 / 5.3.6 / 5.3.7	(943,492)	(18,199)	(92,247)	(1,053,938)
Cost of services to third parties	5.3.3	(5,387)	-	(615,557)	(620,944)
OPERATING INCOME		3,086,081	50,116	532,418	3,668,615
Operating expense
Cost of sales	5.3.2	(255,114)	-	(85)	(255,199)
General and administrative expenses	5.3.2 / 5.3.3	(384,086)	(1,723)	(17,581)	(403,390)
Other operating expenses	5.3.2 / 5.3.3 / 5.3.4	(245,562)	(255)	18,474	(227,343)
		(884,762)	(1,978)	808	(885,932)
INCOME FROM ELECTRIC ENERGY SERVICE		2,201,319	48,138	533,226	2,782,683
Financial income
Income	5.3.2 / 5.3.8	376,996	2,851	(28,487)	351,360
Expense	5.3.3 / 5.3.5 / 5.3.8	(692,927)	(20,100)	51,961	(661,066)
		(315,931)	(17,249)	23,474	(309,706)
INCOME BEFORE TAXES		1,885,388	30,889	556,700	2,472,977
Social contribution		(155,459)	(2,787)	(50,101)	(208,348)
Income tax		(428,847)	(7,739)	(139,176)	(575,761)
		(584,306)	(10,526)	(189,277)	(784,109)
Net income for the year		1,301,082	20,363	367,423	1,688,868
Net income attributed to controlling shareholders		1,286,470	-	370,827	1,657,297
Net income attributed to noncontrolling shareholders		14,612	20,363	(3,404)	31,571

d)Reconciliation of assets, liabilities, equity and net income:

			Shareholders' equity
					Revaluation reserve
January 1, 2009	Assets	Liabilities	Capital and reserves	Additional dividend proposed	Deemed cost	Financial instruments	Accumulated profit or loss	Net Equity Parent Company	Noncontrolling interest	Total net Equity
Previous	16,243,172	11,136,221	5,018,619	-	-			5,018,619	88,332	5,106,951
Reclassifications										-
Escrow deposit	149,998	149,998	-					-		-
Other	(6,104)	(6,104)						-		-
Consolidation	454,847	289,074						-	165,773	165,773
Adjustments								-		-
Reversal of regulatory assets and liabilities	(1,022,524)	(331,569)					(690,794)	(690,794)	(162)	(690,956)
Pension plan	-	294,939					(294,939)	(294,939)	-	(294,939)
ICPC 01 - Concession agreements	200,186	-				208,930	(12,229)	196,701	3,485	200,186
Property, plant and equipment - deemed cost	1,002,991	-			1,002,991		-	1,002,991	-	1,002,991
Write-off of discount	12,828	-					12,828	12,828	-	12,828
Guarantees	45,860	63,692					(17,832)	(17,832)	-	(17,832)
Public utility	395,247	424,115					(18,764)	(18,764)	(10,104)	(28,868)
Other	372	(5)					377	377	-	377
Dividend	-	(614,642)		606,105				606,105	8,537	614,642
Tax effects	250,383	270,691			(341,016)	(71,035)	389,442	(22,609)	2,302	(20,307)
Balance after application of new practices	17,727,256	11,676,410	5,018,619	606,105	661,975	137,895	(631,911)	5,792,683	258,163	6,050,846

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			Shareholders' equity
					Revaluation reserve
December 31, 2009	Assets	Liabilities	Capital and reserves	Additional dividend proposed	Deemed cost	Financial instruments	Accumulated profit or loss	Net Equity Parent Company	Noncontrolling interest	Total net Equity	Net income 2009
Previous	16,869,991	11,702,008	5,082,942					5,082,942	85,041	5,167,983	1,301,082
Reclassifications										-
Escrow deposit	139,671	139,671						-		-	-
Pension plan	3,054	3,054						-		-
Consolidation	443,576	262,275						-	181,301	181,301	20,363
Adjustments										-
Reversal of regulatory assets and liabilities	(555,966)	(548,095)					(7,987)	(7,987)	116	(7,871)	619,898
Pension plan	6,671	294,863					(288,192)	(288,192)	-	(288,192)	6,747
ICPC 01 - Concession agreements	185,027	-				196,817	(15,071)	181,746	3,280	185,026	(4,329)
Property, plant and equipment - deemed cost	963,440	-			963,440			963,440	-	963,440	(39,551)
Write-off of discount	12,828	-					12,828	12,828	-	12,828	-
Guarantees	50,052	71,151					(21,099)	(21,099)	-	(21,099)	(3,267)
Public utility	392,217	421,534					(19,291)	(19,291)	(10,026)	(29,317)	(450)
Depreciation generation assets	(27,288)	-					(21,730)	(21,730)	(5,558)	(27,288)	(27,288)
Other	1,197	(3,336)				(348)	5,311	4,963	(430)	4,533	4,941
Dividend	-	(664,522)		655,017				655,017	9,505	664,522	-
Tax effects	6,289	275,377			(327,570)	(66,672)	120,953	(273,289)	4,202	(269,087)	(189,278)
Balance after application of new practices	18,490,759	11,953,980	5,082,942	655,017	635,870	129,797	(234,278)	6,269,348	267,431	6,536,779	1,688,868

e)2009 Statement of Cash Flow:

	Previous	Consolidation	Adjustments	New practices
Income including CSLL and IRPJ	1,870,776	25,406	576,795	2,472,977
Adjustments to income	1,181,792	35,414	86,612	1,303,818
Operating assets	364,677	343	(452,179)	(87,159)
Operating liabilities	(995,105)	(30,027)	(225,243)	(1,250,375)
Cash from operations	2,422,140	31,136	(14,015)	2,439,261
Acquisitions of property, plant and equipment	(1,233,695)	(10,620)	695,269	(549,046)
Additions of intangible assets	(93,317)	(31)	(585,706)	(679,054)
Other	78,755	4,208	(93,764)	(10,801)
Cash from investments	(1,248,257)	(6,443)	15,799	(1,238,901)
Cash from financing	(438,555)	(31,232)	(1,784)	(471,571)
Increase (decrease) in cash and cash equivalents	735,328	(6,539)	-	728,789
Opening cash and cash equivalents balance	737,847	20,607	-	758,454
Closing cash equivalents balance	1,473,175	14,068	-	1,487,243

5.2 Reclassification of the amounts of the financial statements published previously:

Certain reclassifications were made in order to adjust presentation of the financial statements to the new accounting standard, with a view to facilitating understanding of the Company's operations. These reclassifications relate basically to (i) reclassification of balances of escrow deposits that were previously presented net of provisions for contingencies, (ii) transfer of the balance of tax credits or debits from current to non-current and consequent offset of the balances of assets and liabilities in compliance with the provisions of IAS 1 – Presentation of the financial statements and IAS 12 – Income taxes, and (iii) transfer of balances between accounts to open or group items that became or ceased relevant in presentation of the balance sheet, after adoption of new practices.

5.3 Nature of the adjustments on first application of the IFRS

5.3.1 Consolidation adjustments:

The concept of consolidation applied by the accounting practices applied previously differs from the conceptsestablished by IAS 27 and 31, which are based on the control criterion. According to IAS 27, control is the ability to preside over the financial and operational policies of the entity so as to obtain the rewards of its activities. IAS 31 establishes that joint control exists when the strategic and operating decisions in relation to the activity require a unanimous consensus of the parties sharing the control, thereby permitting proportionate consolidation of the subsidiary's financial statements.

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Application of these concepts for the investments held by the Company resulted in a change in the consolidation criterion for the subsidiary CERAN, which is now fully consolidated. The adjustment recognized in this lines refers to the amounts of the difference between 100% and the interest held in the subsidiary, which were added line by line for consolidation purposes.

5.3.2  Reversal of regulatory assets and liabilities

To December 31, 2008, the electric energy concessionaires had regulatory asset balances referring to pre-payments made by the concessionaire in relation to the increase in the electric energy acquisition cost and expenditure on system charges, among others, which were received by tariff increase granted by the regulatory authority in the following years. They also had regulatory liability balances in relation to the decrease in these non-manageable costs to be returned to the consumers by a subsequent reduction in the tariff.

In accordance with the new practices (Note 3.13), these regulatory assets and liabilities cannot be recognized, as they do not meet the criteria for definition of assets and liabilities as established in the Framework for the Preparation and Presentation of Financial Statements.

The adjustment made refers to the reversal of the balances of regulatory assets and liabilities of the distribution subsidiaries. Note 37 shows a breakdown of these balances for the reporting dates presented.

5.3.3 IFRIC 12 – Concession Agreements and adjustment for reconciliation of the intangible infrastructure asset

In accordance with the previous accounting practices, the whole concession infrastructure was accounted for as a fixed asset tied to the concession. IFRIC 12 changes the method for recognizing the concessions if certain conditions are met, such as: (i) control over the activities to be provided, to whom the services are provided and at what price, and (ii) the reversal of the assets to the Granting Authority at the end of the concession.

These definitions having been met, the infrastructure of the distribution concessionaires has been segregated and rollforwarded since the construction date, complying with the provisions of the IASs and IFRSs, so that the following was recognized in the financial statements (i) an intangible asset corresponding to the right to operate the concession by collecting from the users of the public utilities, and (ii) a financial asset corresponding to the unconditional contractual right to receive payment (compensation) by reversal of the assets at the end of the concession.

The financial concession asset was measured at fair value, based on the remuneration of the assets fixed by the regulatory body. The financial asset is classified as available-for-sale and is restated and amortized annually in accordance with the adjustment of its fair value, against the revaluation reserve in equity account.

The remaining amount was recognized in intangible assets and corresponds to the right to collect from consumers for the electricity energy distribution services, and amortized in accordance with the consumption pattern that reflects the estimated economic benefit to the end of the concession.

In accordance with IFRIC 12, the distribution subsidiaries applied the concepts retroactively and reconstructed the infrastructure accounting base so that the costs used in formation of the intangible and financial asset are fully aligned with the provisions of the IFRS.

The adjustments to net income and services cost relate to recognition of the revenue from construction work of the distribution assets carried out by the concessionaires. For further details, see Note 3.1.

The following tables show the reclassifications and adjustments made in the distribution companies to comply with IFRIC 12, at January 1, 2009 and December 31, 2009.

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	January 1, 2009
	Previous	Transfers between asset accounts	Adjustments to equity and income statement	New practices
Property, plant and equipment	3,308,975	(3,308,975)	-	-
Intangible assets	717,570	2,938,831	(11,912)	3,644,489
Financial assets	-	370,144	212,097	582,241
	December 31, 2009
	Previous	Transfers between asset accounts	Adjustments to equity and income statement	New practices
Property, plant and equipment	3,579,720	(3,579,720)	-	-
Intangible assets	741,307	3,105,894	(15,177)	3,832,024
Financial assets	-	473,826	200,204	674,030

5.3.4  Recognition of property, plant at equipment at deemed cost

As previously mentioned, the Company opted to apply the exemption foreseen in IFRS 1 in respect of evaluation of property, plant and equipment, at the transition date, for the assets of the subsidiaries CPFL Sul Centrais and CPFL Geração, taking the fair value of the transition date as the deemed cost.

The adjustment of this line corresponds to the recognition of the added value attributed to the revalued assets, against equity, amounting to R$ 1,002,991 (R$ 661,974 net of tax effects, at January 1, 2009).

5.3.5 Charge for the use of public utilities

On signing their Concession Agreements, the subsidiary CERAN and the jointly-controlled ENERCAN, BAESA and Foz do Chapecó assumed obligations to the Federal Government in relation to the granting of the concession, as “Public Utilities”. The liabilities are restated annually by the variation in the General Market Price Index – IGP-M.

To December 31, 2008, the subsidiaries recognized the granting expenses in profit or loss in accordance with their maturities. Under the new practices, the Public Utilities liabilities, discounted to present value in accordance with the fundraising rates of each venture, have been recognized on the date of signing the contract, against an intangible asset related to the right to exploit the concession.

The adjustment at the transition date relates to recognition of the Public Utilities liability (less expenses recognized by the practices adopted previously), in the amount of R$ 424,115, against R$ 395,247 and R$ 28,868 (R$19,053 net of tax effects) in relation to recognition of the intangible asset and accumulated loss for the period.

5.3.6 Depreciation over the concession term

The concession agreements of the subsidiary CERAN and the jointly-owned subsidiaries ENERCAN, BAESA and Foz do Chapecó are ruled by Decree 2003, of 1996. In view of all the legal disputes and potential conflicts between (i) the wording of the Concessions Law, (ii) interpretations of the decree itself, and (iii) the way in which the concession agreements were drawn up, the Company conservatively made the adjustment to the related depreciation rates so that the property, plant and equipment related to the basic project would be depreciated over the useful life of the asset, provided it is restricted to the term of the concession.

5.3.7 Pension plan

- Employee benefit (pension plan)

As previously mentioned, the Company opted to recognize all accumulated actuarial gains and losses atJanuary 1, 2009. The adjustment of R$ 294,939 (R$ 194,660 net of tax effects) corresponds to recognition of the accumulated actuarial loss at the transition date, in accordance with IFRS 1, for all the defined benefit plans of the subsidiaries CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE.

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5.3.8 Other adjustments:

- Write-down of negative goodwill

In accordance with IFRS 3 “Business Combinations”, negative goodwill recognized in accordance with the previous accounting practices should be written down at the transition date for IFRS.

An adjustment of R$ 12,828 (R$ 8,466 net of tax effects) was made in the Investment in relation to the write-down against retained earnings in the opening equity at the transition date.

- Guarantees provided

The accounting practices adopted in Brazil to December 31, 2008 contained no specific pronouncement in respect of the requirements for accounting for guarantees, and issuing of guarantees was therefore not recognized in the financial statements.

As a result of adoption of the pronouncements on recognition, measurement, presentation and disclosure of financial instruments (IAS 39, IAS 32 and IFRS 7) from January 1, 2009, the Company now recognizes guarantees issued in excess of its participation in the joint ventures.

These guarantees are recognized initially at the fair value of the obligation on issue. The Company therefore recognized a liability in Other Payables corresponding to the fair value of the guarantee contracted on January 1,  2009 to a total amount of R$ 63,692, which will be amortized by a credit in finance income as the guarantee risk is discharged.

The balancing items of R$ 45,860 were recognized as Other assets. The amount corresponding to the Company's participation in each jointly-owned subsidiary and the amounts that will not be reimbursed by the other shareholders of the jointly-owned subsidiaries are recognized in profit or loss as finance expense to maturity. Any remaining amount is subject to reimbursement by the other shareholders of the jointly-owned subsidiaries. The net adjustment against retained earnings at January 1, 2009 was R$ 17,832 (R$11,769 net of tax effects).

- Dividend and Interest on shareholders’ equity

The practices adopted previously determined that retained earnings should be distributed at the end of the year. A provision was recognized for the amount corresponding to appropriation of dividends as proposed by management even if it was subject to approval by the AGM.

In accordance with current accounting practices, as mentioned in Note 3.9, provisions are only recognized for amounts in excess of the minimum mandatory dividend after approval in an AGM, at which point they meet the obligation criteria determined by IAS 37. The adjustment stated reflects a reversal of the provision for an additional dividend to be paid in excess of the mandatory dividend not yet approved in a meeting payable.

- Revaluation reserve

The adjustments in this group relate to (i) recognition of the value-added of the cost allocated to the property, plant and equipment of the generators and (ii) the balancing item of the restatement of the financial concession asset.

- Non-controlling interest

In accordance with the new accounting practices (IAS 1), since January 1, 2009, the Company has classified the participation of non-controlling shareholders as part of the consolidated results and of equity in the consolidated financial statements.

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To December 31, 2008, this amount was stated in liabilities in the consolidated balance sheet and the adjustment in this line corresponded to reclassification of the liability to equity.

The amount previously stated in net income is now stated as net income attributable to the Company and the portion of the noncontrolling interests as net income attributable to noncontrolling interests.

Re-presentation of the quarterly financial statements

The reconciliation of the effects of adoption of the new accounting practices on net income and equity for the quarters ended March 31, 2009, June 30, 2009, September 30, 2009, March 31, 2010, June 30, 2010 and September 30, 2010 is presented below, in conformity with CVM Decision 656/2011:

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	Changes in the quarter			Changes in the quarter
	1st Quarter 09	2nd Quarter 09	3rd Quarter 09	1st Quarter 10	2nd Quarter 10	3rd Quarter 10
Previous net income	282,703	288,968	289,674	390,199	384,230	387,659
Adjustments
Reversal of regulatory assets and liabilities	(11,811)	217,435	281,226	164,329	(37,348)	(61,391)
Pension plan	19	19	18	3	3	3
ICPC 01 - Concession agreements	(1,028)	(1,170)	(831)	10,646	10,591	10,504
Property, plant and equipment - deemed cost	(9,884)	(9,885)	(9,891)	(9,887)	(9,880)	(9,906)
Write-down of discount	-	-	-	-	-	-
Guarantees	(972)	521	436	(3,481)	(4,638)	(4,714)
Public utility	153	236	215	(2,510)	(3,435)	(2,707)
Depreciation rate	(6,822)	(6,822)	(6,822)	(6,822)	(6,822)	(6,822)
Other	709	1,196	1,458	1,867	1,265	1,546
Tax effects	10,797	(81,794)	(107,544)	(62,442)	19,370	28,733
Effects of adjustments on the Noncontrolling interests	844	614	827	1,024	1,766	1,243
Net parent company income after application of the new practices	264,708	409,318	448,766	482,926	355,102	344,148
Noncontrolling interests as a result of the change in consolidation practices	2,927	6,914	6,235	3,542	4,011	5,847
Effects of adjustments on the Noncontrolling interests	(845)	(614)	(827)	(1,024)	(1,766)	(1,243)
Previous Noncontrolling interests	2,086	2,699	3,510	2,419	2,423	2,029
Total net income after adoption of the new practices	268,876	418,317	457,684	487,863	359,770	350,781
	Changes in the period			Changes in the period
	1st Quarter 09	2nd Quarter 09	3rd Quarter 09	1st Quarter 10	2nd Quarter 10	3rd Quarter 10
Previous net income	282,703	571,671	861,345	390,199	774,429	1,162,088
Adjustments
Reversal of regulatory assets and liabilities	(11,811)	205,624	486,850	164,329	126,981	65,590
Pension plan	19	38	56	3	6	9
ICPC 01 - Concession agreements	(1,028)	(2,198)	(3,029)	10,646	21,237	31,741
Property, plant and equipment - deemed cost	(9,884)	(19,769)	(29,660)	(9,887)	(19,767)	(29,673)
Write-off of discount	-	-	-	-	-	-
Guarantees	(972)	(451)	(15)	(3,481)	(8,119)	(12,833)
Public utility	153	389	604	(2,510)	(5,945)	(8,652)
Depreciation rate	(6,822)	(13,644)	(20,466)	(6,822)	(13,644)	(20,466)
Other	709	1,905	3,363	1,867	3,132	4,678
Tax effects on the adjustments	10,797	(70,997)	(178,541)	(62,442)	(43,072)	(14,339)
Effects of adjustments on the Noncontrolling interests	845	1,459	2,286	1,024	2,790	4,033
Net parent company income after application of the new practices	264,709	674,027	1,122,793	482,926	838,028	1,182,176
Non-cntrolling interests as a result of the change in consolidation practices	2,927	9,841	16,076	3,542	7,553	13,400
Effects of adjustments on Noncontrolling interests	(845)	(1,459)	(2,286)	(1,024)	(2,790)	(4,033)
Previous Noncontrolling interests	2,086	4,785	8,295	2,419	4,842	6,871
Total net income after application of the new practices	268,877	687,194	1,144,878	487,863	847,633	1,198,414

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	Quarter ended in			Quarter ended in
	March 31, 2009	June 30, 2009	September 30, 2009	March 31, 2010	June 30, 2010	September 30, 2010
Previous equity	5,301,322	5,020,641	5,312,835	5,473,141	5,138,168	5,525,827
Adjustments
Reversal of regulatory assets and liabilities	(702,768)	(485,332)	(204,106)	156,457	119,110	57,718
Pension plan	(294,920)	(294,901)	(294,883)	(288,212)	(288,206)	(288,200)
ICPC 01 - Concession agreements	193,965	191,203	188,099	216,120	247,023	274,073
Property, plant and equipment - deemed cost	993,107	983,222	973,331	953,553	943,673	933,767
Write-down of discount	12,828	12,828	12,828	12,828	12,828	12,828
Guarantees	(18,804)	(18,283)	(17,847)	(24,580)	(29,218)	(33,932)
Public utility	(28,715)	(28,478)	(28,263)	(59,117)	(62,549)	(65,258)
Depreciation rate	(6,822)	(13,644)	(20,466)	(6,822)	(13,644)	(20,466)
Other	827	1,704	2,889	4,928	7,294	8,673
Dividend	614,647	576,624	-	664,522	780,941	-
Tax effects on the adjustments	(7,656)	(88,801)	(195,397)	(337,707)	(325,620)	(302,456)
Effects of adjustments on the Noncontrolling interests	(3,186)	1,053	6,853	87	6,384	14,142
Parent company equity after application of the new practices	6,053,825	5,857,836	5,735,873	6,765,198	6,536,184	6,116,716
Effects of adjustments on Noncontrolling interests	3,186	(1,053)	(6,853)	(87)	(6,384)	(14,142)
Noncontrolling interests as a result of the change in consolidation practices	168,700	175,614	181,850	184,843	188,852	194,699
Previous Noncontrolling interests	85,384	82,611	85,612	87,195	72,905	74,494
Total equity after adoption of the new practices	6,311,095	6,115,008	5,996,482	7,037,149	6,791,557	6,371,767
Equity of the controlling interests	6,053,825	5,857,836	5,735,873	6,765,198	6,536,184	6,116,716
Noncontrolling interests	257,270	257,172	260,609	271,951	255,373	255,051

( 6 ) CASH AND CASH EQUIVALENTS

	December 31, 2010	December 31, 2009	January 1, 2009
Bank balances	361,746	313,104	123,760
Short-term financial investments	1,201,149	1,174,139	634,694
Total	1,562,895	1,487,243	758,454

Short-term financial investments are short-term transactions with institutions operating in the Brazilian financial market, with daily liquidity, low credit risk and average interest of 100% of the Interbank deposit rate (CDI).

