CPFL Energy (CPL) 20-F 2014 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, 2014
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 142
CEP 04547‑005 Vila Olímpia ‑ São Paulo, São Paulo
Federative Republic of Brazil
+55 11 3841‑8507
(Address of principal executive offices)

Gustavo Estrella
+55 19 3756 8704 – gustavoestrella@cpfl.com.br
Rodovia Engenheiro Miguel Noel Nascentes Burnier, 1,755, km 2,5 – Parque São Quirino – Campinas, São Paulo ‑ 13088 140
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 2 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, 2014, there were962,274,260 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 

 

Table of Contents

                                                                                Page

Contents

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
ITEM 4.	Information on the Company	16
ITEM 4A.	Unresolved Staff Comments	62
ITEM 5.	Operating and Financial Review and Prospects	62
ITEM 6.	Directors, Senior Management and Employees	95
ITEM 7.	Major Shareholders and Related Party Transactions	103
ITEM 8.	Financial Information	106
ITEM 9.	The Offer and Listing	108
ITEM 10.	Additional Information	110
ITEM 11.	Quantitative and Qualitative Disclosures About Market Risk	128
ITEM 12.	Description of Securities Other than Equity Securities	129
ITEM 13.	Defaults, Dividend Arrearages and Delinquencies	130
ITEM 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	130
ITEM 15.	Controls and Procedures	130
ITEM 16A.	Audit Committee Financial Expert	131
ITEM 16B.	Code of Ethics	132
ITEM 16C.	Principal Accountant Fees and Services	132
ITEM 16D.	Exemptions from the Listing Standards for Audit Committees	133
ITEM 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	133
ITEM 16F.	Change in Registrant’s Certifying Accountant	133
ITEM 16G.	Corporate Governance	133
ITEM 16H.	Mine Safety Disclosure	135

i

 

ITEM 17.	Financial Statements	135
ITEM 18.	Financial Statements	135
ITEM 19.	Exhibits	135
GLOSSARY OF TERMS		136
SIGNATURES		139

ii

 

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 136.

1

 

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”). 

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 years ended December 31, 2014, 2013, 2012, 2011, and 2010.  Our financial data as of December 31, 2014 and 2013 and for each of the three years in the period ended December 31, 2014 was derived from our consolidated financial statements, which appear elsewhere in this annual report and were 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 included in this annual report.  Our financial data as of December 31, 2012, 2011 and 2010 and for each of the two years ended December 31, 2011 was derived from our audited financial statements that are not included in this annual report. 

We restated our balance sheets, as of January 1, 2012 and December 31, 2012, and the Statements of Income, Comprehensive Income, Change in Shareholders’ Equity and Cash Flows for the years ended December 31, 2012 and 2011 as a result of the adoption, as of January 1, 2013, of two new standards issued by the IASB: IAS 19 (Employee Benefits – as revised in 2011) and IFRS 11 (Joint Arrangements).  However, data for 2010 has not been restated in application of new accounting standards mentioned above and therefore cannot be compared to the the financial information presented for the years ended December 31, 2014, 2013, 2012 and 2011.

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

2

 

STATEMENT OF OPERATIONS DATA

	For the year ended December 31,
	2014(5)	2014(6)	2014	2013	2012(7)	2011(7)	2010(8)
	US$	US$	R$	R$	R$	R$	R$
		(in millions, except per share and per ADS data)
Net operating revenue	5,395	6,515	17,306	14,634	14,891	12,674	12,024
Cost of electric energy services:
Cost of electric energy	3,318	4,007	10,643	8,197	8,253	6,668	6,222
Operating cost	521	630	1,672	1,468	1,378	1,070	1,068
Services rendered to third parties	295	356	946	1,010	1,356	1,138	1,051
Gross operating income	1,261	1,523	4,044	3,960	3,904	3,798	3,683
Operating expenses:
Sales expenses	126	152	403	377	468	364	301
General and administrative expenses	241	291	774	929	724	595	443
Other operating expense	102	123	328	285	377	213	200
Income from electric energy service	792	956	2,540	2,370	2,335	2,625	2,739
Interest in associates and joint ventures	19	22	60	121	121	82	-
Financial income (expense):
Income	278	335	890	699	707	753	483
Expense	(617)	(745)	(1,980)	(1,671)	(1,285)	(1,156)	(837)
Net financial income (expenses)	(340)	(410)	(1,089)	(971)	(578)	(403)	(354)
Income before taxes	471	569	1,511	1,519	1,878	2,304	2,385
Social contribution	(53)	(64)	(169)	(157)	(178)	(204)	(221)
Income tax	(142)	(171)	(455)	(413)	(493)	(555)	(604)
Total taxes	(194)	(235)	(624)	(570)	(671)	(759)	(825)
Net income	276	334	886	949	1,207	1,545	1,560
Net income attributable to controlling shareholders	296	357	949	937	1,176	1,493	1,538
Net income (loss) attributable to non‑controlling shareholders	(20)	24	(63)	12	31	52	22
Earnings per share attributable to controlling shareholders(1):
Basic	0.31	0.37	0.99	0.97	1.22	1.55	1.66
Diluted	0.30	0.36	0.97	0.95	1.20	1.55	1.66
Net income per ADS(1):
Basic	0.61	0.74	1.97	1.94	2.44	3.10	3.32
Diluted	0.60	0.73	1.94	1.90	2.40	3.10	3.32
Dividends(2)	305	368	977	931	1,096	1,506	1,260
Weighted average of number of common shares (in millions)	962	962	962	962	962	962	962
Dividends per share(1)(2)	0.32	0.38	1.02	0.97	1.14	1.57	1.31
Dividends per ADS(2)	0.63	0.76	2.03	1.94	2.28	3.13	2.62

3

 

BALANCE SHEET DATA

	For the year ended December 31,
	2014(5)	2014(6)	2014	2013	2012(7)	2011(7)	2010(8)
	US$	US$	R$	R$	R$	R$	R$
		(in millions)
Current assets:
Cash and cash equivalents	1,358	1,640	4,357	4,206	2,435	2,663	1,563
Consumers, concessionaires and licensees	702	847	2,251	2,008	2,205	1,861	1,816
Other current assets	812	981	2,606	1,050	905	799	519
Total current assets	2,872	3,469	9,215	7,264	5,545	5,323	3,898
Noncurrent assets:
Accounts receivable	38	46	123	154	162	182	196
Financial asset of concession	884	1,067	2,835	2,787	2,343	1,377	935
Investments in joint-ventures	343	414	1,099	1,033	1,022	1,006	-
Property, plant and equipment	2,767	3,342	8,878	7,717	7,104	5,673	5,786
Intangible Assets	2,854	3,447	9,156	8,748	9,180	8,535	6,585
Other noncurrent assets	1,182	1,428	3,793	3,339	3,568	3,073	2,657
Total noncurrent assets	8,069	9,745	25,884	23,778	23,379	19,846	16,159
Total assets	10,941	13,214	35,099	31,043	28,294	25,169	20,057
Current liabilities:
Short‑term debt(3)	1,099	1,328	3,526	1,837	1,962	1,496	2,251
Other current liabilities	1,213	1,465	3,891	3,068	3,007	2,819	2,177
Total current liabilities	2,312	2,792	7,417	4,906	4,969	4,315	4,428
Noncurrent liabilities:
Long‑term debt(3)	4,870	5,882	15,624	15,184	13,511	10,317	7,167
Other long‑term liabilities	833	1,006	2,673	2,155	2,553	1,879	1,712
Noncurrent liabilities	5,704	6,888	18,297	17,339	16,064	12,196	8,879
Non-controlling interest	761	919	2,441	1,775	1,510	1,485	256
Net equity attributable to controlling shareholders	2,164	2,614	6,944	7,024	6,381	7,173	6,494
Total liabilities and shareholders’ equity	10,941	13,214	35,099	31,043	28,294	25,169	20,057

4

 

OPERATING DATA

	For the year ended December 31,
	2014	2013	2012(10)	2011(10)	2010(8)
Energy sold (in GWh):
Residential	16,501	15,426	14,567	13,626	12,983
Industrial	14,144	14,691	14,536	14,718	15,413
Commercial	9,437	8,837	8,714	8,140	7,695
Rural	2,326	2,081	2,093	1,991	2,100
Public administration	1,295	1,234	1,220	1,154	1,112
Public lighting	1,622	1,586	1,525	1,495	1,444
Public services	1,861	1,820	1,864	1,823	1,742
Own consumption	34	34	33	33	33
Total energy sold to Final Consumers	47,221	45,709	44,552	42,979	42,522
Electricity sales to wholesalers (in GWh)	14,987	14,975	14,429	12,271	12,737
Total consumers (in thousands)(4)	7,586	7,386	7,176	6,952	6,748
Installed Capacity (in MW)	3,162	2,988	2,961	2,644	2,309
Assured Energy (in GWh)(9)	13,566	12,758	12,742	11,678	7,786
Energy generated (in GWh)	13,658	11,427	10,570	9,638	9,142

(1) Net income per share and Dividends per share are based on the number of shares resulting from the reverse and forward stock split of our common shares, which occurred in July 2011, as if they had occurred on January 1, 2010.

(2) “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.

(3) Short‑term debt and long‑term debt include loans and financing, debentures, accrued interest on loans, financing and debentures and derivatives.

(4) Represents active consumers (meaning consumers who are connected to the Distribution Network), rather than consumers invoiced at period‑end.

(5) Translated at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of March 31, 2015 of R$3.208 to US$1.00.

(6) Translated at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2014 of R$2.656 to US$1.00.

(7) Data for 2012 and 2011 have been restated in application of IAS 19 – Employee Benefits (as revised in 2011) and IFRS 11 – Joint Arrangements, as described in our audited annual consolidated financial statements for the year ended December 31, 2013.  With respect to IAS 19 – Employee Benefits, the principal adjustments are as follows: (i) changes in the accounting record method of actuarial gain and losses, such that accumulated differences between actuarial estimates and actual obligations are recognized in Other Comprehensive Income when they occur, and (ii) instead of recording interest cost and expected returns on plan assets as was previously done, we now record an amount for “net interest”.  With respect to IFRS 11 – Joint Arrangements, the results of the joint-ventures Campos Novos Energia S.A. (“ENERCAN”), BAESA - Energética Barra Grande S.A. (“BAESA”), Chapecoense Geração S.A. (“Chapecoense”) and Centrais Elétricas da Paraíba S.A. (“EPASA”) are recognized using the equity method of accounting in 2014, 2013, 2012 and 2011 rather than through proportional consolidation as was previously the case.

(8) Data for 2010 has not been restated in application of IAS 19 – Employee Benefits (as revised in 2011)  and IFRS 11 – Joint Arrangements. 

(9) Refers to Assured Energy in GW available at the end‑period, multiplied by the number of hours per year.  For further information about commencement of operations of each power plant, see “Item 4.  Information on the Company”.

(10) 2012 and 2011 volume information was restated for comparison purposes between operational and financial information, due to the adoption of IFRS 11.

Convenience Translations into U.S. Dollars

Solely for the investor’s convenience, we have translated certain amounts included in this annual report fromreais into U.S. dollars at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2014 of R$2.656 to US$1.00.  In light of the depreciation of the Brazilianreal compared to the U.S. dollar in the first quarter of 2015, we have also presented these amounts translated into U.S. dollars at the commercial selling rate at closing as of March 31, 2015 of R$3.208 to US$1.00.  The translated amounts have been rounded.  These translations should not be considered as a representation that any such amounts have been, could have been or could be converted into U.S. dollars at that or at any other exchange rate, as of those dates or any other date.  In addition, the translations should not be construed as a representation that the amounts translated into U.S. dollars are in accordance with generally accepted accounting principles.  See “—Exchange Rates” below for more information regarding thereal/U.S. dollar exchange rate.

5

 

Exchange Rates

The Brazilian 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 Brazilian Central Bank or the Brazilian government will continue to let therealfloat 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 inreaisper 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, 2010	1.666	1.759	1.655	1.881
December 31, 2011	1.876	1.671	1.535	1.902
December 31, 2012	2.044	1.958	1.702	2.112
December 31, 2013	2.343	2.174	1.953	2.446
December 31, 2014	2.656	2.360	2.197	2.740

(1) Average for period represents 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:
October 2014	2.444	2.448	2.391	2.534
November 2014	2.560	2.548	2.484	2.614
December 2014	2.656	2.639	2.561	2.740
January 2015	2.662	2.634	2.575	2.711
February 2015	2.878	2.816	2.689	2.881
March 2015	3.208	3.139	2.866	3.268
April 2015 (through April 13)	3.101	3.104	3.047	3.156

(1)  Average for period represents the average of the selling exchange rates at the close of trading on each business day during such period.

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), or ANEEL.  ANEEL regulates and oversees various aspects of our business and establishes our tariffs.  If we are obligated by ANEEL to make additional and unexpected capital investments and are not allowed to adjust our tariffs accordingly, if ANEEL does not authorize the recovery of all costs or if ANEEL modifies the regulations related to tariff adjustments, we may be adversely affected.

In addition, both the implementation of our strategy for growth and our ordinary 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.

6

 

If regulatory changes require us to conduct our business in a manner substantially different from our current operations, our operations and financial results may be adversely affected.

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

The Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 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 Federal Supreme Court (Supremo Tribunal Federal).  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 and authorizations.

We carry out our generation, transmission and distribution activities pursuant to concession agreements entered into with the Brazilian government.  Our concessions range in duration from 16 to 35 years.  The Brazilian constitution requires that all concessions relating to public services be awarded through public tender.  Under laws and regulations specific to the electric energy sector, the Brazilian government may renew existing concessions for an additional period of up to 20 or 30 years, depending on the nature of the concession, without public tender, provided that the concessionaire has met minimum performance standards and that the proposal is otherwise acceptable to the Brazilian government.  The Brazilian government has considerable discretion under Law No. 8,987/95, or the Concession Law, and under concession contracts with respect to renewal of concessions.

The first of our distribution concessions due to expire are those held by our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista, which were originally granted in 1999 for a 16‑year term that is due to expire in July 2015. 

Law No. 12,783/13 of 2013 provided that existing distribution concessions such as those held by CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista could be renewed, subject to certain conditions, for a further term of up to 30 years.  Accordingly, in 2014 we applied for renewal of those concessions in time for the renewal date of July 2015.  On March 31, 2015, however, before we had received a response from the authorities to these requests for renewal, it was reported that a federal court in Brasília had issued a decision in a case commenced by the Brazilian public prosecutor against ANEEL and the Brazilian federal government stating that distribution concessions, particularly those that have already been renewed in the past, may not be automatically renewed without certain requirements being met.   Since we are not a party to this litigation, and we understand it may be subject to appeal, we are currently unable to predict its effect on our requests for renewal of these concessions.  See “Item 4.  Information on the Company—Our Concessions and Authorizations—Concessions”.   We cannot give any assurance that the concessions expiring in July 2015 will be renewed, or whether the financial conditions of any renewed or new concessions will be acceptable.  If these or any of our concessions are not renewed, or if they are renewed subject to conditions that are unfavorable to us, our revenues could be adversely affected.

The tariffs that we charge for sales of electricity to Captive Consumers and the tariffs for using the distribution system that we charge to Free and Special 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 government, and in accordance with ANEEL’s regulations and decisions.

Our concession agreements and Brazilian law establish a mechanism that permits three types of tariff adjustments: (i) annual adjustment (reajuste tarifário annual), or RTA, (ii) periodic revision (revisão tarifária periódica), or RTP, and (iii) extraordinary revision (revisão tarifária extraordinária), or RTE.  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 electricitywe purchase 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 negatively affect our results of operations or financial position.

7

 

We cannot be sure if ANEEL will establish tariffs at rates that are favorable to us, due to changes in the methods used by ANEEL in calculating the periodic revision adjustments.  The methodology set by ANEEL for the 2011-2014 periodic revision cycle under Resolution No. 457/2011 negatively impacted our financial condition and results of operations.  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 to be applied in the 2015-2018 periodic revision cycle is currently subject to public consultation, which is expected to be concluded during the first half of 2015.  See “Item 5.  Operating and Financial Review and Prospects—Background—Periodic Revisions—RTP”.

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 concession in the financial year prior to the date of the 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 expiration or early termination of our concessions may not be sufficient for us to realize the full value of certain assets.  In addition, 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 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 purchase electricity in the spot market 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 forecast electricity needs for its distribution concession areas, and is authorized to pass up to 105% of this electricity on to consumers.  Over‑ or under‑forecasting demand can have adverse consequences.  If our forecast demand is incorrect and we purchase less or more electricity than we need, we may be prevented fromfully passing through the costs of our electricity purchases and we may also be forced to enter into the spot market to purchase or sell electricity at prices substantially higher or lower 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 in the spot market.  Our forecast 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”. 

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We may not be able to buy electricity in the amount we need to meet our sales agreements in the free market, which may lead us to be exposed to the spot market at prices substantially higher than under our long term agreements.

On August 2, 2012, the MME enacted Act. No. 455, under whichex post energy volume adjustment has been prohibited since June 1, 2014, and the parties will have to registerex ante with the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica), or CCEE, their expected consumption volume, except when the parties have specifically indicated that the relevant agreement is linked to the effective consumption volume.  However, the Brazilian Association of Electricity Traders (ABRACEEL) obtained an injunction against Act 455/2012, preventing the implementation of theex ante contract registration rule to energy traders. The application of this Act in the CCEE has been suspended for all agents (Generators, Traders and Free Consumers), since it may not apply only to a specific group of agents. This Act applies only to the Free Market and does not affect distributors.  Under this system, if the injunction is lifted, and if our projected energy volume is incorrect and we purchase less or more electricity than we need, we would no longer be able to adjust for our exposure to the energy volume purchased.  See “Item 4. Information on the Company—The New Industry Model Law—Recent Developments in the Free Market”.

We generate a significant portion of our operating revenues from consumers 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.  These 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, following which they may only return upon five years’ prior notice.  At December 31, 2014, we supplied energy to 46 Free Consumers, which accounted for approximately1.5% of our net operating revenues of our Distribution segment, and approximately 2.5% of the total volume of electricity sold by our Distribution segment during 2014.  In addition, other consumers meeting certain criteria may become Free Consumers, for example Special Customers who may move to energy from renewable energy sources, such as Small Hydroelectric Power Plants, or SHPPs, wind power or biomass.  At December 31, 2014 we had a total of 1,649 consumers who could choose their supplier, or Potentially Free Consumers.  Potentially Free Consumers accounted for approximately 9.0% of the net operating revenues of our Distribution segment, and approximately 12.7% of the total volume of electricity sold by our Distribution segment during 2014.  See “Item 4. Information on the Company—The New Industry Model Law—The Free Market”.

Additionally, it is possible that our large industrial clients could be authorized by ANEEL to generate electric energy for their own 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.

Our operating results depend on prevailing hydrological conditions.  Poor hydrological conditions may affect our results of operations.

We are dependent on the prevailing hydrological conditions in Brazil, the country in which we operate.  In 2014, according to data from the National Electrical System Operator (Operador Nacional do Sistema Elétrico), or ONS, approximately 73% of Brazil’s electricity supply came from Hydroelectric Power Plants. 

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Brazil is subject to unpredictable hydrological conditions, with non‑cyclical deviations from average rainfall.  In order to compensate for poor hydrological conditions and to maintain security levels in reservoirs and the electricity supply level, the ONS may dispatch Thermoelectric Power Plants, including those operated by us.  The replacement of hydroelectric generation with thermoelectric generation may lead to adverse results in our Generation segment since Hydroelectric Power Plants, including those operated by us, may receive an amount of energy lower than their Assured Energy in the Energy Reallocation Mechanism (Mecanismo de Realocação de Energia), or MRE.  This deficit of energy, called the Generation Scaling Factor, or GSF, will represent an expense valued at the electricity spot price, exposing the operator of the Hydroelectric Power Plants to spot price risk.

In the Distribution segment, thermoelectric generation can lead to additional costs with energy purchase, when ONS dispatches Thermoelectric Power Plants by merit order, and extraordinary charges, such as a component of the System Service Charge (Encargo de Serviço do Sistema), the ESS, related to energy security, the ESS-SE, when these power plants are dispatched out of the merit order.  These additional costs are ultimately passed through by the distributor to consumers through tariff increases in future annual adjustments or periodic reviews, as permitted by regulation.  However, there may be a cash flow mismatch in the intervening period, since these costs must be covered immediately, while the tariffs are only readjusted later.  For more information, see “Item 4.  Information on the Company—The Brazilian Power Industry—Regulatory Charges—ESS”.

In January 2015, the electricity sector began to implement a mechanism of monthly “tariff flags” under which consumer invoices may be subject to tariff additions on a monthly basis when energy supply costs reach certain levels, enabling consumers to adapt their usage to current energy costs.    Revenues collected under the tariff flag system are repaid to distribution companies on the basis of their relative energy cost for the period.  Due to the poor hydrological conditions that have been observed since 2013, red tariff flags have been applied since introduction of this system in January 2015.  Although this mechanism mitigates the cash flow mismatch in part, it may be insufficient to cover the thermoelectric energy supply costs, and distributors still bear the risk of cash flow mismatches in the short term.  See “Item 4.  Information on the Company—The Brazilian Power Industry—Basis of Calculation of Distribution Tariffs”.

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.

Periods of severe or sustained below‑average rainfall resulting in an electricity shortage may adversely affect our financial condition and results of operations.  For example, during the low rainfall period of 2000 and 2001, 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, with reductions in consumption ranging from 15% to 25%.  If Brazil experiences another electricity shortage (a condition which might happen and we are not able to control or anticipate), the Brazilian government may implement similar or other policies in the future to address the shortage.  For example, electricity conservation programs, including mandated reductions in electricity consumption, could be implemented if poor hydrological conditions cannot be offset in practice by other energy sources, such as Thermoelectric Power Plants, thereby resulting in a low supply of electricity to the Brazilian market.

We are uncertain as to the review of our Hydroelectric Power Plants’ Assured Energy.

Decree No. 2,655 of July 2, 1998 established that the Assured Energy of generation power plants would be revised every five years.  As part of these revisions, the Brazilian Ministry of Mines and Energy (MME) can revise a company’s Assured Energy, limited to a maximum change of 5% per revision or 10% over the entire period of the concession agreement.  In addition to these periodic revisions, it is still unclear when the effects of the first revision are expected to take place for all Hydroelectric Power Plants (with the exception of SHPPs), sincePortaria No. 681 of December 30, 2014 provided that all Assured Energy values will remain unchanged until December 31, 2015 and did not set a date for the change.  We cannot be certain whether the MME will make any revisions to our Assured Energy, either under the periodic revision cycle or under this extraordinary revision, and if so whether it will increase or decrease our Assured Energy.  If our Assured Energy is decreased, our ability to supply electricity under our power purchase agreements, or PPAs, would be adversely affected, which could lead to a decrease in our revenues and increase our costs if our generation subsidiaries are required to purchase power elsewhere.  See “Item 4—Principal Regulatory Authorities—Ministry of Mines and Energy - MME”.

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Construction, expansion and operation of our electricity generation, transmission 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, transmission and distribution of electricity involve 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 or distribute electricity in amounts consistent with our projections, which may have an adverse effect on our financial condition and results of operations.

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 activities are subject to comprehensive federal, state and municipal legislation as well as regulation and 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$2,121 million in our generation activities (R$2,058 million in renewable sources and R$62 million in conventional sources), R$6,413 million in our distribution activities and R$395 million in our commercialization and services activities during the period from 2015 through 2019.  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.

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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 our renewable energy generation businesses.

Through our subsidiary CPFL Renováveis we have made substantial capital investments in generation businesses other than hydro power, principally wind and biomass.  These renewable generation businesses are dependent on certain factors that are not within our control and may significantly affect these businesses.

In the biomass business, we may suffer from market shortages of sugar cane, a necessary input for biomass generation.  In addition, we depend to a certain extent on the performance of our partners in the operation of biomass plants.  The operation of wind farms involves significant uncertainties and risks, including financial risk associated with the difference between the energy we generate and the energy contracted through the public energy auctions.  These financial risks are principally: (i) lower wind intensity and duration than that contemplated in the study phase of the project; (ii) any delay in commencement of a wind farm’s operations; and (iii) unavailability of wind turbines at levels above the performance benchmarks.

If these generation plants are not able to generate the energy we have contracted to supply, we may be obliged to buy the shortfall in the spot market.  Spot market prices are volatile and may be higher than the price at which our renewable energy subsidiaries have contracted to sell energy, which would increase our costs and lead to losses in this segment.  See “Item 4.  Information on the Company—The Brazilian Power Industry—The New Industry Model Law”.

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

As of December 31, 2014, ESC Energia S.A., or ESC, PREVI (through BB Carteira Livre I FIA) and Energia São Paulo Fundo de Investimento em Ações, or Energia São Paulo FIA/Bonaire Participações S.A., owned 24.33%, 29.99% and 14.87%, respectively, of our outstanding common shares. Bonaire Participações S.A., or Bonaire, is a holding company controlled by Energia São Paulo Fundo de Investimento em Ações. 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 non-controlling 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, 2014, approximately 82.0% of our total indebtedness was denominated inreaisand indexed to Brazilian money‑market rates or inflation rates, or bore interest at floating rates.  The remaining 18.0% of our total indebtedness was denominated in U.S. dollars and substantially subject to currency swaps that converted these obligations intoreais.  In addition, the costs of electricity purchased from the Itaipu Power Plant, or Itaipu, are indexed to the U.S. dollar exchange variation.  Our tariffs are adjusted annually in order to contemplate the losses or gains from such electricity acquisition.  Accordingly, if these indexation rates rise or the U.S. dollar/realexchange rates appreciate, our financing expenses will increase.

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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, 2014, we had a debt of R$19,150 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, this 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.  Any such failure 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:

·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.

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Political conditions may have an adverse impact on the Brazilian economy and on our business.

Current political conditions in Brazil may affect the confidence of investors and the public in general as well as the development of the economy. Uncertainty with regard to matters such as the presidential administration’s future policies and appointments to influential governmental positions and ongoing investigations into allegations of corruption in state-controlled enterprises may also affect the confidence of investors and the general public. It may also have an adverse impact on the Brazilian economy, our business, financial condition, results of operations and the market price of our common shares and ADSs.

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 experienced frequent and substantial variations in relation to the U.S. dollar and other foreign currencies over the last decade.  On December 31, 2012, 2013 and 2014, the exchange rate of thereal against the U.S. dollar was R$2.044, R$2.343 and R$2.656 per US$1.00, respectively. On April 13, 2015, the exchange rate was R$3.101 per US$1.00.  Therealmay further depreciate against the U.S. dollar in the future.

Depreciation of therealincreases the cost of servicing our foreign currency denominated debt and the cost of purchasing electricity from the Itaipu power plant, a Hydroelectric Power Plant that is one of our major suppliers and that adjusts electricity prices based in part on its U.S. dollar costs.  Depreciation of therealagainst 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, curtail access to foreign financial markets and may prompt government intervention, including recessionary governmental policies.  Depreciation of therealagainst the U.S. dollar can also lead to decreased consumer spending, deflationary pressures and reduced growth in the economy as a whole.  On the other hand, appreciation of therealrelative to the U.S. dollar and other foreign currencies could lead to a deterioration of the Brazilian foreign exchange current account, as well as dampen export‑driven growth.  Depending on the circumstances, either depreciation or appreciation of therealcould 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.

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

Brazil has in the past experienced extremely high rates of inflation and has therefore followed monetary policies that have resulted in one of the highest real interest rates in the world.  Between 2006 and 2014, the base interest rate in Brazil, or SELIC, varied between 7.25% p.a. and 17.25% p.a., reaching its lowest level (7.25%) at the end of 2012. On April 13, 2015, the SELIC rate was 12.65% p.a..  Inflation and the Brazilian government’s measures to fight it, principally through the Brazilian Central Bank, have had and may in the future 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 Brazilian Central Bank policies and interest rate decreases may trigger increases in inflation, and, consequently, volatility in growth 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 our 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.  The global financial crisis that commenced in 2008 led to significant consequences, including stock and credit market volatility, unavailability of credit, higher interest rates, a general economic slowdown, volatile exchange rates and inflationary pressure.  Global recovery from this crisis has been slower than expected in recent years, with the largest emergingeconomies of China, Brazil and India posting weaker than expected results and the European Union is continuing to experience weak GDP growth, although the United States posted GDP growth of approximately 3.0% in 2014.  Although economic conditions in other countries may differ significantly from economic conditions in Brazil, investor reactions to developments in those 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.

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Risks Relating to the ADSs and Our Common Shares

Holders of our ADSs do not have the same voting rights as our shareholders.

Holders of our ADSs do not have the same voting rights as holders of our shares.  Holders of our ADSs are entitled to the contractual rights set forth for their benefit under the deposit agreements.  ADS holders exercise voting rights by providing instructions to the depositary, as opposed to voting at shareholders’ meetings or by proxy.  In practice, the ability of a holder of ADSs to instruct the depositary as to voting will depend on the timing and procedures for providing instructions to the depositary, either directly or through the holder’s custodian and clearing system.

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 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, Citibank N.A., 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 morespeculative 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 50.7% of the aggregate market capitalization of theBM&FBOVESPA S.A. ‑ Bolsa de Valores, Mercadorias & Futuros,or BM&FBOVESPA, as of December 31, 2014.  The top ten stocks in terms of trading volume accounted for 46.3%, 41.3% and 43.0% of all shares traded on the BM&FBOVESPA in 2014, 2013, and 2012, respectively.

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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 142, 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, transmits and commercializes electricity in Brazil as well as provides energy-related services.  We were incorporated in 1998 as a joint venture among VBC Energia S.A., or 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 43,160 GWh of electricity we distributed to approximately 7.6 million consumers in 2014.  In electricity generation, our Installed Capacity at December 31, 2014 (after accounting for the acquisition of Dobrevê Energia S.A., or DESA, in October 2014) was 3,162 MW.  Through our interest in CPFL Renováveis, we are also involved in the building of 1 SHPP and 12 wind farms, as a result of which we expect to increase our Installed Capacity (also after accounting for the acquisition of DESA) to 3,299 MW over the next five years as they are completed.

We also engage in power commercialization, buying and selling electricity to power producers, Free Consumers and power trading companies.  We also provide agency services to Free Consumers before the CCEE and other agents as well as electricity‑related services to our affiliates and unaffiliated parties.  In 2014, the total amount of electricity sold by our commercialization subsidiaries was 1,773 GWh and 9,840 GWh to affiliated and unaffiliated parties, respectively.

The following significant developments have occurred in our business since the beginning of 2013:

·In July 2013, CPFL Renováveis carried out its IPO and its common shares began trading publicly on the BM&FBOVESPA.  The offering consisted of a primary offering of 29.2 million common shares (including overallotment option) and a concurrent secondary offering of 44.0 million common shares, at a price of R$12.51 per share.  As a result of this transaction, our interest in CPFL Renováveis was reduced from 63% to 58.84%.  Although our interest was reduced, the transaction resulted in an increase of R$59.3 million in our shareholder’s equity, capital reserve account, due to the increase of the nominal value of the shares of CPFL Renováveis.  All references in this Annual Report to our total Installed Capacity and other operating information as at and for the year ended December 31, 2013 reflect the impact of this change in shareholding and consolidation.

·In August 2013, CPFL Coopcana Biomass Thermoelectric Plant, or UTE Coopcana, commenced operations.  UTE Coopcana is located in São Carlos do Ivaí, in the state of Paraná, has Installed Capacity of 50 MW, and has sold all its energy in the Free Market under a supply agreement with a 21‑year term averaging 18 MW of contracted energy.

·In September 2013, operations started at the Campo dos Ventos II Wind Farm with 30 MW of Installed Capacity.  The Campo dos Ventos II Wind Farm is located in João Câmara, in the state of Rio Grande do Norte and was acquired in the 2010 Reserve Energy Auction (LER).  ANEEL has authorized thestart of commercial operations of Campo dos Ventos II Wind Farm by means of Dispatch No. 4,706 of December 5, 2014, when the energy generated by these farms became fully available to the system. Campo dos Ventos II became entitled to bill energy, as provided for in the 2010 Reserve Energy Auction (LER) rules, even though the conclusion of the construction of the ICG (shared generation facilities) – which are not a responsibility of the company – were still pending. Therefore, Campo dos Ventos II Wind Farm has been recording revenues since September 2013.

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·In November 2013, Alvorada Biomass Thermoelectric Plant, or UTE Alvorada, commenced operations.  UTE Alvorada is located in Araporã, in the state of Minas Gerais, has Installed Capacity of 50 MW, and has sold all its energy in the Free Market under a supply agreement with a 20‑year term averaging 18 MW of contracted energy.

·In December 2013, at the Second A‑5/2013 Energy Auction, CPFL Renováveis traded an average of 26.1 MW of contracted energy to be generated by the Pedra Cheirosa Complex, consisting of two wind farms in the state of Ceará 51.3 MW of Installed Capacity.  An “A‑5” auction is an energy auction held five years before the initial delivery date.  The contracts arising from the trade will be executed with the distribution companies that participated in the auction as energy purchasers.  The contracts will have a duration of 20 years, with energy supply commencing January 1, 2018.  The traded energy was sold at an average price of R$125.04 per MWh, with annual adjustments to be made in accordance with IPCA.

·The acquisition of Rosa dos Ventos Geração e Comercialização de Energia S.A., or Rosa dos Ventos, by CPFL Renováveis was completed in February 2014. The acquisition price, after all adjustments, was R$103.4 million, consisting of (i) R$70.3 million in cash and (ii) the assumption of net debt in the amount of R$33.1 million.  Rosa dos Ventos holds an ANEEL authorization to exploit two wind farms: (i) Canoa Quebrada, which has Installed Capacity of 10.5 MW; and (ii) Lagoa do Mato, which has Installed Capacity of 3.2 MW.  These wind farms are located on the coast of the state of Ceará and are in full commercial operation, and all the energy generated has been contracted to Eletrobrás through the Electric Energy Alternative Sources Incentive Program (Programa de Incentivo às Fontes Alternativas de Energia Elétrica), or Proinfa Program, which was established by the Brazilian government.

·In February 2014, CPFL Renováveis entered into an agreement with Arrow – Fundo de Investimento em Participações, or Arrow, an investment fund, to acquire Arrow’s indirect subsidiary DESA, by way of the merger of DESA’s holding company, WF2 Holding S.A., or WF2, with and into CPFL Renováveis, in exchange for the issuance of 61,752,782 new common shares of CPFL Renováveis to Arrow on October 1, 2014.  As a result of this transaction, our interest in CPFL Renováveis was reduced from 58.84% to 51.61%.  DESA has been operating with installed power of 278 MW and has renewable generation construction projects with Installed Capacity of 53 MW, whose operations are expected to start in 2016.  All references in this Annual Report to our total Installed Capacity and other operating information as at and for the year ended December 31, 2014 reflect the impact of this change in shareholding and consolidation as from October 1, 2014.  See note 15.6.2 to our audited annual consolidated financial statements.

·In March 2014, CPFL Renováveis completed the last wind farm of the Atlântica Complex located in the municipality of Palmares do Sul, in the state of Rio Grande do Sul, has Installed Capacity of 120 MW, and has sold all its energy at the Alternative Sources Auction (“LFA/2010”) with a 20-year supply term and 52.7 average MW of contracted energy. The Complex windmills have gradually started operating since November 2013.

·In June 2014, Macacos  Complex (the wind farms of Pedra Preta, Costa Branca, Juremas and Macacos) was deemed fit for operation by ANEEL, beginning as of May 1, 2014.Beginning on this date, the wind farms became eligible to bill for energy as required by the rules of the Alternative Sources Auction (LFA) 2010. Macacos Complex has Installed Capacity of 78.2 MW, physical guarantee of 37.5 average-MW and is located in the city of João Câmara, in Rio Grande do Norte.

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·In October 2014, CPFL Eficiência Energética S.A. (“CPFL ESCO”) commenced its operations. Located in Campinas, state of São Paulo, this company provides consulting and management services related to energetic efficiency improvements, rental of generation assets and research and development activities for energy-related programs. Self-production activities, which were conducted by CPFL Serviços until October 2014, are also part of CPFL ESCO services portfolio.

·The incorporation of CPFL Transmissora Morro Agudo S.A., subsidiary company of CPFL Geração, was approved in January 2015, with the objective of operating and exploiting electric energy transmission concessions, including the construction, implementation, operation and maintenance of transmission facilities, of the basic network of the Interconnected Power System.

The following chart provides an overview of our corporate structure at March 31, 2015:

Notes:

(1)Controlling shareholders;

(2)Includes the 0.1% stake of Camargo Corrêa S.A.;

(3)Includes the 0,5% stake of Caixa de Previdência dos Funcionários do Banco do Brasil;

(4)Includes the 0.2% stake of Petros e Sistel pension funds;

(5)51.54% stake of the availability of power and energy of Serra da Mesa HPP, regarding the Power Purchase Agreement between CPFL Geração and Furnas.

Our core businesses are:

·Distribution.  In 2014, our eight fully‑consolidated distribution subsidiaries delivered 43,160 GWh of electricity to approximately 7.6 million consumers primarily in the states of São Paulo and Rio Grande do Sul.

·Conventional Generation.  At December 31, 2014 our conventional generation subsidiaries had Installed Capacity of 2,248 MW.  During 2014, we generated a total of 11,179 GWh of electricity, and we had 10,106 GWh of Assured Energy at December 31, 2014, the amount of energy representing our long‑term average electricity production, as established by ANEEL, which is the primary driver of our revenues from generation activities. We hold equity interests in eight Hydroelectric Power 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 the Serra da Mesa Hydroelectric Facility is held by another party, Furnas, we are entitled to 51.54% of its Assured Energy.  We also own three Thermoelectric Power Plants, Termonordeste, Termoparaíba and Carioba, although the Carioba Thermoelectric Power Plant has been deactivated.  In addition, 10 of our 49 Small Hydroelectric Power Plants remain under the management of two of our conventional generation subsidiaries, CPFL Geração and CPFL Centrais Geradoras, and report their results within the Conventional Generation segment.

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·Renewable Generation.  Our indirect subsidiary, CPFL Renováveis, in which we own a 51.61% interest through CPFL Geração, concentrates our activities in energy generation through renewable sources.  CPFL Renováveis operates all of our wind farms and Thermoelectric Biomass Power Plants as well as 39 of our 49 Small Hydroelectric Power Plants.  These 39 Small Hydroelectric Power Plants, of which (i) 38 Small Hydroelectric Power Plants located in the states of São Paulo, Santa Catarina, Rio Grande do Sul, Minas Gerais, Mato Grosso and Paraná, are operational and have aggregate Installed Capacity of 399 MW, and (ii) 1 Small Hydroelectric Power Plant under construction to scheduled to commence operations in 2016 and are expected to have Installed Capacity of approximately 24 MW.  CPFL Renováveis also has 45 wind farms, of which (i) 33 farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, are operational and have aggregate Installed Capacity of 999 MW, and (ii) the remaining 12 farms are under construction, scheduled to commence operations between 2016 and 2018, and are expected to have Installed Capacity of approximately 312 MW.  CPFL Renováveis has eight operational Thermoelectric Biomass Power Plants, with aggregate Installed Capacity of 370 MW, located in the states of Minas Gerais, Paraná, São Paulo and Rio Grande do Norte.  CPFL Renováveis also operates the Tanquinho Solar Power Plant, which is located in the state of São Paulo and has Installed Capacity of 1.1 MWp.  At December 31, 2014, our total consolidated Installed Capacity through our Renewable Generation segment (calculated on the basis of our 51.61% interest in CPFL Renováveis) was 914 MW and as a result of the acquisition of DESA in October 2014, we expect that our Renewable Generation segment will reach an Installed Capacity of 2,108 MW in 2018.  These capacity amounts do not include eventual decreases in our installed capacity ballast (limit of energy produced in our own power plants that we are allowed to sell).  Those decreases are calculated by the Ministry of Mines and Energy, for power plants participating in MRE.  For further details about MRE, see “—Regulatory Charges—Energy Reallocation Mechanism”.

·Commercialization.  Our commercialization subsidiaries handle our commercialization operations and provide agency services to Free Consumers before the CCEE and other agents, including guidance on their operational requirements.  CPFL Brasil, our largest commercialization subsidiary, procures and sells electricity to Free Consumers, other commercialization and generation companies and distribution facilities.  In 2014, we sold 11,613 GWh of electricity, of which 9,840 GWh was sold to unaffiliated third parties.

·Services.�� Commencing January 1, 2012, we report the results of our services activities as a separate operating segment.  Our activities in this sector include providing electricity‑related services, such as project design and construction, to our affiliates and unaffiliated parties.

Our Strategy

Our overall objective is to consolidate our leadership position in the Brazilian electricity sector while creating value for our shareholders.  We seek to achieve these goals in all of our sectors (distribution, conventional generation, renewable generation, commercialization and services) by pursuing operational efficiency (through innovation and technology) and growth (through business synergies and new projects).  Our strategies are grounded on financial discipline, social responsibility and enhanced corporate governance.  More specifically, our approach involves the following key business strategies:

Complete the development of our existing renewable generation projects, expand our generation portfolio by developing new conventional and renewable energy generation projects and maintain our position asmarket leader in renewable energy sources.  At December 31, 2014, our total consolidated Installed Capacity (calculated on the basis of our 51.61% interest in CPFL Renováveis) was 3,162 MW, of which 2,248 MW was conventionally generated and 914 MW was generated through renewable sources.  Through CPFL Renováveis, in August 2011 we became the largest renewable energy generation group in Brazil in terms of Installed Capacity and capacity under construction, according to ANEEL.

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Our total Installed Capacity at December 31, 2014 represents a 5.8% increase as compared to Installed Capacity of 2,988 MW at December 31, 2013.  This growth was due to the acquisition of the Rosa dos Ventos Wind Farms, the commercial start‑up of two wind complexes, Atlântica and Macacos, and the acquisition of DESA.

By the end of 2018, when we expect the Mata Velha SHPP and Campo dos Ventos, São Benedito, Morro dos Ventos II and Pedra Cheirosa Wind Complexes to become operational, we expect our Installed Capacity to reach 3,299 MW.

Many of our generation facilities hold long‑term PPAs, approved by ANEEL, which we believe will ensure us an attractive rate of return on our investment.  We also have a consolidated portfolio of 1,944 MW (calculated on the basis of our 51.61% interest in CPFL Renováveis’ total portfolio of 3,767 MW) of renewable generation projects to be developed by CPFL Renováveis in the coming years.  As consumption of electricity in Brazil increases, we believe that there will continue to be new opportunities for us to explore investments in additional conventional and renewable generation projects.

Focus on further improving our operating efficiency.  The distribution of electricity in our distribution concession areas is our largest business segment, representing approximately 95.3% of our consolidated net income in 2014.  We continue to focus on improving the quality of our service and maintaining efficient operating costs by exploiting synergies and technologies.  We also make an effort to standardize and update our operations regularly, introducing automated systems where possible.  In recent years, in order to achieve a new level of operational efficiency, we commenced roll out of the Tauron Program, which consists of two main projects: Smart Metering for Commercial and Industrial consumers (high and medium voltage customers) and Mobile Workforce Management.  This program is already delivering benefits, with 24,554 smart meters deployed in the field and our eight distribution companies operating with a data dispatch system for emergency services, replacing the previous voice-based system. 

Expand and strengthen our commercialization.  Free Consumers make up a significant segment of the electricity market in Brazil, representing approximately 25% of the market.  Through our subsidiary CPFL Brasil, our commercialization subsidiary, we are focusing on signing bilateral contracts with former customers of our distribution companies that became Free Consumers, in addition to attracting additional Free Consumers from concession areas other than those covered by our distribution companies.  In order to achieve this objective, we foster positive relationships with customers by providing dedicated key account managers, CCEE operational support and PPAs customized to each consumer profile.

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, 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 and our consumers 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.  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 and corporate governance, providing equitable shareholder rights and, through various measures, including the increase of our free float and the liquidity of our shares, seeking 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 2014.  Our eight distribution subsidiaries together supply electricity to a region covering 176,521 square kilometers, primarily in the states of São Paulo and Rio Grande do Sul.  Their concession areas include 561¹ municipalities and a population of approximately 18 million people.  Together, they provided electricity to approximately 7.6million consumers as of December 31, 2014.  Our eight subsidiaries distributed approximately 13% of the total electricity distributed in Brazil in 2014, based on data from the Energetic Studies Company (Empresa de Pesquisas Energéticas), or EPE.

Distribution Companies

We have eight distribution subsidiaries:

·CPFL Paulista.  Companhia Paulista de Força e Luz, or CPFL Paulista, supplies electricity to a concession area covering 90,440 square kilometers in the state of São Paulo with a population of approximately 9.6 million people.  Its concession area covers 234 municipalities, including the cities ofCampinas, Bauru, Ribeirão Preto, São José do Rio Preto, Araraquara and Piracicaba.  CPFL Paulista had approximately 4.1 million consumers at December 31, 2014.  In 2014, CPFL Paulista distributed 22,852 GWh of electricity, accounting for approximately 22.8% of the total electricity distributed in the state of São Paulo and 6.6% of the total electricity distributed in Brazil during the year.

¹               This total refers to the total number of municipalities situated within our subsidiaries’ concession areas.  In addition, we serve consumers located in municipalities outside of our concession areas in cases where those consumers are not served by the local concessionaire.

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·CPFL Piratininga.  Companhia Piratininga de Força e Luz, or CPFL Piratininga, supplies electricity to a concession area covering 5,618 square kilometers in the southern part of the state of São Paulo with a population of approximately 3.7 million people.  Its concession area covers 27 municipalities, including the cities of Santos, Sorocaba and Jundiaí.  CPFL Piratininga had approximately 1.6 million consumers at December 31, 2014.  In 2014, CPFL Piratininga distributed 9,532 GWh of electricity, accounting for approximately 11.5% of the total electricity distributed in the state of São Paulo and 3.3% of the total electricity distributed in Brazil during the year.

·RGE.  Rio Grande Energia S.A., or RGE, supplies electricity to a concession area covering 58,940 square kilometers in the state of Rio Grande do Sul with a population of approximately 3.7 million people.  Its concession area covers 255 municipalities, including the cities of Caxias do Sul, Gravataí, Passo Fundo and Bento Gonçalves.  During 2014, RGE won a new tender for two municipalities in the state, Putinga and Anta Gorda.  RGE had approximately 1.4 million consumers at December 31, 2014.  In 2014, RGE supplied 8,287 GWh of electricity, accounting for approximately 33.6% of the total electricity distributed in the state of Rio Grande do Sul and 2.2% of the total electricity distributed in Brazil during the year.

·CPFL Santa Cruz.  Companhia Luz e Força Santa Cruz, or CPFL Santa Cruz, supplies electricity to a concession area covering 11,870 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 2014, CPFL Santa Cruz distributed 1,096 GWh of electricity to approximately 202,000 consumers, accounting for approximately 0.8% of the total electricity distributed in the state of São Paulo and 0.2% of the total electricity distributed in Brazil during the year.

·CPFL Jaguari.  Companhia Jaguari de Energia, or CPFL Jaguari, supplies electricity to a concession area covering 252 square kilometers, which includes two municipalities of the state of São Paulo.  In 2014, CPFL Jaguari distributed 502 GWh of electricity to approximately 38,000 consumers.

·CPFL Mococa.  Companhia Luz e Força de Mococa, or CPFL Mococa, supplies electricity to a concession area covering 1,844 square kilometers, which includes one municipality in the state of São Paulo and three municipalities in the state of Minas Gerais.  In 2014, CPFL Mococa distributed 210 GWh of electricity to approximately 45,000 consumers.

·CPFL Leste Paulista.  Companhia Leste Paulista de Energia, or CPFL Leste Paulista, supplies electricity to a concession area covering 2,589 square kilometers, which includes seven municipalities of the state of São Paulo.  In 2014, CPFL Leste Paulista distributed 295 GWh of electricity to approximately 56,000 consumers.

·CPFL Sul Paulista.  Companhia Sul Paulista de Energia, or CPFL Sul Paulista, supplies electricity to a concession area covering 3,802 square kilometers, which includes five municipalities of the state of São Paulo.  In 2014, CPFL Sul Paulista distributed 382 GWh of electricity to approximately 81,000 consumers.

Distribution Network

Our eight distribution subsidiaries operate distribution lines with voltage levels ranging from 11.9 kV to 138 kV.  These lines distribute electricity from the connection point with the Basic Network to our power substations, 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), or TUSD.

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Each of our subsidiaries has a distribution network consisting of a widespread network of predominantly overhead lines and substations 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).

At December 31, 2014, our distribution networks consisted of 240,944 kilometers of distribution lines, including 353,722 distribution transformers.  Our eight distribution subsidiaries had 9,881 km of High Voltage distribution lines between 34.5 kV and 138 kV.  At that date, we had 445 transformer substations for transforming High Voltage into Medium Voltages for subsequent distribution, with total transforming capacity of 14,571 mega‑volt amperes.  Of the industrial and commercial consumers in our concession area, 345 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 2013 according to the most recent information available from the Brazilian Association of Electric Energy Distributors (Associação Brasileira de Distribuidores de Energia Elétrica), or ABRADEE, an industry association.

We are also actively engaged in efforts to reduce commercial losses from illegal connections, fraud or 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.  We conducted 226,042 inspections during 2014, which we believe led to a recovery of receivables estimated at more than R$28 million.

Power Outages

The following table sets forth the frequency and duration of electricity outages per consumer for the years ended December 31, 2014 and 2013 for each of our distribution subsidiaries:

	Year ended December 31, 2014
	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Jaguari	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista
SAIFI1	4.87	4.20	9.14	5.29	4.31	7.26	6.19	6.91
SAIDI2	6.92	6.98	18.77	6.75	5.36	6.76	8.40	9.55

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

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

	Year ended December 31, 2013
	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Jaguari	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista
SAIFI1	4.73	4.58	9.04	6.82	5.43	4.93	6.33	6.72
SAIDI2	7.14	7.44	17.35	6.97	5.92	4.86	7.58	9.08

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

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

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 2013, our frequency and duration of interruptions per consumer in the past few years compare favorably to the averages for other Brazilian distribution companies.

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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.  However, their duration and frequency of outages are below the national average.

ANEEL establishes performance indicators per consumer to be complied with by power companies.  If these indicators are not reached, we are obliged to reimburse our consumers, and our revenues are negatively affected.  In 2013, according to data from ANEEL, the amount we reimbursed our consumers was lower than the average amount reimbursed by power companies of similar size.

Our distribution subsidiaries have construction and maintenance technology that allows for repairs of the electricity network without interruption in electricity service, thereby allowing us to have low rates of scheduled interruption, which amounts to up to approximately 7.8% 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 2014, we invested approximately R$702 million in our Distribution segment, primarily in: (i) expansion, maintenance, improvement, automation, modernization and reinforcement of the electrical system in order to meet market growth; (ii) operational infrastructure; (iii) customer service; and (iv) research and development programs, among other things.  We expect to invest an additional R$1,168 million for such purposes throughout 2015.

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 2014, 11.3% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries (including our joint‑ventures).

In 2014, we purchased 10,417 GWh of electricity from the Itaipu Power Plant, amounting to 17.7% 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 determines annually 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 US$26.05/Kw.  Our purchases represent approximately 17% 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, payments of principal and interest on its U.S. dollar‑denominated debts and the cost of transmitting the power to their concession areas.

The Itaipu Power Plant has an exclusive transmission network.  Distribution companies pay a fee for the use of this network.

In 2014, we paid an average of R$132.82 per MWh for purchases of electricity from Itaipu, compared with R$121.11 during 2013 and R$104.98 during 2012.  These figures do not include the transmission fee.

We purchased 48,463 GWh of electricity in 2014 from generating companies other than Itaipu, representing 82.3% of the total electricity we purchased.  We paid an average of R$201.79 per MWh for purchasesof electricity from generating companies other than Itaipu, compared with R$147.30 per MWh in 2013 and R$121.11 per MWh in 2012.  For more information on the Regulated Market and the Free Market, see “—The New Industry Model Law— The Regulated Market” and “—The New Industry Model Law— The Free Market”.

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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,
	2014	2013	2012
	(in GWh)
Energy purchased for resale
Itaipu	10,417	10,719	10,781
Electric Energy Trading Chamber - CCEE	5,074	2,974	2,662
Proinfa Program	1,043	1,019	1,070
Energy purchased in the Regulated Market and through bilateral contracts	42,345	42,980	48,085
TOTAL	58,879	57,692	62,597

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.

Beginning in 2013, all distribution companies in Brazil are required to purchase electricity from generation companies whose concessions were renewed in accordance with Law 12,783/13.  The tariffs and volumes of electricity to be purchased by each distribution company, as well as the provisions of the applicable agreements between the generation and distribution companies, were set by ANEEL in the law.  See “Item 3.  Key Information—Risk Factors—Our operating results depend on prevailing hydrological conditions.  Poor hydrological conditions may require a higher dispatch of thermoelectric generation in the Brazilian electric system, which may affect our results of operations”.

Transmission Tariffs.  In 2014, we paid a total of R$485 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 annual consolidated financial statements for a breakdown of our sales by category.

·Industrial consumers.  Sales to final industrial consumers accounted for 24.7% of revenues from electricity sales in our Distribution segment in 2014.

·Residential consumers.  Sales to final residential consumers accounted for 41.8% of our revenues from electricity sales in our Distribution segment in 2014.

·Commercial consumers.  Sales to final commercial consumers, which include service businesses, universities and hospitals, accounted for 22.2% of our revenues from electricity sales in our Distribution segment in 2014.

·Rural consumers.  Sales to final rural consumers accounted for 3.2% of our revenues from electricity sales in our Distribution segment in 2014.

·Other consumers.  Sales to other consumers, which include public and municipal services such as street lighting, accounted for 8.1% of our revenue of electricity sales in our Distribution segment in 2014.

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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 electricity is supplied to them.  Each consumer is placed in a certain tariff level defined by law and based on its respective classification.  Some discounts are available depending on the consumer classification, tariff level or environment for trading (Free Consumers and generators).  Group B consumers pay higher tariffs.  Tariffs in Group B vary by type of consumer (residential, rural, other categories and public lighting).  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 ratified 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 day electricity is supplied.  The 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: the TUSD and the tariff for energy consumption, or TE.  The TUSD, expressed inreais per kW, is based on: (i) the electricity demand contracted by the party connected to the system; (ii) certain regulatory charges; and (iii) technical and non‑technical losses of energy on the distribution system.  The TE, expressed inreaisper MWh, is based on the amount of electricity actually consumed.  These consumers may opt to purchase electricity in the Free Market under the New Industry Model Law.  See  “—The New Industry Model Law”.

Group B consumers receive electricity at less than 2.3 kV (220V and 127V).  Tariffs for Group B consumers are charged for the tariff for using the distribution system and also for energy consumption.  Both are charged in R$/MWh.

The following tables set forth our average retail prices for each consumer category for 2014 and 2013.  These prices include taxes (ICMS, PIS and COFINS) and were calculated based on our revenues and the volume of electricity sold in 2014 and 2013.

	Year ended December 31, 2014
	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari	CPFL Mococa
	(R$/MWh)
Residential	394.06	378.82	431.13	415.97	374.54	381.50	309.37	437.22
Industrial	364.14	330.51	327.26	384.69	302.95	286.98	237.19	302.98
Commercial	366.82	352.67	419.95	421.79	344.86	356.49	284.17	388.85
Rural	203.82	232.05	220.55	249.83	213.03	225.60	184.13	233.33
Other	280.68	254.17	186.10	225.00	255.96	257.10	208.68	270.16
Total	357.14	347.00	331.10	346.49	301.75	322.53	252.07	346.54

	Year ended December 31, 2013
	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari	CPFL Mococa
	(R$/MWh)
Residential	362.57	351.98	430.59	345.40	391.18	389.56	286.82	478.59
Industrial	311.98	304.74	301.21	320.33	328.00	304.86	241.09	347.11
Commercial	320.44	328.12	416.85	358.88	368.54	365.49	267.43	428.69
Rural	180.39	210.91	221.40	207.09	225.19	228.55	174.64	248.85
Other	241.97	237.18	183.19	169.24	324.87	269.18	216.20	295.39
Total	317.96	321.24	323.81	286.17	329.32	332.46	248.96	382.16

Under current regulations, residential consumers may be eligible to pay a reduced tariff (Tarifa Social de Energia Elétrica), or the TSEE.  Families eligible to benefit from the TSEE are (i) those registered with the Brazilian government’s Single Registry of Social Programs (Cadastro Único para Programas Sociais do GovernoFederal) with monthly per capita income at or below half the national minimum wage and (ii) those who receive the Continued Social Assistance Provision Benefits (Benefício da Prestação Continuada da Assistência Social).  Discounts range from 10% to 65% on energy consumption per month.  In addition, these residential consumers are not required to pay the Proinfa Program charge or any extraordinary tariff approved by ANEEL.  Indigenous peoples and residents of traditional rural communities (quilombos) receive free electricity up to maximum consumption of 50 kWh.

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TUSD.  The TUSD tariffs are set by ANEEL and consist of the three tariffs described under “Item 4.  Information on the Company—System Tariffs—TUSD”.  In 2014, tariff revenues for the use of our network by Free Consumers amounted to R$991 million.  The average tariff for the use of our network was R$58.97/MWh and R$55.78/MWh in 2014 and 2013, respectively, including the TUSD we charge to other distributors connected to our Distribution Networks.

Billing Procedures

The procedure we use for billing and payment for electricity supplied to our consumers is determined by consumer and tariff categories.  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 two months, as authorized by relevant regulation.  Bills are issued from meter readings or, if meter readings are not possible, from the average of monthly consumption.  Low voltage consumers are billed within a maximum of three business days after the meter reading, with payment required within a minimum of five business days after the invoice presentation date.  In case of nonpayment, we send the consumer a notice of nonpayment with the following month’s invoice and we allow the consumer up to 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 may be suspended.  We may also take other measures, such as inclusion of the consumer in the list of debtors of credit reporting agencies, or extrajudicial or judicial collection through collection agencies.

High voltage consumers are read and billed on a monthly basis with payment required within five business days after the receipt of an invoice.  In the event of nonpayment, we send the consumer a notice up to two 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 2013, the percentage of customers in default for 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 up to 90 days overdue.  Bills due and outstanding for over 360 days are deemed unrecoverable.

Customer Service

We strive to provide high‑quality customer service to our distribution consumers.  We provide customer service 24 hours a day, 7 days a week.  The requests are received using a variety of platforms such as call centers, our website, SMS and our smartphone application.  In 2014, we responded to approximately 29.6 million inquiries.  We also provide customer service through our branch offices, which handled approximately 5.2 million customer requests in 2014.  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 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 that a generation facility has sold its electricity and participates in the MRE, it will receive at least the revenue amount that corresponds to the Assured Energy, even if it does not actually generate all the energy.  Conversely, if a generation facility’s output exceeds its Assured Energy, its incremental revenue is equal only to the costs associated therewith.

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Most of our Hydroelectric Power Plants are members of the MRE, a system by which hydroelectric generation facilities share the hydrological risks of the Interconnected Power System.  Our total Installed Capacity in our Conventional Generation and Renewable Generation segments was 3,162 MW as of December 31, 2014.  Most of the electricity we produce comes from our Hydroelectric Power Plants.  We generated a total of 13,658GWh in 2014, 11,427 GWh in 2013 and 10,570 GWh in 2012, in each case after accounting for the decrease in our participation in CPFL Renováveis as a result of its initial public offering in 2013 and the agreement with Arrow in 2014 (see “– Overview”).

Conventional Generation

Hydroelectric Power Plants

At December 31, 2014, our subsidiary CPFL Geração owned a 51.54% interest in the Assured Energy from the Serra da Mesa Power Plant.  Through its 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 Power Plants, which have been operational since December 2004, November 2005, February 2007, March 2008, December 2008 and October 2010, respectively.  Through CPFL Jaguari Geração, we owned a 6.93% interest in the Assured Energy from the Luis Eduardo Magalhães Power Plant.

All Installed Capacity and Assured Energy numbers stated in the discussion below refer to the full capacity of the plant in question rather than our consolidated share of such energy, which reflects our interest in the plant.

Serra da Mesa.  Our largest Hydroelectric Facility in operation is the Serra da Mesa facility, which we acquired in 2001 from ESC (formerly 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 a total 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 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 was renewed in March 2014 at a price that is adjusted annually based on the IGP‑M.  This contract expires in 2028.  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 30, 2014, the concession held by Furnas was formally extended to November 12, 2039.  

CERAN Complex.  We own a 65.0% interest in CERAN, a subsidiary that was granted a 35‑year concession in March 2001 to construct, finance and operate the CERAN hydroelectric complex.  The other shareholders are CEEE (with 30.0%) and Desenvix (with 5.0%).  The CERAN hydroelectric complex consists of three Hydroelectric Power 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 1,515.4 GWh per year, of which our share is 985 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).  Monte Claro’s first generating unit, which became operational in 2004, has Installed Capacity of 65 MW and the second generating unit, which became operational in 2006, also has an Installed Capacity of 65 MW, giving total Installed Capacity of 130 MW and Assured Energy of 516.8 GWh per year. 

·Castro Alves (CERAN Complex).  In March 2008, the first generation unit of the Castro Alves Power Plant became operational, with total Installed Capacity of 43.4 MW.  In April 2008, the second generation unit became operational, with Installed Capacity of 43.4 MW.  In June 2008, this plant became fully operational (when the third generation unit started operations), giving total Installed Capacity of 130 MW and annual Assured Energy of 560.6 GWh per year.

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·14 de Julho (CERAN Complex).  The first generation unit of the 14 de Julho Power 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. 

We are currently engaged in refurbishment of the CERAN complex.  We are installing equipment to assure the free flow of water in the three hydroelectric plants, which will therefore increase their availability.  In 2013, we completed refurbishment of the Monte Claro Hydroelectric Power Plant, and we are currently monitoring that equipment to determine its efficiency.  Subject to the results of this monitoring, we intend to agree to a schedule of the remaining improvements with ANEEL and expect to complete the improvements in all CERAN facilities by the end of 2016.  In addition, discussions with ANEEL and other entities in the transmission sector are ongoing regarding the conditions under which we will transfer the Monte Claro Substation to the Basic Network, which would eliminate maintenance costs and our responsibility for operation of the Substation.

Barra Grande.  This facility became fully operational in May 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) (15.0%), DME (Departamento Municipal de Eletricidade de Poços de Caldas) (8.82%), andCamargo Corrêa Cimentos S.A. (9.0%). We sell our participation in the Assured Energy of this facility to affiliates in our group.

Campos Novos.  We own a 48.72% interest in ENERCAN, a joint venture formed by a consortium of private and public sector companies that was granted a 35‑year concession in May 2000 to construct, finance and operate the Campos Novos Hydroelectric Facility.  The plant was constructed on the Canoas River in the state of Santa Catarina, and became fully operational in May 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 (33.14%), Votorantim Metais Níqueis S.A. (11.6%) and CEEE (6.51%).  The plant is operated by ENERCAN under CPFL Geração’s supervision.  We sell our participation in the Assured Energy of this joint venture to affiliates in our group.

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 Power Plant.  The remaining 49.0% interest in the joint venture is divided among Furnas, which holds a 40.0% interest, and CEEE, which holds a 9.0% interest.  The Foz do Chapecó Hydroelectric Power Plant is located on the Uruguay River, on the border between the states of Santa Catarina and Rio Grande do Sul.  The Foz do Chapecó Power Plant became fully operational in March 2011 with 855 MW of total Installed Capacity and Assured Energy of 3,784.3 GWh per year.  Of our 51.0% share in the Assured Energy of this project, we sell 40.0% to affiliates in our group and 11.0% through Agreements on Energy Commercialization in the Regulated Market (Contratos de Comercialização de Energia no Ambiente Regulado), or CCEARs.  In January 2013, at the request of ANEEL, we began the process of transferring the Foz do Chapecó Substation and exclusive transmission lines to the Basic Network, thereby eliminating maintenance costs, responsibility for operation of these assets and reducing the transmission line energy loss factor (regulatory loss).

Luis Eduardo Magalhães.  We own a 6.93% interest in the Assured Energy from 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).

Thermoelectric Power Plants

We operate three Thermoelectric Power Plants.  Termonordeste, which commenced operations in December 2010, and Termoparaíba, which commenced operations in January 2011 under ANEEL authorizations, are powered by fuel oil from the EPASA complex, with total Installed Capacity of 341.6 MW and total Assured Energy of 2,169.0 GWh.  On December 31, 2014, we owned an aggregate 57.13% interest in Termonordeste and Termoparaíba, which was diluted to 53.34% as of March 2015.  See note 38.4 to our audited annual consolidated financial statements.  The Termonordeste and Termoparaíba Thermoelectric Power Plants are located in the city ofJoão Pessoa, in the state of Paraíba.  The electricity from these power plants was sold in CCEARs, and part of this energy was purchased by our own distributors.

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The Carioba facility has an Installed Capacity of 36 MW; however, it has been officially deactivated since October 19, 2011, as provided for in Order No. 4,101 of 2011.  We have applied to terminate the Carioba concession since ANEEL reduced the subsidy associated with the Fuel Usage Quota Account (Conta de Consumo de Combustível), or the CCC Account.  ANEEL has recommended that the MME terminate Carioba’s concession.  The MME is currently analyzing the request.

Small Hydroelectric Power Plants

At December 31, 2014, 10 of our 49 Small Hydroelectric Power Plants were under the management of two of our conventional generation subsidiaries, CPFL Geração and CPFL Centrais Geradoras. These 10 Small Hydroelectric Power Plants reported their results within the Conventional Generation segment.  They consist of two groups of facilities:

·Nine of these facilities were originally managed together with their associated distribution companies within our Distribution segment.  Law No. 12,783/13 of January 11, 2013 specified the conditions for the renewal of generation, transmission and distribution concessions obtained under articles 17, 19 or 22 of Law No. 9,074 of July 7, 1995.  Under Law No. 12,783/13, these concessions may be extended once, at the discretion of the Brazilian government, for up to 30 years, in order to ensure the continuity and efficiency of the services rendered and of low tariffs.  In addition, Law No. 12,783/13 provided that holders of concessions that were due to expire in 2015, 2016 and 2017 could apply for early renewal in 2013, subject to certain conditions.  However, Resolution No. 521/12 published by ANEEL on December 14, 2012 established that the generation concessions to be renewed under Law No. 12,783/13 must be partitioned into separate operating entities in cases where the Installed Capacity of the original concessionaire entity exceeded 1 MW.  On October 10, 2012, in anticipation of Law 12,783/13, we applied for early renewal of the concessions held by our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista, which were originally granted in 1999 for a 16‑year term.  Pursuant to the partition requirement under Resolution No. 521/12, we were required to separate the generation and distribution activities of three of the plants, Rio do Peixe I and II and Macaco Branco, whose generation facilities were transferred to CPFL Centrais Geradoras on August 29, 2013.  At that time, our Management decided for operational reasons to partition the generation and distribution activities of the remaining six facilities held by the five distribution subsidiaries (Santa Alice, Lavrinha, São José, Turvinho, Pinheirinho and São Sebastião), the generation facilities of which were also transferred to CPFL Centrais Geradoras.

