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

CRC

     During the concession regime that existed prior to the enactment of Law No. 8,987 on February 13, 1995 (the “Concessions Law”), the Federal Government decided that electric concessionaires should maintain a guaranteed rate of return, between 10% and 12%. In order to ensure this rate of return, a netting account was created in 1971, Conta de Resultados a Compensar (“CRC Account”), whereby the difference between (i) the rate of return defined by the Federal Government and (ii) the actual rate of return of a concessionaire in any given year would be registered in the CRC Account of each concessionaire in order to compensate excesses and shortfalls.

     The guaranteed rate of return regime was discontinued in 1993. The balance of each CRC Account was set-off against certain debts of concessionaires relating, among other things, to the supply of energy by Itaipu and the supply of fossil fuel.

     In 1994, the Federal Government recognized the remaining balance of the CRC Account as an asset belonging to the respective concessionaires. In the same year, the Federal Government authorized the exchange of such assets for an equivalent amount of Elets, a Federal Government bond.

Energy Reallocation Mechanism

     Centrally dispatched hydrogenerators are protected against certain hydrological risks by the Energy Reallocation Mechanism (“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, either less or in excess to 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 will be accounted monthly by each generator.

Research and Development

     The companies holding concessions, permission and authorizations for distribution, generation and transmission of electricity must invest every year a minimum of 1% of their net operational revenue in research and development. Small Hydroelectric Power Plants, wind, sun and biomass energy projects are not subject to this requirement.

include 67.07% of each item for RGE. We also account for four of our generation facilities owned by our subsidiaries using proportionate consolidation. Three of these facilities are under construction and one facility, CERAN, has one turbine in operation and two others under construction. See “Presentation of Financial Information.”

Overview

     We are a holding company and, through subsidiaries, we (a) distribute electricity to customers in our concession areas, (b) generate electricity and develop additional generation projects and (c) 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.

     In addition to achieving the best returns we can from our regulated distribution business, we have two broad initiatives to improve our future financial performance. One is the growth in our generating capacity as our existing hydroelectric generation projects progressively come on line from now through 2008. Approximately 3.6% of our new generation capacity came online in 2004, approximately 8.5% is expected to come online by the end of 2005 and approximately 60% is expected to come online by the second quarter of 2006. We plan to use the additional electricity generated by these projects to supply electricity to our distribution business, and we currently expect that this degree of integration will improve our consolidated profit margin and our cash flows. The second is the development of our commercialization and electricity-related services business in a progressively more liberal market. While it is difficult to predict the size this business will attain, it will provide additional revenues without a significant investment in a business that is not currently subject to regulated margins.

     Of course, there are factors beyond our control that can have a significant impact, positive or adverse, on our financial performance, as we have seen in recent years with the effects of an energy crisis in 2001 and increases in interest rates and indexation rates on our debt. By reducing our indebtedness, we have reduced our vulnerability to some of these factors. The most important external factors involve regulation, and we believe that the current regulatory environment is reasonably promising.

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 customers at regulated tariffs. In 2004, sales to captive consumers represented 82.4% of the volume of electricity we delivered and 91.0% of our operating revenues as compared to 85.4% and 93.9%, respectively, in 2003.

     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 customers and shareholders. For a description of tariff regulations, see “The Brazilian Power Industry—Distribution Tariffs” and “Information on the Company—Customers, Analysis of Demand and Tariffs.”

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

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     Through 2002, the annual adjustments were the same in percentage terms for all of our customers. Beginning in 2003, tariff increases have been applied differently to different customer classes, with generally higher increases for customers using higher voltages, to reduce the effects of historical cross-subsidies in their favor. The following table sets forth the percentage increase in our tariffs resulting from each annual adjustment from 2001 through the date of this annual report. Rates of tariff increase should be evaluated in light of the rate of Brazilian inflation. See “ ¾ Background ¾ Brazilian Economic Conditions.”

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2003 Periodic Revision

     The following description provides additional details on the 2003 Periodic Revision and related tariff adjustments.

      Piratininga . In October 2003, ANEEL established, on a provisional basis, Piratininga’s 2003 periodic revision at a rate of 18.08%. However, only 14.68% took effect, with the remaining increase deferred to the 2004-2006 annual adjustments. In October 2004, ANEEL decreased, also on a provisional basis, Piratininga’s 2003 periodic revision from 18.08% to 10.51%. The effect of the October 2004 downward tariff adjustment in our audited consolidated financial statements for the year ended December 31, 2004 was the following: (1) a reversal of the regulatory asset related to the difference between 18.08% and 14.68%, in the amount of R$14 million, which was recorded as revenue in 2003 and (2) the creation of a regulatory liability related to the difference between 14.68% and 10.51%, in the amount of R$71 million, to be refunded to customers in future periods. The source of this downward revision relates to our acquisition of Piratininga in 2001, when Bandeirante was divided into two companies—Bandeirante and Piratininga. Under the terms of the division of Bandeirante, ANEEL decreed that future tariff adjustments for both companies would be based on the tariff realignment index of either Bandeirante or Piratininga, whichever was lower. The downward revision in Piratininga’s tariff adjustment reflects Bandeirante’s lower tariff realignment index, which was applied to Piratininga in accordance with ANEEL rules, in October 2004. These percentage adjustments are still provisional adjustments.

      Paulista . In April 2003, ANEEL established, on a provisional basis, Paulista’s periodic revision at a rate of 19.55%, which was modified in April 2004 to 21.10%. In April 2005, ANEEL officially confirmed that Paulista’s 2003 periodic revision would be set a rate of 20.29%. We believe that ANEEL underestimated Paulista’s appropriate tariff increase and have appealed to ANEEL to reevaluate its initial decision. We believe that the correct percentage increase for the 2003 periodic revision should be 20.66%.