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( 7 ) CONSUMERS, CONCESSIONAIRES AND LICENSEES

In the consolidated financial statements, the balance derives mainly from the supply of electric energy. The following table shows the breakdown at December 31, 2010, 2009 and January 1, 2009: 

	Amounts	Past due		Total
	coming due	until 90 days	> 90 days	December 31, 2010	December 31, 2009	January 1, 2009
Current
Consumer classes
Residential	289,992	191,137	21,410	502,539	485,541	407,544
Industrial	119,408	75,898	37,637	232,943	264,798	249,592
Commercial	113,061	43,835	13,059	169,955	189,080	154,569
Rural	29,486	7,082	2,526	39,094	32,671	32,079
Public administration	26,663	5,049	902	32,614	60,943	29,396
Public lighting	24,372	2,166	15,211	41,749	60,557	81,159
Public utilities	34,814	4,743	498	40,055	35,380	31,324
Billed	637,796	329,910	91,243	1,058,949	1,128,970	985,663
Unbilled	465,077	-	-	465,077	388,162	355,627
Financing of Consumers' Debts	81,150	7,007	23,984	112,141	91,437	55,902
Free energy	3,727	-	-	3,727	3,506	457
CCEE transactions	23,932	-	-	23,932	14,722	45,364
Concessionaires and Licensees	193,852	-	-	193,852	184,891	175,282
Provision for doubtful accounts	-	-	(80,691)	(80,691)	(81,974)	(82,462)
Other	35,485	2,542	1,078	39,104	23,144	67,322
Total	1,441,019	339,459	35,614	1,816,091	1,752,858	1,603,155
Non current
Financing of Consumers' Debts	154,438	-	-	154,438	140,893	151,573
Free energy	-	-	-	-	38	145
CCEE transactions	41,301	-	-	41,301	41,301	39,416
Concessionaires and Licensees	-	-	-	-	42,655	87,196
Total	195,739	-	-	195,739	224,887	278,330

Financing of Consumers' Debts -Refers to the negotiation of overdue receivables from consumers, principally public organizations. Payment of some of these credits is guaranteed by the debtors, in the case of public entities, by pledging the bank accounts through which their ICMS revenue is received. Allowances for doubtful accounts are based on best estimates of the subsidiaries' management for unsecured amounts and losses regarded as probable.

Electric Energy Trading Chamber (CCEE) transactions -The amounts refer to the sale of electric energy on the short-term market. The noncurrent amount receivable mainly comprises: (i) legal adjustments, established as a result of suits brought by agents in the sector; (ii) lawsuits challenging the CCEE accounting for the period from September 2000 to December 2002; and (iii) provisional accounting entries established by the CCEE. The subsidiaries consider that there is no significant risk on the realization of these assets and consequently no provision was posted in the accounts.

Concessionaires and licensees- Refers to accounts receivable in respect of the supply of electric energy to other Concessionaires and Licensees, mainly by the subsidiaries CPFL Geração and CPFL Brasil, and to transactions relating to the partial spin-off of Bandeirante Energia S.A. by the subsidiary CPFL Piratininga. The amounts are set off against accounts payable, through a settlement of accounts.

In 2008, amounts receivable of R$ 127,965 from AES Tietê S/A (“AES Tietê”) were also recognized by the subsidiaries CPFL Paulista and CPFL Leste Paulista, for use of the distribution system, and the respective pass-through (recognizing of the same amount as accounts payable) to CTEEP – Companhia de Transmissão de Energia Elétrica Paulista in respect of the charge for use of the Border Transmission Systems.

Under an agreement made between the parties involved, through the intermediary of ANEEL, the amounts are being paid both by the generator and by the subsidiaries to CTEEP, in 36 monthly installments as from January2009, restated at the SELIC rate. The balance of the operation at December 31, 2010 was R$ 42,655, classified in current assets.

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Allowance for doubtful accounts

Changes in the allowance for doubtful accounts are shown below:

At January 1, 2009	(82,462)
Provision recognized	(88,298)
Recovery of revenue	52,048
Write-off of accounts receivable provisioned	36,738
At December 31, 2009	(81,974)
Provision recognized	(108,663)
Recovery of revenue	56,995
Write-off of accounts receivable provisioned	52,951
At December 31, 2010	(80,691)

( 8 ) FINANCIAL INVESTMENTS

In 2005, through a Private Credit Agreement, the Company acquired the credit arising from the Purchase and Sale of Electric Energy Agreement between Companhia Energética de São Paulo (“CESP”) (seller) and CPFL Brasil (purchaser), referring to the supply of energy for a period of 8 years. The amounts handed over by the Company to CESP will be settled by CPFL Brasil using the funds derived from the acquisition of energy produced by that company.

( 9 ) RECOVERABLE TAXES

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	December 31, 2010	December 31, 2009	January 1, 2009
Current
Prepayments of social contribution - CSLL	1,046	8,189	24,135
Prepayments of income tax - IRPJ	2,298	19,549	5,531
Income tax and social contribution to be offset	11,560	15,424	14,361
Withholding tax - IRRF	38,927	42,959	69,681
IRRF on interest on equity	34,088	33,095	25
ICMS to be offset	71,833	48,271	40,421
Social integration program - PIS	3,852	4,545	3,390
Contribution for Social Security financing- COFINS	13,401	12,028	11,177
National Social Security Institute - INSS	2,192	1,115	961
Other	13,828	7,103	6,285
Total	193,025	192,278	175,967
Noncurrent
Social contribution to be offset - CSLL	32,389	29,999	27,315
Income tax to be offset - IRPJ	1,002	1,001	3,400
Social integration program - PIS	2,787	2,787	2,787
ICMS to be offset	101,381	74,212	70,161
Other	1,410	5,236	1,504
Total	138,969	113,235	105,167

Social contribution to be offset – Balance refers to the final favorable decision in a lawsuit filed by the subsidiary CPFL Paulista. The subsidiary CPFL Paulista is awaiting the outcome of the administrative procedures for ratification of the credit with the Federal Revenue Office, in order to offset the credit.

ICMS to be offset - mainly refers to the credit recorded on acquisition of a permanent asset.

( 10 )DEFERRED TAXES

10.1- Breakdown of tax credits and debits:

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	December 31, 2010	December 31, 2009	January 1, 2009
Social contribution credit
Tax loss carryforwards	51,805	52,174	38,707
Tax benefit of merged goodwill	172,255	191,184	199,103
Temporarily non-deductible differences	(12,418)	(3,941)	58,777
Subtotal	211,642	239,417	296,587
Income tax credit
Tax losses	143,867	132,471	93,782
Tax benefit of merged goodwill	583,723	641,757	672,155
Temporarily non-deductible differences	(33,619)	(11,081)	178,885
Subtotal	693,971	763,147	944,822
PIS and COFINS credit
Temporary non-deductible differences	78	2,231	77,880
Total	905,691	1,004,795	1,319,289
Total tax credit	1,183,458	1,286,805	1,594,131
Total tax debit	(277,767)	(282,010)	(274,842)

10.2 - Tax Benefit of Merged Intangible asset:

The tax benefit on merged goodwill refers to the tax credit calculated on the merged goodwill on acquisition and is recorded in accordance with CVM Instructions nº 319/99 and nº 349/01. The benefit is realized in proportion to amortization of the merged definite life intangible asset that gave rise to it, in accordance with the projected net income of the subsidiaries during the remaining term of the concession, as shown in Note 15.

	December 31, 2010		December 31, 2009		January 1, 2009
	CSLL	IRPJ	CSLL	IRPJ	CSLL	IRPJ
CPFL Paulista	94,584	262,733	103,736	288,152	113,571	315,477
CPFL Piratininga	21,274	73,002	23,207	79,630	25,285	86,760
RGE	41,117	169,806	44,378	183,269	47,447	195,943
CPFL Santa Cruz	4,705	14,794	5,862	18,435	7,126	22,405
CPFL Leste Paulista	2,622	7,986	3,451	9,586	1,714	4,761
CPFL Sul Paulista	3,767	11,758	5,020	13,943	1,678	4,662
CPFL Jaguari	2,305	7,001	3,027	8,411	1,603	4,452
CPFL Mococa	1,456	4,527	1,966	5,461	�� 679	1,887
CPFL Geração	-	30,877	-	33,379	-	35,808
CPFL Serviços	425	1,239	537	1,491	-	-
Total	172,255	583,723	191,184	641,757	199,103	672,155

CSLL and IRPJ are federal income taxes.

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10.3 - Accumulated balances on temporary nondeductible differences:

	December 31, 2010			December 31, 2009			January 1, 2009
	CSLL	IRPJ	PIS/COFINS	CSLL	IRPJ	PIS/COFINS	CSLL	IRPJ	PIS/COFINS
Temporary non-deductible differences:
Provision for contingencies	18,396	50,984	-	21,884	60,454	-	22,217	76,500	-
Tariff review - remuneration base	-	-	-	-	-	-	2,819	7,830	-
Private pension fund	3,051	9,473	-	4,097	12,377	-	4,770	14,247	-
Allowance for doubtful accounts	7,426	21,026	-	7,389	20,927	-	7,101	20,123	-
Free energy provision	3,730	10,362	-	2,410	6,694	-	-	-	-
Research and Development and Energy Efficiency Programs	15,079	41,883	-	16,736	46,477	-	16,703	46,396	-
Profit-sharing	2,338	7,160	-	1,986	6,267	-	1,864	5,924	-
Depreciation rate difference - Revaluation	9,306	25,846	-	9,898	27,494	-	11,036	30,650	-
Financial instruments (IFRS / CPC)	623	1,595	-	832	2,255	-	533	1,464	-
Recognition of the concession - adjustment of intangible assets (IFRS / CPC)	(6,276)	(17,433)	-	(4,025)	(11,183)	-	(4,174)	(11,593)	-
Reversal of regulatory assets and liabilities (IFRS / CPC)	(1,076)	(3,030)	(1,399)	1,561	4,337	1,607	69,887	194,138	77,800
Actuarial losses on the transition of accounting practices (IFRS/CPC)	27,035	75,098	-	26,042	72,340	-	26,673	74,086	-
Other adjustments changes in practices	63	174	-	13	36	473	2,726	7,577	80
Other	12,390	33,540	1,477	6,387	15,860	151	540	205	-
Temporarily non-deductible differences - comprehensive income:
Recognition of the concession - financial adjustment  (IFRS / CPC)	(25,337)	(70,388)	-	(18,019)	(50,051)	-	(19,090)	(53,027)	-
Property, plant and equipment  - deemed cost adjustments (IFRS/CPC)	(79,166)	(219,909)	-	(81,132)	(225,365)	-	(84,828)	(235,635)	-
Total	(12,418)	(33,619)	78	(3,941)	(11,081)	2,231	58,777	178,885	77,880

10.4 Expected recovery estimates

2011	193,580
2012	93,750
2013	85,683
2014	62,181
2015	58,847
2016 to 2018	130,816
2019 to 2021	87,942
2022 to 2024	48,438
2025 to 2027	124,183
2028 to 2030	20,271
Total	905,691

10.5 - Reconciliation of the amounts of income tax and social contribution reported in the income statements for 2010 and 2009:

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	2010		2009
	CSLL	IRPJ	CSLL	IRPJ
Income before taxes	2,385,372	2,385,372	2,472,977	2,472,977
Adjustments to reflect effective rate:
- Amortization of intangible asset acquired	115,782	146,194	121,319	149,623
- Realization CMC	11,589	-	13,549	-
- Tax incentives - PIIT	(6,058)	(6,050)	(483)	(483)
- Effect of presumed profit system	(17,622)	(20,448)	(34,090)	(39,790)
- Other permanent additions/(eliminations), net	16,838	(35,338)	2,256	(20,876)
- Elimination Law 11.941/09 art. 4			(32,143)	(32,143)
Calculation base	2,505,901	2,469,730	2,543,385	2,529,308
Statutory rate	9%	25%	9%	25%
Tax credit result	(225,531)	(617,433)	(228,905)	(632,327)
-  Tax credit allocated	4,296	13,333	20,557	56,566
Total	(221,235)	(604,100)	(208,348)	(575,761)
Current	(200,878)	(554,443)	(138,771)	(366,432)
Deferred	(20,357)	(49,657)	(69,577)	(209,329)

Amortization of Intangible asset acquired – business combinations -Refers to the non-deductible portion of amortization of intangible assets derived from the acquisition of investees.

Realization of Complimentary Restatement CMC -Refers to the depreciation of the portion of incremental cost of the complementary restatement introduced by Law 8.200/91, which is not deductible for purposes of determination of social contribution. 

Tax Credit Allocated– Credit recorded by the Company on tax loss carryforwards in the light of a revision of projections, which resulted in a margin recorded to complete the accounting entries.

Elimination under Lawn° 11.941/09 – Refers to thereductions in interest, fines and legal charges on liabilities,as a result of adhering to REFIS IV, in accordance with the sole paragraph of article 4 of Lawnº 11.941/09.  

10.6 Unrecognized tax credits

The subsidiary Sul Geradora has income tax and social contribution assets on tax loss carryforwards of R$ 72,492 that were not recognized as it could not be reliable estimated whether future taxable profit will be available against which they can be utilized. There is also no prescriptive period for use of the tax loss carryforwards.

( 11 )LEASES  

The subsidiary CPFL Brasil provides services and leases equipment relating to own power production, in which it is the lessor, and the main risks and rewards of ownership of the assets are transferred to the lessees.

Investments in these finance lease projects are recognized at the present value of the minimum payments receivable which are treated as amortization of the investment and financial income is recognized in profit and loss for the year over the term of the contracts.

The investments produced financial income for the year of R$ 5,363 (R$ 2,276 in 2009).

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	December 31, 2010	December 31, 2009	January 1, 2009
Present value of the minimum payments receivable	102,769	104,835	21,339
Unrealized financial income	(71,701)	(80,643)	(14,950)
Gross investment	31,068	24,192	6,389
Current	4,754	2,949	1,133
Noncurrent	26,314	21,243	5,256
	Within 1 year	1 to 5 years	Over 5 years	Total
Present value of the minimum payments receivable	13,591	48,495	40,683	102,769

( 12 )FINANCIAL ASSET OF CONCESSION

At January 1, 2009	582,241
Additions	104,587
Marked to market	(10,830)
Disposal	(1,969)
At December 31, 2009	674,029
Additions	179,501
Marked to market	82,637
Disposal	(1,521)
At December 31, 2010	934,646

The balance refers to the fair value of the financial asset in relation to the right established in the concession agreements of the energy distributors to receive payment on reversal of the assets at the end of the concession.

Under the current tariff model, interest on the asset is recognized in profit or loss on billing of the consumers and realized on receipt of the electric energy bills. The difference in relation to the adjustment to market value is recognized against the revaluation reserve in equity.

( 13 )OTHER CREDITS

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	Current			Noncurrent
	December 31, 2010	December 31, 2009	January 1, 2009	December 31, 2010	December 31, 2009	January 1, 2009
Receivables from CESP	-	8,923	24,021	-	-	11,964
Receivables from BAESA's shareholders	17,128	15,503	14,147	-	15,503	28,296
Advances - Fundação CESP	7,995	6,299	5,700	-	-	-
Advances to suppliers	16,659	6,134	-	-	-	-
Pledges, funds and tied deposits	2,108	1,804	513	89,051	99,762	132,906
Fund tied to foreign currency loans	-	-	-	21,221	19,148	30,023
Orders in progress	13,988	4,484	16,214	-	-	2,379
Services rendered to third parties	73,163	48,845	18,600	-	-	42
Reimbursement RGR	5,683	5,504	5,173	1,909	1,611	766
Advance energy purchase agreements	15,817	13,989	12,061	65,786	61,847	40,970
Prepaid expenses	29,565	14,351	9,050	2,724	6,573	5,443
Collection agreements	26,573	4,263	-	-	-	-
Other	44,733	26,461	12,918	41,415	32,585	35,672
Total	253,412	156,560	118,397	222,106	237,029	288,461

Receivables - BAESA Shareholders- From November 1, 2005 to April 30, 2008, differences in the prices used in billing energy sold to the shareholders, different payment terms and other factors resulted in variations in contributions from the shareholders towards the results of the indirect subsidiary BAESA. To settle this question, BAESA’s shareholders agreed in 2007 that the excess contributions made by the subsidiary CPFL Geração should be restated in accordance with the CDI rate and offset over 36 months from January, 2009.

Advances - Fundação CESP –Refers to advances to employee for welfare programs and operational maintenance of the entity.

Pledges, Funds and Tied Deposits:collateral offered to guarantee CCEE operations and guarantees granted to jointly-owned subsidiaries.

Fund Tied to Foreign Currency Loans: These are guarantees offered when negotiating or renegotiating loans.

Services Rendered to Third Parties:Refers to accounts receivable for services provided to consumers in relation to electric energy distribution.

Refund of RGR: Refers to amounts to be offset in relation to the difference between the RGR - Global Reversal Reserve approved by ANEEL and the amount actually incurred, based on property, plant and equipment in use.

Advance Energy Purchase Agreements:Refers to prepayments of energy purchases by the subsidiaries, which will be liquidated on delivery of the energy to be supplied.

Collection agreements -Refers to agreements between the distributors and city halls and companies for collection  through the electric energy bills and subsequent pass-through  of amounts related to public letting, newspapers, healthcare, residential insurance, etc. From April 2010, as a result of introduction of the new billing system - CCS, the subsidiaries change the accounting method (from collection-based to billing-based recognition), affecting accounting for both receivables and payables(Note 24).

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( 14 )PROPERTY, PLANT AND EQUIPMENT

	Land	Reservoirs, dams and  water mains	Buildings, construction and improvements	Machinery and equipment	Vehicles	Furniture and fittings	In progress	Total
At January 1, 2009	51,125	976,545	1,272,879	1,674,210	2,402	4,988	724,388	4,706,537
Historic cost	51,125	1,186,753	1,499,868	2,267,321	3,878	6,617	724,388	5,739,950
Accumulated depreciation/amortization	-	(210,208)	(226,989)	(593,111)	(1,476)	(1,629)	-	(1,033,413)
Additions	1,906	4,910	6,481	3,566	1,082	274	642,156	660,375
Disposals	-	-	-	(420)	(114)	(16)	(18)	(568)
Transfers	1,510	1,220	30,990	27,972	82	1,298	(63,072)	-
Depreciation	(1,195)	(33,077)	(45,262)	(71,605)	(1,414)	(752)	-	(153,305)
At December 31, 2009	53,346	949,598	1,265,088	1,633,723	2,038	5,792	1,303,454	5,213,039
Historic cost	54,541	1,192,883	1,537,339	2,298,439	4,927	8,174	1,303,454	6,399,757
Accumulated depreciation/amortization	(1,195)	(243,285)	(272,251)	(664,715)	(2,889)	(2,382)	-	(1,186,717)
Additions	-	3,851	3,471	(13,181)	1,457	2,044	754,298	751,940
Disposals	(48)	-	-	(15,508)	(355)	(37)	(8)	(15,956)
Transfers	128,287	617,391	132,256	376,536	847	5,197	(1,260,514)	-
Depreciation	(1,195)	(37,613)	(49,329)	(72,696)	(784)	(941)	-	(162,558)
At December 31, 2010	180,390	1,533,227	1,351,486	1,908,875	3,203	12,055	797,230	5,786,466
Historic cost	182,780	1,814,125	1,673,066	2,646,286	6,877	15,378	797,230	7,135,742
Accumulated depreciation	(2,390)	(280,898)	(321,580)	(737,411)	(3,674)	(3,323)	-	(1,349,276)
Average depreciation rate	-	2.36%	3.86%	3.11%	20.00%	10.00%	-

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As mentioned in item 3.4, assets not acquired recently were measured at deemed cost at the transition date, while the assets of recently-built plants are recognized at cost, which in Management’s opinion, approximates market value. Property, plant and equipment were valuated to their market valuesbased on an appraisal carried out by an independent engineering company specializing in equity valuation. Added value of R$ 1,002,991 was determined at January 1, 2009 and recognized in the revaluation reserve in equity. The amortization of the value-added with an impact on the profit or loss for the years ended December 31, 2010 and 2009, determined based on the remaining useful life of the assets, was R$ 39,605 and R$ 39,552.