·During 2014, the concessions for the Salto do Pinhal and Ponte do Silva facilities were terminated under Authorizing Resolution No. 4,559/2014, which determined that concessions for inactive Micro Hydroelectric Power Plants would be extinguished without reversion of the respective assets to the government.

·The remaining facility, Cariobinha, has been held by CPFL Geração since the signing of the concession contract.

On December 4, 2012, the concessions of the Rio do Peixe I and II and Macaco Branco Small Hydroelectric Power Plants were renewed for 30 years under Law No. 12,783/13.  The renewals of these concessions were subject to the following conditions:

(i)            The energy generated must be sold to all distribution companies in Brazil according to quotas defined by ANEEL (previously, energy was sold only to the related distribution subsidiary);

(ii)           The concessionaire’s annual revenue is set by ANEEL, subject to tariff reviews (previously, the energy prices were defined contractually and adjusted according to the IPCA); and

(iii)          The assets that remained unamortized at the renewal date would be indemnified, and the indemnification payment would not be considered as annual revenue.  The remuneration relatingto new assets or existing assets that were not indemnified would be considered as annual revenue.  Rio do Peixe I and II received a total of R$34.4 million in indemnification payments.  The assets of Macaco Branco had been fully amortized, and therefore generated no indemnification payment.

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The following table sets forth certain information relating to our principal conventional generation facilities in operation and the Small Hydroelectric Power Plants that reported their results within the Conventional Generation segment as of December 31, 2014:

	Holding company	Partic.	Capacity (MW)		Assured Energy (GWh)		Placed in service	Concession expires
			Our share	TOTAL	Our share	TOTAL
Hydroelectric plants:
Serra da Mesa	CPFL Geração	51.54%	657.1	1,275.0	3,029.5	5,878.0	1998	2028(1)
Monte Claro.	CPFL Geração	65%	84.5	130.0	335.9	516.8	2004	2036
Barra Grande	CPFL Geração	25.01%	172.6	690.0	833.9	3,334.1	2005	2036
Campos Novos	CPFL Geração	48.72%	428.7	880.0	1,612.8	3,310.4	2007	2035
Castro Alves	CPFL Geração	65%	84.5	130.0	364.4	560.6	2008	2036
14 de Julho	CPFL Geração	65%	65.0	100.0	284.7	438.0	2008	2036
Luis Eduardo Magalhães	CPFL Jaguari de Geração	6.93%	62.5	902.5	319.7	4,613.0	2001	2032
Foz do Chapecó	Chapecoense	51%	436.1	855.0	1,930.0	3,784.3	2010	2036
SUBTOTAL ‑ Hydroelectric plants			1,991.0		8,710.9
Thermoelectric plants:
Carioba	CPFL Geração	100%	36.0	36.0	93.7	93.7	1954	2027(2)
EPASA facilities:
Termonordeste	CPFL Geração	57.13%(5)	97.6	170.8	619.6	1,084.5	2010	2042
Termoparaíba	CPFL Geração	57.13%(5)	97.6	170.8	619.6	1,084.5	2011	2042
SUBTOTAL ‑ Thermoelectric plants			231.2		1,332.9
Small Hydroelectric Plants
Cariobinha	CPFL Geração	100%	1.3	1.3	‑	-	N/A	2027(2)
Lavrinha	CPFL Centrais Geradoras	100%	0.3	0.3	(4)	(4)	N/A	(3)
Macaco Branco	CPFL Centrais Geradoras	100%	2.4	2.4	14.5	(4)	N/A	2042
Pinheirinho	CPFL Centrais Geradoras	100%	0.6	0.6	(4)	(4)	N/A	(3)
Rio do Peixe I	CPFL Centrais Geradoras	100%	3.1	3.1	‑	N/A	N/A	2042
Rio do Peixe II	CPFL Centrais Geradoras	100%	15.0	15.0	46.9	N/A	N/A	2042
Santa Alice	CPFL Centrais Geradoras	100%	0.6	0.6	(4)	(4)	N/A	(3)
São José	CPFL Centrais Geradoras	100%	0.8	0.8	(4)	(4)	N/A	(3)
São Sebastião	CPFL Centrais Geradoras	100%	0.7	0.7	(4)	(4)	N/A	(3)
Turvinho	CPFL Centrais Geradoras	100%	0.8	0.8	(4)	(4)	N/A	(3)
SUBTOTAL – Small Hydroelectric Plants			25.6		61.4
TOTAL – Conventional Generation			2,248		10,105.2

(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.

(2) Inactive power plant.

(3) 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.

(4) Power plants that currently do not have Assured Energy approved by the MME.  We have recently requested ANEEL and the MME approve the parameters of reference used to calculate the Assured Energy for these power plants. However, until the approval of Assured Energy at these plants is published, energy produced by these plants will be sold in the spot market.

(5) After a capital increase on January 31, 2014, the holdings of certain shareholders of the joint venture EPASA were diluted. As per the actual Shareholders Agreement, these shareholders were entitled to repurchase shares in order to reconstitute their holdings, and accordingly, on March 1, 2015, CPFL Geração holds 53.34% of EPASA. See note 38.4 of ouraudited annualconsolidated financial statements.

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Renewable Generation

At December 31, 2014, through our subsidiary CPFL Geração, we owned a 51.61% interest in CPFL Renováveis, a company resulting from an association with another Brazilian renewable energy producer, Energias Renováveis S.A., or ERSA, which holds our subsidiaries engaged in the generation of electricity from renewable sources.  Through CPFL Renováveis, in August 2011, we became the largest renewable energy generation group in Brazil in terms of Installed Capacity and capacity under construction, according to ANEEL.  We have fully consolidated CPFL Renováveis in our financial statements since August 1, 2011.  CPFL Renováveis carried out its initial public offering in July 2013, resulting in a decrease in our shareholding from 63% to 58.84%. On October 1, 2014, CPFL Renováveis acquired 100% of the shares of DESA through an issuance of shares of CPFL Renováveis, resulting in a decrease in our shareholding of CPFL Renováveis from 58.84% to 51.61%.

CPFL Renováveis invests in independent renewable energy production sources with low environmental and social impact, such as Small Hydroelectric Power Plants, wind farms, biomass‑fueled thermoelectric plants and photovoltaic solar plants, focusing exclusively on the Brazilian market.  CPFL Renováveis has extensive experience in the development, acquisition, construction and operation of electricity-generating plants using renewable energy sources.  CPFL Renováveis operates in the four main segments of the renewable energy generation industry in Brazil: Small Hydroelectric Power Plants, wind farms, biomass‑fueled thermoelectric plants and photovoltaic solar plants.  CPFL Renováveis operates in eight Brazilian states and its business contributes to the local and regional economic and social development.

At the date of this Annual Report, CPFL Renováveis consists of the generation entities described below.  All Installed Capacity and Assured Energy numbers stated in the discussion below refer to the full capacity of the plant in question rather than our consolidated share of such energy, which only reflects our interest in the plant.   

·28 subsidiaries involved in the generation of electric energy through 39 Small Hydroelectric Power Plants, consisting of (i) 38 SHPPs that are operational, with aggregate Installed Capacity of 399 MW, located in the states of São Paulo, Santa Catarina, Rio Grande do Sul, Paraná, Minas Gerais and Mato Grosso, and (ii) the Mata Velha SHPP, with 24 MW of Installed Capacity (from DESA), located in the state of Minas Gerais, which is under construction and scheduled to commence operations in 2016.

·45 subsidiaries involved in the generation of electric energy from wind sources.  Of this total, 33 farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, are operational and have aggregate Installed Capacity of 999 MW (or aggregate capacity of 1,003 MW based on the total industrial capacity of CPFL Renováveis’ assets).  The remaining 12 farms are under construction, scheduled to commence operations between 2016 and 2018, and are expected to have aggregate Installed Capacity of approximately 312 MW.

·Eight subsidiaries involved in the generation of electric energy from biomass, all of which are operational, with total Installed Capacity of 370 MW, located in the states of Minas Gerais, Paraná, São Paulo and Rio Grande do Norte.  On August 27, 2010, CPFL Bioenergia’s Baldin Plant, our first sugarcane bagasse‑powered plant started operations, with 45 MW of total Installed Capacity.  CPFL Bio Formosa began operations on September 2, 2011, with total Installed Capacity of 40 MW.  CPFL Bio Buriti began operations on October 7, 2011 with total Installed Capacity of 50 MW.  Bio Ipê began operations on May 17, 2012 with total Installed Capacity of 25 MW.  Bio Pedra began operations on May 31, 2012 with total Installed Capacity of 70 MW.  On October 18, 2012, we completed the acquisition of the Ester Thermoelectric Power Plant, which has total Installed Capacity of 40 MW.  CPFL Coopcana and CPFL Alvorada, each with 50 MW of total Installed Capacity, began operations on August 28, 2013 and November 11, 2013, respectively.

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·One subsidiary involved in the generation of electric energy from a solar power plant, Tanquinho, which is located in the state of São Paulo and has total Installed Capacity of 1.1 MWp.  Tanquinho started operations on November 27, 2012 and is expected to generate approximately 1.6 GWh/year.

Existing Installed Capacity

The following describes our existing and operational renewable generation plants:

Small Hydroelectric Power Plants

Small Hydroelectric Power Plants are plants with generation capacity between 1 MW and 30 MW and a reservoir area of up to three square kilometers.  A typical Small Hydroelectric Power Plant operates under a “run-of-river” system and as a result, it may experience idleness when the available water flow is less than the turbine inflow capacity.  If flows are greater than the equipment’s capacity, water flows through a spillway.  Small Hydroelectric Power Plants are allowed to participate in the MRE, and in this case, the amount of energy sold by the power plant depends solely on its certificate of guarantee and not on its individual energy production. 

CPFL Renováveis operates 39 of our 49 (48 operational and 1 under construction) Small Hydroelectric Power Plants primarily under the concession and registration regime, all located in the state of São Paulo, Minas Gerais, Mato Grosso, Paraná, Santa Catarina and Rio Grande do Sul.

There have been several revisions, mainly consisting of reductions, to CPFL Renováveis’ Assured Energy, on account of reductions in the expected operational performance.

The automation of these power plants allows us to carry out control, supervision and operations remotely.  Since CPFL Energia acquired CPFL Renováveis’ renewable business, we have established an operational center for the management and monitoring of our power plants in Jundiai, São Paulo. Regarding the remote control, supervison and operation of the wind energy assets, we have also established a remote control center in Fortaleza , Ceará.

Biomass Thermoelectric Power Plants

Biomass‑fueled thermoelectric plants are generators that use the combustion of organic matter for the production of energy.  This organic matter may include products such as sugarcane bagasse, vegetable coal, biogas, black liquor, rice husk and wood chips.  Energy fueled by biomass is renewable and creates less pollution than other energy forms, such as those obtained from the use of fossil fuels (petroleum and coal), create.  The construction period of biomass‑fueled thermoelectric plants is shorter than that of Small Hydroelectric Power Plants (from one to two years, on average).  The necessary investment per installed MW for the construction of a biomass‑fueled thermoelectric plant is proportionally lower than the investment for construction of a Small Hydroelectric Power Plant.  On the other hand, the operation of a biomass‑fueled thermoelectric plant is generally more complex, as it involves the acquisition, logistics and construction of organic matter used for power generation.  For this reason, the operational costs of biomass‑fueled thermoelectric plants tend to be higher than the operational costs of Small Hydroelectric Power Plants.

Despite being more complex, biomass‑fueled thermoelectric plants benefit from: (i) expedited environmental licensing; (ii) abundant fuel in Brazil, which may come from sub‑products of other activities (e.g. wood chips); and (iii) proximity to consumers, reducing transmission costs.  Fuel acquisition and logistics costs are significantly lower for biomass‑fueled thermoelectric plants compared to Thermoelectric Power Plants from non‑renewable sources.  Additionally, even though they are eligible for the Clean Development Mechanism established by the Kyoto Protocol (Mecanismo de Desenvolvimento Limpo), or MDL, and have the potential to generate carbon credits, biomass-fueled thermoelectric plants installed in Brazil have encountered difficulties in obtaining approval for projects due to the methodology of the approval process.

We currently have eight biomass‑fueled thermoelectric plants under the authorization regime, located in the states of São Paulo, Minas Gerais, Rio Grande do Norte and Paraná.

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, that became operational in August 2010.  This co‑generation planthas total Installed Capacity of 45.0 MW.  The plant has an Assured Energy of 112.1 GWh and all of its electricity is sold to CPFL Brasil.

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CPFL Bio Formosa.  In 2009, CPFL Brasil established the Baia Formosa power plant (CPFL Bio Formosa), located in the city of Baía Formosa, in the state of Rio Grande do Norte, with total Installed Capacity of 40 MW.  The CPFL Bio Formosa plant began operations in September 2011.   Approximately 11 MW of energy were sold in the A-5 auction (see “— The New Industry Model Law —Auctions on the Regulated Market”), with CCEARs in force until 2025.

CPFL Bio Buriti.  In March 2010, CPFL Bio Buriti, which was formed to develop electric energy generation projects using sugarcane bagasse, executed a partnership agreement with Grupo Pedra Agroindustrial to develop new biomass generation projects.  The CPFL Bio Buriti plant, located in the city of Buritizal, in the state of São Paulo, began its operations in October 2011.  The total Installed Capacity of this plant is 50 MW.  CPFL Bio Buriti has an associated PPA of 184.1 GWh in force until 2030 with CPFL Brasil.

CPFL Bio Ipê.  In March 2010, CPFL Bio Ipê, which was formed to develop electric energy generation projects using sugarcane bagasse, executed a partnership agreement with Grupo Pedra Agroindustrial to develop new biomass generation projects.  The CPFL Bio Ipê plant, located in Nova Independência, in the state of São Paulo, began its operations in May 2012.  The total Installed Capacity of this plant is 25 MW.  This project has an associated PPA of 71.7 GWh in force until 2030 and the energy has been entirely sold to CPFL Brasil.

CPFL Bio Pedra.  In March 2010, CPFL Bio Pedra, which we formed to develop electric energy generation projects using sugarcane bagasse, executed a partnership agreement with Grupo Pedra Agroindustrial to develop new biomass generation projects.  Bio Pedra, located in Serrana, in the state of São Paulo, started operations in May 2012 with total Installed Capacity of 70 MW and Assured Energy of 213.7 GWh.  The electricity from Bio Pedra has been sold through an auction held in 2010, with CCEARs in force until 2027.

CPFL Bio Ester.  In October 2012, CPFL Renováveis completed the acquisition of the electrical energy and steam co‑generation assets of SPE Lacenas Participações Ltda., which controlled the Ester Thermoelectric Power Plant, located in the municipality of Cosmópolis, in the state of São Paulo.  Around 7 MW average of co‑generation energy from theEster Thermoelectric Power Plant was commercialized in the 2007 alternative energy sources auction, for a period of 15 years.  The remaining 3.2 MW of energy was sold on the free market for 21 years.

CPFL Coopcana. The construction of UTE Coopcana began in 2012 in the city of São Carlos do Avaí, in the state of Paraná, and operations started on August 28, 2013.The total Installed Capacity of UTE Alvorada is of 50 MW and Assured Energy is 157.7 GWh.  This project has an associated PPA in force until 2033 with CPFL Brasil.

CPFL Alvorada. The UTE Alvorada plant is located in the city of Araporã, in the state of Minas Gerais, began operations in November 2013.  The total Installed Capacity of UTE Alvorada is 50 MW and Assured Energy is 158.6 GWh.  This project has an associated PPA in force until 2032 with CPFL Brasil.

Solar Power Plant

Tanquinho.  The Tanquinho solar power plant, in the state of São Paulo, started operations in November 2012, with total Installed Capacity of 1.1 MWp.  We expect Tanquinho to generate approximately 1.6 GWh per year.

Wind Farms

Wind power is derived from the force of the wind passing over the blades of a wind turbine and causing the turbine to spin.  The amount of mechanical power that is transferred and the potential of electricity to be produced are directly related to the density of the air, the area covered by the blades of the wind turbine and the wind speed and height of each wind turbine.

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The construction of a wind farm is less complex than the construction of Small Hydroelectric Power Plants, consisting of the preparation of the foundation and installation of wind turbines, which are assembled on site by suppliers.  The construction period of a wind farm is shorter than that of a Small Hydroelectric Power Plant, ranging from 18 months to two years, on average.  The investment per installed MW for the construction of a wind farm is proportionally lower than the investment for construction of a Small Hydroelectric Power Plant.  In contrast, the operation may be more complex and there are more risks associated with the variability of winds, especially in Brazil, where there is little history of wind measurement.

Certain regions of Brazil are more favorable in terms of wind speed, with higher average speeds and lower volatility as measured by speed variation, allowing for more predictability in the volume of wind energy to be produced.  Wind farms operate complementary to hydroelectric plants, since wind speed is usually higher in drought periods and it is, therefore, possible to preserve water from reservoirs in scarce rain periods.  The complementary operation of wind farms and Small Hydroelectric Power Plants should allow us to “stock up” on electric power in the Small Hydroelectric Power Plants’ reservoirs during periods of high wind power generation.  Estimates of the 2001 Wind Potential Atlas (Atlas do Potencial Eólico) (the latest study on the subject) indicate a wind energy potential of 143 GW in Brazil, a volume that greatly exceeds the country’s current total Installed Capacity of 4.4 GW as of December 2014 according to ANEEL signaling a high growth potential in this segment.  Wind farms are also eligible for MDL and have the potential to generate carbon credits for sale.

We currently have 42 wind farms under the authorization regime, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul.

Praia Formosa:Praia Formosa Wind Farm, in the state of Ceará, began operations in August 2009.  It has an Installed Capacity of 105 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The PPA is in force until August 2029.

Icaraizinho:Icaraizinho Wind Farm, in the state of Ceará, began operations in October 2009.  It has an Installed Capacity of 54.6 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The PPA is in force until October 2029.

Foz do Rio Choró:Foz do Rio Choró Wind Farm, in the state of Ceará, began operations in January 2009.  It has an Installed Capacity of 25.2 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The PPA is in force until June 2029.

Paracuru:Paracuru Wind Farm, in the state of Ceará, began operations in November 29, 2008.  It has an Installed Capacity of 25.2 MW and an associated PPA in force until November 2028.

Taíba Albatroz:Taíba Albatroz Wind Farm, in the state of Ceará, has an Installed Capacity of 16.5 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The acquisition of Taíba Albatroz Wind Farm was concluded in June 2012.

Bons Ventos:Bons Ventos Wind Farm, in the state of Ceará, has an Installed Capacity of 50.0 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The acquisition of Bons Ventos Wind Farm was concluded in June 2012. 

Canoa Quebrada:Canoa Quebrada Wind Farm, in the state of Ceará, has an Installed Capacity of 57.0 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The acquisition of Canoa Quebrada Wind Farm was concluded in June 2012.

Enacel:Enacel Wind Farm, in the state of Ceará, has an Installed Capacity of 31.5 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The acquisition of Enacel Wind Farm was concluded in June 2012.

Santa Clara Complex:Santa Clara Complex, in the state of Rio Grande do Norte, comprises seven wind farms with an Installed Capacity of 188 MW and an associated CCEAR in force until June 2032.  The Santa Clara wind farms sold their energy through the 2009 Reserve Energy Auction.

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Campo dos Ventos II Wind Farm. In 2010, CPFL Geração acquired Campo dos Ventos II Wind Farm (CPFL Renováveis currently holds this investment) in the cities of João Câmara and Parazinho, in the state of Rio Grande do Norte, which began operations in September 2013.  This wind farm has an Installed Capacity of 30 MW and Assured Energy of 131.4 GWh.  The electricity from Campo dos Ventos II has been sold through an auction held in 2010, with PPAs in force until August 2033.

Rosa dos Ventos Wind Farm: In June 2013, CPFL Renováveis acquired Rosa dos Ventos Wind Farm (Canoa Quebrada and Lagoa do Mato fields), located in the state of Ceará.  This wind farm has an Installed Capacity of 13.7 MW and the electricity produced by Rosa dos Ventos is subject to an agreement with Eletrobras under the Proinfa Program.

Atlântica Complex:The Atlântica Complex consists of the Atlântica I, II, IV and V Wind Farms.  The Complex has an aggregate Installed Capacity of 120 MW and aggregate Assured Energy of 461.7 GWh.  The electricity from these wind farms has been sold through an alternative energy auction held in 2010, with CCEARs in force until 2033.  The Atlântica Complex commenced operations in March 2014.

Macacos Complex: The Macacos Complex consists of the Pedra Preta, Costa Branca, Juremas and Macacos Wind Farms.  The Complex has an aggregate Installed Capacity of 78.2 MW and aggregate Assured Energy of 37.1 MWavg.  The Macacos Complex sold its energy through the 2010 Alternative Sources Auction.

Morro dos Ventos Complex: The Morro dos Ventos Complex consists of the Morro dos Ventos I, Morro dos Ventos III, Morro dos Ventos IV, Morro dos Ventos VI and Morro dos Ventos IX Wind Farms.  The Complex has an aggregate Installed Capacity of 144.0 MW and aggregate Assured Energy of 68.5 MWavg.  The Morro dos Ventos Complex sold its energy through the 2009 Reserve Energy Auction.

Eurus Complex: Eurus Complex consists of the Eurus I and Eurus III Wind Farms.  The Complex has an aggregate Installed Capacity of 60 MW and aggregate Assured Energy of 31.6 MWavg.  The Eurus Complex sold its energy through the 2010 Reserve Energy Auction.

The following table sets forth certain information relating to our principal renewable facilities, held by CPFL Renováveis (51.61% our share) in operation as of December 31, 2014:

	Capacity (MW)		Assured Energy (GWh)		Placed in service	Facility upgraded	Concession expires
	Our share	TOTAL	Our share	TOTAL
Small Hydroelectric plants:
Alto Irani	10.8	21.0	61.9	120.0	2008		2032
Americana	15.5	30.0	26.6	51.5	1949	2002	2027
Andorinhas	0.3	0.5	1.9	3.7	1940		(4)
Arvoredo	6.7	13.0	35.1	68.1	2010		2032
Barra da Paciência	11.9	23.0	67.3	130.4	2011		2029
Buritis	0.4	0.8	1.6	3.1	1922		2027(2)
Capão Preto	2.2	4.3	10.3	20.0	1911	2008	2027
Chibarro	1.3	2.6	7.3	14.1	1912	2008	2027
Cocais Grande	5.2	10.0	22.0	42.6	2009		2029
Corrente Grande	7.2	14.0	38.6	74.7	2011		2030
Diamante	2.2	4.2	7.2	14.0	2005		2019
Dourados	5.6	10.8	31.6	61.2	1926	2002	2027
Eloy Chaves	9.7	18.8	52.4	101.5	1954	1993	2027
Esmeril	2.6	5.0	13.0	25.2	1912	2003	2027
Fiqueiropolis	10.0	19.4	56.5	109.5	2010		2034
Gavião Peixoto	2.5	4.8	17.3	33.5	1913	2007	2027
Guaporé	0.4	0.7	2.5	4.9	1950		(4)
Jaguari	6.1	11.8	20.3	39.4	1917	2002	2027
Lençóis	0.9	1.7	4.7	9.1	1917	1988	2027
Ludesa	15.5	30.0	95.8	185.7	2007		2032
Monjolinho	0.3	0.6	0.5	1.0	1893	2003	2027(2)
Ninho da Águia	5.2	10.0	29.4	56.9	2011		2029
Novo Horizonte	11.9	23.0	47.0	91.1	2011		2032
Paiol	10.3	20.0	49.8	96.5	2010		2032
Pinhal	3.5	6.8	16.7	32.4	1928	1993	2027
Pirapó	0.4	0.8	2.6	5.1	1952		(4)
Plano Alto	8.3	16.0	44.1	85.5	2008		2032
Saltinho	0.4	0.8	3.3	6.4	1950		(4)
Salto Góes	10.3	20.0	50.2	97.2	2012		2040
Salto Grande	2.4	4.6	11.7	22.6	1912	2003	2027
Santa Luzia.	14.7	28.5	83.3	161.4	2007		2037
Santana.	2.2	4.3	11.8	22.9	1951	2002	2027
São Gonçalo	5.7	11.0	34.4	66.6	2010		2030
São Joaquim.	4.2	8.1	22.9	44.4	1911	2002	2027
Socorro	0.5	1.0	1.4	2.7	1909	1994	2027(2)
Três Saltos	0.3	0.6	1.9	3.8	1928		2027(2)
Varginha.	4.6	9.0	24.4	47.2	2010		2029
Várzea Alegre	3.9	7.5	22.1	42.7	2011		2029
SUBTOTAL ‑ Small Hydroelectric Power Plants (our share)	206	399	1,031	1,999

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	Capacity (MW)		Assured Energy (GWh)		Placed in service	Facility upgraded	Concession expires
	Our share	TOTAL	Our share	TOTAL
Thermoelectric biomass plants:
Baldin (CPFL Bioenergia)	23.2	45.0	57.9	112.1	2010		2039
Bio Alvorada.	25.8	50.0	81.5	157.9	2013		2042
Bio Buriti.	25.8	50.0	95.0	184.1	2011		2040
Bio Coopcana.	25.8	50.0	81.6	158.0	2013		2042
Bio Ester	20.6	40.0	46.1	89.4	2010		2029
Bio Formosa.	20.6	40.0	49.7	96.4	2011		2032
Bio Ipê	12.9	25.0	37.0	71.7	2012		2040
Bio Pedra.	36.1	70.0	110.3	213.7	2012		2046
SUBTOTAL - Thermoelectric biomass plants (our share)	191	370	559	1,083
Wind farm plants
Atlântica I.	15.5	30.0	59.2	114.8	2014		2046
Atlântica II.	15.5	30.0	58.3	113.0	2014		2046
Atlântica IV	15.5	30.0	58.8	113.9	2014		2046
Atlântica V	15.5	30.0	61.9	120.0	2014		2046
Bons Ventos	25.8	50.0	74.0	143.4	2010		2033
Campo dos Ventos II	15.5	30.0	67.8	131.4	2013		2046
Canoa Quebrada..	29.4	57.0	108.8	210.9	2010		2032
Canoa Quebrada (Rosa dos Ventos)	5.4	10.5	1.7	3.3	2014		2032
Costa Branca	10.7	20.7	44.3	85.8	2014		2046
Enacel	16.3	31.5	46.2	89.6	2010		2032
Eurus I	15.5	30.0	70.1	135.8	2014		2046
Eurus III	15.5	30.0	72.8	141.0	2014		2046
Eurus VI.	4.1	8.0	14.3	27.7	2011		2045
Foz do Rio Choró	13.0	25.2	33.3	64.6	2009		2032
Icaraizinho	28.2	54.6	99.8	193.4	2009		2032
Juremas	8.3	16.1	34.4	66.6	2014		2046
Lagoa do Mato	1.7	3.2	0.7	1.4	2014		2032
Macacos	10.7	20.7	44.3	85.8	2014		2046
Morro dos Ventos I.	14.9	28.8	61.1	118.3	2014		2045
Morro dos Ventos III	14.9	28.8	62.9	121.8	2014		2045
Morro dos Ventos IV	14.9	28.8	61.9	120.0	2014		2045
Morro dos Ventos VI	14.9	28.8	59.2	114.8	2014		2045
Morro dos Ventos IX	14.9	28.8	64.7	125.3	2014		2045
Paracuru..	13.0	25.2	56.9	110.2	2008		2032
Pedra Preta	10.7	20.7	46.6	90.2	2014		2046
Praia Formosa	54.2	105.0	130.4	252.6	2009		2032
Santa Clara I	15.5	30.0	62.0	120.1	2011		2045
Santa Clara II	15.5	30.0	57.7	111.8	2011		2045
Santa Clara III	15.5	30.0	56.6	109.6	2011		2045
Santa Clara IV	15.5	30.0	55.6	107.8	2011		2045
Santa Clara V	15.5	30.0	56.1	108.7	2011		2045
Santa Clara VI	15.5	30.0	55.6	107.7	2011		2045
Taiba..	8.5	16.5	30.3	58.8	2008		2032
SUBTOTAL - Wind farms (our share)	516	999	1,868	3,620
Solar power plant
Tanquinho	0.6	1.1	1.0	1.7	2012		-
SUBTOTAL – Solar power plant (our share)	1	1	1	2
TOTAL (our share only)	914	1,769	3,460	6,704

(1) Inactive power plants.

(2) Hydroelectric projects with an installed capacity equal to or less than 1,000 kW that have a concession contract. The legislation for SHPP with an installed capacity is less than 1.000 kW has changed and currently a Registration is required. The concession contracts are valid until the concession expires.

(3) 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.

(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.

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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 in renewable generation.  CPFL Renováveis is constructing the Mata Velha SHPP and the São Benedito, Campo dos Ventos, Pedra Cheirosa and Morro dos Ventos II Wind Farms, which are expected to have an aggregate Installed Capacity of 335 MW (of which our consolidated share will be 173 MW, after accounting for the decrease in our stake in  as a result of the merger with DESA in October 2014).  We expect that the total generating capacity from these facilities will become fully operational by the end of 2018.

The following table sets forth information regarding these renewable generation construction projects:

Plants under development	Estimated Installed Capacity	Estimated Assured Energy	Start of Construction	Expected Start of Operations	Our Ownership	Estimated Installed Capacity Available	Estimated Assured Energy Available to us
	(MW)	(GWh/yr)			(%)		(GWh/yr)
São Benedito and Campo dos Ventos Complexes (9 companies)(1)	231	1,059	2015	2016	51.61	119	547
Pedra Cheirosa Complex (2 companies)(2)	51	229	2016	2018	51.61	26	118
Morro dos Ventos II Wind Farm (1 company)	29	134	2013	2016	51.61	15	69
Mata Velha Small Hydro Power Plant (1 company)	24	115	2013	2016	51.61	12	59
TOTAL	335	1,537				173	793

(1) Ventos de São Benedito, Ventos de Santo Dimas, Santa Mônica, Santa Úrsula, São Domingos, Ventos de São Martinho,Campo dos Ventos I, III, and V; and

(2) Pedra Cheirosa I and II.

São Benedito and Campo dos Ventos Complexes.  The São Benedito and Campo dos Ventos Complexes are located in the state of Rio Grande do Norte. The São Benedito Complex consists of the Ventos de São Benedito, Ventos de Santo Dimas, Santa Mônica, São Domingos, Ventos do São Martinho and Santa Úrsula Wind Farms.The São Domingos and Ventos de São Martinho Wind Farms, previously part of the Campo dos Ventos Complex, were allocated to the São Benedito Complex in order to increase synergies.The Campo dos Ventos Complex consists of Campo dos Ventos I, III and V Wind Farms. Together, they are expected to have an aggregate Installed Capacity of 231 MW and aggregate Assured Energy of 1,059.1 GWh/year.  Operations are scheduled to enter in gradual operation in the second half of 2016.  This project has a PPA in force until 2034 for São Benedito Complex and 2033 for Campo dos Ventos Complex, respectively.

Pedra Cheirosa. The Pedra Cheirosa Complex is located in the state of Ceara.  The Pedra Cheirosa Complex is comprised of the Pedra Cheirosa I and Pedra Cheirosa II Wind Farms, which will have an aggregate Installed Capacity of 51.3 MW and aggregate Assured Energy of 228.6 GWh/year.  The contracts arising from this trade shall be executed with the electric energy distributors that stated themselves to be energy buyers at that auction.  The duration of these contracts shall be 20 years, and the start of energy supply shall take place on January 1, 2018.  The batches were sold at the average price of R$125.04 per MWh, with annual adjustments by the IPCA.

Morro dos Ventos II Wind Farm. The Morro dos Ventos II Wind Farm islocated in the state of Rio Grande do Norte. Its operations are scheduled to begin in the first half of 2016.  Morro dos Ventos II will have an aggregate Installed Capacity of 28.8 MW and aggregate Assured Energy of 134 GWh/year.  The energy was sold through an A-5 auction held in December 2011.

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Mata Velha SHPP.  Mata Velha SHPP is located in the state of Minas Gerais. Mata Velha SHPP is expected to enter into operation in the first quarter of 2016. It will have an aggregate Installed Capacity of 24.0 MW and an aggregate Assured Energy of 114.8 GWh/year.  The energy was sold through an A-5 auction held in 2013.  Prior to construction, a bilateral contract (Free Market) was entered into for the period between 2016 and 2018, when the term of the 2013 New Energy Auction (LEN) begins.

Electricity Commercialization, Services and Other

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 agency services to Free Consumers and Power Generators before the CCEE and other agents, such as guidance on their operational requirements.

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 by ANEEL regulations.  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.

Services

Through CPFL Serviços, CPFL Atende, CPFL Total, CPFL Esco and Nect, we offer our consumers a wide range of electricity‑related services.  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:

·Transmission networks: CPFL Serviços plans, constructs, commissions and provides electricity to substations and transmission lines in consideration of each consumer’s needs and growth expectations and in accordance with rigorous safety criteria, aiming for an optimal use of resources.

·Distribution networks:CPFL Serviços plans and constructs electric energy distribution system networks, including above and underground electricity grids, medium‑voltage substations and transformers, industrial plants and lighting solutions.  It has significant experience in the market and familiarity with the various technical standards applicable in different regions of Brazil.  As a result, it is able to bring quality and technologically‑advanced energy solutions.

·Electric network maintenance:CPFL Serviçosoffers maintenance services on medium and high‑voltage networks on a one‑time or periodic basis with rapid diagnosis and precise service.  It also performs renovations of substations, maintenance services for generating units and work on live‑wire networks.

·Self‑production networks and energy-efficiency programs:The self‑production networks, formerly offered by CPFL Serviços, consist of electric energy production alternatives.  They ensure supply of energy to consumers, diversify inputs and reduce costs.  It offers diesel and natural gas generators that operate only in peak periods, which reduce our customers’ electricity costs.  Its natural gasco‑generation activities include the simultaneous and sequential production of electric and thermoelectric energy using a single fuel type.  It also offers solutions in acclimatization and energy‑efficiency projects as well as distributed generation of solar energy.  After October 2014, all self-production activities were transferred to CPFL ESCO.

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·Equipment recovery:CPFL Serviços has experience in refurbishing electric assets in order to restore their efficiency.  Its familiarity with refurbishing equipment also allows it to produce distribution and high‑power transformers.  In addition, it self‑produces and fabricates measurement panels as well as panels for protection and command networks.

·CPFL Atende:CPFL Atende is a contact center and customer relationship company, created to provide services both for companies within our group and for other companies.  Among these services are face‑to‑face service, back office services, credit recovery, toll free customer support, ombudsman services, service desks and sales.

·CPFL Total:CPFL Total is a collections and onlending company that offers bill payment services for water, electric power, telephone, bank and cable television bills.  CPFL Total is also equipped to issue back copies of electric power bills, change billing preferences and top up prepaid cellphone cards.  CPFL Total also provides the “Serviço em Conta”, which enables us to charge business customers for additional products and services through their electricity bills.

·Nect:Nect is a company created to provide administrative services such as human resources, materials purchasing and logistics, maintenance and operation of IT systems and administrative infrastructure for the companies within our group.  Nect aims to standardize processes and achieve productivity gains.

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 and our concession agreements provide that all of our distribution and hydroelectric concessions or authorizations 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 or hydropower exploitation 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.  The Brazilian government 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.  Furthermore, there can be no assurance as to whether the renewal of a certain concession will be granted on the same grounds as the current relevant concession.

Our Concessions and Authorizations

Hydroelectric generation projects with a capacity greater than 3,000 kW can usually only be implemented through concessions granted by ANEEL by means of 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 foster the public interest.

For further information about concessions and authorizations, see “—Concessions, Permissions and Authorizations—Concessions”.

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Concessions

We operate under concessions granted by the Brazilian government through ANEEL for our generation, transmission and distribution businesses.  We have the following concessions with respect to our distribution and transmission 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)
003/2013	CPFL Transmissão	São Paulo	30 years from February 2013
006/2015	CPFL Morro Agudo	São Paulo	30 years from March 2015

In connection with our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista, Law No. 12,783/13 of 2013 provided that existing distribution concessions such as these could be renewed, subject to certain conditions, for a further term of up to 30 years.  Accordingly, in 2014 we applied for renewal of these concessions in time for the renewal date of July 2015.  On March 31, 2015, however, before we had received a response from the authorities to these requests for renewal, it was reported that a federal court in Brasília issued a decision in a case commenced by the Brazilian public prosecutor against ANEEL and the Brazilian federal government stating that distribution concessions, particularly those that have already been renewed in the past, may not be automatically renewed without certain requirements being met.  Since we are not a party to this litigation, and we understand it may be subject to appeal, we are currently unable to predict its effect on our requests for renewal of these concessions.  See “Item 3.  Risk Factors—We are uncertain as to the renewal of our concessions and authorizations.”

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

Conventional generation

	Concession no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Hydroelectric plants
	Decree No. 85,983/81	CPFL Geração	Serra da Mesa	Goiás	(1)	20 years
	008/2001	CERAN	14 de Julho, Castro Alves and Monte Claro	Rio Grande do Sul	35 years from March 2001	At the discretion of ANEEL
	036/2001	Barra Grande	Barra Grande	Rio Grande do Sul	35 years from May 2001	At the discretion of ANEEL
	043/2000	ENERCAN	Campos Novos	Santa Catarina	35 years from May 2000	At the discretion of ANEEL
	005/1997	Investco	Luiz Eduardo Magalhães	Tocantins	35 years from December 1997	At the discretion of ANEEL
	128/2001	Foz do Chapecó	Foz do Chapecó	Santa Catarina and Rio Grande do Sul	35 years from November 2001	At the discretion of ANEEL
Thermoelectric plants
	015/1997	CPFL Geração	UTE Carioba	São Paulo	30 years from November 1997	30 years
Small Hydroelectric Plants
	015/1997	CPFL Geração	Cariobinha (Small Hydroelectric Power Plant)	São Paulo	30 years from November 1997	30 years
	(3)	CPFL Centrais Geradoras(4)	Lavrinha (Micro Hydroelectric Power Plant)	São Paulo	(3)	‑
	009/1999	CPFL Centrais Geradoras(4)	Macaco Branco (Small Hydroelectric Power Plant)	São Paulo	30 years (from December 2012)	(2)
	(3)	CPFL Centrais Geradoras(4)	Pinheirinho (Micro Hydroelectric Power Plant)	São Paulo	(3)	‑
	010/1999	CPFL Centrais Geradoras(4)	Rio do Peixe I and II (Small Hydroelectric Power Plants)	São Paulo	30 years (from December 2012)	(2)
	(3)	CPFL Centrais Geradoras(4)	Santa Alice (Micro Hydroelectric Power Plant)	São Paulo	(3)	‑
	(3)	CPFL Centrais Geradoras(4)	São José (Micro Hydroelectric Power Plant)	São Paulo	(3)	‑
	(3)	CPFL Centrais Geradoras(4)	São Sebastião (Micro Hydroelectric Power Plant)	São Paulo	(3)	‑
	(3)	CPFL Centrais Geradoras(4)	Turvinho (Micro Hydroelectric Power Plant)	São Paulo	(3)	‑

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Renewable generation

	Concession no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Small Hydroelectric Plants
	003/2011	CPFL Renováveis	Americana	São Paulo	up to November 2027	20 years
	Dispatch No. 1990	CPFL Renováveis	Andorinhas	Rio Grande do Sul	(3)	(3)
	002/2011	CPFL Renováveis	Buritis	São Paulo	up to November 2027	20 years
	002/2011	CPFL Renováveis	Capão Preto	São Paulo	up to November 2027	20 years
	002/2011	CPFL Renováveis	Chibarro	São Paulo	up to November 2027	20 years
	Resolution No. 475	CPFL Renováveis	Diamante	Mato Grosso	up to November 2027	30 years
	002/2011	CPFL Renováveis	Dourados	São Paulo	up to November 2027	20 years
	004/2011	CPFL Renováveis	Eloy Chaves	São Paulo	up to November 2027	20 years
	002/2011	CPFL Renováveis	Esmeril	São Paulo	up to November 2027	20 years
	002/2011	CPFL Renováveis	Gavião Peixoto	São Paulo	up to November 2027	20 years
	Resolution No. 1,987/2005	CPFL Renováveis	Guaporé	Rio Grande do Sul	(3)	(3)
	004/2011	CPFL Renováveis	Jaguari	São Paulo	up to November 2027	20 years
	002/2011	CPFL Renováveis	Lençóis	São Paulo	up to November 2027	20 years
	004/2011	CPFL Renováveis	Monjolinho	São Paulo	up to November 2027	20 years
	004/2011	CPFL Renováveis	Pinhal	São Paulo	up to November 2027	20 years
	Dispatch No. 1989	CPFL Renováveis	Pirapó	Rio Grande do Sul	(3)	(3)
	Dispatch No. 1988	CPFL Renováveis	Saltinho	Rio Grande do Sul	(3)	(3)
	003/2011	CPFL Renováveis	Salto Grande	São Paulo	up to November 2027	20 years
	002/2011	CPFL Renováveis	São Joaquim	São Paulo	up to November 2027	20 years
	004/2011	CPFL Renováveis	Socorro	São Paulo	up to November 2027	20 years
	003/2011	CPFL Renováveis	Santana	São Paulo	up to November 2027	20 years
	003//2011	CPFL Renováveis	Três Saltos	São Paulo	up to November 2027	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 it was recently extended to November 12, 2039.  On April 27, 2012, the MME published Ordinance No. 262, which approved the renewal of the concession for Serra da Mesa.

(2) Hydroelectric projects with an Installed Capacity higher than 1,000 kW that were granted through a concession process with the regulatory authority and the administrator of power concessions.

(3) 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.

(4) CPFL Centrais Geradoras: as described previously on “Overview”, a subsidiary created to consolidate the generation activities of the (i) renewed and unbundled generation concessions – Small Hydroelectric Power Plant (Macaco Branco and Rio do Peixe I and II) and (ii) unbundled generation concessions – Micro Hydroelectric Power Plant (Santa Alice, Lavrinha, São José, Turvinho, Pinheirinho and São Sebastião).

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Authorizations

Conventional generation

	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Thermoelectric plants
	2277	EPASA	Termoparaíba Thermoelectric Power Plant	Paraíba	35 years from December 7, 2007	At the discretion of MME
	2277	EPASA	Termonordeste Thermoelectric Power Plant	Paraíba	35 years from December 12, 2007	At the discretion of MME

Renewable generation

	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Small Hydroelectric plants
	Resolution No.357	SPE Aiuruoca Energia S.A.	Aiuruoca(*)	Minas Gerais	30 years from December 23, 1999	At the discretion of the granting authority
	Resolution No.  587	SPE Alto Irani Energia S.A.	Alto Irani	Santa Catarina	30 years from October 30, 2002	At the discretion of the granting authority
	Resolution No. 606	SPE Arvoredo Energia S.A.	Arvoredo	Santa Catarina	30 years from November 7, 2002	At the discretion of the granting authority
	Resolution No.  348	SPE Barra da Paciência Energia S.A.	Barra da Paciência	Minas Gerais	30 years from December 20, 1999	At the discretion of the granting authority
	Resolution No. 425	Bonanza Energética S.A.	Bonanza	Paraná	30 years from January 30, 2006	At the discretion of the granting authority

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	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
	Resolution No.540	SPE Cachoeira Grande Energia S.A.	Cachoeira Grande(*)	Minas Gerais	30 years from October 15, 2003	At the discretion of the granting authority
	Resolution No.  349	SPE Cocais Grande Energia S.A.	Cocais Grande	Minas Gerais	30 years from December 23, 1999	At the discretion of the granting authority
	Resolution No.  17	SPE Corrente Grande Energia S.A.	Corrente Grande	Minas Gerais	30 years from January 17, 2000	At the discretion of the granting authority
	Resolution No. 198	Figueirópolis Energética S.A.	Figueirópolis	Mato Grosso	30 years from May 04, 2004	At the discretion of the granting authority
	Resolution No. 440	Laranjinha Energética S.A.	Laranjinha	Paraná	30 years from February 06, 2006	At the discretion of the granting authority
	Resolution No. 705	Ludesa Energética S.A.	Ludesa	Santa Catarina	30 years from december 17, 2002	At the discretion of the granting authority
	Resolution No. 262	Mata Velha Energética S.A.	Mata Velha	Minas Gerais	30 years from May 16, 2002	At the discretion of the granting authority
	Resolution No.  370	SPE Ninho da Águia Energia S.A.	Ninho da Águia	Minas Gerais	30 years from December 30, 1999	At the discretion of the granting authority
	Resolution No. 652	Novo Horizonte Energética S.A.	Novo Horizonte	Paraná	30 years from november 26, 2002	At the discretion of the granting authority
	Resolution No.  406	SPE Paiol Energia S.A.	Paiol	Minas Gerais	30 years from August 07, 2002	At the discretion of the granting authority
	Resolution No.  607	SPE Plano Alto Energia S.A.	Plano Alto	Santa Catarina	30 years from November 7, 2002	At the discretion of the granting authority
	Resolution No. 2510	SPE Salto Góes Energia S.A.	Salto Góes	Santa Catarina	30 years from August 19, 2010	At the discretion of the granting authority
	Resolution No.718	SPE Santa Cruz Energia S.A	Santa Cruz(*)	Minas Gerais	30 years from December 18, 2002	At the discretion of the granting authority
	Resolution No.  13	SPE São Gonçalo Energia S.A.	São Gonçalo	Minas Gerais	30 years from January 14, 2000	At the discretion of the granting authority
	Ordinance No. 352	SPE Santa Luzia Energética S.A.	Santa Luzia	Santa Catarina	35 years from December 21, 2007	At the discretion of the granting authority
	Resolution No.  355	SPE Varginha Energia S.A.	Varginha	Minas Gerais	30 years from December 23, 1999	At the discretion of the granting authority
	Resolution No.  367	SPE Várzea Alegre Energia S.A.	Várzea Alegre	Minas Gerais	30 years from December 30, 1999	At the discretion of the granting authority
Thermoelectric biomass plants
	2106	CPFL Bioenergia	Baldin Thermoelectric Power Plant	São Paulo	30 years from September 24, 2009	At the discretion of the granting authority
	Resolution No. 3714	SPE Alvorada S.A.	Alvorada Thermoelectric Power Plant	Minas Gerais	30 years from October 29, 2012	At the discretion of the granting authority
	Resolution No. 2643	CPFL Bio Buriti S.A.	Buriti Thermoelectric Power Plant	São Paulo	30 years from December 16, 2010	At the discretion of the granting authority
	Resolution No. 3328	SPE Coopcana S.A.	Coopcana Thermoelectric Power Plant	Paraná	30 years from February 14, 2012	At the discretion of the granting authority

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	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
	Resolution No.117	Lacenas Participações Ltda.	Ester Thermoelectric Power Plant	São Paulo	30 years from May 21, 1999	At the discretion of the granting authority
	Resolution No. 259	CPFL Bio Formosa S.A.	Baía Formosa Thermoelectric Power Plant	Rio Grande do Norte	30 years from May 15, 2002	At the discretion of the granting authority
	Resolution No. 2375	CPFL Bio Ipê S.A.	Ipê Thermoelectric Power Plant	São Paulo	30 years from May 3, 2010	At the discretion of the granting authority
	Ordinance No. 129	CPFL Bio Pedra S.A.	Pedra Thermoelectric Power Plant	São Paulo	35 years from February 28, 2011	At the discretion of the granting authority
Wind farm plants
	Ordinance No. 134	Atlântica I Parque Eólico S.A.	Atlântica I	Rio Grande do Sul	35 years from February 28, 2011	At the discretion of the granting authority
	Ordinance No. 148	Atlântica II Parque Eólico S.A.	Atlântica II	Rio Grande do Sul	35 years from March 04, 2011	At the discretion of the granting authority
	Ordinance No. 147	Atlântica IV Parque Eólico S.A.	Atlântica IV	Rio Grande do Sul	35 years from March 04, 2011	At the discretion of the granting authority
	Ordinance No. 168	Atlântica V Parque Eólico S.A.	Atlântica V	Rio Grande do Sul	35 years from March 22, 2011	At the discretion of the granting authority
	Resolution No. 093	Bons Ventos Geradora de Energia S.A.	Bons Ventos	Ceará	30 years from March 10, 2003	At the discretion of the granting authority
	Ordinance No. 257	Campo dos Ventos II Energias Renováveis S.A.	Campo dos Ventos II	Rio Grande do Norte	35 years from April 18, 2011	At the discretion of the granting authority
	Resolution No.3967	Campo dos Ventos I Energias Renováveis S.A.	Campo dos Ventos I	Rio Grande do Norte	30 years from March 26, 2013	At the discretion of the granting authority
	Resolution No.3968	Campo dos Ventos III Energias Renováveis S.A.	Campo dos Ventos III	Rio Grande do Norte	30 years from March 26, 2013	At the discretion of the granting authority
	Resolution No.3969	Campo dos Ventos V Energias Renováveis S.A.	Campo dos Ventos V	Rio Grande do Norte	30 years from March 26, 2013	At the discretion of the granting authority
	Resolution No. 680	Bons Ventos Geradora de Energia S.A.	Canoa Quebrada	Ceará	30 years from December 11, 2002	At the discretion of the granting authority
	Resolution No. 329	Rosa dos Ventos Geração e Comercialização de Energia S.A.	Canoa Quebrada	Ceará	30 years from June 19, 2002	At the discretion of the granting authority
	Ordinance No. 585	SPE Costa Branca Energia S.A.	Costa Branca	Rio Grande do Norte	35 years from October 14, 2011	At the discretion of the granting authority
	Resolution No. 625	Bons Ventos Geradora de Energia S.A.	Enacel	Ceará	30 years from November 13, 2002	At the discretion of the granting authority
	Ordinance No. 264	Desa Eurus I S.A.	Eurus I	Rio Grande do Norte	35 years from April 19, 2011	At the discretion of the granting authority
	Ordinance No. 266	Desa Eurus III S.A.	Eurus III	Rio Grande do Norte	35 years from April 27, 2011	At the discretion of the granting authority
	Ordinance No. 749	Eurus VI Energias Renováveis Ltda.	Eurus VI	Rio Grande do Norte	35 years from August 25, 2010	At the discretion of the granting authority
	Resolution No. 306	SIIF Cinco Geração e Comercialização de Energia S.A.	Foz de Choró	Ceará	30 years from June  05, 2002	At the discretion of the granting authority

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Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Resolution No. 454	Eólica Icaraizinho Geração e Comercialização de Energia S.A.	Icaraizinho	Ceará	30 years from August 28, 2002	At the discretion of the granting authority
Ordinance No. 556	SPE Juremas Energia S.A.	Juremas	Rio Grande do Norte	35 years from September 29, 2011	At the discretion of the granting authority
Resolution No. 340	Rosa dos Ventos Geração e Comercialização de Energia S.A.	Lagoa do Mato	Ceará	30 years from June 26, 2002	At the discretion of the granting authority
Ordinance No. 557	Macacos Energia S.A.	Macacos	Rio Grande do Norte	35 years from September 29, 2011	At the discretion of the granting authority
Ordinance No. 664	Desa Morro dos Ventos I S.A.	Morro dos Ventos I	Rio Grande do Norte	35 years from July 27, 2010	At the discretion of the granting authority
Ordinance No. 373	Desa Morro dos Ventos II S.A.	Morro dos Ventos II	Rio Grande do Norte	35 years from June 12, 2012	At the discretion of the granting authority
Ordinance No. 685	Desa Morro dos Ventos III S.A.	Morro dos Ventos III	Rio Grande do Norte	35 years from August 04, 2010	At the discretion of the granting authority
Ordinance No. 686	Desa Morro dos Ventos IV S.A.	Morro dos Ventos IV	Rio Grande do Norte	35 years from August 04, 2010	At the discretion of the granting authority
Ordinance No. 663	Desa Morro dos Ventos VI S.A.	Morro dos Ventos VI	Rio Grande do Norte	35 years from July 27, 2010	At the discretion of the granting authority
Ordinance No. 665	Desa Morro dos Ventos IX S.A.	Morro dos Ventos IX	Rio Grande do Norte	35 years from July 27, 2010	At the discretion of the granting authority
Resolution No. 460	Eólica Paracuru Geração e Comercialização de Energia S.A.	Paracuru	Ceará	30 years from August 28, 2002	At the discretion of the granting authority
Ordinance No. 584	Pedra Preta Energia S.A.	Pedra Preta	Rio Grande do Norte	35 years from October 14, 2011	At the discretion of the granting authority
Resolution No. 307	Eólica Formosa Geração e Comercialização de Energia S.A.	Praia Formosa	Ceará	30 years from June  05, 2002	At the discretion of the granting authority
Ordinance No. 609	Santa Clara I Energia Renováveis Ltda.	Santa Clara I	Rio Grande do Norte	35 years from July 02, 2010	At the discretion of the granting authority
Ordinance No. 683	Santa Clara II Energia Renováveis Ltda.	Santa Clara II	Rio Grande do Norte	35 years from August 05, 2010	At the discretion of the granting authority
Ordinance No. 610	Santa Clara III Energia Renováveis Ltda.	Santa Clara III	Rio Grande do Norte	35 years from July 02, 2010	At the discretion of the granting authority
Ordinance No. 672	Santa Clara IV Energia Renováveis Ltda.	Santa Clara IV	Rio Grande do Norte	35 years from July 30, 2010	At the discretion of the granting authority
Ordinance No. 838	Santa Clara V Energia Renováveis Ltda.	Santa Clara V	Rio Grande do Norte	35 years from October 11, 2010	At the discretion of the granting authority
Ordinance No. 670	Santa Clara VI Energia Renováveis Ltda.	Santa Clara VI	Rio Grande do Norte	35 years from July 30, 2010	At the discretion of the granting authority
Resolution No. 4592	Santa Mônica Energias Renovaveis Ltda.	Santa Mônica	Rio Grande do Norte	30 years from April 01, 2014	At the discretion of the granting authority

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	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
	Resolution No. 4591	Santa Ursula Energias Renovaveis Ltda.	Santa Úrsula	Rio Grande do Norte	30 years from March 31, 2014	At the discretion of the granting authority
	Resolution No. 778	Bons Ventos Geradora de Energia S.A.	Taíba Albatroz	Ceará	30 years from December 24, 2002	At the discretion of the granting authority
	Resolution No. 4563	São Benedito Energias Renovaveis Ltda.	Ventos de São Benedito	Rio Grande do Norte	30 years from March 07, 2014	At the discretion of the granting authority
	Resolution No. 4562	Ventos de Santo Dimas Energias Renovaveis Ltda.	Ventos de Santo Dimas	Rio Grande do Norte	30 years from March 07, 2014	At the discretion of the granting authority
	Resolution No. 4572	Ventos de São Martinho Energias Renovaveis Ltda.	Ventos de São Martinho	Rio Grande do Norte	30 years from March 21, 2014	At the discretion of the granting authority
Solar power plants
	Of.ANEEL No. 961/2012	SPE CPFL Solar 1 Energia S.A.	Tanquinho	São Paulo	Undetermined(**)	Undetermined(**)

(*)   Project in planning phase.

(**) Power plant with reduced capacity, exempted from granting authority, requiring only registration with the granting authority (ANEEL).

Independent Power Producers

A generation company classified as an Independent Power 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 Power 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.

Concessionaires

A company classified as a concessionaire under Brazilian law receives a concession to distribute, transmit and/or generate electric energy.  Since concessions usually involve public services or assets, they can only be granted through a public bidding procedure (licitação pública).  Most of the tariffs charged by concessionaires of public services are determined by ANEEL.  Concessionaires are not free to negotiate these rates with consumers, except for (i) generation concessionaires, which are free to establish these rates, as long as their concessions have not been extended pursuant to Law No. 12,783/13, in which case ANEEL determines the tariff that must be applied and (ii) distribution concessionaires that may grant discounts to consumers (as long as equal treatment is granted to other consumers within the same category).

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 up to 35 years, renewable once for a maximum period of 20 years, according to Law No. 9,074/95 or for a maximum period of up to 30 years, if the concession period extension is subject to Law No. 12,783/13.

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 foster 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.  The net book value of our total property, plant and equipment as of December 31, 2014 was R$8,878 million.  No single one of our properties produces morethan 10.0% of our total revenues.  Our facilities are generally adequate for our present needs and suitable for their intended purposes.

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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, transmission and generation facilities are subject to environmental licensing procedures, which include the preparation of environmental impact assessments before such facilities are constructed and the implementation of programs to reduce environmental impacts during the construction and operation of the facilities.  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 specifically 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 ensure environmental compliance and future electricity generation.  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.

In order to ensure 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

According to the ANEEL, as of December 31, 2014, the Installed Capacity of power generation in Brazil was 133,985 MW.  Historically, approximately 67% of the total Installed Capacity in Brazil has derived from Hydroelectric Power Plants.  Large Hydroelectric Power Plants tend to be far from the consumption centers.  This requires construction of large transmission lines at high and extra‑high voltage (230 kV to 750 kV) that often cross the territory of several states.  Brazil has a robust electric grid system, with more than 125,000 km of transmission lines with voltage equal to or greater than 230 kV and processing capacity of over 301,000 MVA from the state of Rio Grande do Sul through the the state of Amazonas.

According to the EPE, electricity consumption in Brazil grew by 2.2% in 2014, reaching 473,395 GWh. The MME and the EPE estimate that electricity consumption will grow by 4% per year until 2023.  According to the ten-year expansion plan published by the MME and the EPE, Brazil’s Installed Capacity is expected to reach 195.9GW by 2023, of which 116.9 GW (59.7%) is projected to be hydroelectric, 31.8 GW (16.2%) is projected to be thermoelectric and nuclear and 47.2 GW (24.1%) is projected to be from other renewable sources.

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Currently, approximately 34% of the Installed Capacity in Brazil is owned by Eletrobras, a joint capital and publicly traded company controlled by the Brazilian government.  We are the second largest private player within the electricity generation sector, with 2.3% of the market share. 

The Distribution segment in Brazil remains fragmented, with six companies controlling approximately 50% of the market.  We are the largest player, with 13% of the electricity distribution market.

Principal Regulatory Authorities

Ministry of Mines and Energy — MME

The MME is the Brazilian government’s primary authority in the power industry.  Following the adoption of the New Industry Model Law in 2004, 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 tender process for concessions that relate to public services and public assets.

National Energy Policy Council — CNPE

The 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 eight government ministers, three members selected by the President of Brazil, another representative of the MME and the president of the EPE.  The CNPE was created to optimize the use of Brazil’s energy resources and to guarantee national energy supply.

Brazilian Electricity Regulatory Agency — ANEEL

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 tender 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 nonprofit organization that coordinates and controls the production and transmission of energy by electric utilities engaged in generation, transmission and distribution activities.  The primary role of the ONS is to oversee generation and transmission operations in the Interconnected Power System, subject to regulation and supervision by ANEEL.  Objectives and principal responsibilities of the ONS include: (i) operational planning for the generation industry; (ii) organizing the use of the domestic national grid and international interconnections; (iii) guaranteeing that all parties in the industry have access to the transmission network in a non‑discriminatory manner; (iv) assisting in the expansion of the electric energy system; (v) proposing plans to the MME for expansions of the Basic Network; and (vi) submitting rules for the operation of the transmission system for ANEEL’s approval.

Electric Energy Trading Chamber — CCEE

The CCEE is a nonprofit organization that is subject to authorization, inspection and regulation by ANEEL.  The CCEE replaced the Wholesale Energy Market.  The CCEE is responsible, among other things, for (i) registering all CCEARs and all 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 entities that hold concessions, permissions or authorizations 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.

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Energy Research Company — EPE

On August 16, 2004, the Brazilian government created the 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), or 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 and permissions are granted through proceedings or through public tender, whilst authorizations are granted through more simple administrative proceedings or through public auctions for power purchase and sale.

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 with respect to regularity, continuity, efficiency, safety and accessibility.

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 must compensate the affected private landowners.

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

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

Intervention by the granting authority.  Pursuant to Law No. 12,767 of December 27, 2012, as modified by Law No. 12,839 of July 2013, the granting authority may intervene in the concession, acting through ANEEL, 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, ANEEL 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 government appointed manager becomes responsible for carrying on the concession.  Theadministrative proceeding must be completed within one year (which may be extended for two more years).  In order for the intervention to cease and the concession to return to the concessionaire, the concessionaire’s shareholders are required to present a detailed recovery plan to ANEEL and correct the irregularities identified by ANEEL.

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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.  Additionally, on December 10, 2014, our distribution companies signed a concession contract amendment that guarantees, at the concession period termination, that the company will receive or pay the balance of the remaining amounts under billed Sector Assets or Liabilities.

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.

Renewal.  Law No. 12,783/13 of January 11, 2013 specified the conditions for the renewal of generation, transmission and distribution concessions obtained under articles 17, 19 or 22 of Law No. 9,074 of July 7, 1995.  Under Law No. 12,783/13, these concessions may be extended once, at the discretion of the Brazilian government, for up to 30 years, in order to ensure the continuity and efficiency of the services rendered and low tariffs.  In addition, Law No. 12,783/13 provided that holders of concessions that were due to expire in 2015, 2016 and 2017 could apply for early renewal in 2013, subject to certain conditions.  These conditions, in respect of distribution companies, have not yet been disclosed by the Brazilian government.  The renewal of generation concession is contingent on the satisfaction of the following conditions: (i) tariffs calculated by ANEEL for each hydroelectric plan; (ii) allocation of energy quotas to distribution companies in the National Interconnected System; and (iii) submission to the standards of service quality set by ANEEL.  For renewal, the assets remaining unamortized at the renewal date would be indemnified and the indemnification payment would not be considered to be annual revenue.  The remuneration relating to new assets or existing assets that were not indemnified would be considered annual revenue.  Resolution No. 521/12 published by ANEEL on December 14, 2012 also established that the generation concessions owned by a distribution company, to be renewed under Law No. 12,783/13, must be partitioned into separate operating entities where the Installed Capacity of the original concessionaire entity exceeded 1 MW.  Law No. 12,783/13 also extinguished two sector charges (the CCC and the RGR Fund (see “—Regulatory Charges—RGR Fund and UBP” and “—Regulatory Charges—CDE Account”)). 

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 severity of the breach (including warnings, fines and forfeiture).  For each breach, the fines can be up to 2.0% 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 concessionaire 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 the controlling interests in 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.

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Permissions

Permissionshave a very limited use withintheBrazilian electricity sector.  Permissions are granted to rural power generation cooperatives that supply power to their members and occasionally to consumers that are not part of the cooperative, inareas not regularlyservedbylargedistributors.  Permissions are not a material portion of the Brazilian power matrix.

Authorizations

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

In the power generation sector, Independent Power Producers and self‑generators hold an authorization as opposed to a concession.  Independent Power Producers 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 Independent Power Producer 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 behalf, and to their benefit, are subject to ANEEL’s supervision and 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 Independent Power Producer may sell part or all of its output to customers on its own account and at its own risk.  A self‑generator may, upon specific authorization by ANEEL, sell or trade any excess energy it is unable to consume.  Independent Power Producers and self‑generators are not granted monopoly rights and are not subject to price controls, with the exception of specific cases.  Independent Power Producers 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 Brazilian government has taken a number of measures to reform the Brazilian electric energy industry.  These culminated, on March 15, 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 the intention to (i) provide incentives to private and public entities to build and maintain generation capacity and (ii) assure the supply of electricity within Brazil at adequate tariffs through competitive public electricity auction processes.  The key features of the New Industry Model Law include:

·Creation of two “environments” for the trading of electricity, including: (i) the Regulated Market, a more stable market in terms of supply of electricity; and (ii) 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 than 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.

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The New Industry Model Law excludes Eletrobras 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 PPAs and the method of passing costs through to Final Consumers.  Under these regulations, all parties that purchase electricity must contract all of their electricity demand under the guidelines of the New Industry Model Law.  Parties that sell electricity must have “ballast” for their sales (i.e., the amount of energy sold in CCEE must be previously purchased under PPAs and/or generated by the seller’s own power plants).  Agents that do not comply with such requirements are subject to penalties imposed by ANEEL and CCEE.

Beginning in 2005, all electricity generation, distribution and transmission 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.

Environments 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.  Distribution companies may also purchase electricity outside the public auction 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; (iii) the Itaipu Power Plant; (iv) auctions administered by the distribution companies, if the market that they supply is no greater  than 500 GWh/year; and (v) Hydroelectric Power Plants whose concessions have been renewed by the government under Law No. 12,783/13 of 2013 (in this latter case, in “energy quotas” distributed among the distribution companies by the Brazilian government, at prices determined by MME/ANEEL).  The electricity generated by Itaipu continues to be sold by Eletrobras to the distribution concessionaires operating in the South/Southeast/Midwest Interconnected Power System, although no specific contract was entered into by these concessionaires.  The rates at which the electricity generated by Itaipu 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 electricity generated by Itaipu 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: (i) Energy Agreements (Contratos de Quantidade de Energia); and (ii) 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 is 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’srevenue is guaranteed and the distributors must bear the risk of a supply shortage.  Together, these agreements comprise the CCEARs.

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According to the New Industry Model Law, within certain limits (as explained below), electricity distribution entities are entitled to pass through to their respective consumers the cost of electricity they purchase through public auction as well as any taxes and industry charges.

With respect to the granting of new concessions, the regulations require bids for new Hydroelectric Power Plants to include, among other things, a minimum percentage of electricity to be supplied to the Regulated Market.