      RGE . In April 2003, ANEEL established, on a provisional basis, RGE’s periodic revision at a rate of 27.36%, which was officially confirmed to be 27.96% in April 2004.

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 customers, the number of potentially free consumers is relatively small, but those customers represent a significant volume of our electricity sales and revenues. In 2004, approximately 38% of our electricity sales by volume were made to potentially free consumers. Most of our potentially free consumers have not elected to become free consumers. We believe this is because (1) they consider that the advantages of negotiating for a long-term contract at lower rates than the regulated tariff are outweighed by the need to bear additional costs (particularly transmission costs) and the long-term price risk and (2) some of our potentially free consumers, those that consume between 500 kW and 3 MW and with a contracted demand equal to

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or greater than 3 MW serviced in voltages lower than 69 kV, and who entered into contracts before July 1995, are limited to electricity purchases 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 becomes a free consumer, it would still have to pay us network usage charges, and such payments would mitigate the loss in operating income from any such migration. Furthermore, the majority of customers in our distribution concession areas that have opted to be come free consumers now purchase their electricity from CPFL Brasil. In the short term, we do not expect to see a substantial number of our customers become free consumers, but the prospects for migration over the long term, and its implications for our financial results, are difficult to predict.

Prices for Purchased Electricity

     We purchase the majority of our electricity under long-term contracts with large Brazilian generation companies, and the prices under these contracts are subject to regulation. In 2004, we purchased 26,339 GWh (63.6% of the volume of electricity we purchased) from nine generators under long-term contracts, as opposed to 26,011 GWh (64.3% of the volume of electricity we purchased) from eight generators under long-term contracts in 2003. The prices under these long-term contracts are adjusted annually to reflect increases in certain generation costs and the IGP-M inflation index. The adjustment is linked to the annual adjustment in distribution tariffs, so that the increased costs are passed on to our customers in increased tariffs.

     The Initial Supply Contracts (as defined in the “Glossary of Terms”) are scheduled to expire in December 2005 (stepping down in volume 25% per year beginning in 2003). In practice, the replacement of energy purchased under the Initial Supply Contracts with energy purchased under new electricity supply agreements takes place in January each year. The price for newly contracted energy is usually higher than the existing prices under the Initial Supply Contracts. The result until December 2005 is a temporary increase in our costs that is not passed through to customers until the next tariff adjustment. Additionally, as of November 2004, the MME authorized the inclusion in the Parcel A account ( conta de compensação de variação de valores de parcela A ), or CVA, of the differences between the costs of acquiring electricity and the prices charged to our customers that were not taken into account in the prior year’s tariff adjustment. This adjustment should eliminate the difference in the result that originated from these variations. However, our cash flows will continue to be adversely affected until the amounts under CVA are received in future years.

     Before the enactment of the New Industry Model Law, ANEEL determined tariff adjustments based on projected costs of electricity acquired in the previous year. As such, the tariff adjustment in any given year would not take into account the changes that could occur in the composition of electricity suppliers (especially to the extent the Initial Supply Contracts are being gradually reduced), which could make the average price effectively paid for the energy purchased higher than the one projected by ANEEL and passed through to tariffs. With the New Industry Model Law, the calculation method of the costs of acquired energy was changed, and now, with respect to new electricity contracts derived from auctions, the adjustment must reflect the electricity cost in the future reference market.

     Currently, electricity already purchased is subject to the regulation existing prior to the New Industry Model Law and the electricity to be purchased in auctions will be subject to the new regulation.

     A considerable part of our long-term agreements is comprised of Initial Supply Contracts. Pursuant to applicable law and regulation, as of 2003 the quantity of electricity acquired under these contracts is reduced every year by 25% of the quantity originally contracted. In 2004, Initial Supply Contracts accounted for 14,758 GWh, or 35.7% of our electricity purchases, as compared to 23,012 GWh, or 56.9% of our electricity purchases in 2003. As these contracts step down, and as our requirements increase to meet demand, we will need to enter into other long-term supply contracts through public bids in the Regulated Market. Our success in managing this process will affect our margins and our exposure to price risk, since our ability to pass-through costs of electricity purchases will be linked to the successful projection of our expected demand. At present, we have sufficient electricity under contract to supply our projected requirements through 2005, after giving effect to the stepdown of our Initial Supply Contracts discussed above. We do not expect that we will need to contract for substantial quantities of additional electricity until 2007. We believe this will permit us to await full implementation of the New Industry Model Law before we must make substantial purchases other than the amounts for which we have already contracted.

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     Our generation subsidiaries are scheduled to bring online, through 2008, approximately 1,135 MW of new capacity that provides additional Assured Energy of 4,614 GWh per year. Our distribution subsidiaries have entered into long-term contracts to purchase all this electricity, and this new supply will replace part of the electricity we will lose from the stepdown of our Initial Supply Contracts. 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 both the generators’ margin and the distributors’ margin.

     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 2004, we purchased 10,336 GWh of electricity from Itaipu (25.0% of the volume of electricity we purchased), as compared to 10,574 GWh of electricity from Itaipu (26.1% of the volume of electricity we purchased) in 2003. See “Information on 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 real terms when the real depreciates against the U.S. dollar. The change in our costs for Itaipu electricity in any year is subject to the Parcel A cost recovery mechanism described below.