Construction in progress - the balance mainly refers to work in progress of the operating subsidiaries and/or those under development, particularly the EPASA and Foz do Chapecó generation projects, with total property, plant and equipment of R$ 630,616 and R$ 295,673 (R$ 321,614 and R$ 150,793 in proportion to the participation of the subsidiary CPFL Geração).

In conformity with IAS 23, the interest on the loans taken out by the projects to finance the construction is capitalized during the construction phase. During 2010, R$ 84,839 was capitalized in the consolidated financial statements (R$ 56,106 in 2009). For further details of construction assets and fund raising costs, see notes 1, 17 and 18.

Impairment testing: The Company evaluated in respect of all the reporting periods for indications of devaluation of its assets that might involve the need for impairment tests. The evaluation was based on external and internal information sources, taking into account variations in interest rates, changes in market conditions and other factors.

The result of the assessment indicated no signs of impairment of these assets in any of the reporting periods and therefore no impairment losses were recognized.

( 15 )INTANGIBLE ASSETS

	December 31, 2010			December 31, 2009	January 1, 2009
	Historic cost	Accumulated amortization	Net value	Net value	Net value
Goodwill	6,055	-	6,055	4,048	-
Intangible assets - Concession rights:
Acquired in business combinations	3,734,995	(1,692,863)	2,042,132	2,185,780	2,386,304
Distribution infrastructure - operational	8,222,686	(4,886,917)	3,335,769	2,879,341	2,802,271
Distribution infrastructure - in progress	694,343	-	694,343	521,147	387,645
Public utility	407,288	(9,305)	397,983	392,221	395,247
Other intangible assets	162,943	(54,348)	108,595	80,564	80,677
Total intangible assets	13,228,310	(6,643,433)	6,584,877	6,063,101	6,052,144
Historic cost			13,228,310	12,209,040	11,742,436
Accumulated amortization			(6,643,433)	(6,145,939)	(5,690,292)
			6,584,877	6,063,101	6,052,144

15.1 Intangible asset acquired in business combinations

The following table shows the breakdown of the intangible asset of the right to exploit the concession acquired in business combinations:

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	December 31, 2010			December 31, 2009	January 1, 2009	Annual amortization rate
	Historic cost	Accumulated amortization	Net value	Net value	Net value	2010	2009	2008
Intangible asset - acquired in business combinations
Intangible asset acquired, not merged
Parent Company
CPFL Paulista	304,861	(100,817)	204,044	223,937	245,322	5.90%	5.93%	6.23%
CPFL Piratininga	39,065	(12,461)	26,604	29,019	31,619	6.19%	6.19%	6.70%
CPFL Geração	54,555	(17,822)	36,733	39,898	43,150	5.80%	5.83%	6.21%
RGE	3,150	(590)	2,560	2,765	2,959	6.53%	6.53%	6.07%
CPFL Santa Cruz	9	(1)	8	9	24	8.81%	-	-
CPFL Leste Paulista	3,333	(446)	2,887	-	-	8.37%	-	-
CPFL Sul Paulista	7,288	(932)	6,356	-	-	7.99%	-	-
CPFL Jaguari	5,213	(710)	4,503	-	-	8.51%	-	-
CPFL Mococa	9,110	(1,268)	7,842	-	-	8.70%	-	-
CPFL Jaguari Geração	7,896	(474)	7,422	-	-	3.75%	-	-
Other	-	-	-	-	-	-	-	-
	434,480	(135,521)	298,959	295,628	323,074
Subsidiaries
CPFL Jaguariúna	-	-	-	-	120,815	-	-	11.81%
ENERCAN	10,233	(2,316)	7,917	8,626	9,319	6.93%	6.93%	4.83%
Barra Grande	3,081	(1,010)	2,071	2,252	2,432	5.93%	5.93%	6.65%
Chapecoense	7,376	-	7,376	7,376	7,319	-	-	-
EPASA	498	-	498	498	-	-	-	-
Parque eólico Santa Clara	31,735	-	31,735	31,735	-	-	-	-
Parque eólico Campo do Ventos	5,576	-	5,576	-	-	-	-	-
Other	14,498	(11,063)	3,435	3,628	7,022	6.22%	6.22%	4,99% a 11,65%
	72,997	(14,389)	58,608	54,115	146,907
Subtotal	507,477	(149,910)	357,567	349,743	469,981
Intangible asset acquired and merged – Deductible
Subsidiaries
RGE	1,120,266	(739,555)	380,711	399,666	419,982	3.76%	3.76%	4.50%
CPFL Geração	426,450	(219,960)	206,490	223,226	239,464	6.22%	6.22%	5.74%
Subtotal	1,546,716	(959,515)	587,201	622,892	659,446
Intangible asset acquired and merged – Reassessed
Parent company
CPFL Paulista	1,074,026	(415,524)	658,502	722,207	790,690	5.90%	5.93%	6.23%
CPFL Piratininga	115,762	(36,927)	78,835	85,995	93,696	6.19%	6.19%	6.70%
RGE	310,128	(66,832)	243,296	262,839	281,236	6.33%	6.33%	5.88%
CPFL Santa Cruz	61,685	(28,907)	32,778	40,843	49,641	13.07%	13.07%	15.12%
CPFL Leste Paulista	27,034	(8,526)	18,508	22,693	-	15.48%	15.48%	-
CPFL Sul Paulista	38,168	(11,856)	26,312	32,090	-	15.14%	15.14%	-
CPFL Jaguari	23,600	(7,300)	16,300	20,018	-	15.76%	15.76%	-
CPFL Mococa	15,124	(4,950)	10,174	12,588	-	15.96%	15.96%	-
CPFL Jaguari Geração	15,275	(2,616)	12,659	13,872	-	7.94%	7.94%	-
	1,680,802	(583,438)	1,097,364	1,213,145	1,215,263
Subsidiaries
CPFL Leste Paulista	-	-	-	-	12,570	-	-	8.67%
CPFL Sul Paulista	-	-	-	-	12,308	-	-	8.59%
CPFL Jaguari	-	-	-	-	11,754	-	-	8.56%
CPFL Mococa	-	-	-	-	4,982	-	-	8.49%
	-	-	-	-	41,614
Subtotal	1,680,802	(583,438)	1,097,364	1,213,145	1,256,877
Total	3,734,995	(1,692,863)	2,042,132	2,185,780	2,386,304

The intangible asset acquired in business combinations comprises:

- Intangible asset acquired, not merged

Refers mainly to the remaining goodwill on acquisition of the shares held by the noncontrolling shareholders.

- Intangible asset acquired and merged - Deductible

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Goodwill on the acquisition of the subsidiaries that was merged with the respective net equities, without application of CVM Instructions nº 319/99 and nº 349/01, that is, without segregation of the amount of the tax benefit.

- Intangible asset acquired and merged – Reassessed

In order to comply with ANEEL instructions and avoid the goodwill amortization resulting from the merger of a parent company causing a negative impact on dividends paid to the shareholders, the subsidiaries applied the concepts of CVM Instructions nº 319/99 and nº 349/01 on the acquisition goodwill. A reserve was therefore recorded to adjust the goodwill, set against the equity reserves of the subsidiaries, so that the effect on the equity reflects the tax benefit of the merged goodwill. These changes affected the Company's investment in the subsidiaries, and in order to adjust this, non-deductible goodwill was recorded for tax.

15.2 Changes in intangible assets:

The changes in intangible assets for the years ended December 31, 2010 and 2009 are as follows:

	Concession right
	Goodwill	Acquired in business combinations	Public utility	Distribution infrastructure - operational	Distribution infrastructure - in progress	Other intangible assets	TOTAL
Intangible asset at January 1, 2009	-	2,386,304	395,247	2,802,271	387,645	80,677	6,052,144
Additions	4,048	32,290	646	1,001	666,192	12,748	716,925
Amortization	-	(186,899)	(3,672)	(344,193)	-	(13,363)	(548,127)
Transfer - intangible assets	-	-	-	428,103	(428,103)	-	-
Transfer - financial asset	-	-	-	-	(104,587)	-	(104,587)
Transfer - other assets	-	(45,915)	-	(7,841)	-	502	(53,254)
Intangible asset at December 31, 2009	4,048	2,185,780	392,221	2,879,341	521,147	80,564	6,063,101
Additions	2,007	38,286	11,395	5,133	1,159,601	41,146	1,257,568
Amortization	-	(182,615)	(5,633)	(351,690)	-	(12,878)	(552,816)
Transfer - intangible assets	-	-	-	806,904	(806,904)	-	-
Transfer - financial asset	-	-	-	-	(179,501)	-	(179,501)
Transfer - other assets	-	681	-	(3,919)	-	(237)	(3,475)
Intangible asset at December 31, 2010	6,055	2,042,132	397,983	3,335,769	694,343	108,595	6,584,877

In conformity with IAS 23, the interest on the loans taken out by the subsidiaries is capitalized to qualifying intangible assets. During 2010, R$ 48,099 was capitalized in the consolidated financial statements (R$ 28,825 in 2009) at a rate of 7.9% p.a. (6.3% p.a. in 2009).

15.3 Impairment test

For all the reporting periods, the Company assessed possible indications of devaluation of its assets that might involve the need for further impairment tests. The evaluation was based on external and internal information sources, taking into account variations in interest rates, changes in market conditions and other factors.

In analysis of impairment of intangible assets with an indefinite useful life (including goodwill), the Company used the value in use method to assess the recoverable value of each CGU. The cash flows were prepared in accordance with management's assessment of future trends in the electricity sector, based on external sources and historical data.

The result of the assessment indicated no signs of impairment of these assets in any of the reporting periods and there is no impairment loss to be recognized.

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( 16 )SUPPLIERS 

Current	December 31, 2010	December 31, 2009	January 1, 2009
System Service Charges	57,092	34,556	54,607
Energy purchased	584,114	658,068	645,718
Electricity Network Usage Charges	135,404	121,801	128,907
Materials and Services	199,129	143,180	116,228
Free Energy	70,262	61,341	28,731
Other	1,391	2,506	11,713
Total	1,047,392	1,021,452	985,904
Noncurrent
Electricity Network Usage Charges	-	42,655	85,311
Total	-	42,655	85,311

The noncurrent liability refers to charges related to the Use of the Distribution System and the changes are due mainly to the pass-through to CTEEP, as mentioned in Note 7.

( 17 )INTEREST ON DEBTS, LOANS AND FINANCING

	December 31, 2010				December 31, 2009				January 1, 2009
	Interest - Current and Noncurrent	Principal		Total	Interest - Current and Noncurrent	Principal		Total	Interest - Current and Noncurrent	Principal		Total
		Current	Noncurrent			Current	Noncurrent			Current	Noncurrent
Measured at cost
Brazilian currency
BNDES - Power increases	55	5,040	8,498	13,593	86	7,321	13,538	20,945	128	10,108	20,868	31,104
BNDES - Investment	8,494	329,994	3,016,363	3,354,851	11,204	362,902	2,476,242	2,850,348	36,819	258,265	2,271,735	2,566,819
BNDES - Other	1,028	72,123	146,414	219,565	49	661	5,628	6,338	30	194	3,356	3,580
Furnas Centrais Elétricas S.A.	-	-	-	-	379	46,028	-	46,407	1,158	93,666	46,833	141,657
Financial Institutions	50,277	144,624	1,255,312	1,450,213	10,408	194,766	164,054	369,228	5,241	52,879	209,066	267,186
Other	578	23,336	34,488	58,402	554	22,174	30,693	53,421	511	28,517	36,821	65,849
Subtotal	60,432	575,117	4,461,075	5,096,624	22,680	633,852	2,690,155	3,346,687	43,887	443,629	2,588,679	3,076,195
Foreign currency
BID	-	-	-	-	260	3,652	51,379	55,291	541	4,500	73,862	78,903
Financial Institutions	432	3,750	40,750	44,932	541	3,920	46,503	50,964	860	5,999	67,676	74,535
Subtotal	432	3,750	40,750	44,932	801	7,572	97,882	106,255	1,401	10,499	141,538	153,438
Total at Cost	60,864	578,867	4,501,825	5,141,556	23,481	641,424	2,788,037	3,452,942	45,288	454,128	2,730,217	3,229,633
Measured at fair value
Foreign currency
Financial Institutions	8,799	-	416,028	424,827	66,608	87,490	941,005	1,095,103	58,834	102,077	1,355,922	1,516,833
Total	8,799	-	416,028	424,827	66,608	87,490	941,005	1,095,103	58,834	102,077	1,355,922	1,516,833
Total	69,663	578,867	4,917,853	5,566,383	90,089	728,914	3,729,042	4,548,045	104,122	556,205	4,086,139	4,746,466

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Measured at cost	December 31, 2010	December 31, 2009	January 1, 2009	Annual interest	Amortization	Collateral
Brazilian currency
BNDES - Power increases
CPFL Geração	13,593	20,847	30,635	TJLP + 3.1% to 4.3%	36 to 84 monthly installments from February 2003 to December 2008	CPFL Energia and Paulista guarantee
CPFL Geração	-	98	469	UMBND + 4.0%	72 monthly installments from September 2004	CPFL Energia and Paulista guarantee
BNDES/BNB - Investment
CPFL Paulista - FINEM II	-	63,655	127,157	TJLP + 5.4%	48 monthly installments from January 2007	CPFL Energia guarantee and receivables
CPFL Paulista - FINEM III	80,711	107,614	134,356	TJLP + 3.3%	72 monthly installments from January 2008	CPFL Energia guarantee and receivables
CPFL Paulista - FINEM IV	256,572	237,325	100,498	TJLP + 3.28% to 3.4%	60 monthly installments from January 2010	CPFL Energia guarantee and receivables
CPFL Paulista - FINEM V	98,051	-	-	TJLP + 2.12% to 3.3%	72 monthly installments from February 2012	CPFL Energia guarantee and receivables
CPFL Paulista - FINEM V	35,135	-	-	Fixed rate 5.5% to 8.0%	114 monthly installments from August 2011	CPFL Energia guarantee and receivables
CPFL Paulista - FINAME	36,067	-	-	Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
CPFL Piratininga - FINEM I	-	23,702	47,349	TJLP + 5.4%	48 monthly installments from January 2007	CPFL Energia guarantee and receivables
CPFL Piratininga - FINEM II	47,945	63,927	79,813	TJLP + 3.3%	72 monthly installments from January 2008	CPFL Energia guarantee and receivables
CPFL Piratininga - FINEM III	106,944	104,990	54,768	TJLP + 3.28% to 3.4%	60 monthly installments from January 2010	CPFL Energia guarantee and receivables
CPFL Piratininga - FINEM IV	55,099	-	-	TJLP + 2.12% to 3.3%	72 monthly installments from February 2012	CPFL Energia guarantee and receivables
CPFL Piratininga - FINEM IV	13,081	-	-	Fixed rate 5.5% to 8.0%	114 monthly installments from August 2011	CPFL Energia guarantee and receivables
CPFL Piratininga - FINAME	22,905	-	-	Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
RGE - FINEM III	44,858	67,285	89,606	TJLP + 5.0%	60 monthly installments from January 2008	Receivables / Reserve account
RGE - FINEM IV	163,321	173,424	96,481	TJLP + 3.28 to 3.4%	60 monthly installments from January 2010	Receivables / CPFL Energia guarantee
RGE - FINEM V	59,967	-	-	TJLP + 2.12 to 3.3% a.a.	72 monthly installments from February 2012	Receivables / CPFL Energia guarantee
RGE - FINEM V	9,710	-	-	5.5% a.a. Fixed rate	96 monthly installments from February 2013	Receivables / CPFL Energia guarantee
RGE - FINAME	4,857	-	-	Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
CPFL Santa Cruz	10,483	2,255	2,275	TJLP + 2.90%	54 monthly installments from December 2010	CPFL Energia guarantee
CPFL Mococa	5,475	3,018	3,014	TJLP + 2.9%	54 monthly installments from January 2011	CPFL Energia guarantee and receivables
CPFL Jaguari	4,825	2,498	2,495	TJLP + 2.9%	54 monthly installments from December 2010	CPFL Energia guarantee and receivables
CPFL Leste Paulista	3,261	2,024	2,004	TJLP + 2.9%	54 monthly installments from June 2011	CPFL Energia guarantee and receivables
CPFL Sul Paulista	4,735	3,350	2,004	TJLP + 2.9%	54 monthly installments from June 2011	CPFL Energia guarantee and receivables
CPFL Geração	74,531	-	-	TJLP + 1.72%	192 monthly installments from September 2013	CPFL Energia and Paulista guarantee
BAESA	120,347	136,045	151,561	TJLP + 3.125% to 4.125%	144 monthly installments from September 2006	Pledge of shares, credit rights and revenue
BAESA	24,244	28,058	42,015	UMBND + 3.125%  (1)	144 monthly installments from November 2006	Pledge of shares, credit rights and revenue
ENERCAN	273,992	307,203	340,007	TJLP + 4%	144 monthly installments from April 2007	Letters of guarantee
ENERCAN	15,932	18,557	27,663	UMBND + 4%	144 monthly installments from April 2007	Letters of guarantee
CERAN	382,730	417,440	445,414	TJLP + 5%	168 monthly installments from December 2005	CPFL Energia guarantee
CERAN	53,845	60,981	87,085	UMBND + 5%  (1)	168 monthly installments from February 2006	CPFL Energia guarantee
CERAN	174,721	189,283	195,425	TJLP + 3.69%  (Average of percentage)	168 monthly installments from November 2008	CPFL Energia guarantee
Foz do Chapecó	996,013	792,209	535,829	TJLP + 2.49% to 2.95%	192 monthly installments from October 2011	Pledge of shares, credit and concession rights and revenue and CPFL Energia guarantee
CPFL Bioenergia - FINEM	39,512	15,248	-	TJLP + 1.9%	144 monthly installments from June 2011	Mortgage, credit rights and CPFL Energia guarantee
CPFL Bioenergia - FINAME	39,369	30,257	-	Fixed rate 4.5%	102 monthly installments from June 2011	Mortgage, credit rights and CPFL Energia guarantee
EPASA - BNB	95,613	-	-	Fixed rate 10%	132 monthly installments from January 2013	Bank guarantee
BNDES - Other
CPFL Brasil - Purchase of assets	6,785	6,338	3,580	TJLP + from 1.94% to 2.5%	36 monthly installments from May 2009	Tied to the asset acquired
CPFL Piratininga - Working capital	105,652	-	-	TJLP + 5.0% (2)	32 monthly installments from February 2011	No guarantee
CPFL Geração - FINEM - Working capital	53,232	-	-	TJLP + 4.95%	24 monthly installments from February 2011	CPFL Energia guarantee
CPFL Geração - FINAME - Working capital	53,896	-	-	TJLP + 4.95%  (3)	23 monthly installments from February 2011	CPFL Energia guarantee
Furnas Centrais Elétricas S.A.
CPFL Geração	-	46,407	141,657	IGP-M + 10%	24 monthly installments from June 2008	Energy produced by plant
Financial Institutions
CPFL Paulista
Banco do Brasil - Law 8727	34,874	39,314	47,548	IGP-M + 7.42%	240 monthly installments from May 1994	Receivables
Banco do Brasil	104,890	-	-	107% of CDI	1 installment in April 2015	CPFL Energia guarantee
Banco do Brasil-Rural Credit (*)	199,622	-	-	98.50% of CDI	4 annual installments from July 2012	CPFL Energia guarantee
CPFL Piratininga
Banco Alfa	-	50,017	-	105.1% of CDI	1 installment in January 2010	No guarantee
Banco do Brasil-Rural Credit (*)	18,360	-	-	98.5% of CDI	4 annual installments from July 2012	CPFL Energia guarantee
RGE
Banco do Brasil-Rural Credit (*)	236,830	-	-	98.5% of CDI	2 and 4 annual installments from July 2012	CPFL Energia guarantee
CPFL Brasil
FINEP	3,682	-	-	Fixed rate 5%	81 monthly installments from August 2011	Receivables
CPFL Santa Cruz
HSBC	45,206	40,747	36,677	CDI + 1.10%	1 installment in June 2011	CPFL Energia guarantee
Banco do Brasil-Rural Credit (*)	16,337	-	-	98.5% of CDI	2 annual installments from July 2012	CPFL Energia guarantee
CPFL Sul Paulista
Banco do Brasil-Rural Credit (*)	10,109	-	-	98.5% of CDI	2 annual installments from July 2012	CPFL Energia guarantee
CPFL Leste Paulista
Banco do Brasil-Rural Credit (*)	16,798	-	-	98.5% of CDI	2 annual installments from July 2012	CPFL Energia guarantee
CPFL Mococa
Banco do Brasil-Rural Credit (*)	8,476	-	-	98.5% of CDI	2 annual installments from July 2012	CPFL Energia guarantee
CPFL Jaguari
Banco do Brasil-Rural Credit (*)	1,786	-	-	98.5% of CDI	2 annual installments from July 2012	CPFL Energia guarantee
CPFL Geração
Banco Itaú  BBA	103,371	102,750	101,650	106.0% of CDI	1 installment in March 2011	CPFL Energia guarantee
Banco do Brasil	627,432	-	-	107.0% of CDI	1 installment in April 2015	CPFL Energia guarantee
Banco Alfa	-	99,485	-	105.1% of CDI	1 installment in April 2010	CPFL Energia guarantee
CERAN
Banco Bradesco	-	36,915	81,311	CDI + 2%	24 monthly installments from November 2008	No guarantee
Banco Bradesco	22,440	-	-	CDI + 1.75%	1 installment in April 2012	No guarantee