The Free Market

The Free Market covers transactions between generation concessionaires, Independent Power Producers, self‑generators, energy traders, importers of electric energy, Free Consumers and Special Consumers.  Independent Power Producers 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 can 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. However, generators generally sell their generation simultaneously, sharing the total amount of energy between the Regulated and Free Markets. It is possible to sell energy separately in one or more markets.

At December 31, 2014 we had a total of 1,649 Potentially Free Consumers.  Potentially Free Consumers accounted for approximately 12.7% of the net operating revenues of our Distribution segment, and approximately 9.0% of the total volume of electricity sold by our Distribution segment during 2014. 

Potentially Free Consumers will have to comply with an agreement with the local distributor to become Free Consumers.  If a Free Consumer opts for the free contracting environment, which it can only do by providing six months’ prior notice to the distribution company, it will only be able to return to the regulated environment upon five years’ prior notice to the regional distribution company, although the distribution company may choose to reduce this notice period.  The notice period is intended to ensure that, if necessary, the distributor may buy additional energy in the regulated environment without imposing extra costs on its captive market. At December 31, 2014, we supplied energy to 46 Free Consumers, which accounted for approximately 1.5% of our net operating revenues of our Distribution segment, and approximately 2.5% of the total volume of electricity sold by our Distribution segment during 2014.  In addition to Free Consumers, certain Special Consumers with capacity equal to or greater than 500 kW and lower than 3,000 kW may choose to purchase energy in the Free Market, subject to certain terms and conditions.  Special Consumers may only purchase energy from: (i) Small Hydroelectric Power Plants with capacity superior to 3,000 kW and equal or inferior to 30,000 kW; (ii) hydroelectric generators with capacity superior to 3,000 kW and equal or inferior to 50,000 kW; (iii) generators with capacity limited to 3,000 kW; and (iv) alternative energy generators (solar, wind and biomass enterprises) whose capacity supplied to the system does not exceed 50,000 kW.  State‑owned generators may sell electricity to Free Consumers; however, unlike private generators, they may only do so through an auction process.

Recent Developments in the Free Market

On August 2, 2012, the MME enacted Act No. 455, providing for new rules regarding the registration of PPAs in the Free Market.  Currently, PPAs must be registered in advance with the CCEE on a monthly basis, but the electricity volume contracted may be adjusted on anex post basis after the consumption has taken place.  Under Act No. 455, as of June 1, 2014, PPAs need to be registered with the CCEE in advance on a weekly basis, and theex post volume adjustment will be prohibited.  As a result, parties will have to state their expected consumption volumeex ante, except when they have specifically indicated to the CCEE that the PPA in question refers to effective consumption volume. However, the Brazilian Association of Electricity Traders (ABRACEEL) obtained an injunction against Act No. 455, preventing the implementation of theex ante contract registration rule to energy traders. The application of this Act in the CCEE has been suspended for all agents (Generators, Traders and Consumer), since it may not apply only to a specific group of agents.  The act applies only to the Free Market, not affecting distributors.

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These restrictions in the freedom of negotiation between sellers and buyers may have an impact on the cost of energy purchased in the Free Market, and may reduce the benefit to us of trading in the Free Market.

Auctions on the Regulated Market

Electricity auctions for new generation projects in process are held (i) 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”).  Auction bid announcements are prepared by ANEEL in compliance with guidelines established by the MME, which include a requirement to use the lowest energy price 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 of between one 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.

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) reduction, at the distribution company’s discretion, of up to 4.0% per year over the initial contracted amount from existing power generation, excluding the first year of supply, due to market deviations from estimated market projections, beginning two 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 20 auctions for new generation projects, 16 auctions specifically for existing power generation facilities, two auctions for alternative generation projects and six auctions for biomass and wind power generation, qualified as “reserve energy”.  No later than August 1 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 one 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 alternative 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.  Our CCEARs provide that the price will be adjusted annually in accordance with the IPCA.  However, we also use other indexes to adjust prices in our CCEARs, such as fuel prices.  Distributors grant financial guarantees (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.  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 105.5% of actual demand; (ii) limited pass‑through of costs forelectricity purchases in an “A‑3” auction, if the volume of the acquired electricity exceeds 2.0% of the demand for electricity; (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 if the purchase is higher than the minimum limit of 96%. 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), or PLD, and the Annual Reference Value.

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The PLD is used to valuate the energy traded in the spot market. It is calculated for each submarket and load level on a weekly basis and it is based on the marginal cost of operation. The maximum value of PLD is set at R$388.48, according to ANEEL’s Resolution 1,832/2014.  Before such Resolution, the maximum value of PLD was R$822.23 (Resolution No. 1,667/2013). Its value was reduced in order to decrease risks of exposed agents.

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; (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 subject to the same conditions and tariffs as those that apply 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 control or hold relevant equity interests 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 Federal Supreme Court.  In October 2007, the Brazilian Federal Supreme Court issued a decision regarding injunctions that had been requested in the matter, denying the injunctions by a majority of votes.  To date, the Brazilian Federal Supreme Court has not reached a final decision, and we do not know when such a decision may be reached.  While the Brazilian Federal Supreme Court is reviewing the New Industry Model Law, its provisions remain in effect.  Regardless of the Brazilian Federal 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 the Brazilian Federal Supreme Court deems all or a material portion of the New Industry Model Law to be unconstitutional, 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.

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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.  Under Resolution No. 378, ANEEL now submits potential antitrust violations in the electric energy sector for analysis by the Economic Law Department of the Ministry of Justice (Secretaria de Direito Econômico), or SDE.  ANEEL also has the power to monitor potential antitrust activity, either at its own discretion or upon request of the SDE, by identifying: (i) the relevant market; (ii) the influence of the parties involved in the exchange of energy on the submarkets where they 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)  distribution entities’ efficiency gains during the tariff review process.

In practical terms, ANEEL’s role is limited to supplying the SDE with technical information to support technical opinions by the SDE.  SDE, in turn, has regard to ANEEL’s comments and decisions, and may only disregard them if it demonstrates its reasons for doing so.

System Tariffs

ANEEL oversees tariff regulations that govern access to the distribution and transmission systems and establishes tariffs for use of these systems and energy consumption.  Different tariffs apply to different categories of consumers in accordance with how they connect to the system and purchase energy.  The tariffs are: (i) the TUSD; (ii) tariffs for the use of the transmission system, consisting of the Basic Network and its ancillary facilities, or TUST; and (iii) the TE.

TUSD

The TUSD is paid by generators and consumers for the use of the distribution system of the distribution concessionaire to which the relevant generator or consumer is connected.  The TUSD consists of three tariffs with distinct purposes:

·The TUSD Wire (TUSD Fio), which is set in R$/kW, divided into time segments according to the tariff category, is applied to the electricity demand contracted by the party connected to the system, and remunerates the distribution and transmission concessionaire for costs of operating, maintaining and upgrading the distribution system.  It also provides the distribution concessionaire with a legal margin. 

·The TUSD Charges (TUSD Encargos), which is set in R$/MWh, is applied to electricity consumption (in MWh) and contemplates certain regulatory charges applicable to the use of the local network, such as the Proinfa Program, theConta de Desenvolvimento Energético, or CDE Account, the Tax on the Supervision of Electrical Services, or TFSEE, the ONS and others.  These charges are set by regulatory authorities and linked to the quantity of energy carried by the system.

·The TUSD Loss (TUSD Perdas) compensates for technical losses of energy on the transmission and distribution systems, as well as non‑technical losses of energy on the distribution system.

TUST

The TUST is paid by distribution companies, generation companies and Free Consumers who connect directly to the Basic Network.  It applies to their use of the Basic Network 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 network 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 Consumers directly connected to the transmission network, sign contracts with the ONS and the transmission companies (represented by the ONS) entitling them to the use of the transmission network in return for the payment of certain tariffs. 

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TE

The TE is paid by Captive Consumers for energy consumption, based on the amount of electricity actually consumed.  It remunerates the cost of energy, certain regulatory charges related to the use of energy, transmission costs related to Itaipu, certain transmission system losses related to the Captive Consumer market, R&D charges and ANEEL Inspection Fee - TFSEE.

Basis of Calculation of Distribution Tariffs

ANEEL has the authority to adjust and review the above tariffs in response to changes in energy purchase costs and market conditions.  When calculating distribution tariffs, ANEEL divides the costs of distribution companies between (i) costs that are not under the control of the distributor, or Parcel A Costs, and (ii) costs that are under the control of the distributor, 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 mandatorily purchased from Itaipu and the generation companies renewed under Law 12,783/13;

·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 assets necessary to energy distribution activities;

·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.

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:

·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

·determining the “X factor”, which consists of three components:

opotential increases in productivity, based on costs as compared to market growth;

oservice quality; and

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oan operating expense target.

Increases in productivity and the operating expense target are determined at each periodic review.  The service quality component is determined at each annual adjustment following the third periodic revision cycle.

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 and X factor.

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 December 2011, ANEEL established the methodology and procedures applicable to further periodic revisions as of that year.  However, a new methodology, under discussion in Public Hearing 023/2014 is expected to be concluded in the first semester of 2015.  For information on the new methodology applicable to the fourth 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”.

From 2013, conjunctural issues, like full dispatch of thermal plants and involuntary exposure of distributors have generated extraordinary costs that exceeded the ability to pay of distributors. To cover the involuntary exposure of distributors, part of the energy costs was reimbursed by the CDE Account and by the ACR account.  The reimbursement by the CDE Account, created by Decree No. 7945/2013, and ACR account, created by Decree No. 8,221/2014, aims to cover all or part of the costs incurred by distribution utilities in the period from January 2013 to December 2014, due to (i) involuntary exposure in the spot market and (ii) thermoelectric dispatch regarding CCEAR. CCEE manages the ACR account, and hired credit with 13 banks to provide the necessary amount to cover the high energy costs.  From 2015, the total cost of CDE reimbursement and contracted loans will be amortized over five years and 24 months, respectively, through the collection of additional electricity tariff increases passed on to consumers by all distribution companies in proportion to their captive markets.  The CDE quotas defined by ANEEL in 2015 and passed through to consumers already consider those obligations.  Additionally, as those CDE and energy purchase costs remain high, ANEEL increased tariffs by means of an Extraordinary Tariff Review (RTE) to all distribution companies, under Resolution No. 1,858 of February 27, 2015.  The RTE aims to pass on to the consumers the forecasted costs from March 2015 to the following tariff review or adjustment of the distribution company.

In January 2015, the electricity sector began to implement a mechanism of monthly “tariff flags” under which consumer invoices may be subject to tariff additions on a monthly basis when energy supply costs reach certain levels, enabling consumers to adapt their usage to current energy costs.  Previously, the pass-through of energy costs to tariffs was set annually.  The tariff flag system was initially approved in 2011 and was tested during 2013 and 2014.  It consists of a green (normal), orange (heightened) or red (critical) tariff flag, determined by ANEEL on the basis of electricity generation conditions, pursuant to Decree 8,401 of February 4, 2015.  Revenues billed under the tariff flag system are collected by the distribution companies and paid into a Tariff Flag Resources Centralizing Account administered by the CCEE from which the revenues are repaid to distribution companies on the basis of their relative energy cost for the period.

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Due to the poor hydrological conditions that have been observed since 2013, red tariff flags have been applied since introduction of this system in January 2015.  Although this mechanism mitigates the cash flow mismatch in part, it may be insufficient to cover the thermoelectric energy supply costs, and distributors still bear the risk of cash flow mismatches in the short term. 

Government Incentives to the Energy Sector

In 2000, a federal decree created the Thermoelectric Priority Program (Programa Prioritário de Termeletricidade), or PPT, for purposes of diversifying the Brazilian energy matrix and decreasing its strong dependency on Hydroelectric Power Plants.  The incentives granted to the Thermoelectric Power Plants included in the PPT are: (i) guarantee 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, or BNDES.

In 2002, the Brazilian government established the Electric Energy Alternative Sources Incentive Program (Programa de Incentivo às Fontes Alternativas de Energia Elétrica), or Proinfa Program.  Under the Proinfa Program, Eletrobras purchased 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 was limited to a total contracted capacity of 3,299 MW.  The objective of this initiative was to reach a contracted capacity of up to 10% of the total annual electricity consumption in Brazil within 20 years from 2002.  The Proinfa Program charge is collected from Final Consumers on a monthly basis.  Although provided for in Law No. 10,438 of 2002, it is still uncertain whether the Brazilian government will regulate and implement the second phase of the Proinfa Program.

In order to create incentives for alternative generators, the Brazilian government has established that a reduction of not less than 50% applies to TUSD amounts owed by: (i) Small Hydroelectric Power Plants with capacity superior to 3,000 kW and equal or inferior to 30,000 kW; (ii) hydroelectric power plants with capacity equal or inferior to3,000 kW; and (iii) alternative energy generators (solar, wind power and biomass generators) with capacity up to 30,000 kW.  The reduction is applicable to the TUSD due by the generation entity and also by its consumer.  The amount of the TUSD reduction is reviewed and approved by ANEEL and reimbursed through CDE, by an on a monthly basis deposit made by Eletrobrás.

Regulatory Charges

EER

The Reserve Energy Charge (Encargo de Energia de Reserva), or 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 on a monthly basis from Final Consumers of the Interconnected Power System registered with CCEE.

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 1957, the Brazilian government created a reserve fund designed to provide funds for such compensation, known as the “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.  Law No. 12,431 of 2011 extended the imposition of this fee until 2035.  However, Law No. 12,783/13 of 2013 provides that, as of January 1, 2013, this charge is no longer levied on distribution companies, generation and transmission concessions which had the concession extended under that Law or new generation and transmission concessionaires.

Independent Power Producers that use hydropower sources must also pay a fee similar to the fee levied on public‑industry generation companies in connection with the RGR Fund.  Independent Power Producers are required to make contributions for using a public asset (Uso de Bem Público), or UBP, according to the rules set out in thepublic tender for the relevant concession.  Eletrobras received the UBP payments until December 31, 2002.  All charges related to the UBP since December 31, 2002 have been paid directly to the Brazilian government.

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CDE Account

In 2002, the Brazilian government instituted the Electric Energy Development Account, or 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 systems.  These fees are adjusted annually.  The CDE Account was originally 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.  In addition, the CDE Account subsidizes the operations of thermoelectric generation companies for the purchase of fuel in isolated areas not connected to the Interconnected Power System, which costs were supported by the CCC Account, before the enactment of Law No. 12,783/13.  As from January 23, 2013, (Decree No. 7,891/13), the CDE Account subsidizes discounts for certain categories of consumers, such as Special Consumers, rural consumers, distribution concessionaires and permissionaires, among others.  By Decree 7,945 dated March 7, 2013, the Brazilian government decided to use the CDE Account to subsidize: (i) a portion of the distribution companies’ energy costs on thermal generation in 2013; (ii) the hydrological risks of the generation concessions renewed under Law No. 12,783/13 in 2013; (iii) the involuntary energy under contract shortage because some generation concessions did not seek to renew their contracts and the energy produced by those concessions could not be reallocated to distributors; and (iv) part of the ESS and the CVA, such that the impact of tariff adjustments in connection with these two accounts was limited to 3% of adjustments from March 8, 2013 to March 7, 2014. The CDE Account will be in effect for 25 years from 2002.  It is regulated by ANEEL and managed by Eletrobras.

ESS

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

In 2013, due to adverse hydrological conditions, the ONS dispatched a number of Thermoelectric Power Plants, leading to increased costs.  These dispatches caused a significant increase in the ESS‑SE.  Since the ESS‑SE charge applies only to distribution companies (although it can subsequently be passed on by them to consumers) and to Free Consumers, the CNPE decided, through Resolution No. 03/2013, to spread the cost by extending the ESS‑SE charge to all players in the electrical energy industry.  This decision increased the cost base of our subsidiaries in businesses other than distribution (since they cannot pass on the cost to consumers), principally our Generation segment.  However, certain industry participants, including our generation subsidiaries, are contesting the validity of Resolution No. 03/2013 and have obtained a court injunction, which was confirmed by the Brazilian Federal Supreme Court, exempting them from the ESS‑SE.

Fee for the Use of Water

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 itself 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.

Default on the Payment of Regulatory Charges

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

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Energy Reallocation Mechanism

Centrally dispatched hydroelectric generators 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 hydroelectric generators share the hydrological risks of the Interconnected Power System.  Under Brazilian law, each Hydroelectric Power 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, who 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 4A.Unresolved Staff Comments

None.

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.   

Overview

We are a holding company and, through our subsidiaries, we: (i) distribute electricity to consumers in our concession areas; (ii) generate electricity from conventional and renewable sources and develop generation projects; (iii) engage in electricity commercialization; and (iv) offer electricity‑related services.  We have four broad initiatives to improve our financial performance: (i) the expansion of our generation Installed Capacity through greenfield and brownfield investments; (ii) the acquisition of additional distributors; (iii) the consolidation of our commercialization business; and (iv) the development of our service business.

Two very important drivers of our financial performance are our operating income margin and cash flows from our regulated distribution business.  In recent years, our regulated distribution business has produced reasonably stable margins, and its cash flows, while sometimes subject to short‑term variability, have been stable over the medium term.Nevertheless, there are factors beyond our control that can have a significant impact, positive or negative, on our financial performance.  We face periodic changes in our tariff structure, resulting from the periodic regulatory review of our tariffs.  In 2011, a new methodology was defined by ANEEL for the third cycle of periodic reviews and all of our distributors, who had their periodic reviews in 2011, 2012 and 2013, had a reduction in average tariffs.   The methodology to be applied in the 2015-2018 periodic revision cycle is currently subject to public consultation, which is  expected to be settled during the first half of 2015.  See “—Background—Periodic Revisions —RTP”.

In March 2012, through our subsidiary CPFL Renováveis, we purchased 100% of the shares of Atlântica I, Atlântica II, Atlântica IV and Atlântica V, companies engaged in generation of energy through wind sources, with an aggregate Installed Capacity of 120 MW.  The Atlântica Complex commenced operations in March 2014.

In October 2012, through our subsidiary CPFL Renováveis, we purchased 100% of the electric energy and water steam co‑generation assets of SPE Lacenas Participações Ltda., including its subsidiary, the Ester Thermoelectric Power Plant.  The Ester Thermoelectric Power Plant holds authorization from ANEEL to exploitelectric energy from biomass (sugar cane), with Installed Capacity of 40.0 MW.  These co‑generation plants, located in the city of Cosmópolis, in the State of São Paulo, are fully operational.

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In June 2012, through our subsidiary CPFL Renováveis, we purchased 100% of the shares of BVP, the holding company of Bons Ventos, which holds authorizations to exploit wind farms with an aggregate Installed Capacity of 157.5 MW.  The acquisition was completed on June 19, 2012.

In November 2012, Tanquinho started operations.  Tanquinho is the first solar power plant in the State of São Paulo and is located in the city of Campinas, with an Installed Capacity of 1.1 MWp. 

In August 2013, the CPFL Coopcana Thermoelectric Power Plant started operations, with Installed Capacity of 50 MW.  In September 2013, the Campo dos Ventos II Wind Farm with 30 MW of Installed Capacity started operations.  In November 2013, the CPFL Alvorada Biomass Thermoelectric Power Plant (“UTE Alvorada”) started operations, with Installed Capacity of 50 MW.

In December 2013, at the Second A‑5/2013 Energy Auction, CPFL Renováveis traded an average of 26.1 MW of contracted energy to be generated by the Pedra Cheirosa Complex, consisting of two wind farms in the state of Ceará with 51.3 MW of Installed Capacity.  An “A‑5” auction is an energy auction held five years before the initial delivery date.  The contracts arising from the trade will be executed with the distribution companies that participated in the auction as energy purchasers.  The contracts will have a duration of 20 years, with energy supply commencing January 1, 2018.  The traded energy was sold at an average price of R$125.04 per MWh, with annual adjustments to be made in accordance with IPCA

In February 2014, CPFL Renováveis acquired Rosa dos Ventos Wind Farms, with 14 MW of Installed Capacity.  In June 2014, the Macacos Complex (composed of the Macacos, Pedra Preta and Costa Branca Wind Farms), started operations with 78 MW of Installed Capacity.

In February 2014, CPFL Renováveis entered into an agreement with Arrow – Fundo de Investimento em Participações, or Arrow, an investment fund, to acquire Arrow’s indirect subsidiary DESA, through the issuance and exchange of 61,752,782 new common shares of CPFL Renováveis to Arrow on October 1, 2014.  As a result of this transaction, our interest in CPFL Renováveis was reduced from 58.84% to 51.61%. DESA has been operating with installed power of 278 MW and has renewable generation construction projects with Installed Capacity of 53 MW, whose operations are expected to start in 2016.  All references in this Annual Report to our total Installed Capacity and other operating information as at and for the year ended December 31, 2014 reflect the impact of this change in shareholding and consolidation.See note 15.6.2 to our audited annual consolidated financial statements.

We expect the Mata Velha SHPP and Campo dos Ventos, São Benedito, Morro dos Ventos II and the Pedra Cheirosa Wind Complexes to become operational until 2018. At such time, after accounting for the decrease in our stake in CPFL Renováveis as a result of the acquisition of DESA in October 2014, we expect that our Installed Capacity will increase to 3,336 MW.

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 Consumers at regulated tariffs.  In 2014, sales to Captive Consumers represented 69.8% of the volume of electricity we delivered and 67.3% of our operating revenues, compared to 68.6% and 66.7%, respectively, in 2013.  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”.

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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 “Item 4.  Information on the Company—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.

·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 any increase to Parcel B Costs passed on to all of our consumers.  ANEEL’s Resolution No. 457/2011 has established the methodology applicable to the third periodic revision cycle (2011 to 2014).  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.  The last extraordinary revisions took place on January 24, 2013 and February 27, 2014.  The 2013 event aimed to adjust our tariffs as a result of the changes introduced by Law No. 12,783/13.  Law No. 12,783/13 reduced the CDE Account charge and eliminated the CCC and RGR charges, therefore reducing the Parcel A Costs (energy prices, charges for the use of the Basic Network and regulatory charges, which we pass on to our consumers).  In 2015, tariffs were increased to consider the extraordinary costs due to the full dispatch of thermal plants and involuntary exposure of distributors.

Annual Adjustment — RTA

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 2011 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”.

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	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari
2011
Economic adjustment(1)	6.11%	4.45%	8.58%	8.01%	6.84%	6.42%	6.57%	5.22%
Regulatory adjustment(2)	1.27%	0.98%	8.63%	15.60%	2.66%	1.34%	1.45%	0.25%
Total adjustment	7.38%	5.43%	17.21%	23.61%	9.50%	7.76%	8.02%	5.47%
2012
Economic adjustment(1)	1.96%	7.71%	0.49%	4.36%	7.20%	-2.20%	-4.41%	-7.15%
Regulatory adjustment(2)	1.75%	1.08%	11.02%	3.74%	1.80%	2.28%	0.69%	0.05%
Total adjustment	3.71%	8.79%	11.51%	8.10%	9.00%	0.08%	-3.72%	-7.10%
2013
Economic adjustment(1)	4.53%	9.69%	-10.66%	12.15%	-1.83%	7.96%	6.98%	10.76%
Regulatory adjustment(2)	0.95%	-2.27%	0.34%	-2.82%	8.83%	-1.47%	-4.71%	-8.06%
Total adjustment	5.48%	7.42%	-10.32%	9.32%	7.00%	6.48%	2.27%	2.71%
2014
Economic adjustment(1)	14.56%	15.81%	18.83%	9.89%	2.00%	-4.74%	-3.16%	1.17%
Regulatory adjustment(2)	2.62%	3.92%	2.99%	4.96%	-4.07%	-2.93%	-2.35%	-4.90%
Total adjustment	17.18%	19.73%	21.82%	14.86%	-2.07%	-7.67%	-5.51%	-3.73%
2015
Economic adjustment(1)	(3)	(3)	(3)	22.01%	28.90%	28.82%	30.24%	40.07%
Regulatory adjustment(2)	(3)	(3)	(3)	12.67%	-5.55%	-8.02%	-5.36%	-1.61%
Total adjustment	(3)	(3)	(3)	34.68%	23.34%	20.80%	24.88%	38.46%

(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 present in our regulatory financial information, primarily the CVA, and is not considered in the calculation of the following year’s adjustment.

(3)   Annual adjustments for CPFL Paulista, RGE and CPFL Piratininga occur in April, June and October, respectively.

Periodic Revisions — RTP

On November 22, 2011, ANEEL defined the methodology applicable to the third periodic revision cycle (2011 to 2014) through Resolution No. 457/2011.  For the third cycle, ANEEL has designated a new method of recognizing which costs we may pass through to our consumers.  In addition, ANEEL approved the new methodology for calculating the tariff for using the distribution system (Tarifa de Uso do Sistema de Distribuição), or TUSD, and other electricity tariffs, under which distribution companies assume all market risk resulting from tariff indicators.  As compared to the previous tariff cycle, this new methodology negatively impacted our financial condition and results of operations.  The tariff methodology under this cycle continues to apply to each distribution company until such time as each company’s tariffs are revised under the fourth revision cycle.

On October 10, 2013, ANEEL launched Public Consultation 011/2013 to examine the conceptual methodology to be applied in the 2015-2018 periodic revision cycle.  On June 10, 2014, ANEEL submitted a proposed methodology for this cycle for public discussion in the first phase of Public Hearing 023/2014. The documents released indicate that this periodic revision cycle will likely substantially maintain the structure of the existing methodology, other than the accounting methodology to be used by ANEEL in determining the Regulatory Asset Base (Base de Remuneração Regulatória), or BRR, which may be significantly modified.  In the second phase of Public Hearing 023/2014, which was opened on December 11, 2014, ANEEL commenced discussion of the implementation of this methodology (other than the BRR, for which the structure of the methodology remains under analysis by ANEEL).  As part of this revision process, ANEEL has also indicated that tariff parameters and methodology will be revised on standalone cycles, separate from the company’s revision cycle; thus, revised tariff parameters will apply immediately to the entire sector upon publication, rather than applying to each distribution company only when its specific concession enters the next tariff cycle, as was previously the case.  On this basis, on February 3, 2015, ANEEL published Resolution No. 648/2015 specifying that the cost of capital remuneration to be paid to all distribution companies from March 2015 to December 2017 is 8.09% in real terms after taxes and a new remuneration percentage will be fixed for the three-year period commencing January 2018 when this parameter is next updated.  In addition, ANEEL has clarified that existing methodologies will continue to apply until publication of a new methodology.

The current methodology review is expected to be concluded during the first half of 2015.

The following table sets forth the percentage change in our tariffs resulting from the first, second and third cycles of periodic revisions.

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	First cycle		Second cycle		Third cycle
	Adjustment date	Economic adjustment	Adjustment date	Economic adjustment	Adjustment date	Economic adjustment
		(%)		(%)		(%)
CPFL Paulista	April 2003	20.66	April 2008	-14.00	April 2013	5.65(3)
CPFL Piratininga	October 2003	10.14	October 2007	-12.77	October 2011	-3.95(1)(3)
RGE	April 2003	27.96	April 2008	2.34	June 2013	-9.92(3)
CPFL Santa Cruz	February 2004	17.14	February 2008	-14.41	February 2012	4.16(1)(2)
CPFL Mococa	February 2004	21.73	February 2008	-7.60	February 2012	7.18(1)(2)
CPFL Leste Paulista	February 2004	20.10	February 2008	-2.18	February 2012	-2.00(1)(2)
CPFL Sul Paulista	February 2004	12.29	February 2008	-5.19	February 2012	-3.78(1)(2)
CPFL Jaguari	February 2004	-6.17	February 2008	-5.17	February 2012	-7.09(1)(2)

(1)   As a result of ANEEL’s delay in determining the methodology applicable to the third periodic revision cycle, the periodic review process for CPFL Piratininga was concluded on October 23, 2012, rather than the October 23, 2011, which is the date that complies with the concession agreement. CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista had their revision process concluded on February 3, 2013, rather than February 3, 2012, which is the date that complies with the concession agreement. However, the difference of tariffs billed from the date of the revision process specified in the concession agreement and the actual date on which the process was concluded was reimbursed to consumers.

(2)   CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista filed administrative appeals questioning the results of their periodic review processes.  The appeals were assessed by ANEEL in January 2014, with the following results: (i) Dispatch No. 165 of January 28, 2014 alters the tariff revision index from 7.20% to 7.18% for CPFL Mococa, mainly because of a Regulatory Asset Base, or RAB, reduction; (ii) Dispatch 212 of January 30, 2014 alters the tariff revision index from 4.36% to 4.16% for CPFL Santa Cruz, mainly because of a RAB reduction; (iii) Dispatch No. 166 of January 28, 2014 alters the tariff revision index from ‑2.20% to ‑2.00% for CPFL Leste Paulista, mainly because of an increase in RAB and regulatory non-technical losses; (iv) Dispatch No. 211 of January 30, 2014 alters the tariff revision index from ‑3.72% to ‑3.78 % for CPFL Sul Paulista, mainly because of a RAB reduction; and (v) Dispatch No. 167 of January 28, 2014 alters the tariff revision index from -7.10% to -7.09% for CPFL Jaguari, mainly because of a RAB increase.

(3)   CPFL Piratininga, CPFL Paulista and RGE filed administrative appeals questioning the results of their periodic review processes. CPFL Piratininga questioned the regulatory losses in the periodic review process.  The appeal was assessed by ANEEL, and Dispatch No. 3,426, issued on October 8, 2013, altered the result of the periodic review process from ‑4.45% to ‑3.95%.  CPFL Paulista questioned the Regulatory Asset Base, and Dispatch No. 733 of March 25, 2014 altered the result of the periodic review process from 5.48% to 5.65%.  RGE also had the Regulatory Asset Base altered once the assets of the two municipalities, Putinga and Anta Gorda, that won on a tender, were included in the RAB. Therefore, Dispatch No. 1,857 of June 17, 2014 altered the result of the periodic review process from ‑10.32% to ‑9.92%.

Extraordinary Tariff Adjustment – RTE

Pursuant to Law No. 12,783/13, commencing January 24, 2013 an RTE process was issued enabling all distributors  to pass on to consumers the effects of the renewal of generation and transmission concessions and the reduction in regulatory charges.

 The table below shows the impact of this extraordinary tariff adjustment on our entities:

	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari
2013
Economic adjustment	-15.3%	-11.3%	-12.0%	-6.8%	-7.6%	-17.2%	-18.4%	-25.4%
Regulatory adjustment	-0.5%	1.1%	0.7%	3.7%	1.8%	2.3%	0.0%	0.1%
Total adjustment	-15.8%	-10.2%	-11.4%	-3.1%	-5.8%	-14.9%	-18.4%	-25.3%

Pursuant to Resolution No. 1,858/2015, tariffs were increased to consider extraordinary costs due to full dispatch of thermal plants and involuntary exposure of distribution companies, as follows:

	CPFL Paulista	CPFL Piratininga	RGE	CPFL Santa Cruz	CPFL Mococa	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari
2015
Economic adjustment	0.0%	0.0%	0.0%	0.0%	0.0%	0.0%	0.0%	0.0%
Regulatory adjustment	31.77%	29.25%	35.47%	9.15%	16.25%	19.09%	21.29%	22.85%
Total adjustment	31.77%	29.25%	35.47%	9.15%	16.25%	19.09%	21.29%	22.85%

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 “Item 4. Information on the Company—The New Industrial Model Law—The Free Market”.  To date, as compared to the total number of our Captive Consumers, thenumber of Potentially Free Consumers is relatively small, but they account for a significant amount of our electricity sales and revenues.  At December 31, 2014 we had a total of 1,649 Potentially Free Consumers and they accounted for approximately 15.1% of our electricity sales.  In comparison, at December 31, 2013 Potentially  Free Consumers accounted for approximately 17.0% of our electricity sales.  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 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 that a substantial number of our consumers will 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 2014, we purchased 58,879 GWh, compared to 57,692 GWh in 2013.  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 2014, we purchased 10,417 GWh of electricity from Itaipu (17.7% of the electricity we purchased in terms of volume), as compared to 10,719 GWh (18.6% of the electricity we purchased in terms of volume) in 2013.  See “Item 4.  Information of the Company—Purchases of Electricity”.  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 therealdepreciates 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.

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 concessionaires and licensees (including our subsidiaries).  See “—The New Industry Model Law—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.

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 income will decrease in the same period.  These losses will be offset in the future, when the next annual tariff adjustments occur.

See note 8 to our audited annual consolidated financial statements and “—Sector financial asset and liability”.

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Sector financial asset and liability

According to the tariff-pricing mechanism applicable to the distribution companies, energy tariffs should be set at a price level (price-cap) that ensures the economic and financial equilibrium of the concession.  Therefore, concessionaires are authorized to charge consumers (i) an annual tariff increase (after review and ratification by ANEEL) and (ii) every four or five years, as specified in the concession contract, the periodic review adjustment used to recalculate Parcel A and Parcel B adjustments of certain tariff components, such as changes in the cost of energy purchased and return in infrastructure investments.

The distributors’ revenue is mainly derived from the sale and delivery of electric energy.  The concessionaires’ revenue is determined by the amount of energy delivered and the electric energy tariff, which is determined by Parcel A (non-controllable costs) and Parcel B costs (controllable costs).

This tariff-pricing mechanism may lead to timing differences between the budgeted costs (Parcel A and other financial components) included in the tariff at the beginning of the tariff period and those actually incurred while it is in effect.  This difference permits the concessionaire to receive cash when the budgeted costs included in the tariff are lower than those effectively incurred, or requires it to make a payment if the budgeted cost are higher than those effectively incurred. 

On November 25, 2014, ANEEL approved an amendment to distribution concession contracts.  On December 10, 2014, the eight distribution subsidiaries signed this addendum. This amendment introduced a new clause providing compensation for any outstanding balance (assets or liabilities) related to insufficient collection or reimbursement through the tariffs resulting from termination of the concession.  This provision, which comes into effect once an addendum to each specific concession contract is executed, provides that the concessionaire has the unconditional right (and obligation) to receive (or deliver) cash or another financial instrument in respect of this amount.See note 8 to our audited annual consolidated financial statements.

Operating Segments

As discussed in note 30 to our audited annual consolidated financial statements, we present our financial results under five operating segments: (i) distribution; (ii) conventional generation sources; (iii) renewable generation sources; (iv) commercialization; and (v) services.

The profitability of each of our segments differs.  Our Distribution segment primarily reflects sales to Captive Consumers and TUSD charges paid by Free 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 79.0% of our net operating revenue (79.1% in 2013), but its contribution to our net income was greater in 2014 at 95.3% of our net income for the year (by comparison, our distribution activities accounted for 76.5% of our net income in 2013 and 68.7% in 2012).

The contributions of Distribution, Conventional Generation, Renewable Generation, Commercialization and Services segments to the net operating revenues and net income for the years ended December 31, 2014, 2013 and 2012 are presented in the following table:

	Distribution	Conventional Generation	Renewable Generation	Commercialization	Services
2014
Net operating revenue	79.0%	6.9%	8.0%	12.6%	2.0%
Net income	95.3%	12.2%	-19.0%	15.3%	3.2%
2013
Net operating revenue	79.1%	6.3%	7.4%	12.6%	1.4%
Net income	76.5%	32.9%	-5.8%	3.8%	1.7%
2012
Net operating revenue	83.4%	5.6%	5.5%	12.7%	1.2%
Net income	68.7%	28.7%	0.7%	8.5%	2.2%

Our Conventional Generation Sources segment consists in substantial part of Hydroelectric Power Plants, and our Renewable Generation Sources segment consists of wind farms, Biomass Thermoelectric Power Plants andSmall Hydroelectric Power Plants.  All of our generation sources 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 become operational, they generally result in a higher margin (operating income as a percentage of revenue) than the Distribution segment, but will also contribute to higher interest expenses and other financing costs.  As a result, in the year ended December 31, 2014, our Renewable Generation Sources segment provided 9.1% of our operating income, but due to the significant financial expenses incurred to finance these projects, the segment’s contribution to net income was negative (-19.0%).

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As of December 31, 2014, 2.9% of the property, plant and equipment in the Renewable Generation Sources segment was under construction.

Our Commercialization segment sells electricity to Free Consumers and other concessionaires or licensees. 

Our Services segment offers our consumers a wide range of electricity‑related services.  These services are designed to help consumers improve the efficiency, cost-effectiveness and reliability of the electric equipment they use.

Our segments also purchase and sell electricity and value‑added services from and to one another.  In particular, our Generation (from both conventional and renewable sources), Commercialization and Services segments sell electricity and provide services to our Distribution segment.  Our consolidated financial statements eliminate revenues and expenses that relate to sales from one subsidiary to another, which is reflected in the column entitled “Elimination” in the table below.  However, the analysis of results by segment would be inaccurate if the same set‑offs were carried through with respect to sales between segments.  As a result, sales from one segment to another have not been eliminated or set‑off in the discussion of results by segment below.

We present below selected financial information of our five reportable segments as of and for the years ended December 31, 2014, 2013 and 2012:

	Distribution	Conventional generation sources	Renewable generation sources	Commercialization	Services	Other (*)	Elimination	Total
2014
Net Revenue	13,658,786	722,623	982,613	1,790,822	151,037	61	-	17,305,942
(-) Inter-segment Revenues	19,668	467,761	397,630	387,788	193,483	-	(1,466,329)	-
Income from electric energy service	1,602,519	482,214	231,280	205,108	45,072	(26,119)	-	2,540,073
Financial income	552,918	84,884	98,991	29,543	6,380	117,720	-	890,436
Financial expense	(849,774)	(482,671)	(464,713)	(29,104)	(10,221)	(143,407)	-	(1,979,890)
Income before taxes	1,305,663	144,112	(134,442)	205,547	41,230	(51,806)	-	1,510,304
Income tax/social contribution	(461,264)	(36,291)	(33,645)	(69,543)	(12,687)	(10,430)	-	(623,860)
Net Income	844,400	107,820	(168,087)	136,003	28,543	(62,236)	-	886,443
Total Assets(**)	16,724,269	4,414,196	11,601,754	507,960	828,184	1,022,454	-	35,098,816
Capital Expenditures and other intangible assets	702,386	14,419	250,803	3,531	90,707	22	-	1,061,868

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	Distribution	Conventional generation sources	Renewable generation sources	Commercialization	Services	Other (*)	Elimination	Total
Depreciation and Amortization	(577,753)	(136,447)	(432,267)	(4,471)	(8,760)	(265)	-	(1,159,964)
2013
Net Revenue	11,563,700	601,980	802,011	1,579,893	84,622	1,649	‑	14,633,856
(‑) Intersegment Revenues	15,354	323,658	281,913	264,891	116,184	‑	(1,002,001)	‑
Income from electric energy service	1,550,951	559,784	214,750	52,060	13,333	(21,103)	‑	2,369,775
Financial income	504,463	40,005	55,083	27,665	13,876	58,115	‑	699,208
Financial expense	(906,153)	(338,783)	(314,243)	(22,601)	(4,358)	(84,513)	‑	(1,670,651)
Income before taxes	1,149,261	381,874	(44,410)	57,123	22,852	(47,500)	‑	1,519,200
Income tax and social contribution	(423,712)	(69,937)	(10,607)	(21,399)	(6,881)	(37,627)	‑	(570,164)
Net Income	725,549	311,937	(55,017)	35,724	15,970	(85,127)	‑	949,036
Total Assets(**)	15,263,417	4,515,880	9,470,564	342,516	243,612	1,206,806	‑	31,042,796
Capital Expenditures and other intangible assets	844,804	9,744	827,704	3,593	48,646	345	‑	1,734,836
Depreciation and Amortization	(564,538)	(133,514)	(348,355)	(4,106)	(4,632)	(86)	‑	(1,055,231)
2012
Net Revenue	12,391,730	558,547	608,223	1,284,069	46,855	1,452	-	14,890,875
(-) Intersegment Revenues	22,138	269,688	210,260	602,332	124,968	-	(1,229,386)	-
Income from electric energy service	1,369,809	494,885	215,139	255,193	26,276	(28,210)	-	2,335,091
Financial income	558,130	32,809	56,461	39,389	4,777	15,397	-	706,963

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	Distribution	Conventional generation sources	Renewable generation sources	Commercialization	Services	Other (*)	Elimination	Total
Financial expense	(632,278)	(228,949)	(254,333)	(140,506)	8,475	(37,143)	-	(1,284,736)
Income before taxes	1,295,661	421,423	17,268	154,076	39,528	(49,957)	-	1,877,998
Income tax and social contribution	(469,081)	(72,756)	(9,256)	(52,000)	(12,856)	(54,987)	-	(670,937)
Net Income	826,580	348,667	8,011	102,075	26,672	(104,944)	-	1,207,062
Total Assets(**)	14,729,776	4,376,137	8,786,521	466,645	186,303	378,897	-	28,924,279
Capital Expenditures and other intangible assets	1,402,994	12,804	1,021,970	2,870	18,865	508	-	2,460,011
Depreciation and Amortization	(544,192 )	(138,417)	(289,372)	(3,177)	(3,693)	(74)	-	(978,926)

(*)   Refers to the assets and transactions recorded, which are not related to any of the identified segments.

(**) Intangible assets (net of amortization) recorded at the parent company level, were allocated to their respective segments.

We also derive non‑material income at the parent company level that is not related to or included in the results of our reportable segments and is reflected in the column “Other” in the table above.  General expenses and indirect costs 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 goodwill, 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. 

Some factors may significantly affect demand for electricity, depending on the category of consumers:

·Residential and Commercial Consumers.  These segments are highly affected by weather conditions, labor market performance, income distribution and credit availability, amongst other factors.  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 and investments, mostly correlated to industrial production.  During periods of financial crisis, this category suffers the strongest impact.

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 a 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 Costs areindexed to the variation of the SELIC and IGP-M rates until they passed through to our tariffs and Parcel B costs are indexed to the IGP-M net of factor X (see “Item 4.  Information on the Company—The Brazilian Power Industry—Basis of Calculation of Distribution Tariffs”).

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Depreciation of therealincreases 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.

The following table shows the main performance indicators of Brazilian economy for the years ended December 31, 2014, 2013 and 2012:

	2014	2013	2012
Growth in GDP (in reais)	0.2%	2.3%	1.0%
Unemployment rate ‑ % average	4.9%	5.4%	5.5%
Credit to individuals (non‑earmarked resources) ‑ % GDP	15.1%	15.5%	15.7%
Growth in Retail Sales	2.2%	4.3%	8.4%
Growth (contraction) in Industrial Production	(3.2%)	1.1%	(2.6%)
Inflation (IGP‑M)(1)	3.7%	5.5%	7.8%
Inflation (IPCA)(2)	6.4%	5.9%	5.8%
Average exchange rate–US$1.00(3)	R$2.360	R$2.174	R$1.958
Year‑end exchange rate–US$1.00(4)	R$2.656	R$2.343	R$2.044
Depreciation (appreciation) of thereal vs. U.S. dollar(4)	13.4%	14.6%	9.0%

Sources:Fundação Getúlio Vargas, the Instituto Brasileiro de Geografia e Estatística and the Brazilian 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.

(4)   The Brazilianreal depreciated as compared to the U.S. dollar in the first quarter of 2015, with the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of March 31, 2015 of R$3.208 to US$1.00.

The Brazilian economic environment has been characterized by significant variations in economic growth rates, with very low growth from 2001 through 2003 (1.7% p.a.) and an economic recovery between 2004 and 2008 (4.8% p.a.).  This trend was interrupted by the international financial crisis in 2009.  Since then, Brazilian economic activity has been affected by the international scenario and industrial performance showed moderate results due to the lower exports, unfavorable investors’ expectations and infrastructure deficiencies.  GDP grew at lower rates in this period, reaching an average growth rate of 2.6% between 2009 and 2013 and only 0.2% in 2014.

However, income and employment are maintaining a good performance, despite the recent moderate results.  Retail sales, especially household appliances, and credit availability had a good performance as well, although recent results suggest a slowdown.  The strength of domestic market, reflecting better income distribution, improvements in labor market and household consumption, benefits our operations.

Results of Operations—2014 compared to 2013

Net Operating Revenues

Compared to the year ended December 31, 2013, net operating revenues increased 18.3% (or R$2,672 million) in the year ended December 31, 2014, amounting R$17,306 million.  The increase in operating revenue primarily reflected the increase in the RTA of our distribution subsidiaries, impacting the electricity sales to Captive Consumers and TUSD revenue from Free Consumers in our concession areas.  Additionally, due to the fact that the concession contracts have been amended, we have recognized on an accrual basis R$911 million related to our contractual right to receive cash from consumers through subsequent tariffs or to pay to or receive from the granting authority any remaining amounts at the expiration of the concession’s term (see note 8 to our audited annual consolidated financial statements). Additionally, the commencement of operations of the Campo dos Ventos II Wind Farm, Atlântica Complex and Macacos I Wind Farm and the acquisition of Rosa dos Ventos and WF2 (DESA) contributed to the increase of net operating revenue as well. Also included in net operating revenue are the revenuesrelating to the construction of concession infrastructure in the amount of R$945 million, which does not affect results, due to corresponding costs in the same amount.

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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

Compared to the year ended December 31, 2013, our gross operating revenues from sales to Final Consumers increased 17.9% in the year ended December 31, 2014, to R$22,796 million.  Our gross operating revenues primarily reflect sales to Captive Consumers at concession areas from our eight distribution subsidiaries, and are subject to tariff adjustment, as described below.

The tariffs of the distribution companies are adjusted every year, in percentages specific to each category of consumer.  The month in which the tariff adjustment becomes effective varies.  The adjustment at the largest subsidiaries occurred in April (CPFL Paulista), June (RGE) and October (CPFL Piratininga).  In the year ended December 31, 2014, energy prices increased by an average of 9.7%, mainly due to the result of the tariff adjustment of CPFL Paulista (17.18%), RGE (21.82%) and CPFL Piratininga (19.73%), considering their effective dates.  See note 27 to our audited annual consolidated financial statements.  Average prices for Final Consumers in 2014 were higher for all consumer categories:

·Residential and commercial consumers.  With respect to Captive Consumers (which represent 99.6% of the total amount sold to this category in our consolidated statements), average prices increased 7.0% and 10.0%, respectively, due to the annual tariff adjustment, as described above.  With respect to Free Consumers, the average price for the commercial consumers increased 4.2%.

·Industrial consumers.  Average prices increased 12.1%, mainly due to tariff adjustments, as described above.  With respect to Free Consumers, the average price for industrial consumers increased 6.6%.  The increase in the average price for the industrial consumers was due to the tariff increase due to the annual tariff adjustment on the contracts for the use of our distribution system (TUSD) by Free Consumers.

The total volume of energy sold to Final Consumers in the year ended December 31, 2014 increased 3.3% compared to the year ended December 31, 2013.  The volume sold to residential and commercial categories, which accounts for 63.9% for our sales to Final Consumers, increased 7% and 6.8%, respectively.  The growth of these categories is a result of good performance in the income and the labor market, confirmed by historically low unemployment levels and the expansion of credit available to the consumer in recent years.  These factors reflected positively in sales on the retail and furniture and household appliances markets in this year.

The volume sold to industrial consumers decreased 3.7% in the year ended December 31, 2014 compared to the year ended December 31, 2013, which represents 24.7% of our sales to Final Consumers (26.1% as of December 31, 2013). In 2014, the volume sold in this category to Captive Consumers and in the Free Market decreased 2% and 6.3%, respectively, reflecting the slowdown in economic activity that impacted the consumption of large industrial customers.  Additionally, industrial consumers in our distribution concession areas that buy 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 audited annual financial statements under “Other Operating Revenues”.

Sales to wholesalers

Compared to the year ended December 31, 2013, our gross operating revenues from sales to wholesalers increased 24.7% (or R$623 million) to R$3,145 million in the year ended December 31, 2014 (13.8% of gross operating revenues), due mainly to (i) an increase of R$770 million in sales of energy in the spot market (increases of 124.5% in the volume and 111.1% of the average price) due to the poor hydrological conditions in 2014, that led market participants to buy energy from our commercialization companies to cover their Assured Energy; (ii) an increase of 8.1% (or R$36 million) in sales to Furnas as a result of the tariff increases due to the effect of the IGP‑M offset by (iii) a decrease of 9.8% (or R$184 million) in sales of electricity to other concessionaires and licensees.  For more information on net operating revenues from our segments, see “—Sales  by Segment”.

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Other operating revenues

Compared to the year ended December 31, 2013, our other gross operating revenues increased 3.1% (or R$91 million) in the year ended December 31, 2014 to R$3,030 million (13.3% of our gross operating revenues), mainly due to (i) the increase of 2.6% (or R$25 million) in TUSD revenue from the use of our network by Free Consumers that buy from other suppliers. Such increase has arisen from the annual tariff adjustment (RTA) and is net of the negative effect in the volume sold to industrial consumers which decreased 3.7% in the year ended December 31, 2014 compared to the year ended December 31, 2013; (ii) the increase of 22.8% (or R$143 million) in revenue related to the low-income subsidy; and (iii) the increase of 17.5% (or R$26 million) related to rental activities revenue. Those increases were partially offset by the decrease of 5.9% (or R$59 million) of revenue from construction of concession infrastructure and the decrease of 64.4% (or R$51 million) from other revenues.

Deductions from operating revenues

We deduct certain taxes and industry charges from our gross operating revenue to calculate net revenue.  The state‑level value‑added tax (ICMS), federal PIS and COFINS taxes, and the research and development and energy efficiency programs (regulatory charges) are calculated based on gross operating revenue, while other regulatory charges vary depending on the regulatory effect reflected in our tariffs.  These deductions represented 24.1% of our gross operating revenue in the year ended December 31, 2014 and 24.3% in the year ended December 31, 2013.  Compared to the year ended December 31, 2013, these deductions increased 16.7% (or R$785 million) to R$5,490 million in 2014, mainly due to: (i) an increase of 11.9% (or R$329 million) in ICMS, as a result of the rise of in our billed supply; (ii) an increase of 24.0% (or R$365 million) in PIS and COFINS, basically due to the increase in our gross operating revenues (the calculation base for these taxes); and (iii) by the net effect of the increase of 21.9% (or R$88 million) in regulatory charges, mainly as a result of the increase in contributions made to the CDE Account.  See explanatory note 27 to our audited annual consolidated financial statements.

Sales by segment

Distribution

Compared to the year ended December 31, 2013, our net operating revenues from our Distribution segment increased 18.1% (or R$2,099 million) to R$13,678 million in the year ended December 31, 2014.  This increase primarily reflected: (i) the increase related to annual tariff adjustments of our distribution subsidiaries, impacting the electricity sales to Captive Consumers and TUSD revenue from Free Consumers in our concession areas (increase of R$1,836 million); (ii) accrual basis revenue recognition (R$911 million) related to our contractual right to receive cash from consumers through subsequent tariffs or to pay to or receive from the granting authority any remaining amounts at the expiration of the concession’s term (see note 8 to our audited annual consolidated financial statements); (iii) an increase of R$143 million related to the low-income subsidy and discounts on tariffs reimbursed by funds from the CDE Account (see note 27.4 to our audited annual consolidated financial statements); and (iv) an increase of R$66 million in sales to wholesalers, mainly due to an increase in short‑term energy sales in the CCEE as a result of increase in the amount of electric energy sold mainly by our subsidiaries CPFL Paulista, CPFL Piratininga and RGE. Those increases were partially offset by a reduction of R$120 million in revenue from construction of concession infrastructure, as a result of lower investments in improving and expanding of our distribution subsidiaries and an increase (which represents a decrease in operating revenues) of R$725 million in deductions from operating revenues mainly due to an increase of R$638 million in taxes (ICMS, PIS and COFINS) and a net increase of R$88 million in regulatory charges. 

Generation (conventional sources)

Net operating revenues from our Generation from Conventional Sources segment in the year ended December 31, 2014 amounted to R$1,190 million, an increase of 28.6% (or R$264 million) compared to R$926 million in the year ended December 31, 2013.  This increase was mainly due to: (i) an increase of R$124 million in the amount of energy sold in the spot market and (ii) an increase of 28.3% (or R$145 million) in sales toour distribution subsidiaries, considering an increase of 46.6% in the average price, offset by a reduction of 12.5% in the volume sold in this period.

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Generation (renewable sources)

Net operating revenues from our Generation from Renewable Sources segment in the year ended December 31, 2014 amounted to R$1,380 million, an increase of 27.3% (or R$296 million) compared to R$1,084 million in the year ended December 31, 2013.  This increase was mainly due an increase of 14.4% in the volume of energy sold because of: (i) the commencement of operations of the Campo dos Ventos II Wind Farm and Atlântica Complex in the last quarter of 2013 and the Macacos I Wind Farm in the second quarter of 2014; and (ii) the acquisition of Rosa dos Ventos (first quarter of 2014) and the acquisition of DESA in the last quarter of 2014 (see note 15.6 to our audited annual consolidated financial statements).  Additionally, another contributing factor to the increase in net operating revenues was the increase of 11.5% in the average price of energy sold in comparison with the year ended December 31, 2013.

Commercialization

Net operating revenues from our Commercialization segment in the year ended December 31, 2014 amounted to R$2,179 million, an increase of 18.1% (or R$334 million) compared to R$1,845 million in the year ended December 31, 2013.  The increase was mainly due to an increase of R$572 million in sales to CCEE because of the increase in the volume (118.9%) and average price (142.1%) of the energy sold in comparison with the year ended December 31, 2013.  This increase was partially offset by a reduction of R$220 million (21.3%) in sales to other concessionaires and licensees due to a reduction of 39.7% in the volume sold, partially offset by an increase of 30.6% in the average price.

Services

Net operating revenues from our Services segment in the year ended December 31, 2014 amounted to R$345 million, an increase of 71.6% (or R$144 million) compared to R$201 million in the year ended December 31, 2013.  The increase was mainly due to the increased sales by CPFL Serviços (both to third parties and to other our subsidiaries), reflecting an effort to expand the range of electricity‑related services provided, and by an increase in the transaction volume of CPFL Total.

Income from Electric Energy Service by Destination

Cost of Electric Energy

Electricity purchased for resale.  Compared to the year ended December 31, 2013, our costs to purchase energy for resale increased 36.0% (or R$2,689 million) in the year ended December 31, 2014, to R$10,158 million (69.1% of our total operating costs and operating expenses) from R$7,469 million for the year ended December 31, 2013 (representing 60.9% of our total operating costs and operating expenses), mainly due to an increase of 33.3% in the overall average price, reflecting: (i) an increase of R$2,292 million of energy purchased in the Free Market (reflecting an increase of 70.6% in the volume and 143.3% in the average price); (ii) an increase of R$2,051 million of the energy bought in the Regulated Market (reflecting an increase of 32.2% in the average price partially offset by a decrease of 1.5% in the volume purchased); and (iii) an increase of R$85 million in purchases of energy from Itaipu which reflects an increase of 9.7% in the average price of energy bought (inreais), caused by the average depreciation of 8.5% of thereal against the U.S. dollar during 2014, as the tariff in U.S. dollars remained substantially the same (decrease of 0.11% in comparison with 2013), and a 2.8% decrease in the volume of energy purchased.  These increases were partially offset by an increase of R$1,513 million in reimbursement of costs by CDE Account and an increase of R$257 million in tax credits from purchases of energy.

Electricity network usage charges.  Compared to the year ended December 31, 2013, our charges for the use of our transmission and distribution system decreased 33.3% (or R$242 million) to R$485 million in the year ended December 31, 2014, mainly as a result of a reduction of R$881 million in the System Service Charges, net of an increase of R$168 million in the Basic Network Charges due to the increase in the tariffs of the transmission companies and reimbursement of costs by CDE Account.  For further information about electricity network usage charges, see the explanatory note 28 to our audited annual consolidated financial statements.

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Other costs and operating expenses

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

Compared to the year ended December 31, 2013, our other costs and operating expenses increased 1.4% (or R$55 million) to R$4,123 million in the year ended December 31, 2014, mainly due to the following important events: (i) an increase of R$129 million in expenses with personnel due to collective bargaining agreements and an increase of 8.9% in our number of employees; (ii) an increase of R$117 million in depreciation and amortization expenses mainly as a result of the commencement of operations of CPFL Renováveis’ new investments and acquisition of DESA in the last quarter of 2014; (iii) a decrease of R$60 million in the net income related to disposal and decommissioning and other noncurrent assets, which resulted in a net loss of R$21 million for the year ended December 31, 2014; and (iv) an increase of R$39 million in outsourced services. Those increases were partially offset by a decrease of R$237 million in legal, judicial and indemnity expenses and a decrease of R$62 million in expenses related to construction of concession infrastructure.

Income from Electric Energy Service

Compared to the year ended December 31, 2013, our income from electric energy service increased 7.2% (or R$170 million) to R$2,540 million in the year ended December 31, 2014, due to the net effect of an increase in our net operating revenue in a higher amount than the increase in our cost of generating and distributing electric energy and other operating costs and expenses.

Income from Electric Energy Service by Segment

Distribution

Compared to the year ended December 31, 2013, income from electric energy service from our Distribution segment increased 3.3% (or R$52 million) to R$1,603 million in the year ended December 31, 2014, which represents the net effect in the income from electric energy service due to an increase of 18.1% (or R$2,099 million) in net operating revenues (as discussed above) and an increase of 20.4% (or R$2,047 million) to costs and operational expenses.  The main contributing factors to variations in cost and operational expenses were:

·Electricity costs.  Compared to the year ended December 31, 2013, electricity costs increased 31.5% (or R$2,158 million), to R$9,010 million in the year ended December 31, 2014.  The cost of energy purchased for resale increased 39.1%, (or R$2,410 million), reflecting an increase of average prices, arising from the greater exposure and variation in the PLD, tariff adjustments and the exchange rate variations in the purchase from Itaipu.  However, charges for use of the transmission and distribution system decreased 37.1% (or R$252 million) due to: (i) a decrease of R$881 million in System Service Charges to account for a reimbursement by Energy Reserve Account, or CONER (see note 28.1 to our audited annual consolidated financial statements), partially offset by an increase of R$155 million in the Basic Network Charges due to the increase in the tariffs of the transmission companies;and (ii) a decrease of R$459 million in the amount of reimbursement by the CDE Account (which represents an increase in the charges for use of the transmission and distribution system).

·Other costs and operating expenses.  Compared to the year ended December 31, 2013, our other costs and operating expenses for the Distribution segment decreased 3.5% (or R$110 million), to R$3,066 million in the year ended December 31, 2014, mainly due to: (i) a reduction of R$232 million in legal, judicial and indemnity expenses; (ii) a decrease of R$120 million in infrastructure construction costs for investments in improving and expanding distribution; and (iii) a decrease of R$13 million in employee expenses due to our post-employment benefit obligation as of December 31, 2014 (see note 19 to our audited annual consolidated financial statements). Such decrease was partially offset by: (i) an increase of R$74 million in outsourced services; (ii) an increase of R$97 million in expenses with personnel due to the effects of 2014’s collective labor agreement, an increase of 5% in the number of employees and higher distributions from our profit-sharing plan; (iii) an increase ofR$26 million in depreciation and amortization expenses; and (iv) an increase of R$53 million on the disposal of noncurrent assets.

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Generation (conventional sources)

Compared to the year ended December 31, 2013, income from electric energy service from our Conventional Generation segment decreased 13.9% (or R$78 million) to R$482 million in the year ended December 31, 2014.  An increase of 28.6% (or R$265 million) in net operating revenue was more than offset by an increase of 93.6% (or R$343 million) in costs and operational expenses, primarily due an increase of R$334 million in electricity purchased for resale, for which average prices increased 260.5% in comparison with the period ended December 31, 2013, considering that our Hydroelectric Power Plants received an amount of energy lower than their Assured Energy in the MRE, which led them to purchase energy from other sources in the spot market. Additionally, this GSF represents an increase in the cost of energy purchased in the spot market compared with the cost of energy generated by us.

Generation (renewable sources)

Compared to the year ended December 31, 2013, income from electric energy service from our Renewable Generation segment increased 7.7% (or R$17 million) to R$231 million for the year ended December 31, 2014.  Despite the increase of 27.3% (or R$296 million) in net operating revenues, the cost and operational expenses also increased 32.2% (or R$279 million) mainly due to: (i) an increase of R$139 million in electricity purchased for resale, as a result of an increase of 68.5% in the average prices, offset by a reduction of 9.2% in the volume purchased; (ii) an increase of R$84 million in depreciation and amortization due to CPFL Renováveis’ commencement of operations at greenfield plants; and (iii) an increase of R$35 million in outsourced services mainly related to operation and maintenance expenses.

Commercialization

Compared to the year ended December 31, 2013, income from electric energy service from our Commercialization segment increased 294.0% (or R$153 million), to R$205 million in the year ended December 31, 2014.  This increase was due to an increase of 18.1% (or R$334 million) in net operating revenues and a relatively smaller increase of 10.1% (or R$181 million) in costs and operational expenses.  The increase in costs and expenses was primarily due to an increase of R$186 million in electricity purchased for resale, arising from an increase of 37.7% in the average price, which was mitigated by a reduction of 19.6% in the volume of energy purchased.  The R$186 million increase in electricity purchased for resale was partially offset by a reduction of R$7 million in charges for use of the distribution and transmission system.

Services

Compared to the year ended December 31, 2013, income from electric energy service from our Service segment increased 238% (or R$32 million), to R$45 million in the year ended December 31, 2014.  Despite the increase of 71.6% (or R$144 million) in net operating revenues, the cost and operational expenses increased 59.7% (or R$112 million) mainly due to: (i) an increase of R$58 million in infrastructure construction costs for investments in transmission activities; (ii) an increase of R$24 million in expenses with personnel due to an increase of 29.9% in the number of employees; and (iii) an increase of R$20 million in expenses related to materials and outsourced services.

Net Income

Net Financial Expense

Compared with the year ended December 31, 2013, our net financial expense increased 12.1% (or R$118 million), from R$971 million in 2013 to R$1,089 million in the year ended December 31, 2014, mainly due to an increase of R$309 million in our financial expense, offset by an increase of R$191 million in our financial income.

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The increase in financial income is because of the following main reasons: (i) a R$105 million increase related to the adjustment in the estimated cash flow of the financial assets of concession in 2014 and (ii) an increase of R$114 million income from financial investments, partially offset by (iii) a decrease of R$44 million in monetary adjustment of escrow deposits.

The reasons for the increase in financial expenses are: (i) an increase in the debt charges and monetary and exchanges variations (R$316 million), as a result of increased indebtedness; and (ii) a decrease of R$45 million in capitalized borrowing costs, which means an increase in financial expenses, partially offset by the adjustment in the estimated cash flow of the financial assets of our concessions, which decreased R$67 million. 

At December 31, 2014, we had R$15,709 million (R$15,103 million at December 31, 2013) in debt denominated inreais, which accrued both interest and inflation corrections based on a variety of Brazilian indices and money market rates.  We also had the equivalent of R$3,441 million (R$2,008 million at December 31, 2013) of debt denominated in U.S. dollars.  In order to reduce the risk of exchange losses with respect to these U.S. dollar‑denominated debts and variations in interest rates, we have the policy of using derivatives to reduce the risks of variations in exchange and interest rates.  The CDI interbank rate increased to 10.5% in 2014, compared to 7.8% in 2013, and the TJLP remained stable at 5% in 2014 and 2013.

Income and Social Contribution Taxes

Our net charge for income and social contribution taxes increased from R$570 million in the year ended December 31, 2013 to R$624 million in the year ended December 31, 2014.  The effective rate of 41.4% on pretax income in the year ended December 31, 2014 was higher than the official rate of 34%, principally due to our inability to use certain tax loss carryforwards.  Such amount of unrecorded credit corresponds to losses generated for which there is no currently reasonable certainty that future taxable income will be sufficient to absorb such losses (see note 9.5 to our audited annual consolidated financial statements).

Net Income

Compared to the year ended December 31, 2013, and due to the factors discussed above, net income decreased 6.6% (or R$63 million), to R$886 million in the year ended December 31, 2014.

Net Income by Segment

In the year ended December 31, 2014, 95.3% of our net income derived from our Distribution segment, 12.2% from our Generation from Conventional Sources segment, -19.0% from our Generation from Renewable Sources segment, 15.3% from our Commercialization segment and 3.2% from our Services segment.

Distribution

Compared to the year ended December 31, 2013, net income from our Distribution segment increased 16.4%, or (R$119 million), to R$844 million in the year ended December 31, 2014, as a result of the increase of 3.3% (R$52 million) in income from electric energy service and a decrease of 26.1% (R$105 million)in net financial expenses.  The decrease in net financial expenses was mainly due to:

·an increase of R$49 million in financial income, owing primarily to an increase in financial income arising from an adjustment in the estimated cash flow of the financial assets of our concessions (R$105 million) and an increase of R$9 million due to the monetary adjustment of tax credits, partially offset by a decrease of R$44 million in the monetary adjustment of escrow deposits and a decrease of R$25 million in income from financial investments.

·a decrease of R$56 million in financial expenses. The primary contributing factors to the decrease in financial expenses were: (i) a decrease in the financial expense arising from adjustment in the estimated cash flow of the financial assets of our concessions (R$67 million), and (ii) a decrease of R$23 million in other financial expenses, partially offset by an increase of R$33 million in our financial expenses arising from debt charges and monetary and exchange rate variations as a result of higher indebtedness.

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Generation (conventional sources)

Net income from our Generation from Conventional Sources segment decreased by 65.4% (or R$204 million) to R$108 million during the year ended December 31, 2014 from R$312 million for the year ended December 31, 2013.  This decrease resulted principally from the decrease of 13.9% (or R$78 million) in income from electric energy service, and the R$99 million increase in net financial expenses.  The increase in net financial expenses reflected a R$144 million increase in financial expenses (mainly due to an increase of R$124 million in debt charges and monetary and exchange variations, due to the increase in our indebtedness), partly offset by an increase of R$45 million in financial income (driven by a R$41 million increase in financial income arising from financial investments).

Generation (renewable sources)

The net loss from our Generation from Renewable Sources segment increased by 205.5% (or R$113 million) to R$168 million in the year ended December 31, 2014 compared to 2013, as result of the increase of 41.1% (or R$107 million) in net financial expenses.  The increase in net financial expenses was driven by a R$71 million increase in debt expenses and monetary and exchange rate variations, a decrease of R$44 million in capitalized borrowing costs and a R$30 million increase in other financial expenses, partially offset by a R$40 million increase in financial income arising from financial investments.  The increase in net financial expenses was partially offset by an increase of R$17 million in income from electric energy service, as previously discussed. 