Recoverable Cost Variations—Parcel A Costs

     Beginning in 2001, the Brazilian government created the CVA or the Parcel A account to recognize some of our costs in the distribution tariff, referred to as “Parcel A” costs, as beyond our control. These costs are described in Note 10 to our audited consolidated financial statements for the fiscal year ended December 31, 2004. 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. Similarly, if Parcel A costs are lower than forecast, we generally pass-through the savings to customers through lower tariffs in the future.

     When there are variations in Parcel A costs that will be reflected in future tariffs, we defer the incremental costs and record them on our balance sheet as the CVA. We will recognize these amounts as expenses when we collect the related increased tariffs. At December 31, 2004, we had assets of R$1,044 million and liabilities of R$196 million in respect of Parcel A accounts, and the net amount represented 20.7% of our shareholders’ equity. These amounts accrue interest at a rate based on SELIC, a Brazilian money market rate. In 2004 we recognized R$131 million of net financial income on Parcel A accounts.

The 2001-2002 Energy Crisis and Related Regulatory Measures

     The Brazilian Government adopted an electricity Rationing Program from June 2001 through February 2002 that resulted in a reduced supply of electricity in much of Brazil. The resulting decrease in electricity consumption and the increase in electricity prices (which also resulted from other macroeconomic developments) had adverse effects on the Brazilian electricity industry and on the financial condition of distribution and generation companies, and in late 2001 and early 2002, such companies agreed with the Brazilian government on a package of measures to address some of these effects. These measures affected our financial performance, particularly in 2001, and the regulatory consequences still affect our financial condition. See Note 3 to our audited consolidated financial statements. The principal measures adopted in response to the 2001-2002 energy crisis are the following:

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Deductions from Operating Revenues

     To present net operating revenues, we deduct from our operating revenues a variety of taxes and regulatory charges, the most important of which is value-added tax, or ICMS, imposed by Brazilian states. These deductions amounted to 29.5% of our gross operating revenues in 2004 and 25.1% in 2003. The increase in 2004 was primarily due to an increase in the rate of the COFINS revenue tax, from 3.0% to 7.6%. Despite the increase in the COFINS tax rate, a change in the law now allows us to derive COFINS tax credits related to a significant portion of our operating costs and expenses. Pursuant to an instruction from IBRACON, such credits are deducted from each expense account.

     The increase in 2003 was due primarily to (a) the imposition of an emergency capacity charge, which came into effect in March 2002 and (b) the value-added tax on the collection of tariffs attributable to the RTE. In 2003, we billed and collected RTE tariffs, and although these amounts had already been recognized and accordingly did not affect our gross operating revenues, we did recognize the associated value-added tax as a deduction in arriving at net operating revenues. As a result, our effective rate of value-added tax increased substantially in 2003. See “—Background—The 2001-2002 Energy Crisis and Related Regulatory Measures.”

Operating Segments

     Our three reportable segments are distribution, generation and commercialization. See Note 36(iv)(d) to our audited consolidated financial statements. Our generation and commercialization segments are new and currently represent a small percentage of our gross operating revenues – 5.1% in 2004 and 3.9% in 2003. We expect our generation business to grow as our projects come on line through 2008. Since the new electricity will be sold primarily to our distribution companies, on a consolidated basis the new generation may not materially increase our operating revenues but we expect it to have a positive effect on our consolidated operating margin.

     The profitability of our segments differs. Our generation segment consists in substantial part of new hydroelectric 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. Once these projects are operational, they have higher margin (operating income as a percentage of revenue) than the distribution segment, but they also contribute to higher

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interest expense and other financing costs. For example, in 2004 and 2003 our generation segment provided 19% and 27%, respectively, of our operating income, but its contribution to our net income was substantially lower.

     In our commercialization segment, for the year ended December 31, 2004, a majority of our sales and operating income were attributable to transactions with our distribution segment. As our commercialization business grows in future periods, we expect a higher proportion of its sales and operating income will be from transactions with unaffiliated parties, such as sales to free consumers and the provision of value-added services.

Brazilian Economic Conditions

     As a company with all of its operations in Brazil, we are affected by general economic conditions in the country. 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 a very low growth from 2001 through 2003 and an economic recovery in 2004.

     In October of 2002, Luis Inácio da Silva of the Labor Party was elected president of Brazil. His administration largely continued the macroeconomic policies of the previous administration under Fernando Henrique Cardoso. The real appreciated by 18.2% against the U.S. dollar in 2003 to R$2.8892 per US$1.00 at December 31, 2003. Inflation for 2003, as measured by the IGP-M, was 8.7%. However, real gross domestic product decreased by 0.2% during 2003 largely because the very high interest rates that prevailed at the beginning of 2003 also constrained economic growth. The Brazilian economy showed signs of improvement in the third and fourth quarters of 2003 that continued through 2004.

     In 2004, the resumption of economic growth became more visible, particularly in those sectors more sensitive to more widespread availability of credit. This recovery led to improvements in the labor market. Brazilian GDP grew by 5.2% in 2004 and the value of the real increased by 8.5% against the U.S. dollar between December 31, 2003 and December 31, 2004. The Central Bank decreased the short-term interest rates (adjusted in relation to the SELIC index) from 26.5% at December 31, 2003 to 16.3% at December 31, 2004. Inflation for 2004, as measured by the IGP-M, was 12.4%.

     The following table shows inflation, the change in real gross domestic product and the fluctuation in value of the real against the U.S. Dollar for the years ended December 31, 2004, 2003 and 2002.

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     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 lag in time between when the increased costs are incurred and when the increased revenues are received following our annual tariff adjustments.