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Other
Eletrobrás
CPFL Paulista	10,358	8,648	8,887	RGR + 6.0% to 9.0%	Monthly installments up to July 2016	Receivables and promissory notes
CPFL Piratininga	925	1,415	1,903	RGR + 6%	Monthly installments up to July 2016	Receivables and promissory notes
RGE	18,097	12,095	11,309	RGR + 6%	Monthly installments up to June 2020	Receivables and promissory notes
CPFL Santa Cruz	3,947	4,660	5,509	RGR + 6%	Monthly installments up to April 2018	Receivables and promissory notes
CPFL Leste Paulista	1,096	1,011	1,136	RGR + 6%	Monthly installments up to February 2022	Receivables and promissory notes
CPFL Sul Paulista	1,837	1,779	1,694	RGR + 6%	Monthly installments up to July 2018	Receivables and promissory notes
CPFL Jaguari	109	31	35	RGR + 6%	Monthly installments up to May 2017	Receivables and promissory notes
CPFL Mococa	415	285	321	RGR + 6%	Monthly installments up to February 2022	Receivables and promissory notes
Other	21,618	23,497	35,055
Subtotal Brazilian Currency - Cost	5,096,624	3,346,687	3,076,195
Foreign Currency
BID - Enercan	-	55,291	78,903	US$ + Libor + 3.5%	49 quarterly installments from June 2007	CPFL Energia guarantee
Financial Institutions
CPFL Paulista (5)
Debt Conversion Bond	2,982	5,207	9,807	US$ + Libor 6 months + 0.875%	17 semiannual installments from April 2004	Revenue/Government SP guaranteed
New Money Bond	-	-	370	US$ + Libor 6 months+ 0.875%	17 semiannual installments from April 2001	Revenue/Government SP guaranteed
FLIRB	-	-	375	US$ + Libor 6 months+ 0.8125%	14 semiannual installments from April 2003	Revenue/Government SP guaranteed
C-Bond	6,298	8,462	13,881	US$ + 8%	21 semiannual installments from April 2004	Revenue/Government SP guaranteed
Discount Bond	14,570	15,264	20,533	US$ + Libor 6 months + 0.8125%	1 installment in April 2024	Escrow deposits and revenue/ Gov.SP guarantee
PAR-Bond	21,082	22,031	29,569	US$ + 6%	1 installment in April 2024	Escrow deposits and revenue/ Gov.SP guarantee
Subtotal Foreign Currency - Cost	44,932	106,255	153,438
Total Measured at cost	5,141,556	3,452,942	3,229,633
Foreign Currency
Measured at fair value
Financial Institutions
CPFL Paulista
Banco do Brasil	-	101,233	131,435	Yen + 5.7778%	1 installment in January 2011	No guarantee
Banco ABN AMRO Real	424,827	385,969	490,276	Yen +1.49% (4)	1 installment in January 2012	No guarantee
CPFL Piratininga
Banco BNP Paribas	-	-	60,548	US$ + 4.10% .	1 installment in February 2009	Promissory notes
RGE
Banco do Brasil	-	-	46,687	103.5% CDI	1 installment in September 2009	No guarantee
CPFL Geração
Banco do Brasil	-	101,332	131,564	Yen + 5.8% .	1 installment in April 2010	CPFL Energia guarantee
Banco do Brasil	-	506,569	656,323	Yen + 2.5% to 5.8% .	1 installment in January 2011	CPFL Energia guarantee
Total Foreign Currency - fair value	424,827	1,095,103	1,516,833
Total - Consolidated	5,566,383	4,548,045	4,746,466
The subsdiaries hold  swaps converting the operating cost of currency variation to interest tax variation in reais, corresponding to :
(1) 160.5% of the CDI	(3) 106.0% of the CDI
(2) 106.0% to 106.5% of the CDI	(4) 104.98% of the CDI
(5) As certain assets are dollar indexed, a partial swap of R$ 21,221 was contracted, converting the currency variation to 105.95% of the CDI.
(*) Effective rate: 98.5% CDI + 2.88% p.a. (CPFL Paulista and CPFL Piratininga) and 98.5% CDI + 2.5% p.a. (RGE)

In conformity with IAS 39 and 32 (Financial Instruments), the Company and its subsidiaries classified their debts, as segregated in the tables above, as (i) financial liabilities not measured at fair value (or measured at cost), and (ii) financial liabilities measured at fair value through profit or loss.

The objective of classification of financial liabilities measured at fair value is to compare the effects of recognition of income and expense derived from marking hedge derivatives to market, tied to the debts, in order to obtain more relevan and consistent accounting information. At December 31, 2010, the total balance of the debt measured at fair value was R$ 424,827 (R$ 1,095,103 at December 31, 2009), and the amount related to the cost was R$ 429,792 (R$ 1,100,120 at December 31, 2009).

The changes in the fair values of these debts are recognized in the financial income (expense) of the Company and its subsidiaries. The gains of R$ 4,965 (gain of R$ 5,017 in 2009) obtained by marking the debts to market are offset by the effects of R$ 7,607 (R$ 12,428 in 2009) obtained by marking to market the derivative financial instruments contracted as a hedge against exchange variations (Note 34), resulting in a net accumulated loss of R$ 2,642 (R$ 7,411 in 2009).

Main fund-raising in the period:

Brazilian currency

BNDES – Investment:

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- FINEM IV (CPFL Paulista) - The subsidiary obtained financing of R$ 345,990 from the BNDES in 2008, part of a FINEM credit line, to be invested in expanding and upgrading the Electricity System. The amount of R$ 72,761 was released during 2010 and the outstanding balance of R$ 37,101 was not utilized by the subsidiary.

- FINEM V (CPFL Paulista) – The subsidiary received approval for financing of R$ 291,043 from the BNDES in 2010, part of a FINEM credit line, to be invested in implementation of the investment plan for the second half-year of 2010 and for 2011. The subsidiary received the amount of R$ 133,072 during the year and the outstanding balance of R$ 157,971 is scheduled for release by the end of 2011.

- FINEM IV (CPFL Piratininga) – The subsidiary received approval for financing from the BNDES in 2010, of R$ 165,621 part of a FINEM credit line, to be used for the implementation of the investment plan for the second half-year of 2010 and for 2011. The subsidiary received the amount of R$ 68,120 during the year, and the outstanding balance of R$ 97,501 is scheduled for release by the end of 2011. The interest will be paid quarterly during the grace period and monthly during the amortization term.

- FINEM V (RGE) – The subsidiary received approval for financing of R$ 167,861 from the BNDES in 2010, part of a FINEM credit line, to be invested in implementation of the investment plan for the second half-year of 2010 and for 2011. The amount of R$ 69,616 was received during the year and the outstanding balance of R$ 98,245 is scheduled for release by the end of 2011.

- FINAME (CPFL Paulista) – The subsidiary received approval for financing from the BNDES in 2009, of R$ 92,183 part of a FINAME credit line, to be invested in acquisition of equipment for the Electricity System in 2010 and 2011. The subsidiary received the amount of R$ 36,014 in 2010, and the outstanding balance of R$ 56,169 is scheduled for release by the end of 2011. The interest will be paid quarterly, and amortized monthly from January 15, 2012.

- FINAME (CPFL Piratininga) – The subsidiary received approval for financing of R$ 48,116 from the BNDES in 2009, part of a FINAME credit line, to be invested in to acquire equipment for the Electricity System in 2010 and 2011. The amount of R$ 22,860 was received in 2010 and the outstanding balance of R$ 25,257 is scheduled for release by the end of 2011. The interest will be paid quarterly, and amortized monthly from January 15, 2012. There are no restrictive covenants.

- FINEM/FINAME (Bioenergia) – the indirect subsidiary received approval for financing of a total amount of R$ 75,297 from the BNDES in 2009, comprised of R$ 37,491 from FINEM and R$ 37,806 from FINAME, to be invested in construction of the Thermoelectric Plant. The outstanding balance of R$ 29,805 was released in 2010, comprising R$ 22,250 from FINEM and R$ 7,555 from FINAME.  The interest is capitalized during the grace period and will be paid monthly from June 2011, together with the installment of the principal.

- Investment (CPFL Geração) – The subsidiary obtained approval for FINEM financing of R$ 574,098 from the BNDES in 2010, to be invested in the subsidiaries Santa Clara I to VI and Eurus VI for construction and installation of the wind power complex, with a total installed capacity of 188 MW, in the municipality of Parazinho, State of Rio Grande do Norte. The amount of R$ 75,538 was released in 2010.

- Investment (Foz do Chapecó) – The subsidiary obtained financing of R$ 1,633.155 from the BNDES, in 2007, (R$ 832,909 in proportion to the participation of the subsidiary CPFL Geração), to be invested in financing the construction work on the Foz do Chapecó Hydroelectric Power Plant. The amount ofR$ 249,841 was released in 2010 (R$ 127,419 in proportion to the participation of the subsidiary CPFL Geração) to complete construction of the hydropower plant. The interest and principal will be paid monthly from October 2011.

- BNB – Investment (EPASA) – In December 2009, the indirect subsidiarycontracted a loan of R$ 214,278 (R$ 109,282 in proportion to the Company's participation) from Banco Nordeste do Brasil – BNB, tobe invested in the construction of the Termoparaíba and Termonordeste thermoelectric power plants.The amount ofR$ 190,439 was released in 2010 (R$ 97,124 in proportion to the Company’s participation) andrelease of the outstanding balance is conditional upon physical and financial verification of the funds obtained. The interest will be paid quarterly to December 2012 and monthly from January 2013. There are no restrictive covenants for this financing agreement.

BNDES – Other:

- Working capital (CPFL Piratininga) - The subsidiary obtained financing of R$ 100,000 from the BNDES in 2010, in two installments of R$ 50,000, part of a BNDES pass-through credit line with Banco Bradesco, to reinforce the cash position. The interest will be capitalized monthly during the grace period, to February 15, 2011 and October17, 2011, and will be paid monthly, together with the installments of the principal, in 24 installments from February 15, 2011 and October 17, 2011, respectively. There are no restrictive covenants.

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- Working capital (CPFL Geração) - The subsidiary obtained financing of R$ 100,000 from the BNDES in 2010, in two installments of R$ 50,000, part of a BNDES pass-through credit line with the Banco do Brasil, to reinforce its cash position. The interest will be capitalized monthly during the grace period, to February 15, 2011 and July 17, 2011 and will be paid monthly, together with the installments of the principal, in 24 installments from February 15, 2011 and July 17, 2011, respectively. There are no restrictive covenants.

Financial institutions:

- Banco do Brasil – Crédito Rural (CPFL Paulista, CPFL Piratininga, RGE, CPFL Santa Cruz, CPFL Leste Paulista, CPFL Mococa, CPFL Jaguari and CPFL Sul Paulista) - these subsidiaries obtained approval for rural credit financing, of which a total amount of R$ 499,800 was released (R$ 435,849 net of costs), to cover working capital. The interest will be capitalized monthly and amortized together with the installments of the principal.

-CPFL Paulista and CPFL Geração –in 2010, the subsidiaries CPFL Paulista and CPFL Geração renewed debts to the Banco do Brasil. The objective of the renewals was to extend the maturities of the loans, and also resulted in changes in the rates, which are now tied to the CDI. The interest will be paid half-yearly from October 2010.

The maturities of the principal long-term balances of loans and financing, taking into consideration only the amounts recorded at cost, are scheduled as follows:

Maturity
2012	1,166,436
2013	649,914
2014	463,383
2015	1,044,681
2016	246,573
After 2016	1,351,831
Subtotal	4,922,818
Marked to Market	(4,965)
Total	4,917,853

The main financial rates used for restatement of Loans and Financing and the breakdown of the indebtedness in local and foreign currency, taking into consideration the effects of translation of the derivative instruments, are shown below:

	Accumulated variation - %			% of debt
Index	December 31, 2010	December 31, 2009	January 1, 2009	December 31, 2010	December 31, 2009	January 1, 2009
IGP-M	11.32	(1.71)	9.81	0.77	2.12	4.24
UMBND	0.72	(25.66)	33.86	1.69	3.29	5.62
TJLP	6.00	6.13	6.25	58.23	58.76	49.74
CDI	9.71	9.88	12.38	33.80	34.01	38.93
SELIC	9.91	12.48	-	-	-	-
Other	-	-	-	5.53	1.82	1.47
				100	100	100

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RESTRICTIVE COVENANTS

BNDES:

Financing from the BNDES restricts the subsidiaries CPFL Paulista, CPFL Piratininga and RGE to: (i) not paying dividends and interest on shareholders’ equity totaling more than the minimum mandatory dividend laid down by law without prior agreement of the BNDES, and the lead bank in the operation; (ii) full compliance with the restrictive conditions established in the agreement; and (iii) maintaining certain financial ratios within pre-established parameters, as follows:

CPFL Paulista

·Net indebtedness divided by EBITDA – maximum of 3.0;

·Net indebtedness divided by the sum of net indebtedness and net equity – maximum of 0.90.

CPFL Piratininga

·Net indebtedness divided by EBITDA – maximum of 2.5;

·Net indebtedness divided by the sum of net indebtedness and net equity – maximum of 0.80.

RGE

·Net indebtedness divided by EBITDA – maximum of 2.5;

·Net indebtedness divided by the sum of net indebtedness and net equity – maximum of 0.5.

CPFL Geração

The loans from theBNDES raised by the subsidiary CERAN and the jointly-owned subsidiaries ENERCAN, BAESA and Foz do Chapecóestablish restrictions on the payment of dividends to the subsidiary CPFL Geraçãohigher than the minimum mandatory dividend of 25% without the prior agreement of the BNDES.

The loan agreement for CPFL Bioenergia’s loan from BNDES, stipulates that the subsidiary may not pay out dividends for the years of 2009 to 2012, and may only do so from 2013 onwards if all the following conditions are met:

i)Full compliance with its contractual obligations;

ii)Minimum debt coverage ratio of 1.0 ; and

iii)Maximum overall Indebtedness ratio of 0.8

Banco do Brasil – Crédito Rural

·Net indebtedness divided by EBITDA – maximum of3.0. 

Other loan and financing agreements of the direct and indirect subsidiaries are subject to early settlement in the event of changes in the Company’s structure or in the corporate structure of the subsidiaries that result in the loss of the share control or of control over management of the Company by the Company’s current shareholders.

Furthermore, failure to comply with the obligations or restrictions mentioned could result in default in relation to other contractual obligations (cross default).

The Management of the Company and its subsidiaries monitor these ratios systematically and constantly to ensure that the contractual conditions are complied with. In the opinion of the management, these restrictive covenants and clauses are being adequately complied with.

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( 18 )DEBENTURES 

	December 31, 2010				December 31, 2009				January 1, 2009
	Interest	Current	Noncurrent	Total	Interest	Current	Noncurrent	Total	Interest	Current	Noncurrent	Total
Parent Company
3rd Issue
Single series	15,529	-	450,000	465,529	12,788	-	450,000	462,788	20,047	-	450,000	470,047
CPFL Paulista
2nd Issue
1st Series	-	-	-	-	-	-	-	-	8,606	119,680	-	128,286
2nd Series	-	-	-	-	-	-	-	-	8,430	170,599	-	179,029
3rd Issue
1st Series	5,925	213,333	426,667	645,925	4,618	-	640,000	644,618	7,083	-	640,000	647,083
4th Issue
Single series	6,322	109,601	-	115,923	8,285	64,303	109,601	182,189	-	-	-	-
	12,248	322,934	426,667	761,849	12,903	64,303	749,601	826,807	24,119	290,279	640,000	954,398
CPFL Piratininga
1st Issue
1st Series	10,733	200,000	-	210,733	17,690	200,000	200,000	417,690	27,176	-	400,000	427,176
2nd Issue
Single series	-	-	-	-	2,189	-	100,000	102,189	3,479	-	100,000	103,479
3rd Issue
Single series	7,013	-	258,868	265,881	-	-	-	-	-	-	-	-
4th Issue
Single series	1,845	-	278,043	279,888	-	-	-	-	-	-	-	-
	19,591	200,000	536,911	756,502	19,879	200,000	300,000	519,879	30,655	-	500,000	530,655
RGE
2nd Issue
1st Series	2,019	28,370	-	30,389	1,630	-	26,200	27,830	2,033	1,903	26,200	30,136
2nd Series	-	-	-	-	-	-	-	-	7,058	203,800	-	210,858
3rd Issue
1st Series	939	33,333	66,667	100,939	741	-	100,000	100,741	1,110	-	100,000	101,110
2nd Series	7,721	46,667	93,333	147,721	6,437	-	140,000	146,437	9,671	-	140,000	149,671
3rd Series	1,824	13,333	26,667	41,824	1,491	-	40,000	41,491	2,290	-	40,000	42,290
4th Series	1,335	16,667	33,333	51,335	1,103	-	50,000	51,103	1,711	-	50,000	51,711
5th Series	1,335	16,667	33,333	51,335	1,103	-	50,000	51,103	1,711	-	50,000	51,711
4th Issue
Single series	10,633	184,623	-	195,256	8,758	-	183,804	192,562	-	-	-	-
	25,806	339,660	253,333	618,799	21,263	-	590,004	611,267	25,584	205,703	406,200	637,487
CPFL Leste Paulista
1st Issue
Single series	1,400	23,965	-	25,365	1,153	-	23,894	25,047	-	-	-	-
CPFL Sul Paulista
1st Issue
Single series	926	15,979	-	16,905	762	-	15,936	16,698	-	-	-	-
CPFL Jaguari
1st Issue
Single series	583	9,983	-	10,566	480	-	9,948	10,428	-	-	-	-
CPFL Brasil
1st Issue
Single series	9,545	164,728	-	174,273	7,862	-	164,221	172,083	-	-	-	-
CPFL Geração
2nd Issue
Single series	24,327	424,266	-	448,593	20,039	-	423,295	443,334	646	80,930	-	81,576
3rd Issue
Single series	7,121	-	263,137	270,258	-	-	-	-	-	-	-	-
EPASA
1st Issue
Single series	-	-	-	-	3,504	228,473	-	231,977	-	-	-	-
2nd Issue
Single series	-	-	204,406	204,406	-	-	-	-	-	-	-	-
BAESA
1st Series	357	3,165	15,030	18,552	308	3,164	18,195	21,667	532	3,164	21,359	25,055
2nd Series	294	2,569	12,207	15,070	343	3,085	6,075	9,503	530	-	9,331	9,861
Enercan
1st Series	339	2,711	50,623	53,673	-	-	-	-	-	-	-	-
	990	8,445	77,860	87,295	651	6,249	24,270	31,170	1,062	3,164	30,690	34,916
	118,066	1,509,960	2,212,314	3,840,340	101,284	499,025	2,751,169	3,351,478	102,113	580,076	2,026,890	2,709,079
The Company and its subsdiaries hold  swap converting the local cost of currency variation to interest tax variation in reais, corresponding to
(1) 104.4% of CDI
(2) 105.07% of CDI

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Interest

Interest on the debentures will be paid half yearly, except for: (i) 1^st series of the jointly-owned subsidiary BAESA, which will be paid quarterly; (ii) 1^st issue of the subsidiary CPFL Piratininga and 1^st series of the 2^nd issue of the subsidiary RGE, which will be paid annually and (iii) 2^nd issue of the jointly-owned subsidiary EPASA which will be paid monthly (2012).

The maturities of the long-term balance of debentures are scheduled as follow: 

Maturity
2012	553,552
2013	777,436
2014	159,393
2015	681,398
2016	7,834
After 2016	32,701
Total	2,212,314

RESTRICTIVE COVENANTS

The debentures are subject to certain restrictive covenants and include clauses that require the Company and its subsidiaries to maintain certain financial ratios within pre-established parameters. The main ratios are as follows:

CPFL Energia

·Net indebtedness divided by EBITDA – maximum of 3.75;

·EBITDA divided by Financial Income (Expense) – minimum of 2.25;

CPFL Paulista

·Net indebtedness divided by EBITDA – maximum of 3.0;

·EBITDA divided by Financial Income (Expense) – minimum of 2.25;

CPFL Piratininga

·Net indebtedness divided by EBITDA – maximum of 3.0;

·EBITDA divided by Financial Income (Expense) – minimum of 2.25;

RGE

·Net indebtedness divided by EBITDA – maximum of 3.0;

·EBITDA divided by Financial Income (Expense) – minimum of 2.0;

CPFL Geração

·Net indebtedness divided by EBITDA – maximum of 3.5;

·EBITDA divided by Financial Income (Expense) – minimum of 2.0;

CPFL Brasil

·Net indebtedness divided by EBITDA – maximum of 3.0;

·EBITDA divided by Financial Income (Expense) – minimum of 2.25;

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CPFL Jaguari

·Net indebtedness divided by EBITDA – maximum of 3.0;

·EBITDA divided by Financial Income (Expense) – minimum of 2.25;

CPFL Leste Paulista

·Net indebtedness divided by EBITDA – maximum of 3.0;

·EBITDA divided by Financial Income (Expense) – minimum of 2.0;

CPFL Sul Paulista

·Net indebtedness divided by EBITDA – maximum of 3.0;

·EBITDA divided by Financial Income (Expense) – minimum of 2.25;

BAESA

·Total indebtedness– restricted to 75% of their total assets.