Commercialization

Compared to the year ended December 31, 2013, net income from our Commercialization segment increased 280.7% (or R$100 million), to R$136 million in the year ended December 31, 2014, reflecting the increase of R$153 million in the income from electric service, offset mainly by an increase of R$48 million in expense of income and social contribution taxes.

Services

Compared to the year ended December 31, 2013, net income from our Services segment increased 78.7% (or R$13 million), to R$29 million in the year ended December 31, 2014, reflecting an increase of R$32 million in income from electric energy service, offset by a decrease of R$13 million in net financial income and an increase of R$6 million in expense of income and social contribution taxes.

Results of Operations—2013 compared to 2012

Net Operating Revenues

Compared to the year ended December 31, 2012, net operating revenues decreased 1.7% (or R$257 million) in the year ended December 31, 2013, amounting R$14,634 million.  The decrease in operating revenue primarily reflected the decline in revenues in our eight distribution subsidiaries, due to the decrease in the average tariffs charged as a result of Law 12,783/13, which ANEEL ratified the result of the RTE, in 2013 for our distribution companies, applied to consumption from January 24, 2013 and tariff adjustments, impacting the electricity sales to Captive Consumers and TUSD revenue from Free Consumers in our concession areas.  Also is included in net operating revenue the revenues relating to the construction of concession infrastructure in the amount of R$1,004 million, which does not affect results, due to corresponding costs in the same amount.

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

Compared to the year ended December 31, 2012, our gross operating revenues from sales to Final Consumers decreased 9.0% in the year ended December 31, 2013, to R$19,339 million.  Our gross operatingrevenues reflect primarily sales to Captive Consumers at concession areas from our eight distribution subsidiaries, and are subject to tariff adjustment as shown below:

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The tariffs of the distribution companies are adjusted every year, in percentages specific to each category of consumer.  The month in which the tariff adjustment becomes effective varies.  The adjustment at the largest subsidiaries occurred in April (CPFL Paulista), June (RGE) and October (CPFL Piratininga).  In the year ended December 31, 2013, energy prices decreased by an average of 15.4%, mainly due to the result of the RTE in 2013, applied to consumption from January 24, 2013, partially offset by the net effect of the RTA at the following distributors: CPFL Paulista (6.18%), RGE (‑10.64%) and CPFL Piratininga (6.91%).  See note 27 to our audited consolidated financial statements.  Average prices for Final Consumers in 2013 were lower for all consumer categories:

Residential and commercial consumers.  With respect to Captive Consumers (which represent 99.2% of the total amount sold to this category in our consolidated statements), average prices decreased 18.7% and 14.3%, respectively, due to the annual tariff adjustment (RTA) and extraordinary tariff adjustment (RTE), as described above.  With respect to Free Consumers, the average price for the commercial consumers increased 7.6%.

Industrial consumers.  Average prices decreased 10.8%, mainly due to tariff adjustments (RTE and RTA), as described above.  With respect to Free Consumers, the average price for the industrial consumers decreased 7.7%.  The effect of the decrease in the average price for the industrial consumers was due to the tariff reduction by the extraordinary reviews (RTE) on the contracts for the use of our distribution system (TUSD) by Free Consumers.

The total volume of energy sold to Final Consumers in the year ended December 31, 2013 increased 2.6% compared to the year ended December 31, 2012.  The volume sold to residential and commercial categories, which accounts for 62.8% for our sales to Final Consumers, increased 5.9% and 1.4%, respectively.  The growth of these categories is resulted of good performance of income and the labor market, confirmed by historically low unemployment levels and the expansion of credit available to the consumer in recent years.  These factors reflected positively in sales on the retail and furniture and household appliances markets in this year.

The volume sold to industrial consumers increased 1.1% in the year ended December 31, 2013 compared to the year ended December 31, 2012, which represents 26.1% of our sales to Final Consumers, reflecting the modest performance of industrial production in this period.  In 2013, the volume sold in this category to captive Final Consumers decreased 6.0%, which was partially offset by an increase of 14.5% in volume sales to this category in the Free Market, mainly due to the growth of 19.6% our subsidiary CPFL Brasil, which positive result was arising from the successful sales drive directed towards industrial customers in the Free Market.  Additionally, industrial consumers in our distribution concession areas that buy 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 audited financial statements under “Other Operating Revenues”.

Sales to wholesalers

Compared to the year ended December 31, 2012, our gross operating revenues from sales to wholesalers increased 20.8% (or R$434 million) to R$2,522 million in the year ended December 31, 2013 (13.0% of gross operating revenues), due mainly to (i) an increase of 7.3% (or R$30 million) in sales to Furnas as a result of the tariff increase of 7.8% in relation to the effect of the IGP‑M and (ii) an increase of 26.8% (or R$396 million) in sales of electricity to the other concessionaires and licensees mainly by the growth in sales of electricity from our conventional generation subsidiaries (R$72 million) and renewable generation subsidiaries (R$250 million). For more information on net operating revenues from our segments, see “—Sales  by Segment”.

Other operating revenues

Compared to the year ended December 31, 2012, our other gross operating revenues decreased 5.5% (or R$170 million) in the year ended December 31, 2013 to R$2,939 million (15.2% of our gross operating revenues), mainly due to (i) the decrease of 31.6% (or R$447 million) in TUSD revenue for making the electric grid available arising from the RTE in the year ended December 31, 2013, applied to consumption from January 24, 2013, (ii) thedecrease of 25.7% (or R$347 million) in revenue relating to the construction of concession infrastructure, as a result of lower investments, (iii) partially offset by the increase of R$576 million with reference to accounting for the low income subsidy and discounts on tariffs reimbursed by funds from the CDE Account.

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Deductions from operating revenues

We deduct certain taxes and industry charges from our gross operating revenue to calculate net revenue.  The state‑level value‑added tax (ICMS), federal PIS and COFINS taxes, and the research and development and energy efficiency programs (regulatory charges) are calculated based on gross operating revenue, while other regulatory charges vary depending on the regulatory effect reflected in our tariffs.  These deductions represented 24.3% of our gross operating revenue in the year ended December 31, 2013 and 29.9% in the year ended December 31, 2012.  Compared to the year ended December 31, 2012, these deductions decreased 26.0% (or R$1,652 million) to R$4,706 million in 2013, mainly due to: (i) a reduction of 12.6% (or R$401 million) in ICMS, as a result of the drop of 13.3% in the our billed supply; (ii) a reduction of 8.8% (or R$147 million) in PIS and COFINS, basically due to the reduction in our gross operating revenues (the calculation base for these taxes); and (iii) by the net effect of the decrease of 73.2% (or R$1,105 million) in regulatory charges, as a result of changes in ANEEL regulations in Law 12,7833/13 of 2013.  See explanatory note 27 to our audited financial statements.

Sales by segment

Distribution

Compared to the year ended December 31, 2012, our net operating revenues from our Distribution segment decreased 6.7% (or R$835 million) to R$11,579 million in the year ended December 31, 2013.  This decrease was primarily reflected: (i) the decline in the average tariffs charged as a result of Law 12,783/13, which ANEEL ratified the result of the RTE in 2013 for our distribution companies, applied to consumption from January 24, 2013 and tariff adjustments, impacting the electricity sales to Captive Consumers (a decrease of R$2,154 million) and TUSD revenue from Free Consumers (a decrease of R$454 million) in our concession areas; (ii) the decrease R$354 million in revenue from construction of concession infrastructures, as a result of lower investments in improving and expanding of our distribution subsidiaries; and (iii) a decrease of R$139 million in sales to wholesalers, mainly due to a reduction in short‑term energy sales in the CCEE as a result of decline in the amount of electric energy sold mainly by subsidiaries CPFL Paulista, CPFL Piratininga and RGE, partially offset by (a) an increase of R$576 million with reference to accounting for the low income subsidiary and discounts on tariffs reimbursed by funds from the CDE Account and (b) a decrease (which represents an increase in the operating revenues) of R$1,723 million in deductions from operating revenues mainly due to a reduction of R$610 million in taxes (ICMS, PIS and COFINS) and by a net reduction of R$1,102 million in regulatory charges.

Generation (conventional sources)

Net operating revenues from our generation from Conventional Sources segment in the year ended December 31, 2013 amounted to R$926 million, an increase of 11.8% (or R$97 million) compared to R$828 million in the year ended December 31, 2012.  This increase was mainly due to an increase of 16.2% (or R$72 million) in sales to our distribution subsidiaries, arising from an increase of 10.6% in the volume sold in this period.

Generation (renewable sources)

Net operating revenues from our generation from Renewable Sources segment in the year ended December 31, 2013 amounted to R$1,084 million, an increase of 32.4% (or R$265 million) compared to R$818 million in the year ended December 31, 2012.  This increase was mainly due to increased production by the new Biomass Thermoelectric Power Plants in operation since the second semester of 2012, as well as the good performance of the wind farms, besides the contribution of the acquisitions of Bons Ventos S.A. and the Ester Thermoelectric Power Plant, held in 2012.

Commercialization

Net operating revenues from our Commercialization segment in the year ended December 31, 2013 amounted to R$1,845 million, a decrease of 2.2% (or R$42 million) compared to R$1,886 million in the year endedDecember 31, 2012.  The decrease was mainly due to a reduction of 25.4% (or R$186 million) in the volume sold to other concessionaires and licensees, partially offset by an increase of 13.6% in average price and an increase of R$128 million in sales to CCEE.

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Services

Net operating revenues from our Services segment in the year ended December 31, 2013 amounted to R$201 million, an increase of 16.9% (or R$29 million) compared to R$172 million in the year ended December 31, 2012.  The increase was mainly due to the increased sales by CPFL Serviços (both third parties and to other our subsidiaries), reflect from an effort to increase the range of electricity‑related services, and by an increase in the transactions volume of CPFL Total.

Income from Electric Energy Service by Destination

Cost of Electric Energy

Electricity purchased for resale.  Compared to the year ended December 31, 2012, our costs to purchase energy for resale increased 11.0% (or R$739 million) in the year ended December 31, 2013, to R$7,469 million (60.9% of our total operating costs and operating expenses), mainly due to an increase of 20.4% in the average price, reflecting the greater exposure and variation in the PLD, tariff adjustments and the exchange rate variations in the purchase of Itaipu.

Electricity network usage charges.  Compared to the year ended December 31, 2012, our charges for use of the transmission and distribution system decreased 52.2% (or R$795 million) to R$728 million in the year ended December 31, 2013, mainly as a result of: (i) a reduction of R$568 million in the Basic Network  Charges due to the decrease in the tariffs of the transmission companies; and (ii) a reduction of R$157 million in the System Service Charges, net of reimbursement of costs by CDE Account.  For further information about electricity network usage charges, see the explanatory note 28 to our audited financial statements.

Other costs and operating expenses

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

Compared to the year ended December 31, 2012, our other costs and operating expenses decreased 5.5% (or R$235 million) to R$4,067 million in the year ended December 31, 2013, mainly due to the following important events: (i) a decrease of R$347 million in infrastructure construction costs for investments in improving and expanding distribution; (ii) a decrease of R$94 million of loss on disposal and decommissioning and other losses on noncurrent assets; (iii) a decrease of R$93 million in the allowance for doubtful accounts arising basically from receivables from consumers at our distribution subsidiaries; (iv) a decrease of R$54 million in  outsourced services, results of a drop in general operating expenses; (v) partially offset by an increase of R$242 million in legal, judicial and indemnity expenses; (vi) an increase of R$64 million in depreciation and amortization, mainly as a result of the commencement of operations of CPFL Renováveis’ new investments of R$59 million; and (vii) an increase of R$28 million in employee pension plans, as result of the actuarial report for 2013.

Income from Electric Energy Service

Compared to the year ended December 31, 2012, our income from electric energy service increased 1.5% (or R$35 million) to R$2,370 million in the year ended December 31, 2013, due to the reduction in our net operating revenue by the decrease in our cost of electric energy and by operating costs and expenses.

Income from Electric Energy Service by Segment

Distribution

Compared to the year ended December 31, 2012, income from electric energy service from our Distribution segment increased 13.0% (or R$179 million) to R$1,551 million in the year ended December 31, 2013.  Despite thedecrease of 6.7% (or R$835 million) in net operating revenues, the cost and operational expenses decreased 9.2% (or R$1,014 million), which resulted in an increase in the income from electric energy service.  The main variations on cost and operational expenses were:

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Electricity costs.  Compared to the year ended December 31, 2012, electricity costs decreased 9.1% (or R$687 million), to R$6,851 million in the year ended December 31, 2013.  The cost of energy purchased for resale increased 2.1%, (or R$128 million), reflecting an increase of average prices, arising from the greater exposure and variation in the PLD, tariff adjustments and the exchange rate variations in the purchase from Itaipu.  Although this increase would be passed along through tariffs in 2013 or 2014, part of it had to be reimbursed by the CDE account or by the ACR Account instantly, otherwise distribution companies would not be able to afford the high costs of energy performed in 2014. Charges for use of the transmission and distribution system decreased 54.5% (or R$814 million), mainly due to a reduction of R$574 million in the Basic Network Charges due to the decrease in the tariffs of the transmission companies. There was also a reduction of R$157 million in the System Service Charges, net of reimbursement of costs by CDE Account.  A significant part of the increase in these costs was not included in the distribution tariffs and will be passed along in the next tariff adjustment.

Other costs and operating expenses.  Compared to the year ended December 31, 2012, our other costs and operating expenses for the Distribution segment decreased 9.3% (or R$327 million), to R$3,177 million in the year ended December 31, 2013, mainly due to (i) a decrease of R$354 million in infrastructure construction costs for investments in improving and expanding distribution; (ii) a decrease of R$77 million of loss on disposal and decommissioning and other losses on noncurrent assets; (iii) a decrease of R$94 million in the allowance for doubtful accounts arising basically from receivables from consumers at our distribution subsidiaries; (iv) a decrease of R$43 million in  outsourced services, results of a drop in general operating expenses; (v) partially offset by an increase of R$236 million in legal, judicial and indemnity expenses; and (vi) an increase of R$26 million in employee pension plans, as result of the actuarial report for 2013.

Generation (conventional sources)

Compared to the year ended December 31, 2012, income from electric energy service from our Conventional Generation segment increased 12.7% (or R$63 million) to R$560 million in the year ended December 31, 2013.  This increase was mainly due to an increase of 11.8% (or R$97 million) in net operating revenue, offset by an increase of 10.4% (or R$35 million) in cost and operational expenses, primarily by (i) an increase of R$39 million in electricity purchased for resale arising from the increase in average prices; (ii) an increase of R$4 million in employee pension plans, as result of the actuarial report for 2013; and (iii) partially offset by a decrease of R$7 million in outsourced services, results of a drop in general operating expenses, which resulted in an increase in the income from electric energy service.

Generation (renewable sources)

Compared to the year ended December 31, 2012, income from electric energy service from our Renewable Generation segment decreased 0.2% (or R$0.4 million) to R$215 million in the year ended December 31, 2013.  Despite the increase of 32.4% (or R$265 million) in net operating revenues, the cost and operational expenses increased 44.1% (or R$266 million) mainly due to: (i) an increase of R$199 million in electricity purchased for resale, as a result of the extraordinary  purchase of electricity in order to honor the electricity sale contracts of Coopcana, Alvorada and Complexo Atlântica, due to a change in the expected time of construction, (ii) an increase of R$42 million in depreciation and amortization due to CPFL Renováveis’ commencement of operations at greenfield plants, and (iii) an increase of R$18 million in personnel expense as a result of the effects of the 2013’s collective labor, the expenditure on severance pay and indemnities in 2013, a higher expedinture on pension funds and increases in employee benefits.

Commercialization

Compared to the year ended December 31, 2012, income from electric energy service from our Commercialization segment decreased 79.6% (or R$203 million), to R$52 million in the year ended December 31,2013.  This decreased was due to a reduction of 2.2% (or R$42 million) in net operating revenues and by an increase of 9.9% (or R$162 million) in costs and expenses primarily due to an increase of R$159 million in electricity purchased for resale, arising from an increase of 21.5% in the average price, partially offset by a reduction of 9.5% in the volume of energy purchased.

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Services

Compared to the year ended December 31, 2012, income from electric energy service from our Service segment decreased 49.3% (or R$13 million), to R$13 million in the year ended December 31, 2013.  Despite the increase of 16.9% (or R$29 million) in net operating revenues, the cost and operational expenses increased 28.8% (or R$42 million) mainly due to an increase of R$17 million in personnel, as a result of an increase of employees at CPFL Serviços and effects of the 2013’s collective labor, and by an increase of R$16 million materials and outsourced services, both arising from the expanding of CPFL Serviços activities.

Net Income

Net Financial Expense

Compared with the year ended December 31, 2012, our net financial expense increased 68.1% (or R$394 million), from R$578 million in 2012 to R$971 million in the year ended December 31, 2013, mainly due to: (i) a decrease of R$8 million in our financial income and an increase of R$386 million in our financial expense.

The reduction in financial income is because of the main following reasons: (i) R$159 million in the adjustment in the estimated cash flow of the financial assets of concession in 2012; (ii) reduction of R$24 million in arrears of interest and fines, partially offset by: (iii) an increase of R$116 million income from financial investments; and (iv) an increase of R$68 million in monetary adjustment of escrow deposits.

The reasons of the increase in financial expenses are: (i) an increase in the debt charges and monetary and exchanges variations (R$281 million), as a result of the increased indebtedness; and (ii) by the adjustment in the estimated cash flow of the financial assets of concession (R$67 million). 

At December 31, 2013, we had R$15,013 million in debt denominated inreais, which accrued both interest and inflation correction based on a variety of Brazilian indexes and money market rates.  We also had the equivalent of R$2,008 million of debt denominated in U.S. dollars.  In order to reduce the risk of exchange losses with respect to these U.S. dollar‑denominated debts and variations in interest rates, we have the policy of using derivatives to reduce their risks of variations in exchange and interest rates.  The average CDI index variation rate posted an increase of 7.8% in 2013, compared to 8.4% in 2012, and the TJLP decreased 5% in 2013, compared to 5.8% in 2012.

Income and Social Contribution Taxes

Our net charge for income and social contribution taxes decreased from R$671 million in the year ended December 31, 2012 to R$570 million in the year ended December 31, 2013.  The effective rate of 37.5% on pretax income in the year ended December 31, 2013 was higher than the official rate of 34%, principally due to our inability to use certain tax loss carryforwards, as described in note 9.5 to our consolidated financial statements.

Net Income

Compared to the year ended December 31, 2012, and due to the factors discussed above, net income decreased 21.4% (or R$258 million), to R$949 million in the year ended December 31, 2013.

Net Income by Segment

In the year ended December 31, 2013, 76.5% of our net income derived from our Distribution segment, 32.9% from our generation from Conventional Sources segment, -5.8% from our generation from Renewable Sources segment, 3.8% from our Commercialization segment and 1.7% from our Services segment.  

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Distribution

Compared to the year ended December 31, 2012, net income from our Distribution segment decreased 12.2%, or (R$101 million), to R$726 million in the year ended December 31, 2013, as result of the increase of 13.2% or (R$181 million) in income from electric energy service, partially offset by an increase of R$328 million in net financial expenses, mainly due to: (i) a decrease of R$54 million in the financial income arising from the adjustment in the estimated cash flow of the financial assets of concession (R$159 million); (ii) a reduction of R$26 million in arrears of interest and fines,  (iii) an increase of R$68 million income from financial investments; (iv) an increase of R$40 million in monetary adjustment of tax credits; and (v) an increase of R$28 million in monetary adjustment of escrow deposits,  partially offset by: (i) an increase of R$274 million in our financial expense mainly arising from the debt charges and monetary and exchanges variations (R$173 million) as a result of the higher indebtedness; (ii) an increase in the adjustment in the estimated cash flow of the financial assets of concession (R$67 million); and (iii) a decrease of R$45 million in expense of income and social contribution taxes.

Generation (conventional sources)

Compared to the year ended December 31, 2012, net income from our Generation from Conventional Sources segment decreased 10.5% (or R$37 million) to R$312 million in the year ended December 31, 2013, as result of: (i) the increase of 12.7% (or R$63 million) in income from electric energy service, partially offset by an increase of R$103 million in net financial expenses, mainly reflecting an increase of R$110 million in financial expenses (mainly due to an increase of R$120 million in debt charges and monetary and exchanges variations); (ii) an increase of R$7 million in financial income arising of income from financial investments; and (iii) a decrease of R$3 million in income and social contribution tax expenses.

Generation (renewable sources)

Compared to the year ended December 31, 2012, net loss from our Generation from Renewable Sources segment was R$55 million in the year ended December 31, 2013 (representing a R$63 million difference when compared to 2012 profit), as result of the decrease of 0.2% (or R$0.4 million) in income from electric energy service, added to an increase of R$61 million in net financial expenses, mainly reflecting an increase of R$110 million in the financial expenses and an increase of R$1 million in expense of income and social contribution taxes.

Commercialization

Compared to the year ended December 31, 2012, net income from our Commercialization segment decreased 65.0% (or R$66 million), to R$36 million in the year ended December 31, 2013, reflecting the decrease of R$203 million in the income from electric service, offset by an increase of R$106 million in net financial income and by a reduction in expense of income and social contribution taxes in R$31 million.

Services

Compared to the year ended December 31, 2012, net income from our Services segment decreased 40.1% (or R$11 million), to R$16 million in the year ended December 31, 2013, reflecting a decrease of R$13 million in income from electric energy service, added to a decrease of R$3.7 million in net financial expenses, offset by a decrease of R$6 million in expense of income and social contribution taxes.

Liquidity and Capital Resources

On December 31, 2014, our working capital reflected a superavit (excess of current assets over current liabilities) of R$1,798 million, a reduction of R$561 million compared to R$2,359 million at December 31, 2013. The main causes of this decrease are:

(i)            the transfer from noncurrent to current liabilities of the balance of debentures of R$ 2,007 million set to mature within the next 12 months, partially offset by:

(ii)           an increase of current receivables of R$352 million related to resources provided by the CDE Account;

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(iii)          an increase of net current receivables of R$589 million related to sector financial assets;  and

(iv)          the transfer from noncurrent to current of our financial asset of concession in R$540 million (this amount refers to the estimated indemnization of the five distributors whose concessions expire in July 2015).

Sources of Funds

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

Cash Flow

For ease of reference, lists of items and amounts explaining any increases or decreases in the discussion below are listed in the same order that such line items appear in our applicable financial statements.

Our net cash provided by operating activities was R$1,593 million in the year ended December 31, 2014, compared to R$2,518 million in the year ended December 31, 2013, which decreased 36.7%.  The decrease of R$925 million primarily reflected adjustments to reconcile income to cash provided by operating activities.  The main causes are:

(i)an increase in receivables of R$207 million related to resources provided by the CDE Account (which represents a reduction in cash generation);

(ii)a net increase of receivables of R$911 million related to sector financial assets of concession (which means income higher than the cash generation); partially offset by

(iii)increase of interest and monetary adjustment of R$192 million (which represents an expense with no immediate cash outflow).

Our net cash provided by operating activities was R$2,518 million in the year ended December 31, 2013, compared to R$1,989 million in the year ended December 31, 2012.  The increase of R$529 million primarily reflected: (i) an increase of R$282 million of net income adjusted for the reconciliation of net cash; (ii) a decrease of R$577 million in operating assets (which represents an increase in the cash provided by operating activities) basically due to a reduction of R$691 million in accounts receivables from consumers, concessionaires and licensees (reflecting the decline in our gross operating revenue, comparing 2013 to 2012), a reduction in escrow deposits and a reduction in dividends and interest on equity received, partially offset by an increase related to resources provided by the CDE Account in the amount of R$121 million; and (iii) a decrease of R$312 million in cash as result of a reduction in operating liabilities mainly due to a reduction of R$369 million in suppliers, in regulatory charges and in reserve for tax, civil and labor risks paid, and partially offset by an increase of R$63 million for other taxes and social contribution expenses, advances from Eletrobrás (resources provided by the CDE Account) and other operating liabilities, and (iv) an increase of R$19 million, which represents the net effect of payment of interest, income tax and social contribution.

Our net cash from financing activities was a consumption of R$509 million in the year ended December 31, 2014 compared to a generation of R$948 million in the year ended December 31, 2013.  This reduction of R$1,457 million was due to: (i) the reduction of fund‑raising from loans, financing and debentures of R$2,772 million and (ii) the effect of R$329 million of the CPFL Renováveis’ initial public offering that occurred in 2013 partially offset by (i) a decrease of R$1,820 million related to payments of loans, financing, debentures and derivatives and (ii) an increase of R$178 million in dividend payments (which represents a decrease in cash generated).

Our net cash from financing activities was R$948 million in the year ended December 31, 2013 compared to R$1,143 million in the year ended December 31, 2012.  This reduction of R$194 million was due to an increase of R$2,762 million related to payments of loans, financing and debentures (net of derivatives), mainly from our distribution and generation subsidiaries (which represents a decrease in cash), partially offset by the following fund‑raising: (i) the initial public offering of our indirect subsidiary CPFL Renováveis, which occurred in 2013(R$329 million); (ii) an increase of loans, financing and debentures obtained (R$1,672 million); and (iii) a decrease of R$568 million in dividend payments (which represents an increase in cash generated).

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Indebtedness

The following table sets forth our current and noncurrent liabilities (in millions) for the year ended December 31, 2014:

	2014
	Current	Noncurrent
Secured debt	810	6,251
Unsecured debt	6,607	12,046
Total	7,417	18,297

Our total indebtedness increased R$2,129 million, or 12.5%, from December 31, 2013 to December 31, 2014, mainly as result of:

·Debentures issuances in the total amount of R$1,005 million, by (i) CPFL Geração (R$ 705 million) and (ii) CPFL Renováveis (R$ 300 million).  In addition to the normal issuances, we have consolidated the first and second debentures issuance of WF2 and its subsidiary DESA, in the total amount of R$262 million, due the acquisition of WF2 on October 1, 2014.

·Loans from BNDES through the Fund for the Financing and Acquisition of Machinery and Equipment (Fundo para Financiamento e Aquisições de Máquinas e Equipamentos), or FINAME, and Financing and Entrepreneurship (Financiamento e Empreendimentos), or FINEM, in the total amount of R$543 million primarily to fulfill the biannual investment plan for our largest distribution subsidiaries (R$91 million) and services companies (R$63 million) as well as to fulfill required investments for our renewable generation subsidiaries (R$389 million); and

·Fund‑raising in the amount of R$1,574 million (which R$1,313 million is U.S. dollar‑denominated debt) at most of our distribution subsidiaries and at our indirect subsidiary CPFL Renováveis, to reinforce of working capital and debt payments, refinance maturing debt and to fulfill required investments for our renewable generation subsidiaries.

The main purpose of these financings were to (i) finance the investments of our distribution companies, and (ii) invest in our Generation from Renewable Sources segment.

In 2015 and 2016, we expect to continue to take advantage of the financing opportunities offered by the market through issuing debentures and debt for working capital, both in the domestic and overseas markets, and those offered by the government through lines of financing provided by BNDES, in order to expand and modernize the electricity system, to undertake new investments in the Generation segment (both from Conventional Sources and Renewable Sources) and to be prepared for possible consolidation in the sector.

Moreover, fundraising seeks to maintain the liquidity of the group and a good debt profile through extending the average maturity of our debt and reducing its cost.

Terms of Outstanding Debt

Total debt outstanding at December 31, 2014 (including accrued interest) was R$19,150 million.  Of this total amount, approximately R$3,441 million, or 18.0%, was 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.  The amount of R$3,526 million of our total outstanding debt is due in 12 months.

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Our major categories of indebtedness are as follows:

·BNDES.  At December 31, 2014, we had R$5,331 million outstanding under a number of facilities provided through BNDES.  These loans are denominated inreais.  The most significant part of these loans relates to: (i) loans to our indirect generation subsidiaries, CPFL Renováveis and CERAN (R$3,974 million); (ii) financing of investment programs for our distribution subsidiaries, primarily CPFL Paulista, CPFL Piratininga and RGE (R$1,269 million); and (iii) loans to our subsidiaries CPFL Serviços, CPFL Brasil, CPFL Esco, CPFL Telecom and CPFL Transmissão (R$ 88 million).

·Debentures.  At December 31, 2014, we had indebtedness of R$8,472 million outstanding under several series of debentures issued by CPFL Energia, CPFL Paulista, CPFL Piratininga, RGE, CPFL Santa Cruz, CPFL Brasil, CPFL Geração and CPFL Renováveis.  The terms of these debentures are summarized in note 18 to our audited annual consolidated financial statements.

·Working capital.  At December 31, 2014, we had R$1,444 million outstanding under a number of loan agreements indexed to the CDI relating to working capital for our distribution, generation and services subsidiaries.

·Otherreal‑denominated debt.  As of December 31, 2014, we had R$483 million outstanding under a number of otherreal‑denominated facilities. 

·Other U.S. dollar‑denominateddebt.  At December 31, 2014, we had the equivalent of R$3,441 million outstanding under other loans denominated in U.S. dollars (US$1,296 million).  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations. 

For more details on our loans, debentures and derivatives please see notes 17, 18 and 35 to our audited annual consolidated financial statements.

Financial and Operating Covenants

We are subject to financial and operating covenants under our financial instruments and those of our subsidiaries. The main parameters established by financial institutions under these instruments are: (i) net indebtedness divided by EBITDA; (ii) net indebtedness divided by the sum of net indebtedness and net equity; (iii) maintaining the debt coverage ratio and own capitalization ratio and (iv) other restrictions such as restrictions on the payment of dividends to our subsidiaries.

Our Management and that of our subsidiaries monitor these ratios systematically and constantly to ensure that we and our subsidiaries remain in compliance with such contractual conditions.  In the opinion of our Management and that of its subsidiaries and joint-ventures, we were in compliance with these restrictive covenants and clauses as at December 31, 2014.

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

Uses of funds

Our cash flow used for investing activities was R$933 million in the year ended December 31, 2014 compared with R$1,695 million in the year ended December 31, 2013.  This decrease of R$762 million (44.9%) primarily reflects a reduction of R$538 million in purchases of property, plant and equipment mainly due to lower investments in power generation from renewable sources and a reduction of R$135 million in intangibles mainly from lower investments in improving and expanding distribution, partially compensated for by a cash inflow from the acquisition of DESA in the amount of R$139 million.

Our cash flow used for investing activities was R$1,695 million in the year ended December 31, 2013 compared with R$3,361 million in the year ended December 31, 2012.  This decrease of R$1,666 million primarily reflects: (i) a reduction of R$145 million in purchases of property, plant and equipment mainly by lower investmentsin power generation from renewable sources, and a reduction of R$581 million in intangibles mainly from lower investments in improving and expanding distribution; and (ii) a decrease of R$879 million related to the acquisitions of the Atlântica Complex, Bons Ventos Wind Farm and the Ester Plant (SPE Lacenas) in 2012.

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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 renewable generation projects.  See “—Capital Expenditures” below for a discussion of our historical and planned capital expenditures;

·Repayment or refinancing maturing debt.  At December 31, 2014 we had outstanding debt maturing during the following 12 months in the total amount of R$3,526 million; and

·Dividends on a semiannual basis.  We paid R$987 million in dividends in 2014 and R$816 million in dividends in 2013.  These amounts exclude dividends paid by our controlled subsidiaries to non-controlling shareholders.  See “Item 10.  Additional Information—Interest Attributable to Shareholders’ Equity” and Note 25.5 to our audited annual consolidated financial statements.

CPFL Energia has adopted, since the second half of 2011, a pre‑funding strategy in order to acess the capital markets at more favorable conditions.  It may either retire the debt due in advance or carry cash to improve its liquidity. CPFL Energia continued to employ this strategy during 2014 in relation to debt due in 2015 and will continue to apply it in 2015 in relation to debt due in 2016.  By applying this strategy, we aim to reduce CPFL Energia’s future cash flow exposure as well as its exposure to interest rate risk.

Capital Expenditures

Our principal capital expenditures in the past several years have been for the maintenance and upgrading of our distribution networks and for our generation projects.  The following table sets forth our capital expenditures for years ended December 31, 2014, 2013 and 2012:

	Year ended December 31,
	2014	2013	2012
	(in millions ofreais)
Distribution	702	845	1,403
Conventional Generation	14	10	13
Renewable Generation	251	828	1,022
Commercialization and other investments	94	52	22
Total	1,062	1,735	2,460

In addition to the capital expenditures shown above, we invested R$57 million for the year ended December 31, 2014 and R$7 million for the year ended December 31, 2013 related to the construction of CPFL Transmissão’s transmission lines, which, in accordance with the requirements of IFRIC 12, was recorded as a financial asset of concession in noncurrent assets.

We plan to make capital expenditures aggregating approximately R$1,557 million in 2015 and approximately R$2,659 million in 2016.  Of total budgeted capital expenditures over this period, R$2,272 million are expected to be invested in our Distribution segment, R$1,741 million in our Renewable Generation segment and R$32 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$171 million in our commercialization and services activities.  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 “Item 4.  Information on the Company—Generation of Electricity”.

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Dividends

On August 27, 2014, our Board of Directors approved the declaration of an interim dividend in the amount of R$422 million, equivalent to R$0.438746730 per share, based on our results for the first six months of 2014.  On March 25, 2015 our Board of Directors approved the allocation of R$555 million from our accumulated profit for the year 2014 to our statutory reserve – working capital improvement account.  Additionally, this reserve will be proposed to be capitalized by issuing new shares to our shareholders.  This proposal will be submitted for approval at the Extraordinary General Meeting called for April 29, 2015.  The decision to allocate it to reserves reflected the economic climate in Brazil, the current hydrological unpredictability, and uncertain projections regarding the electricity distribution market due to energy efficiency campaigns and extraordinary tariff increases.

During 2014, we made dividend payments of R$987 million (R$565 million relating to dividends declared in 2013).  See note 25.5 to our audited annual consolidated financial statements for additional information. 

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2014 (including our noncurrent contractual obligations).  

	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, 2014:
Suppliers	2,375	2,375	-	-	-
Debt obligations(1)	26,265	4,945	8,008	8,636	4,676
Public utilities(1)	85	4	8	8	65
Post-employment benefit(2)	1,964	125	255	265	1,319
Other	292	258	16	-	18
Total of Balance Sheet items(1)	30,981	7,707	8,287	8,909	6,078
Electricity purchase agreements(3)	128,203	10,562	20,541	20,843	76,255
Generation projects(4)	1,049	173	877	-	-
Supplies	2,307	1,262	806	69	170
Total of other commitments	131,559	11,997	22,224	20,912	76,425
Total of contractual obligations	162,541	19,704	30,511	29,821	82,503

(1)   Includes interest payments, including future interest projected cash flow based on undiscounted, through index projections.  These future interests are not recorded on our Balance Sheet.

(2)   Estimated future contributions to the post-employment benefit.

(3)   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 2014 price.  See “—Background—Prices for Purchased Electricity” and note 36 to our audited annual consolidated financial statements.

(4)   The power plant construction projects include commitments made basically to make funds available for construction and acquisition of concession related to the subsidiaries in the Renewable Energy segment.

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, solar 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 concessionaires 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 programsthrough 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.

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Our disbursements on research and development projects in the years ended December 31, 2014, 2013 and 2012 totaled million R$120 million, R$132 million and R$159 million, respectively.

Off‑Balance Sheet Arrangements

As of December 31, 2014, we had no off‑balance sheet arrangements that have or are reasonably likely to have a material impact on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

We have used the following amounts of our current funding arrangements:

			In 2014 (in thousands ofreais)
Modality	Approval	Company	Debt	Released	Balance
BNDES / Investment – FINEM VI	In 2012	CPFL Paulista	790,000	528,223	261,777(1)
BNDES / Investment – FINEM V	In 2012	CPFL Piratininga	220,000	144,306	75,694(1)
BNDES / Investment – FINEM VI	In 2012	RGE	274,997	239,505	35,492(1)
BNDES / Investment – FINEM VI	In 2012	CPFL Renováveis	85,244	81,339	3,905(1)
BNDES / Investment – FINEM XII	In 2012	CPFL Renováveis	211,691	207,296	4,395(1)
BNDES / Investment – FINEM XIII	In 2013	CPFL Renováveis	389,311	356,181	33,130
BNDES / Investment – FINEP I	In 2013	CPFL Renováveis	20,728	6,921	13,806
BNDES / Investment – FINEP II	In 2014	CPFL Renováveis	379,948	314,991	64,957
BNDES / Investment – FINEP III	In 2014	CPFL Renováveis	88,095	10,348	77,747
BNDES / Investment – FINEM	In 2014	CPFL Santa Cruz	25,360	21,891	3,469
BNDES / Investment – FINEM I	In 2014	CPFL Leste Paulista	13,045	6,655	6,390
BNDES / Investment – FINEM	In 2014	CPFL Sul Paulista	12,280	6,945	5,335
BNDES / Investment – FINEM V	In 2014	CPFL Jaguari	10,398	4,110	6,288
BNDES / Investment – CCB Santander	In 2014	CPFL Mococa	6,119	2,524	3,595
BNDES / Investment – FINEME	In 2014	CPFL Transmissão	23,824	13,054	10,770
BNDES / Investment – FINEM	In 2014	CPFL Telecom	95,333	34,918	60,415

(1) Outstanding balance was canceled.

Trend Information

We invest in innovation and technology to improve the quality of our services and our operational efficiency, which are our perennial goals.  The Tauron Program – focused on smart metering for high and medium voltage consumers and on the excellence of workforce management by the use of tablets and new software – will increase our operational efficiency in the near future.  We have already deployed 24,554 smart meters in the field, reaching the conclusion of the project implementation. Currently, our eight distribution companies are already operating under the new data dispatch system for emergency services. 

 Additionally, we seek to promote growth in each of our business segments: Distribution, Conventional Generation Sources, Renewable Generation Sources, Commercialization and Services.

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).

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.

According to projections from the FOCUS report, published on February 6, 2015 by the Brazilian Central Bank, GDP is expected to grow 0.0% in 2015 and 1.5% in 2016.  Despite the modest growth scenario estimated for 2015 and 2016, the energy consumption in residential and commercial segments are expected to continue to grow, albeit at a slower pace than that observed in recent years, since these segments are favored by an anticipated low unemployment rate, the improving quality of the workforce, the maintenance of social programs (e.g.Minha Casa,Minha Vida andMinha Casa Melhor) and large events, such as the Olympic Games in 2016.  Industrialperformance, on the other hand, will retract as a result of increased inflation, which is a threat that may lead to higher interest rates and lower investments, infrastructure deficiencies, weak export volume, a possible reduction in the availability of BNDES loans and a poor small business outlook, due to high stocks of final goods, and an adverse macroeconomic situation.

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Our Generation segment has shown high levels of growth in the last few years, with the acquisition and construction of new plants.  In 2011, the creation of CPFL Renováveis marked an important moment for us.  We plan to continue to expand our generation activities, both in the conventional energy and the renewable energy (wind farms, Small Hydroelectric Power Plants, Biomass Thermoelectric Plants and Solar Power Plants) sectors.  We are currently pursuing this strategy through CPFL Renováveis, with an Installed Capacity of 1,769 MW (of which our share is 915 MW) and 336 MW under construction (of which our share is 173 MW), as well as seeking out new projects.

As of December 31, 2014, we had an Installed Capacity of 3,162 MW. In 2018, we expect to reach an Installed Capacity of 3,336 MW, when the Mata Velha SHPP and Campo dos Ventos, São Benedito, Pedra Cheirosa I and II, and Morro dos Ventos II Wind Farm Complexes will have begun operations.  We also have a 3,767 MW (of which our share is 1,944 MW) portfolio to be developed over the coming years through CPFL Renováveis.  In addition, we will continue to seek out new projects in the conventional energy sector. 

In the Commercialization and Services segment, our main objective is to maintain our leading position, in terms of market share, in order to guarantee our above‑average profitability.  In addition, we expect to expand our portfolio of services, retain the loyalty of our customers and expand our services to new markets.

Since our founding, we have employed a growth strategy based on operational excellence through innovation and technology, synergy, financial discipline and the accumulation of value.  We plan to continue this in the future in order to consolidate our strong position in the energy industry.

CriticalAccounting 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 annual 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 based on historical costs net of accumulated depreciation and amortization.  We are required under IFRS to periodically evaluate whether these assets are impaired, that is, whether their future capacity to generate cash does not justify maintaining them at their carrying values.  The methods used to assess impairment include tests based on the asset’s value in use.  In such cases, the assets (e.g. goodwill and intangible assets of concession) are segregated and grouped together at the lowest level that generates identifiable cash flows (the “cash generating unit”, or CGU).  If they are impaired, we are required to recognize a loss by writing off part of their value to expense in the current period.  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.  Ourevaluations in 2014, 2013 and 2012 did not result in any significant impairment of our property, plant and equipment or intangible assets and investments.

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Impairment of 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 for both specific asset and at a 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 higher or lower 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 asset’s original effective interest rate.  Losses are recognized in profit or loss and shown 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 that the amount of impairment loss has decreased, this reduction is reversed to credit through profit or loss.

·Available‑for‑sale: as 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.  Losses are recognized in profit or loss.

In the case of financial assets registered at amortized cost and/or debt instruments classified as available‑for‑sale, if an increase (gain) is identified in periods subsequent to recognition of the loss, the impairment loss is reversed through profit or loss.  However, any subsequent recovery in the fair value of an impaired available‑for‑sale security is recognized in other comprehensive income.

Pension Liabilities

We sponsor pension plans and disability and death benefit plans covering substantially all of our employees.  The determination of the amount of our obligations for pension benefits depends on certain actuarial assumptions, including discount rate, inflation, etc.

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  evidences are not enough to prove that it is more likely than not that we will 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.

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Provision for Tax, Civil and Labor Risks

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 matters.

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

Financial instruments

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 and Capital Market Institutions (Associação Brasileira das Entidades dos Mercados Financeiros e de Capitais) 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 Brazilian 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 indexes.

Law No. 12,783/13 defined the methodology and criteria for valuation of the compensation on reversion of the assets based on the Regulatory Asset Base.  Accordingly, the valuation of the compensation on reversion is prescribed through a valuation process carried out by ANEEL.

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 in accordance with IFRS.  Amortization of intangible assets varies according to the way they are acquired:

·Intangible assets acquired in a business combination.  The portion arising from business combinations that corresponds to the right to operate the concession is stated as an intangible asset.  Such amounts are amortized over the remaining term of the concessions, on a straight‑line basis or based on the net income curves projected for the concessionaires, as applicable.

·Investments in infrastructure (application of IFRIC 12 – Service Concession Arrangements).  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.

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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 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. Six membersof our currentBoardwere elected at our shareholders’ meeting held on April 29, 2014. However, Mr. Marcelo Pires Oliveira Dias, who was one of those elected members, resigned fromhis position. Therefore, the Board of Director, pursuant to Article 150 of Brazilian Corporate Law, elected Mr. Francisco Caprino Neto, whose election was ratified at the Shareholders’ Meeting held on September 24, 2014. Their terms will expire at our next annual shareholders’ meeting, scheduled to take place on April 28, 2015.  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$10,056,000.00, 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 decision by the CVM, non-controlling 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.  Non-controlling shareholders that own greater than 5.0% of voting shares may request multiple voting (voto múltiplo).

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	67	Chairman
Claudio Borin Guedes Palaia	40	Member
Francisco Caprino Neto	54	Member
Renê Sanda	51	Vice‑Chairman
Deli Soares Pereira	65	Member
Carlos Alberto Cardoso Moreira	61	Member
Maria Helena dos Santos Fernades de Santana	55	Independent Member

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 as Head of Forestry Products, Environment and Metallurgy Area and as the CEO ofCelulose Nipo‑Brasileira S.A (CENIBRA) and Florestas Rio Doce S.A.  Between 1993 and 2006, he was CEO of Bahia Sul Celulose S.A. and subsequently, of Suzano Papel e Celulose S.A.  He was a member of the Board of Directors of Brasil Agro - Companhia  Brasileira de Propriedades Agrícolas between 2007 and 2010.  He is a certified director member of the Brazilian Corporate Governance Institute (IBGC).  Currently, he is a member of the Management Committee of the Board of Directors of Suzano Papel e Celulose S.A., an Honorary Member of the Foundation for the National Quality Award (FNPQ), a member of the Superior Council 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 and of the Financial Committee of São Martinho S.A. and a member of the Board of Directors of Odontoprev S.A., Camil Alimentos S.A. and Tegma Gestão Logística S.A.  Since 2010, he has been the Chairman of our Board of Directors.

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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 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 a project leader in Camargo Corrêa Energia S.A. (CCE), 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.  From 2008 to 2012, he was an executive officer at Intercement Brasil S.A. From 2012 to 2015, he was Chief Financial Officer of Intercement Participações S.A.  He has also been a sitting member of the Board of Directors of São Paulo Alpargatas, CCSA and Intercement Participações S.A. and an alternate member at Companhia de Concessãoes Rodoviárias S.A. (CCR).  In 2009, he was an alternate member of the Board of Directors of CPFL Energia and since 2010, he has been a sitting member of the Board of Directors of CPFL Energia.

Francisco Caprino Neto – Mr. Caprino Neto graduated in Metallurgical Engineering from the University of São Paulo (USP-SP) in 1983 and also obtained a Master’s degree in Metallurgical Engineering from the same institution in 1992.  Mr. Caprino Neto has acted as Head of the Process Engineering Department and Planning and Control Advisor for Siderúrgica J.L. Aliperti S.A., and Coordinator of Metallurgical Processes for Aços Vilares S.A. He was a sitting member of the Boards of Directors of CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE between 2000 and 2005.  He is a certified director member of IBGC.  He has been Superintendent Officer and Chairman of the Board of Directors of Camargo Corrêa Energia S.A. (CCE) and Camargo Corrêa Investimentos em Infraestrutura S.A. (CCII) since 2007, of VBC Energia S.A. since 2009 and of ESC Energia S.A. since 2012.  He has also been a sitting member of the Board of Directors of Companhia de Concessões Rodoviárias S.A. (CCR) since 2004.  He was a sitting member of the Board of Directors of CPFL Energia, from 2004 to April 2013, and a deputy member from April 2013 to August 2014.  Currently, he is a sitting member of the Board of Directors of CPFL Energia.

Renê Sanda – Mr. Sanda graduated in Statistics from USP-SP in 1986, earned a Master’s degree in Statistics from the same institution in 1989, and received an Executive MBA in Finance from the Brazilian Institute of Capital Markets (IBMEC-DF) in 1992.  He participated in the Commercial and Investment Banking Program Professional Development Center administered by Citibank, in Fort Lauderdale (USA) in 1992.  From 2002 to 2006, Mr. Sanda was Deputy General Manager at BB New York (USA) and Assistant Managing Director of Banco do Brasil Securities (USA) between 2005 and 2006.  From 2006 to 2010, he served as Risk Management Director for Banco do Brasil.  He was appointed Chief Investment Office of Previ in 2010 until his retirement in 2014.  He was a member of the Fiscal Council of Tele Amazônia Celular Participações and Telemig Celular Participações from 2000 to 2001 and of CPFL Paulista and CPFL Geração S.A. from 2001 to 2002.  He was also a member of the board of directors of Petroflex S.A. from 2007 to 2008, Fundição Tupy S.A. from 2009 to 2011, Banco do Brasil Securities LLC – New York (USA) from 2006 to 2010, and BB Securities Ltd. – London (UK) from 2006 to 2010.  Currently, Mr. Sanda is a member of the Board of Directors of Fundo Garantidor de Créditos. He has been a sitting member of the Board of Directors of CPFL Energia since 2011 and has been Vice-Chairman since 2013.

Deli Soares Pereira – Mr. Pereira graduated in Social Sciences from the University of São Paulo (USP) in 1979 and earned a graduate degree in Economics and Labor Relations Management from Pontifícia Universidade Católica de São Paulo (PUC‑SP) in 2009.  He was a deputy member of the Boards of Directors of VALE S.A. and VALEPAR S.A. (2000 to 2013).  He has served as a sitting member on the Boards of Directors of Tigre S.A. – Tubos e Conexões (2001 to 2003), SOLPART Participações S.A. (2006 to 2008), CPFL Piratininga, CPFL Paulista,CPFL Geração and CPFL Energia (2004 to 2006).   Mr. Pereira became a member of the Board of Directors of CPFL Energia in 2013.

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Carlos Alberto Cardoso Moreira–Mr. Cardosograduated in Business Administration from Pontifícia Universidade Católica de São Paulo (PUC-SP) in 1984.From 1984 to 1988, he was Senior Investment Analyst of Credibanco. Between 1988 and 1992, he served as Resident Vice President of Citibank N.A.  Mr. Moreira was also the Institutional Client Officer for Banco BMC S.A. from 1992 to 1999.  From 2000 to 2014, he served as the Executive Investment and Finance Officer for Fundação Sistel de Seguridade Social (SISTEL) and is currently its CEO.  He is a certified director member of IBGC.  He is currently a member of the National Investment Technical Committee (CNTI) of Abrapp and a member of the Board of Directors of Geração, Transmissão e Distribuição S.A. (GTD).  Additionally, he is the Managing Director of Bonaire Participações S.A. and a member of the Board of Directors of CPFL.

Maria Helena dos Santos Fernandes de Santana – Ms. Santana graduated in Economics from the School of Economics, Administration and Accounting of the University of São Paulo (FEA‑USP) in 1990.  She was formerly the Chairperson of the Brazilian Securities and Exchange Commission (CVM) from 2007 to 2012, where she served as Commissioner since 2006.  She was also Chair of the Executive Committee of the International Organization of Securities Commissions (IOSCO) from 2010 to 2012.  She worked for the São Paulo Stock Exchange (BOVESPA—now BM&FBovespa S.A.) for 12 years, acting as Head of Listings and Issuer Relations from 2000 to 2006.  She was Vice-Chairman of IBGC from 2004 to 2006 and a member of its Board of Directors from 2001 to 2006.  She is a certified director member of IBGC. She is currently Chair of the Corporate Governance Committee and a member of the Board of Directors of Companhia Brasileira de Distribuição (CBD) and Chair of the Audit Committee and a member of the Board of Directors of TOTVS S.A.  She is also a member of Itaú Unibanco Holiding S.A.’s Audit Committee.  In 2014, Ms. Santana became Trustee of the International Financial Reporting Standards Foundation.  She has been an independent member of our Board of Directors since 2013.

Executive Officers

Our executive officers are responsible for our day‑to‑day management.  Under our bylaws, our board of executive officers is comprised of six 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 on April 24, 2013.

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 Júnior	55	Chief Executive Officer
Gustavo Estrella	40	Chief Financial Officer and Investor Relations Officer
Hélio Viana Pereira	61	Operations Vice-President
José Marcos Chaves de Melo	51	Administrative Vice-President
Carlos da Costa Parcias Junior	54	Business Development Vice-President
Luiz Eduardo Fróes do Amaral Osório	41	Chief Institutional Relations and Legal Officer

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 programs, 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.  Mr. Ferreira Junior is currently the Vice-President of the Brazilian Association of Infrastructure and Basic Industry (ABDIB), a member of the Board of Directors of the National Electrical System Operator (ONS) and has been a member of the Board of Directors of WEG S.A. since 2010. From 2002 to 2011, he was a member of the Board of Directors of CPFL Paulista, CPFL Piratininga, CPFL Geração andRGE.  From 2000 to 2011, he was CEO of CPFL Paulista, and from 2001 to 2011, he was CEO of CPFL Piratininga, CPFL Geração and CPFL Brasil.  He has also been the CEO of CPFL Jaguariúna, Nect, and  certain of our other subsidiaries.  Since 2002, he has been the CEO.  Mr. Ferreira Junior is currently the Chairman of the Board of Directors of CPFL Renováveis and Institution CPFL and the CEO of CPFL Energia S.A.

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Gustavo Estrella – Mr. Estrella graduated from the State University of Rio de Janeiro (UERJ) in Business Administration.  He completed an MBA program in Finance from the Brazilian Institute of Capital Markets (IBMEC-RJ).  He worked at Grupo Lafarge and at the companies Light and Brasil Telecom.  He has worked at CPFL Energia since 2001, where he has been Manager of Economic Planning and Finance, Director of Investor Relations and Director of Planning and Control.  Since February 2013, he has been the Chief Financial Officer and Investor Relations Officer of CPFL Energia and the Finance and Investor Relations Director of CPFL Paulista, CPFL Piratininga, CPFL Geração, RGE amongst other subsidiaries of our group.  Mr. Estrella is currently Vice‑Chairman of the Board of Directors of CPFL Renováveis and a member of the Board of Directors of RGE, CPFL Paulista, CPFL Piratininga and CPFL Geração. 

Hélio Viana Pereira– Mr. Pereira graduated in Electrical Engineering from the Itajubá Federal School of Engineering (EFEI) in 1976 and completed a specialization program in Industrial Quality Engineering at the State University of Campinas (Unicamp).  He completed post‑graduate studies in Electricity Business Management at the Getúlio Vargas Foundation (FGV) and the University of São Paulo (USP).  Mr. Pereira served as an engineer in the Eletrobrás Department of Rural Electrification from 1976 to 1978, as an engineer at the Underground Grid Studies Department and as a manager at the Public Lighting Division of the Companhia de Eletricidade de Brasília (CEB) from 1978 to 1981.  He held several senior positions and was the Operating Control Supervisor and Operations Manager of Companhia Energética de São Paulo (CESP) from 1984 to 1989.  At CPFL Paulista, he served as the Manager of the Planning and Modernization Department from May to August 2000.  He was also the Distribution Officer of CPFL Paulista, CPFL Piratininga, RGE, CPFL Santa Cruz, CPFL Jaguariúna and other of our subsidiaries until 2011 and Chief Executive Officer of CPFL Paulista and CPFL Piratininga until 2013.  Mr. Pereira is currently our Operations Vice-President.

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 Mechanical Engineering from the University of Kansas.  He was won many awards and honors, including the 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. Chaves worked at Accenture from 1987 to 2008, serving as a senior executive from 1998 to 2008.  He was responsible for the execution of several projects with companies in the electricity sector for 12 years, in the oil and gas sectors for five years, in the steel sector for two years, and in the manufacturing sector for one year.  He has experience in several functional areas, such as information technology, supply chain, field work and asset management.  During his career with Accenture, he served companies such as Neoenergia, Light, CEMIG, Duke Energy, Petrobrás, Repsol‑YPF and CSN, the Electric Power Trade Board (CCEE) and ONS.  Mr. Chaves is currently the Administrative Officer of CPFL Paulista, CPFL Piratininga, RGE, CPFL Geração and other of our subsidiaries.  He has been our Administrative Vice-President since 2008.

Carlos da Costa Parcias Junior– Mr. Parcias graduated with a Bachelor’s degree in Economics from the Rio de Janeiro Federal University (UFRJ) in 1984 and a Master’s degree in Economics from the Rio de Janeiro Catholic University (PUC‑Rio) in 1988.  After graduating, he held the following senior leadership positions in the financial industry: Advisor to the Presidency at BNDES (1990 to 1992); Executive Office at JP Morgan Brazil (1992 to 1993); Head of Capital Markets at BBA‑Creditanstalt Bank (1993 to 1995); CEO at BBA‑Capital Asset Management (1996 to 1998); Head of Investment Banking at Fleming Graphus (1998 to 2000); and CEO at Icatu Gestão de Participações (2001 to 2003) focusing on alternative investment management.  From 2004 to 2010, Mr. Parcias had his own Independent Financial Advisory Firm, focusing on mergers and acquisitions and private equity transactions.  In 2011, he was Director of Equity Investments in Energy at Camargo Correa Holding Company and since March 2012, Mr. Parcias has been our Business Development Vice-President.     

Luiz Eduardo Fróes do Amaral Osòrio –Mr. Osório graduated from Pontifícia Universidade Católica do Rio de Janeiro (PUC-RJ) in Law in 1999. He also holds a Master’s Degree in Development Management from the School of International Service at American University – Washington DC (USA), where he was inducted into Pi Alpha Alpha, the National Honors Society for outstanding graduates in Public Affairs and Administration.  Mr.Osório also holds certificates in Executive Education in Corporate Social Responsibility from Harvard Business School, Identifying the Challenges and Building General Management Skills from Insead (France), and Strategy to Execution and Leading in a High Performance Organization from The Wharton School of the University of Pennsylvania.  He has extensive experience in several strategic areas, such as International Relations, Issues Management, Law, Corporate Affairs and Sustainability.  Mr. Osório has held senior leadership and management positions in multinational companies such as AmBev, Diageo, Shell and Raízen, which is based in London. Additionally, he was a sitting member of the Deliberative Council of Brazilian Beverages Association (ABRABE), an Ethical Committee Member at the National Advertising Self-Regulatory Council (CONAR), and a member of the Center for Information on Health and Alcohol (CISA) Fiscal Council. He was also a board member of Brewing Industry National Association (SINDICERV) and the Brazilian Association of Soft Drinks and Non-Alcoholic Beverages (ABIR).  He is currently our Chief Institutional Relations and Legal Officer and a sitting member of the Board of Directors of CPFL Renováveis and Instituto CPFL.

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Fiscal Council

Under Brazilian Corporate Law, theConselho Fiscal, or fiscal council, is a corporate body independent of a company’s management and 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 our financial statements, and to report its findings to our shareholders.  Brazilian Corporate Law requires fiscal council members to receive as remuneration at least 10.0% of the average annual amount paid to our executive officers, excluding benefits and profit sharing.  Non-controlling 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 29, 2014, with a mandate of one year, is composed of five members: William Bezerra Cavalcanti Filho (Chairman), Marcelo de Andrade, Adalgiso Fragoso de Faria, Martin Roberto Glogowsky and Celene Carvalho de Jesus.

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; and (iii) coordinating internal audits and preparing improvement proposals. In addition, the Board of Directors has delegated to this Committee the responsibility for monitoring the initiatives about Sustainability, Environment, and Institutional Communication. The members of this committee areFrancisco Caprino Neto, João Ernesto de Lima Mesquita and Augusto Etchebehere Tavares de Tavares.

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) monitoring the selection process  of the Vice-Presidentsof CPFL Energia and CEOs of controlled companies;(iii)defining criteria for compensation of the executive officers, including long- and short‑term incentives plans; (iv) coordinating evaluation procedures of the executive board; and (v) preparation of the plan of succession of the executive board and (vi) monitoring the execution of human resources policies and practices and preparing improvement proposals when necessary.  The members of this committee areRenê Sanda, Francisco Caprino Neto and Carlos Alberto Cardoso Moreira.

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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 Paola Rocha Ferreira, Francisco Caprino Neto, and Alexandre Jose Fava de Souza Junior.

In addition to the advisory committees, our Board of Directors may createad hoc commissions, if deemed necessary.  The main responsibilities of anad hoc commission include evaluating and addressing specific matters that may arise.  In 2014, our Board of Directorsset upthreead hoccommissions: the Strategy Commission, the Finance and Budget Commission, and the Risk Management Commission.

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 responsible for setting individual compensation levels.

The members of our Board of Executive Officers receive a portion of their compensation directly from us, and a portion from our subsidiaries on an allocation basis in return for services provided to those subsidiaries.  Our subsidiaries do not pay any member of our Board of Directors or Fiscal Council or any of our executive officers for any duties carried out exclusively for CPFL Energia, however.

The table below shows the aggregate compensation paid directly by CPFL Energia to the members of our Board of Directors and Fiscal Council and our executive officers for 2014:

	Compensation for the year ended December 31, 2014
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	7 members(1)	5 members(1)	5.67 members(1)
Fixed annual compensation:	(in thousands ofreais)
Salary	1,528	670	4,588	6,786
Direct or indirect benefits	10	12	46	68
Other	306	134	1,630	2,070
Variable compensation:
Bonus	-	-	4,142	4,142
Other	-	-	1,699	1,699
Post‑employment benefits	-	-	477	477
Total compensation	1,844	816	12,582	15,242

(1)   Represents the weighted average number of members.

The table below sets forth the compensation paid by our subsidiaries to our management for 2014:

	Year ended December 31, 2014
	Board of Directors	Fiscal Council	Executive Officers
	Fixed	Fixed	Total (fixed and variable)
	(in thousands ofreais)
Subsidiaries(1)	-	‑	3,214

(1)   Compensation amounts include charges and accruals.

                The table below shows the aggregate compensation to be paid directly by CPFL Energia to the members of our Board of Directors and Fiscal Council and our executive officers for2015 (excluding any compensation to be paid by our subsidiaries to such individuals):

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	Approved compensation for the year ending December 31, 2015
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	7 members(1)	5 members(1)	6.67 members(1)
Fixed annual compensation:	(in thousands ofreais)
Salary	1,632	716	6,167	8,515
Direct or indirect benefits	-	-	144	144
Other	326	143	1,727	2,196
Variable compensation:
Bonus	-	-	7,836	7,836
Other	-	-	-	-
Post‑employment benefits	-	-	562	562
Total compensation	1,958	859	16,436	19,253

(1)Represents the weighted average number of members.

In addition, the Brazilian CVM requires us to disclose the aggregate compensation paid by the CPFL group to all members of the boards of directors and fiscal councils, and all executive officers, of all companies in our consolidated group.  This aggregate compensation, including cash and benefits in kind, amounted to approximately R$44 million for 2014, including R$14 million in variable compensation.  The total amount set aside or accrued by the CPFL group to provide pension, retirement or similar benefits for the same period was approximately R$1 million.

Our executive officers receive fixed and variable compensation that aims to attract, retain and incentivize these individuals in accordance with our standards of excellence and the goals set forth in our strategic plan.  Members of our Board of Directors and Fiscal Council receive fixed compensation that is not based on individual or organizational performance indicators.

The table below shows the proportion of fixed and variable compensation and benefits paid to members of our Board of Directors and Fiscal Council and our executive officers:

	Board of Directors	Fiscal Council	Executive Officers*
Fixed compensation:	100%	100%	50%
Benefits:	‑	‑	4%
Variable compensation:
Short‑term incentives	‑	‑	24%
Long‑term incentives	‑	‑	22%
Total	100%	100%	100%

(*)          Overall contributions to aggregate compensation.  Proportion of fixed and variable compensation of specific individuals may vary.

Compensation of                 Members of our Board of Directors and Fiscal Council

Members of our Board of Directors and Fiscal Council receive fixed monthly fees that are set in accordance with market standards and reviewed annually.  Since 2012, the Chairman of our Board of Directors has received additional compensation in light of the specific duties of that position.

Compensation of Executive Officers

Our executive officers receive a fixed monthly salary, benefits, and variable incentives.  This compensation policy aims to encourage our executives to seek the greatest returns on our investments and projects through the following tools:

·benefits reflecting market practice;

·short‑term incentives, such as variable salary;

·medium-term incentives, such asbonuses based on pre‑established targets; and

·long‑term incentives, such ascash bonuses under our long-term incentive plan discussed below, through which we aim to create a long‑term vision and foster commitment, aligning the interests of ourexecutive officers and our shareholders and rewarding positive results and the sustainable creation of value.

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This variable compensation policy reflects corporate and individual goals established under our strategic plan and our Shareholder Value Creation System.  Our Human Resources Management Committee tracks and evaluates our executive officers’ performance in accordance with annual goals, which include financial results, individual growth, value creation and human resource management.

Long-term Incentive Plan

Our long‑term incentive plan, known as the ILP, seeks to align the interests of our Eligible Professionals with those of our shareholders, including share price performance, as part of their overall compensation mix, with the aim of fostering long‑term commitment and the consistent and sustainable creation of value.  By linking a share valuation target with our long‑term strategic plan, we seek to align the aims of the ILP with market recognition of the achievement of our strategic plan.  The ILP also aims to incentivize and retain employees who provide the greatest value through their individual performance.  Beneficiaries under the ILP receive cash bonuses after a vesting period when our share price reaches certain targets.  The cash bonuses reflect our stock performance through a “phantom stock” grant mechanism, such that no physical shares are issued.The ILP is reviewed annually by our Board of Directors through the Human Resources Management Committee, and may be suspended at any time.

We measure individual performance under the ILP using a matrix of nine potential and actual performance goals that aims to track whether the individual possesses the necessary skills and potential, and has achieved certain individual targets.  The number of phantom shares granted to each beneficiary is based on targets that follow best practices in the market.

The total expense amount accrued by us related to the ILP was R$7 million as of December 31, 2014.

Compensation or Benefits Linked to Corporate Events

We provide indemnification for our executive officers in the event of a change of control of our company that results in elimination of the officer’s post, termination of the officer by our Board of Directors or a change in working conditions that is deemed to be a constructive termination.  We do not provide any compensation or benefit to members of our Board of Directors or Fiscal Council linked to corporate events.

Pension Plans

We provide pension plans for our executive officers, but not for members of our Board of Directors or Fiscal Council.  The table below summarizes our pension plan arrangements regarding executive officers as at and for the year ended December 31, 2014:         

	Pension Plans for Executive Officers
Name of pension plan	PGBL Bradesco	PGBL Brasil Prev
Number of Executive Officer members	5	1
Number of Executive Officer members eligible for retirement	0	0
Early retirement provisions	None	None
Inflation-adjusted value of pension plan contributions held at year-end, excluding contributions made by beneficiaries (in thousands ofreais)	R$1,054	R$114
Amount of pension plan contributions made during the year, excluding contributions made by beneficiaries (in thousands ofreais)*	R$490	R$5
Provisions for early redemption by beneficiary, if any	At any time, subject to vesting rules.	At any time, subject to vesting rules.

(*)           Inflation-adjusted.

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Share Ownership

The total number of common shares owned by our directors and executive officers as of March 31, 2015 was 103,100.  None of our directors or executive officers beneficially owns one percent or more of our common shares.

Indemnification of Officers and Directors

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

Employees

As of December 31, 2014, we had 9,136 full time employees.  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,
	2014	2013	2012
Distribution	4,706	4,503	5,466
Conventional Generation	108	106	156
Renewable Generation	357	329	267
Commercialization	49	51	64
Services	2,367	1,822	1,589
Corporate staff	1,549	1,580	935
Total	9,136	8,391	8,477

Some 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 26 years that materially affected our operations.

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 2014, we reserved R$63 million (R$56 million of which are booked in current liabilities) 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, 2014.  Percentages in the following table are based on 962,274,260 outstanding common shares. 