Results of Operations—2004 compared to 2003

Operating revenues

     Our gross operating revenues were R$9,549 million in 2004. This was 18.2% higher than in 2003, primarily reflecting a 11.3% increase in average prices on sales to final customers and a 4.2% increase in the total volume of electricity delivered to final customers. Nearly all of our gross operating revenues result from sales to final customers (R$8,869 million, or 92.9%, in 2004), and the increases in price and in volume were similar for every major category of final customer. See Note 24 to our audited consolidated financial statements for a breakdown of revenues by category of final customer.

     Our net operating revenues were R$6,736 million in 2004. This was 11.2% higher than in 2003, reflecting the 18.2% increase in gross operating revenues discussed above. This increase was partially offset by the increase in the rate of the COFINS tax. See “—Background—Deductions from Operating Revenues” for a discussion of items we deduct from our operating revenues.

      Prices and volumes on sales to final customers

     Our average prices in 2004 increased for all categories of final customers. Tariffs are adjusted annually, in April for Paulista and RGE and in October for Piratininga. See “—Background—Regulated Distribution Tariffs.” Our higher operating revenues in 2004 reflected annual adjustments in 2003 and 2004. The increase in average prices from 2003 to 2004 was 14.7%, 13.8% and 13.1% for rural, commercial and residential customers, respectively, because of tariff adjustments. The increase in average prices for industrial customers was 8.5%, due mainly to tariff adjustments for captive industrial consumers. The increase for industrial consumers was offset by lower sales prices applicable to industrial consumers in the free market due to competitive forces and the fact that the average price in the free market does not reflect revenues from TUSD, a tariff paid to us by free consumers in our concession areas.

     The total volume of electricity sold to final customers, which was 35,928 GWh in 2004 compared to 34,471 GWh in 2003, in each case excluding our own consumption, increased for all categories of final customers. Consumption by industrial customers, which increased by 5.8% in 2004, also reflected improved economic performance in our concession areas.

      Sales to distributors

     Operating revenues from sales to unaffiliated distributors were R$310 million in 2004 (3.3% of our gross operating revenues), representing an increase of 12.7% compared to 2003. The increase was due primarily to (a) sales by our generation subsidiary Semesa to Furnas under a long-term contract, which increased from R$233 million in 2003 to R$254 million in 2004 because of price adjustments, and (b) sales to other concessionaires and licensees, consisting primarily of sales by CPFL Brasil, which increased from R$24 million in 2003 to R$44 million in 2004.

      Other operating revenues

     Our other operating revenues were R$369 million in 2004 (3.9% of our gross operating revenues), as compared to R$157 million in 2003, primarily reflecting an increase of R$180 million related to electricity network usage charges.

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Operating Costs and Operating Expenses

      Electricity purchased for resale

     Our costs to purchase electricity were R$3,126 million in 2004 (56.1% of our total operating costs and operating expenses). This was 3.5% higher than in 2003, primarily resulting from (a) an increase in the volume of electricity we purchased and (b) price increases applicable to our long-term purchase contracts, which were offset by lower prices for electricity from Itaipu. The increase in costs to purchase electricity was partially offset by PIS and COFINS tax credits. See “—Deductions from Operating Revenues.”

     The average price for all purchases excluding Itaipu was 12.6% higher in 2004 than in 2003, because of the effect of the annual adjustment and the replacement of volume under our Initial Supply Contracts. The average price for electricity purchased from Itaipu, which represented 25.0% of the volume we purchased in 2004, was on average 1.3% less expensive in 2004 than in 2003. The real drop in price reflected the rise in the value of the real against the U.S. dollar in 2004, which proved more significant than the increase in nominal prices. Additionally, the PIS and COFINS tax credits reduced our expenses related to electricity purchased for resale by R$289 million in 2004.

     In the aggregate, we purchased 2.3% more electricity in 2004, because of an increase in volume sold to final consumers and other concessionaires and licensees. See “—Background—Prices for Purchased Electricity.” Note 25 to our audited consolidated financial statements provides a breakdown of our electricity purchase costs and volumes by supplier.

      Electricity network usage charges

     Our costs for electricity network usage charges were R$679 million in 2004. This was 52.3% higher than in 2003, due to (a) higher tariffs and increased use of the transmission grid, (b) the deferment and amortization of assets and liabilities related to the Parcel A account and (c) PIS and COFINS tax credits. See “—Deductions from Operating Revenues.”

      Other costs and expenses

     Our other costs and expenses (other than electric utility service costs) were R$1,764 million in 2004. This was 9.5% lower than in 2003, due primarily to the change in the amortization of goodwill as from January 1, 2004, which resulted in a decrease in amortization of R$422 million in 2004. The decrease in costs was offset by an increase in the CDE Account from R$78 million to R$185 million. See Note 13 to our audited consolidated financial statements for a discussion of the change in the amortization of goodwill.

Operating Income (Loss)

     Our operating income was R$1,168 million in 2004, as compared to income of R$642 million in 2003, due primarily to revenue growth and lower operating expenses, as discussed above.

Net Financial Expense

     Our net financial expense was R$568 million in 2004, compared to R$821 million in 2003. The decrease of 30.9% reflected a reduction in financial expense, which was R$1,006 million in 2004 compared to R$1,405 million in 2003, partly offset by a decrease in financial income, which was R$438 million in 2004 compared to R$584 million in 2003.