Certain debentures of subsidiaries and jointly-owned subsidiaries are subject to early settlement in the event of changes in the Company’s structure or in the corporate structure of the subsidiaries that result in the loss of the share control or of control over management of the Company by theCompany’s current shareholders.

Failure to comply with the restrictions mentioned could result in default in relation to other contractual obligations (cross default).

In the opinion of the management of the Company and its subsidiaries and jointly-owned subsidiaries, these restrictive covenants and clauses are being adequately complied with.

( 19 )PRIVATE PENSION FUND

The subsidiaries CPFL Paulista, CPFL Piratininga and CPFL Geração, through Fundação CESP, the subsidiary RGE, through Fundação CEEE de Seguridade Social – ELETROCEEE and Bradesco Vida e Previdência, the subsidiary CPFL Santa Cruz through BB Previdência – Fundo de Pensão Banco do Brasil and the subsidiary CPFL Jaguariúna through IHPREV Fundo de Pensão, sponsor supplementary retirement and pension plans for their employees.

19.1 – Characteristics

- CPFL Paulista

The plan currently in force for the employees of the subsidiary CPFL Paulista is a Mixed Benefit Plan, with the following characteristics:

a)Defined Benefit Plan (“BD”) – in force until October 31, 1997 – a defined benefit plan, which grants a Proportional Supplementary Defined Benefit (BSPS), in the form of a lifetime income convertible into a pension, to participants enrolled prior to October 31, 1997, the amount being defined in proportion to the accumulated past service time up to that date, based on compliance with the regulatory requirements for granting. The total responsibility for coverage of actuarial deficits of this plan falls to the subsidiary.

b)Mixed model, as from November 1, 1997, which covers:

·benefits for risk (disability and death), under a defined benefit plan, in which the subsidiary assumes  responsibility for Plan’s actuarial deficit, and

·scheduled retirement, under a defined contribution plan, consisting of a benefit plan, which is a defined contribution plan up to the granting of the income, and does not generate any actuarial liability for the subsidiary CPFL Paulista. The benefit plan only becomes a defined benefit plan, consequently generating actuarial responsibility for the subsidiary, after the granting of a lifetime income, convertible or not into a pension.

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As a result of modification of the Retirement Plan in October 1997, a liability was recognized as payable by the subsidiary CPFL Paulista in relation to the plan deficit calculated by the external actuaries of Fundação CESP.  The liability, to be settled in 260 installments plus interest of 6% p.a. and restatement at the IGP-DI rate (FGV), is amortized on a monthly basis. Under the Contractual Amendment signed with Fundação CESP on January 17, 2008, the payment terms were amended to 238 monthly installments and 19 annual installments, as of the base date of December 31, 2007, with final maturity on October 31, 2027. The balance of the obligation at December 31, 2010 is R$ 479,877 (R$ 508,706 in 2009). The contract amount differs from the carrying amount recorded by the subsidiary, which is in conformity with IAS 19.

Managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Bradesco.

- CPFL Piratininga

As a result of the spin-off of Bandeirante Energia S.A. (the subsidiary’s predecessor), the subsidiary CPFL Piratininga assumed the responsibility for the actuarial liabilities for its retired and discharged employees up to the date of the spin-off, as well as the responsibilities relating to the active employees transferred to CPFL Piratininga.

On April 2, 1998, the Supplementary Welfare Office – “SPC”, approved the restructuring of the retirement plan previously maintained by Bandeirante, creating a "Proportional Supplementary Defined Benefit Plan – BSPS”, and a "Mixed Benefit Plan", with the following characteristics:

a) Defined Benefit Plan (“BD”) - in force until March 31, 1998 – a defined-benefit plan, which concedes a Proportional Supplementary Defined Benefit (BSPS), in the form of a lifetime income convertible into a pension to participants registered up to March 31, 1998, to an amount calculated in proportion to the accumulated past service time up to that date, based on compliance with the regulatory requirements for granting. In the event of death while working or the onset of a disability, the benefits incorporate the entire past service time. CPFL Piratininga has full responsibility for covering the actuarial deficits of this Plan.

b) Defined Benefit Plan - in force after March 31, 1998 – defined-benefit type plan, which concedes a lifetime income convertible into a pension based on the past service time accumulated after March 31, 1998, based on 70% of the average actual monthly salary for the last 36 months of active service. In the event of death while working or the onset of a disability, the benefits incorporate the entire past service time (including the accumulated time up to March 31, 1998). The responsibility for covering the actuarial deficits of this Plan is equally divided between CPFL Piratininga and the participants.

c) Defined Contribution Plan – implemented together with the Defined Benefit plan effective after March 31, 1998.  This is a defined-benefit type pension plan up to the granting of the income, and generates no actuarial liability for CPFL Piratininga. The pension plan only becomes a Defined Benefit type plan after the concession of the lifetime income, convertible (or not) into a pension, and accordingly starts to generate actuarial liabilities for the subsidiary.

In September 1997, through a contractual instrument of adjustment of reserves to be amortized, Eletropaulo Metropolitana El. São Paulo S.A. (the predecessor of Bandeirante) recognized an obligation to pay referring to the plan deficit determined at the time by the external actuaries of the Fundação CESP, to be liquidated in 260 installments, amortized monthly, plus interest of 6% p.a. and restatement at the IGP-DI rate (FGV). Under the Contractual Amendment, signed with Fundação CESP on January 17, 2008, the payment terms were amended to 221 monthly payments and 18 annual installments, as of December 31, 2007, with final maturity on May 31, 2026. The balance of the obligation at December 31, 2010 is R$ 133,170 (R$ 150,444 in 2009). The contract amount differs from the carrying amount recorded by the subsidiary, which is in conformity with IAS 19.

Managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Bradesco.

- RGE

A defined benefit type plan, with a benefit level equal to 100% of the adjusted average of the most recent salaries, less the presumed Social Security benefit, with a Segregated Net Asset administered by ELETROCEEE. Only those whose work contracts were transferred from CEEE to RGE are entitled to this benefit. A private pension plan was set up in January 2006 with Bradesco Vida e Previdência for employees admitted from 1997.

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- CPFL Santa Cruz

The benefits plan of the subsidiary CPFL Santa Cruz, administered by BB Previdência - Fundo de Pensão do Banco do Brasil, is a defined contribution plan.

- CPFL Jaguariúna

In December 2005, the companies joined the CMSPREV private pension plan, administered by IHPREV Pension Fund. The plan is structured as a defined contribution plan.

- CPFL Geração

The employees of the subsidiary CPFL Geração belong to the same pension plan as CPFL Paulista.

With the modification of the Retirement Plan, at that point maintained by CPFL Paulista, in October 1997, a liability was recognized as payable by the subsidiary CPFL Geração, in relation to the plan deficit calculated by the external actuaries of Fundação CESP, to be amortized in 260 monthly installments, plus interest of 6% p.a. and restatement at the IGP-DI rate (FGV). Under the Contractual Amendment, signed with Fundação CESP on January 17, 2008, the payment terms were amended to 238 monthly installments and 19 annual installments, as of December 31, 2007, with final maturity on October 31, 2027. The balance of the obligation at December 31, 2010 is R$ 17,689 (R$ 18,354 in 2009). The contract amount differs from the carrying amount recorded by the subsidiary, which is in conformity with IAS 19.

19.2 – Changes in the defined benefit plans

	December 31, 2010
	CPFL	CPFL	CPFL	Total liability	RGE	Total asset
	Paulista	Piratininga	Geração
Present value of actuarial liabilities	3,088,723	784,933	67,543	3,941,199	207,759	207,759
Fair value of plan's assets	(2,987,448)	(785,231)	(70,177)	(3,842,856)	(245,537)	(245,537)
Present value of liabilities (fair value of assets), net	101,275	(298)	(2,634)	98,343	(37,778)	(37,778)
Adjustments due to deferments allowed
Unrecognized actuarial gains	368,348	111,872	14,086	494,306	31,978	31,978
Net actuarial Liabilities (assets) recognized on balance sheet	469,623	111,574	11,452	592,649	(5,800)	(5,800)
	December 31, 2009
	CPFL	CPFL	CPFL	Total liability	RGE	Total asset
	Paulista	Piratininga	Geração
Present value of actuarial liabilities	2,962,118	760,719	64,198	3,787,035	182,615	182,615
Fair value of plan assets	(2,611,813)	(676,790)	(54,969)	(3,343,572)	(212,369)	(212,369)
Present value of liabilities (fair value of assets), net	350,305	83,929	9,229	443,463	(29,754)	(29,754)
Adjustments due to deferments allowed
Unrecognized actuarial gains	241,407	58,035	4,545	303,987	20,029	20,029
Net actuarial liabilities (assets) recognized in balance sheet	591,712	141,964	13,774	747,450	(9,725)	(9,725)
	January 1, 2009
	CPFL	CPFL	CPFL	Total liability	RGE	Total asset
	Paulista	Piratininga	Geração
Present value of actuarial liabilities	3,067,116	774,598	66,094	3,907,808	174,721	174,721
Fair value of plan assets	(2,413,252)	(618,671)	(51,207)	(3,083,130)	(180,708)	(180,708)
Present value of liabilities (fair value of assets), net	653,864	155,927	14,887	824,678	(5,987)	(5,987)
Adjustments due to deferments allowed
Unrecognized actuarial gains	-	-	-	-	5,987	5,987
Net actuarial liabilities (assets) recognized in balance sheet	653,864	155,927	14,887	824,678	-	-

The changes in present value of the actuarial obligations and the fair values of the plan assets are as follows:

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	CPFL	CPFL	CPFL	RGE	Total liability
	Paulista	Piratininga	Geração
Present value of actuarial liabilities at January 1, 2009	3,067,116	774,598	66,094	174,721	4,082,529
Gross current service cost	1,413	4,172	165	152	5,902
Interest on actuarial obligation	303,015	76,981	6,532	17,626	404,154
Participants' contributions transferred during the year	68	1,249	2	1,104	2,423
Actuarial (Gain)/loss	(195,082)	(51,310)	(4,138)	(3,456)	(253,986)
Benefits paid during the year	(214,412)	(44,971)	(4,457)	(7,532)	(271,372)
Present value of actuarial liabilities at December 31, 2009	2,962,118	760,719	64,198	182,615	3,969,650
Gross current service cost	1,061	3,550	142	202	4,955
Interest on actuarial obligation	292,456	75,535	6,345	18,349	392,685
Participants' contributions transferred during the year	190	1,156	1	1,597	2,944
Actuarial (Gain)/loss	64,883	(9,660)	1,794	12,346	69,363
Benefits paid during the year	(231,985)	(46,367)	(4,937)	(7,350)	(290,639)
Present value of actuarial liabilities at December 31, 2010	3,088,723	784,933	67,543	207,759	4,148,958

	CPFL	CPFL	CPFL	RGE	Total asset
	Paulista	Piratininga	Geração
Present value of actuarial assets at January 1, 2009	(2,413,252)	(618,671)	(51,207)	(180,708)	(3,263,838)
Expected return during the year	(304,351)	(77,554)	(6,468)	(18,378)	(406,751)
Participants' contributions transferred during the year	(68)	(1,249)	(2)	(1,104)	(2,423)
Sponsors' contributions	(62,229)	(17,562)	(1,342)	(3,138)	(84,271)
Actuarial (gain)/loss	(46,325)	(6,725)	(407)	(16,573)	(70,030)
Benefits paid during the year	214,412	44,971	4,457	7,532	271,372
Current value of actuarial assets at December 31, 2009	(2,611,813)	(676,790)	(54,969)	(212,369)	(3,555,941)
Expected return during the year	(364,286)	(93,152)	(7,679)	(23,718)	(488,835)
Participants' contributions transferred during the year	(190)	(1,156)	(1)	(1,597)	(2,944)
Sponsors' contributions	(51,320)	(16,323)	(1,129)	(9,084)	(77,856)
Actuarial (gain)/loss	(191,824)	(44,177)	(11,336)	(6,119)	(253,456)
Benefits paid during the year	231,985	46,367	4,937	7,350	290,639
Current value of actuarial assets at December 31, 2010	(2,987,448)	(785,231)	(70,177)	(245,537)	(4,088,393)

19.3 Changes in the assets and liabilities recognized:

The changes in net liabilities are as follows:

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	December 31, 2010				December 31, 2010
	CPFL	CPFL	CPFL	Total liability	RGE	Total asset
	Paulista	Piratininga	Geração
Actuarial liabilities /(assets) at the beginning of the year	591,712	141,964	13,774	747,450	(9,725)	(9,725)
Expense (Income) recognized in income statement	(70,769)	(14,068)	(1,192)	(86,029)	5,400	5,400
Sponsors' contributions transferred during the year	(51,320)	(16,322)	(1,130)	(68,772)	(1,475)	(1,475)
Actuarial liabilities /(assets) at the end of the year	469,623	111,574	11,452	592,649	(5,800)	(5,800)
Other contributions	13,875	375	177	14,427	-	-
Subtotal	483,498	111,949	11,629	607,076	(5,800)	(5,800)
Other contributions RGE	-	-	-	3,905
Total liabilities	483,498	111,949	11,629	610,981
Current				40,103		-
Noncurrent				570,878		5,800

	December 31, 2009				December 31, 2009
	CPFL	CPFL	CPFL	Total liability	RGE	Total asset
	Paulista	Piratininga	Geração
Actuarial liabilities /(assets) at the beginning of the year	653,864	155,927	14,887	824,678	-	-
Expense (Income) recognized in income statement	77	3,599	229	3,905	(6,971)	(6,971)
Sponsors' contributions transferred during the year	(62,229)	(17,562)	(1,342)	(81,133)	(2,754)	(2,754)
Actuarial liabilities /(assets) at the end of the year	591,712	141,964	13,774	747,450	(9,725)	(9,725)
Other contributions	13,342	243	281	13,866	-	-
Subtotal	605,054	142,207	14,055	761,316	(9,725)	(9,725)
Other contributions RGE	-	-	-	6,454
Total liabilities	605,054	142,207	14,055	767,770
Current				44,484		-
Noncurrent				723,286		9,725

19.4 Recognition of income and expense of private pension fund:

The external actuary’s estimate of the expense and/or revenue to be recognized in 2011 and the income recognized in 2010 is as follows:

	2011 Estimated
	CPFL	CPFL	CPFL	Consolidated
	Paulista	Piratininga	Geração
Cost of service	1,043	3,781	136	4,960
Interest on actuarial obligations	304,730	77,929	6,673	389,332
Expected return on plan assets	(369,344)	(97,889)	(8,706)	(475,939)
Amortization of unrecognized actuarial gains	(4,730)	(2,448)	(585)	(7,763)
Total income	(68,301)	(18,627)	(2,482)	(89,410)

	2010 Realized
	CPFL	CPFL	CPFL	RGE	Consolidated
	Paulista	Piratininga	Geração
Cost of service	1,061	3,550	142	1,153	5,906
Interest on actuarial obligations	292,456	75,534	6,345	18,349	392,684
Expected return on plan assets	(364,286)	(93,152)	(7,679)	(23,717)	(488,834)
Recognition of the asset (limited to paragraph 58-b of CPC 33)	-	-	-	9,615	9,615
Total Expense (Income)	(70,769)	(14,068)	(1,192)	5,400	(80,629)

	2009 Realized
	CPFL	CPFL	CPFL	RGE	Consolidated
	Paulista	Piratininga	Geração
Cost of service	1,413	4,172	165	1,256	7,006
Interest on actuarial obligations	303,015	76,981	6,532	17,626	404,154
Expected return on plan assets	(304,351)	(77,554)	(6,468)	(18,387)	(406,760)
Recognition of the asset (limited to paragraph 58-b of CPC 33)	-	-	-	(7,466)	(7,466)
Total Expense (Income)	77	3,599	229	(6,971)	(3,066)

Since the changes in the RGE plan indicate the need to recognize an asset, and the amount to be recognized is restricted to the present value of the economic rewards available at the time, recognition in 2011 will require analysis of the possibility of recovery of the asset at the end of the year.

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The principal assumptions taken into consideration in the actuarial calculations at the balance sheet date were:

	CPFL Paulista, CPFL Piratininga and CPFL Geração			RGE
	December 31, 2010	December 31, 2009	January 1, 2009	December 31, 2010	December 31, 2009	January 1, 2009
Nominal discount rate for actuarial liabilities:	10.24% p.a.	10.24% p.a.	10.24% p.a.	10.24% p.a.	10.24% p.a.	10.24% p.a.
Nominal Return Rate on Assets:	(*)	(**)	(***)	10.24% p.a.	11.28% p.a.	10.24% p.a.
Estimated Rate of nominal salary increase:	6.08% p.a.	6.08% p.a.	6.08% p.a.	6.08% p.a.	6.08% p.a.	6.08% p.a.
Estimated Rate of nominal benefits increase:	0.0% p.a.	0.0% p.a.	0.0% p.a.	0.0% p.a.	0.0% p.a.	0.0% p.a.
Estimated long-term inflation rate (basis for establishing
nominal rates above)	4.0% p.a.	4.0% p.a.	4.0% p.a.	4.0% p.a.	4.0% p.a.	4.0% p.a.
General biometric mortality table:	AT-83	AT-83	AT-83	AT-83	AT-83	AT-83
Biometric table for the onset of disability:	MERCER TABLE	MERCER TABLE	MERCER TABLE	MERCER TABLE	Light-Average	Light-Average
Expected turnover rate:	0.30 / (Service time + 1)	0.30 / (Service time + 1)	0.30 / (Service time + 1)	0.30 / (Service time + 1)	null	null
Likelihood of reaching retirement age:	100% when a beneficiary of the Plan first becomes eligible	100% when a beneficiary of the Plan first becomes eligible		100% when a beneficiary of the Plan first becomes eligible
(*) CPFL Paulista and CPFL Geração 12.73% p.a. and  CPFL Piratininga 12.71% p.a. (**) CPFL Paulista and CPFL Geração 14.36% p.a. and  CPFL Piratininga 14.05% p.a. (***) CPFL Paulista and CPFL Geração 13.05% p.a, CPFL Piratininga 12.84% p.a

( 20 )REGULATORY CHARGES

	December 31, 2010	December 31, 2009	January 1, 2009
Fee for the Use of Water Resources	4,452	4,080	3,636
Global Reverse Fund - RGR	16,483	9,876	7,451
ANEEL Inspection Fee	2,283	1,945	2,012
Fuel Consumption Account - CCC	58,289	9,392	48,194
Energy Development Account - CDE	42,035	38,457	33,237
Total	123,542	63,750	94,530

( 21 )TAXES AND CONTRIBUTIONS

	Current			Noncurrent
	December 31, 2010	December 31, 2009	January 1, 2009	December 31, 2010	December 31, 2009	January 1, 2009
ICMS (State VAT)	247,890	315,906	276,112	-	-	-
PIS (Tax on Revenue)	13,565	11,762	9,022	-	-	-
COFINS (Tax on Revenue)	63,668	54,978	41,591	959	1,639	2,243
IRPJ (Corporate Income Tax)	85,999	69,480	94,944	-	-	-
CSLL (Social Contribution Tax)	22,086	18,583	13,475	-	-	-
Other	22,035	27,901	21,528	-	-	-
Total	455,243	498,610	456,672	959	1,639	2,243

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( 22 )PROVISION FOR CONTINGENCIES

	December 31, 2010		December 31, 2009		January 1, 2009
	Reserve for contingencies	Escrow Deposits	Reserve for contingencies	Escrow Deposits	Reserve for contingencies	Escrow Deposits
Labor
Various	39,151	147,062	42,752	127,750	55,106	108,646
Civil
General Damages	11,126	75,003	9,897	59,434	14,450	64,407
Tariff Increase	10,814	9,200	12,249	9,068	10,635	18,498
Energy Purchased	-	-	-	-	14,899	13,228
Other	10,678	16,698	11,967	15,674	6,695	15,588
	32,618	100,901	34,113	84,176	46,679	111,721
Tax
FINSOCIAL	18,714	53,322	18,601	52,998	18,478	52,649
Increase in basis - PIS and COFINS	866	721	866	1,022	1,277	1,010
Interest on  Shareholders’ Equity - PIS and COFINS	10,666	10,666	9,800	9,800	70,301	-
PIS and COFINS - Non-Cumulative Method	87,672	-	122,792	-	124,887	-
Income Tax	73,401	539,601	63,914	498,347	59,708	456,519
Other	28,178	38,411	7,806	20,084	6,091	19,429
	219,497	642,721	223,779	582,251	280,742	529,607
Total	291,266	890,684	300,644	794,177	382,527	749,974

The changes in the provisions for contingencies and escrow deposits are shown below:

	December 31, 2009	Addition	Reversal	Payment	Monetary Restatement	December 31, 2010
Labor	42,752	28,769	(2,866)	(29,504)	-	39,151
Civil	34,113	9,402	(5,512)	(5,678)	293	32,618
Tax	223,779	31,393	(40,098)	(22)	4,445	219,497
Reserve for Contingencies	300,644	69,564	(48,476)	(35,204)	4,738	291,266
Escrow Deposits	794,177	80,226	(13,737)	(14,380)	44,398	890,684

	January 1, 2009	Addition	Reversal	Payment	Monetary Restatement	December 31, 2009
Labor	55,106	1,016	(3,688)	(9,682)	-	42,752
Civil	46,679	10,603	(667)	(22,502)	-	34,113
Tax	280,742	13,444	(1,481)	(72,844)	3,918	223,779
Reserve for Contingencies	382,527	25,063	(5,836)	(105,028)	3,918	300,644
Escrow Deposits	749,974	64,268	(17,164)	(48,052)	45,151	794,177

The provisions for contingencies were based on appraisal of the risks of losing litigation to which the Company and its subsidiaries are parties, where a loss is more likely than not in the opinion of the legal advisers and the management of the Company and its subsidiaries.