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	Common Shares	(%)
BB Carteira Livre I FIA(1)	288,569,602	29.99
ESC Energia S.A.(2)	234,092,930	24.33
Energia São Paulo FIA(3)	141,929,430	14.75
Bonaire Participações S.A.(4)	1,200,000	0.12
Bradespar S.A.(5)	50,541,820	5.25
BNDES Participações S.A.(6)	64,842,768	6.74
Executive officers and directors as a group	103,100	0.01
Total	781,279,650	81.19

(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.

(2) ESC Energia S.A. is controlled by the Brazilian group Camargo Corrêa.

(3)Energia São Paulo Fundo de Investimento em Ações is an investment fund 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 other telecommunication 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) Bonaire Participações S.A. is a holding company controlled by Energia São Paulo Fundo de Investimento em Ações.

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

(6) 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 ESC, PREVI (through BB Carteira Livre I FIA), Energia São Paulo FIA, Bonaire and us, as intervening and consenting party, governs control of us and our subsidiaries.  Under the shareholders’ agreement, certain actions require the approval of at least ESC 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$39 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$10.0 million;

·appointment of our independent auditors in certain specified cases;

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

·amendment of concession agreements of any controlled entity;

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·approval of stock option plans; and

·acquisition, sale or encumbrance of any fixed assets in an amount equal or over R$40.1 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 ESC;

·two appointed by PREVI;

·one appointed by Energia São Paulo FIA/Bonaire; and

·one independent, in accordance with theNovo MercadoListing Rules.

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

·two appointed by ESC;

·two appointed by PREVI; and

·one appointed by Energia São Paulo FIA/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 non-controlling shareholders, exercising their rights under the corporate law, elect the independent director required by the BM&FBOVESPA’sNovo Mercado Listing Rules, ESC, PREVI and Energia São Paulo FIA/Bonaire must abstain from proposing a nominee for the position.  If the non-controlling shareholders do not elect the independent director, ESC, PREVI and Energia São Paulo FIA/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 boards 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 Energia São Paulo FIA/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 Energia São Paulo FIA/Bonaire.  In the event of a sale, assignment or transfer of subject shares by PREVI and ESC that results in an equity percentage lower than 20.0% and 30.0%, respectively, of the aggregate subject shares and, as long as Energia São Paulo FIA/Bonaire has notexercised its right of first refusal, it will have the right to sell its entire stake of subject shares together with PREVI or ESC, 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

We acquired our interest in Semesa from VBC Energia S.A. in December 2001 for R$496 million.  The Semesa acquisition price is subject to adjustment, based on the assessment of Semesa’s Assured Energy.  The earliest that this assessment will take place is 2016.

One of our principal shareholders is ESC.  The controlling shareholder of ESC currently is the Camargo Corrêa Group.  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 also conduct transactions with the shareholders of ESC 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 joint-ventures, BAESA, ENERCAN and Foz do Chapecó, and through its subsidiary, CERAN, has entered into transactions with Construções e Comércio Camargo Corrêa S.A., a member of the Camargo Corrêa Group, for the provision of construction services to our generation subsidiaries.

We and our subsidiaries also have been conducting several transactions with Banco do Brasil related to loans and financings.  For balances and further details please see note 32 to our audited annual consolidated financial statements.

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, Energia São Paulo FIA.  See note 32 to our audited annual consolidated financial statements concerning “Transactions with Related Parties”.

ITEM 8.Financial Information

Consolidated Statements and Other Financial Information

See Item 18.  Financial Statements.

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Legal Proceedings

CPFL Paulista and CPFL Piratininga are defendants in numerous proceedings commenced by industrial consumers alleging that certain tariff increases that occurred in the past were illegal.  The plaintiffs allege that electricity tariffs were among items subject to a price freeze under financial regulations that were in force at the time.  The total amount claimed under these proceedings was approximately R$88 million as of December 31, 2014.  This amount consists of R$38.7 million where we believe the likelihood of loss is probable; R$19.5 million where we believe the likelihood of loss is possible; and R$30.4 million where we believe the likelihood of loss is remote.  A significant number of these proceedings have been decided against us in part by appellate courts.  We have made accounting provisions of approximately R$38.7 million in respect of these proceedings.

CPFL Paulista is a defendant in a class action suit commenced by the Consumer Protection Office (Promotoria de Defesa do Consumidor) of Campinas in the State of São Paulo, seeking to suspend the tariff adjustment authorized by ANEEL for 2009.  The claim against us was rejected by the court of first instance, but the Consumer Protection Office appealed the decision.  The tariff adjustment remains in force until a ruling on appeal is made.  We believe that the risk of loss in these proceedings is possible and therefore have not recorded any accounting provision in this respect.

CPFL Piratininga is subject to a tax claim regarding alleged improper tax deductions regarding payments made to the Fundação CESP pension fund.  The payments in question originated from an agreement by CPFL Piratininga to pay a debt owed by the pension fund.  CPFL Piratininga has appealed against this tax claim and is awaiting a decision on the appeal.  The amount claimed totaled approximately R$152 million as of December 31, 2014.  We believe that the likelihood of loss is possible.

CPFL Piratininga is also subject to a tax claim from the state of São Paulo regarding its calculation of ICMS tax on the supply of electricity to one city in the state.  CPFL Piratininga is seeking annulment of this claim and is awaiting a decision on the appeal.  The amount claimed totaled approximately R$53 million as of December 31, 2014.  We believe that the likelihood of loss is possible.

We are subject to legal proceedings relating to the authorization of certain of our Hydroelectric Power Plants.  These proceedings include a class action suit commenced by the office of the Federal Public Attorney of the Municipality of Caxias do Sul, challenging the validity of the environmental license for the Rio das Antas hydroelectric complex and seeking an injunction to prevent construction of the plants.  The request for an injunction was denied by the lower court and the appeal court, but confirmation of the appeal court decision has been outstanding since 2012.  We believe that the likelihood of loss is remote.

CPFL Paulista is subject to a tax claim challenging the deductibility of expenses recognized in 1997 relating to a deficit in the Fundação CESP pension fund.  CPFL Paulista deducted the expenses for income tax purposes in reliance on a favorable opinion from the Brazilian tax authority.  We made a payment to court of R$414 million in 2007 (adjusted to R$703 million as of December 31, 2014 to account for inflation) in order to prevent any attachment of assets by the tax authority and enable CPFL Paulista to appeal the claim.  This tax claim has also resulted in other proceedings.  We believe that the likelihood of loss is possible.

CPFL Paulista commenced proceedings against ANEEL in 2007 seeking annulment of the methodology applied in periodic tariff adjustments since the first periodic adjustment cycle in 2003, on the basis that the adjustments affected the economic basis of CPFL Paulista’s concessions.  Following denial of its claim by the court of first instance, CPFL Paulista appealed and is awaiting a decision on the appeal.  In addition, ABRADEE, a group of electricity distribution companies that includes CPFL Paulista, CPFL Piratininga and RGE, commenced proceedings against ANEEL in 2002 challenging the basis for remuneration of concession assets that has been in effect since the first periodic adjustment cycle.  We are currently awaiting a final decision in these proceedings.  If the relevant distribution companies succeed in any of these proceedings, the tariffs that they may charge will increase.  If the distribution companies lose the cases, however, they may be required to pay court costs as well as legal fees that will be arbitrated by the court to ANEEL.

CPFL Geraçao and Furnas are subject to legal proceedings commenced by Mr. Alberto Vieira Borges and others.  The claim relates to the Serra da Mesa joint venture, in which CPFL Geraçao and Furnas are joint venture partners, although the concession for the Serra da Mesa project is held by Furnas alone.  The plaintiffs, who wereowners of a lumberyard, seek compensation of R$681 million on the basis that the Brazilian environmental agency prevented them from felling their trees before the area was flooded as part of the construction of the hydroelectric facility, and therefore that the Serra da Mesa joint venture expropriated the timber.  The claim is awaiting trial at the court of first instance.  CPFL Geraçao has argued that the claim is groundless, and that any potential claim should be made solely against Furnas, as sole holder of the concession operated by the joint venture.  We therefore believe that the likelihood of loss is remote.

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CPFL Geração is subject to a tax claim in the amount of approximately R$225 million as of December 31, 2014 regarding an interpretation of the basis of calculation of PIS and COFINS taxes due.  CPFL Geração’s appeal in this case is awaiting decision.  We believe that the likelihood of loss is possible.

RGE has challenged a tax claim in the amount of approximately R$448 million as of December 31, 2014 regarding corporate income tax (IRPJ) and social contributions (CSLL) levied in relation to the period from 1999 to 2003.  The claim alleges excess goodwill amortization in the 10‑year period under Law 9,532/97; excess asset depreciation charges; and the exclusion from the basis of tax calculation of certain inflation-related adjustments to items within Parcel A, known as CVA.  RGE is awaiting a court decision on its challenge to this claim.  We believe that the likelihood of loss is possible.

CPFL Santa Cruz, CPFL Geração and RGE are also subject to tax claims in the amounts of R$43 million, R$195 million and R$223 million, respectively, as of December 31, 2014, alleging excess goodwill amortization for purposes of calculating IRPJ and CSLL taxes.  Our appeals in this case are awaiting decision.  We believe that the likelihood of loss is possible.

We establish balance sheet provisions relating to potential losses from litigation based on estimates of such losses.  For this purpose, we classify these losses as remote, possible or probable.  IFRS practices require us to establish provisions in connection with probable losses, and it is therefore our policy to establish provisions in connection with those claims only.  As of December 31, 2014, our provisions for contingencies were approximately R$491 million, reflecting our ongoing contingency monitoring and risk control.  Our Management believes that none of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition.  See note 22 to our audited annual consolidated financial statements for more information on the status of our litigation.

Dividend Policy

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

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 two shares.  The ADSs commenced trading on the NYSE on September 29, 2004.  As of December 31, 2014, the ADSs represented 5.1% of our shares and 16.7% 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 a proposal for a simultaneous reverse 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 became one common share and, simultaneously, through the forward stock split, each common share resulting from the reverse stock split became 20 common shares.

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

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The shares resulting from the reverse and forward stock splits were 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 were 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
2010 (*)	22.00	17.42	25.64	19.10
2011 (*)	26.50	19.43	30.56	22.15
2012	29.30	21.28	32.94	20.75
2013	23.57	18.39	22.78	15.49
2014:
2013:
First Quarter	22.16	19.00	21.70	19.36
Second Quarter	23.57	18.76	22.78	16.90
Third Quarter	21.75	19.20	19.21	16.17
Fourth Quarter	20.09	18.39	18.40	15.49
2014:
First Quarter	18.87	15.42	16.57	12.85
Second Quarter	20.83	17.70	18.55	15.79
Third Quarter	22.74	19.11	20.19	15.55
Fourth Quarter	20.18	17.18	16.74	12.56
October	20.18	17.24	16.74	13.52
November	20.11	17.80	15.87	13.64
December	19.08	17.18	14.80	12.56
2015:
January	19.00	16.56	14.40	12.51
February	19.15	17.31	13.33	12.09
March	20.46	17.44	12.72	11.06
April (up to April 13)	21.20	20.50	13.70	13.05

(*)   Prices were adjusted to reflect the change in the ratio of our ADSs and the simultaneous reverse stock split and forward stock split of our common shares.

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 theNovo 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 Management has 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.);

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

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.  In 2012, the Board of Directors approved the updating of our Corporate Governance Guidelines, regarding their application to our Controlled and Affiliated Companies.  Furthermore, it was registered that the members of the Board of Directors’ Advisory Committees shall no longer receive compensation.

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, 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, corporate risk management, sustainability, purchase of energy, new operations and financial policies, etc.

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 bylaws; (ii) prohibition of the same individual to hold the positions of chairman 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.  On December 19, 2011, we amended our bylaws to incorporate these rules, among other changes.  In 2013 we amended our bylaws to include the creation of a "Reserve for Adjustment of the Concession Financial Assets", with subsequent amendment to items “a” and “c” and addition of items “d” and “e” of paragraph 2, Article 27.

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:

·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, sale industry, building, and/or operating projects concerning electricity generation, distribution, transmission and related services.

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Qualification of Directors

Members of our board of executive officers must be resident in Brazil, but such requirement does not apply to members of our Board of Directors.  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.

Under our bylaws, at least 25.0% of our adjusted net income, as calculated under Brazilian Accounting Principles and adjusted under Brazilian Corporate Law, 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, if it has been installed.  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 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, declared unclaimed dividends do not bear interest, are not monetarily adjusted and revert to us if unclaimed within 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 Brazilian 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 Brazilian Central Bank and, therefore, is able to have dividends, sales proceeds or other amounts with respect to the common shares remitted outside Brazil.

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Payments of cash dividends and distributions, if any, are made inreaisto 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 (i) dividends declared based on profits generated prior to December 31, 1995, and (ii) dividends possibly paid in excess, due to a difference in the calculation of the profit resulting from the recent change of accounting standards adopted in Brazil,  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 Brazilian 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 Brazilian 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 Brazilian Central Bank may remit these payments by international transfer of Brazilian currency pursuant to CMN Resolution No. 3,568, dated May 29, 2008, and Brazilian 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.

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%, or25.0% 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.

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

We distributed R$422 million to our shareholders from our 2014 net income, or R$0.438746730 per common share, paid as an interim dividend on October 1, 2014.  Since the amount of R$422 million was more than the obligatory dividend required under Brazilian Corporate Law, has already been distributed as dividends for the year, and in consideration of (i) the current economic scenario, (ii) the unpredictability of the hydrological situation and (iii) the uncertainties about the market projections of the distributors due to the energy efficiency campaigns and extraordinary tariff increases, our Board of Directors has approved the allocation of R$555 million to the statutory reserve – working capital improvement account.

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.

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 take 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;

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

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·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 from theNovo 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 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”.

Quorum

As a general rule, Brazilian Corporate Law provides that a quorum for purposes of a shareholders’ meeting shall 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 or consolidate us with another company;

·spin off a portion of our assets or liabilities;

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·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 CVM and the U.S. Securities and Exchange Commission websites, as well as at our investor relations 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 Bylaws;

·capital increase or capital reduction;

·issuance of Debentures or Subscription Bonuses;

·issuance of 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.

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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 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, in the case of a private placement, a period of at least 30 days following the publication of notice of the capital increase is allowed for the exercise of the preemptive right.  In the case of a public offering, the issuance may occur with or without the exercise of preemptive rights or with a reduced term for the exercise of preemptive rights.  Under Brazilian Corporate Law, holders are permitted to transfer or dispose of their preemptive right for consideration.

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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 minimum mandatory dividends; (ii) the merger of the company or consolidation with another company; (iii) the change of the corporate purpose of the company; (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); (v) the acquisition by us of the control of another company for a price that exceeds the limits established in paragraph two of Article 256 of Brazilian Corporate Law; or (vi) a change in our corporate form.  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, our 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 Brazilian 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 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, or ADRs.

Resolution No. 1,927/1992 of the National Monetary Council, which is the restated and amended Annex V to Resolution No. 1,289/1987, 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 17.0%, 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 Citibank N.A., 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 electronicregistration for only five business days after the exchange.  After that, the holder must seek to obtain its own electronic registration with the Brazilian Central Bank under Law No. 4,131/1962 or Resolution No. 2,689/2000.  Thereafter, unless the holder has registered its investment with the Brazilian 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”.

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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 discussion summarizes 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, own or dispose of 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 (possibly on a retroactive basis) and different interpretations. 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 currently 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 common shares under Resolution No. 2,689 of the National Monetary Council, or Resolution No. 2,689.

Resolution No. 2,689 allows foreign investors to invest in almost all financial assets and to engage in almost all transactions available in 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 the power to perform actions relating to 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 Brazilian 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 Brazilian Central Bank or the CVM.  In addition, securities trading is restricted to transactions carried out in stock exchanges or organized over‑the‑counter markets licensed by the CVM, except for transfers resulting from a corporatereorganization, 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.

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Taxation of Dividends

Stock dividends paid by a Brazilian company to foreign investors, with respect both to foreign direct investments and to foreign investments carried out under the rules of Resolution No. 2,689/00, are generally not subject to withholding income tax in Brazil, to the extent that such amounts are related to profits generated as of January 1, 1996, as provided under article 10 of Law No. 9,249, dated December 26, 1995, or Law No. 9,249/95.

In this context, it should be noted that Law No. 11,638, dated December 28, 2007, or Law No. 11,638/07, significantly altered Brazilian corporate law in order to align the Brazilian generally accepted accounting standards more closely with the International Financial Reporting Standards, or IFRS.  Nonetheless, Law No. 11,941, dated May 27, 2009, introduced the Transitory Tax Regime, or RTT, in order to render neutral, from a tax perspective, all the changes provided by Law No. 11,638/07.  Under the RTT, for tax purposes, legal entities should observe the accounting methods and criteria as in force on December 31, 2007.

Profits determined pursuant to Law No. 11,638/07, or IFRS Profits, can differ from the profits calculated pursuant to the accounting methods and criteria as in force on December 31, 2007, or 2007 Profits.

While it was general market practice to distribute exempted dividends with reference to the IFRS Profits, Normative Ruling No. 1,397 issued by the Brazilian tax authorities on September 16, 2013 (“Normative Ruling No. 1,397/13”) has established that legal entities should observe the accounting methods and criteria as in force on December 31, 2007 (e.g., the 2007 Profits), upon determining the amount of profits that could be distributed as exempted income to its beneficiaries.

Any profits paid in excess of said 2007 Profits, or Excess Dividends, should, in the tax authorities’ view and in the specific case of non‑resident beneficiaries, be subject to the following rules of taxation: (i) 15% withholding income tax, or WHT, in the case of beneficiaries domiciled abroad, but not in tax havens, and (ii) 25% WHT, in the case of beneficiaries domiciled in tax havens.

Since tax authorities could attempt to charge income tax due over Excess Dividends paid over the past five years based on the provisions of Normative Ruling No. 1,397/13, and in order to try to mitigate potential lawsuits of taxpayers that could argue that Normative Ruling No. 1,397/13 is unlawful, the Brazilian government introduced new provisions dealing with the Excess Dividends. A new tax regime (the “New Tax Regime”) was introduced through the enactment of Law No. 12,973 of May 13, 2014, which brought significant modifications related to IRPJ, CSLL, PIS and COFINS, as well as revoking the RTT.  Under the New Tax Regime, the current accounting standards (IFRS) became the starting point for the assessment of such taxes, except when Law No. 12,973/14 or supervening laws may treat such assessments in a different way, providing for specific adjustments to this purpose.

Moreover, the New Tax Regime applies to all taxpayers beginning January 1, 2015, except for those who chose to anticipate  and apply the provisions contained in Articles 1, 2 and 4 through 70 of Law No. 12,973/14 for the 2014 base period, for whom the RTT was revoked beginning December 31, 2013; however, the current treatment for transactions carried out before the New Tax Regime’s effectiveness (under its Article 64) were protected.  We did not voluntarily elect to apply the New Tax Regime in 2014.

With respect to the taxation of dividends, the aforementioned new provisions determined that (i) the Excess Dividends related to profits assessed from 2008 to 2013 are assured to be exempt; (ii) potential disputes remain concerning the Excess Dividends related to 2014 profits, unless the company voluntarily elects to apply the New Tax Regime in 2014; and (iii) as of 2015, once the New Tax Regime is mandatory and has extinguished the RTT, it is possible to argue that dividends should be considered fully exempt as ordinarily provided by law.

 Taxation of Gains

Pursuant to Law No. 10,833, enacted on December 29, 2003, gains on the disposition or sale of assets located in Brazil by a Non‑Brazilian Holder, whether to another non‑Brazilian resident or to a Brazilian resident, are subject to withholding income tax in Brazil.

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With respect to the disposition of our common shares, as they are assets located in Brazil, the Non‑Brazilian Holder should be subject to income tax on the gains assessed, following the rules described below, regardless of whether the transactions are conducted in Brazil or with a Brazilian resident.

With respect to our ADSs, arguably the gains realized by a Non‑Brazilian Holder upon the disposition of ADSs to another non‑Brazilian resident should not be taxed in Brazil, on the basis that ADSs are not “assets located in Brazil” for the purposes of Law No. 10,833.  We cannot assure you, however, that the Brazilian tax authorities or the Brazilian courts will agree with this interpretation.  As a result, gains on a disposition of ADSs by a Non‑Brazilian Holder to a Brazilian resident, or even to a non‑Brazilian resident, in the event that courts determine that ADSs would constitute assets located in Brazil, may be subject to income tax in Brazil according to the rules applicable to our common shares, described above.

As a general rule, gains realized as a result of a disposition of our common shares or ADSs are the positive difference between the amount realized on the transaction and the acquisition cost of our common shares or ADSs.

Under Brazilian law, however, income tax rules on such gains may vary depending on the domicile of the Non‑Brazilian Holder, the type of registration of the investment by the Non‑Brazilian Holder with the Brazilian Central Bank and how the disposition is carried out, as described below.

Gains realized on a disposition of shares carried out on a Brazilian stock exchange (which includes the organized over‑the‑counter market) are:

·exempt from income tax when realized by a Non‑Brazilian Holder that (1) has registered the investment in Brazil with the Brazilian Central Bank under the rules of Resolution No. 2,689, or a 2,689 Holder, and (2) is not a resident in a country or location which is defined as a “Favorable Tax Jurisdiction” for this purposes as described below; or

·subject to income tax at a rate of 15% in the case of gains realized by (A) a Non‑Brazilian Holder that (1) is not a 2,689 Holder and (2) is not a Favorable Tax Jurisdiction Resident; or by (B) a Non‑Brazilian Holder that (1) is a 2,689 Holder, and (2) is a Favorable Tax Jurisdiction Resident.  In this case, a withholding income rate of 0.005% shall be applicable and withheld by the intermediary institution (i.e., a broker) that receives the order directly from the Non‑Resident Holder, which can be later offset against any income tax due on the capital gain earned by the Non‑Resident Holder.

Any other gains assessed on a sale or disposition of the common shares that is not carried out on a Brazilian stock exchange are subject to income tax at a rate of 15%, except for a Non-Brazilian Holder in a Low or Nil Tax Jurisdiction which, in this case, is subject to income tax at the rate of up to 25%. If these gains are related to transactions conducted on the Brazilian non-organized over-the-counter market with intermediation, the withholding income tax of 0.005% on the sale value shall also be applicable and can be offset against the eventual income tax due on capital gain.

In the case of redemption of securities or capital reduction by a Brazilian corporation, such as us, the positive difference between the amount effectively received by the Non‑Brazilian Holder and the corresponding acquisition cost is treated, for tax purposes, as capital gain derived from sale or exchange of shares not carried out on a Brazilian stock exchange, and is therefore subject to income tax at the rate of 15% or 25%, as the case may be.

The deposit of our common shares in exchange for ADSs will be subject to Brazilian income tax if the acquisition cost of the shares is lower than (1) the average price per share on a Brazilian stock exchange on which the greatest number of such shares were sold on the day of deposit, or (2) if no shares were sold on that day, the average price on the Brazilian stock exchange on which the greatest number of shares were sold in the 15 trading sessions immediately preceding such deposit.  In this case, the difference between the acquisition cost and the average price of the shares calculated as above will be considered to be a capital gain subject to withholding income tax at the rate of 15% or 25%, as the case may be.  In some circumstances, there may be arguments to claim that this taxation is not applicable, including the case of a Non‑Brazilian Holder that is a 2,689 Holder and is not a resident in a “Favorable Tax Jurisdiction” for this purpose.  The availability of these arguments to any specific holder of our common shares will depend on the circumstances of the holder.  Prospective holders of our common shares shouldconsult their own tax advisors as to the tax consequences of the deposit of our common shares in exchange for ADSs.

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Any exercise of preemptive rights relating to our common shares or ADSs will not be subject to Brazilian taxation.  Any gain on the sale or assignment of preemptive rights relating to our common shares, including the sale or assignment carried out by the depositary, on behalf of Non‑Brazilian Holders of ADSs, will be subject to Brazilian income taxation according to the same rules applicable to the sale or disposition of our common shares.

There can be no assurance that the current favorable tax treatment of 2,689 Holders will continue in the future.

Interpretation of the Discussion on the Definition of “Favorable Tax Jurisdiction”

On June 4, 2010, Brazilian tax authorities enacted Normative Instruction No. 1,037 listing (i) the countries and jurisdictions considered as Favorable Tax Jurisdiction or where local legislation does not allow access to information related to the shareholding composition of legal entities to their ownership or to the identity of the effective beneficiary of the income attributed to non‑residents, or Tax Haven Jurisdictions, and (ii) the privileged tax regimes, whose definition is provided by Law No. 11,727, of June 23, 2008.  Although we believe that the best interpretation of the current tax legislation could lead to the conclusion that the above mentioned “privileged tax regime” concept should apply solely for purposes of Brazilian transfer pricing, thin capitalization and controlled foreign company rules, we cannot assure you whether subsequent legislation or interpretations by the Brazilian tax authorities regarding the definition of a “privileged tax regime” provided by Law No. 11,727 will also apply to a Non‑Brazilian Holder on payments potentially made by a Brazilian source.

Moreover, on November 28, 2014, due to the enactment of Ordinance No. 488, the definition of a Favorable Tax Jurisdiction, for the purposes described above, was changed from jurisdictions where there is no income tax, or the income tax applicable rate is inferior to 20%, to jurisdictions where there is no income tax, or the income tax applicable rate is inferior to 17%. Due to this change, the listing of Normative Instruction No. 1,037 may soon be updated.

We recommend prospective investors consult their own tax advisors from time to time to verify any possible tax consequences arising of Normative Ruling No. 1,037 and Law No. 11,727.  If the Brazilian tax authorities determine that the concept of “privileged tax regime” provided by Law No. 11,727 will also apply to a Non‑Resident Holder on payments potentially made by a Brazilian source the withholding income tax applicable to such payments could be assessed at a rate up to 25%.

Interest Attributable to Shareholders’ Equity.  Law No. 9,249, dated December 26, 1995, as amended, allows a Brazilian corporation, such as us, to make distributions to shareholders of interest on shareholders’ equity, and treat those payments as a deductible expense for purposes of calculating Brazilian corporate income tax, and, since 1998, social contribution on net profit as well, as long as the limits described below are observed.  These distributions may be paid in cash.  For tax purposes, the deductible amount of this interest is limited to the daily pro rata variation of the TJLP, as determined by the Brazilian Central Bank from time to time, and the amount of the deduction may not exceed the greater of:

·50% of net income (after the deduction of social contribution on net profit but before taking into account the provision for corporate income tax and the amounts attributable to shareholders as interest on shareholders’ equity) for the period in respect of which the payment is made; and

·50% of the sum of retained profits and income reserves as of the date of the beginning of the period in respect of which the payment is made.

Payment of interest on shareholders’ equity to a Non‑Brazilian Holder is subject to withholding income tax at the rate of 15%, or 25% if the Non‑Brazilian Holder is domiciled in a Favorable Tax Jurisdiction.

These payments of interest on shareholders’ equity to a Non‑Brazilian Holder may be included, at their net value, as part of any mandatory dividend.  To the extent payment of interest on net equity is so included, we arerequired to distribute to shareholders an additional amount to ensure that the net amount received by them, after payment of the applicable income tax withholding, is at least equal to the mandatory dividend.

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Payments of interest on shareholders’ equity are decided by our shareholders, at an annual shareholders meeting, on the basis of recommendations of on board of directors.  No assurance can be given that our board of directors will not recommend that future distributions of profits should be made by means of interest on shareholders’ equity instead of by means of dividends.

Tax on foreign exchange transactions

Pursuant to Decree No. 6,306/07, the conversion into foreign currency or the conversion into Brazilian currency of the proceeds received or remitted by a Brazilian entity from a foreign investment in the Brazilian securities market, including those in connection with the investment by a non-Brazilian holder in the preferred shares and ADSs may be subject to the Tax on Foreign Exchange Transactions, or IOF/Exchange. Currently, the applicable rate for most foreign currency exchange transactions is 0.38%. However, currency exchange transactions carried out for the inflow of funds in Brazil by a 2,689 Holder are subject to IOF/Exchange at (i) 0% rate in case of variable income transactions carried out on the Brazilian stock, futures and commodities exchanges, as well as in the acquisitions of shares of Brazilian publicly-held companies in public offerings or subscription of shares related to capital contributions, provided that the issuer company has registered its shares for trading in the stock exchange (ii) 0% for the outflow of resources from Brazil related to these type of investments, including payments of dividends and interest on shareholders’ equity and the repatriation of funds invested in the Brazilian market. Furthermore, the IOF/Exchange is currently levied at a 0% rate on the withdrawal of ADSs into shares. In any case, the Brazilian government is permitted to increase at any time the rate to a maximum of 25%, but only in relation to future transactions.

Brazilian law imposes a tax on transactions involving bonds and securities, or 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 almost all transactions, including those carried out on a Brazilian stock exchange.  The rate of the IOF/Bonds Tax applicable to transactions involving our common shares is currently zero, including, as of December 24, 2013, the rate of the IOF/Bonds Tax applicable to the transfer of our common shares with the specific purpose of enabling the issuance of ADSs.  The Brazilian government may increase the rate of the IOF/Bonds Tax at any time up to 1.5% per day of the transaction amount, but only in respect of transactions carried out after the increase in rate enters into effect.

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 stamps, 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 acquisition, ownership and disposition of common shares or ADSs.  This discussion is based on the U.S. Internal Revenue Code of 1986, as amended, or the Code, its legislative history, existing final, temporary and proposed Treasury regulations, administrative pronouncements by the U.S. Internal Revenue Service, or 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 our 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 we are not a passive foreign investment company, or 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 entity classified as a partnership for U.S. federal income tax purposes) that holds common shares or ADSs, or any U.S. federal estate and gift, state, local or non‑U.S. tax consequences of the acquisition, ownership and disposition of common shares or ADSs.  This discussion does not address the Medicare tax on net investment income.  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).

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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 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 acquisition, 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 our 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 our 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 inreaiswill be the U.S. dollar value of thereaisreceived, calculated by reference to the exchange rate in effect on the date of actual or constructive receipt, regardless of whether the payment inreais is in fact converted into U.S. dollars at that time.  If thereaisreceived as a dividend are converted into U.S. dollars on the date of actual or constructive receipt, a U.S. holder should not recognize foreign currency gain or loss in respect of such dividend.  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 suchreaisare not converted into U.S. dollars on the date of actual or constructive receipt.

Dividends paid by us 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) with respect to the ADSs will be subject to taxation at a maximum rate of 20.0% 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) we were not, in the year prior to the year in which the dividend was paid, and are 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 our 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 we 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 our 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.  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  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 (subject to various exceptions).  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 and involves uncertainty.  Based on our audited financial statements, the nature of our business, and relevant market and shareholder data, we believe that we would not be classified as a PFIC for our last taxable year or our current taxable year (although the determination cannot be made until the end of such taxable year), and we do not expect to be classified as a PFIC in the foreseeable future, based on our current business plans and our current interpretation of the Code and Treasury regulations that are currently in effect.  However, because the application of the Code and Treasury regulations are not entirely clear and because PFIC status depends on the composition of a non‑U.S. corporation’s income and assets and the market value of its assets from time to time, there can be no assurance that we will not be treated as a PFIC for any taxable year.

If, contrary to the discussion above, we are 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 taxable disposition of common shares or ADSs and (b) any “excess distribution” made by us 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 we  became a PFIC would be taxable as ordinary income, (c) the amount allocated to each prior year in which  we were 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  we were a PFIC.

If we are treated as a PFIC and, at any time, we invest 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 we are treated as a PFIC, a U.S. holder could incur liability for the deferred tax and interest charge described above if either (i) we receive a distribution from, or dispose of all or part of our  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 we are 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 we are treated as a PFIC generally would be required to file IRS Form 8621, including in order to comply with an additional annual filing requirement for U.S. persons owning shares of a PFIC.  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 we be considered a PFIC for any taxable year and the reporting requirements that may apply 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) establishes that it 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 additional reporting requirements apply 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 foreign financial asset rules 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.

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.

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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.  We are subject to market risk deriving from changes in rates which affect the cost of our financing.

Exchange Rate Risk

At December 31, 2014, approximately 18.0% of our indebtedness was denominated in U.S. dollars.  Also at December 31, 2014, we had swap agreements that offset the exchange rate risk with respect to R$3,570 million of those amounts.  As our net exposure is an asset denominated in U.S. dollars since the swap has higher balances than the liability, our exchange rate risk is associated with the risk of a drop in the value of the U.S. dollar.  The potential loss to us that would result from a hypothetical favorable 50.0% change in foreign currency exchange rates (an expected scenario provided by the BM&FBOVESPA), after giving effect to the swaps, would be approximately R$32 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.  For further information on other scenarios, please see note 35.c.1 to our audited annual consolidated financial statements.

Risk of Index Variation

We have indebtedness and financial assets that are denominated inreaisand that bear interest at variable rates or, in some cases, are fixed.  The interest or indexation rates include several different Brazilian money‑market rates and inflation rates.  At December 31, 2014, the amount of such liabilities, net of such assets and after giving effect to swaps, was R$12,596 million.  Further information for other scenario, please see note 35.c.2 to our audited annual consolidated financial statements.

A hypothetical, instantaneous and unfavorable change of 25% in rates applicable to floating rate financial assets and liabilities held at December 31, 2014, would result in a net additional cash outflow of approximately R$522 million.  This sensitivity analysis is based on the assumption of an unfavorable 25% movement of the interest rates applicable to each homogeneous category of financial assets and liabilities (an expected scenario available in the Market).  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 as 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 former depositary, Deutsche Bank Trust Company Americas, provided the services of depositary bank to holders of ADSs until January 7, 2015. Citibank N.A. is the current depositary, as of January 8, 2015. The following table summarizes the fees and expenses payable by holders of ADSs (charged by the depositary):

Service:	Fee:	Paid by:
Issuance of ADSs upon deposit of shares, excluding issuances resulting from distributions described in the fourth item below	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) issued	Person depositing our common shares or person receiving ADSs
Delivery of common shares deposited under our deposit agreement against surrender of ADSs	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) surrendered	Person surrendering ADSs for cancellation and withdrawal of deposited securities or person to whom deposited securities are delivered
Distribution of cash dividends or other cash distributions	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person to whom distribution is made
Distribution of ADSs pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADSs	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person to whom distribution is made
Distribution of securities other than ADSs or rights to purchase additional ADSs	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person to whom distribution is made
Depositary services	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person holding ADSs on the applicable record date(s) established by the depositary

The depositary may deduct applicable depositary fees from the funds being distributed in the case of cash distributions. For distributions other than cash, the depositary will invoice the amount of the applicable depositary fees to the applicable holders.

Additional Charges

Holders and beneficial owners of our ADSs and persons depositing our common shares and persons surrendering ADSs for cancellation and for the purpose of withdrawing deposited securities shall be responsible for the following charges:

(a) taxes (including applicable interest and penalties) and other governmental charges;

(b) such registration fees as may from time to time be in effect for the registration of our common shares or other deposited securities on the share register and applicable to transfers of our common shares or other deposited securities to or from the name of the custodian, the depositary or any nominees upon the making of deposits and withdrawals, respectively;

(c) such cable, telex and facsimile transmission and delivery expenses as are expressly provided in the deposit agreement to be at the expense of the person depositing or withdrawing our common shares or holders and beneficial owners of ADSs;

(d) the expenses and charges incurred by the depositary in the conversion of foreign currency;

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(e) such fees and expenses as are incurred by the depositary in connection with compliance with exchange control regulations and other regulatory requirements applicable to our common shares, deposited securities, ADSs and ADRs; and

(f) the fees and expenses incurred by the depositary, the custodian, or any nominee in connection with the delivery or servicing of deposited securities.

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 2014 we received the following payments from the depositary: (i) US$16,815; and (ii) US$15,918 for expenses incurred by us relating to the ADR program.

ITEM 13.Defaults, Dividend Arrearages and Delinquencies

None.

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, 2014.  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.

Management’s Report on 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.

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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, 2014 based on the criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO in 1992. Based on such assessment and criteria, our Management has concluded that our internal control over financial reporting was effective as of December 31, 2014. Our  management   did  not identify  any  changes in our  internal  control  over financial   reporting  during  the  fiscal  year  ended  December 31, 2014  that  has  materially  affected,   or is reasonably   likely  to materially  affect,  our  internal  control  over financial  reporting.

COSO issued a new version of its framework in 2013.  For the 2014 financial year, we continued to use the COSO framework issued in 1992, but we are currently structuring the implementation of the 2013 framework.  Management is currently comparing our internal controls implemented under the COSO 1992 framework to the 2013 framework and so far, based on our business, has not found any relevant gaps in internal control.

In October2014, our subsidiary CPFL Renováveis, acquired 100% of shares of DESA. Pursuant to SEC’s instructions, management may exclude an acquired business from its report on internal control over financial reporting ifa registrant consummates a material purchase business combination during the relevant fiscal year. On that basis, our management excluded from its assessment the internal control over financial reporting at DESAwhosefinancial statementsconstitute6.7%of total assets and0.3% of net revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2014.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  

To the Board of Directors and Shareholders of

CPFL Energia S.A.

São Paulo - SP

We have audited the internal control over financial reporting of CPFL Energia S.A. and subsidiaries (the “Company”) as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Dobrevê Energia S.A. (“DESA”), which was acquired in October 2014 and whose financial statements constitute 6.7% of total assets and 0.3% of net operating revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2014. Accordingly, our audit did not include the internal control over financial reporting at Dobrevê Energia S.A. The Company's management is responsible 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 the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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 Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated April 10, 2015 expressed an unqualified opinion on those financial statements.

/s/DELOITTE TOUCHE TOHMATSU

     Auditores Independentes

Campinas, São Paulo, Brazil
April 10, 2015

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 of Directors recognizes that one member of our fiscal council, Marcelo de Andrade, qualifies as an audit committee financial expert and meets the applicable independence requirements for fiscal council membership under Brazilian law.  He 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 consider ethics to be an essential value for its reputation and longevity. Our Ethics Management and Development System (SGDE) aims to turn concerns with ethical behavior into effective practices, focusing on avoiding breaches and promoting development of ethical quality throughout the Organization’s actions. The system is composed of a set of provisions, implemented in all of our subsidiaries. SGDE aims to prevent, monitor, assess, revise and improve individual and institutional actions of the company that directly or indirectly imply in ethical behavior, partially or fully. Our Code of Ethics and Business Conduct (“Code of Ethics”) has a scope that is similar to the one required for a U.S. domestic company under the NYSE rules. We report each year under Item 16B of its annual report on Form 20-F any waivers of the Code of Ethics in favor of our CEO, CFO, principal accounting officer and persons performing similar functions. Besides the initiatives that directly involve our partners, we seek to ensure that our business values are shared by the chain of suppliers through contractual items that require compliance with the Code of Ethics and the SA 8000 (social responsibility) Norm. In our services contracts, there is an exclusive clause regarding the Code of Ethics in the contracting processes. The Code of Ethics governs all relations between companies of the Group and their stakeholders (shareholders, clients, employees, suppliers, service providers, governments, communities and society). The detailed 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).

We are also listed on the Pro-Ethics Company, a system developed by the federal Controller-General’s Office (Controladoria Geral da União – CGU) and the Ethos Institute. By becoming a part of Pro-Ethics, we assume a public commitment, before governments and society, to invest in measures that promote ethics and prevention of corruption as a way of contributing to more integrity and to a more ethical and transparent environment in the private sector and our relations with the public sector.

In 2014, we finished reviewing our Code of Ethics, whereby the suggestions of our employees and outside stakeholders have been implemented. The final version of our Code of Ethics together with its accompanying document “Conduct Rules” were approved by the Ethics Committee on November 21, 2014. The approval by Management and Board of Directors is expected to take place in 2015. Dissemination through all CPFL’s companies, employees and outside stakeholders will take place subsequently, and depends on receipt of the Management and Board of Directors’ approval.

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, 2014 and 2013.  Our independent accounting firm was Deloitte Touche Tohmatsu Auditores Independentes for the years ended December 31, 2014 and 2013.

	Year ended December 31,
	2014	2013
	(in thousands ofreais)
Audit fees	5,978	4,101
Audit‑related fees	2,098	1,880
Tax fees	197	115
All other fees	‑	‑
Total	8,273	6,096

“Audit Fees” are the aggregated fees billed by Deloitte Touche Tohmatsu 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 fiscal years 2014 and 2013, respectively.

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“Audit‑related fees” are fees charged by Deloitte Touche Tohmatsu Auditores Independentes for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements for the years ended December 31, 2014 and 2013, respectively.

“Tax fees” in the above table are for services related to tax compliance charged by Deloitte Touche Tohmatsu Auditores Independentes for the years ended December 31, 2014 and 2013, respectively.

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.

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 ESC Energia S.A., PREVI through BB Carteira Livre I Fundo de Investimento em Ações and Energia São Paulo FIA (including through 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 ad hoc Corporate Governance Commission, composed of 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 whenever necessary, proposing improvements to CPFL’s governance practices, and monitoring the implementation of CPFL’s corporate governance practices.

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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.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 our 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 the matters specified in the NYSE rules. CPFL’s corporate governance guidelines are available on http://www.cpfl.com.br/ir.
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 16H.Mine Safety Disclosure

Not applicable.

ITEM 17.Financial Statements

Not applicable.

ITEM 18.Financial Statements

See pages F‑1 through F‑102, 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.

135

 

 GLOSSARY OF TERMS

ABRADEE: Brazilian Association of Electric Energy Distributors (Associação Brasileira de Distribuidores de Energia Elétrica).

ACR Account: The ACR account, created by Decree No. 8,221/2014, aims to cover all or part of the costs incurred by distribution utilities in the period from February to December 2014, due to (i) involuntary exposure in the spot market and (ii) thermoelectric dispatch regarding CCEAR.

Allowed Annual Revenue:Revenue received by electricity transmission companies annually.  Such revenue is calculated based on the estimated investment to build, maintain and operate a transmission system.

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.

Biomass Thermoelectric Power Plant: a generator which uses the combustion of organic matter for the production of energy.

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.

Captive Consumers: Consumers that acquire energy from the distribution company or holder of a permit to whose network the consumer is connected.  These consumers are subject to regulated tariffs, which include the costs of transmission and distribution as well as the energy purchase costs.

CCEAR: Agreements on Energy Commercialization in theRegulated 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.

CNPE: National Energy Policy Council (Conselho Nacional de Política Energética).

Debt-Service Coverage Ratio:The Debt-Service Coverage Ratio (DSCR) is the amount of cash flow available to meet annual interest and principal payments on debt.

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 lowreservoir 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.

136

 

FinalConsumer: A party that uses electricity for its own needs.

Free Consumers: Consumers with a minimum demand of 3 MW who opt to purchase energy, entirely or partially, from another authorized selling agent under the terms of current, applicable legislation.

Free Market: 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 2.3 kV and equal to or lower than 230 kV.

Hydroelectric Power Plant: A generator that uses water power to drive the electric generator.

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.

IPCA:Broad consumer price index (Indice Nacional de Preços ao Consumidor Amplo, calculated and published byInstituto Brasileiro de Geografia e Estatística).

Kilovolt (kV): One thousand volts.

Kilowatt (kW): One thousand watts.

Kilowatthour (kWh): One kilowatt of power supplied or demanded for one hour, or one thousand watt hours.

Low Voltage:A class of nominal system voltages equal to or lower than 1,000 volts (1 kV).

MCPSE:Electricity Sector Asset Control Manual (Manual de Controle Patrimonial do Setor Elétrico).

Medium Voltage:A class of nominal system voltages greater than 2.3 kV and equal or lower than 138 kV.

Megawatt (MW): One million watts.

Megawatthour (MWh): One megawatt of power supplied or demanded for one hour, or one million watt hours.

Micro Hydroelectric Power Plants: Power projects with capacity lower than 1 MW.

MME: Ministry of Mines and Energy (Ministério de Minas e Energia).

Megawatt‑peak (MWp):The measure of the nominal power of a photovoltaic solar device under laboratory lighting conditions.

MRE: Energy Reallocation Mechanism (Mecanismo de Realocação de Energia).

137

 

MVA:Mega Volt Ampère.

ONS: National Electric System Operator (Operador Nacional do Sistema Elétrico), 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.

RTA:Annual Tariff Adjustment (reajuste tarifário annual).

RTE: Extraordinary Tariff Adjustment (reajuste tarifário extraordinário).

RTP: Periodic Tariff Revision (revisão tarifária periódica)

SHPP or Small Hydroelectric Power Plants: Power projects with capacity from 1 MW to 30 MW.

Special Consumer: Consumer or a group of consumers that uses at least 500 kV.  Special Consumers may only purchase energy from (i) Small Hydroelectric Power Plants with capacity superior to 3,000 kW and equal or inferior to 30,000 kW, (ii) hydroelectric generators with capacity superior to 3,000 kW and equal or inferior to 50,000 kW, under the independent power production regime; (iii) generators with capacity limited to 3,000 kW, and (iv) alternative energy generators (solar, wind and biomass enterprises) with system capacity not greater than 50,000 kW.

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 network (in lines with capacity between 69 kV and 525 kV).

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 April 17, 2015.

CPFL ENERGIA S.A.

By:     /s/ Wilson Ferreira Junior       

Name:  Wilson Ferreira Junior

Title:    Chief Executive Officer

By:     /s/ Gustavo Estrella                

Name:  Gustavo Estrella

Title:    Chief Financial Officer

139

Deloitte Touche Tohmatsu Av. Dr. José Bonifácio Coutinho Nogueira, 150 - 5º andar Campinas - SP - 13091-611 Brasil
Tel: + 55 (19) 3707-3000 Fax:+ 55 (19) 3707-3001
www.deloitte.com.br

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

CPFL Energia S.A.

São Paulo - SP

We have audited the accompanying consolidated balance sheets of CPFL Energia S.A. and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CPFL Energia S.A. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in accordance with International Financial Reporting Standards - IFRS, issued by the International Accounting Standards Board - IASB.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 10, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/DELOITTE TOUCHE TOHMATSU

    Auditores Independentes

Campinas, São Paulo, Brazil

April 10, 2015

 

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2014 and 2013 (In thousands of Brazilian reais – R$)

ASSETS	Dec 31, 2014	Dec 31, 2013
CURRENT ASSETS
Cash and cash equivalents (note 5)	4,357,455	4,206,422
Consumers, concessionaires and licensees (note 6)	2,251,124	2,007,789
Dividends and interest on shareholders´ equity receivable (note 13)	54,483	55,265
Financialinvestments	5,324	24,806
Recoverable taxes (note 7)	329,638	262,433
Derivatives (note 35)	23,260	1,842
Sector financial assets (note 8)	610,931	-
Materials and supplies	18,505	21,625
Leases (note 10)	12,396	10,757
Financial asset of concession (note 11)	540,094	-
Other credits (note 12)	1,011,495	673,383
TOTAL CURRENT ASSETS	9,214,704	7,264,323
NONCURRENT ASSETS
Consumers, concessionaires and licensees (note 6)	123,405	153,854
Loans to joint ventures (note 32)	100,666	86,655
Escrow deposits (note 22)	1,162,477	1,143,179
Recoverable taxes (note 7)	144,383	173,362
Sector financial assets (note 8)	321,788	-
Derivatives (note 35)	584,917	316,648
Deferred taxes assets (note 9)	938,496	1,168,706
Leases (note 10)	35,169	37,817
Financial asset of concession (note 11)	2,834,522	2,787,073
Other credits (note 12)	388,828	296,096
Investment at cost	116,654	116,654
Investments in joint ventures (note 13)	1,098,769	1,032,681
Property, plant and equipment (note 14)	8,878,064	7,717,419
Intangible assets (note 15)	9,155,973	8,748,328
TOTAL NONCURRENT ASSETS	25,884,112	23,778,473
TOTAL ASSETS	35,098,816	31,042,796

The accompanying notes are an integral part of these financial statements.                                      

F -1

 

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2014 and 2013 (In thousands of Brazilian reais – R$)

LIABILITIES AND SHAREHOLDERS’ EQUITY	Dec 31, 2014	Dec 31, 2013
CURRENT LIABILITIES
Suppliers (note 16)	2,374,147	1,884,693
Accrued interest on loans and financing (note 17)	97,525	125,829
Accrued interest on debentures (note 18)	293,108	162,134
Loans and financing (note 17)	1,093,500	1,514,626
Debentures (note 18)	2,042,075	34,872
Post-employment benefit obligation (note 19)	85,374	76,810
Regulatory charges (note 20)	43,795	32,379
Taxes and social contributions payable (note 21)	436,267	318,063
Dividends and interest on equity	19,086	21,224
Accrued liabilities	70,252	67,633
Derivatives (note 35)	38	-
Sector financial liabilities (note 8)	21,998	-
Public utilities (note 23)	4,000	3,738
Other accounts payable (note 24)	835,941	663,529
TOTAL CURRENT LIABILITIES	7,417,104	4,905,531
NONCURRENT LIABILITIES
Suppliers (note 16)	633	-
Accrued interest on loans and financing (note 17)	60,717	43,396
Accrued interest on debentures (note 18)	-	32,177
Loans and financing (note 17)	9,426,634	7,546,144
Debentures (note 18)	6,136,400	7,562,219
Post-employment benefit obligation (note 19)	518,386	350,640
Taxes and social contributions payable (note 21)	-	32,555
Deferred taxes liabilities (note 9)	1,385,498	1,117,146
Provisions for tax, civil and labor risks (note 22)	490,858	467,996
Derivatives (note 35)	13,317	2,950
Public utilities (note 23)	80,992	79,438
Other accounts payable (note 24)	183,766	103,886
TOTAL NONCURRENT LIABILITIES	18,297,200	17,338,547
SHAREHOLDERS’ EQUITY (note 25)
Capital	4,793,424	4,793,424
Capital reserves	468,082	287,630
Legal reserves	650,811	603,352
Earnings retained for investment	-	108,987
Statutory reserve – financial asset of concession	330,437	265,037
Statutory reserve – working capital improvement	554,888	-
Dividend	-	567,802
Other comprehensive income	145,893	397,668
	6,943,535	7,023,899
Net equity attributable to non-controlling shareholders	2,440,978	1,774,819
TOTAL SHAREHOLDERS' EQUITY	9,384,513	8,798,718
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	35,098,816	31,042,796

The accompanying notes are an integral part of these financial statements.

F -2

 

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS
ENDED DECEMBER 31, 2014, 2013 and 2012
(In thousands of Brazilian reais – R$, except for earnings per share)

	2014	2013	2012
NET OPERATING REVENUE (note 27)	17,305,942	14,633,856	14,890,875
COST OF ELECTRIC ENERGY SERVICES
Cost of electric energy (note 28)	(10,643,130)	(8,196,687)	(8,252,995)
Operating cost (note 29)	(1,672,359)	(1,467,516)	(1,377,706)
Services rendered to third parties (note 29)	(946,052)	(1,009,518)	(1,355,675)
GROSS OPERATING INCOME	4,044,401	3,960,135	3,904,499
Operating expenses (note 29)
Sales expenses	(402,698)	(376,597)	(468,146)
General and administrative expenses	(773,630)	(928,614)	(724,364)
Other operating expense	(328,000)	(285,148)	(376,898)
INCOME FROM ELECTRIC ENERGY SERVICE	2,540,073	2,369,775	2,335,091
INTEREST IN JOINT VENTURES (note 13)	59,684	120,868	120,680
FINANCIAL INCOME (EXPENSE) (note 30)
Income	890,436	699,208	706,963
Expense	(1,979,890)	(1,670,651)	(1,284,736)
	(1,089,454)	(971,443)	(577,773)
INCOME BEFORE TAXES	1,510,304	1,519,200	1,877,998
Social contribution (note 9)	(168,989)	(156,756)	(178,017)
Income tax (note 9)	(454,871)	(413,408)	(492,919)
	(623,860)	(570,164)	(670,936)
NET INCOME	886,443	949,036	1,207,062
Net income attributable to controlling shareholders	949,177	937,419	1,176,252
Net income attributable to non-controlling shareholders	(62,733)	11,618	30,810
Earnings per share attributable to controlling shareholders: Basic (note 26)	0.99	0.97	1.22
Diluted (note 26)	0.97	0.95	1.20

The accompanying notes are an integral part of these financial statements.

F -3

 

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED IN DECEMBER 31, 2014, 2013 and 2012

 (In thousands of Brazilian reais – R$)

	2014	2013	2012
NET INCOME	886,443	949,036	1,207,062
Items that will not be reclassified subsequently to profit or loss:
Gains (losses) in actuarial plans, net of taxes	(225,720)	460,226	(572,225)
Comprehensive income for the year	660,724	1,409,262	634,837
Comprehensive income attributable to controlling shareholders	723,457	1,397,645	604,027
Comprehensive income attributable to non-controlling shareholders	(62,733)	11,618	30,810

F -4

 

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 and 2012

(In thousands of Brazilian reais - R$)

												Net equity attributable to non-controllinng shareholders
			Profit reserves					Other comprehensive income
				Earnings	Statutory reserve	Statutory reserve			Post-employment benefit			Other		Total
		Capital	Legal	retained for	financial asset	working capital		Deemed		Retained	Total	comprehensive	Other	Shareholders'
	Capital	reserves	reserve	investment	of concession	improvement	Dividend	Cost		earnings		income	equity	equity
Balance at December 31, 2011	4,793,424	229,956	495,185	-	-	-	758,470	563,005	-	333,082	7,173,122	20,679	1,464,673	8,658,475
Total comprehensive income
Net income for the restated year	-	-	-	-	-	-	-	-	-	1,176,252	1,176,252	-	30,810	1,207,062
Other comprehensive income - actuarial loss	-	-	-	-	-	-	-	-	(572,225)	-	(572,225)	-	-	(572,225)
Internal changes of shareholders'equity
- Realization of deemed cost of fixed assets	-	-	-	-	-	-	-	(41,482)	-	41,482	-	(1,421)	1,421	-
- Tax on deemed cost realization	-	-	-	-	-	-	-	14,104	-	(14,104)	-	483	(483)	-
- Formation of legal reserve	-	-	61,296	-	-	-	-	-	-	(61,296)	-	-	-	-
- Reserve of retained earnings for investment	-	-	-	326,899	-	-	-	-	-	(326,899)	-	-	-	-
- Other changes in non-controlling shareholders	-	-	-	-	-	-	-	-	-	-	-	-	(334)	(334)
Capital transactions with the shareholders
- Prescribed dividend	-	-	-	-	-	-	-	-	-	3,921	3,921	-	-	3,921
- Interim dividend	-	-	-	-	-	-	-	-	-	(640,239)	(640,239)	-	-	(640,239)
- Additional dividend proposed	-	-	-	-	-	-	455,906	-	-	(455,906)	-	-	(5,875)	(5,875)
- Additional dividend aproved	-	-	-	-	-	-	(758,470)	-	-	-	(758,470)	-	(8,201)	(766,671)
- Payment of capital by non-controlling shareholders in subsidiaries	-	-	-	-	-	-	-	-	-	-	-	-	3,563	3,563
- Business Combination - CPFL Renováveis	-	(1,634)	-	-	-	-	-	-	-	-	(1,634)	-	5,086	3,452
Balance at December 31, 2012	4,793,424	228,322	556,481	326,899	-	-	455,906	535,627	(572,225)	56,293	6,380,728	19,741	1,490,660	7,891,129
Total comprehensive income
Net income for the year	-	-	-	-	-	-	-	-	-	937,419	937,419	-	11,617	949,036
Other comprehensive income - actuarial gain	-	-	-	-	-	-	-	-	460,226	-	460,226	-	-	460,226
Internal changes of shareholders'equity
- Realization of deemed cost of fixed assets	-	-	-	-	-	-	-	(39,336)	-	39,336	-	(1,895)	1,895	-
- Tax on deemed cost realization	-	-	-	-	-	-	-	13,374	-	(13,374)	-	644	(644)	-
- Earnings retained for investment	-	-	-	108,987	-	-	-	-	-	(108,987)	-	-	-	-
- Formation of legal reserve	-	-	46,871	-	-	-	-	-	-	(46,871)	-	-	-	-
- Transfer to statutory reserve	-	-	-	(326,899)	326,899	-	-	-	-	-	-	-	-	-
- Statutory reserve for the year	-	-	-	-	(61,863)	-	-	-	-	61,863	-			-
- Other changes in non-controlling shareholders	-	-	-	-	-	-	-	-	-	-	-	-	(68)	(68)
Capital transactions with the shareholders
- Prescribed dividend	-	-	-	-	-	-	-	-	-	5,172	5,172	-	-	5,172
- Interim dividend	-	-	-	-	-	-	-	-	-	(363,049)	(363,049)	-	(2,301)	(365,349)
- Additional dividend proposed	-	-	-	-	-	-	567,802	-	-	(567,802)	-	-	-	-
- Aproval of additional dividend	-	-	-	-	-	-	(455,906)	-	-	-	(455,906)	-	(17,589)	(473,495)
- Payment of capital by non-controlling shareholders in subsidiaries	-	-	-	-	-	-	-	-	-	-	-	-	3,566	3,566
- IPO of CPFL Renováveis	-	59,308	-	-	-	-	-	-	-	-	59,308	-	269,191	328,500
Balance at December 31, 2013	4,793,424	287,630	603,352	108,987	265,036	-	567,802	509,666	(111,998)	-	7,023,899	18,490	1,756,328	8,798,718
Total comprehensive income
Net income for the year	-	-	-	-	-	-	-	-	-	949,177	949,177	-	(62,733)	886,443
Other comprehensive income - actuarial loss	-	-	-	-	-	-	-	-	(225,720)	-	(225,720)	-	-	(225,720)
											-			-
Internal changes of shareholders'equity											-			-
- Realization of deemed cost of fixed assets	-	-	-	-	-	-	-	(39,478)	-	39,478	-	(2,254)	2,254	-
- Tax on deemed cost realization	-	-	-	-	-	-	-	13,422	-	(13,422)	-	766	(766)	-
- Formation of legal reserve	-	-	47,459	-	-	-	-	-	-	(47,459)	-	-	-	-
- Reversion of earnings retained for investment	-	-	-	(108,987)	-	-	-	-	-	108,987	-	-	-	-
- Statutory reserve for the year	-	-	-	-	65,400	554,888	-	-	-	(620,288)	-	-	-	-
- Other changes in non-controlling shareholders	-	-	-	-	-	-	-	-	-	-	-	-	(33)	(33)
											-			-
Capital transactions with the shareholders											-			-
- Prescribed dividend	-	-	-	-	-	-	-	-	-	5,722	5,722	-	-	5,722
- Interim dividend	-	-	-	-	-	-	-	-	-	(422,195)	(422,195)	-	(2,382)	(424,576)
- Aproval of additional dividend	-	-	-	-	-	-	(567,802)	-	-	-	(567,802)	-	(27,156)	(594,958)
- Payment of capital by non-controlling shareholders in subsidiaries	-	-	-	-	-	-	-	-	-	-	-	-	(2,189)	(2,189)
- Increase of capital in subsidiaries without change in control	-	362	-	-	-	-	-	-	-	-	362	-	760	1,123
- Gain / (loss) in interests without change in control	-	(207)	-	-	-	-	-	-	-	-	(207)	-	207	-
- Business combination - CPFL Renováveis / DESA	-	180,297	-	-	-	-	-	-	-	-	180,297	-	653,366	833,663
- Business combination - CPFL Renováveis / DESA - non controlling effect of the subsidiary´ shareholders	-	-	-	-	-	-	-	-	-	-	-	-	106,320	106,320
Balance at December 31, 2014	4,793,424	468,082	650,811	-	330,437	554,888	-	483,610	(337,718)	-	6,943,535	17,003	2,423,975	9,384,513

The accompanying notes are an integral part of these financial statements

F -5

 

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWSFOR THE YEARS ENDED DECEMBER 31, 2014, 2013 and 2012

(In thousands of Brazilian reais – R$)

	2014	2013	2012
OPERATING CASH FLOW
Income for the year, before income tax and social contribution	1,510,304	1,519,200	1,877,998
ADJUSTMENT TO RECONCILE INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES
Depreciation and amortization	1,159,964	1,055,230	978,926
Provision for tax, civil and labor risks	191,228	316,787	94,926
Allowance for doubtful accounts	83,699	70,324	163,811
Interest and monetary adjustment	1,486,061	1,294,281	904,340
Post-employment benefit gain/loss	48,165	61,665	33,332
Interest in associates and joint ventures	(59,684)	(120,868)	(120,680)
Losses on the write-off of noncurrent assets	20,726	7,248	54,579
Deferred taxes (PIS and COFINS)	24,946	28,328	(64,005)
Other	(2,431)	(5,218)	21,919
	4,462,978	4,226,977	3,945,147
DECREASE (INCREASE) IN OPERATING ASSETS
Consumers, concessionaires and licensees	(265,103)	129,731	(435,899)
Dividends and interest on shareholders´ equity receivable	40,374	112,607	79,730
Recoverable taxes	(134)	42,176	51,772
Lease	1,009	1,648	(3,969)
Escrow deposits	65,732	101,310	8,505
Sectorial financial assets	(932,719)	-	-
Resources provided by CDE/CCEE	(352,379)	(145,571)	(24,972)
Other operating assets	(41,665)	(30,725)	(41,289)
INCREASE (DECREASE) IN OPERATING LIABILITIES
Suppliers	470,982	191,089	388,975
Other taxes and social contributions	193,357	(130,405)	(149,121)
Post-employment employee benefit	(118,897)	(85,546)	(79,450)
Regulatory charges	11,415	(78,397)	(27,600)
Tax, civil and labor risks paid	(188,000)	(184,070)	(64,084)
Sectorial financial liabilities	21,998	-	-
Accounts payable – CDE	25,807	9,246	-
Other operating liabilities	83,458	10,820	(23,842)
CASH FLOWS PROVIDED BY OPERATIONS	3,478,213	4,170,890	3,623,904
Interests paid	(1,333,570)	(1,093,465)	(866,025)
Income tax and social contribution paid	(552,070)	(559,879)	(768,578)
NET CASH FROM OPERATING ACTIVITIES	1,592,573	2,517,546	1,989,301
INVESTING ACTIVITIES
Price paid in business combination net of cash acquired	(68,464)	-	(706,186)
Cash acquired in business combination	139,293	-	-
Capital increase in joint ventures	(45,445)	-	-
Payment of acquisition payables	-	-	(172,476)
Increase in property, plant and equipment	(345,049)	(882,588)	(1,027,109)
Financial investments, pledges, funds and tied deposits	(7,839)	41,392	(13,943)
Additions to intangible assets	(716,818)	(852,248)	(1,432,902)
Sale of non-financial asset	43,024	80,945	-
Loans to joint ventures	949	(81,456)	-
Return of advances by the supplier	67,342	-	-
Other	-	(584)	(7,955)
	(933,007)	(1,694,539)	(3,360,571)
NET CASH FLOW USED IN INVESTING ACTIVITIES

F -6

 

FINANCING ACTIVITIES
IPO of CPFL Renováveis	-	328,500	-
Capital increase of non-controlling shareholders	1,123	-	-
Loans, financing and debentures obtained	3,186,384	5,958,322	4,286,812
Loans, financing, debentures and derivatives paid	(2,679,399)	(4,499,451)	(1,737,088)
Dividend and interest on shareholders’ equity paid	(1,016,641)	(838,990)	(1,406,846)
NET CASH FLOW PROVIDED BY (USED IN) FINANCING ACTIVITIES	(508,533)	948,381	1,142,878
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	151,033	1,771,388	(228,392)
OPENING BALANCE OF CASH AND CASH EQUIVALENTS	4,206,422	2,435,034	2,663,425
CLOSING BALANCE OF CASH AND CASH EQUIVALENTS	4,357,455	4,206,422	2,435,034

The accompanying notes are an integral part of these financial statements

F -7

 

CPFL ENERGIA S.A.

NOTES TO THE FINANCIAL STATEMENTS

FOR THE YEARS ENDED ON DECEMBER 31, 2014, 2013 and 2012

(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 Gomes de Carvalho Street, 1510 - 14º floor- Room 142 - Vila Olímpia - São Paulo - SP - Brazil.