     At December 31, 2004, we had R$4,130 million of debt denominated in reais, which accrued both interest and monetary correction based on a variety of Brazilian indices and money market rates. The lower financial expense in 2004 resulted primarily from (a) lower rates of index variation (the CDI, in particular, went from 23.3% in 2003 to 16.2% in 2004) and (b) an approximately 6.5% lower average level of indebtedness. At December 31, 2004 we had the equivalent of R$777 million (US$293 million) of debt denominated in U.S. dollars, on which we

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recognize exchange loss if the real depreciates against the U.S. dollar. To reduce the risk of exchange losses with respect to this U.S. dollar-denominated debt, we have entered into long-term currency swaps with respect to a significant portion of this debt, and we recognize our gains and losses on these swaps as part of our net financial expense.

Net Non-operating Income (Expense)

     We had net non-operating expense of R$4 million in 2004, compared to net non-operating income of R$44 million in 2003. The change was primarily due to a R$40 million gain in 2003 on the sale of part of our interests in our generation affiliates ENERCAN and BAESA. The components of non-operating income and expense are set forth in Note 28 to our audited consolidated financial statements.

Income and Social Contribution Taxes

     We recorded a net charge of R$254 million for income and social contribution taxes in 2004. Our effective tax rate of 42.6% on pretax income exceeded the combined statutory rate of 34% primarily because (1) part of our amortization of goodwill arising from acquisitions is not deductible for tax purposes and (2) CPFL Energia and its subsidiaries are not consolidated for Brazilian tax purposes. Losses at the holding company level accordingly cannot be used to offset present or future taxable income at the subsidiary level, and they do not result in deferred tax credit because of the absence of past profits. In 2003, we had a net charge of R$111 million although we reported a pretax loss, due to the same reasons described above.

Extraordinary Item

     We recorded a charge of R$34 million for extraordinary item, net of taxes of R$17 million, in each of 2004 and 2003. The charge resulted from a change in accounting for post-retirement benefits plans under Brazilian Accounting Principles. We are recognizing the initial effect of this change in income as an extraordinary item, net of taxes, over a five-year period from 2002 through 2006.

Net Income (Loss)

     Our net income was R$287 million in 2004, compared to a net loss of R$282 million in 2003, due primarily to the increase in our operating income in 2004, reflecting the combination of higher operating revenues, the change in the goodwill amortization period and the decrease in net financial expense.

Results of Operations—2003 compared to 2002

Operating revenues

     Our gross operating revenues were R$8,082 million in 2003. This was 18.4% higher than in 2002, primarily reflecting a 16.5% increase in average prices on sales to final customers and a 6.4% increase in the total volume of electricity delivered to final customers. Nearly all of our gross operating revenues result from sales to final customers (R$7,649 million, or 94.6%, in 2003), and the increases in price and in volume were similar for every major category of final customer. See Note 24 to our audited consolidated financial statements for a breakdown of operating revenues by category of final customer.

     Our net operating revenues were R$6,057 million in 2003. This was 15.1% higher than in 2002, reflecting the 18.4% increase in gross operating revenues discussed above. See “—Background—Deductions from Operating Revenues” for a discussion of items we deduct from our operating revenues.

      Prices and volumes on sales to final customers

     Our average prices in 2003 increased for all categories of final customers. Tariffs are adjusted annually, in April for Paulista and RGE and in October for Piratininga. See “—Background—Regulated Distribution Tariffs.” Our higher operating revenues in 2003 reflect annual adjustments in 2002 and 2003. The increase in average prices

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from 2002 to 2003 was greatest for residential customers, because a regulatory change in 2002 made some residential customers ineligible for special lower tariffs for low-income consumers. The increase in average prices was smallest for industrial customers, because larger industrial customers improved the management of their consumption of electricity to reduce the average price they paid.

     The total volume of electricity sold to final customers, which was 34,471 GWh in 2003 compared to 32,409 GWh in 2002, in each case excluding our own consumption, increased for all categories of final customers. In part, this was because consumption continued to recover from the lower levels that followed the Rationing Program. Consumption by industrial customers, which increased by 7.5% in 2003, also reflected growth in consumption by exporters, particularly in Piratininga’s concession area.

      Sales to distributors

     Operating revenues from sales to unaffiliated distributors were R$275 million in 2003 (3.4% of our gross operating revenues). This was 33.1% lower than in 2002, because we sold less power to the Energy Trading Chamber (1,349 GWh in 2003, compared to 3,212 GWh in 2002). These revenues primarily consist of (a) sales by our generation subsidiary Semesa to an unaffiliated purchaser under a long-term contract and (b) sales to the Energy Trading Chamber of electricity we purchased under long-term supply contracts that exceeded our deliveries of electricity to final customers. Semesa’s sales increased from R$190 million in 2002 to R$233 million in 2003, primarily because of price adjustments. Sales to the Energy Trading Chamber decreased from R$230 million in 2002 to R$22 million in 2003. Our long-term contracts largely reflect projections of our requirements that were made before the Rationing Program, and as a result the volume of electricity we purchased in 2002 exceeded the volume we sold to final customers. The amount of excess declined in 2003 as consumption recovered and as the volume purchased under our Initial Supply Contracts began to step down.

      Other operating revenues

     Our other operating revenues were R$157 million in 2003 (1.9% of our gross operating revenues). This was 107% higher than in 2002, reflecting several categories of increased revenues. Payments under government subsidy programs for low-income customers were R$32 million in 2003 and we did not receive these payments in 2002; revenues from rental of pole space were R$37 million in 2003 compared to R$29 million in 2002; fees for transmission over our network were R$36 million compared to R$8 million in 2002; and revenues from value-added services were R$20 million compared to R$13 million in 2002.