The principal pending issues relating to litigation, legal cases and tax assessments are summarized below:

a)Labor:The main labor suits relate to claims filed by former employees or unions for additional salary payments (overtime, salary parity, severance payments and other claims).

b)Civil: 

Bodily injury -mainly refer to claims for indemnities relating to accidents in the subsidiaries' electrical grids, damage to consumers, vehicle accidents, etc.

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Tariff increase: Corresponds to various claims by industrial consumers as a result of increases imposed by DNAEE Ordinances 38 and 45, dated February 27 and March 4, 1986, when the “Plano Cruzado” economic plan price freeze was in effect.

c)Tax 

FINSOCIAL- relates to legal challenges of the rate increase and collection of FINSOCIAL during the period June 1989 to October 1991.

PIS and COFINS - JCP -in 2009, the Company dropped its suit  disputing PIS and COFINS charged on Interest on shareholders’ equity  received, and paid the amounts in question, taking advantage of the benefit granted in Law n° 11,941/09 (REFIS IV), that is, a reduction in the fine, interest and legal charges. The Company is awaiting finalization of the legal procedures in order to offset the escrow deposits of the amounts.

PIS and COFINS – Non-cumulative method –refers to the tax disputes in relation to the non-cumulative levying of PIS and COFINS on certain sector charges. In 2010, the subsidiaries reversed the contingency of R$ 39,502 against the “General and administrative expenses – Legal, court fees and indemnities” account and the restatement of the amount of R$ 4,136 against the “Financial expense - Restatement and exchange variations” account.

Income tax -The provision of R$ 53,356 (R$ 44,531 in 2009) recognized by the subsidiary CPFL Piratininga, refers to the lawsuit in relation to the tax deductibility of CSLL in determination of IRPJ.

Other - tax- Refers to other suits in progress at the judicial and administrative levels resulting from of the subsidiaries' operations, in relation to INSS, FGTS and SAT tax issues.

d)Possible losses - the Company and its subsidiaries are parties to other suits in which management, supported by its legal advisers, believes that the chances of a successful outcome are possible, due to a solid defensive position in these cases. It is not yet possible to predict the outcome of the courts’ decisions or any other decisions in similar proceedings considered probable or remote. Consequently, no provision has been established for these. The claims relating to possible losses, at December 31, 2010, were as follows: (i) R$ 341,608 labor (R$ 294,825 in 2009); (ii) R$ 604,603 civil cases related mainly to bodily injury, environmental impact and tariff increases (R$ 472,710 in 2009); and (iii) R$ 823,872 in tax claims, principally Income tax, ICMS, FINSOCIAL and PIS and COFINS (R$ 625,369 in 2009).

Based on the opinion of their legal advisers, Management of the Company and its subsidiaries consider that there are no significant contingent risks that are not covered by adequate provisions in the Financial Statements, or that might result in a significant impact on future earnings.

Escrow deposits -The deposit of R$ 483,355 (R$ 450,319 in 2009) by CPFL Paulista refers to the dispute on the deductibility for income tax purposes of expense recognized in 1997 in respect of settlement in respect of the welfare deficit of the employees’ pension plan in relation to Fundação CESP, due to the renegotiation and renewal of debt in that year. On consulting the Brazilian Federal Revenue Office, the subsidiary obtained a favorable reply in Note MF/SRF/COSIT/GAB nº 157, of April 9, 1998, and took advantage of the tax deductibility of the expense, thereby generating a tax loss for that year. In March 2000, the subsidiary was assessed by the tax inspectors in relation to use of the tax loss carryforwards in 1997 and 1998. In 2007, as a result of the legal decision demanding the deposit as a condition for continuing the discussions, the subsidiary made an escrow deposit.  The deductibility resulted in other assessments and in order to be able to continue the discussions, the subsidiary offered collateral in the form of bank guarantees amounting to R$ 325,292. Based on the updated position of the legal counsel in charge of the case, the risk of loss continues to be classified as remote.

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( 23 )CHARGES FOR THE USE OF PUBLIC UTILITIES

Companies	December 31, 2010	December 31, 2009	January 1, 2009	Number of remaining installments	Interest rates
CERAN	71,987	65,904	67,546	304	IGP-M + 9.6% p.a.
ENERCAN	9,884	9,434	9,693	294	IGP-M + 8% p.a.
BAESA	52,865	50,402	51,729	306	IGP-M + 8% p.a.
Foz do Chapecó	312,182	295,794	295,147	313	IGP-M / IPC-A + 5.3% p.a.
TOTAL	446,918	421,534	424,115
Current	17,287	15,697	15,228
Noncurrent	429,631	405,837	408,887

( 24 )OTHER ACCOUNTS PAYABLE

	Current			Noncurrent
	December 31, 2010	December 31, 2009	January 1, 2009	December 31, 2010	December 31, 2009	January 1, 2009
Consumers and Concessionaires	63,584	50,250	50,545	-	-	-
Energy Efficiency Program - PEE	63,698	55,889	36,979	32,039	56,915	63,992
Research & Development - P&D	110,418	100,544	37,767	29,682	12,636	64,670
National Scientific and Technological Development Fund - FNDCT	3,076	4,705	28,230	-	-	228
Energy Research Company - EPE	1,206	2,008	13,593	-	-	114
Fund for Reversal	-	-	-	17,751	17,751	17,751
Advances	14,517	9,652	6,962	8,680	55,987	48,441
Provision for environmental expenditure	11,685	2,483	6,330	2,455	2,628	544
Payroll	6,724	8,085	8,533	-	-	-
Profit sharing	37,970	32,490	25,870	-	-	-
TAC ANEEL fine (DEC/FEC and voltage level)	-	10,877	-	-	-	-
Collections agreement	51,271	27,138	14,584	-	-	-
Guarantees	-	-	-	45,831	71,152	63,692
Other	46,712	34,740	50,295	4,692	9,575	10,080
Total	410,861	338,861	279,688	141,130	226,644	269,512

Consumers and concessionaires:refers to liabilities in connection with bills paid twice and adjustments to billing to be offset or returned to consumers as well the participation of consumers in the “Programa de Universalização” program.  Liabilities to concessionaires refer principally to transactions relating to the partial spin-off of Bandeirante by the subsidiary CPFL Piratininga.

Research and Development and Energy Efficiency Programs: the subsidiaries recognized liabilities relating to amounts already billed in tariffs (1% of the Net Operating Income), but not yet invested in the Research and Development and Energy Efficiency Programs. These amounts are subject to monthly restatement, at the SELIC rates, to realization.

Advances: the noncurrent amount refers to the contribution (“AFAC”) made exclusively by EPASA’s shareholders. In the future, the subsidiary CPFL Geraçãowill contribute the funds relating to its participation. In 2009 the balance represented the contributions made by shareholders of Chapecoense.

ANEEL TAC Fine (DEC and FEC):fine imposed on the subsidiary RGE, in relation to meeting DEC (Equivalent Duration of Interruptions per Client) and FEC (Equivalent Frequency of Interruptions per Consumer) indexes.

Profit-sharing:in conformity with a collective labor agreement, the Company and its subsidiaries introduced an employee profit-sharing program, based on achievement of operating and financial targets established in advance.

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( 25 )SHAREHOLDER’S EQUITY

The shareholders’ participations in the Company’s equity as of December 31, 2010 and 2009 are shown below:

	Number of shares
	December 31, 2010		December 31, 2009		January 1, 2009
Shareholders	Common Shares	Interest %	Common Shares	Interest %	Common Shares	Interest %
VBC Energia S.A.	122,948,720	25.55	122,948,720	25.62	133,653,591	27.85
BB Carteira Livre I FIA	149,233,727	31.02	149,233,727	31.10	149,233,727	31.10
Bonaire Participações S.A.	60,713,511	12.62	60,713,511	12.65	60,713,511	12.65
BNDES Participações S.A.	40,526,739	8.42	40,526,739	8.44	29,821,870	6.21
Brumado Holdings S.A.	17,251,048	3.59	17,251,048	3.59	28,420,052	5.92
Board Members	112	-	112	-	3,112	-
Executive Officers	2,824	-	6,450	-	31,152	0.01
Other Shareholders	90,460,449	18.80	89,230,631	18.60	78,033,923	16.26
Total	481,137,130	100.00	479,910,938	100.00	479,910,938	100.00

25.1 - Capital increase

The Annual and Extraordinary General Meetings of CPFL Energia held on April 26, 2010 approved the merger of all the shares held by theminority shareholders of the subsidiaries CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista, CPFL Mococa, Jaguari Geração, CPFL Serviços and CPFL Santa Cruz with the equity of CPFL Energia and conversion of these companies into wholly-owned subsidiaries. Accordingly, thecapital ofCPFL Energia increased by R$ 52,249, from R$ 4,741,175 to R$ 4,793,424 with the issue of 1,226,192 new common shares. 

25.2 - Capital Reserve

Refers to profits on the sale of treasury shares, resulting from shareholders exercising their right to withdraw at the time of the incorporation of the shares of minority shareholders in November 2005.

25.3 - Profit Reserve

Comprises the balance of the Statutory Reserve of R$ 418,665.

25.4 - Dividends

In July 2010, the Company’s Board of Directors approved the distribution of net income of R$ 774,429 as at June 30, 2010, as interim dividends, corresponding to R$ 1.609579599  per share.

During the year, the Company paid R$ 1,423,550 in respect of the dividends declared at December 31, 2009 and June 30, 2010.

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25.5 - Allocation of Net Income for the Year

The Company’s by-laws assure shareholders of a minimum dividend of 25% of net income, adjusted in accordance with the law.

For this year, Company management is proposing distribution of the remaining balance of the net income, by  declaration of R$ 486,040 in the form of dividends, corresponding to R$ 1.010190770 per share, as shown below:

Net income - Parent company	1,538,281
Prescribed Dividend	6,406
Constitution of Legal Reserve	(76,914)
Realization of comprehensive income	26,974
Net loss on first time adoption of IFRS	(234,278)
Net Income Base for Allocation	1,260,469
Interim Dividend	(774,429)
Proposed Dividend	486,040

( 26 )EARNINGS PER SHARE

Basic earnings per share

Calculation of the basic earnings per share at December 31, 2010 was based on the profit of R$ 1,538,281 attributable to CPFL Energia (R$ 1,657,297 at December 31, 2009) and the average weighted number of common shares outstanding during the year ended December 31, 2010, as shown below:

	December 31, 2010	December 31, 2009
Net income attributable to CPFL Energia	1,538,281	1,657,297
Weighted average number of common shares
Shares issued on January 1	479,910,938	479,910,938
Shares issued on April 26, 2010	1,226,192	-
Weighted average number of common shares as of December 31	480,747,436	479,910,938
Earnings per share - attributable to CPFL Energia	3.20	3.45
	December 31, 2010	December 31, 2009
Consolidated net income	1,560,037	1,688,868
Weighted average number of common shares
Shares issued on January 1	479,910,938	479,910,938
Shares issued on April 26, 2010	1,226,192	-
Weighted average number of common shares as of December 31	480,747,436	479,910,938
Consolidated - Earnings per share	3.25	3.52

Diluted earnings per share

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In 2010 and 2009, the Company held no notes convertible into shares to be taken into account in calculating the earnings per share.

( 27 )OPERATING REVENUE

	Number of Consumers (*)		GWh (*)		R$ Thousand
Revenue from Eletric Energy Operations	2010	2009	2010	2009	2010	2009
Consumer class
Residential	5,880,204	5,695,689	12,983	12,346	5,416,581	5,098,424
Industrial	78,261	77,166	15,413	14,970	4,123,723	4,127,319
Commercial	490,554	496,377	7,695	7,297	2,795,127	2,700,025
Rural	237,903	238,566	2,100	2,257	434,519	438,666
Public Administration	45,386	44,051	1,112	1,074	384,742	376,735
Public Lighting	8,096	7,933	1,444	1,408	303,862	293,463
Public Services	7,239	6,738	1,742	1,664	470,323	462,431
Billed	6,747,643	6,566,520	42,489	41,016	13,928,877	13,497,063
Own Consumption	783	768	33	33
Unbilled (Net)					1,304	43,217
Emergency Charges - ECE/EAEE					7	(5)
Reclassification to Network Usage Charge - TUSD - Captive Consumers					(5,843,561)	(6,025,716)
Electricity sales to final consumers			42,522	41,049	8,086,627	7,514,559
Furnas Centrais Elétricas S.A.			3,026	3,026	347,472	353,554
Other Concessionaires and Licensees			7,217	7,016	731,493	854,852
Current Electric Energy			2,495	2,883	117,156	90,732
Electricity sales to wholesaler			12,738	12,925	1,196,121	1,299,138
Revenue due to Network Usage Charge - TUSD - Captive Consumers					5,843,561	6,025,716
Revenue due to Network Usage Charge - TUSD - Free Consumers					1,127,795	789,357
Revenue from construction of concession infrastructure					1,043,678	615,557
Low Income Consumer´s Subsidy					31,245	31,970
Other Revenue and Income					227,651	215,013
Other operating revenues					8,273,930	7,677,613
Total gross revenues					17,556,678	16,491,310
Deductions from operating revenues
ICMS					(2,728,416)	(2,613,276)
PIS					(265,444)	(263,951)
COFINS					(1,224,934)	(1,216,563)
ISS					(3,847)	(3,617)
Global Reversal Reserve - RGR					(53,985)	(61,407)
Fuel Consumption Account - CCC					(593,630)	(386,949)
Energy Development Account - CDE					(470,981)	(449,417)
Research and Development and Energy Efficiency Programs					(134,772)	(102,175)
PROINFA					(56,933)	(35,954)
Other					(7)	5
					(5,532,949)	(5,133,304)
Net revenue					12,023,729	11,358,006
(*) Information not examined by the independent auditors.

The details of the tariff adjustments for the distributors are as follows:

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		2010		2009
Company	Month	Total adjustment	Effect perceived by consumers (*)	Total adjustment	Effect perceived by consumers (*)
CPFL Paulista	April	2.70%	-5.69%	21.22%	21.56%
CPFL Piratininga	October	10.11%	5.66%	5.98%	-2.12%
RGE	June/April	12.37%	3.96%	18.95%	3.43%
CPFL Santa Cruz	February	10.09%	-2.53%	24.09%	11.85%
CPFL Leste Paulista	February	-13.21%	-8.47%	12.94%	10.61%
CPFL Jaguari	February	5.16%	3.67%	11.36%	9.40%
CPFL Sul Paulista	February	5.66%	4.94%	11.64%	10.23%
CPFL Mococa	February	3.98%	3.24%	11.18%	5.59%
(*) Represents the average effect perceived by consumers, as a result of the elimination from the tariff base of financial components added in the annual adjustment for the previous year

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( 28 )COST OF ELECTRIC ENERGY

	Consolidated
Cost of Electric Energy	GWh (*)		R$ thousand
Electricity Purchased for Resale	2010	2009	2010	2009
Energy Purchased in Restricted Framework - ACR
Tractebel Energia S.A.	7,482	6,827	1,108,578	973,344
Itaipu Binacional	10,835	11,084	1,010,132	1,157,306
Petróleo Brasileiro S.A. Petrobrás	1,717	1,721	207,011	210,488
CESP - Cia Energética de São Paulo	1,759	1,808	175,467	171,837
Furnas Centrais Elétricas S.A.	1,673	1,649	156,197	147,681
CEMIG  - Cia  Energética de Minas  Gerais	1,036	1,357	131,451	222,604
CHESF - Cia Hidro Elétrica do São Francisco	1,343	1,318	119,594	113,143
Termorio S.A.	454	248	119,028	75,286
Copel Geração e Transmissão S.A.	694	713	69,817	69,126
Tractebel Energia Comercializadora Ltda.	397	136	43,500	14,325
Câmara de Comercialização de Energia Elétrica - CCEE	3,373	3,101	198,789	57,748
PROINFA	1,133	958	182,674	169,706
Other	4,726	5,574	593,054	663,391
	36,622	36,494	4,115,292	4,045,985
Energy Purchased in the Free Market - ACL	15,762	16,180	1,443,246	1,455,049
	52,384	52,674	5,558,538	5,501,034
Credit of PIS and COFINS			(508,463)	(521,366)
Subtotal			5,050,075	4,979,668
Electricity Network Usage Charge
Basic Network Charges			899,112	901,589
Transmission from Itaipu			88,568	84,281
Connection Charges			68,985	59,475
Charges of Use of the Distribution System			30,217	25,657
System Service Charges - ESS			174,230	80,727
Reserve Energy charges - EER			32,281	3,220
			1,293,393	1,154,949
Credit of PIS and COFINS			(120,978)	(120,108)
Subtotal			1,172,415	1,034,841
Total			6,222,490	6,014,509
(*) Information not examined by the independent auditors.

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( 29 )OPERATING COSTS AND EXPENSES

	Operating costs		Services Rendered to Third Parties		Operating expenses						Total
					Sales		General		Other
	2010	2009	2010	2009	2010	2009	2010	2009	2010	2009	2010	2009
Personnel	351,447	332,033	279	640	80,013	69,253	161,878	151,186	-	-	593,617	553,112
Employee Pension Plans	(80,629)	(3,066)	-	-	-	-	-	-	-	-	(80,629)	(3,066)
Materials	62,175	58,787	2,368	1,246	4,402	4,277	11,678	8,048	-	-	80,623	72,358
Outside Services	199,065	160,887	2,358	1,742	84,488	72,648	181,493	153,642	-	-	467,404	388,919
Depreciation and Amortization	475,647	451,712	-	-	9,212	10,944	24,167	23,518	152	-	509,178	486,174
Costs related to infrastructure construction	-	-	1,043,678	615,557	-	-	-	-	-	-	1,043,678	615,557
Other:
Collection charges	-	-	-	-	55,910	50,367	-	-	-	-	55,910	50,367
Allowance for doubtful accounts	-	-	-	-	51,668	36,250	-	-	-	-	51,668	36,250
Leases and Rentals	15,068	15,633	-	-	1,676	65	9,764	4,866	13	-	26,521	20,564
Publicity and Advertising	-	-	-	-	-	-	19,852	7,970	-	-	19,852	7,970
Legal, Judicial and Indemnities	-	-	-	-	-	-	5,416	25,209	-	-	5,416	25,209
Donations, Contributions and Subsidies	-	-	-	-	-	-	5,810	7,095	27	-	5,837	7,095
Inspection fee	-	-	-	-	-	-	-	-	24,769	23,563	24,769	23,563
Loss (gain) on the write-off of noncurrent assets	-	-	-	-	-	-	-	-	(11,308)	(2,240)	(11,308)	(2,240)
Free energy adjustment	-	-	-	-	-	-	-	-	2,782	19,378	2,782	19,378
Intangible of concession amortization	-	-	-	-	-	-	-	-	182,615	186,899	182,615	186,899
Other:	44,720	37,952	2,297	1,759	13,066	11,395	23,154	21,856	754	(257)	83,991	72,705
Total	1,067,493	1,053,938	1,050,980	620,944	300,435	255,199	443,212	403,390	199,804	227,343	3,061,924	2,560,814

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( 30 )FINANCIAL INCOME AND EXPENSES

	2010	2009
Financial Income
Income from Financial Investments	156,420	94,356
Arrears of  interest and fines	136,181	124,713
Restatement of tax credits	7,789	3,860
Restatement of Escrow Deposits	44,366	45,154
Monetary and Exchange Variations	42,548	22,171
Discount on purchase of ICMS credit	7,806	7,803
Interest - Extraordinary Tariff Adjustment	191	147
Interest on intercompany loans	5,894	2,460
PIS and COFINS of Interest on Shareholders' Equity	(18,253)	(18,476)
Guarantees	45,256	6,034
Other	54,917	63,138
Total	483,115	351,360
Financial Expense
Debt Charges	(740,973)	(619,582)
Monetary and Exchange Variations	(90,381)	(37,107)
(-) Capitalized borrowing costs	132,938	84,931
Public utilities	(31,578)	(8,651)
Guarantees	(37,835)	(9,301)
Other	(69,229)	(71,356)
Total	(837,058)	(661,066)
Net financial income (expense)	(353,943)	(309,706)

( 31 )SEGMENT INFORMATION

The Company’s operating segments are separated by business segment (electric energy distribution,generationand commercialization), based on the internal financial information and management structure.