The Company has direct and indirect interests in the following subsidiaries and joint ventures (unaudited information on the concession area, number of consumers, energy production capacity and associated data):

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 São Paulo	234	4,128	30 years	November 2027
Companhia Piratininga de Força e Luz ("CPFL Piratininga")	Publicly-quoted corporation	Direct 100%	Interior of São Paulo	27	1,620	30 years	October 2028
Rio Grande Energia S.A. ("RGE")	Publicly-quoted corporation	Direct 100%	Interior of Rio Grande do Sul	255	1,415	30 years	November 2027
Companhia Luz e Força Santa Cruz ("CPFL Santa Cruz")	Private corporation	Direct 100%	Interior of São Paulo and Paraná	27	202	16 years	July 2015
Companhia Leste Paulista de Energia ("CPFL Leste Paulista")	Private corporation	Direct 100%	Interior of São Paulo	7	56	16 years	July 2015
Companhia Jaguari de Energia ("CPFL Jaguari")	Private corporation	Direct 100%	Interior of São Paulo	2	38	16 years	July 2015
Companhia Sul Paulista de Energia ("CPFL Sul Paulista")	Private corporation	Direct 100%	Interior of São Paulo	5	81	16 years	July 2015
Companhia Luz e Força de Mococa ("CPFL Mococa")	Private corporation	Direct 100%	Interior of São Paulo and Minas Gerais	4	45	16 years	July 2015

					Installed power (MW)
Energy generation (conventional and renewable sources)	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, 1 SHPs (a) e 1 Thermal	694	694
CERAN - Companhia Energética Rio das Antas ("CERAN")	Private corporation	Indirect 65%	Rio Grande do Sul	3 Hydroelectric	360	234
Foz do Chapecó Energia S.A. ("Foz do Chapecó")	Private corporation	Indirect 51%	Santa Catarina and Rio Grande do Sul	1 Hydroelectric	855	436
Campos Novos Energia S.A. ("ENERCAN")	Private corporation	Indirect 48.72%	Santa Catarina	1 Hydroelectric	880	429
BAESA - Energética Barra Grande S.A. ("BAESA")	Publicly-quoted corporation	Indirect 25.01%	Santa Catarina and Rio Grande do Sul	1 Hydroelectric	690	173
Centrais Elétricas da Paraíba S.A. ("EPASA")	Private corporation	Indirect 57.13%	Paraíba	2 Thermals	342	195
Paulista Lajeado Energia S.A. ("Paulista Lajeado")	Private corporation	Indirect 59.93% (b)	Tocantins	1 Hydroelectric	903	63
CPFL Energias Renováveis S.A. ("CPFL Renováveis")	Publicly-quoted corporation	Indirect 51.61%	(c)	(c)	(c)	(c)
CPFL Centrais Geradoras Ltda ("CPFL Centrais Geradoras")	Limited company	Direct 100%	São Paulo	9 SHPs	24	24

F -8

 

Commercialization of energy	Company Type	Core activity	Equity Interest
CPFL Comercialização Brasil S.A. ("CPFL Brasil")	Private corporation	Energy commercialization	Direct 100%
Clion Assessoria e Comercialização de Energia Elétrica Ltda. ("CPFL Meridional")	Limited company	Commercialization and 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 Brasil Varejista S.A. ("CPFL Basil Varejista")	Private corporation	Energy commercialization	Indirect 100%

Services	Company Type	Core activity	Equity Interest
CPFL Serviços, Equipamentos, Industria e Comércio S.A. ("CPFL Serviços")	Private corporation	Manufacturing, commercialization, rental and maintenance of electro-mechanical equipment and services	Direct 100%
NECT Serviços Administrativos Ltda ("Nect")	Limited company	Administrative services	Direct 100%
CPFL Atende Centro de Contatos e Atendimento Ltda. ("CPFL Atende")	Limited company	Telephone answering services	Direct 100%
CPFL Total Serviços Administrativos Ltda. ("CPFL Total")	Limited company	Billing and collection services	Direct 100%
CPFL Telecom S.A ("CPFL Telecom")	Private corporation	Telecommunication services	Direct 100%
CPFL Transmissão Piracicaba S.A ("CPFL Transmissão")	Private corporation	Energy transmission	Indirect 100%
CPFL Eficiência Energética S.A ("CPFL ESCO") (e)	Private corporation	Management in energy efficiency (e)	Direct 100%

Other	Company Type	Core activity	Equity Interest
CPFL Jaguariúna Participações Ltda ("CPFL Jaguariuna")	Limited company	Venture capital company	Direct 100%
CPFL Jaguari de Geração de Energia Ltda ("Jaguari Geração")	Limited company	Venture capital company	Direct 100%
Chapecoense Geração S.A. ("Chapecoense") (d)	Private corporation	Venture capital company	Indirect 51%
Sul Geradora Participações S.A. ("Sul Geradora")	Private corporation	Venture capital company	Indirect 99.95%

^(a)     SHP – Small Hydropower Plant.

^(b)     Paulista Lajeado has a 7% participation in the installed power of Investco S.A.(5.94% share of its capital).

^(c)     CPFL Renováveis has operations in São Paulo, Minas Gerais, Mato Grosso, Santa Catarina, Ceará, Rio Grande do Norte, Paraná and Rio Grande do Sul states and its main activities are: (i) holding investments in renewable generation sources; (ii) identification, development, and exploitation of generation potential sources; and (iii) commercialization of electric energy. At December 31, 2014, CPFL Renováveis had a project portfolio of 129 projects of 3,020.5 MW of installed capacity (1,769.0 MW operational), as follows:

·Hydropower generation: 48 SHP’s (571 MW) being38SHP’s operational (399MW) and 10 SHP’s under development (172 MW);

·Wind power generation: 73 projects (2,078.4 MW) being33projects operational (998.9MW) and40projects under construction/development (1.079,5 MW);

·Biomass power generation: 8 operational plants (370MW); 

·Solar energy generation:1solar plant operational (1.1MW).

^(d)Chapecoense fully consolidates the financial statements of its direct subsidiary, Foz de Chapecó.

^(e)  CPFL Eficiência Energética S.A. (“CPFL ESCO”), former CPFL Participações S.A., was set up with the objective of providing services, mainly energy efficiency and quality consultancy and management, asset rental to generation plants, energy commercialization, research and development projects for energy-related programs and participation in the capital of other companies.

F -9

 

In relation to the concessions´ terms that end in July 2015, on 26 June, 2012, our subsidiaries filed a request for extension of the concession contracts, under the present conditions, reserving the right to review the request in the event of changes in the current contractual conditions. Our subsidiaries confirmed the request for extension on October 10, 2012.On January 17, 2014,  ANEEL advised our subsidiaries that it is analyzing the applications for extension of the concessions and the final approval for such extension is within the Grantor responsibilities.By the date of approval of these financial statements,Management doesnot knowthe terms ofthe extension. However, Management expects that the requests for extension will be approved, and if there is no extension, no significant effects are anticipated on the consolidated operations and the financial statements.

( 2 ) PRESENTATION OF THE FINANCIAL STATEMENTS

2.1 Basis of presentation:

The consolidated financial statements were prepared in accordance with International Financial Reporting Standards - IFRS, issued by the International Accounting Standard Board – IASB.

The consolidated financial statements were authorized for issue by the Board of Directors on April 10, 2015.

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 measured at fair value through profit or loss, and iii) available-for-sale financial assets measured at fair value.

2.3 Use of estimates and judgments:

The preparation of the financial statements requires Company 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 accounting estimates are rarely the same as the actual results. Accordingly, Company Management reviews the estimates and assumptions on an ongoing basis, based on previous experience and other relevant factors. Adjustments resulting from reviews to accounting estimates are recorded in the period in which the estimates are reviewed 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 in subsequent periods is included in the following accounts:

·Note 6 – Consumers, concessionaires and licensees;

·Note 8 – Sector financial asset and liability;

·Note 9 – Deferred taxes;

·Note 10 – Leases;

·Note 11 – Financial asset of concession;

·Note 12 – Other Credits (Allowance for doubtful accounts);

·Note 14 – Property, plant and equipment and recognition of impairment losses;

·Note 15 – Intangible assets and recognition of impairment losses;

F -10

 

·Note 19 – Post-employment benefit obligation;

·Note 22 – Provisions for tax, civil and labor risks and escrow deposits;

·Note 24 – Other accounts payable (provision to environmental costs);

·Note 27 – Net operating revenues;

·Note 28 – Cost of electric energy; and

·Note 35 – Financial instruments.

2.4 Functional currency and presentation currency:

The Company’s functional currency is the Brazilian Real, and the financial statements are presented in thousands of reais.  Figures are rounded only after addition of the amounts.  Consequently, when added, the amounts shown in thousands of reais may not tally with the rounded totals.

2.5 Basis of consolidation:

(i) Business combinations

The Company measures goodwill as the fair value of the consideration transferred including the recorded amount of any non-controlling interest in the acquiree, less the recorded amount of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date.

(ii) Subsidiaries and joint ventures:

The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. Joint ventures are accounted for using the equity method of accounting from the moment joint control is established.

The accounting policies of subsidiaries, and joint ventures taken into consideration for consolidation and/or equity method of accounting, as applicable, are aligned with the Company's accounting policies.

The consolidated financial statements include the balances and transactions of the Company and its subsidiaries. The balances and transactions of assets, liabilities, income and expenses have been fully consolidated for our subsidiaries. Prior to consolidation in the Company's financial statements, the financial statements of the subsidiaries CPFL Geração, CPFL Brasil, CPFL Jaguari Geração and CPFL Renováveis are fully consolidated with those of their subsidiaries.

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 Company’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.

In the case of subsidiaries, the portion related to non-controlling shareholders is stated in equity and stated after profit or loss and comprehensive income in each period presented. 

Balances of joint ventures, as well our interest in each of them is described in note 13.2

(iii) Acquisition of non-controlling interest:

Accounted for as equity transaction (within the shareholders’ equity) and therefore no gain or goodwill is recognized as a result of such transaction.

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.

F -11

 

Company Management bases strategic decisions on reports, segmenting the business into: (i) electric energy distribution activities (“Distribution”); (ii) electric energy generation activities from conventional sources (“Generation”); (iii) electric energy generation activities from renewable sources (“Renewables”); (iv) energy commercialization activities (“Commercialization”); (v) service activities (“Services”); and (vi) 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:

The Company's interests in the direct and indirect subsidiaries and joint ventures are described in note 1. Except for (i) the companies ENERCAN, BAESA, Chapecoense and EPASA, which use the equity method of accounting, and (ii) the investment recorded at cost by the subsidiary Paulista Lajeado in Investco S.A., all other entities are fully consolidated.

As of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 the non-controlling interests stated in the financial statements refers to the interests held by third-parties in the subsidiaries CERAN, Paulista Lajeado and CPFL Renováveis, and interests held by third-parties in CPFL Renováveis’ subsidiaries.

( 3 ) SUMMARY OF THE SIGNIFICANT ACCOUNTING POLICIES

The main accounting policies used in preparing the Company’s financial statements are set out below. These policies have been applied consistently to all periods presented.

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.

Considering that these definitions have been attended, the infrastructure of distribution concessionaires is segregated at the time of construction in accordance with the IFRS standards, so that in the financial statements are recorded (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 (indemnity) by transferring control of the assets at the end of the concession.       

The financial asset of the concession is measured based on its fair value, determined in accordance with the remuneration base for the concession assets, pursuant to the legislation in force established by the regulatory authority (ANEEL). It takes into consideration changes in the estimated cash flow, mainly based on factors such as new replacement price, and updated in accordance with the IGP-M. The financial asset is classified as available-for-sale, set against the financial income or expense accounts in profit or loss for the year (Note 4).

The remaining amount is recorded as intangible assets and relates to the right to charge consumers for electric energy distribution services, and is amortized in accordance with the consumption pattern that reflects the estimated economic benefit to the end of the concession.

Services related to the construction of infrastructure are recorded in accordance with IAS 11 – Construction Contracts, against a financial asset corresponding to the amount subject to right to receive cash (indemnity). Residual amounts are classified as intangible assets and are amortized over the term of the concession in proportion to a curve that reflects the consumption pattern in relation to the economic benefits.

Considering that (i) the tariff model that does not provide for a profit margin for the infrastructure construction services, (ii) the way in which the subsidiaries manage  building the infrastructure byusing a high level of outsourcing, and (iii) the fact that there is no provision for profit margin on construction in the Company‘s business plans, Management is of the opinion that the margins on this operation are irrelevant, and therefore no mark-up to the cost is considered in revenue. The revenue and construction costs are therefore presented in profit or loss for the year at the same amounts.

F -12

 

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 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 or when the risks and rewards of ownership of the financial asset are transferred. The Company and its subsidiaries hold the following main financial assets:

i.Fair value through profit or loss: these are 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 and/or investment strategy. These financial assets are measured at fair value, and changes therein are recognized in profit or loss for the year.

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 subsequently measured at amortized cost using the effective interest method, less any impairment losses.

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 subsequently measured at amortized cost using the effective interest method, less any impairment losses.

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 using the effective interest method is recognized in profit or loss as part of the financial income. Changes to fair value of these financial assets are recognized in the other comprehensive income. The accumulated result in the other comprehensive income is transferred to profit or loss when the asset is realized.

- 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 match the effects of recognition of income and expenses to obtain more relevant and consistent accounting information, or (iii) derivatives. These liabilities are recorded at fair value and any change in their fair value is subsequently recorded in profit or loss.

ii.Other financial liabilities (not measured at fair value through profit or loss): these are other financial liabilities not classified in the previous category. They are measured initially at fair value net of any transaction cost and subsequently measured at amortized cost using the effective interest method.

The Company accounts for guarantees when issued to non-controlled entities or when the financial guarantee is granted to joint ventures at a percentage higher than the Company's interest to cover commitments of joint ventures. Such financial guarantees are initially measured at fair value, by recording (i) a liability corresponding to the risk of non-payment of the debt, which is amortized against financial income simultaneously and in proportion with amortization of the debt, and (ii) an asset equivalent to the right to compensation by the guaranteed party or a prepaid expense underthe guarantees, which is amortized by receipt of cash from other shareholders or at the effective interest rate over the term of the guarantee. After initial recognition, the liability related to the financial guarantee is assessed periodically at the higher of the amount determined in accordance with IAS 37 and the amount initially recognized less accumulated amortization.

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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 the liability simultaneously.

The financial instruments classifications are described on Note 35.

- Capital

Common shares are classified as equity. Additional costs directly attributable to share issues and share options are recognized as a deduction from equity, net of any tax effects.

3.3 Lease

At the inception of an agreement is determined 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 lessee 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 commencement of the lease against a liability measured at an amount equal to the lower of its fair value and the present value of the minimum future lease payments. Property, plant and equipment are depreciated over the shorter of the estimated useful life of the asset or the lease term.

For the financial leases the Company or its subsidiaries act as lessor, receivables from lessees are initially recorded based on the fair value of the asset leased.

In both cases, the financial income/expense is recognized in profit or loss over the term of the lease so as to produce an effective interest rate 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 restoring the site on which they are located and capitalized borrowing costs on qualifying assets.

The replacement cost of items of property, plant and equipment is recognized if it is probable that it will involve economic benefits 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 Grantor.

Gains and losses derived from write off of an item of property, plant and equipment are determined by comparing the resources produced by disposal with the 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,  but determines that the proceeds of the disposal be deposited in a tied bank account for use in theconcession.

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3.5 Intangible assets

Includes rights related to non-physical assets such as goodwill and concession exploitation rights, software and rights-of-way.

Goodwill that arises on the acquisition of subsidiaries is measured at the difference between the fair value of the consideration transferred for acquisition of a business and the net fair value of the assets and liabilities of the subsidiary acquired.

Goodwill is subsequently measured at cost less accumulated impairment losses. Goodwill and other intangible assets, if any, with indefinite useful lives, are not subject to amortization and are tested annually for impairment.

Negative goodwill is recorded as gain in the income statement in the year of the business acquisition.

Intangible assets corresponding to the right to operate concessions may have three origins, as follows:

i.Acquisitions through business combinations: the portion arising from business combinations that corresponds to the right to operate the concession is stated as an intangible asset. Such amounts are amortized over the remaining term of the concessions, on a straight-line basis or based on the net income curves projected for the concessionaires, as applicable.

ii.Investments in infrastructure (Application IFRIC 12 – Concession agreements): under the electric energy distribution concession agreements with the subsidiaries, the intangible asset recorded corresponds to the concessionaires' right to charge the consumers for use of the concession infrastructure. Since the exploitation 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 economic benefits. For further information see note 3.1.

The infrastructure components are directly tied to the Company's operation and may not be removed, disposed of, assigned or pledged in mortgage without the prior and express authorization of ANEEL. In Resolution 20, of 3 February 1999, ANEEL authorizes public electric energy utilities concessionaires to release from their assets property and assets considered to be of no use to the concession, in accordance with articles 63 and 64 of Decree 41,019, of February 26, 1957, as amended by Decree 56,227 of April 30, 1965.

iii.Public utilities: upon certain generation concessions were granted the concessionaires assumed an obligation to pay the federal government for use of public assets. On the signing date of the respective agreements the Company’s subsidiaries recoded intangible assets and the corresponding liabilities at fair value. The intangible assets, capitalized by interest incurred on the obligation until the start-up date, are amortized on a straight-line basis over the remaining term of each concession.   

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 for both specific asset and at a collective level for all significant securities. Receivables and held-to-maturity investment securities that are not individually significantare collectively assessed for impairment by grouping together the securities with similar risk characteristics.

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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 higher or lower than suggested by historic trends.

An impairment loss of a financial asset is recognized as follows:

I.Amortized cost: as the difference between the carrying amount and the present value of the estimated future cash flows discounted at the asset’s original effective interest rate. Losses are recognized in profit or loss and shown in an allowance account against receivables. When a subsequent event indicates that the amount of impairment loss has decreased, this reduction is reversed to credit through profit or loss.

II.Available-for-sale: as 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. Losses are recognized in profit or loss.

In the case of financial assets recorded at amortized cost and/or debt instruments classified as available-for-sale, if an increase (gain) is identified in subsequent periods, the impairment loss is reversed through profit or loss. However, any subsequent recovery in the fair value of an impaired equity instrument classified as available-for-sale is recognized in other comprehensive income.

- Non-financial assets

Non-financial assets that have indefinite useful lives, such as goodwill, are tested annually for impairment to assess whether the asset's carrying amount does not exceed its 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 and 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, concession asset) are segregated and grouped together at the lowest level that generates identifiable cash inflows (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 impairment which cannot be reversed in the subsequent period, impairment losses are reassessed annually for any possibility of reversals.

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. When applicable, provisions are determined by discounting the expected future cash outflows at a rate that reflects current market assessment and the risks specific to the liability.

3.8 Employee benefits

Certain subsidiaries have post-employment benefits including pension plans, recognized by the accrual method in accordance with IAS 19 “Employee benefits” (as revised 2011), and are regarded as sponsors of these plans. Although the plans have particularities, they have the following characteristics:

i.Defined contribution plan: a post-employment benefit plan under which the Sponsor pays fixed contributions into a separate entity and will have no liability for the actuarial deficits of the plan. The obligations are recognized as an expense in profit or loss in the periods during which the services are rendered.

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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 as of the reporting date. The actuarial liability is calculated annually by independent actuaries, under the responsibility of Management, using the projected unit credit method. Actuarial gains and losses are recognized in Other Comprehensive Income when they occur. Net Interest (income and expense) are calculated by applying the discount rate in the beginning of the period to the plan net liability or asset and the defined benefit obligation. When applicable, the cost of past services is recorded immediately in profit or loss.

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 future 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 Company´s bylaws. 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 present liability criteria 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 an interim dividend and Interest on shareholders’ equity determined in a half-yearly balance sheet. An interim dividend and interest on shareholders’ equity declared at the base date of June 30 is only recorded as a liability in the Company's financial statement after the date of the Board's decision.

Interest on shareholders' equity is treated in the same way as dividends and is also stated in changes in shareholders’ equity. Withholding tax on interest on shareholders' equity is debited against shareholders’ equity when proposed by Management, as it fulfills the obligation criteria at that time.

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, 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 supplied. Unbilled revenue related to the monthly billing cycle is appropriated based on the actual amount of energy provided in the month and the annualized loss rate. Revenue from energy generation sales is accounted 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 Company´s net revenue.

Service revenue is recognized when the service is effectively provided, under a service agreement between the parties.

Revenue from construction contracts is recognized based on the percentage of completion method (“fixed-price”), and losses, if any, are recognized in profit or loss as incurred.

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3.11 Income tax and Social contribution

Income tax and Social contribution expense are calculated and recognized in accordance with the legislation in force and comprise current and deferred taxes. Income tax and social contribution are recorded in profit or loss except to the extent that they relate to items recorded directly in equity or other comprehensive income, or those taxes effects arising from business combinations.

Current taxes are the expected taxes payable or receivable/to be offset on the taxable income or loss. Deferred taxes are recorded for temporary differences between the carrying amounts of assets and liabilities for accounting purposes and the equivalent amounts used for taxes purposes and for taxes loss carryforwards.

The Company and certain subsidiaries recorded in their financial statements the effects of taxes loss carryforwards and deductible temporary differences, based on projections of future taxable profits, approved annually by the Boards of Directors and examined by the Fiscal Council. The subsidiaries also recognized taxes credits on merged goodwill, which are amortized in proportion to the individual projected net incomes for the remaining term of each concession agreement.

Deferred taxes assets and liabilities are offset if there is a legally enforceable right to offset current taxes liabilities and assets, and they relate to 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 they are no longer probable that the related taxes benefit will be realized.

3.12 Earnings per share

Basic earnings per share are calculated by dividing the profit or loss for the year attributable to the Company’s controlling shareholders by the weighted average number of shares outstanding during the year. Diluted earnings per share are calculated by dividing the profit or loss for the year attributable to the controlling shareholders, adjusted by the effects of instruments that potentially would have impacted the profit or loss for the year by the weighted average of the number of shares outstanding, adjusted by the effects of all dilutive potential convertible notes for the reporting periods, in accordance with IAS 33.

3.13 Government grants – CDE (Energy Development Account)

Government grants are only recognized when it is reasonably certain that the amounts will be received by the Company. They are recorded in profit or loss for the periods in which the Company recognizes as income the discounts granted in relation to the low-income subsidy and other tariff discounts and as expense the costs of hydrological risk, involuntary exposure and ESS - Energy System Service charges.

The subsidies received through funds from the CDE (Notes 27 and 28) have the main purpose to  offset discounts granted and expenses already incurred in order to provide immediate financial assistance to the distribution companies, in accordance with IAS 20.

3.14 Sector financial asset and liability

According to the tariff-pricing mechanism applicable to distribution companies, the energy tariffs are set at a price level that ensures  the economic and financial equilibrium of the concession. Therefore, the concessionaires are authorized to charge  from their consumers (after review and ratification by ANEEL) for: (i) the annual tariff increase; and (ii) every four or five years, depending on the  respective concession contract, adjustments resulting from the periodic review relating to Parcel B (controllable costs) and Parcel A (non-controllable costs) as described below.

The distributors' revenue is mainly comprised of the sale of electric energy and transmission electric energy via the distribution infrastructure (network). The distribution concessionaires' revenue is affected by the volume of energy delivered and the tariff. The electric energy tariff is comprised of two parcels which reflect the revenue breakdown:

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·Parcel A (non-controllable costs): this parcel should be neutral in relation to the entity's performance, i.e., the costs incurred by the distributors, classifiable as “Parcel A” is fully passed through the consumer or borne by the Granting Authority ; and

·Parcel B (controllable costs) – comprised of capital expenditure on investments in infrastructure, operational costs and maintenance and remuneration to the providers of capital. This parcel effectively affects the entity's performance, since it has no guarantee of tariff neutrality and thus involves an intrinsic business risk.

This tariff-pricing mechanism can cause temporal differences arising from the difference between the budgeted costs (Parcel A and other financial components) included in the tariff at the beginning of the tariff period and those actually incurred while it is in effect. This difference constitutes a right of the concessionaire to receive cash when the budgeted costs included in the tariff are lower than those effectively incurred, or an obligation to pay if the budgeted costs are higher than those effectively incurred.

On November 25, 2014, ANEEL approved an amendment to the distribution companies’ concession contracts, to include a specific clause that guarantee the receipt from or requires payment to the grantor of outstanding balances (assets or liabilities) to be adjusted in future rates or upon termination of the concession contracts.  

On December 10, 2014, our eight distribution subsidiaries signed the amendments to their respective concession contracts. The amendment includes a specific clause that assures the receipt or payment for outstanding balances (assets or liabilities) of any insufficient collection or reimbursement through the tariff resulting from termination of the concession, for any reason. These contractual amendments guarantee the unconditional right to receive or the obligation to pay cash or another financial instrument. This amendment eliminates any uncertainty as to the realization of the asset or creation of the liability. Accordingly, the Company and its distribution subsidiaries recognized the components of Parcel A and other financial components, such as financial assets and liabilities with a corresponding adjustment to other operating revenue, in the Net Operating Revenue. After the initial recognition, the assets and liabilities are monetarily restated based on the variation in the SELIC or IPCA rates, based on to their respective nature.

In accordance with IAS 8, this was prospectively from December 2014.

3.15 Business combination

Business combinations are accounted for by applying the acquisition method. The consideration transferred in a business combination is measured at fair value, calculated as the sum of the fair values of the assets transferred by the acquirer, the liabilities incurred at the acquisition date to the former owner of the acquiree and the equity interests issued by the acquirer in exchange for control of the acquiree. Costs related to the acquisition are generally recognized in profit or loss, when incurred.

The non-controlling interests are initially being measured either at fair value or at the non-controlling interest’s proportionate share of the acquiree’s identifiable net assets. The measurement method is chosen on a transaction-by-transaction basis.

The excess of the consideration transferred over the fair value of the identifiable assets (including the intangible asset of operation of the concession) and net liability assumed at the acquisition date is recognized as goodwill. In the event that the fair value of the identifiable assets (including the intangible asset of operation of the concession) net liabilities assumed exceeds the consideration transferred, a bargain purchase is identified and the gain is recognized in the statement of income at the acquisition date.

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3.16 New standards and interpretations adopted

A number of IASB standards were issued or revised in 2014 and are mandatory for accounting periods beginning on January 1, 2014:

a)Amendments to IAS 32 - Offsetting of financial assets and liabilities

The amendments to IAS 32 clarify questions related to the requirements for offsetting of financial assets and liabilities and address inconsistencies in the previous standard for application of the offsetting criteria. The amendments clarify the meaning of "currently has a legal right to set-off" and "simultaneous realization and settlement".

As the Company and its subsidiaries have no financial assets and liabilities that qualify for offsetting, application of the amendments had no impact on the disclosures or amounts recognized in the financial statements.

b)Amendments to IFRS 10, IFRS 12 and IAS 27 - Investment entities

The amendments to IFRS 10 define an investment entity and require an entity that reports and falls into this category to not consolidate its subsidiaries, but to measure them at fair value through profit or loss. To be classified as an investment entity, an entity shall: (i) obtains funds from one or more investors for the purpose of providing those investor(s) with investment management services; (ii) commits to its investor(s) that its business purpose is to invest funds solely for returns from capital appreciation, investment income, or both; and (iii) measures and evaluates the performance of substantially all of its investments on a fair value basis.

Changes were consequently made to IFRS 12 and IAS 27 to introduce new disclosure requirements for investment entities.

As the Company is not an investment entity (applying the criteria defined by IFRS 10, application of the amendments had no impact on the disclosures or amounts recognized in the financial statements).

c)IFRIC 21 - Levies

IFRIC 21 addresses accounting for liabilities for levies if the liability is within the scope of IAS 37. It also addresses accounting for a levy liability for which the amount and term are known.

The Company first applied these amendments, retrospectively, in the current financial year.  However, application of the amendments had no significant impact on the disclosures or the amounts recognized in the financial statements.

d)Amendments to IAS 36 - Recoverable amount disclosures for non-financial assets

The amendments to IAS 36 address the disclosure of information about the recoverable amount of assets if based on fair value less costs of decommissioning. These amendments exclude the requirements for disclosure of the recoverable amount of a cash generating unit to which an intangible asset with an indefinite useful life has been allocated if there has been no reduction in the recoverable amount or reversal of a reduction in the recoverable amount.

Additional disclosures were also introduced for when the recoverable amount of an asset is measured at fair value less disposal costs, including fair value hierarchy and appreciation assumptions used.

The application of the amendments had no impact on the in the financial statements of the Company since the recoverable amounts of the assets are based on their values in use.

e)Amendments to IAS 39 – Novation of derivatives and continuation of hedge accounting

The amendments to IAS 39 (i) provide relief from the requirement to discontinue hedge accounting when a hedging instrument is novated and (ii) clarify that any change in the fair valueof the derivative hedge instrument that occurs after the novation shall be included in the assessment and measurement of the effectiveness of the hedge.

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The Company does not apply hedge accounting in its transactions and these amendments therefore had no impact on the disclosures or the amounts recognized in the financial statements.

f)Amendments to the IFRS - annual improvements to IFRS 2010-2012 cycle applicable from July 1, 2014)

The following Improvements were established in these amendments:

f.1) Amendments to IFRS 2: (i) amend the definitions of "vesting condition" and "market condition"; and (ii) add a "performance condition" and a "service condition", both of which were previously incorporated within the definition of a vesting condition;

f.2) Amendments to IFRS 3: clarify that contingent considerations classified as assets or liabilities should be remeasured to fair value at each reporting date, irrespective of whether they are a financial instrument or a non-financial asset or liability. Changes in fair value that are not measurement adjustments for the period should be recognized in profit or loss for the year;

f.3) Amendments to IFRS 8: require the disclosure of judgments made by management in aggregation of operating segments, including a description of the segments that have been aggregated and the indicators considered in determining that the aggregated operating segments share "similar economic characteristics". The amendments also clarify that a reconciliation of the total of reportable segments assets to the Company’s assets is only required if a measure of segment assets is regularly used by the decision makers.

f.4) Amendments to the basis for conclusions of IFRS 13: the amendments clarify that short-term receivables and payables with no stated interest rate can still be measured at the invoice amount without discounting, where the effect of discounting is immaterial.  As there is no initial effective date for these amendments, they are taken to be effective immediately;

f.5) Amendments to IAS 16 and IAS 38: these amendments eliminate inconsistencies in accounting for accumulated depreciation and amortization on revaluation of intangible assets and/or items of property, plant and equipment.  They clarify that the gross carrying amount is adjusted in a manner consistent with revaluation of the asset and that the accumulated depreciation or amortization is the difference between the gross value of the asset and its value after accumulated impairment losses.

f.6) Changes to IAS 24: These clarify that a management entity providing key management personnel services to a reporting entity is a related party of the reporting entity. Consequently, the Company has to disclose the amounts incurred, paid or payable to the group entity for the service, as transactions with related parties, set against the provision of services of key management personnel. However, it is not necessary to disclose the components of the consideration paid.

The application of the amendments had no significant impact on the disclosures or the amounts recognized in the financial statements of the Company.

g)Amendments to the IFRS - annual improvements to IFRS 2011-2013 cycle (applicable from July 1, 2014)

The following Improvements were established in these amendments:

g.1) Amendments to IFRS 3: these amendments clarify that IFRS 3 does not apply to all types of joint arrangement in the financial statements of the joint arrangement itself;

g.2) Amendments to IFRS 13: these amendments clarify that the scope of the exclusions for measurement of the fair value of financial assets and liabilities with offsetting positions includes all contracts that fall within the scope of or are recorded in accordance with IAS 39 or IFRS 9, even if the contracts do not meet the definition of financial assets or financial liabilities included in IAS 32;

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g.3) Amendments to IAS 40: These clarify that IAS 40 and IFRS 3 are not mutually exclusive and application of both standards may be required. Consequently, a company acquiring investment property has to determine whether it meets the definition of investment property pursuant to IAS 40 and the definition of a business combination in the scope of IFRS 3.

The application of the amendments had no significant impact on the disclosures or the amounts recognized in the financial statements of the Company.

3.17 New standards and interpretations not yet adopted:

A number of new IFRS standards and amendments to the standards and interpretations were issued by the IASB and had not yet come into effect for the year ended December 31, 2014. Consequently, the Company has not adopted them:

a)IFRS 9 - Financialinstruments

It established new requirements for classification and measurement of financial assets and liabilities. Financial assets are classified in two categories: (i) measured at fair value at initial recognition; and (ii) measured at amortized cost, based on the business model under which they are held and the characteristics of the contractual cash flows.

With regard to financial liabilities, the main alteration in relation to the requirements already set by IAS 39 requires any change in fair value of a financial liability designated at fair value through profit or loss attributable to changes in the liability's credit risk to be stated in other comprehensive income and not in profit or loss, unless such recognition results in incompatibility in profit or loss.

Adoption is scheduled from January 1, 2018, including the changes related to impairment, measurement and classification. 

In relation to changes in financial assets, the distribution subsidiaries have relevant assets classified as available-for-sale, in accordance with the current requirements of IAS 39. These assets represent the right to compensation at the end of the distribution subsidiaries' concession terms. These instruments are designated as available-for-sale as they are not classified in the other three categories established by IAS 39 (loans and receivables, fair value through profit or loss and held-to-maturity).

If these instruments were to be classified in accordance with the new concepts of fair value or amortized cost, they would be designated and registered at "fair value through profit or loss". These financial assets correspond to the fair value of compensation at the end of the concession, and therefore fall into this category.

Based on a preliminary evaluation of initial adoption of these changes, the Company estimates that although it holds financial assets classified as available-for-sale, there will be no relevant impacts on its financial statements.

b)IFRS 14 - Regulatorydeferral accounts

IFRS 14 establishes that rate-regulated entities may continue to recognize regulatory deferral accounts only in connection with their first-time adoption of IFRS, allowing first-time adopters to continue to apply their previous GAAP accounting policies in relation to regulatory assets and liabilities.

IFRS 14 is effective for the first annual financial statements of an entity prepared in accordance with IFRS for annual periods beginning on or after 1 January 2016. Earlier application is permitted.

As the Company and its subsidiaries are not first-time adopters of IFRS, there will be no impact on their financial statements.

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c)IFRS 15 - Revenue from contracts with customers

IFRS 15 provides a single, straightforward model for accounting for contracts with customers, and when it comes into effect, will substitute the current guide for revenue recognition provided in IAS 18 – Revenue and IAS 11 - Construction contracts and related interpretations.

The standard establishes that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard introduces a five-step model for revenue recognition: (1) Identify the contract with the customer; (2) Identify the performance obligations in the contract; (3) Determine the transaction price; (4) Allocate the transaction price to the performance obligations in the contract and (5) Recognize revenue when (or as) the entity satisfies a performance obligation.

Under IFRS 15, an entity recognizes revenue when (or as) the entity satisfies a performance obligation, i.e., when the "control" over the goods and services in a certain operation is transferred to the customer, and will establish a greater level of detail in the disclosures.

The standard will be applicable for annual reporting periods beginning on or after 1 January 2017, and the Company is assessing the potentials impacts of adoption of this new pronouncement.

d)Amendments to IFRS 11 - Accounting for acquisition of an interest in a joint operation

The amendments to IFRS 11 provide instructions for accounting for an interest in a joint operation that constitute a "business" under the definition established in IFRS 3 – Business combinations.  

The amendments established the relevant principles for accounting for a business combination in respect of testing for impairment of an asset to which the goodwill arising from acquisition of the business combination has been allocated. The same requirements should be applied in setting up a joint arrangement if, and only if, a business that existed previously benefits from the joint arrangement in the case of one of the participating parties. A business combination is also required to disclose the relevant information required by IFRS 3 and the other business combination standards.

These amendments apply prospectively to annual periods beginning on or after 1 January 2016.  Based on a preliminary evaluation of initial adoption of these amendments, the Company estimates that there will be no relevant impacts on its financial statements.

e)Amendments to IAS 16 and IAS 38 - Clarification of acceptable methods of depreciation and amortization

The amendments to IAS 16 prohibit the use of the revenue based depreciation method.

The amendments to IAS 38 introduced the premise that revenue is an inappropriate basis for amortizing an intangible asset, except when: (i) the intangible asset is expressed as a measure of revenue; or (ii) when it can be demonstrated that revenue and the economic benefits of the intangible asset are highly correlated.

These amendments apply prospectively to annual periods beginning on or after 1 January 2016. The Company currently amortizes some of its intangible asset of concession based on the projected income curve of the concessionaires over the remaining term of the concession. These projections are reviewed annually. The balances of the subsidiary CPFL Renováveis are amortized over the remaining term of the exploration rights, by the straight-line method.

Considering these amendments, this method no longer will be permitted, and the Company will amortize these intangible assets prospectively and from 2016 using the straight-line method over the remaining term of the concessions. The preliminary and initial estimate of the impact is R$ 91,255 lower amortization between 2016 and 2021, generating higher net income, estimated at R$ 85,415. This effect will be offset against higher amortization between 2022 and 2036.

F -23

 

f)  Amendment to IAS 19 - Defined Benefit Plans: Employee Contributions

These amendments apply to employees or third-party contributions to the defined benefit plans. The objective of the amendments is to simplify accounting for contributions that do not relate to the years of service of the employee, e.g. employee contributions that are calculated in accordance with a fixed percentage of the salary.

The amendments are effective for annual periods from July 1, 2014. Based on a preliminary analysis, the Company does not anticipate relevant impacts on its financial statements.

( 4 ) DETERMINATION OF FAIR VALUES

A number of the Company’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.

Accordingly, the Company measures fair value in accordance with IFRS 13, which define fair value as an estimate of the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, under current market conditions. 

- 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 fair value 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 valued based on quoted prices in an active market, or, if such prices were not available, 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, when available, from the BM&FBOVESPA S.A – Bolsa de Valores, Mercadorias e Futuros (“BM&FBOVESPA”) and “Associação Brasileira das Entidades dos Mercados Financeiro e de Capitais – ANBIMA” (note 35)and also includes the debtor's credit rating.

Financial assets classified as available-for-sale refer to the right to compensation, to be paid by the Federal Government regarding the assets of the distribution concessionaires when the concession contract is over. 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, involves assessing the replacement price for the distribution infrastructure, in accordance with criteria established by the Grantor (“ANEEL”). 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.

The Law nº 12,783 on January 11, 2013, established that, for concession contracts that expire by 2017, calculation of the amount of compensation due on reversal of the assets will be based on the replacement value method, according to regulatory criteria to be established the granting authority.In the case of concessions terms that expire after 2017, Management believes that, compensation will be based at least on valuation of the assets using the new replacement value model, as under Law 12,783/13.

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 Grantor 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 accordance with the tariff review process.

F -24

 

( 5 ) CASH AND CASH EQUIVALENTS

	December 31, 2014	December 31, 2013
Bank balances	177,872	132,130
Short-term financial investments	4,179,583	4,074,292
Overnight investment (a)	84,512	46,809
Bank deposit certificates (b)	557,018	377,556
Repurchase agreements with debentures (b)	15,985	8,970
Investment funds (c)	3,522,069	3,640,957
Total	4,357,455	4,206,422

a)Overnight investment, which earn daily interest by investment in repurchase agreements secured on debentures and interest of 20% of the variation in the Interbank Deposit Certificate - CDI.

b)Short-term investments in Bank Deposit Certificates and secured debentures with major financial institutions that operate in the Brazilian financial market, with daily liquidity, low credit risk and interest equivalent, on average, to 101% of the CDI.

c)Exclusive Fund investments, with daily liquidity and interest equivalent, on average, of 101% of the CDI, subject to floating rates tied to the CDI linked to federal government bonds, CDBs, financial bills and secured debentures of low credit risk financial institutions.

( 6 ) CONSUMERS, CONCESSIONAIRES AND LICENSEES

In the financial statements, the balance derives mainly from the supply of electric energy. The following table shows the breakdown at December 31, 2014 and 2013:

		Past due		Total
	Amounts coming due	until 90 days	> 90 days	December 31, 2014	December 31, 2013
Current
Consumer classes
Residential	196,656	234,465	38,197	469,318	500,623
Industrial	85,161	51,311	34,600	171,072	179,953
Commercial	90,574	46,308	11,238	148,120	173,828
Rural	27,882	7,300	1,136	36,319	35,023
Public administration	38,606	8,052	418	47,076	33,906
Public lighting	31,633	5,541	7,976	45,151	38,134
Public utilities	43,547	5,100	131	48,777	41,182
Billed	514,060	358,077	93,696	965,833	1,002,649
Unbilled	705,318	-	-	705,318	627,852
Financing of consumers' debts	73,217	10,272	20,023	103,512	128,782
Free energy	388	-	-	388	4,161
CCEE transactions	227,986	-	-	227,986	21,313
Concessionaires and licensees	334,403	-	-	334,403	324,535
Other	18,271	-	-	18,272	24,254
	1,873,643	368,349	113,718	2,355,712	2,133,546
Allowance for doubtful accounts				(104,588)	(125,758)
Total				2,251,124	2,007,789
Non current
Financing of consumers' debts	96,547	-	-	96,547	120,042
Free energy	4,139	-	-	4,139	-
CCEE transactions	41,301	-	-	41,301	41,301
	141,988	-	-	141,988	161,343
Allowance for doubtful accounts				(18,583)	(7,489)
Total				123,405	153,854

Financing of Consumers' Debts -Refers to the negotiation of overdue receivables from consumers, principally public administration. 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 (VAT)revenue is received. Allowances for doubtful accounts are based on best estimates of Management for unsecured amounts.

F -25

 

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) adjustments of entries made by the CCEE in response to certain legal decisions (preliminary orders) in the accounting processes for the period from September 2000 to December 2002; and (ii) 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 valuation allowance was recorded for these transactions.

Concessionaires and Licensees- Refers basically to accounts receivable in respect of the supply of electric energy to other concessionaires and licensees, mainly by the subsidiaries CPFL Geração, CPFL Brasil and CPFL Renováveis.

Allowance for doubtful accounts

Changes in the allowance for doubtful accounts are shown below:

	Consumers, concessionaires and licensees	Other Credits (note 12)	Total
At December 31, 2011	(85,314)	-	(85,314)
Reversion/(constitution) of allowance for doubtful accounts	(165,620)	(22,000)	(187,620)
Recovery of revenue	23,809	-	23,809
Write-off of accounts receivable reserved for	98,646	-	98,646
At December 31, 2012	(128,478)	(22,000)	(150,479)
Reversion/(constitution) of allowance for doubtful accounts	(111,768)	3,999	(107,769)
Recovery of revenue	35,016	2,429	37,445
Write-off of accounts receivable reserved for	71,984	2,421	74,405
At December 31, 2013	(133,247)	(13,152)	(146,400)
Reversion/(constitution) of allowance for doubtful accounts	(129,482)	(3,444)	(132,925)
Recovery of revenue	49,363	(136)	49,227
Write-off of accounts receivable reserved for	90,196	1,446	91,642
At December 31, 2014	(123,171)	(15,285)	(138,457)
Current	(104,588)	(13,304)	(117,892)
Noncurrent	(18,583)	(1,981)	(20,564)

F -26

 

( 7 ) RECOVERABLE TAXES

	December 31, 2014	December 31, 2013
Current
Prepayments of social contribution - CSLL	21,951	3,054
Prepayments of income tax - IRPJ	32,030	5,767
IRRF on interest on equity	21,044	14,537
Income tax and social contribution to be offset	51,236	14,731
Withholding tax - IRRF	88,249	106,627
ICMS to be offset	66,641	77,559
Social Integration Program - PIS	7,527	6,783
Contribution for Social Security financing- COFINS	38,098	30,123
National Social Security Institute - INSS	1,846	2,279
Other	1,015	972
Total	329,638	262,433
Noncurrent
Social contribution to be offset - CSLL	46,555	42,848
Income tax to be offset - IRPJ	8,352	11,851
ICMS to be offset	79,223	99,777
Social Integration Program - PIS	1,576	3,073
Contribution for Social Security financing- COFINS	7,305	14,116
Other	1,372	1,698
Total	144,383	173,362

Withholding tax - IRRF–The balance at December 31, 2014 and 2013 relates mainly to the IRRF on financial investments.

Social contribution to be offset – CSLL– In noncurrent, the balance refers primarily to the final favorable decision in a lawsuit filed by the subsidiary CPFL Paulista. The subsidiary CPFL Paulista is awaiting the normal course of permission by the Federal tax authority in order to systematically offset the credit.

ICMS (VAT) to be offset – Noncurrent balance mainly refers to the credit recorded on acquisition of assets that result in the recognition of intangible assets and financial assets.

PIS and COFINS – In noncurrent, the balance refers basically to credits recognized by the indirect subsidiary CPFL Renováveis in relation to the acquisition of equipment, which will be realized by depreciation of the equipment.

F -27

 

( 8 ) SECTOR FINANCIAL ASSETS AND LIABILITIES

	December 31, 2014
Parcel "A"
CVA (*)
CCC (**)	58
CDE	53,198
Eletric energy cost	1,248,165
EER (Energy reserve charge)	(18,922)
ESS	(603,321)
Proinfa	9,249
Basic network charges	154,593
Passthrough from Itaipu	(309,727)
Transmission from Itaipu	4,076
Neutrality of the sector charges	(12,338)
Overcontracting	597,422
Other financial components	(211,735)
	910,720
Current asset	610,931
Noncurrent asset	321,788
Current liability	(21,998)
	910,720

(*) Deferred tariff costs and gains variations from Parcel “A” items

(**) Fuel consumption account

As the sector financial assets and liabilities were recognized in December 2014, no financial income or expense was appropriated for the year ended December 31, 2014.

a) CVA

Refers to Parcel A accounts variation, in accordance with note 3.14. The amounts recorded are monetarily adjusted by SELIC rate and are compensated in the subsequent tariff adjustments.

b) Overcontracting

Electric energy distribution concessionaires are obliged to guarantee 100% of their energy market through contracts approved, registered and ratified by ANEEL. It is also assured to the distribution concessionaries that costs or income derived from overcontracting will be passed through the tariffs, up to 5% of the energy load requirement. These amounts are monetarily adjusted by IPC-A (surpluses) and by SELIC (shortfalls) rates and are compensated in the subsequent tariff adjustments.

c) Tariff review / provisional procedure

These are financial components granted to compensate any re-calculations of tariff processes by ANEEL so as to neutralize the effects on consumers.

F -28

d) Other financial components

Mainly refers to (i) price exposure differences between sub-markets imposed on the distribution agents who entered into Agreements for commercialization of electric energy in the regulated environment - CCEAR and (ii) financial guarantees related to prior guarantees required from the distributors in the commercial transactions between sector agents.

( 9 ) DEFERRED TAXES

9.1- Breakdown of tax credits and debits:

	December 31, 2014	December 31, 2013
Social contribution credit/(debit)
Tax losses carryforwards	47,564	47,660
Tax benefit of merged goodwill	107,359	121,820
Deductible temporary differences	(290,367)	(185,861)
Subtotal	(135,444)	(16,381)
Income tax credit / (debit)
Tax losses carryforwards	126,085	141,113
Tax benefit of merged goodwill	367,944	416,418
Deductible temporary differences	(807,934)	(519,615)
Subtotal	(313,906)	37,917
PIS and COFINS credit/(debit)
Deductible temporary differences	2,348	30,025
Total	(447,002)	51,560
Deferred tax assets	938,496	1,168,706
Deferred tax liabilities	(1,385,498)	(1,117,146)

9.2 - Tax benefit of merged goodwill:

Refers to the tax credit calculated on the goodwill derived from the acquisition of subsidiaries, as shown in the following table, which had been incorporated and is recognized in accordance with CVM Instructions nº 319/99 and nº 349/01. The benefit is realized proportionally to amortization of the merged goodwill that gave rise to it, in accordance with the projected net income of the subsidiaries during the remaining term of the concessions, as shown in note 15.

	December 31, 2014		December 31, 2013
	Social contribution	Income tax	Social contribution	Income tax
CPFL Paulista	61,819	171,719	68,938	191,495
CPFL Piratininga	14,691	50,417	16,148	55,414
RGE	28,496	117,683	31,342	129,436
CPFL Santa Cruz	869	2,733	1,757	5,525
CPFL Leste Paulista	387	1,184	939	2,863
CPFL Sul Paulista	603	1,892	1,386	4,332
CPFL Jaguari	312	962	824	2,516
CPFL Mococa	182	554	485	1,499
CPFL Geração	-	20,800	-	23,282
CPFL Serviços	-	-	-	57
Total	107,359	367,944	121,820	416,418

F -29

 

9.3 - Accumulated balances on nondeductible temporary differences:

	December 31, 2014			December 31, 2013
	Social contribution	Income tax	PIS/COFINS	Social contribution	Income tax	PIS/COFINS
Nondeductible temporary differences
Provision for tax, civil and labor risks	29,282	81,340	-	29,969	83,241	-
Post-employment benefit obligation	1,900	5,277	-	2,004	5,566	-
Allowance for doubtful accounts	12,422	34,506	-	13,379	37,163	-
Free energy provision	6,210	17,251	-	5,429	15,081	-
Research and Development and Energy Efficiency Programs	11,821	32,836	-	11,471	31,864	-
Reserves related to personnel	3,303	9,176	-	3,522	9,785	-
Depreciation rate difference	7,087	19,685	-	7,212	20,033	-
Recognition of the concession - adjustment of intangible assets (IFRS)	(1,572)	(4,368)	-	(1,798)	(4,995)	-
Recognition of the concession - financial asset of concession adjustment (IFRS)	(45,322)	(125,895)	(278)	(36,093)	(100,258)	(22)
Regulatory assets and liabilities	-	-	-	17,067	47,407	18,549
Tariff review - provisional procedure	4,579	12,720	5,186	10,151	28,198	11,497
Actuarial losses (IFRS)	39,023	108,398	-	33,178	92,464	-
Other adjustments (IFRS)	8,613	23,788	-	13,758	38,081	-
Accelerated depreciation	(19)	(54)	-	(9)	(26)	-
Other	4,511	11,306	-	7,496	17,324	-
Nondeductible temporary differences - Other comprehensive income:
Property, plant and equipment - deemed cost adjustments (IFRS)	(61,792)	(171,643)	(2,559)	(65,079)	(180,774)	-
Nondeductible temporary differences - Business combination - CPFL Renováveis			-
Deferred taxes - asset:
Fair value of property, plant and equipment (net of value added of assets)	25,725	71,458	-	27,050	75,138	-
Deferred taxes - liability:
Value added derived from determination of deemed cost	(6,477)	(17,992)	-	(6,970)	(19,360)	-
Value added of assets received from the former ERSA	(89,882)	(249,671)	-	(93,120)	(258,667)	-
Intangible asset - exploration right/authorization of acquired subsidiaries	(224,871)	(624,642)	-	(155,471)	(431,863)	-
Other temporary differences	(14,907)	(41,410)	-	(9,006)	(25,016)	-
Total	(290,367)	(807,935)	2,348	(185,861)	(519,615)	30,025

9.4 - Reconciliation of the amounts of income tax and social contribution reported in the income statements for 2014, 2013 and 2012:

	2014		2013		2012
	Social contribution	Income tax	Social contribution	Income tax	Social contribution	Income tax
Income before taxes	1,510,304	1,510,304	1,519,200	1,519,200	1,877,998	1,877,998
Adjustments to reflect effective rate:
Equity in subsidiaries	(59,684)	(59,684)	(120,868)	(120,868)	(120,680)	(120,680)
Amortization of intangible asset acquired	93,116	119,477	101,886	131,161	107,888	137,747
Tax incentives - PIIT (Technological innovation incentive program)(*)	(10,914)	(10,914)	(10,882)	(10,882)	(11,895)	(11,895)
Effect of presumed profit system	17,467	(25,827)	(42,151)	(74,675)	(103,369)	(146,158)
REFIS(**) - Law n° 11.941/2009 - art 4°	-	-	(12,739)	(12,739)	-	-
Adjustment of excess and surplus revenue of reactive	102,062	102,062	74,318	74,318	32,260	32,260
Tax incentive - Exploitation profit	-	(71,380)	-	(53,200)	-	(41,756)
Other permanent additions, net	56,652	(1,661)	50,489	15,871	125,606	101,119
Calculation base	1,709,002	1,562,376	1,559,254	1,468,187	1,907,810	1,828,636
Statutory rate	9%	25%	9%	25%	9%	25%
Tax debit result	(153,810)	(390,594)	(140,333)	(367,047)	(171,703)	(457,159)
Tax credit (not recorded) / recorded, net	(15,179)	(64,278)	(16,422)	(46,361)	(6,315)	(35,759)
Total	(168,989)	(454,871)	(156,756)	(413,408)	(178,017)	(492,919)
Current	(135,421)	(330,600)	(147,107)	(374,874)	(228,710)	(610,418)
Deferred	(33,568)	(124,272)	(9,648)	(38,534)	50,692	117,499

(*) Technologic innovation program

(**) Tax recovery program

Amortization of intangible asset acquired–Refers to the non-deductible portion of amortization of intangible assets derived from the acquisition of investees.

Tax credit (not recorded) / recorded, net -the tax credit recorded corresponds to the amount of the tax credit on the tax loss carry forwards recorded as a result of review of the projections of future profit or loss. The amount of unrecorded credit corresponds to losses generated where there is not currently reasonable certainty that future taxable income will be sufficient to absorb it.

Deferred income taxes and social contribution recorded in Other Comprehensive Income in 2014, 2013 and 2012 are as follows:

F -30

	2014		2013		2012
	Social contribution	Income tax	Social contribution	Income tax	Social contribution	Income tax
Actuarial loss/(gain)	247,040	247,040	(431,529)	(431,529)	572,225	572,225
Statutory rate	9%	25%	9%	25%	9%	25%
Taxes credit/debit result	(22,234)	(61,760)	38,838	107,882	(51,500)	(143,056)
Restriction on recording (reversal) of tax credits(*)	16,590	46,081	(46,434)	(128,980)	51,500	143,056
Recognized taxes in other comprehensive income	(5,644)	(15,679)	(7,596)	(21,098)	-	-

(*) It refers to limitation on recognition of tax credits imposed by local regulation.

In relation to the provisions introduced by Law 12,973/2014, involving changes in IRPJ, CSLL, PIS and COFINS, effective from January 1, 2015, the subsidiary CPFL Geração has opted for early adoption. The other CPFL group entities, including CPFL Energia, did not opt for early adoption and, for 2014, they continue to be subject to the Temporary Tax Regime - RTT, introduced by Law 11,941/2009.

9.5 Unrecognized tax credits

The parent company has unassessed tax loss and social contribution carryforwards amounting to R$ 106,586 that could be recognized in the future, in accordance with reviews of the annual projections of taxable income. 

Some subsidiaries also have income tax and social contribution credits on tax loss carryforwards that were not recognized as it could not be reliable estimated whether future taxable income will be available against which they can be utilized. In December 31, 2014, the main subsidiaries that have such credits of Income Tax and Social Contribution are CPFL Renováveis (R$ 435,438 and R$ 125,072 in 2013), Sul Geradora (R$ 72,537 and R$ 72,523 in 2013) e CPFL Jaguari Geração (R$ 1,774 and R$ 1,779 in 2013). There is no prescriptive period for use of the tax loss carryforwards.

( 10 ) LEASES

We are the lessor in activities to provide services and leases equipment relating to power self-produced, until October 31, 2014, were performed by the subsidiary CPFL Serviços, after that by the subsidiary CPFL Eficiência Energética S.A (Note 15.4)in which it is the lessor, and the main risks and rewards of ownership of the assets are transferred to the lessees.

The essence is to lease equipment of own power production in order to attend the customers who require higher consumption of electricity at peak hours (when tariffs are higher). In addition, the company offers maintenance and operation services.

We construct the power generation plant at the customer’s place. Since the equipment is operating, the customer makes monthly fixed payments; the revenue is recognized in the period of the lease contract based on the contract effective interest rate.

These investments are recorded at present value of the minimum lease payments receivable. These payments received are recorded as amortization of the minimum lease payments and the operational revenue is recorded in the profit or loss in accordance with the effective interest rate during the lease term.

The investments produced operational income during 2014 were R$ 10,683 (R$ 14,615 in 2013 and R$ 12,031 in 2012).

	December 31, 2014	December 31, 2013
Gross investment	88,969	93,398
Financial income unrealized	(41,403)	(44,824)
Present value of minimum lease payments receivable	47,566	48,574
Current	12,396	10,757
Noncurrent	35,169	37,817
	Within 1 year	1 to 5 years	Over 5 years	Total
Gross investment	15,866	42,907	30,196	88,969
Present value of minimum lease payments receivable	12,396	24,387	10,782	47,566

F -31

 

At December 31, 2014, there are no (i) unsecured residual amounts that benefit the lessor; (ii) provisions for uncollectible minimum lease payments receivable; or (iii) contingent payments recognized as revenue during the period.

( 11 )FINANCIAL ASSET OF CONCESSION

	Distribution	Transmission	TOTAL
At December 31, 2011 (noncurrent)	1,376,664	-	1,376,664
Additions	555,101	-	555,101
Effect of changing in amortization rates	294,785	-	294,785
Adjustments to expected cash flow	159,195	-	159,195
Disposal	(10,211)	-	(10,211)
Compensation SHP Rio do Peixe II	1,706	-	1,706
At December 31, 2012	2,377,240	-	2,377,240
Current	34,444	-	34,444
Noncurrent	2,342,796	-	2,342,796
Additions	521,168	15,249	536,417
Spin-off generation activity on the distribution	(12,862)	-	(12,862)
Adjustments to expected cash flow	(66,851)	-	(66,851)
Amortized cost - monetary adjustments	-	231	231
Receipt	(34,444)	-	(34,444)
Disposal	(12,659)	-	(12,659)
As of December 31, 2013 (noncurrent)	2,771,593	15,480	2,787,073
Spin-off generation activity on the distribution
Additions	435,852	59,576	495,428
Spin-off generation activity on the distribution	(5,542)	-	(5,542)
Adjustments to expected cash flow	104,642	-	104,642
Amortized cost - monetary adjustments	-	2,723	2,723
Disposal	(9,708)	-	(9,708)
As of December 31, 2014	3,296,837	77,779	3,374,616
Current	540,094	-	540,094
Noncurrent	2,756,744	77,779	2,834,522

 

The amount refers to the financial asset corresponding to the right established in the concession contracts of the energy distributors (measured at fair value) and transmitters (measured at amortized cost) to receive cash (i) by compensation on reversal of the assets to the granting authority at the end of the concession, and (ii) the transmitter's right to receive cash throughout the concession through allowed  annual income ("RAP"). For the subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista and CPFL Mococa, the amounts are fully classified in current assets in accordance with the maturity of the concession term (Note 1).

For the energy distribution, in accordance with the current tariff model, remuneration for this asset is recognized in profit or loss on billing to the consumers and it is realized on receipt of the electric energy bills. Additionally, the difference to adjust the balance to its expected cash flows is recorded against the financial income and/or expense account in profit or loss for the year, in accordance with the new replacement amount, “VNR” methodology, (financial income of R$ 104,642 in 2014, financial expense of R$ 66,851 in 2013).

F -32

 

For the energy transmission, remuneration for this asset is recognized in accordance with the internal rate of return, which takes into account the investment made and the allowed annual income to be received during the remaining term of the concession.  Financial income of R$ 2,723 in relation to the concession revenue, set against other operating income, since this is a component of the allowed annual income to make the network available to ONS (National System Operator).

As mentioned in note 15.3, as a result of the corporate restructuring in June 2013, the generation assets of the subsidiaries CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista, and CPFL Mococa were spun off and transferred to CPFL Centrais Geradoras. The financial concession asset of R$ 12,862 related to the generation assets previously recorded for those subsidiaries was also transferred to the subsidiary CPFL Centrais Geradoras, forming part of the subsidiary's total fixed assets. As a complement to this transaction, the amount of R$ 5,542 was transferred in 2014 in relation to the spin-off of the generation assets. These changes had no effect on the consolidated financial statements.

( 12 )OTHER CREDITS

	Current		Noncurrent
	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013
Advances - Fundação CESP	11,569	9,113	-	-
Advances to suppliers	15,934	17,159	-	-
Pledges, funds and tied deposits	8,007	7,695	290,839	174,538
Orders in progress	262,076	273,496	-	-
Outside services	12,787	6,929	-	-
Advance to energy purchase agreements	515	14,614	32,119	30,981
Collection agreements	73,076	61,771	-	-
Prepaid expenses	43,185	39,207	9,630	1,359
Receivables from CDE/CCEE	522,922	170,543	-	-
Receivables - Business Combination	-	-	13,950	13,950
Advances to employees	10,945	11,097	-	-
Allowance for doubtful accounts (note 6)	(13,304)	(12,930)	(1,981)	(221)
Other	63,782	74,689	44,270	75,488
Total	1,011,495	673,383	388,828	296,096

Pledges, funds and tied deposits:collateral offered to guarantee CCEE operations and short-term cash investments required by the subsidiaries’ loans contracts.

Orders in progress: Encompasses costs and revenue related to ongoing decommissioning or disposal of intangible assets and the service costs related to expenditure on projects in progress under the Energy Efficiency and Research and Development programs, introduced by resolutions 300/2008 and 316/2008 applied until October 2012 and amended by resolution 504/2012 . On termination of the respective projects, balances are amortized against the respective liability recorded in Other Accounts Payable (note 24).

Advance to 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 (i) agreements among the distributors, municipalities and companies for collection  through the electric energy bills and subsequent pass-through  of amounts related to public lighting, newspapers, healthcare, residential insurance, etc.; e (ii) receipts by  CPFL Total, to be passed on subsequently to the customers who use the collection services provided by that subsidiary.

Receivables from Resources provided by the Energy Development Account – CDE/CCEE – refer to: (i) low income subsidies totaling R$ 18,549 (R$ 11,808 as of December 31, 2013) and (ii) other tariff discounts granted to consumers amounting to R$ 504,373 (R$ 70,254 as of December 31, 2013). In December 31, 2013 was also recorded a amounting of R$ 88,481 mainly related toinvoluntary exposure and CCEAR account - Electric Energy  Sales in the Regulated Environment Agreement.

F -33

 

( 13 )INVESTMENTS IN JOINT VENTURES

	December 31, 2014	December 31, 2013
Permanent equity interests - equity method
By equity method of the subsidiary	1,085,835	1,018,565
Added value on assets, net	12,934	14,116
Total	1,098,769	1,032,681

In the financial statements, the investment balances relate to interests in entities accounted for by the equity method:

	Shareholders' equity interest		Equity in joint ventures
Joint Ventures	December 31, 2014	December 31, 2013	2014	2013	2012
Baesa	163,662	153,175	10,583	4,618	(6,476)
Enercan	415,952	391,728	49,040	67,640	68,493
Chapecoense	399,979	390,822	21,285	60,809	46,501
EPASA	106,243	82,839	(20,041)	(10,961)	13,457
Added value on assets, net	12,934	14,116	(1,182)	(1,238)	(1,294)
	1,098,769	1,032,681	59,684	120,868	120,680

13.1 - Dividends and Interest on shareholders’ equity receivable:

On 31 December 2014 and 2013, the Company has the following amounts receivable from subsidiaries which financial statements are not consolidated, relating to dividends and interest on shareholders’ equity:

	Dividends		Interest on Shareholders´ Equity		Total
Investee	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013
Investco	-	-	2,552	2,527	2,552	2,527
EPASA	14,891	14,891	-	-	14,891	14,891
BAESA	96	49	-	-	96	49
ENERCAN	24,816	16,054	-	-	24,816	16,054
Chapecoense	12,128	21,744	-	-	12,128	21,744
	51,931	52,738	2,552	2,527	54,483	55,265

F -34

 

13.2 – Joint Ventures

Summarized financial information of the joint ventures at December 31, 2014 and 2013 and for the years ended on December 31, 2014, 2013 and 2012 are as follows:

	December 31, 2014
Joint venture	Enercan	Baesa	Chapecoense	Epasa
Current assets	143,213	71,178	252,223	337,891
Cash and cash equivalents	45,329	19,178	154,554	96,588
Noncurrent assets	1,238,047	1,210,974	3,090,190	637,190
Current liabilities	149,088	138,909	374,374	480,948
Financial liabilities	91,723	130,122	313,222	345,657
Noncurrent liabilities	378,465	488,751	2,183,767	308,168
Financial liabilities	338,297	479,329	2,183,155	307,622
Shareholders' equity	853,707	654,492	784,272	185,965
Net operating revenue	492,921	395,440	820,500	1,220,511
Depreciation and amortization	(53,674)	(50,554)	(130,988)	(32,339)
Interest income	14,295	6,345	26,208	2,368
Interest expense	(40,572)	(32,933)	(135,463)	(34,983)
Expense or revenue income tax	(50,112)	(20,982)	(21,751)	16,862
Net income	100,650	42,321	41,735	(34,271)
Equity Interests and voting capital	48.72%	25.01%	51.00%	57.13% (*)
*Up to February 28, 2014, the CPFL Geração´s interest in EPASA was 52.75%.

	December 31, 2013
Joint venture	Enercan	Baesa	Chapecoense	Epasa
Current assets	97,961	58,980	144,018	171,387
Cash and cash equivalents	21,483	36,010	44,924	19,173
Noncurrent assets	1,296,035	1,267,818	3,200,402	644,508
Current liabilities	136,414	131,196	274,679	279,753
Financial liabilities	88,969	125,372	206,968	158,049
Noncurrent liabilities	453,592	583,045	2,303,424	374,763
Financial liabilities	416,513	573,781	2,295,940	374,696
Shareholders' equity	803,990	612,557	766,317	161,379
Net operating revenue	465,617	277,940	669,126	585,535
Depreciation and amortization	(50,370)	(51,736)	(133,035)	(32,298)
Interest income	14,480	4,386	12,049	972
Interest expense	(45,363)	(39,658)	(140,427)	(37,609)
Expense or revenue income tax	(69,620)	(9,433)	(60,844)	10,750
Net income	138,832	18,462	119,233	(20,778)
Equity Interests and voting capital	48.72%	25.01%	51.00%	52.75%
	December 31, 2012
Joint venture	Enercan	Baesa	Chapecoense	Epasa
Net operating revenue	418,115	282,114	626,098	362,302
Depreciation and amortization	(60,670)	(120,060)	(135,267)	(34,718)
Interest income	7,646	5,261	8,566	2,026
Interest expense	(55,072)	(50,436)	(163,288)	(47,118)
Expense or revenue income tax	(78,065)	(34,387)	(43,557)	(13,198)
Net income	140,575	(25,896)	91,178	25,510
Equity Interests and voting capital	48.72%	25.01%	51.00%	52.75%

F -35

 

Although CPFL Energia indirectly holds interest of more than 50% in EPASA and Chapecoense, CPFL Energia indirectly jointly controls these investments with other shareholders. Analysis of the classification of the type of investment is based on the Shareholders' Agreement for each venture.

The loans obtained from the BNDES by the joint ventures ENERCAN, BAESA and Chapecoense establish restrictions on payment of dividends to our subsidiary CPFL Geração in excess of the mandatory minimum of 25% without the prior consent of the BNDES.

13.3 - Jointly controlled operations

Through its fully-owned subsidiary CPFL Geração, the Company holds part of the assets of the Serra da Mesa hydropower plant, located on the Tocantins River, in Goias State. The concession and operation of the hydropower plant belong to Furnas Centrais Elétricas S.A. In order to maintain these assets operating jointly with Furnas  it is assured to CPFL Geração 51.54% of the installed power of 1,275 MW (657 MW) and the guaranteed mean energy of 671 MW (mean 345.4 MW) until 2028 (physical information and energetic capacity measures unaudited).

13.4Capital increase in the joint venture EPASA

At an Extraordinary General Meeting (EGM) of the  joint venture EPASA held on January 31, 2014, the shareholders approved a capital increase of R$ 65,000. An amount of R$ 34,288 was subscribed and paid up by CPFL Geração in proportion to its interest in EPASA's capital. 

Pursuant to corporate law legislation, the other shareholders have the option to exercise the preference to subscribe shares to be issued within 30 days of signing of the Notice to Shareholders, published on February 1, 2014. At the same EGM, CPFL Geração stated its interest in subscribing the remaining shares, in case the other shareholders do not exercise their preference right within the stipulated period. After this period, the shareholders Eletricidade do Brasil S.A. and OZ&M Incorporação e Participação Ltda. partially exercised the share subscription rights granted to them, subscribing and paying up the amounts of R$ 14,000 and R$ 1,000, respectively.