Operating Costs and Operating Expenses

      Electricity purchased for resale

     Our costs to purchase electricity were R$3,020 million in 2003 (55.8% of our total operating costs and operating expenses). This was 18.1% higher than in 2002, primarily because the deferral of Parcel A costs reduced our costs by R$242 million in 2002 and increased our costs by R$95 million in 2003. Our Parcel A costs rose in 2002 but decreased in 2003 because of lower costs for Itaipu electricity, as described below.

     In the aggregate, we purchased 2.8% less electricity in 2003, because the volume under our Initial Supply Contracts stepped down by 25% pursuant to their terms, and we did not replace all of this electricity, based on our strategic management of long-term supply. See “—Background—Prices for Purchased Electricity.” Note 25 to our audited consolidated financial statements provides a breakdown of our electricity purchase costs and volumes by supplier. This reduction in the volume of purchased electricity, combined with a 6.4% increase in the volume of electricity delivered to final customers, led us to sell substantially less electricity to distributors through the Energy Trading Chamber, as discussed above.

     The higher prices in 2003 resulted from price increases applicable to our long-term purchase contracts, which were offset by lower prices for electricity from Itaipu. The average price for all purchases excluding Itaipu was 20.2% higher in 2003 than in 2002, because of the effect of the annual adjustment and the replacement of volume under our Initial Supply Contracts. The average price for electricity purchased from Itaipu, which

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represented 26.1% of the volume we purchased in 2003, was on average 13.3% less expensive in 2003 than in 2002, reflecting changes in Itaipu’s cost structure.

      Electricity network usage charges

     Our costs for electricity network usage charges were R$446 million in 2003. This was 42.1% higher than in 2002, reflecting higher tariffs for use of the transmission grid.

      Other costs and expenses

     Our other costs and expenses (other than electric utility service costs) were R$1,950 million in 2003. This was 1.2% higher than in 2002. The two principal changes largely offset each other: a R$47 million increase in the CCC (R$339 million in 2003, compared to R$292 million in 2002) and a R$45 million decrease in charges for pensions (R$84 million in 2003, compared to R$129 million in 2002). The increase in the fuel usage quota in 2003 was a result of higher use of thermal generation during the drought of 2001-2002. The lower pension charges reflect the implementation of changes in Brazilian pension accounting, because in 2003 we reversed some charges we had recognized in 2002 upon the initial adoption of new CVM rules.

     The stability of our other costs and expenses, despite inflation of 8.7% in 2003 as measured by the IGP-M, reflected our cost control program, and particularly personnel reductions and other operating synergies between Paulista and Piratininga. In 2003, we recognized R$532 million of amortization of goodwill that relates to our successive acquisitions. See Note 13 to our audited consolidated financial statements.

Operating Income

     Our operating income was R$642 million in 2003. This was 37.6% higher than in 2002, because of revenue growth, the effect of lower costs for electricity from Itaipu and the stability of our operating costs and expenses.

Net Financial Expense

     Our net financial expense was R$821 million in 2003, compared to R$1,301 million in 2002. The decrease reflected a reduction in financial expense, which was R$1,405 million in 2003 compared to R$2,077 million in 2002, partly offset by a decrease in financial income, which was R$584 million in 2003 compared to R$776 million in 2002.

     At December 31, 2003, we had R$4,098 million of debt denominated in reais, which accrued both interest and monetary correction based on a variety of Brazilian indices and money market rates. The lower financial expense in 2003 resulted primarily from (a) lower rates of index variation (the IGP-M, in particular, went from 25.3% in 2002 to 8.7% in 2003), (b) an approximately 9% lower average level of indebtedness and (c) lower exchange loss. At December 31, 2003 we had the equivalent of R$1,152 million (US$371 million) of debt denominated in U.S. dollars, on which we recognize exchange loss whenever the real depreciates against the U.S. dollar. To reduce the risk of exchange losses with respect to this U.S. dollar-denominated debt, we have entered into long-term currency swaps with respect to a significant portion of this debt, and we recognize our gains and losses on these swaps as part of our net financial expense.

Net Non-operating Income (Expense)

     Our net non-operating income was R$44 million in 2003, compared to R$10 million in 2002. The change was primarily due to a gain of R$40 million on the sale of part of our interests in our generation affiliates ENERCAN and BAESA. The components of non-operating income and expense are set forth in Note 28 to our audited consolidated financial statements.

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Income and Social Contribution Taxes

     We recorded a net charge of R$111 million for income and social contribution taxes in 2003, although we had a pretax loss. In 2002, we had an even larger pretax loss, so we recognized net credits for income and social contribution taxes of R$88 million.

Extraordinary Item

     We recorded a charge of R$34 million for extraordinary item, net of taxes of R$17 million, in each of 2003 and 2002. The charge resulted from a change in accounting for post-retirement benefits plans under Brazilian Accounting Principles. We are recognizing the initial effect of this change in income as an extraordinary item, net of taxes, over a five-year period from 2002 through 2006.

Minority Interest

     Minority interest was a charge of R$2 million in 2003, compared to a credit of R$21 million in 2002. In each period, minority interest primarily represented the interest of outside shareholders in our subsidiaries, particularly our principal distribution subsidiaries Paulista and Piratininga. The lower minority interest charge in 2003 reflected a lower level of losses at Paulista and in our generation business.

Net Loss

     Our net loss decreased to R$282 million in 2003, from R$749 million in 2002. The reduced loss was due to the increase in our operating income in 2003, reflecting the combination of higher operating revenues and stable operating costs, and the decrease in net financial expense.