Profit or loss, assets and liabilities per segment include items directly attributable to a segment, as well as those that can be allocated on a reasonable basis, if applicable. Prices charged between the segments are based on similar market transactions. Note 1 shows the subsidiaries in accordance with their areas of operation and provides further information about each subsidiary and its business area.

The segregated information by segment of activity is shown below, in accordance with the criteria established by Company management:

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	Distribution	Generation	Commercialization	Other (*)	Elimination	Total
2010
Net revenue	10,471,192	538,217	1,012,525	1,795	-	12,023,729
(-) Intersegment revenues	13,904	650,571	766,922	-	(1,431,397)	-
Income from electric energy service	1,852,867	616,416	302,981	(32,949)	-	2,739,315
Financial income	316,020	53,725	22,389	90,981	-	483,115
Financial expense	(394,999)	(323,441)	(22,311)	(96,307)	-	(837,058)
Income before taxes	1,773,749	345,914	302,024	(36,315)	-	2,385,372
Income tax and social contribution	(604,865)	(88,731)	(95,840)	(35,899)	-	(825,335)
Net Income	1,168,884	257,183	206,184	(72,214)	-	1,560,037
Total Assets (**)	11,689,503	7,568,600	349,047	449,655	-	20,056,805
Capital Expenditures  and other intangible assets	1,127,637	645,040	27,853	10	-	1,800,540
Depreciation and Amortization	352,806	188,981	4,553	145,453	-	691,793
2009
Net revenue	9,764,670	453,711	1,139,621	4	-	11,358,006
(-) Intersegment revenues	14,127	611,335	644,620	-	(1,270,082)	-
Income from electric energy service	1,860,801	649,561	292,543	(20,222)	-	2,782,683
Financial income	262,914	30,884	20,113	37,449	-	351,360
Financial expense	(361,852)	(222,990)	(9,764)	(66,460)	-	(661,066)
Income before taxes	1,761,863	457,455	302,892	(49,233)	-	2,472,977
Income tax and social contribution	(602,761)	(125,711)	(93,300)	37,663	-	(784,109)
Net Income	1,159,102	331,744	209,592	(11,570)	-	1,688,868
Total Assets (**)	10,696,228	6,761,330	422,816	610,385	-	18,490,759
Capital Expenditures  and other intangible assets	667,614	550,565	9,789	131	-	1,228,099
Depreciation and Amortization	344,499	175,825	3,882	148,867	-	673,073
(*) Other - Refers basically to the CPFL Energia figures after eliminations of balances with related parties (**) The goodwill created in an acquisition and recorded in CPFL Energia was allocated to the respective segments

( 32 )TRANSACTIONS WITH RELATED PARTIES

The Company is controlled by the following Companies:

·VBC Energia S.A.

Controlled by the Camargo Corrêa group, with operations in a number of segments, such as construction, cement, footwear, textiles, aluminum and highway concessions, among others.

·Bonaire Participações S.A.

Controlled by Energia São Paulo Fundo de Investimento em Participações, which in turn is controlled by the following pension funds: (a) Fundação CESP, (b) Fundação SISTEL de Seguridade Social, (c) Fundação Petrobras de Seguridade Social - PETROS, and (d) Fundação SABESP de Seguridade Social - SABESPREV.

·Fundo BB Carteira Livre I - Fundo de Investimento em Ações (“Fund")

Fund controlled by PREVI - Caixa de Previdência dos Funcionários do Banco do Brasil.

The direct and indirect participations in operating subsidiaries are described in Note 1.

Controlling shareholders, subsidiaries and associated companies, jointly controlled corporations and entities under common control and that in some way exercise significant influence over the Company are regarded as related parties. Balances and transactions involving related parties are shown in tables 32.1 and 32.2.

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32.1) Transactions between related parties involving controlling shareholders, entities under common control or with significant influence:

	ASSETS			LIABILITIES			REVENUE		EXPENSE
	December 31, 2010	December 31, 2009	January 1, 2009	December 31, 2010	December 31, 2009	January 1, 2009	2010	2009	2010	2009
Bank deposits and short-term investments
Banco do Brasil S.A.	141,372	179,781	67,480	-	-	-	13,147	7,030	494	4
Banco Nossa Caixa S.A.	-	196	-	-	-	-	-	-	-	10
Loans and Financing, Debentures and Derivatives contracts (*)
Banco do Brasil S.A.	-	10,352	266,531	1,409,587	813,805	1,036,739	3,612	-	110,671	78,832
Other financial transactions
Banco do Brasil S.A.	-	-	-	4,012	6,824	8,646	1,458	1,819	4,005	3,215
Banco Nossa Caixa S.A.	-	-	-	-	-	-	-	-	-	1,469
Energy sales in the free market
Camargo Corrêa Cimentos S.A.	656	-	-	-	-	-	7,737	-	-	-
Tavex Brasil S.A.	-	-	-	-	-	-	19,983	18,549	-	-
Energy purchases in the free market
NC Energia S.A.	42	2,238	2,055	-	-	-	18,745	24,961	-	1,146
Vale S.A	-	-	-	-	-	-	-	-	-	8,994
Vale Energia S.A.	-	-	-	-	1,348	-	-	-	20,277	26,613
Cia Energetica de Pernambuco - Celpe	52	-	-	-	-	-	-	-	-	-
Companhia de Eletricidade do Estado da Bahia - Coelba	342	-	-	-	-	-	2,834	-	-	-
Materials and Service Provision
Brasil Telecom S.A.	-	-	-	19	-	56	-	-	834	831
Camargo Corrêa Cimentos S.A.	-	-	-	-	2	3	-	-	-	20
Camargo Corrêa Geração de Energia S.A.	-	5	-	-	-	-	-	42	-	-
Banco do Brasil S.A.	-	-	-	-	-	-	-	-	220	-
Other revenue
Brasil Telecom S.A.	2,671	890	-	-	-	-	10,684	9,794	-	-
Property, plant and equipment acquisition
Construções e Comércio Camargo Correa S.A.	55,986	36,536	145,114	1,957	1,850	863
(*) Cost value, both for loans and for derivatives

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32.2)Transactions between related parties involving subsidiaries and jointly-owned subsidiaries:

	ASSETS			LIABILITIES			REVENUE		EXPENSE
Companies	December 31, 2010	December 31, 2009	January 1, 2009	December 31, 2010	December 31, 2009	January 1, 2009	2010	2009	2010	2009
Intercompany allocation of expense
Companhia Paulista de Força e Luz	-	-	1	-	150	141	-	-	1,598	1,440
Companhia Piratininga de Força e Luz	-	-	-	-	27	20	-	-	314	219
CPFL Comercialização Brasil S.A	-	-	-	-	14	15	-	-	239	182
CPFL Geração de Energia S.A.	-	-	-	-	-		-	-	-	(30)
Leasing and rental
Companhia Paulista de Força e Luz	-	-	-	-	7		-	-	70	77
Intercompany loans
Centrais Elétricas da Paraiba S.A.		-		-	-		-	165	-	-
CPFL Atende Centro de Cont. e Aten. Ltda	12,384	6,238	1,045	-	-		799	465	-	-
CPFL Bioenergia S.A.	-	14,422	-	-	-		786	391	-	-
CPFL Serv. Equip. Ind. e Com. S.A.	2,491	1,430	-	-	-		211	13	-	-
Companhia Luz e Força de Mococa	-	3,012	-	-	-		139	-	-	-
Dividend / Interest on shareholders' equity
Companhia Luz e Força de Mococa	3,648	500	-	-	-	-	-	-	-	-
Companhia Luz e Força Santa Cruz	12,000	7,000	10,000	-	-	-	-	-	-	-
Companhia Leste Paulista de Energia	-	4,957	-	-	-	-	-	-	-	-
Companhia Paulista de Força e Luz	237,000	-	-	-	-	-	-	-	-	-
Companhia Piratininga de Força e Luz	-	138,829	-	-	-	-	-	-	-	-
Companhia Sul Paulista de Energia	-	5,836	-	-	-	-	-	-	-	-
CPFL Comercialização Brasil S.A	75,000	-	-	-	-	-	-	-	-	-
CPFL Geração de Energia S.A.	85,000	-	148,203	-	-	-	-	-	-	-
CPFL Serv. Equip. Ind. e Com. S.A.	-	3,648	-	-	-	-	-	-	-	-
Rio Grande Energia S.A.	-	41,002	-	-	-	-	-	-	-	-
								-
Advance to future capital increase
CPFL Jaguariúna S.A.	445	140		-	-	-	-	-	-	-
Perácio Participações S.A.	-	-	409,310
Other
Perácio Participações S.A.	-	-	4,233	-	-	-	-	-	-	-

32.3)The main transactions are described below:

a)Bank deposits and short-term investments –refer mainly to bank deposits and short-term financial investments, as mentioned in Note 6.

b)Loans and Financing, Debentures and Derivatives– relate to funds raised in accordance with Notes 17 and 18, contracted under the normal market conditions at the time.

c)Other Financial Transactions – the amounts in relation to Banco do Brasil are bank costs and collection expenses. The balance recorded in liabilities comprises basically the rights over the payroll processing of certain subsidiaries, negotiated with Banco do Brasil, which are appropriated as an income in the statement of operations over the term of the contract. The Company also has an Exclusive Investment Fund managed by BB DTVM, which charges management fees under normal market conditions for such management.

d)Property, plant and equipment, Materials and Service Provision– refers to the acquisition of equipment, cables and other materials for use in distribution and generation, and contracting of services such as construction and information technology consultancy. These operations were contracted under normal market conditions.

e)Energy sales to the free market– refers basically to energy sales to free consumers, through short or long-term contracts made under conditions regarded by the Company as being market conditions at the time of the negotiation, in accordance with internal policies established in advance by Company management.

f)Energy purchased in the free market – refers basically to energy purchased by the trading companies in accordance with short or long-term agreements made under conditions regarded bythe Company as being market conditions at the time of the negotiation, in accordance with policies established in advance by Company management.

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g)Other revenue – refers basically to revenue from rental of use of the distribution system for telephony services.

The subsidiaries that are public distribution service concessionaires charge tariffs for the use of the distribution system (TUSD) and sell energy to related parties in their respective concession areas (captive consumers). The amounts charged are established in accordance with prices regulated by the regulatory agency. These distributors also purchase energy from related parties, mainly involving long-term agreements, in conformity with the rules established by the sector (principally by auction); these prices are also regulated and approved by ANEEL.

Additionally, certain subsidiaries have supplementary retirement plan maintained with Fundação CESP and offered to the employees of the subsidiaries, as mentioned in Note 19.

To ensure that commercial transactions with related parties are conducted under normal market conditions, the Company set up a Related Parties Committee, comprising representatives of the controlling shareholders, responsible for analyzing the main transactions with related parties.

The Company guarantees certain loans raised by its subsidiaries, as mentioned in Notes 17 and 18.

The total remuneration of key management personnel in2010, in accordance with CVM Decision nº 560/2008, was R$ 18,260.This amount comprisesR$ 16,152in respect of short-term benefits, R$ 624for post-employment benefitsand R$ 1,484for other long-term benefits, and refers to the amount recorded by the accrual method. 

( 33 )INSURANCE 

The insurance cover maintained by the subsidiaries is based on specialized advice and takes into account the nature and degree of risk. The amounts are considered sufficient to cover any significant losses on assets and/or responsibilities. The principal insurance policies in the financial statements are:

DESCRIPTION	TYPE OF COVER	2010	2009	2008
Property, Plant and Equipment	Fire, Lightning, Explosion, Machinery breakdown, Electrical Damage and Engeneering Risk	4,605,688	3,935,861	3,984,443
Transport	National Transport	197,712	101,000	75,600
Stored Materials	Fire, Lightning, Explosion and Robbery	18,729	30,423	27,830
Automobiles	Comprehensive Cover	3,531	2,138	6,886
Civil Liability	Electric Energy Distributors	20,134	19,996	19,999
Personnel	Group Life and Personal Accidents	68,532	76,617	125,544
Other	Operational risks and other	31,598	125,048	529,740
Total		4,945,924	4,291,083	4,770,042
Information not examined by the independent auditors.

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( 34 )FINANCIAL INSTRUMENTS

The main financial instruments, classified in accordance with the group’s accounting practices, are:

a) Financial assets

a.1) Measured at amortized cost

Loans and receivables	December 31, 2010	December 31, 2009	January 1, 2009
Consumers, Concessionaires and Licensees	2,011,830	1,977,745	1,881,485
Leases	31,068	24,192	6,389
Other
Receivables from BAESA's shareholders	17,128	31,006	42,443
Pledges, Funds and Tied Deposits	91,159	101,566	133,419
Fund Tied to Foreign Currency Loans	21,221	19,148	30,023
Services Rendered to Third Parties	73,163	48,845	18,642
Reimbursement RGR	7,592	7,115	5,939
Collection Agreements	26,573	4,263	-
	2,279,734	2,213,880	2,118,340
Held to maturity	December 31, 2010	December 31, 2009	January 1, 2009
Financial investments	81,749	101,432	125,366
Receivables - CESP	-	8,923	35,985
	81,749	110,355	161,351

a.2) Measured at fair value

Measured at fair value through profit or loss	December 31, 2010	December 31, 2009	January 1, 2009
Cash and cash equivalent	1,562,895	1,487,243	758,454
Derivatives	326	8,676	433,395
Financial investments	33,606	17,656	9,669
	1,596,827	1,513,575	1,201,518
Available for sale	December 31, 2010	December 31, 2009	January 1, 2009
Financial asset of concession	934,646	674,029	582,241

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b) Financial liabilities

b.1) Measured at amortized cost

	December 31, 2010	December 31, 2009	January 1, 2009
Suppliers	(1,047,392)	(1,064,107)	(1,071,215)
Loans and financing - Principal and interest	(5,141,556)	(3,452,942)	(3,229,633)
Debentures - Principal and interest	(3,840,340)	(3,351,478)	(2,709,079)
Regulatory Charges	(123,542)	(63,750)	(94,530)
Other
Consumers, Concessionaires and Licensees	(63,584)	(50,250)	(50,545)
National Scientific and Technological Development Fund - FNDCT	(3,076)	(4,705)	(28,458)
Energy Research Company - EPE	(1,206)	(2,008)	(13,707)
Collection Agreements	(51,271)	(27,137)	(14,584)
Reversal Fund	(17,751)	(17,751)	(17,751)
	(10,289,718)	(8,034,128)	(7,229,502)

b.2) Measured at fair value through profit or loss

Measured at fair value through profit or loss	December 31, 2010	December 31, 2009	January 1, 2009
Held for trade
Derivatives	(11,864)	(12,706)	(54,404)
Initial recognition (1)
Loans and financing - certain debts	(424,827)	(1,095,103)	(1,516,833)
	(436,691)	(1,107,809)	(1,571,237)

(1) Due to the initial recognition at fair value of the above financial liability, the consolidated result was a loss of R$ 52 in 2010 (R$ 56,609 in 2009).

c) Valuation of financial instruments

IFRS 7 requires classification at three levels of hierarchy for measurement of the fair value of financial instruments, based on observable and unobservable information in relation to valuation of a financial instrument at the measurement date.

IFRS 7 also defines observable information as market data obtained from independent sources and unobservable information that reflects market assumptions.

The three levels of fair value are:

· Level 1: quoted prices in an active market for identical instruments;

· Level 2: observable information other than quoted prices in an active market that are observable for the asset or liability, directly (i.e. as prices) or indirectly (i.e. derived from prices);

· Level 3: inputs for the instruments that are not based on observable market data (unobservable inputs).

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The classification in accordance with the fair value hierarchy of the Company’s financial instruments, measured at fair value, is as follows:

	December 31, 2010			December 31, 2009			January 1, 2009
	Level 1	Level 2	Level 3	Level 1	Level 2	Level 3	Level 1	Level 2	Level 3
Cash and cash equivalents	1,562,895	-	-	1,487,243	-	-	758,454	-	-
Derivatives	-	(11,538)	-	-	(4,030)	-	-	378,991	-
Loans and financing	-	(424,827)	-	-	(1,095,103)	-	-	(1,516,833)	-
Financial investments	33,606	-	-	17,656	-	-	9,669	-	-
Financial asset of concession	-	-	934,646	-	-	674,029	-	-	582,241
	1,596,501	(436,365)	934,646	1,504,899	(1,099,133)	674,029	768,123	(1,137,842)	582,241

Since the distribution subsidiaries have classified their financial concession assets as available-for-sale, as mentioned in Note 3.2, the relevant factors for measurement at fair value are not publicly observable. The fair value hierarchy classification is therefore level 3. The changes between years and the respective gains (losses) in the equity valuation reserve are disclosed in Note 12.

The comparative information on marking to market the other financial instruments measured at amortized cost is described below:

It is assumed that financial instruments such as accounts receivable from consumers, concessionaires and licensees and accounts payable to suppliers are already close to the respective market values.

At December 31, 2010 and 2009, the market values of the financial instruments obtained by the methodology described in Note 4, are as follows:

	December 31, 2010		December 31, 2009
	Accounting balance	Fair value	Accounting balance	Fair value
Loans and financing (note 18)	(5,141,556)	(4,870,909)	(3,452,942)	(3,194,735)
Debentures (note 19)	(3,840,340)	(3,891,397)	(3,351,478)	(3,392,071)
Total	(8,981,896)	(8,762,306)	(6,804,420)	(6,586,806)

In the case of specific electricity sector operations, where there are no similar transactions in the market and with low liquidity, mainly related to the regulatory aspects and credits receivable from CESP, the subsidiaries assumed that the market value is represented by the respective carrying amount. This is due to the uncertainties reflected in the variables which have to be taken into consideration in creating a pricing model.

The Company recognized in “Investments at cost” in the consolidated financial statements the 5.93% interest held by the indirect subsidiary Paulista Lajeado Energia S.A. in the total capital of Investco S/A, in the form of 28,154 common shares and 18,508 preferred shares.As the shares of that company are not quoted on the stock exchange and the main objective of it operations is to generate electric energy for commercialization by the shareholders who hold the concession, the Company opted to recognize the investment at cost.

d) Derivatives

The Company and its subsidiaries have a policy of using derivatives as a hedge against the risks of variations in exchange and interest rates, without any speculative purposes. The Company and its subsidiaries have an exchange hedge compatible with the net exposure to exchange risks, including all the assets and liabilities tied to exchange variation.

The hedge instruments contracted by the Company and its subsidiaries are currency or interest rate swaps with no leverage component, margin call requirements or daily or periodical adjustments. As terms of the majority of the derivatives contracted by the subsidiary CPFL Paulista are fully aligned with thedebts protected, and in order to obtain more relevant and consistent accounting information through the recognition of income and expenses, certain debts were designated at fair value, for accounting purposes. Other debts with different terms from the derivatives contracted as a hedge continue to be recorded at amortized cost. Furthermore, the Company and its subsidiaries do not adopt hedge accounting for derivative operations.

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At December 31, 2010, the Company and its subsidiaries had the following swap operations:

	Market values (book values)
Company / strategy / counterparts	Asset	(Liability)	Market values, net	Values at cost, net	Gain (Loss) on marking to market	Currency / index	Maturity range	Notional	Negotiation market
Derivatives for protection of debts designated at fair value
Exchange variation hedge
CPFL Paulista
ABN	-	(7,421)	(7,421)	186	(7,607)	yen	Jan, 2012	376,983	Over the counter
Subtotal	-	(7,421)	(7,421)	186	(7,607)
Derivatives for protection of debts  not designated at fair value
Exchange variation hedge
CPFL Paulista
Itau BBA	-	(606)	(606)	(606)	-	dollar	Oct 2010	30,121	Over the counter
CPFL Geração
Itaú BBA	-	(2,760)	(2,760)	(2,618)	(142)	dollar		65,237
							Oct 2010 to Mar 2011		Over the counter
Hedge interest rate variation(1)
CPFL Energia
Citibank	-	(583)	(583)	7	(590)	CDI + spread	Sep 2010 to Sep 2014	450,000	Over the counter
RGE
Santander	289	-	289	95	194	CDI + spread	Jan 2011 to Dec 2013	280,000	Over the counter
Citibank	37	(2)	35	8	27	CDI + spread	Jun 2011 to Dec 2013	100,000	Over the counter
Hedge interest rate variation(2)
CPFL Piratininga
HSBC	-	(114)	(114)	6	(120)	TJLP	Jan 2013	25,453	Over the counter
Santander	-	(137)	(137)	(3)	(134)	TJLP	Jan 2013	25,453	Over the counter
CPFL Geração
HSBC	-	(241)	(241)	(9)	(245)	TJLP	Dec 2012	50,377	Over the counter
Subtotal	326	(4,443)	(4,117)	(3,120)	(1,010)
Total	326	(11,864)	(11,538)	(2,934)	(8,617)
Circulante	244	(3,981)
Não circulante	82	(7,883)
Total	326	(11,864)
* For further details of terms and information about debts and debentures, see Notes 18 and 19 (1) The interest rate hedge swaps have half-yearly validity, so the notional value reduces in accordance with amortization of the debt. (2) The interest rate hedge swaps have monthly validity, so the notional value reduces in accordance with amortization of the debt.

The subsidiary CPFL Paulista opted to mark to market the debt with fully tied hedge instruments, resulting in a gain of R$ 4,965 at December 31, 2010 (Note 17). The gain minimized the loss on derivatives stated previously.