In accordance with the Notice to Shareholders, Eletricidade do Brasil S.A. expressed its interest in subscribing the remaining shares, within the period stipulated in the Notice to Shareholders published on March 12, 2014. On March 21, 2014, Eletricidade do Brasil S.A and CPFL Geração, paid up the remaining shares, at R$ 4,556 and R$ 11,157, respectively. Through CPFL Geração, the Company now holds 57.13% of the capital of the joint venture EPASA. The change of R$ 2,002 in corporate interest was registered in the investment and income of the subsidiary CPFL Geração, and consequently, also of the Company.

The other shareholders are assured by the Shareholders Agreement of the right to exercise the option to purchase any remaining shares within 12 months from the date on which the remaining shares are paid up, in order to recompose their diluted interest.

F -36

 

( 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 December 31, 2011	131,843	331,446	2,104,415	2,094,687	3,117	14,262	992,954	5,672,725
Historic cost	134,745	540,560	2,527,002	2,946,214	8,152	19,867	992,954	7,169,494
Accumulated depreciation	(2,900)	(209,114)	(422,587)	(851,526)	(5,035)	(5,607)	-	(1,496,770)
Additions	1,185	21,105	18,648	68,574	315	257	983,903	1,093,987
Disposals	(1,192)	(2,086)	(4,002)	(6,020)	(775)	(371)	(68)	(14,514)
Reversal of provision to environmental costs	-	(66,763)	-	-	-	-	-	(66,763)
Transfers	(17,343)	701,548	(557,182)	1,232,197	3,077	3,071	(1,365,368)	-
Reclassification and transfers to other assets - cost	-	-	-	3,939	-	-	(55)	3,884
Reclassification of cost	-	217,435	(333,674)	115,355	14	870	-	-
Depreciation	(3,885)	(15,523)	(74,024)	(188,218)	(1,085)	(2,332)	-	(285,067)
Disposal of depreciation	-	995	157	2,586	696	282	-	4,715
Reclassification and transfers to other assets - depreciation	-	(71,606)	92,615	(20,970)	10	(50)	-	-
Business combination	-	-	65,470	606,620	-	(2)	23,006	695,093
At December 31, 2012	110,609	1,116,551	1,312,422	3,908,751	5,370	15,986	634,372	7,104,060
Historic cost	117,394	1,459,396	1,677,795	5,044,085	10,772	23,956	634,372	8,967,768
Accumulated depreciation	(6,786)	(342,845)	(365,372)	(1,135,334)	(5,402)	(7,969)	-	(1,863,708)
Additions	-	926	2,551	1,000	373	38	926,029	930,916
Disposals	-	-	-	(1,071)	(847)	(24)	(153)	(2,095)
Reversal of provision to environmental costs	-	-	(17,747)	-	-	-	-	(17,747)
Transfers	4,203	13,988	172,530	373,362	19,531	543	(584,156)	-
Reclassification and transfers to other assets - cost	(15)	440	(200)	15,946	17	117	422	16,727
Reclassification of cost	1,286	(104,176)	(119,373)	230,290	3	(343)	(7,687)	-
Depreciation	(4,089)	(43,995)	(71,159)	(206,087)	(2,379)	(2,961)	-	(330,670)
Disposal of depreciation	-	-	-	103	527	15	-	645
Reclassification and transfers to other assets - depreciation	-	(947)	38,524	(35,808)	22	377	-	2,169
Spin-off generation activity on the distribuition - cost (note 15.3)	3,953	5,420	3,070	7,443	83	(10)	-	19,959
Spin-off generation activity on the distribuition - depreciation (note 15.3)	-	(1,680)	(2,225)	(2,595)	(38)	(6)	-	(6,544)
At December 31, 2013	115,946	986,527	1,318,394	4,291,334	22,661	13,731	968,826	7,717,419
Historic cost	126,820	1,375,993	1,718,629	5,671,053	29,928	24,277	968,826	9,915,527
Accumulated depreciation	(10,874)	(389,466)	(400,235)	(1,379,719)	(7,267)	(10,545)	-	(2,198,107)
Additions	-	375	372	6,739	-	88	330,900	338,475
Disposals	(1,772)	-	(12,723)	(14,719)	(1,804)	(582)	(71,760)	(103,359)
Reversal of provision to environmental costs	-	-	9,193	-	-	-	-	9,193
Transfers	500	(3,674)	156,986	997,610	14,862	(92)	(1,166,193)	-
Reclassification and transfers to other assets - cost	(23)	163	(7,467)	(5,284)	-	(103)	(3,716)	(16,430)
Depreciation	(3,981)	(61,923)	(54,392)	(293,464)	(4,511)	(2,280)	-	(420,551)
Disposal of depreciation	-	-	-	404	1,026	482	-	1,911
Business combination	48,644	180,642	70,343	715,585	93	240	330,030	1,345,577
Spin-off generation activity on the distribuition - cost (note 15.3)	-	-	460	6,089	-	204	-	6,754
Spin-off generation activity on the distribuition - depreciation (note 15.3)	-	-	(32)	(866)	-	(28)	-	(926)
At December 31, 2014	159,314	1,102,110	1,481,136	5,703,428	32,328	11,660	388,088	8,878,064
Historic cost	174,169	1,553,404	1,939,485	7,392,044	43,081	22,462	388,088	11,512,733
Accumulated depreciation	(14,855)	(451,295)	(458,349)	(1,688,616)	(10,753)	(10,802)	-	(2,634,669)
Average depreciation rate 2014	3.86%	2.99%	2.85%	4.44%	14.29%	11.25%
Average depreciation rate 2013	3.86%	3.16%	2.75%	3.91%	14.23%	10.46%

F -37

 

In the financial statements, the amount relating to construction in progress refers mainly to works in progress of the operating subsidiaries and/or those under development, especially CPFL Renováveis´ projects, which has construction in progress of R$ 262,225, in December 31, 2014 (R$ 905,444 in December 31, 2013). In 2014, of the amount of R$ 71,760 shown as disposal of construction in progress, R$ 67,342 refers to the return by suppliers of the advances made by CPFL Renováveis before December 31, 2013, due to termination of the equipment supply contract.

In 2013, CPFL Renováveis completed the review of the Property, Plant and Equipment (PP&E) subsidiary ledger of the subsidiary Bons Ventos (“BVP”), as a result of which it reclassified buildings and improvements to machinery and equipment, both shown in the line "reclassification of cost". The reclassification did not result in changes in the depreciation expense, as the useful lives of these assets were correctly applied.

In accordance with IAS 23, the interest on loans and financing taken out by the subsidiaries to finance the construction is capitalized during the construction phase. During 2014, R$4,236 was capitalized in the financial statements (R$ 48,339 in 2013 and R$ 32,527 in 2012). For further details on interest capitalized see note 30.

Depreciation expenses are registered in Statement of Income at “depreciation and amortization” (note 29).

At December 31, 2014, the total amount of fixed assets pledged as collateral for loans and financing, as mentioned in note 17, was approximately R$3,656,329, mainly relating to the subsidiary CPFL Renováveis (R$ 3,625,028).

14.1 Impairment testing: For all the reporting years the Company evaluates whether there are indicators of impairment of its assets that would require an impairment test. 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

	Goodwill	Concession rights				Other intangible assets	Total
		Acquired in business combinations	Distribution infrastructure - operational	Distribution infrastructure - in progress	Public utility
At December 31, 2011	6,115	4,103,740	3,584,408	730,807	34,421	75,182	8,534,673
Historical cost	6,152	5,995,056	8,975,287	730,807	38,679	141,498	15,887,479
Accumulated Amortization	(37)	(1,891,315)	(5,390,879)	-	(4,258)	(66,315)	(7,352,804)
Additions	-	792,320	-	1,418,637	-	29,910	2,240,867
Amortization	-	(284,714)	(390,133)	-	(1,419)	(18,713)	(694,979)
Transfer - intangible assets	-	-	961,030	(961,030)	-	-	-
Transfer - financial asset	-	-	(294,785)	(555,101)	-	-	(849,886)
Disposals and transfer - other assets	-	-	(44,091)	-	-	(6,272)	(50,363)
At December 31, 2012	6,115	4,611,347	3,816,428	633,313	33,001	80,108	9,180,312
Historical cost	6,152	6,815,774	9,183,730	633,313	38,679	156,661	16,834,309
Accumulated Amortization	(37)	(2,204,427)	(5,367,301)	-	(5,678)	(76,553)	(7,653,996)
Additions	-	-	-	853,649	-	7,444	861,093
Amortization	-	(296,978)	(413,994)	-	(1,419)	(14,196)	(726,587)
Transfer - intangible assets	-	-	412,930	(412,930)	-	-	-
Transfer - financial asset	-	-	(22,499)	(498,669)	-	-	(521,169)
Disposals and transfer - other assets	-	(1,989)	(29,115)	(1,232)	-	(12,433)	(44,769)
Spin-off generation activity on the distribuition (note 15.3)	-	-	(553)	-	-	-	(553)
At December 31, 2013	6,115	4,312,381	3,763,197	574,131	31,582	60,922	8,748,328
Historical cost	6,152	6,811,237	9,310,710	574,131	35,840	156,023	16,894,093
Accumulated Amortization	(37)	(2,498,856)	(5,547,513)	-	(4,258)	(95,100)	(8,145,764)
Additions	-	-	-	709,811	-	18,887	728,698
Amortization	-	(285,018)	(440,689)	-	(1,419)	(13,166)	(740,292)
Transfer - intangible assets	-	-	433,440	(433,440)	-	-	-
Transfer - financial asset	-	-	235	(436,087)	-	-	(435,852)
Disposals and transfer - other assets	-	-	(21,279)	159	-	16,357	(4,763)
Business combination	-	856,650	-	-	-	3,488	860,138
Spin-off generation activity on the distribuition (note 15.3)	-	-	(299)	-	-	13	(286)
At December 31, 2014	6,115	4,884,012	3,734,606	414,574	30,162	86,503	9,155,973
Historical cost	6,152	7,670,434	9,526,355	414,574	35,840	195,577	17,848,932
Accumulated Amortization	(37)	(2,786,422)	(5,791,748)	-	(5,678)	(109,074)	(8,692,959)

F -38

 

In the Statement of Income the amortization of intangibles is recorded under the following headings: (i) “depreciation and amortization” for the amortization of the intangible assets related to Distribution Infrastructure, Public Utilities and Other Intangible Assets; and (ii) “amortization of intangible concession asset” for amortization of the intangible asset acquired through business combination (note 29).

In accordance with IAS 23, the interest on loans taken out by the subsidiaries is capitalized to qualifying intangible assets. During 2014, R$8,044 was capitalized in the financial statements (R$ 8,845 in 2013 and R$ 15,645 in 2012) at a rate of 7.50% p.a. (8.32% p.a. in 2013 and 8.23% p.a. in 2012).

15.1 Intangible asset acquired in business combinations

The following table shows the breakdown of the intangible asset of exploitation rights of the concession acquired in business combinations:

	December 31, 2014			December 31, 2013	Annual amortization rate
	Historic cost	Accumulated amortization	Net value	Net value	2014	2013	2012
Intangible asset - acquired in business combinations
Intangible asset acquired, not merged
Parent company
CPFL Paulista	304,861	(172,465)	132,397	147,933	5.10%	6.03%	6.05%
CPFL Piratininga	39,065	(20,694)	18,371	20,192	4.66%	4.85%	5.58%
RGE	3,150	(1,386)	1,764	1,943	5.70%	5.86%	6.90%
CPFL Geração	54,555	(29,046)	25,509	28,170	4.88%	4.83%	5.28%
CPFL Santa Cruz	9	(8)	1	3	16.22%	16.40%	16.25%
CPFL Leste Paulista	3,333	(2,820)	513	1,091	17.36%	17.45%	16.16%
CPFL Sul Paulista	7,288	(6,132)	1,156	2,434	17.53%	16.94%	17.90%
CPFL Jaguari	5,213	(4,500)	713	1,710	19.13%	16.49%	14.40%
CPFL Mococa	9,110	(8,069)	1,041	2,638	17.53%	18.96%	18.29%
CPFL Jaguari Geração	7,896	(2,810)	5,086	5,616	6.71%	7.07%	7.64%
	434,480	(247,930)	186,550	211,730
Subsidiaries
CPFL Renováveis	3,993,342	(415,016)	3,578,326	2,850,857	4.11%	4.11%	3.42%
Outros	15,096	(14,175)	921	1,083
	4,008,438	(429,191)	3,579,246	2,851,940
Subtotal	4,442,918	(677,121)	3,765,797	3,063,670
Intangible asset acquired and merged – Deductible
Subsidiaries
RGE	1,120,266	(818,702)	301,564	321,225	1.75%	1.89%	1.74%
CPFL Geração	426,450	(287,347)	139,103	155,698	3.89%	3.66%	4.00%
Subtotal	1,546,716	(1,106,049)	440,667	476,923
Intangible asset acquired and merged – Reassessed
Parent company
CPFL Paulista	1,074,026	(643,640)	430,386	479,952	4.61%	5.39%	5.48%
CPFL Piratininga	115,762	(61,322)	54,439	59,836	4.66%	4.85%	5.58%
RGE	310,128	(142,488)	167,640	184,700	5.50%	5.65%	6.69%
CPFL Santa Cruz	61,685	(55,631)	6,054	12,241	10.03%	10.14%	10.05%
CPFL Leste Paulista	27,034	(24,325)	2,709	6,615	14.45%	14.47%	13.91%
CPFL Sul Paulista	38,168	(33,984)	4,184	9,662	14.35%	14.02%	14.52%
CPFL Mococa	15,124	(13,858)	1,266	3,390	14.05%	14.85%	14.56%
CPFL Jaguari	23,600	(21,404)	2,195	5,813	15.33%	14.28%	13.44%
CPFL Jaguari Geração	15,275	(6,600)	8,675	9,578	5.91%	6.23%	6.73%
Subtotal	1,680,801	(1,003,252)	677,548	771,788
Total	7,670,434	(2,786,422)	4,884,012	4,312,381

The intangible asset acquired in business combinations associated to the right to operate the concessions comprises:

- Intangible asset acquired, not merged

  Relates basically to the intangible asset of acquisition of the shares held by non-controlling interests prior to adoption of IFRS 3.

- Intangible asset acquired and merged - Deductible

F -39

 

Intangible asset 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 intangible asset amortization resulting from the merger of a parent company causing a negative impact on dividends paid to the non-controlling shareholders, the subsidiaries applied the concepts of CVM Instructions nº 319/1999 and nº 349/2001 to the intangible acquisition asset. A reserve was therefore recorded to adjust the intangible, set against the special equity reserves for intangible on the merger of each subsidiary, so that the effect on the equity reflects the tax benefit of the merged intangible asset. These changes affected the Company's investment in the subsidiaries, and in order to adjust this, a non-deductible intangible asset was recorded for tax purposes.

For the balances relating to the subsidiary CPFL Renováveis, amortization is recorded for the remaining terms of the respective exploration authorizations, using the straight line method. For the other balances, the amortization rates for intangible assets acquired through business combination are based on the projected income curves of the concessionaires for the remainder of the concession term, and these projections are reviewed annually.

15.2 Impairment test

For all the reporting years the Company evaluates whether there are indicators of impairment of its assets that would require an impairment test. The evaluation was based on external and internal information sources, taking into account variations in interest rates, changes in market conditions, the profitability of its operations and other factors.

The result of the assessment indicated no signs of impairment of these assets in any of the reporting years and there is no impairment loss to be recognized.

15.3 – 2014 and 2013 corporate restructuring – CPFL Centrais Geradoras, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa

On July 31, 2013, to comply with Decree 7,805/2012 and Law 12,783/2013 in relation to deverticalization of generation operation contained in distributors companies, the Company put into effect the corporate restructuring which resulted in the spin-off of the generation assets of the distributors CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista and CPFL Mococa, which assets were transferred to CPFL Centrais Geradoras and the Company holds 100% of the capital of the direct subsidiary CPFL Centrais Geradoras.

The net equity of the distribution subsidiaries spun-off, as of July 31, 2013, was R$13,424.

In 2014, complementing this operation, an additional amount of R$ 5,828 was granted in relation to generation assets and registered in the property, plant and equipment of the subsidiary CPFL Centrais Geradoras (Note 14), set against the outflow of the financial asset of concession of R$ 5,542 (Note 11) and the intangible asset of R$ 286 (note 15) of the distribution subsidiaries.  

The restructuring between the subsidiaries had no impact on the Company's financial statements.

15.4CPFL Serviços and CPFL ESCOcorporate restructuring

A corporate restructuring took place on October 31, 2014 as a result of the spin-off of the assets of CPFL Serviços, related to leases, maintenance and operating services for the diesel oil energy generation plants, signed with free consumers, denominated “self-production”. These assets were spun off from CPFL Serviços to CPFL ESCO.

The net equity of the subsidiary CPFL Serviços spun-off at October 31, 2014 was R$ 48,154.

The restructuring between the subsidiaries had no impact on the Company's financial statements.

F -40

 

15.5 – 2013 IPO of CPFL Renováveis

The initial public offer of 28 million common shares, second offer of 43.9 million common shares and complementary offer of 1.2 common shares of the subsidiary CPFL Renováveis, were completed on August, 2013. A total of 73.1 million shares were offered, amounting a total of R$ 914,686. The operation raised a gross amount (i) of R$ 364,687 with the initial and complementary offer; and (ii) R$ 549,999 with the second offer.  Fund-raising costs of R$ 36,187 were incurred in the transaction.

As a result of the transaction, the indirect interest in CPFL Renováveis was diluted from 63% to 58.84% on August 31, 2013, by the subsidiary CPFL Geração, and a positive impact of R$ 59,308 related to the change in the interest was accounted for as an equity transaction in accordance with IFRS 10 and recorded directly in the shareholder’s equity, in a capital reserve account.

15.6 – Business combinations

15.6.1 Rosa dos Ventos Geração e Comercialização de Energia S.A. – (“RDV”)

On June 18, 2013, CPFL Renováveis signed a contract for acquisition of 100% of the assets of the Canoa Quebrada windfarms, with installed capacity of 10.5 MW, and Lagoa do Mato, with installed capacity of 3.2 MW, located on the coast of the Ceará State. Both are operating commercially, and there is a contract with Eletrobrás, through PROINFA (Incentive Program for Alternative Sources of Electric Energy) for all the energy generated by these farms (physical information and energetic capacity measures unaudited).

On February 28, 2014, CPFL Renováveis acquired Rosa dos Ventos.The total purchase price was R$ 103,358, which includes: (i) the amount of R$ 70,296 paid to the seller; (ii) a price adjustment of R$ 634 and (iii) the assumption of Rosa dos Ventos’ net debt of R$ 32,428.

Additional information about acquisition

a) Considerations

	Rosa dos Ventos
	February 28, 2014
Consideration transferred:
Consideration transferred in cash and cash equivalents by the acquirer	70,296
Price adjustment paid to sellers according to contractual clause	634
Total of consideration transferred	70,930

b) Assets acquired and liabilities recognized on the acquisition date

The total amount of consideration transferred (paid) was allocated at fair value to the assets acquired and liabilities assumed, including the intangible assets related to the right to operate the authorization, which will be amortized over the remaining period of the authorization tied to operation of the wind farms. The average term for Rosa dos Ventos is estimated to be 18 years. Consequently, as the total amount paid was allocated to identified assets and liabilities, no residual amount was allocated to goodwill for this transaction.

The allocation of the amount paid was based on economic/financial valuation report. The subsidiary's management does not expect the amount allocated as the right to operate the acquisition to be tax-deductible and has therefore recorded deferred income tax and social contribution for the difference between the amount allocated to the assets and liabilities and their corresponding tax bases.

The accounting for the Rosa dos Ventos acquisition was concluded, and the, fair value of assets and liabilities assumed at the acquisition date are presented as follows:

F -41

 

	Rosa dos Ventos
	February 28, 2014
Current assets
Cash and cash equivalents	2,466
Other current assets	6,231
Non current assets
Fiduciary investments	4,223
Propert, plant and equipment	50,102
Intangible - exploitation rights	67,741
Deffered taxes credits	570
Other assets	307
Current liabilities	3,797
Non current liabilities
Loans, Financings and Debentures	32,934
Deferred taxes on exploitation rights	23,032
Provision for decommissioning costs	947
Net assets acquired	70,930
Consideration transferred	70,930

c) Outflow of net cash on acquisition of the subsidiary

	Rosa dos Ventos
	February 28, 2014
Consideration transferred in cash	70,930
Less: Balance of cash and cash equivalent acquired	(2,466)
Net cash	68,464

d) Financial information on the net operating revenue and net income of the subsidiary acquired included in the 2014 consolidated financial statements:

	Net operating revenues	Net income (loss)
	2014	2014
Rosa dos Ventos March 01, 2014 to Dec 31, 2014	15,166	7,711

The Company's financial statements for 2014 includes 10 (ten) months of operations of the subsidiary Rosa dos Ventos.

F -42

 

15.6.2 Acquisition of Dobrevê Energia S.A. - (“DESA”):

In February 2014, CPFL Renováveis and CPFL Geração signed an association agreement with Arrow - Fundo de Investimentos e Participações (“FIP Arrow”), the wholly owner of WF2 Holding S.A. (“WF2”), whereby CPFL Renováveis would merge WF2, which was wholly owner of the DESA’s shares on the acquisition date. On October 1, 2014,after all the preliminary conditions have been fulfilled, the acquisition was concluded, as follows.

The shareholders of CPFL Renováveis and WF2 approved, in Extraordinary General Meetings, the Protocol and Justification for Merger and the Termination of the Association Agreement (with effects as from October 1, 2014). Therefore, on October 1, 2014, FIP Arrow contributed into CPFL Renováveis the net assets of WF2 as a capital increase, and in turn CPFL Renováveis issued to FIP Arrow 61,752,782 new ordinary shares whereby FIP Arrow became a shareholder of CPFL Renováveis, with an interest of 12.27%.

After the capital increase, WF2 was merged into CPFL Renováveis, which became the holder of 100% of DESA´s shares. Therefore, DESA is now controlled by CPFL Renováveis.   

The exchange ratio of the shares of 100% of WF2 by 12.27% of CPFL Renováveis (after the new ordinary shares issued) was freely negotiated and agreed by the parties and reflects the best valuation of WF2 and CPFL Renováveis.

This acquisition resulted in a business combination in accordance with IFRS 3 (R) – Business Combinations, as CPFL Renováveis obtained the control of DESA, by issuing new shares.

Due this issuance of shares, the Shareholders’ Equity of CPFL Renováveis was increased by R$ 833,663 represented by its fair value, which was determined based on the income approach.

As a result of this transaction, the Company’s interest in CPFL Renováveis was diluted from 58.83% to 51.61% and  the carrying amount of the controlling and non-controlling interest were adjusted to reflect the change in the relative interest in CPFL Renováveis (R$ 180,297 in its equity interest from non-controlling to controlling shareholders). For the Company, this was accounted for as an equity transaction, in accordance with IFRS 10.

	Before the capital increase			After the capital increase
Equity attributable to:	Number of shares	% of equity interest (1)	Interest	Number of shares	% of equity interest(2)	Interest	Increase in Equity
CPFL Energia - controlling shareholder	259,748,799	58.83%	2,037,289	259,748,799	51.61%	2,217,587	180,297
Non-controlling shareholders	181,781,079	41.17%	1,425,781	243,533,861	48.39%	2,079,146	653,366
	441,529,878	100%	3,463,070	503,282,660	100%	4,296,733	833,663
(1) Interest on September 30, 2014.
(2) Interest on October 1, 2014.

Additional information about the acquisition (DESA acquisition)

a) Assets acquired and liabilities recognized on the acquisition date

On the acquisition date, the total consideration transferred (fair value of the shares issued by CPFL Renováveis) was allocated to the assets acquired and liabilities assumed, including the intangible assets related to the right to operate the authorization, which will be amortized over the remaining period of the authorization tied to operation of the wind farms and SHPs.  DESA has been operating with installed power of 278 MW and has renewable generation construction projects with Installed Capacity of 53 MW, which operations are expected to start in 2016.The average term is estimated at 25 years. Consequently, as the total consideration transferred was allocated to identified assets and liabilities assumed, no residual amount was allocated to goodwill for this transaction.

The subsidiary's management does not expect the amount allocated as the right to operate the acquisition to be tax-deductible and has therefore recorded deferred income tax and social contribution for the difference between the amount allocated to the assets and liabilities and their corresponding tax bases.

The initial accounting for the acquisition of DESA was provisionally determined at December 31, 2014 for the consolidated  financial statements, based on Management´s analysis, until the economic-financial valuation isfinalized by an independent advisor. The fair value of the assets and liabilities and allocation of the price paid are shown below.

F -43

 

Net assets acquired
	WF2 (DESA)
	October 01, 2014
Current assets
Cash and cash equivalents	139,293
Other assets	32,274
Noncurrent assets
Property, plant and equipment	1,295,476
Intangible assets	7,937
Intangible - exploitation rights	784,459
Other assets	98,264
Current liabilities
Loans, Financings and Debentures	102,996
Other accounts payable	106,097
Noncurrent liabilities
Loans, Financings and Debentures	871,987
Deferred taxes debits	280,234
Other accounts payable	56,406
Net assets acquired	939,983

Goodwill arising on acquisition
Consideration transfered	833,663
(+) Non-controlling interest	106,320
(-) Fair value of identifiable net assets acquired	939,983
Goodwill	-

The fair values shown above are provisional and confirmation of the amounts is pending on receipt of the economic-financial valuation report, currently being prepared by an independent advisor:

	R$
Property, plant and equipment	1,295,476
Intangible	7,937
Intangible - exploitation right	784,459
Deferred taxes	280,234
Other non current liabilities	56,406
Non-controlling interest	106,320

F -44

 

b) Outflow of net cash on the acquisition

As this acquisition was a share exchange transaction, no cash payment was made for this acquisition.  Our cash and cash equivalents was increased by the cash and cash equivalents of WF2 (R$139,293) on the acquisition date since we began to consolidate this company as from that date.

c) Financial information on the net operating revenue and net income of the subsidiary acquired included in the consolidated financial statements in 2014

	Net operating revenues	Net income (loss)
	2014	2014
DESA consolidated - Oct 01, 2014 to Dec 31, 2014	48,036	1,880

The Company's consolidated information for 2014 includes 3 (three) months of operations of DESA.

d) Non-controlling interests

Non-controlling interests of R$ 106,320 is related to 40% interest held by third parties in LUDESA S.A. (WF2's subsidiary). The non-controlling interest was recognized in the consolidated financial statements on the acquisition date, based on its fair value that was determined based on income approach.

15.6.3Combined financial information on the net operating income and profit (loss) for the 2014 if the acquisitions had occurred on January 1, 2014.

	Net operating revenues	Net income (loss)
	2014	2014
CPFL Energia - presented	17,305,942	886,443
Pro-forma adjustments (i)	104,038	(46,106)
Total	17,409,980	840,337

(i) The pro forma adjustments to the net operating revenue took into account the addition of the net operating revenue of the subsidiaries Rosa dos Ventos and DESA for the period in which they were not controlled and consequently not consolidated by the Company.

The pro forma adjustments of the net income (loss) take into account: (i) addition of the profit or loss of the subsidiaries Rosa dos Ventos and DESA for the period in which they were not controlled by the Company; (ii) inclusion of amortization of the exploration right, net of tax effects, if the acquisition had occurred on January 1, 2014; (iii) exclusion of the effects of non-recurring consultancy expenses in relation to the acquisition of DESA; and (iv) inclusion of the financial effects of the debentures issued by WF2 to acquire DESA’ non-controlling shareholders.

F -45

 

( 16 )SUPPLIERS

	December 31, 2014	December 31, 2013
Current
System Service Charges	-	61,880
Energy purchased	1,895,742	1,300,598
Electricity network usage charges	125,860	91,603
Materials and services	250,416	338,524
Free energy	102,129	92,088
Total	2,374,147	1,884,693
Noncurrent
Materials and Services	633	-

( 17 )ACCRUED INTEREST ON LOANS AND FINANCING AND LOANS AND FINANCING

	December 31, 2014				December 31, 2013
	Interest - Current and Noncurrent	Principal		Total	Interest - Current and Noncurrent	Principal		Total
		Current	Noncurrent			Current	Noncurrent
Measured at cost
Brazilian currency
BNDES - Power increases	-	-	-	-	6	1,229	-	1,235
BNDES/BNB - Investment	10,463	619,704	4,696,171	5,326,338	24,555	872,818	4,071,441	4,968,814
BNDES - Purchase of assets	14	631	3,649	4,294	27	1,364	5,717	7,108
Financial Institutions	128,887	239,799	1,434,168	1,802,855	128,752	560,121	1,520,231	2,209,104
Other	709	108,918	14,223	123,851	674	40,658	19,063	60,395
Subtotal	140,074	969,053	6,148,211	7,257,338	154,013	1,476,190	5,616,452	7,246,656
Measured at fair value
Foreign currency
Financial Institutions	18,168	125,511	3,353,468	3,497,147	15,213	42,307	1,906,739	1,964,259
Market to market	-	155	(56,153)	(55,998)	-	194	44,001	44,195
Total at fair value	18,168	125,667	3,297,315	3,441,149	15,213	42,501	1,950,740	2,008,454
Fundraising costs	-	(1,219)	(18,891)	(20,110)	-	(4,066)	(21,048)	(25,114)
Total	158,241	1,093,500	9,426,634	10,678,376	169,226	1,514,626	7,546,144	9,229,996

F -46

 

Measured at amortized cost	December 31. 2014	December 31. 2013	Annual interest	Amortization	Collateral
Brazilian currency
Power increases
CPFL Renováveis
BNDES	-	1,235	TJLP + 3.1% to 4.3%	75 monthly installments from September 2007	CPFL Energia guarantee and Promissory Note
Investment
CPFL Paulista
FINEM IV	-	64,103	TJLP + 3.28% to 3.4%	60 monthly installments from January 2010	CPFL Energia guarantee and receivables
FINEM V	103,617	137,195	TJLP + 2.12% to 3.3%	72 monthly installments from February 2012	CPFL Energia guarantee and receivables
FINEM V	7,130	8,874	Fixed rate 8%	90 monthly installments from August 2011	CPFL Energia guarantee and receivables
FINEM V	45,937	53,481	Fixed rate 5.5%	96 monthly installments from February 2013	CPFL Energia guarantee and receivables
FINEM VI	245,445	284,373	TJLP + 2.06% to 3.08%	72 monthly installments from January 2014	CPFL Energia guarantee and receivables
FINEM VI	11,917	12,684	Fixed rate 2.5%	114 monthly installments from June 2013	CPFL Energia guarantee and receivables
FINEM VI	218,640	204,849	Fixed rate 2.5%	96 monthly installments from December 2014	CPFL Energia guarantee and receivables
FINAME	42,260	50,706	Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
CPFL Piratininga
FINEM III	-	26,719	TJLP + 3.28% to 3.4%	60 monthly installments from January 2010	CPFL Energia guarantee and receivables
FINEM IV	55,807	73,892	TJLP + 2.12% to 3.3%	72 monthly installments from February 2012	CPFL Energia guarantee and receivables
FINEM IV	2,299	2,861	Fixed rate 8%	90 monthly installments from August 2011	CPFL Energia guarantee and receivables
FINEM IV	23,889	27,812	Fixed rate 5.5%	96 monthly installments from February 2013	CPFL Energia guarantee and receivables
FINEM V	71,737	80,513	TJLP + 2.06% to 3.08%	72 monthly installments from January 2014	CPFL Energia guarantee and receivables
FINEM V	3,130	3,288	Fixed rate 2.5%	114 monthly installments from June 2013	CPFL Energia guarantee and receivables
FINEM V	54,409	48,237	Fixed rate 2.5%	96 monthly installments from December 2014	CPFL Energia guarantee and receivables
FINAME	20,039	24,044	Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
RGE
FINEM IV	-	40,805	TJLP + 3.28 to 3.4%	60 monthly installments from January 2010	CPFL Energia guarantee and receivables
FINEM V	62,721	83,046	TJLP + 2.12 to 3.3%	72 monthly installments from February 2012	CPFL Energia guarantee and receivables
FINEM V	17,622	20,516	Fixed rate 5.5%	96 monthly installments from February 2013	CPFL Energia guarantee and receivables
FINEM VI	131,125	157,318	TJLP + 2.06% to 3.08%	72 monthly installments from January 2014	CPFL Energia guarantee and receivables
FINEM VI	1,261	1,420	Fixed rate 2.5%	114 monthly installments from June 2013	CPFL Energia guarantee and receivables
FINEM VI	80,396	73,013	Fixed rate 2.5%	96 monthly installments from December 2014	CPFL Energia guarantee and receivables
FINAME	10,056	12,065	Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
FINAME	287	345	Fixed rate 10.0%	90 monthly installments from May 2012	Fiduciary alienation of assets
CPFLSanta Cruz
Bank credit note - Unibanco	929	3,159	TJLP + 2.9%	54 monthly installments from December 2010	CPFL Energia guarantee and receivables
FINEM	11,317	-	Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	3,334	-	SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	7,596	-	TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
CPFL Leste Paulista
Bank credit note - Unibanco	1,286	2,688	TJLP + 2.9%	54 monthly installments from June 2011	CPFL Energia guarantee and receivables
FINEM	2,904	-	Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	1,179	-	SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	2,685	-	TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
CPFL Sul Paulista
Bank credit note - Unibanco	1,393	2,911	TJLP + 2.9%	54 monthly installments from June 2011	CPFL Energia guarantee and receivables
FINEM	1,968	-	Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	1,553	-	SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	3,545	-	TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
CPFL Jaguari
Bank credit note - Unibanco	455	1,547	TJLP + 2.9%	54 monthly installments from December 2010	CPFL Energia guarantee and receivables
Bank credit note - Santander	1,968	2,136	TJLP + 3.1%	96 monthly installments from June 2014	CPFL Energia guarantee
Bank credit note - Santander	635	607	UMBNDES + 2.1%	96 monthly installments from June 2014	CPFL Energia guarantee
FINEM	2,775	-	Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	1,104	-	SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	2,516	-	TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
CPFL Mococa
Bank credit note - Unibanco	608	1,824	TJLP + 2.9%	54 monthly installments from January 2011	CPFL Energia guarantee and receivables
Bank credit note - Santander	2,532	2,747	TJLP + 3.1%	96 monthly installments from June 2014	CPFL Energia guarantee
Bank credit note - Santander	2,067	1,358	UMBNDES +1.99% to 2.1%	96 monthly installments from June 2014	CPFL Energia guarantee
Bank credit note - Santander	4,335	2,305	TJLP + 2.99%	96 monthly installments from October 2015	CPFL Energia guarantee

F -47

 

CPFL Serviços
FINAME	1,675	1,701	Fixed rate 2.5% to 5.5%	96 monthly installments from August 2014	CPFL Energia guarantee and equipment fiduciary alienation
FINAME	357	-	Fixed rate 6%	72 monthly installments from April 2016	CPFL Energia guarantee and equipment fiduciary alienation
FINAME	1,272	1,258	Fixed rate 6% to 10%	90 monthly installments from November 2012	CPFL Energia guarantee and equipment fiduciary alienation
FINAME	14,806	11,699	Fixed rate 2.5% to 5.5%	114 monthly installments from February 2013	CPFL Energia guarantee and equipment fiduciary alienation
FINAME	74	87	TJLP + 4.2%	90 monthly installments from November 2012	CPFL Energia guarantee and equipment fiduciary alienation
FINAME	2,860	-	Fixed rate 6%	90 monthly installments from November 2014	CPFL Energia guarantee and equipment fiduciary alienation
FINAME	7,017	-	Fixed rate 6%	96 monthly installments from June 2016	CPFL Energia guarantee and equipment fiduciary alienation
CERAN
BNDES	360,217	409,365	TJLP + 3.69% to 5%	168 monthly installments from December 2005	Pledge of shares, credit and concession rights and revenue and CPFL Energia guarantee
BNDES	54,604	54,956	UMBNDES + 5% (1)	168 monthly installments from February 2006	Pledge of shares, credit and concession rights and revenue and CPFL Energia guarantee
CPFL Transmissão
FINAME	17,736	4,667	Fixed rate 3.0%	96 monthly installments from July 2015	CPFL Energia guarantee
CPFL Telecom
FINAME	7,588	-	Fixed rate 6.0%	60 monthly installments from December 2016	CPFL Energia guarantee
FINEM	6,187	-	SELIC + 3.12%	60 monthly installments from December 2016	CPFL Energia guarantee
FINEM	21,349	-	TJLP + 2.12% to 3.12%	60 monthly installments from December 2016	CPFL Energia guarantee
CPFL Renováveis
FINEM I	321,088	352,830	TJLP + 1.95%	168 monthly installments from October 2009	PCH Holding a joint debtor, Letters of guarantee
FINEM II	28,605	31,997	TJLP + 1.90%.	144 monthly installments from June 2011	CPFL Energia guarantee, fiduciary alienation of assets and joint fiduciary assignment of credit rights
FINEM III	565,890	605,263	TJLP + 1.72%	192 monthly installments from May 2013	CPFL Energia guarantee, plegde of shares, fiduciary alienation of assets and joint fiduciary assignment of credit rights
FINEM V	101,723	113,106	TJLP + 2.8% to 3.4%	143 monthly installments from December 2011	PCH Holding 2 and CPFL Renováveis debtor solidarity.
FINEM VI	84,176	76,673	TJLP + 2.05%	192 monthly installments from October 2013	CPFL Renováveis pledge of shares, pledge of receivables
FINEM VII	176,252	194,041	TJLP - 1.92 %	156 monthly installments from October 2010	Pledge of shares, fiduciary alienation and equipment fiduciary alienation
FINEM VIII	79,124	50,811	TJLP + 2.02%	192 monthly installments from January 2014	Pledge of shares and Reserve Account of SPE Assignment of Receivables
FINEM IX	39,581	46,994	TJLP + 2.15%	120 monthly installments from May 2010	Pledge of shares, fiduciary alienation and equipment fiduciary alienation
FINEM X	827	1,108	TJLP	84 monthly installments from October 2010	Pledge of shares, fiduciary alienation and equipment fiduciary alienation
FINEM XI	126,670	138,101	TJLP + 1.87% to 1.9%	168 monthly installments from January 2012	CPFL Energia guarantee, fiduciary alienation of assets and joint fiduciary assignment of credit rights
FINEM XII	357,620	336,782	TJLP + 2.18%	192 monthly installments from July 2014	CPFL Energia guarantee, fiduciary alienation of assets, joint fiduciary assignment of credit rights and pledge of shares
FINEM XIII	315,596	-	TJLP + 2.02% to 2.18%	192 monthly installments from November 2014	Pledge of shares and equipaments, fiduciary alienation.
FINEM XIV	19,707	-	TJLP + 3.50%	120 monthly installments from June 2007	(i)Fiduciary assignments of assets and credit rigths (ii) pledge of grantor rights - ANEEL and shares.
FINEM XV	35,392	-	TJLP + 3.44%	Monthly installments until March 2023	(i)Fiduciary assignments of assets (ii) pledge of grantor rights - ANEEL and shares.
FINEM XV	10,581	-	Fixed rate 5.50%	Monthly installments until January 2020	(i)Fiduciary assignments of assets (ii) pledge of grantor rights - ANEEL and shares.
FINEM XVI	146,812	-	TJLP + 2.18%	Monthly installments until February 2030	(i)Fiduciary assignments of assets and credit rigths (ii) pledge of grantor rights - ANEEL and shares and reserve account
FINEM XVI	378,728	-	TJLP + 2.18%	Monthly installments until December 2028	(i)Fiduciary assignments of assets and credit rigths (ii) pledge of grantor rights - ANEEL and shares and reserve account
FINAME I	163,476	190,396	Fixed rate 5.5%	108 monthly installments from January 2012	CPFL Energia guarantee, fiduciary alienation of assets and fiduciary assignment of credit rights
FINAME II	26,081	31,168	Fixed rate 4.5%	102 monthly installments from June 2011	CPFL Energia guarantee, fiduciary alienation of assets and fiduciary assignment of credit rights
FINAME III	115,681	129,659	Fixed rate 2.5%	108 monthly installments from January 2014	Pledge of CPFL Renováveis shares Pledge of shares and Reserve Account of SPE Assignment of receivables
FINEP I	2,382	2,506	Fixed rate 3.5%	61 monthly installments from October 2014	Bank Garantee
FINEP II	10,366	-	TJLP - 1.00%	85 monthly installments from June 2017	Bank Garantee
FINEP III	6,945	-	TJLP + 3.00%	73 monthly installments from July 2015	Bank Garantee
BNB I	117,516	133,192	Fixed rate 9.5% to 10%	168 monthly installments from January 2009	Fiduciary alienation
BNB II	172,430	175,695	Fixed rate 10% (f)	222 monthly installments from May 2010	CPFL Energia guarantee
BNB III	32,591	-	Fixed rate 9.5%	228 monthly installments from July 2009	CPFL Energia guarantee, fiduciary alienation of assets and joint fiduciary assignment of credit rights
NIB	74,197	79,109	IGPM + 8.63%	Interest and principal quarterly paid started in June 2011 until September 2023	No guarantee
Bridge BNDES II	-	84,507	TJLP + 3.02 %	1 installment in February 2014	Pledge of SPE shares
Bridge BNDES III	-	194,242	TJLP + 3.02 %	1 installment in February 2014	Pledge of SPE shares
Bridge BNDES IV	49,492	-	TJLP + 2.40%	1 installment in January 2016	Bank Garantee
CPFL Brasil
FINEP	2,657	3,461	Fixed rate 5%	81 monthly installments from August 2011	Receivables

F -48

 

Purchase of assets
CPFL Serviços
FINAME	-	146	TJLP + 2.15%	36 monthly installments from March 2011	Fiduciary alienation of assets
FINAME	-	4,911	Fixed rate 2.5% to 8.7%	96 monthly installments from April 2012	Fiduciary alienation of assets and CPFL Energia guarantee
FINAME	-	2,051	TJLP + 1.72%	60 monthly installments from May 2012	CPFL Energia guarantee
CPFL ESCO
FINAME	4,135	-	Fixed rate 4.5% to 8.7%	96 monthly installments from March 2012	Fiduciary alienation of assets and CPFL Energia guarantee
FINAME	158	-	Fixed rate 6%	72 monthly installments from October 2016	CPFL Energia guarantee
Financial institutions
CPFL Paulista
Banco do Brasil - Law 8727	-	4,648	IGP-M + 7.42%	240 monthly installments from May 1994	Receivables (CPFL Paulista and São Paulo Government)
Banco do Brasil - Working capital	105,500	105,124	107% of CDI	1 installment in April 2015	CPFL Energia guarantee
Banco do Brasil - Working capital (a)	73,758	133,334	98.50% of CDI	4 annual installments from July 2012	CPFL Energia guarantee
Banco do Brasil - Working capital (b)	-	95,704	99.00% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
Banco do Brasil - Working capital (d)	291,036	261,334	104.90% of CDI	2 annual installments from July 2017	CPFL Energia guarantee
CPFL Piratininga
Banco do Brasil - Working capital (a)	6,784	12,263	98.5% of CDI	4 annual installments from July 2012	CPFL Energia guarantee
Banco do Brasil - Working capital (b)	-	12,282	99.0% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
Banco do Brasil - Working capital (d)	51,222	45,995	104.90% of CDI	2 annual installments from July 2017	CPFL Energia guarantee
RGE
Banco do Brasil - Working capital (a)	31,894	57,656	98.5% of CDI	4 annual installments from July 2012	CPFL Energia guarantee
Banco do Brasil - Working capital (b)	-	35,338	99.0% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
CPFL Santa Cruz
Banco do Brasil - Working capital (b)	-	4,340	99.0% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
Banco do Brasil - Working capital (d)	38,417	34,496	104.90% of CDI	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	8,083	-	CDI + 0.27%	12 semiannual installments from June 2015	CPFL Energia guarantee
CPFL Leste Paulista
Banco do Brasil - Working capital (b)	-	11,156	99.0% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
Banco IBM - Working capital	7,419	8,140	100.0% of CDI	14 semiannual installments from December 2012	CPFL Energia guarantee
Banco IBM - Working capital	25,666	-	CDI + 0.1%	12 semiannual installments from October 2014	CPFL Energia guarantee
Banco IBM - Working capital	7,969	-	CDI + 0.27%	12 semiannual installments from March 2015	CPFL Energia guarantee
Banco IBM - Working capital	10,307	-	CDI + 0.27%	12 semiannual installments from June 2015	CPFL Energia guarantee
CPFL Sul Paulista
Banco do Brasil - Working capital (b)	-	5,982	99.0% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
Banco do Brasil - Working capital (d)	24,447	21,952	104.90% of CDI	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	4,036	-	CDI + 0.27%	12 semiannual installments from June 2015	CPFL Energia guarantee
CPFL Jaguari
Banco do Brasil - Working capital (b)	-	3,755	99.0% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
Banco do Brasil - Working capital (d)	3,376	3,031	104.90% of CDI	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	15,064	16,615	100.0% of CDI	14 semiannual installments from December 2012	CPFL Energia guarantee
Banco IBM - Working capital	13,836	-	CDI + 0.1%	12 semiannual installments from October 2014	CPFL Energia guarantee
CPFL Mococa
Banco do Brasil - Working capital (b)	-	1,908	99.0% of CDI	2 annual installments from March 2013	CPFL Energia guarantee
Banco do Brasil - Working capital (d)	22,119	19,861	104.90% of CDI	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	4,888	5,392	100.0% of CDI	14 Semi-annual installments from December 2012	CPFL Energia guarantee
Banco IBM - Working capital	15,519	-	CDI + 0.27%	12 semiannual installments from March 2015	CPFL Energia guarantee
CPFL Serviços
Banco IBM - Working capital	6,316	7,325	CDI + 0.10%	11 semiannual installments from June 2013	CPFL Energia guarantee
CPFL Geração
Banco do Brasil - Working capital	637,635	628,828	107.0% of CDI	1 installment in March 2019	CPFL Energia guarantee
CPFL Renováveis
Banco Safra	-	27,713	CDI+ 0.4%	Annual installment until 2014	No guarantee
HSBC (e)	322,336	350,329	CDI + 0.5%	8 annual installment from June 2013	Shares alienation
Banco do Brasil	36,739	-	Fixed rate 10.00%	132 montly installment from June 2010	Shareholders support, pledge of shares, of grantor rights and of credit rights, insurance, bank guarantee and civil liability
Banco do Brasil - Promissory Note	-	144,428	108.5% of CDI	1 installment in January 2014	Shares alienation
Banco Itaú - Promissory Note	-	150,175	105% of CDI	Semi-annual until June 2014	No guarantee
CPFL Telecom
Banco IBM - Working capital	38,489	-	CDI + 0.18%	12 semiannual installments from August 2014	CPFL Energia guarantee
Other
Eletrobrás
CPFL Paulista	5,414	6,918	RGR + 6% to 6.5%	monthly installments from August 2006	Receivables and promissory notes
CPFL Piratininga	239	390	RGR + 6%	monthly installments from August 2006	Receivables and promissory notes
RGE	9,746	11,834	RGR + 6%	monthly installments from August 2006	Receivables and promissory notes
CPFL Santa Cruz	1,601	2,173	RGR + 6%	monthly installments from January 2007	Receivables and promissory notes
CPFL Leste Paulista	747	961	RGR + 6%	monthly installments from February 2008	Receivables and promissory notes
CPFL Sul Paulista	808	1,072	RGR + 6%	monthly installments from August 2007	Receivables and promissory notes
CPFL Jaguari	41	58	RGR + 6%	monthly installments from June 2007	Receivables and promissory notes
CPFL Mococa	222	275	RGR + 6%	monthly installments from January 2008	Receivables and promissory notes
Other	105,034	36,713
Subtotal Brazilian Currency - Cost	7,257,338	7,246,656

F -49

 

Foreign Currency
Measured at fair value
Financial Institutions
CPFL Paulista
Bank of America Merrill Lynch	270,248	238,318	US$ + 3.69 % (3)	1 installment in July 2016	CPFL Energia guarantee and promissory notes
Bank of America Merrill Lynch	399,887	352,685	US$ + Libor 3 months + 1.48% (3)	1 installment in July 2016	CPFL Energia guarantee and promissory notes
Bank of America Merrill Lynch	119,561	-	US$+Libor 3 months+1.70% (4)	1 installment in September 2018	CPFL Energia guarantee and promissory notes
Bank of Tokyo-Mitsubishi (b)	132,887	-	US$+Libor 3 months+0.80% (3)	4 semiannual installments from September 2017	CPFL Energia guarantee and promissory notes
Citibank	133,585	117,821	US$ + Libor 6 months + 1.77% (2)	1 installment in September 2016	CPFL Energia guarantee and promissory notes
Citibank	132,962	-	US$+Libor 3 months + 1.35% (4)	1 installment in March 2019	CPFL Energia guarantee and promissory notes
Mizuho Bank (c)	199,235	-	US$+Libor 3 months+1.55% (3)	3 semiannual installments from March 2018	CPFL Energia guarantee and promissory notes
Morgan Stanley	133,601	117,843	US$ + Libor 6 months + 1.75% (2)	1 installment in September 2016	CPFL Energia guarantee and promissory notes
Scotiabank	64,958	57,299	US$ + 3.3125% (3)	1 installment in July 2016	CPFL Energia guarantee and promissory notes
J.P. Morgan	106,383	-	US$ + 2.28% a 2.32% (3)	1 installment in December 2017	CPFL Energia guarantee and promissory notes
CPFL Piratininga
Citibank	21,401	18,878	US$ + Libor 6 months + 1.69%(2)	1 installment in August 2016	CPFL Energia guarantee and promissory notes
Citibank	167,050	-	US$ + Libor 6 monthss + 1.14% (2)	1 installment in January 2017	CPFL Energia guarantee and promissory notes
Citibank	132,962	-	US$ + Libor 3 months + 1.35% (4)	1 installment in March 2019	CPFL Energia guarantee and promissory notes
Santander	120,585	106,348	US$ + 2.58% (3)	1 installment in July 2016	CPFL Energia guarantee and promissory notes
Scotiabank	84,843	74,840	US$ + 3.3125% (3)	1 installment in July 2016	CPFL Energia guarantee and promissory notes
Sumitomo (b)	133,259	-	US$ + Libor 3 months + 1.35% (3)	1 installment in April 2018	CPFL Energia guarantee and promissory notes
RGE
Bank of Tokyo-Mitsubishi	47,908	42,252	US$ + Libor 3 months + 0.82%(3)	1 installment in April 2018	CPFL Energia guarantee and promissory notes
Bank of Tokyo-Mitsubishi	218,046	192,298	US$ + Libor 3 months + 0.83%(3)	1 installment in May 2018	CPFL Energia guarantee and promissory notes
Citibank	39,912	-	US$ + Libor 3 months + 1.25%(4)	2 annual installments from May 2018	CPFL Energia guarantee and promissory notes
Citibank	186,593	164,567	US$ + Libor 6 months + 1.45% (3)	1 installment in April 2017	CPFL Energia guarantee and promissory notes
J.P. Morgan	126,126	111,235	US$ + 2.64% (3)	1 installment in July 2016	CPFL Energia guarantee and promissory notes
HSBC	36,223	-	US$ + Libor 3 months + 1.30% (4)	1 installment in October 2017	CPFL Energia guarantee and promissory notes
CPFL Santa Cruz
J.P. Morgan	25,864	22,813	US$ + 2.38% (2)	1 installment in July 2015	CPFL Energia guarantee and promissory notes
Santander	23,590	20,805	USD + 2.544% (3)	1 installment in June 2016	CPFL Energia guarantee and promissory notes
CPFL Leste Paulista
Citibank	-	11,226	US$ + Libor 6 months + 1.52%(2)	1 installment in September 2014	CPFL Energia guarantee and promissory notes
Scotiabank	32,926	29,037	US$ + 2.695% (2)	1 installment in July 2015	CPFL Energia guarantee and promissory notes
CPFL Sul Paulista
Citibank	-	11,226	US$ + Libor 6 months + 1.52%(2)	1 installment in September 2014	CPFL Energia guarantee and promissory notes
J.P. Morgan	13,578	11,977	US$ + 2.38% (2)	1 installment in July 2015	CPFL Energia guarantee and promissory notes
Santander	25,949	22,885	US$ + 2.544% (3)	1 installment in June 2016	CPFL Energia guarantee and promissory notes
Scotiabank	13,829	12,195	US$ + 2.695% (2)	1 installment in July 2015	CPFL Energia guarantee and promissory notes
CPFL Jaguari
Citibank	-	10,284	US$ + Libor 6 months + 1.57%(2)	1 installment in August 2014	CPFL Energia guarantee and promissory notes
Santander	36,564	32,247	US$ + 2.544% (3)	1 installment in June 2016	CPFL Energia guarantee and promissory notes
Scotiabank	17,122	15,099	US$ + 2.695% (2)	1 installment in July 2015	CPFL Energia guarantee and promissory notes
CPFL Mococa
Citibank	-	9,822	US$ + Libor 6 months + 1.52%(2)	1 installment in September 2014	CPFL Energia guarantee and promissory notes
Scotiabank	14,488	12,776	US$ + 2.695% (2)	1 installment in July 2015	CPFL Energia guarantee and promissory notes
CPFL Geração
Citibank	-	147,482	US$ + Libor 6 months + 1.69% (2)	1 installment in August 2016	CPFL Energia guarantee and promissory notes
HSBC	265,779	-	US$+Libor 3 months + 1.30% (3)	1 installment in March 2017	CPFL Energia guarantee and promissory notes
CPFL Serviços
J.P. Morgan	10,040	-	US$ + 1.75% (2)	1 installment in October 2016	CPFL Energia guarantee and promissory notes
CPFL Telecom
Banco Itaú	9,202	-	US$ + 2.35% (3)	1 installment in November 2015	CPFL Energia guarantee and promissory notes
Mark to market	(55,998)	44,195
Total Foreign Currency - fair value	3,441,149	2,008,454
Fundraising costs(*)	(20,110)	(25,114)
Total - Consolidated	10,678,376	9,229,996
The subsdiaries hold swaps converting the operating cost of currency variation to interest tax variation in reais, corresponding to :
(1) 143.85% of CDI	(3) 104.1% to 109% of CDI
(2) 99% to 104% of CDI	(4) 109.1% to 110% of CDI
Efective rate:
(a) 106% to 106.99% of CDI	(d) 109.47% of CDI
(b) 107% to 107.99% of CDI	(e) CDI + 0.73%
(c) 108.49% of CDI	(f) Fixed rate 10.57%

(*) In accordance with IAS 39, this refers to the fundraising costs attributable to issuance of the respective debts.

F -50

 

In accordance with IAS 32 and 39, the Company and its subsidiaries classified their loans and financing, as segregated in the tables above, as (i) other financial liabilities (or measured at amortized cost), and (ii) financial liabilities measured at fair value through profit and loss.

The objective of classification of financial liabilities on loans and financing measured at fair value is to compare the effects of recognition of income and expense derived from marking derivatives to market, tied to the loans and financing, in order to obtain more relevant and consistent accounting information. At December 31, 2014, the total balance of the loans and financing measured at fair value was R$ 3,441,149 (R$ 2,008,454 as of December 31, 2013).

Changes in the fair values of these loans and financing are recognized in the financial income/expense of the subsidiaries. Accumulated gains of R$55,998 (losses of R$ 44,195 at December 31, 2013) on marking the loans and financing to market, less the losses of R$25,382 (gain of R$ 18,080 at December 31, 2013) of marking to market the derivative financial instruments contracted as a hedge against foreign exchange variations (note 35), resulted in a total net gain of R$30,616 (losses of R$ 26,114 at December 31, 2013).

The maturities of the principal long-term balances of loans and financing are scheduled as follows:

2016	2,177,991
2017	1,581,937
2018	1,654,242
2019	1,642,385
2020	515,495
2021 to 2025	1,359,618
2026 to 2030	551,119
Subtotal	9,482,787
Mark to market	(56,154)
Total	9,426,634

The main financial rates applicable for our loans and financing their related breakdown in local and foreign currency, after taking into consideration the effects of the derivative instruments, are as shown below:

	Accumulated variation		% of debt
Index	December 31, 2014	December 31, 2012	December 31, 2014	December 31, 2013
IGP-M	3.69	5.53	0.69	0.91
UMBND	13.27	17.80	0.53	0.62
TJLP	5.00	5.00	36.50	39.03
CDI	10.81	8.02	49.26	45.42
Other			13.01	14.03
			100.00	100.00

F -51

 

Main fund-raising in the year:

Brazilian currency
		R$ thousand
Company	Bank / credit line	Total approved	2014 released	Released net of fundraising costs	Interest	Destination of the resources
Investment
CPFL Paulista	FINEM VI (a) (b)	790,000	26,969	26,969	Monthly	Subsidiary's investment plan
CPFL Piratininga	FINEM V (a) (b)	220,000	12,442	12,442	Monthly	Subsidiary's investment plan
RGE	FINEM VI (a) (b)	274,997	8,354	8,354	Monthly	Subsidiary's investment plan
CPFL Santa Cruz	FINEM (b)	25,360	21,891	21,891	Monthly	Subsidiary's investment plan
CPFL Leste Paulista	FINEM (b)	13,045	6,655	6,655	Monthly	Subsidiary's investment plan
CPFL Sul Paulista	FINEM (b)	12,280	6,945	6,945	Monthly	Subsidiary's investment plan
CPFL Jaguari	FINEM (b)	10,398	6,288	6,288	Monthly	Subsidiary's investment plan
CPFL Mococa	CCB Santander (b)	6,119	2,523	1,631	Monthly	Subsidiary's investment plan
CPFL Serviços	FINAME (b)	15,140	15,140	15,140	Monthly	Acquisition of electrical equipment and vehicules
CPFL Transmissão	FINAME (b)	23,824	13,054	13,054	Monthly	Acquisition of electrical equipment
CPFL Telecom	FINAME e FINEM (b)	95,333	34,918	34,632	Quarterly during grace and monthly after grace	Subsidiary's investment plan
CPFL Renováveis	BNB II (b)	(c)	(c)	(c)	(c)	(c)
CPFL Renováveis	FINEM XIII	379,948	314,991	314,991	Monthly	Subsidiary's investment plan
CPFL Renováveis	FINEM XIV, FINEM XV, FINEM XVI, BNDES bridge IV (b), FINEP III (b)	(e)	(e)	(e)	Bridge BNDES IV: January 2016; Others: monthly	Subsidiary's investment plan (SHPs e wind power)
CPFL Renováveis	FINEM VI	85,244	9,667	9,667	Monthly	SPHs development
CPFL Renováveis	FINEM XII	289,954	22,758	22,758	Monthly	Windfarm development
CPFL Renováveis	FINAME III	207,000	31,543	31,543	Monthly	Power plant development
CPFL Renováveis	FINEP II (b)	88,095	10,348	10,234	Monthly	Subsidiary's investment plan (technological innovation)
Financial institutions
CPFL Santa Cruz	Banco IBM (b)	8,006	8,006	8,006	Semiannual	Reinforce working capital
CPFL Leste Paulista	Banco IBM (b)	43,955	43,955	43,955	Semiannual	Reinforce working capital
CPFL Sul Paulista	Banco IBM (b)	3,997	3,997	3,997	Semiannual	Reinforce working capital
CPFL Jaguari	Banco IBM (b)	13,986	13,986	13,986	Semiannual	Reinforce working capital
CPFL Mococa	Banco IBM (b)	15,000	15,000	15,000	Semiannual	Reinforce working capital
CPFL Telecom	Banco IBM (b)	37,989	37,989	37,989	Semiannual	Reinforce working capital
CPFL Renováveis	Banco do Brasil - Promissory Note (b)	138,000	138,000	138,000	(d)	(d)
CPFL Renováveis	Banco do Brasil	(e)	(e)	(e)	Monthly	Subsidiary's investment plan (SHPs)
(a)The outstanding balance was cancelled (b)The agreement has no restrictive covenants (c)The indirect subsidiary Rosa dos Ventos, purchased in February 2014, owned these operations, which are consolidated in the Company's financial statements as from March 2014. (d)The outstanding balance of the promissory notes issued by the indirectly owned subsidiaries Atlântica I, Atlântica II, Atlântica IV and Atlântica V was settled in January 2014, using funds from a new issue under the same conditions.
(e) These were operations of the indirect subsidiary DESA, acquired in October 2014, and have been consolidated in the Company's financial statements as from that date.

F -52

 

Foreign currency
		R$ thousand
Company	Bank / credit line	Total approved	Nine months of 2014 released	Released net of fundraising costs	Interest	Destination of the resources
Instituições Financeiras:
CPFL Paulista	Bank of America Merrill Lynch - Law 4131/62	106,020	106,020	106,020	Quartely	Extend the debt profile
CPFL Paulista	Banco Tokyo-Mitsubishi - Law 4131/62	117,400	117,400	116,226	Quartely	Extend the debt profile
CPFL Paulista	Citibank - Law 4131/62	117,250	117,250	117,250	Quartely	Extend the debt profile
CPFL Paulista	Mizuho Bank - Law 4131/62	174,900	174,900	173,413	Quartely	Extend the debt profile
CPFL Paulista	JP Morgan - Law 4131/62	104,570	104,570	104,570	Semmiannual	Extend the debt profile
CPFL Piratininga	Citibank - Law 4131/62	151,875	151,875	151,875	Semmiannual	Extend the debt profile
CPFL Piratininga	Citibank - Law 4131/62	117,250	117,250	117,250	Quartely	Extend the debt profile
CPFL Piratininga	Sumitomo - Law 4131/62	110,275	110,275	109,448	Quartely	Reinforce working capital
RGE	Citibank - Law 4131/62	33,285	33,285	33,285	Quartely	Reinforce working capital
RGE	HSBC - Law 4131/62	32,715	32,715	32,715	Quartely	Extend the debt profile
CPFL Geração	HSBC - Law 4131/62	232,520	232,520	232,520	Quartely	Extend the debt profile
CPFL Serviços	J.P. Morgan (b)	9,000	9,000	9,000	Semmiannual	Reinforce working capital
CPFL Telecom	Banco Itaú (b)	9,000	9,000	9,000	Wih the principal	Reinforce working capital

Prepayment

CPFL Geração – Citibank - The maturity of the subsidiary CPFL Geração's foreign currency debt to Citibank, originally scheduled for August 2016, was settled in 2014.

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  complying with all the contractual obligations; (ii) full compliance with the restrictive conditions established in the agreement; and (iii) maintaining certain financial ratios within pre-established parameters, calculated annually:

CPFL Paulista, CPFL Piratininga and RGE

Maintaining, by these subsidiaries, the following index:

·Net indebtedness divided by EBITDA – maximum of 3.5;

·Net indebtedness divided by the sum of net indebtedness and Shareholder’s Equity – maximum of 0.90.

CPFL Geração

The loans from theBNDES raised by the indirect subsidiary CERANestablish:

·Maintaining the debt coverage ratio at 1.3 during the amortization period;

·Restrictions on the payment of dividends to the subsidiary CPFL Geração higher than the minimum mandatory dividend of 25% without the prior agreement of the BNDES.

CPFL Telecom

Maintaining, by the Company, the following index:

F -53

 

·Maintaining Net Equity / (Net Equity + Net Bank Debt) of more than 0.28; and

·Maintaining Net Bank Debt / Adjusted EBITDA of less than 3.75.

CPFL Renováveis

FINEM I and FINEM VI

·Maintaining the debt coverage ratio “ICSD” (cash balance for the previous year + cash generation for the current year) / debt service charge for the current year) at 1.2.

·Own capitalization ratio of 25% or more.

In December 2014, the subsidiary obtained a waiver from the BNDES for determination of the ICSD for the current year.

FINEM II and FINAME II

·Restrictions on the dividends distribution if a debt service coverage ratio of 1.0 or more and general indebtedness ratio of 0.8 or less is not maintained.

FINEM III

·Maintaining Shareholders’ Equity/(Shareholders’ Equity + Net Bank Debts) of more than 0.28, determined in the Company's annual consolidated financial statements;

·Maintaining a Net Bank Debt/EBITDA ratio of 3.75 or less, determined in the Company's annual consolidated financial statements.

An amendment  to the agreement was signed in 2014 in order to change the limit of the financial ratio, Net Debt/EBITDA (determined for CPFL Energia) from 4.00 to 3.75, and the calculation methodology.

FINEM V

·Maintaining the debt coverage ratio at 1.2;

·Maintaining the own capitalization ratio at 30% or more.

In December 2014, the subsidiary obtained a waiver from the Banco do Brasil for determination of the ICSD for the year ended December 31, 2014.

FINEM VII and X

·Maintaining the annual debt coverage ratio at 1.2.

·Distribution of dividends restricted to the Total Liabilities ratio divided by Shareholders’ Equity ex-Dividend of less than 2.33.

FINEM VIII and FINAME III

·Maintaining a Debt Service Coverage Ratio of 1.2 or more;

·Maintaining a Net Indebtedness/EBITDA ratio of 7.5 or less in 2013, 6.0 in 2014, 5.6 in 2015, 4.6 in 2016 and 3.75 in 2017 onward, determined in the consolidated financial statements of CPFL Renováveis;

·Maintaining a Shareholders' Equity/(Shareholder’s Equity + Net Debt) ratio of 0.41 or more in 2013 to 2016 and 0.45 in 2017 onward, determined in the consolidated financial statements of CPFL Renováveis.

In December 2014, the subsidiaries Bio Alvorada e Bio Coopcana obtained a waiver from BNDES for determination of the ICSD and for the Net Indebtedness/EBITDA ratio that was a CPFL Renováveis commitment for the year ended December 31, 2014.

FINEM IX e FINEM XIII

·Maintaining the Debt Service Coverage Ratio at 1.3 or more;

F -54

 

FINEM XI and FINAME I

·Maintaining a Net Bank Debt/EBITDA ratio of 4.0 or less, determined in the Company's annual consolidated financial statements.

On December 30, 2014, the Company obtained a waiver from the BNDES for determination of the Net Bank Debt/EBITDA for FINEM XI and FINAME I for the year ended December 31, 2014.

FINEM XII

·Maintaining the Debt Service Coverage Ratio of the Campo dos Ventos II Energias Renováveis S.A., SPE Macacos Energia S.A., Costa Branca Energia S.A., SPE Juremas Energia S.A. and Pedra Preta Energia S.A. subsidiaries at 1.3 or more after amortization starts;

·Maintaining the Consolidated Debt Service Coverage Ratio at 1.3 or more, determined in the consolidated financial statements of Eólica Holding S.A., after amortization starts;

FINEM XIV

·Maintaining the half-yearly equity ratio (ICP), defined by the ratio of net equity to total assets, at 30% or more of the total investment in the project, and the debt coverage ratio at 1.3 or more during the amortization period.