     We plan to make capital expenditures aggregating approximately R$723 million in 2005 and approximately R$681 million in 2006. Of total budgeted capital expenditures over this period, R$627 million is for distribution and R$777 million is for generation. 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.”

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Liquidity and Capital Resources

Funding Requirements and Contractual Commitments

     Our capital requirements are primarily for the following purposes:

     The following table summarizes our contractual obligations as of December 31, 2004. The table does not include accounts payable or pension liabilities, each of which is reported on our balance sheet.

Sources of Funds

     We generate substantial cash from our operations, but it can vary from period to period as Parcel A costs change. Under our regulatory system, we regularly recover some of our increased costs from one period through tariff adjustments in future periods, and we will recover some foregone revenues from July 2001 through February 2002 through the RTE in future periods. Our cash from operations will be positively affected in the future periods

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when we actually realize these amounts. Net cash provided by operating activities was R$766 million in 2004, as compared to net cash provided of R$947 million in 2003. Such decrease is explained by financial investments in the amount of R$318 million made in 2004, which amount is recorded as reducing our net cash provided by operating activities in that same year.

     Net cash used in financing activities was R$86 million in 2004, as compared to R$526 million in 2003. In 2003, we raised R$1,200 million in cash from our shareholders. We do not expect any further capital contributions from our principal shareholders in the foreseeable future. In September 2004, we raised R$685 million from our initial public offering.

     Our debt decreased in 2004 by R$343 million, primarily as a result of pre-paying our debentures. In 2005 and 2006, we expect to fund the completion of work on our generation projects by drawing on credit facilities and using the proceeds of our initial public offering. With these sources of funds, and cash flows from operations, we do not expect to increase our total debt in 2005 and 2006, except for financings associated with our generation projects. This expectation could change if there is a major change in the tariff system or in economic conditions in the power sector or in Brazil generally.

Terms of Outstanding Debt

     Total debt outstanding at December 31, 2004 (excluding accrued interest) was R$4,907 million, a decrease of 6.5% from R$5,250 million at December 31, 2003. Of the total amount, approximately R$777 million, or 15.8%, was denominated in U.S. dollars, and the balance was denominated in reais . R$1,122 million of our total debt is scheduled to mature in the next 12 months.

     Our major categories of indebtedness are as follows:

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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:

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     We are currently in compliance with our financial and operating covenants, including those set forth in the above paragraphs. Breach of any of these covenants would give our lenders the right to accelerate our repayment obligations.

     In addition, a number of our financing instruments are subject to acceleration if our current shareholders cease to own a majority of CPFL Energia’s voting equity or otherwise control the management and policies of the company, or if VBC ceases to own, directly or indirectly, at least 25% of Paulista’s issued and outstanding capital stock.

     The ability of our subsidiaries to pay dividends is subject to the following material restrictions under agreements to which they are party: (a) for RGE to pay dividends in excess of the legal minimum under Brazilian law, we require the agreement of the other investor in RGE and (b) our Campos Novos, Barra Grande and CERAN generation projects are restricted from paying dividends under their financing agreements. In 2004, we enhanced the ability of our subsidiaries to pay dividends to us by undertaking certain corporate reorganizations with respect to Paulista and Piratininga. Additionally, for Piratininga, the change will permit it to deduct for tax purposes the goodwill amortization that was previously recorded in an intermediate holding company’s financial statements. This will improve the prospects for subsidiaries to pay dividends to us.

     The concessions for our distribution and generation subsidiaries prohibit them from making loans or advances to us or to our other subsidiaries and affiliates without approval from ANEEL. Most of our debt instruments also provide that if there is a default under a covenant, the company in question will be limited in its ability to pay dividends in excess of the legal minimum under Brazilian law.

     We and our controlling shareholders, VBC, 521 and Bonaire, entered into a Share Retention Agreement with IFC, under which they agree to maintain, as a group, direct ownership of 51% of our outstanding voting shares and direct or indirect ownership of 51% of the issued and outstanding voting shares of Paulista and CPFL Geração. In addition, each of our controlling shareholders agrees to maintain direct ownership of at least 5% of our outstanding voting shares and direct or indirect ownership of at least 5% of the outstanding voting shares of Paulista and CPFL Geração. If it provides cash collateral as provided in the Share Retention Agreement, Bonaire will be permitted to reduce its ownership percentage of our voting shares and the voting shares of Paulista and CPFL Geração below the levels described above.

     In connection with the Investment Agreement, IFC, CPFL Geração and CPFL Centrais Elétricas entered into a Shareholders Agreement for the governance of CPFL Centrais Elétricas. Under the Shareholder Agreement, IFC’s approval is required for certain actions by CPFL Centrais Elétricas, including amendments to its bylaws, the issuance of additional shares, any merger, consolidation or other corporate restructuring or, any transfer of its assets.

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

Off-Balance Sheet Arrangements

     We have guaranteed some of the debt of our proportionately consolidated subsidiaries. These guarantees are generally of a proportion of the debt that is no greater than our proportionate ownership share of the subsidiary. During 2004, however, we guaranteed the full amount payable under R$436 million of credit facilities (not all of which has been drawn) of our subsidiary CERAN, while we will only report our proportionate 65% share of the liabilities on our balance sheet. Additionally, in 2005 we guaranteed 57.27% of the amount payable under a US$75 million credit facility (not all of which has been drawn) of our subsidiary ENERCAN, while we only report our proportionate 48.72% share of the liabilities on our balance sheet. As of December 31, 2004, we had no: (a) guarantee obligations (as described in paragraph 3 of FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees), with the exception of the CERAN guarantee described above; (b) retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements; (c) obligations under derivative instruments that are indexed to our common shares and classified in shareholders’ equity; or (d) obligations arising out of a variable interest in an unconsolidated entity, as defined in FASB Interpretation No. 46, Consolidation of Variable Interest Entities.