The Company and its subsidiaries have recorded gains and losses on their derivatives. However, as these derivatives are used as a hedge, these gains and losses minimized the impact of variations in exchange and interest rates on the protected indebtedness. For the years 2010 and 2009, the derivatives resulted in the following impacts on the consolidated result:

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			Gain (loss)
Company	Hedged risk / Operation	Account	2010	2009
CPFL Energia	Interest rate variation	Financial expense - Swap transactions	(14)	136
CPFL Energia	Marking to market	Financial expense - Adjustment to fair value	20	228
CPFL Paulista	Exchange variation	Financial expense - Swap transactions	(3,269)	(230,440)
CPFL Paulista	Marking to market	Financial expense - Adjustment to fair value	392	49,810
CPFL Piratininga	Interest rate variation	Financial expense - Swap transactions	3	-
CPFL Piratininga	Marking to market	Financial expense - Adjustment to fair value	(254)	-
CPFL Geração	Exchange variation	Financial expense - Swap transactions	(16,094)	(274,350)
CPFL Geração	Interest rate variation	Financial expense - Swap transactions	567	(1,305)
CPFL Geração	Marking to market	Financial expense - Adjustment to fair value	1,710	11,157
RGE	Exchange variation	Financial expense - Other financial exp	-	(11,743)
RGE	Interest rate variation	Financial expense - Other financial exp	553	514
RGE	Marking to market	Financial expense - Derivative adjustment to fair value	(71)	198
			(16,457)	(455,795)

e) Sensitivity Analysis

In compliance with CVM Instruction n° 475/08, the Company and its subsidiaries performed sensitivity analyses of the main risks to which their financial instruments (including derivatives) are exposed, mainly comprising variations in exchange and interest rates, as shown below:

e.1) Exchangevariation 

If the level of exchange exposure at December 31, 2010 is maintained, the simulation of the consolidated effects by type of financial instrument for three different scenarios would be:

Instruments	Exposure	Risk	Exchange depreciation of 8.9%*	Exchange depreciation of 25%**	Exchange depreciation of  50%**
Financial asset instruments	21,221	apprec. dollar	1,879	5,305	10,611
Financial liability instruments	(138,953)	apprec. dollar	(12,301)	(34,741)	(69,477)
Derivatives - Plain Vanilla Swap	83,328	apprec. dollar	7,377	20,834	41,664
	(34,404)		(3,045)	(8,602)	(17,202)
Financial liability instruments	(424,827)	apprec. yen	(37,608)	(106,207)	(212,414)
Derivatives - Plain Vanilla Swap	424,827	apprec. yen	37,608	106,207	212,414
	-		-	-	-
	(34,404)		(3,045)	(8,602)	(17,202)
* In accordance with exchange graphs contained in information provided by the BM&F **In compliance with CVM Instruction 475/08

e.2) Variation in interest rates

If (i) the scenario of exposure of the financial instruments indexed to variable interest rates at December 31, 2010 were to be maintained, and (ii) the respective accumulated annual indexes as of that date were to remain stable (CDI 9.71%  p.a.; IGP-M 11.32% p.a.; TJLP  6.0% p.a.), the effects on the consolidated financial statements for the next company year would be a net financial expense R$ 526,941. In the event of fluctuations in the indexes in accordance with the three scenarios described, the effect on the net financial expense would as follows:

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Instruments	Exposure	Risk	Scenario I*	Raising index by 25%**	Raising index by 50%**
Financial asset instruments	1,718,110	CDI variation	38,482	41,708	83,414
Financial liability instruments	(5,242,137)	CDI variation	(116,323)	(127,253)	(254,505)
Derivatives - Plain Vanilla Swap	(628,272)	CDI variation	(14,325)	(15,251)	(30,502)
	(4,152,299)		(92,166)	(100,796)	(201,593)
Financial assets instruments	81,749	IGP-M variation	(4,831)	2,313	4,627
Financial liability instruments	(65,263)	IGP-M variation	3,857	(1,847)	(3,694)
	16,486		(974)	466	933
Financial liability instruments	(3,238,304)	TJLP variation	5,099	(48,574)	(97,150)
Derivatives - Plain Vanilla Swap	108,579	TJLP variation	(173)	1,629	3,257
	(3,129,725)		4,926	(46,945)	(93,893)
Total increase	(7,265,538)		(88,214)	(147,275)	(294,553)
* The CDI, IGP-M and TJLP indexes considered of 11.99%, 5.41% and 5.84%, respectively, were obtained from information available in the market **In compliance with CVM Instruction 475/08

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( 35 )RISK MANAGEMENT

The business of the Company and its subsidiaries comprises principally generation, commercialization and distribution of electric energy. As public service concessionaires, the operations and/or tariffs of its principal subsidiaries are regulated by ANEEL.

Risk management structure:

The Board of Directors is responsible for allocating priorities in respect of the risks to be monitored by the Company, confirming the tolerance levels approved by the Executive Board and being aware of the corporate risk management model adopted by the Company.  The Executive Board is responsible for developing and implementing action and risk monitoring plans. The Risk Management and Internal Controls Department and the Corporate Risk Management Committee were set up to assist it in this process.  Since its creation, the Risk Management and Internal Controls Departmenthas drawn up theCorporate Risk Management Policy, approved by the Executive Board and the Board of Directors, set up the Corporative Risk Management Committee, comprising directors appointed to represent each Management Unit, and the internal rules, and is implementing the Corporate Risk Management model for the Group with regard to Strategy (guidelines, risk map and treatment), Processes (planning, execution, monitoring and reports), Systems, Organization and Governance.

The risk management policies are establishedto identify, analyze and treats the risks faced by the Company and its subsidiaries,and includes reviewing the model adopted wherever necessary to reflect changes in market conditions and in the Group's activities, with a view to developing an environment of disciplined and constructive control. 

The Group's Board of Directors is assisted in its supervisory role by the Internal Audit department. The Internal audit department conducts both the regular reviews and the ad hoc reviews of risk management controls and procedures, the results of which are reported to theBoard of Directors and the Fiscal Council.

The main market risk factors affecting the businesses are as follows:

Exchange rate risk:This risk derives from the possibility of the subsidiaries incurring losses and cash constraints on account of fluctuations in exchange rates, increasing the balances of foreign currency denominated liabilities. The exposure in relation to raising funds in foreign currency is largely covered by contracting swap operations, which allow the Company and its subsidiaries to exchange the original risks of the operation for the cost of the variation in the CDI. The operations of the Company’s subsidiaries are also exposed to exchange variations on the purchase of electric energy from Itaipu. The compensation mechanism - CVA protects the companies against possible losses. However, the compensation only comes into effect through consumption and the consequent billing of energy after the next tariff adjustment in which such losses have been considered. The quantification of this risk is measured in Note 34 (e.1).

Interest Rate Risk:This risk derives from the possibility of the Company and its subsidiaries incurring losses due to fluctuations in interest rates that increase financial expenses on loans, financing and debentures. The subsidiaries have tried to increase the proportion of pre-indexed loans or loans tied to indexes with lower rates and little fluctuation in the short and long term. The quantification of this risk is measured in Note 34 (e.2).

Credit Risk:This risk arises from the possibility of the subsidiaries incurring losses resulting from difficulties in receiving amounts billed to customers. This risk is evaluated by the subsidiaries as low, as it is spread over the number of customers and in view of the collection policy and cancellation of supply to defaulting consumers.

Risk of Energy Shortages:The energy sold by the subsidiaries is basically generated by hydropower plants. A prolonged period of low rainfall, together with an unforeseen increase in demand, could result in a reduction in the volume of water in the power plants’ reservoirs, compromising the recovery of their volume, and resulting in losses due to the increase in the cost of purchasing energy or a reduction in revenue due to the introduction of another rationing program, as in 2001. According to the Annual EnergyOperation Plan – PEN of July 2010, drawn up by the Operador Nacional do Electricity System, National Electricity System Operator, the risk of any energy deficit is very low for 2011, and the likelihood of another energy rationing program is remote.

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Risk of Acceleration of Debts:The subsidiaries have loan agreements, financing and debentures with restrictive clauses (covenants) normally applicable to these kinds of operation, related to compliance with economic and financial ratios, cash generation, etc. These covenants are monitored appropriately and do not restrict the capacity to operate normally.

Regulatory risk: The electric energy supplied tariffs charged to captive consumers by the distribution subsidiaries are fixed by ANEEL, at intervals established in the Concession Agreements entered into with the Federal Government and in conformity with the periodic tariff review methodology established for the tariff cycle. Once the methodology has been ratified, ANEEL establishes tariffs to be charged by the distributed to the end consumers. In accordance with Law 8.987/1995, the tariffs fixed should insure the economic and financial balance of the concession contract at the time of the tariff review, however, the risk of application of the tariffs falls to the electric energy distributors. 

Risk Management for Financial instruments:The Company and its subsidiaries maintain operating and financial policies and strategies to protect the liquidity, safety and profitability of their assets. They accordingly control and follow-up procedures are in place on the transactions and balances of financial instruments, for the purpose of monitoring the risks and current rates in relation to market conditions.

Risk management controls: In order to manage the risks inherent to the financial instruments and to monitor the procedures established by management, the Company and its subsidiaries use the MAPS software system to calculate the Mark to Market, Stress Testing and Duration of the instruments, and assess the risks to which the Company and its subsidiaries are exposed. Historically, the financial instruments contracted by the Company and its subsidiaries supported by these tools have produced adequate risk mitigation results. It must be stressed that the Company and its subsidiaries have a formal policy of contracting derivatives, always with the appropriate levels of approval, only in the event of exposure that management regards as a risk. The Company and its subsidiaries do not enter into transactions involving exotic or speculative derivatives. Furthermore, the Company and its subsidiaries meet the requirements of the Sarbanes-Oxley Law, and accordingly have internal control policies that aim for a strict control environment to minimize the exposure to risks.

( 36 )COMMITTMENTS  

The Company’s commitments in relation to long-term energy purchase agreements and plant construction projects are as follows:

Commitments as of December 31, 2010	Duration	2011	2012	2013	2014	Thereafter	Total
Energy purchase contracts (except Itaipu)	2 to 20 years	6,096,973	6,348,357	6,185,466	5,885,869	61,564,231	86,080,896
Itaipu	20 years	1,056,770	1,126,101	1,111,831	1,085,482	13,823,854	18,204,039
Power plant construction projects (a)	2 to 31 years	493,531	232,616	31,559	30,759	391,509	1,179,974
TOTAL		7,647,275	7,707,074	7,328,855	7,002,111	75,779,595	105,464,909
(a) Power plant construction projects include commitments made by the Company corresponding to its proportional share on construction, concession acquisition and bank guarantees relating to the jointly-controlled under development companies.

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( 37 )REGULATORY ASSETS AND LIABILITIES

The Company accounts for the following assets and liabilities for regulatory purposes, which are not recognized in the consolidated financial statements, as mentioned in Note 3.13.

	December 31, 2010	December 31, 2009	January 1, 2009
Assets
Consumers, Concessionaires and Licensees
Extraordinary tariff adjustment	-	-	328
Free energy	-	-	5,985
Discounts TUSD (*) and Irrigation	54,407	12,753	35,976
Other financial components	-	199	7,058
	54,407	12,952	49,347
Deferred Costs Variations
Parcel "A"	332	1,290	236,307
CVA (**)	333,620	374,336	559,357
	333,952	375,626	795,664
Prepaid Expenses
Overcontracting	23,860	100,326	99,313
Low income consumers' subsidy - Losses	34,994	55,506	68,842
Neutrality of the sector charges	4,078	-	-
Other financial components	49,235	11,556	9,358
	126,058	167,388	177,513
Liabilities
Deferred Gains Variations
Parcel "A"	(11,472)	(44,419)	(15,360)
CVA	(364,363)	(377,735)	(191,289)
	(375,835)	(422,154)	(206,649)
Other Accounts Payable
Tariff review	-	(89,261)	(34,692)
Discounts TUSD and Irrigation	(1,923)	(991)	(797)
Tariff adjustment	(3,556)	-	-
Overcontracting	(61,391)	(17,541)	(51,634)
Low income consumers' subsidy - Gains	(6,280)	(6,011)	(13,154)
Neutrality of the sector charges	(63,905)	-	-
Other financial components	(26,111)	(12,137)	(24,642)
	(163,166)	(125,941)	(124,919)
Total net	(24,584)	7,871	690,956
(*) Network Usage Charge - TUSD (**)  Deferred Tariff Costs and Gains Variations from Parcel "A" itens - ("CVA")

The main characteristics of the regulatory assets and liabilities are:

a) TUSD Discounts and Irrigation

The distribution subsidiaries recognize regulatory assets and liabilities in relation to the special discounts applied on the TUSD to the free consumers, in respect of electric energy supplied from alternative sources and on the tariffs for energy supplied for irrigation and aquaculture.

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b) Parcel “A”

Corresponds to the variation in the non-manageable costs representing Parcel "A" of the concession agreements between January 1 and October 25, 2001, during the rationing period.

c) CVA

Refers to the mechanism for offsetting the variations in unmanageable costs incurred by the electric energy distribution concessionaires. These variations are calculated in accordance with the difference between the expenses effectively incurred and the expenses estimated at the time of establishing the tariffs in the annual tariff adjustments. The amounts taken into consideration in the CVA are restated at the SELIC rate.

d) Overcontracting

Electric energy distribution concessionaires are obliged to guarantee 100% of their energy and power market through contracts approved, registered and ratified by ANEEL, and are also assured that costs or income derived from overcontracting will be passed on to the tariffs, restricted to 3% of the energy load requirement.

e) Subsidy - Low Income

Refers to the subsidies granted to consumers entitled to the Social Electric Energy Tariff (Low Income) if they are enrolled in the Sole Register for Federal Government Social (Cadastro Único para Programas Sociais do Governo Federal – CadÚnico), irrespective of their energy consumption if they are enrolled in the Sole Register for Federal Government Social (Cadastro Único para Programas Sociais do Governo Federal – CadÚnico), irrespective of their energy consumption.

f) Neutrality of the Sector Charges

Refers to the neutrality of the sector charges in the tariff, calculating the monthly differences between the amounts billed and the amounts considered in the tariff.

g) Tariff Adjustment and Tariff Review

Financial components were accepted in the Company’s tariff adjustment, so as to adjust previous tariff reviews or adjustments.

h) Other Financial Components

Mainly refers to CCEAR exposure, financial guarantees, subsidies to cooperatives and licensees and TUSD G financial adjustment.

( 38 )RELEVANT FACTS AND SUBSEQUENT EVENTS

38.1 February tariff adjustments

In Ratification Resolutions dated February 1, 2011, ANEEL fixed the tariff adjustments for the subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista. The details of the adjustments are as follows.

	CPFL Santa Cruz	CPFL Jaguari	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista
Average adjustment	23.61%	5.47%	9.50%	7.76%	8.02%
Economic adjustment	8.01%	5.22%	6.84%	6.42%	6.57%
Financial Components	15.61%	0.25%	2.66%	1.34%	1.45%
Effect perceived by consumers	15.38%	6.62%	9.77%	16.44%	7.11%
Ratification Resolution - ANEEL	1.108/11	1.106/11	1.109/11	1.107/11	1.111/11

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 38.2 Acquisition of Jantus

In this quarter, CPFL Energia, through its subsidiary CPFL Comercialização Brasil S.A. acquired all the shares of Jantus, a company that controls SIIF Énergies do Brasil Ltda. and SIIF Desenvolvimento de Projetos de Energia Eólica Ltda., this transaction is subject to accomplish certain conditions stipulated in the Sale and Purchase Agreement, including authorizations from all regulatory agencies concerned. Together they hold (i) four wind farms in operation (Formosa, Icaraizinho, Paracuru SIIF Cinco) in the state of Ceara with an installed capacity of 210 MW and energy sale agreements for 20 years with Eletrobras, (ii) a wind farm project located in the State of Rio de Janeiro with an installed capacity of 135 MW potential and also long-term sale power agreement with Eletrobrás, and iii) a portfolio of wind projects with total installed capacity of 732 MW in the Ceara and Piaui, of which 412 MW are already certified and eligible to participate in the upcoming auctions of energy.

The acquisition price of Jantus that includes wind farms in operation and the portfolio of projects was R$ 950 million, and a net debt of R$ 544.2 million will be assumed.

38.3 Association of CPFL Energia with ERSA

On April 19, 2011, CPFL Energia signed an agreement with the shareholders of ERSA Energias Renováveis S.A. (ERSA), whereby intend to merge assets and projects relating to renewable energy sources held by the subsidiaries CPFL Geração and CPFL Brasil, which includes wind farms, biomass and small hydroelectric power plants.

After a series of predicted restructurings, CPFL Geração and CPFL Brasil will join the control of ERSA, as majority shareholder, holding together, 63.6% of total voting capital of ERSA, while the current shareholders of ERSA will hold 36.4%. When the merger transaction described above is completed, ERSA will have its corporate name changed to CPFL  Energias Renováveis S.A. (CPFL Renováveis).

The exchange ratio between the shares of ERSA and Nova CPFL shares for purposes of the merger, is based on the economic value of ERSA and economic value of assets owned by CPFL Geração and CPFL Brasil that will be contributed to Nova CPFL, and will be confirmed by appraisal reports prepared by specialized firms, in compliance with applicable law. In the context of the association, the assets involved were valued at R$ 4.5 billion.

This association is subject to certain conditions set by the Joint Venture Agreement, including authorizations to regulatory agencies and corporate reorganizations of companies controlled by CPFL Energia, as well as to be in compliance with terms and conditions regarding the acquisition of Jantus, a company that controls SIIF Énergies do Brazil Ltda. and SIIF Desenvolvimento de Projetos de Energia Eólica Ltda.

38.4 Dividend payment

The general shareholders’ meeting held on April 28, 2011 approved the destination of the net income for the fiscal year ended on December 31, 2010, through (i) constitution of capital reserve in the amount of R$76,914; (ii) declaration of R$ 774,429 paid as interim dividend on September 30, 2010, and (iii) approval of R$486,040 related to additional dividend proposed. On April 29 we paid the additional dividend proposed.

38.5  CPFL Paulista 2011 Tariff adjustment

Through Resolution No. 1130 of April 5, 2011, the rates of the subsidiary CPFL Paulista were, on average, adjusted from April 8 in 7.38% (seven point thirty-eight percent). This is composed by 6.11% (six point eleven percent) for the economic annual tariff adjustment, and 1.26% (one point twenty six percent) is related to the regulatory adjustment, corresponding to an average increase of 7.23% (twenty-seven point three percent) to captive consumers.

38.6  Issuance of debentures

On May 23, 2011, our Board of Directors approved the issuance of debentures by certain of our subsidiaries in the total amount of R$2,778 million.  Of this amount, R$484 million will be issued be issued by CPFL Paulista, R$680 million by CPFL Geração, R$160 million by CPFL Piratininga, R$ 70 million by RGE and R$65 million by CPFL Santa Cruz.  These amounts will be used as working capital and to refinance part of these companies' debt.  CPFL Brasil will issue R$1,320 million to finance new investments.

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( 39 )ADDITIONAL INFORMATION

CONSOLIDATED STATEMENTS OF ADDED VALUEFOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

(In thousands of Brazilian reais – R$)

	2010	2009
1- Revenues	18,421,036	16,963,483
1.1 Operating revenues	16,513,001	15,875,755
1.2 Revenue from infrastructure construction	1,043,678	615,557
1.3 Revenues related to the construction of own assets	916,026	508,421
1.4 Provision for losses on the realization of regulatory assets	(51,669)	(36,250)
2 - (-) Inputs	(9,535,417)	(8,461,851)
2.1Electricity Purchased for Resale	(6,914,197)	(6,695,256)
2.2Material	(1,095,907)	(590,704)
2.3Outsourced Services	(1,185,662)	(825,670)
2.4Other	(339,651)	(350,221)
3 - Gross Added Value (1 + 2)	8,885,619	8,501,632
4 – Retentions	(720,528)	(697,869)
4.1Depreciation and Amortization	(537,913)	(510,970)
4.2Amortization of intangible assets	(182,615)	(186,899)
5 - Net Added Value Generated (3 + 4)	8,165,091	7,803,763
6 - Added Value Received in Transfer	521,084	378,423
6.1Financial Income	521,084	378,423
6.2Equity in Subsidiaries	-	-
7 - Added Value to be Distributed (5 + 6)	8,686,175	8,182,186
8 - Distribution of Added Value
8.1Personnel and Charges	498,110	533,508
8.1.1 Direct Remuneration	379,198	357,309
8.1.2 Benefits	89,235	147,277
8.1.3 Government severance indemnity fund for employees - F.G.T.S.	29,677	28,922
8.2Taxes, Fees and Contributions	5,681,647	5,251,649
8.2.1 Federal	2,940,759	2,628,151
8.2.2 State	2,731,991	2,615,272
8.2.3 Municipal	8,897	8,226
8.3Interest and Rentals	946,381	708,161
8.3.1 Interest	931,649	698,622
8.3.2 Rental	14,732	9,539
8.4Interest on capital	1,560,037	1,688,868
8.4.1 Dividends (including additional proposed)	1,260,244	1,228,914
8.4.2 Retained profits	299,793	459,954	1
	8,686,175	8.182,186

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