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U.S. GAAP Reconciliation

     We prepare our financial statements in accordance with Brazilian Accounting Principles, which differ in significant respects from U.S. GAAP. The differences are described in Note 36 to our audited consolidated financial statements. Net income for 2004 was R$389 million under U.S. GAAP, compared with net income of R$287 million under Brazilian Accounting Principles. Shareholders’ equity at December 31, 2004 was R$5,277 million under U.S. GAAP, compared to R$4,096 million under Brazilian Accounting Principles.

     The differences between Brazilian Accounting Principles and U.S. GAAP that have the most significant effects on net income and shareholders’ equity are the following:

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. We have discussed in “—Background” above certain accounting policies relating to regulatory matters. In the discussion below, we have identified several other matters for which our financial presentation would be materially affected if either (a) we used different estimates that we could reasonably have used or (b) 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, goodwill and investments comprise a significant amount of our total assets. We carry balances on our balance sheet that are based on historical costs net

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of accumulated depreciation and amortization. We are required under both Brazilian Accounting Principles and U.S. GAAP 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. Changes in these judgments could require us to recognize impairment losses in future periods. Our evaluations in 2004 and 2003 did not result in any significant impairment of our property, plant and equipment or consolidated goodwill.

Valuation of Deferred Regulatory Assets

     As discussed above, we defer and capitalize Parcel A costs that we expect to recover through rate increases, and in 2001 and 2002 we recognized revenues that we will realize in future years pursuant to the RTE. We take this approach under Brazilian Accounting Principles, and under U.S. GAAP it is also consistent with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). SFAS 71 provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those costs in rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amount of net deferred regulatory assets reflected in the consolidated balance sheets, including interest we have recognized, was R$1,438 million at December 31, 2004, of which R$98 million (composed of R$39 million related to low income consumers regulatory asset; R$46 million related to the PIS and COFINS regulatory asset and R$13 million related to CVA related to energy purchased) is still pending official confirmation by ANEEL. See Note 3 to our audited consolidated financial statements. Under U.S. GAAP, we only recognize the deferred revenues to the extent we expect to recover them over the next 24 months.

     We are entitled to recover these costs through Brazilian regulations. ANEEL performs a rate review on an annual basis. If ANEEL excludes all or part of a cost from recovery, that portion of the deferred regulatory asset is impaired and is accordingly reduced to the extent of the excluded cost. In 2004 we recognized an accrual in the amount of R$32 million against a revenue account related to the RTE. See Note 3(a) to our audited consolidated financial statements for the year ended December 31, 2004.

     The deferral and capitalization of expenses, and the recognition and deferral of revenues, in this manner is based on our judgment that we will in fact recover the amounts under future rate increases. If our judgment as to the likelihood of recovery changes, we could be required to recognize an impairment of these regulatory assets.

Sales to the Energy Trading Chamber (formerly known as the Wholesale Energy Market)

     We engage in both sales and purchases of electricity with the Energy Trading Chamber, and the amounts we recognize as revenues and costs for these transactions are based on our estimates of volumes and prices, which are subject to subsequent confirmation by the Energy Trading Chamber. There are also legal challenges pending that could also affect the accounting for transactions with the Energy Trading Chamber in 2001 and 2002. See Note 6 to our audited consolidated financial statements. If our estimates prove incorrect or are not confirmed for any other reason, we would have to write off part of this amount. In the past, however, we have not had material disagreements with the Energy Trading Chamber over these amounts.

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 Brazilian Accounting Principles, which are similar to SFAS No. 87 “Employers’ Accounting for Pensions” and SFAS No. 106 “Employers’ Accounting for Post-retirement Benefits other than Pensions.” The determination of the amount of our obligations for pension and other post-retirement benefits depends on certain actuarial assumptions. Beginning in 2004, two of these assumptions were modified in accordance with the findings of a study by Fundação CESP – the mortality table and the expected nominal rate of return on plan assets – which tend to reduce the amount of our obligations. The results of this study

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will be reviewed annually. The total amount of our obligations recognized as expenses in 2004 was R$202 million. In 2005, the estimated amount of obligations to be recognized as expenses is R$139 million. The two changes described above and the rest of the actuarial assumptions, including the discount rate applied to future obligations and increases in salaries and benefits, are described in Note 19 (Brazilian Accounting Principles) and Note 36 (U.S. GAAP) to our audited consolidated financial statements.

Deferred Tax Assets and Liabilities

     We account for income taxes in accordance with Brazilian Accounting Principles, which are similar to SFAS No. 109 “Accounting for Income Taxes,” 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. Under Brazilian Accounting Principles, the tax asset is not recognized if it is more likely than not that it will not be realized. Under U.S. GAAP, we establish a valuation allowance based on historical taxable income, projected future taxable income, and the expected timing of the reversals of existing temporary differences. If we are unable to generate sufficient future taxable income, or if there is a material change in the actual effective tax rates or time period within which the underlying temporary differences become taxable or deductible, we could be required to establish a valuation allowance against all or a significant portion of our deferred tax assets resulting in a substantial increase in our effective tax rate and a material adverse impact on our operating results.

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 Brazilian Accounting Principles, which are similar to SFAS No. 5, “Accounting for Contingencies.” Such accruals are estimated based on historical experience, the nature of the claims, as well as 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. Management has applied its best judgment in applying SFAS No. 5 to these matters.