FINEM XV

·Maintaining the quarterly equity ratio (ICP) at 25% (twenty-five percent) or more, defined by the ratio of Net Equity to Total Assets;

·Maintaining the quarterly debt coverage ratio at 1.2 or more during the amortization period.

FINEM XVI

·Maintaining the debt coverage ratio at 1.20 or more during the amortization period. Maintaining the annual consolidated debt coverage ratio at 1.3 or more, determined in the consolidated financial statements of Desa Eólicas S.A.

HSBC

·From 2014, there is the obligation to maintain the ratio of Net Debt and EBITDA less than 4.50 in June 2014, 4.25 in December 2014, 4.0 in June 2015 and 3.50 after that until discharge.

NIB

·Maintaining the half-yearly debt coverage ratio at 1.2.

·Maintaining a Total Debt and Shareholders’ Equity ratio of 30% or more;

·Maintaining the Financing Term Coverage ratio at 1.7 or more;

Banco do Brasil

·Maintaining the annual debt coverage ratio at 1.2 or more during the amortization period.

Banco do Brasil (*) – Working Capital– CPFL Paulista, CPFL Piratininga and RGE

Maintaining, by the Company, the following index:

·Net indebtedness divided by EBITDA  - maximum of 3.75; and

·EBITDA divided by Financial Income (Expense) - minimum of 2.25.

(*) Only for the debts contracted in 2010, whose amounts at December 31, 2014 are R$ 73,758 for CPFL Paulista, R$ 6,784 for CPFL Piratininga and R$ 31,894 for RGE.

F -55

 

Foreign currency loans - Bank of America, J.P Morgan, Citibank, Morgan Stanley, Scotiabank, Bank of Tokyo, Santander, Sumitomo, Mizuho and HSBC(Law 4,131)

The foreign currency loans held by Law 4,131 are subject to certain restrictive conditions,and include clauses that require the Company to maintain certain financial ratios within pre-established parameters, calculated semiannually.

The ratios required are as follows: (i) Net indebtedness divided by EBITDA – maximum of 3.75 and (ii) EBITDA divided by Financial Income (Expense) – minimum of 2.25.

For purposes of determining covenants, the definition of EBITDA for the Company takes into consideration the consolidation of subsidiaries, associates and joint ventures based on the interest in the respective entities (for both EBITDA assets and liabilities).

Various 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, unless at least one of the shareholders (Camargo Corrêa and Previ) remains directly or indirectly in the block of control.

Furthermore, failure to comply with the obligations or restrictions mentioned could result in default in relation to other contractual obligations (cross default), depending on each loan and financing agreement.

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 at December 31, 2014.

F -56

 

( 18 )ACCRUED INTEREST ON DEBENTURES AND DEBENTURES

		December 31, 2014				December 31, 2013
		Interest - Current and Noncurrent	Current	Noncurrent	Total	Interest - Current and Noncurrent	Current	Noncurrent	Total
Parent Company
4th Issue	Single series	15,020	1,290,000	-	1,305,020	12,438	-	1,290,000	1,302,438
		15,020	1,290,000	-	1,305,020	12,438	-	1,290,000	1,302,438
CPFL Paulista
6th Issue	Single series	38,673	-	660,000	698,673	31,674	-	660,000	691,674
7th Issue	Single series	24,291	-	505,000	529,291	20,173	-	505,000	525,173
		62,964	-	1,165,000	1,227,964	51,847	-	1,165,000	1,216,847
CPFL Piratininga
3rd Issue	Single series	7,571	260,000	-	267,571	6,331	-	260,000	266,331
6th Issue	Single series	6,446	-	110,000	116,446	5,279	-	110,000	115,279
7th Issue	Single series	11,304		235,000	246,304	9,388		235,000	244,388
		25,320	260,000	345,000	630,320	20,998	-	605,000	625,998
RGE
6th Issue	Single series	29,298	-	500,000	529,298	23,995	-	500,000	523,995
7th Issue	Single series	8,177	-	170,000	178,177	6,791	-	170,000	176,791
		37,475	-	670,000	707,475	30,786	-	670,000	700,786
CPFL Santa Cruz
1st Issue	Single series	480	-	65,000	65,480	416	-	65,000	65,416
CPFL Brasil
2nd Issue	Single series	2,346	-	228,000	230,346	1,948	-	228,000	229,948
CPFL Geração
3rd Issue	Single series	7,687	264,000	-	271,687	6,429	-	264,000	270,429
4th Issue	Single series	-	-	-	-	5,809	-	680,000	685,809
5th Issue	Single series	11,236	-	1,092,000	1,103,236	9,329	-	1,092,000	1,101,329
6th Issue	Single series	19,446	-	460,000	479,446	16,254	-	460,000	476,254
7th Issue	Single series	13,739	-	635,000	648,739	-	-	-	-
8th Issue	Single series	2,903	-	72,390	75,293	-	-	-	-
		55,012	264,000	2,259,390	2,578,401	37,821	-	2,496,000	2,533,821
CPFL Renováveis
1st Issue - SIIF	1st to 12th Series	798	36,640	476,329	513,767	814	34,872	489,858	525,544
1st Issue - PCH Holding 2	Single series	57,991	8,701	149,492	216,184	32,177	-	158,193	190,370
1st Issue - Renováveis	Single series	5,795	21,500	408,500	435,795	5,065	-	430,000	435,065
2nd Issue - Renováveis	Single series	9,603	-	300,000	309,603	-	-	-	-
1st Issue - WF2 (a)	Single series	2,984	30,000	-	32,984	-	-	-	-
2nd Issue - WF2 (a)	Single series	10,582	132,000	-	142,582	-	-	-	-
1st Issue - DESA (a)	Single series	716	-	35,000	35,716	-	-	-	-
1st Issue - DESA (a)	Single series	6,022	-	65,000	71,022	-	-	-	-
		94,491	228,841	1,434,321	1,757,653	38,056	34,872	1,078,051	1,150,979
Fund raising costs(*)		-	(766)	(30,311)	(31,077)	-	-	(34,832)	(34,832)
Total		293,108	2,042,075	6,136,400	8,471,583	194,311	34,872	7,562,219	7,791,402
(a) In October 1, 2014, as result of acquisition of WF2 e Dobrevê Energia S/A, the Company incorporated the 1st and 2nd issue.

(*) In accordance with IAS 39, this refers to the fundraising costs attributable to issuance of the respective debts.

F -57

 

		Issued	Annual Remuneration	Annual Effective rate	Amortization Conditions	Collateral
Parent Company
4th Issue	Single series	129.000	CDI + 0.40%	CDI + 0.51%	1 installment in May 2015	Unsecured
CPFL Paulista
6th Issue	Single series	660	CDI + 0.8% (2)	CDI + 0.87%	3 annual installments from July 2017	CPFL Energia guarantee
7th Issue	Single series	50,500	CDI + 0.83% (3)	CDI + 0.89%	4 annual installments from February 2018	CPFL Energia guarantee
CPFL Piratininga
3rd Issue	Single series	260	107% of CDI	108.23% of CDI	1 installment in April 2015	CPFL Energia guarantee
6th Issue	Single series	110	CDI + 0.8% (2)	CDI + 0.91%	3 annual installments from July 2017	CPFL Energia guarantee
7th Issue	Single series	23,500	CDI + 0.83% (2)	CDI + 0.89%	4 annual installments from February 2018	CPFL Energia guarantee
RGE
6th Issue	Single series	500	CDI + 0.8% (2)	CDI + 0.88%	3 annual installments from July 2017	CPFL Energia guarantee
7th Issue	Single series	17,000	CDI + 0.83% (3)	CDI + 0.88%	4 annual installments from February 2018	CPFL Energia guarantee
CPFL Santa Cruz
1st Issue	Single series	650	CDI + 1.4%	CDI + 1.52%	2 annual instalments from June 2017	CPFL Energia guarantee
CPFL Brasil
2nd Issue	Single series	2,280	CDI + 1.4%	CDI + 1.48%	2 annual instalments from June 2017	CPFL Energia guarantee
CPFL Geração
3rd Issue	Single series	264	107% of CDI	108.23% of CDI	1 installment in April 2015	CPFL Energia guarantee
4th Issue	Single series	6.800	CDI + 1.4%	CDI + 1.49%	2 annual instalments from June 2017	CPFL Energia guarantee
5th Issue	Single series	10,920	CDI + 1.4%	CDI + 1.48%	2 annual instalments from June 2017	CPFL Energia guarantee
6th Issue	Single series	46,000	CDI + 0.75% (1)	CDI + 0.75%	3 annual instalments from August 2018	CPFL Energia guarantee
7th Issue	Single series	63,500	CDI + 1.06%	CDI + 1.11%	1 installment in April 2019	CPFL Energia guarantee
8th Issue	Single series	1	IPCA + 5.86% (1)	103.33% of CDI	1 installment in April 2019	CPFL Energia guarantee
CPFL Renováveis
1st Issue - SIIF	1st to 12nd Series	432,299,666	TJLP + 1%	TJLP + 1% + 0.6%	39 semi-annual installments from 2009	Fiduciary alienation
1st Issue - PCH Holding 2	Single series	1,581	CDI + 1.6%	CDI + 1.8%	9 annual installments from June 2015	CPFL Renováveis guarantee
1st Issue - Renováveis	Single series	43,000	CDI + 1.7%	CDI + 1.82%	Annual installments from May 2015	BVP and PCH Holding fiduciary assigment of dividends
2st Issue - Renováveis	Single series	300,000	114.0% of CDI	115.43% of CDI	5 annual instalments from June 2017	Unsecured
1st Issue - WF2 (a)	Single series	12	CDI + 1.5%	CDI + 1.5%	1 installment in March 2015	Unsecured
2nd Issue - WF2 (a)	Single series	20	CDI + 2%	CDI + 2%	1 installment in November de 2015	Unsecured
1st Issue - DESA (a)	Single series	20	CDI + 1.75%	CDI + 1.75%	3 semi-annual installments from May de 2016	Unsecured
2nd Issue - DESA (a)	Single series	65	CDI + 1.34%	CDI + 1.34%	3 semi-annual installments from April de 2018	Unsecured
(a) In October 1, 2014, as result of acquisition of WF2 e Dobrevê Energia S/A, the Company incorporated the 1st and 2nd issue.
The Company and its subsidiaries hold swaps that convert the prefixed component of interest on the operation to interest rate variation in reais. corresponding to:
(1) 100.15% to 106.9% of CDI			(3) 108% to 108.1% of CDI
(2) 107% to 107.9% of CDI

F -58

 

The maturities of the long-term balance of debentures are scheduled as follows:

2016	105,841
2017	1,204,809
2018	1,664,194
2019	1,800,175
2020	608,371
2021 to 2025	661,183
2026 to 2030	91,827
Total	6,136,400

Fund raising during the year

			R$ thousand
Company		Issued	2014 released	Released net of fundraising costs	Interest	Destination of the resources
CPFL Geração	7th Issue	63,500	635,000	633,440	Semiannual	Extend the debt profile
CPFL Geração	8th Issue	1	70,000	68,873	Annual	Subsidiary's investment plan
CPFL Renováveis	2nd Issue	300,000	300,000	298,700	Semiannual	Reinforce working capital and subsidiary's investment plan
CPFL Renováveis	1st and 2nd issue - WF2 and 1st and 2nd issue - DESA	(a)	(a)	(a)	(a)	Investment acquisition, business development, investment plan and reinforce working capital
(a) In October 1, 2014, as result of acquisition of WF2 e Dobrevê Energia S/A, the Company incorporated the 1st and 2nd issue.

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 Paulista (6^th and 7^th issues), CPFL Piratininga (3^rd, 6^th and 7^th issues), RGE (6^th and 7^th issues), CPFL Geração (3^rd, 5^th , 6^th , 7^th and 8^th issues), CPFL Brasil and CPFL Santa Cruz

Maintaining, by the Company, of the following ratios:

·Net indebtedness divided by EBITDA – maximum of 3.75;

·EBITDA divided by Financial Income (Expense) - minimum of 2.25;

The definition of EBITDA in the Company, for purposes of determination of covenants, mainly takes into consideration inclusion the consolidation of subsidiaries, associates and joint ventures based on the interest held by the Company in those entities (both for EBITDA assets and liabilities).

CPFL Renováveis

The outstanding debentures are subject of clauses that requires of subsidiary CPFL Renováveis to maintain  the follow index:

- 1^st Issue of CPFL Renováveis

·Operating debt coverage ratio - minimum of 1.00;

·Debt service coverage ratio - minimum of 1.05;

·Net indebtedness divided by EBITDA- maximum of 7.5 in 2013, 6.0 in 2014, 5.6 in 2015, 4.6 in 2016 and 3.75 from 2017;

·EBITDA divided by Net financial expense - minimum of 1.75.

F -59

 

- 2^nd Issue of CPFL Renováveis

·Maintaining a Net Debt/EBITDA ratio of 6.0 or less in 2014, 5.6 in 2015, 4.6 in 2016 and 3.75 from 2017. The ratios will be measured annually.

- 1^st issue of indirectly controlled entity PCH Holding 2 S.A:

·Maintaining the Debt Service Coverage ration of the subsidiary Santa Luzia at 1.2 or more from September 2014.

·Maintaining a Net Debt/EBITDA ratio of 7.5 or less in 2013, 6.0 in 2014, 5.6 in 2015, 4.6 in 2016 and 3.75 from 2017.

2nd issue – Dobrevê Energia S/A (DESA):

·Maintaining a net debt/dividends ratio of 5.5 or less in 2014, 5.5 in 2015, 4.0 in 2016, 3.5 in 2017 and 3.5 in 2018.

Certain debentures of subsidiaries and joint ventures 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),depending on each agreement.

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 of the Company and its subsidiaries, these restrictive covenants and clauses are adequately complied with at December 31, 2014.

( 19 )POST-EMPLOYMENT BENEFIT OBLIGATION

The subsidiaries sponsor supplementary retirement and pension plans for their employees. The main characteristics of these plans are as follows:

19.1 – Characteristics:

- CPFL Paulista:

The plan currently in force for the employees of the subsidiary CPFL Paulista through Fundação CESP 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 variable 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.

In addition, managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Banco Bradesco.

- CPFL Piratininga:

As a result of the spin-off of Bandeirante Energia S.A. (CPFL Piratininga’s predecessor), the subsidiary CPFL Piratininga assumed the responsibility for the actuarial liabilities for its retired and discharged employees up tothe date of the spin-off, as well as the responsibilities relating to the active employees transferred to CPFL Piratininga.

F -60

 

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. The responsibility for covering the actuarial deficits of this Plan is equally divided between CPFL Piratininga and the participants.

c)  Variable 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 addition, managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Banco 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 management by ELETROCEEE. Only those whose work contracts were transferred from CEEE to RGE are entitled to this benefit. A defined benefit private pension plan was set up in January 2006 with Bradesco Vida e Previdência for employees admitted from 1997.

- CPFL Santa Cruz:

The benefits plan of the subsidiary CPFL Santa Cruz, managed by BB Previdência - Fundo de Pensão do Banco do Brasil, is a defined contribution plan.

- CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari:

In December 2005, the companies joined the CMSPREV private pension plan, managed 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.

In addition, managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Banco Bradesco.

F -61

 

19.2 – Changes in the defined benefit plans:

	December 31, 2014
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total liabilities
Present value of defined benefit obligation	3,820,563	986,972	88,621	279,283	5,175,439
Fair value of plan's assets	(3,315,422)	(913,589)	(85,360)	(273,019)	(4,587,390)
Net actuarial liabilities recognized on balance sheet	505,141	73,383	3,261	6,264	588,049

	December 31, 2013
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total liabilities
Present value of defined benefit obligation	3,599,853	919,441	82,167	245,371	4,846,832
Fair value of plan's assets	(3,235,768)	(874,546)	(83,309)	(242,325)	(4,435,948)
Present value of liabilities (fair value of assets), net	364,085	44,895	(1,142)	3,046	410,884
Effect of the limit on the assets to be accounted for	-	-	1,142	-	1,142
Net actuarial liabilities recognized on balance sheet	364,085	44,895	-	3,046	412,025

	December 31, 2012
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total liabilities
Present value of defined benefit obligation	4,431,699	1,159,779	101,714	298,014	5,991,206
Fair value of plan's assets	(3,774,468)	(985,557)	(93,360)	(271,878)	(5,125,263)
Net actuarial liabilities recognized on balance sheet	657,231	174,222	8,354	26,136	865,942

The changes in present value of the defined benefit obligations and the fair values of the plan assets are as follows:

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total liabilities
Present value of the defined benefit obligation at December 31, 2011	3,505,727	884,091	76,649	234,457	4,700,924
Gross current service cost	1,186	4,349	144	1,176	6,855
Interest on actuarial obligation	350,009	88,813	7,663	23,599	470,084
Participants' contributions transferred during the year	171	1,545	35	947	2,698
Actuarial gain - change in financial assumptions	845,470	237,425	23,429	51,673	1,157,997
Benefits paid during the year	(270,864)	(56,444)	(6,206)	(13,838)	(347,352)
Present value of the defined benefit obligation at December 31, 2012	4,431,699	1,159,779	101,714	298,014	5,991,206
Gross current service cost	1,485	6,099	167	359	8,110
Interest on actuarial obligation	380,340	99,150	8,740	25,727	513,957
Participants' contributions transferred during the year	60	1,582	12	927	2,581
Actuarial gain - change in financial assumptions	(912,671)	(282,757)	(21,728)	(63,034)	(1,280,190)
Benefits paid during the year	(301,060)	(64,412)	(6,738)	(16,622)	(388,832)
Present value of the defined benefit obligation at December 31, 2013	3,599,853	919,441	82,167	245,371	4,846,832
Gross current service cost	1,160	3,937	152	(43)	5,206
Interest on actuarial obligation	404,925	104,090	9,250	27,748	546,013
Participants' contributions transferred during the year	14	1,700	-	783	2,497
Actuarial loss - change in financial assumptions	35,892	10,484	1,113	4,379	51,868
Actuarial loss - change in demografic assumptions	89,187	16,695	3,089	19,387	128,358
Benefits paid during the year	(310,468)	(69,375)	(7,150)	(18,342)	(405,335)
Present value of the defined benefit obligation at December 31, 2014	3,820,563	986,972	88,621	279,283	5,175,439

F -62

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	TOTAL
Fair value of the acturial assets at December 31, 2011	(3,236,676)	(839,877)	(80,058)	(218,799)	(4,375,410)
Expected return during the year	(324,813)	(85,126)	(8,074)	(22,185)	(440,198)
Participants' contributions transferred during the year	(171)	(1,545)	(35)	(947)	(2,698)
Sponsors' contributions	(47,708)	(14,655)	(1,041)	(5,132)	(68,536)
Actuarial (gain)/loss	(435,964)	(100,798)	(10,358)	(38,653)	(585,773)
Benefits paid during the year	270,864	56,444	6,206	13,838	347,352
Fair value of the acturial assets at December 31, 2012	(3,774,468)	(985,557)	(93,360)	(271,878)	(5,125,263)
Expected return during the year	(337,591)	(89,686)	(8,560)	(24,698)	(460,535)
Participants' contributions transferred during the year	(60)	(1,582)	(12)	(927)	(2,581)
Sponsors' contributions	(56,266)	(18,243)	(1,208)	(8,336)	(84,053)
Actuarial (gain)/loss	631,557	156,110	13,093	46,892	847,652
Benefits paid during the year	301,060	64,412	6,738	16,622	388,832
Fair value of the acturial assets at December 31, 2013	(3,235,768)	(874,546)	(83,309)	(242,325)	(4,435,948)
Expected return during the year	(365,720)	(100,048)	(9,459)	(27,961)	(503,188)
Participants' contributions transferred during the year	(14)	(1,700)	-	(783)	(2,497)
Sponsors' contributions	(85,024)	(24,930)	(1,809)	(7,421)	(119,184)
Actuarial (gain)/loss	60,636	18,260	2,067	(12,871)	68,092
Benefits paid during the year	310,468	69,375	7,150	18,342	405,335
Fair value of the acturial assets at December 31, 2014	(3,315,422)	(913,589)	(85,360)	(273,019)	(4,587,390)

19.3 Changes in the assets and liabilities recognized:

The changes in net liabilities are as follows:

	December 31, 2012
	CPFL Paulista	CPFL Piratininga	CPFL Geração	Total liability	RGE
Actuarial liabilities at the beginning of the year	269,051	44,214	-	15,658	328,923
Expense/(Income) recognized in income statement	26,382	8,036	(3,676)	2,590	33,332
Sponsors' contributions transferred during the year	(47,708)	(14,655)	(1,041)	(5,132)	(68,536)
Actuarial loss	409,506	136,627	13,070	13,020	572,225
Actuarial liabilities at the end of the year	657,231	174,222	8,353	26,136	865,942
Other contributions	14,593	387	79	1,857	16,917
Total liabilities	671,824	174,610	8,432	27,993	882,859
Current					51,675
Noncurrent					831,184

	December 31, 2013
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total liabilities
Net actuarial liabilities at the beginning of the year	657,231	174,222	8,353	26,136	865,942
Expense recognized in income statement	44,234	15,562	481	1,388	61,665
Sponsors' contributions transferred during the year	(56,266)	(18,243)	(1,207)	(8,336)	(84,052)
Actuarial loss (gain) with changes of financial assumptions	(281,114)	(126,648)	(7,627)	(16,142)	(431,529)
Net actuarial liabilities at the end of the year	364,085	44,895	-	3,046	412,025
Other contributions	14,458	394	69	504	15,425
Total liabilities	378,543	45,289	69	3,550	427,450
Current					76,810
Noncurrent					350,640

	December 31, 2014
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total liabilities
Net actuarial liabilities at the beginning of the year	364,085	44,895	-	3,046	412,025
Expense recognized in income statement	40,365	7,979	77	(256)	48,165
Sponsors' contributions transferred during the year	(85,024)	(24,930)	(1,809)	(7,421)	(119,184)
Actuarial loss (gain): changes of demographic assumptions	35,892	10,484	1,113	4,379	51,868
Actuarial loss (gain): changes of financial assumptions	149,823	34,955	3,880	6,515	195,174
Net actuarial liabilities at the end of the year	505,140	73,383	3,261	6,264	588,048
Other contributions	15,171	456	65	20	15,712
Total liabilities	520,311	73,839	3,326	6,284	603,760
Current					85,374
Noncurrent					518,386

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19.4Estimated contributions and benefits:

The estimated contributions to the plans for 2015 are shown below:

	2015
CPFL Paulista	89,275
CPFL Piratininga	26,177
CPFL Geração	1,899
RGE	7,792

The estimated benefits to be paid by the pension plan administrators for the next 10 years are shown below:

Expected benefit payments (to be paid by Fundação CESP and ELETROCEEE)	2015	2016	2017	2018	2019 to 2024	TOTAL
CPFL Paulista	305,800	320,045	334,684	349,550	2,397,175	3,707,254
CPFL Piratininga	65,866	69,163	72,980	77,122	570,573	855,704
CPFL Geração	7,034	7,324	7,697	8,003	55,227	85,285
RGE	19,392	20,907	22,520	23,696	169,538	256,053

At December 31, 2014, the average duration of the defined benefit obligation was 9.2 years for CPFL Paulista, 10.8 years for CPFL Piratininga, 9.3 years for CPFL Geração and 10.2 years for RGE.

19.5 Recognition of income and expense for defined benefit pension plans:

The external actuary’s estimate of the expense and/or revenue to be recognized in 2015 and the income/expense recognized in 2014, 2013 and 2012 is as follows:

	2015 Estimated
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total
Cost of service	1,270	3,880	188	(31)	5,307
Interest on actuarial obligations	420,314	109,333	9,753	30,895	570,295
Expected return on plan assets	(367,541)	(102,525)	(9,488)	(30,670)	(510,224)
Total expense	54,043	10,688	453	194	65,378

	2014 Recognized
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total
Cost of service	1,160	3,937	152	(43)	5,206
Interest on actuarial obligations	404,925	104,090	9,250	27,748	546,013
Expected return on plan assets	(365,720)	(100,048)	(9,459)	(27,961)	(503,188)
Effect of the limit on the assets to be accounted for	-	-	134	-	134
Total expense	40,365	7,979	77	(256)	48,165

	2013 Recognized
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total
Cost of service	1,485	6,098	167	359	8,109
Interest on actuarial obligations	380,340	99,150	8,740	25,727	513,957
Expected return on plan assets	(337,591)	(89,686)	(8,560)	(24,698)	(460,535)
Effect of the limit on the assets to be accounted for	-	-	134	-	134
Total expense	44,234	15,562	481	1,388	61,665

	2012 Recognized
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Total
Cost of service	1,186	4,348	144	1,176	6,854
Interest on actuarial obligations	350,009	88,812	7,663	23,598	470,082
Expected return on plan assets	(324,813)	(85,124)	(8,074)	(22,184)	(440,195)
Effect of the limit on the assets to be accounted for	-	-	(3,409)	-	(3,409)
Total expense/(income)	26,382	8,036	(3,676)	2,590	33,332

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The main assumptions taken into consideration in the actuarial valuations for the three years presented were as follow:

	December 31, 2014	December 31, 2013	December 31, 2012
Nominal discount rate for actuarial liabilities:	11.46% p.a.	11.72% p.a.	8.78% p .a.
Nominal Return Rate on Assets:	11.46% p.a.	11.72% p.a.	8.78% p .a.
Estimated Rate of nominal salary increase:	8.15% p.a.	7.10% p.a.	6.69% p .a.
Estimated Rate of nominal benefits increase:	0.0% p.a.	0.0% p .a.	0.0% p .a.
Estimated long-term inflation rate (basis for establishing nominal rates above)	5.00% p.a.	5.00% p.a.	4.6% p .a.
General biometric mortality table:	AT-2000 (-10)	AT-83	AT-83
Biometric table for the onset of disability:	Light weak	Mercer Disability	Mercer Disability
Expected turnover rate:	ExpR_2012*	0.3 / (Service time + 1)	0.3 / (Service time + 1)
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

(*) FUNCESP experience, with uniform aggravation of 15% between the ages of 30 and 40, and null from 45 years of age

19.6 Plan assets

The following tables show the allocation (by asset segment) of the assets of the CPFL Energia pension plans, at December 31, 2014, 2013 and 2012 managed by Fundação CESP and ELETROCEEE. It also shows the distribution of the collateral resources established as a target for 2015, in the light of the macroeconomic scenario in December 2014.

Assets managed by the plans as follows:

	Assets managed by Fundação CESP												Assets managed by ELETROCEEE
	CPFL Paulista and CPFL Geração						CPFL Piratininga						RGE
	Quoted in an active market			Not quoted in an active market			Quoted in an active market			Not quoted in an active market			Quoted in an active market			Not quoted in an active market
	2014	2013	2012	2014	2013	2012	2014	2013	2012	2014	2013	2012	2014	2013	2012	2014	2013	2012
Fixed rate	75%	73%	72%	-	-	-	78%	73%	75%	-	-	-	61%	61%	63%	-	-	-
Governament bonds	65%	63%	60%	-	-	-	65%	63%	62%	-	-	-	42%	40%	41%	-	-	-
Corporate bonds (financial institutions)	5%	6%	5%	-	-	-	9%	6%	9%	-	-	-	5%	5%	4%	-	-	-
Corporate bonds (non financial institutions)	1%	2%	2%	-	-	-	2%	2%	2%	-	-	-	8%	8%	10%	-	-	-
Multimarket funds	2%	2%	1%	-	-	-	2%	2%	2%	-	-	-	6%	8%	8%	-	-	-
Other fixed income investments	2%	1%	4%	-	-	-	-	1%	-	-	-	-	-	-		-	-	-
Variable income	18%	21%	22%	-	-	-	18%	21%	21%	-	-	-	23%	24%	23%	-	-	-
CPFL Energia's share	6%	8%	8%	-	-	-	5%	8%	6%	-	-	-	-	-	-	-	-	-
Investiment funds - shares	12%	13%	14%	-	-	-	13%	13%	15%	-	-	-	23%	24%	23%	-	-	-
Structured investments	-	-	-	-	-	-	-	-	-	-	-	-	14%	14%	13%	-	-	-
Equity funds	-	-	-	-	-	-	-	-	-	-	-	-	12%	12%	12%	-	-	-
Real estate funds	-	-	-	-	-	-	-	-	-	-	-	-	1%	1%	-	-	-	-
Multimarket fund	-	-	-	-	-	-	-	-	-	-	-	-	1%	1%	1%	-	-	-
Real estate	-	-	-	4%	3%	3%	-	-	-	2%	3%	2%	-	-		1%	1%	-
Loans to participants	-	-	-	2%	2%	2%	-	-	-	2%	2%	2%	-	-		1%	1%	1%
Other investments	-	-	-	1%	1%	1%	-	-	-	-	1%	-	-	-		-	-	-
Escrow deposits and othes	-	-	-	1%	1%	1%	-	-	-	-	1%		-	-		-	-	-
	93%	94%	94%	7%	6%	6%	96%	94%	96%	4%	6%	4%	98%	98%	99%	2%	2%	1%

The plan assets do not include any properties occupied or assets used by the Company. The fair value of the shares stated on the line "Shares of CPFL Energia" in the assets managed by Fundação CESP is R$ 288,061 in December 31, 2014 (R$ 378,225 in December 31, 2013).

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	2015 Target
	Fundação CESP		Fundação ELETROCEEE
	CPFL Paulista and CPFL Geração	CPFL Piratinga	RGE
Fixed rate	70.2%	73.2%	65.0%
Variable income	22.2%	20.3%	20.0%
Real state	3.4%	1.6%	1.0%
Loans to participants	1.5%	2.0%	1.0%
Structured investiments	2.2%	2.3%	13.0%
Investments abroad	0.5%	0.6%	0.0%
	100.0%	100.0%	100.0%

The allocation target for 2015 was based on the recommendations for allocation of assets made at the end of 2014 by Fundação CESP and ELETROCEEE, in its Investment Policy. This target may change at any time during 2015, in the light of changes in the macroeconomic situation or in the return on assets, among other factors.

The asset management aims to maximize the return on investments, while seeking to minimize the risks of an actuarial deficit. Investments are therefore always made bearing in mind the liabilities that have to be honored. One of the main tools used by Fundação CESP to achieve its management objectives is ALM (Asset Liability Management – Joint Management of Assets and Liabilities), performed at least once a year, for a horizon of more than 10 years. This tool also assists in studying the liquidity of the pension plans, taking into consideration the benefit payment flow in relation to liquid assets. ELETROCEEE also uses ALM.

The basis for determining the assumptions of estimated general return on the assets is supported by ALM. The main assumptions are macroeconomic projections for calculating the anticipated long-term profitability, taking into account the current benefit plan portfolios. ALM processes the ideal average long-term allocation of the plans’ assets and the estimated profitability in the long term is based on this allocation and on the assumptions of the assets’ profitability.

19.7 Sensitivity analysis

The significant actuarial assumptions for determining the defined benefit obligation are discount rate, anticipated salary increase and mortality. The following sensitivity analyses were based on reasonably possible changes in the assumptions at the end of the reporting period, with the other assumptions remaining constant.

The sensitivity analysis may not represent the actual change in the defined benefit liability, as it is improbable that the change would occur to isolated assumptions, as certain assumptions may be correlated.

Furthermore, in the presentation of the sensitivity analysis, the present value of the defined benefit obligation was calculated using the projected unit credit method at the end of the reporting period, the same method used to calculate the defined benefit obligation recognized in the balance sheet.

See below the effects on the defined benefit obligation if the discount rate were 0.25 percentage points higher (lower) and if life expectancy were to increase (decrease) in one year for men and women:

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	TOTAL
Defined benefit plan obligation	3,820,563	986,972	88,621	279,283	5,175,439

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Assumptions	Assumptions report (A)	Increase / (Decrease) (B)	Intended (A+B)	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	Increase / (decrease) of total defined benefit plan obligation
Nominal discount (p.a.)	11.46%	-0.25%	11.21%	88,503	27,097	2,093	7,184	124,877
		0.25%	11.71%	(84,949)	(25,851)	(2,007)	(6,872)	(119,679)
Life expectancy (years)	AT-2000(-10)	-1 year		(55.623)	(12,248)	(979)	(3,891)	(72,741)
		+1 year		80.819	15,228	2,115	4,038	102,200

19.8 Investment risk

The major part of the resources of the Company’s benefit plans is invested in the fixed income segment and, within this segment, the greater part of the funds is invested in federal government bonds, indexed to the IGP, which is the index for adjustment of the actuarial liabilities of the Company’s plans (defined benefit plans), match between assets e liabilities.

Management of the Company’s benefit plans is monitored by the Investment and Pension Management Committee, which includes representatives of active and retired employees, as well as members appointed by the Company. Among the duties of the Committee are the analysis and approval of investment recommendations made by the Fundação CESP investment managers, which happens quarterly, at least.

In addition to controlling market risks by the unplanned divergence methodology, as required by law, Fundação CESP uses the following tools to control market risks in the fixed income and variable income segments: VaR, Tracking Risk, Tracking Error and Stress Test.

Fundação CESP's Investment Policy imposes additional restrictions (along those established by law) which define the percentage of diversification for investments in assets issued or underwritten by the same legal entity.

( 20 )REGULATORY CHARGES

	December 31, 2014	December 31, 2013
Fee for the use of water resources	1,676	1,590
Global Reverse Fund - RGR	15,993	15,983
ANEEL Inspection Fee	1,553	1,869
Energy Development Account - CDE	24,570	12,937
FUST and FUNTEL	2
Total	43,795	32,379

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( 21 )TAXES AND SOCIAL CONTRIBUTIONS PAYABLE

	December 31, 2014	December 31, 2013
Current
ICMS (State VAT)	266,489	117,895
PIS (Tax on Revenue)	15,096	10,156
COFINS (Tax on Revenue)	69,701	45,892
IRPJ (Corporate Income Tax)	35,304	62,771
CSLL (Social Contribution Tax)	22,242	29,659
PIS (REFIS)	-	4,100
COFINS (REFIS)	-	18,886
Other	27,434	28,704
Total	436,267	318,063
Noncurrent
PIS (REFIS)	-	5,807
COFINS (REFIS)	-	26,748
Total	-	32,555

Tax Recovery Program - REFIS - Law 11,941/2009

Law 12,865/2013 was published on October 10, 2013, reopening the period for enrollment in the Tax Recovery Program - REFIS, in which subsidiaries CPFL Paulista and CPFL Piratininga formalized their enrollment in the program for reduction and financing of federal taxes in relation to tax suits - PIS and COFINS on Sector Charges - CCC/CDE - non-cumulative system in the total amount of R$ 57,465, obtaining a discount on interest and fines of R$ 36,823, recorded in financial income (note 30).

In June 2014, Law 12,966 was introduced, establishing the option of settling 70% of the balance of installment payments in process with own tax loss carry forwards or between holding companies and subsidiaries.

In November 2014, the subsidiaries CPFL Paulista and CPFL Piratininga settled   the total balance of R$ 40,006 thousand, R$ 12,001 in cash and R$ 28,005 with deferred tax loss carry forwards of CPFL Energia.

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( 22 )PROVISION FOR TAX, CIVIL AND LABOR RISKS AND ESCROW DEPOSITS

	December 31, 2014		December 31, 2013
	Provision for tax, civil and labor risks	Escrow Deposits	Provision for tax, civil and labor risks	Escrow Deposits
Labor
Various	124,261	82,857	119,707	80,516
Civil
Various	172,564	120,696	149,735	174,961
Tax
FINSOCIAL	27,585	77,576	25,682	73,633
Income Tax	120,054	829,589	128,332	779,899
Other	9,774	51,755	20,555	33,785
	157,413	958,920	174,568	887,318
Various	36,620	4	23,985	384
Total	490,858	1,162,477	467,996	1,143,179

The changes in the provisions for tax, civil and labor risks are shown below:

	December 31, 2013	Addition	Reversal	Payment	Monetary adjustment	Business combination	December 31, 2014
Labor	119,707	81,992	(35,513)	(57,453)	15,528	-	124,261
Civil	149,735	126,363	(35,322)	(105,917)	22,703	15,001	172,564
Tax	174,568	8,223	(27,665)	(7,712)	10,000	-	157,413
Various	23,985	39,427	(10,000)	(16,918)	126	-	36,620
	467,996	256,005	(108,500)	(188,000)	48,356	15,001	490,858

The provision for tax, civil and labor risks were based on assessment of the risks of losing litigation to which the Company and its subsidiaries are parties, where a loss is probable 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 -mainlyrefer to claims for indemnities relating to accidents in the subsidiaries' electrical grids, damage to consumers, vehicle accidents, etc.

Tariff increase -Corresponds to various claims by industrial consumers as a result of tariff increases imposed by DNAEE Ordinances 38 and 45, on 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 subsidiary CPFL Paulista of the rate increase and collection of FINSOCIAL during the period June 1989 to October 1991.

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Income Tax–the provision of R$120,094 (R$ 108,782 at December 31, 2013) recognized by the subsidiary CPFL Piratininga refers to the lawsuit in relation to the tax deductibility of CSLL in determination of corporate income tax - 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.

Possible losses:the Company and its subsidiaries are parties to other suits in which Management, supported by its external 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, 2014, were as follows: (i) R$ 459,303 labor (R$ 244,277 at December 31, 2013) related mainly to workplace accidents, risk premium, overtime, etc; (ii) R$ 481,575 civil (R$ 413,850 at December 31, 2013) are related mainly to bodily injury, environmental impacts and tariff increases; and (iii) R$ 3,216,981 tax (R$ 2,704,881 at December 31, 2013), related mainly to ICMS, FINSOCIAL, PIS and COFINS and Income taxes, being one of the main claims the deductibility of the expense recognized in 1997 in relation to the commitment assumed for the pension plan of the employees of the subsidiary CPFL Paulista with Fundação CESP estimated amounting R$ 1,008,733, for which CPFL Paulista has a linked escrow deposit of R$ 703,073 and (iv) R$ 37,739 regulatory at December 31, 2014 (R$ 27,628 at December 31, 2013).

The possible regulatory loss refers mainly to collection of the system service charge - ESS, established in the CNPE Resolution 03 of March 6, 2013. In relation to which, through the Brazilian Association of Independent Electric Energy Producers - APINE and the Brazilian Association for Generation of Clean Energy - ABRAGEL, the Company's subsidiaries and joint ventures obtained an injunction suspending collection of the charge.  The Company's legal counsel classified the risk of loss as possible.  The total amount of the risk is R$ 18,465, manly related to for the indirect subsidiaries CPFL Renováveis (R$ 12,642), Ceran (R$ 4,679), and Paulista Lajeado (R$ 1,106).

Based on the opinion of their external legal advisers, Management of the Company and its subsidiaries consider that the registered amounts represent best estimate.

Escrow deposits:income tax: of the total amount of R$ 829,589, R$ 703,073 (R$ 648,861 at December 31, 2013) refers to the discussion of the deductibility for federal tax purposes of expense recognized in 1997 in respect of the commitment made by the subsidiary CPFL Paulista to the employees’ pension plan in relation to Fundação CESP, in function of the renegotiation of the debt in that exercise. On consulting the Brazilian Federal tax authority, 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. As a result of that procedure, the subsidiary was assessed by the tax inspectors and, as a result of that procedure, the subsidiary was assessed by the tax inspectors. This discussion was responsible for some other unfavorable court decisions and the subsidiary offered escrow deposits in guarantee. Based on the updated position of the legal counsel in charge of the case and Management’s opinion the risk of loss is classified as possible.

( 23 )PUBLIC UTILITIES

Subsidiary	December 31, 2014	December 31, 2013	Number of remaining installments
CERAN	84,992	83,176	255
Current	4,000	3,738
Noncurrent	80,992	79,438

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( 24 )OTHER ACCOUNTS PAYABLE

	Current		Non current
	December 31, 2014	December 31, 2014	December 31, 2014	December 31, 2013
Consumers and Concessionaires	49,710	43,804	-	-
Energy Efficiency Program - PEE	267,123	218,419	13,370	11,537
Research & Development - P&D	105,125	164,180	12,389	4,842
National Scientific and Technological Development Fund - FNDCT	1,469	1,966	-	-
Energy Research Company - EPE	734	982	-	-
Fund of reversal	-	-	17,750	17,750
Advances	85,683	34,879	23,849	-
Provision for socio-environmental costs and decommissioning of assets	-	-	49,938	34,471
Payroll	12,232	17,639	-	-
Profit sharing	55,659	36,601	7,413	4,171
Collections agreement	91,889	73,240	-	-
Guarantees	-	-	31,479	29,133
Advance CDE	35,053	9,246	-	-
Account payable - bussiness combination	70,419	10,477	16,152	-
Other	60,844	52,095	11,425	1,981
Total	835,941	663,529	183,766	103,886

Consumers and concessionaires:refers to liabilities in connection with bills paid twice and adjustments of billing to be offset or returned to consumers as well the participation of consumers in the “Programa de Universalização” program.

Research and Development and Energy Efficiency Programs: The subsidiaries recognize liabilities relating to amounts already billed in tariffs (1% of Net Operating Revenue), but not yet invested in the Research and Development and Energy Efficiency Programs.  These amounts are subject to monthly restatement at the SELIC rate, to realization. 

Advances: refer mainly to advances from customers in relation to advance billing by the subsidiary CPFL Renováveis, before  the energy or service has actually been provided or delivered.

Provision for socio-environmental costs and decommissioning of assets:Refers mainly to reserve recorded by CPFL Renováveis in relation to socio-environmental licenses as a result of events that have already occurred and obligations to remove assets arising from contractual and legal requirements related to leasing of land on which the wind farms are located. Such costs are reserved for against fixed assets and will be depreciated over the remaining useful life of the asset.

Profit sharing:Mainly comprised by:

(i)in accordance 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;

(ii)Long-Term Incentive Program: In July2012, the Company’s Board of Directors approved the Long-Term Incentive Program for Executives, consisting of a plan to grant Phantom Stock Options and awards in funds, in accordance with the appreciation of the Company’s shares in relation to an amount calculated.The Plan does not cater for share distribution to the executives and only uses them for purposes of monitoring the targets laid down in the Company's Long-Term Strategic Plan, also approved by the Board of Directors.

The plan will run from 2012 to 2018 and certain Company executives who are exercising their duties on the grant date will be eligible.  The grant is annual and the vesting period for conversion into premiums will be from the second, third or fourth year after the grant date, with an option for 1/3 of the shares per year. Any failure to meet expectations in a conversion may be accumulated in subsequent vestings, up to the limit of the respective grant.

The Program provides for partial realization, if a minimum of 80% of the estimates of the Strategic Plan is reached, involving reduction of the award to the percentage reached, as well as the possibility of exceeding them, with a ceiling of 150% in accordance with the same criteria.

F -71

 

Business acquisition: Refers to the amounts recorded by the subsidiary CPFL Renováveis, mainly in relation to the acquisition of minority interests amounting R$ 71,490. This amount is derived from the merger of WF2 (Note 15.6) on October 1, 2014. An agreement for the purchase of shares and other covenants was signed on January 31, 2014 between WF2 and the non-controlling shareholders of DESA, which hold of 21.14% of the voting and total capital of DESA. Upon the  agreement, the non-controlling shareholders undertook to dispose  all of their shares at a price, and under the terms and subject to the conditions established in the agreement, corresponding to the total amount of R$ 203,000. The remaining amount of R$ 71,490 outstanding at December 31, 2014 will be paid  in five quarterly installments up to on January 29, 2016. The amount of each quarterly installment will be monetarily adjusted by CDI rate variation plus 1.2% a year (both on a pro rata basis).

( 25 )SHAREHOLDER’S EQUITY

The shareholders’ interest in the Company’s equity as of December 31, 2014 and 2013 are shown below:

	Number of shares
	December 31, 2014		December 31, 2013
Shareholders	Common shares	Interest %	Common shares	Interest %
BB Carteira Livre I FIA	288,569,602	29.99	288,569,602	29.99
Caixa de Previdência dos Funcionários do Banco do Brasil - Previ	477,700	0.05	487,700	0.05
Camargo Correa S.A.	837,860	0.09	837,860	0.09
ESC Energia S.A.	234,092,930	24.33	234,092,930	24.33
Bonaire Participações S.A.	1,200,000	0.12	6,308,790	0.66
Energia São Paulo FIA	141,929,430	14.75	136,820,640	14.22
Fundação Petrobras de Seguridade Social - Petros	1,759,900	0.18	1,759,900	0.18
Fundação Sistel de Seguridade Social	19,500	0.00	19,500	0.00
BNDES Participações S.A.	64,842,768	6.74	64,842,768	6.74
Antares Holdings Ltda.	16,039,720	1.67	16,039,720	1.67
Brumado Holdings Ltda.	34,502,100	3.59	34,502,100	3.59
Bord of Directors	800	0.00	-	-
Members of Executive Board	102,300	0.01	102,350	0.01
Other shareholders	177,899,650	18.49	177,890,400	18.49
Total	962,274,260	100.00	962,274,260	100.00

25.1Change in capital - controlling shareholder:

On June 28, 2014, the shareholder Bonaire Participações S.A. issued a Notice to Shareholders to communicate the approval of a reduction of R$ 206,541 in its capital, with no cancellation of shares. The capital reduction was as follows: (i) R$ 171,339 in cash, (ii) R$ 35,202 by delivery of 5,108,790 (five million, one hundred and eight thousand seven hundred and ninety) Company´s common shares not tied to the Company's shareholders' agreement, which were held by Bonaire.

25.2Capital reserves:

Refers to: (i) R$ 228,322  related to the CPFL Renováveis business combination occurred in 2011,  (ii) effect of the public offer of shares in the subsidiary CPFL Renováveis, as mentioned in note 15.5, amounting to R$ 59,308, as a result of the dilution in the indirect interest in CPFL Renováveis occurred in 2013, (iii) effect of DESA acquisition through the issuance of shares of CPFL Renováveis, as mentioned in note 15, amounting R$ 180,297, occurred in 2014,  and (iv) other transactions between shareholders without changes in control, amounting R$155. In accordance with IFRS 10, these effects were accounted for as transactions between shareholders and recorded directly in Company Shareholder’s Equity.

25.3Profit reserves:

Is comprised of:

i.Legal reserve, amounting to R$ 650,811.

ii.Statutory reserve – financial asset of concession: The distribution subsidiaries record in profit or loss the change in the expected  cash flow from the financial asset of concession; however, the financial realization will occur at the end of the concession through the indemnification of the concession by the Granting Authority. As result, the Company retains statutory reserve – financial asset of concession of the amounts, supported by article 194 of Law 6404/76, until the receipt of the financial asset. This statutory reserve amounts R$ 330,437 as of December 31, 2014.

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iii.Earnings retained for investment: On December 31, 2013, the Company retained R$108,987 for investments. In August 2014, it was noted that this reserve was no longer required for the purpose for which it was intended and the amount was reversed in August 31, 2014 and comprised the basis for distribution of an interim dividend.

25.4Other comprehensive income:

The accumulated comprehensive income is comprised of:

i.Deemed cost: Relates to recognition of the added value of the deemed cost of the generators' property, plant and equipment, of R$ 483,610;

ii.Post-employment benefit obligation: The negative amount of R$ 337,718 refers to the effects recorded directly in the comprehensive income, according to IAS 19.

25.5Dividends:

The Annual and Extraordinary General Meeting held on April 29, 2014 approved the allocation of net income for the year for 2013 and declared dividends of R$ 930,851, of which R$ 363,049 relate to the interim dividend declared of June 2013, plus an additional dividend of R$ 567,802.

In accordance with the by-laws and based on the income for the first half-year of 2014, the Board of Directors on August 27, 2014, approved the declaration of an interim dividend of R$ 422,195, attributing the amount of R$ 0,438746730 to each share paid on October 1, 2014.

The Company paid R$ 986,811 in 2014 basically in respect of the dividends declared at December 31, 2013 and June 30, 2014.

25.6Allocation 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.

The Management´s proposal is shown below:

Net income - Parent company	949,177
Realization of other comprehensive income	26,055
Prescribed Dividend	5,722
Net Income Base for Allocation	980,954
Legal Reserve	(47,459)
Reversion of Earnings retained for investment	108,987
Interim Dividend	(422,195)
Statutory reserve - financial asset of concession	(65,400)
Statutory reserve - working capital improvement	(554,888)

Since the amount of R$ 422,195 (44.5% of net income of the year), more than the obligatory dividend, has already been distributed as dividends for the year, and in view of (i) the current adverse economic scenario, (ii) the unpredictability of the hydrological situation and (iii) the uncertainties about the market projections of the distributors due to the energy efficiency campaigns and extraordinary tariff increases, Company Management proposes allocation of R$ 554,888 to the statutory - working capital improvement.

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25.7 – Interest of non-controlling shareholders:

Disclosure of interests in subsidiaries, as per IFRS 12, is as follows:

25.7.1 – Changes in the interest of non-controlling shareholders:

	CERAN	CPFL Renováveis		Paulista Lajeado	TOTAL
At December 31, 2011	191,222	1,216,523		77,607	1,485,352
Equity Interests and voting capital	35.00%	37.00%		40.07%
Net income attributable to non-controlling shareholders	19,744	3,037		8,029	30,810
Corporate reorganization	-	5,086		-	5,086
Other	-	3,309		(80)	3,229
Dividends	(5,875)	-		(8,201)	(14,076)
At December 31, 2012	205,091	1,227,955		77,355	1,510,401
Equity Interests and voting capital	35.00%	37.00%		40.07%
Net income attributable to non-controlling shareholders	24,380	(19,851)		7,088	11,617
IPO of CPFL Renováveis	-	269,192		-	269,192
Other	-	3,566		(69)	3,497
Dividends	(13,140)	-		(6,750)	(19,890)
At December 31, 2013	216,331	1,480,864		77,624	1,774,819
Equity Interests and voting capital	35.00%	41.16%		40.07%
Net income attributable to non-controlling shareholders	13,145	(72,782)		(3,097)	(62,733)
Business combination	-	759,686		-	759,686
Other	-	(1,254)		(1)	(1,255)
Dividends	(15,022)	(7,417)		(7,099)	(29,538)
At December 31, 2014	214,454	2,159,096		67,427	2,440,978
Equity Interests and voting capital	35.00%	48.39%	*	40.07%
* Non-controlling shareholders interests were 41.16% until February 28, 2014, 41.17% from March to September 2014 and 48.39% from October 1, 2014.

On October 1, 2014, the indirect subsidiary CPFL Renováveis acquired control of WF2 (holder of all the shares issued by DESA), with a total effect of R$ 759,686 on the non-controlling shareholders. The effect is due to the increased on the non-controlling shareholders due to acquisition of the control of WF2 (R$ 653,366) and the accounting for the fair value of the non-controlling shareholders of Ludesa Energética S.A., indirect subsidiary of WF2 (R$ 106,320). For further information, see Note 15.6.2.

25.7.2 – Summarized financial information for each of the Company's subsidiaries listing the interest of non-controlling shareholders

The summarized financial information at December 31, 2014 and 2013 and for the years ended in 2014, 2013 and 2012 of subsidiaries in which non-controlling interests are as follows:

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December 31, 2014	CERAN	CPFL Renováveis		Paulista Lajeado
Current assets	138,684	1,166,223		13,756
Cash and cash equivalents	84,201	828,411		328
Noncurrent assets	1,040,545	10,469,653		116,751
Current liabilities	129,255	1,019,960		35,315
Financial liabilities	108,355	786,660		9,388
Noncurrent liabilities	437,249	6,273,418		-
Financial liabilities	437,249	4,972,544		-
Shareholders' equity	612,726	4,342,498		95,192
Controlling  shareholders´ interest	612,726	4,230,497		95,192
Non-controlling  shareholders´ interest	-	112,001		-
Net operating revenue	327,066	1,247,627		42,771
Depreciation and amortization	(50,017)	(432,267)		(6)
Financial income	11,604	87,131		656
Financial expense	(40,441)	(418,141)		-
Social contribution and income tax	(18,880)	(33,645)		(2,691)
Net income	37,558	(167,362)		(7,728)
Net income attributable to controlling shareholders	37,558	(168,771)		(7,728)
Net income attributable to non-controlling shareholders	-	1,410		-
Equity Interests and voting capital	35.00%	48.39%	*	40.07%
* Noncontrolling shareholders interests were 41.16% up to February 2014, 41.17% from March to September 2014 and 48.39% from October 1, 2014.

December 31, 2013	CERAN	CPFL Renováveis		Paulista Lajeado
Current assets	110,430	1,040,470		26,529
Cash and cash equivalents	73,686	731,055		14,657
Noncurrent assets	1,090,695	8,454,767		116,739
Current liabilities	96,831	1,082,806		24,241
Financial liabilities	64,921	986,721		1,577
Noncurrent liabilities	486,207	4,834,189		-
Financial liabilities	486,207	3,842,990		-
Shareholders' equity	618,087	3,578,242		119,027
Controlling  shareholders´ interest	618,087	3,564,362		119,027
Non-controlling  shareholders´ interest	-	13,880		-
Net operating revenue	270,511	1,018,612		65,641
Depreciation and amortization	(47,050)	(348,355)		(6)
Financial income	5,928	46,793		615
Financial expense	(44,957)	(305,051)		-
Social contribution and income tax	(34,884)	(10,607)		(8,044)
Net income	69,657	(55,017)		17,693
Net income attributable to controlling shareholders	69,657	(54,947)		17,693
Net income attributable to non-controlling shareholders	-	(70)		-
Equity Interests and voting capital	35.00%	41.16%	*	40.07%
* In accordance with note 14.5, the net equity to noncontrolling shareholders until June, 2013 was 37%.

December 31, 2012	CERAN	CPFL Renováveis	Paulista Lajeado
Net operating revenue	250,595	806,420	47,829
Depreciation and amortization	(49,606)	(288,764)	(6)
Financial income	5,147	40,991	693
Financial expense	(53,141)	(265,226)	-
Social contribution and income tax	(29,201)	(9,256)	(3,447)
Net income	56,411	8,261	20,039
Net income attributable to controlling shareholders	36,667	5,223	12,009
Net income attributable to non-controlling shareholders	19,744	3,038	8,029
Equity Interests and voting capital	35.00%	37.00%	40.07%

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( 26 )EARNINGS PER SHARE

Earnings per share – basic and diluted

Calculation of the basic and diluted earnings per share for the years ended December 31, 2014, 2013 and 2012 was based on the net income attributable to controlling shareholders and the average weighted number of common shares outstanding during the years. For the diluted earnings per share, it was considered the dilutive effects of instruments convertible into shares, as shown below:

	December 31, 2014	December 31, 2013	December 31, 2012
Numerator
Net income attributable to controlling shareholders	949,177	937,419	1,176,252
Denominator
Weighted average shares outstanding during the year	962,274,260	962,274,260	962,274,260
Net income per share - basic	0.99	0.97	1.22
Numerator
Net income attributable to controlling shareholders	949,177	937,419	1,176,252
Dilutive effect of convertible debentures of subsidiary CPFL Renováveis (*)	(17,265)	(25,016)	(17,537)
Net income attributable to the Controlling Shareholders	931,912	912,403	1,158,715
Denominator
Weighted average shares outstanding during the year	962,274,260	962,274,260	962,274,260
Net income per share - diluted	0.97	0.95	1.20
(*) Proportional to the Company´s percentage interest in each period in the subsidiary

The dilutive effect of the numerator in the calculation of diluted earnings per share takes into account the dilutive effects of the debentures convertible into shares issued by subsidiaries of the indirectly subsidiary CPFL Renováveis. Calculation of the effects was based on the assumption that these debentures would have been converted into common shares of the subsidiaries at the beginning of each year.  The share-based payments granted at the subsidiary CPFL Renováveis shares have anti-dilutive impact at each year.

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( 27 )OPERATING REVENUE

	Number of Consumers (*)			In GWh (*)			R$ thousand
Revenue from Eletric Energy Operations	2014	2013	2012	2014	2013	2012	2014	2013	2012
Consumer class
Residential	6,732,715	6,523,553	6,312,737	16,501	15,426	14,567	6,533,590	5,710,050	6,631,596
Industrial	56,920	58,565	59,057	14,144	14,691	14,536	3,871,868	3,605,079	4,086,080
Commercial	483,204	491,057	494,556	9,437	8,837	8,714	3,471,225	2,956,069	3,389,159
Rural	243,275	245,687	243,283	2,326	2,081	2,093	496,790	415,075	492,633
Public Administration	50,538	49,443	48,467	1,295	1,234	1,220	476,557	407,094	451,241
Public Lighting	9,917	9,596	9,166	1,622	1,586	1,525	315,072	284,346	345,058
Public Services	8,155	7,961	7,729	1,861	1,820	1,864	566,719	486,609	543,216
(-) Adjustment of excess and surplus revenue of reactive	-	-	-	-	-	-	(84,017)	(59,731)	(24,643)
Billed	7,584,724	7,385,862	7,174,995	47,187	45,675	44,519	15,647,804	13,804,591	15,914,341
Own comsuption	-	-	-	34	34	33	-	-	-
Unbilled (Net)	-	-	-	-	-	-	63,142	73,536	136,905
Emergency Charges - ECE/EAEE	-	-	-	-	-	-	2	(254)	1
Reclassification to Network Usage Charge - TUSD - Captive Consumers	-	-	-	-	-	-	(5,464,570)	(5,287,096)	(7,558,153)
Electricity sales to final consumers	7,584,724	7,385,862	7,174,995	47,221	45,709	44,552	10,246,379	8,590,776	8,493,094
Furnas Centrais Elétricas S.A.				3,026	3,026	3,034	477,775	441,961	411,798
Other Concessionaires and Licensees				9,628	10,918	9,333	1,690,711	1,874,482	1,478,832
Current Electric Energy				2,334	1,031	2,062	976,377	205,976	197,758
Electricity sales to wholesaler´s				14,988	14,975	14,429	3,144,864	2,522,419	2,088,388
Revenue due to Network Usage Charge - TUSD - Captive Consumers							5,464,570	5,287,096	7,558,153
Revenue due to Network Usage Charge - TUSD - Free Consumers							990,815	965,737	1,412,275
(-) Adjustment of revenue surplus and excess responsive							(18,045)	(14,587)	(7,489)
Revenue from construction of concession infrastructure							944,997	1,004,399	1,351,550
Sector financial assets and liability							910,720	-	-
Revenue from construction of concession infrastructure							771,018	627,832	52,093
Other Revenue and Income							341,061	355,694	300,715
Other operating revenues							9,405,136	8,226,172	10,667,297
Total gross revenues							22,796,379	19,339,367	21,248,779
Deductions from operating revenues
ICMS							(3,106,928)	(2,777,486)	(3,178,771)
PIS							(335,937)	(271,301)	(297,476)
COFINS							(1,547,783)	(1,247,439)	(1,367,898)
ISS							(7,583)	(5,545)	(4,926)
Global Reversal Reserve - RGR							(2,362)	(3,791)	(101,136)
Fuel Consumption Account - CCC							-	(34,432)	(597,925)
Energy Development Account - CDE							(271,577)	(155,249)	(584,399)
Research and Development and Energy Efficiency Programs							(117,683)	(111,243)	(147,390)
PROINFA							(100,569)	(99,244)	(77,886)
Emergency Charges - ECE/EAEE							(2)	253	(1)
IPI							(10)	(34)	(94)
FUST e FUNTEL							(2)	-	-
							(5,490,436)	(4,705,511)	(6,357,904)
Net revenue							17,305,942	14,633,856	14,890,875
(*) Information not reviewed by the independent auditors

In accordance with ANEEL’s Order nº 4,097 of December 30, 2010, concerning the basic procedures for preparation of the financial statements, the energy distribution subsidiaries reclassified part of the amount related to revenue from under the heading “Electricity sales to final consumers”, Commercialization activities, to “Other operating revenues”, Distribution activities, with the title “Revenue due to Network Usage Charge - TUSD captive consumers”.

27.1Adjust of revenue of excess and surplus revenue of reactive:

The tariff regulation procedure (Proret), approved by ANEEL Normative Resolution n° 463 of November 22, 2011, determined that revenuereceived as a result of excess demand and excess reactive power, from the contractual tariff review date for the 3rd periodic tariff review,should be accounted for as Special Obligations and will be amortized from the next tariff review.

In accordance with ANEEL Order nº 4,991, of December 29, 2011, relating to the basic procedures for preparation of the financial statements, the distributors subsidiaries adjusted revenue of excess and surplus revenue of reactive, reducing the accounts of “Electricity sales to final consumers” and “Revenue due to Network Usage Charge - TUSD free consumers” against the item reducing of intangible assets (“Special Obligations”).

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On February 7, 2012, the Brazilian Association of Electric Energy Distributors (Associação Brasileira de Distribuidores de Energia Elétrica - ABRADEE) succeeded in suspending the effects of Resolution 463, whereby the request for advance final relief was granted and the order to account for income from excess demand and excess reactive as special obligations was suspended. The suspensive effect applied for by ANEEL in its interlocutory appeal was granted in June 2012 and the advance relief originally granted in favor of ABRADEE was suspended.The subsidiaries are awaiting the court’s decision on the final treatment of this income, and at December 31, 2014, these amounts are still recorded under Special Obligations, according to IAS 37, net disclosed in intangible assets of concession.

27.2 Periodic tariff revision (“RTP”) e Annual adjustment (“RTA”)

		2014		2013		2012
Company	Month	Annual Tariff Review - RTA	Effect perceived by consumers (a)	Annual Tariff Review - RTA	Effect perceived by consumers (a)	Annual Tariff Review - RTA	Effect perceived by consumers (a)
CPFL Paulista	April	17.18%	17.23%	5.48%	6.18%	3.71%	2.89%
CPFL Piratininga	October	19.73%	22.43%	7.42%	6.91%	8.79%	5.50%
RGE	June	21.82%	22.77%	-10.32%	-10.64%	11.51%	3.38%
CPFL Santa Cruz	February	14.86%	26.00%	9.32%	-0.94%	8.10%	-4.66%
CPFL Leste Paulista	February	-7.67%	-5.32%	6.48%	3.36%	0.08%	-1.25%
CPFL Jaguari	February	-3.73%	3.70%	2.71%	2.68%	-7.10%	-7.33%
CPFL Sul Paulista	February	-5.51%	0.43%	2.27%	2.21%	-3.72%	-5.02%
CPFL Mococa	February	-2.07%	-9.53%	7.00%	5.10%	9.00%	6.34%

(a)     Represents the average effect perceived by consumers, in accordance with ANEEL resolutions, as a result of elimination from the tariff base of financial components added in the annual adjustment for the previous year (unaudited).

27.3 Extraordinary Tariff Review (“RTE”)

In order to encompass the effects of Law 12,783 of January 2013 – Extension of the concessions and other topics of interest, ANEELratified the result of the 2013 Extraordinary Tariff Review (“RTE”), applied for consumption from January 24, 2013. The extraordinary review encompassed the electric energy quotas of the generation plants that renewed their concession contracts. The total energy produced by these plants was divided into quotas for the distributors. The effects of the elimination of the Global Reversal Reserve - RGR and Fuel Consumption Account - CCC, the reduction in the Energy Development Account - CDE and the decrease in the transmission costs were also computed. This RTE has no impact on the net profit or loss.  ANEEL ratified the result of the 2013 extraordinary review for the distribution subsidiaries with the following resolutions. The average effects for the distributors’ consumers were:

Distributors	Resolution n°	Effect perceived by consumers (*)
CPFL Paulista	1,433	-20.42%
CPFL Piratininga	1,424	-26.70%
RGE	1,411	-22.81%
CPFL Santa Cruz	1,452	-23.72%
CPFL Leste Paulista	1,450	-25.33%
CPFL Jaguari	1,451	-24.38%
CPFL Sul Paulista	1,449	-26.42%
CPFL Mococa	1,453	-23.83%
(*) Unaudited information

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27.4 – Resources provided by the Energy Development Account -CDE

Law 12,783 of January 11, 2013 determined that the resources related to the low income subsidy, as well as other tariff discounts should be fully subsidized by resources from the CDE. Income of R$ 771,018 was recorded in 2014 (R$ 627,832 in 2013), R$78,028  for the low income subsidy (R$ 69,231 in 2013) and R$692,990 for other tariff discounts (R$ 558,600 in 2013), set against accounts receivable – Resources provided by the Energy Development Account – CDE/CCEE (note 12) and accounts payable – CDE (note 24).

( 28 )COST OF ELECTRIC ENERGY

	GWh (*)			R$ thousand
Electricity Purchased for Resale	2014	2013	2012	2014	2013	2012
Itaipu Binacional	10,417	10,719	10,781	1,383,604	1,298,210	1,131,744
Current electric energy	5,074	2,974	2,662	3,018,523	726,936	244,921
PROINFA	1,043	1,019	1,070	264,068	233,152	215,400
Energy purchased of bilateral contracts and through action in the regulated market	42,345	42,980	48,085	8,837,459	6,786,524	5,814,982
Resources provided by the energy development account - CDE	-	-	-	(2,340,912)	(827,578)	-
Credit of PIS and COFINS	-	-	-	(1,005,106)	(748,526)	(677,043)
Subtotal	58,879	57,692	62,597	10,157,635	7,468,718	6,730,004
Electricity Network Usage Charge
Basic network charges				727,341	559,631	1,127,319
Transmission from Itaipu				37,896	34,716	96,454
Connection charges				44,834	44,470	79,855
Charges of use of the distribution system				33,147	29,542	34,322
System service charges - ESS				(326,248)	554,865	252,708
Reserve energy charges				10,898	33,194	85,148
Resources provided by the energy development account - CDE				(1)	(458,792)	-
Credit of PIS and COFINS				(42,372)	(69,655)	(152,815)
Subtotal				485,495	727,969	1,522,991
Total				10,643,130	8,196,687	8,252,995
(*) Unaudited information

28.1 Law 12,783/2013, Decree 7,945/2013, 8,203/2014 and 8,221/2014 and Dispatch 3,998/2014 – Resources provided by the CDE

Due to the unfavorable hydropower conditions from the end of 2012, including the low levels of water reserves at the hydroelectric power plants, the output of the thermal plants was set at the highest level. In view of this and considering the concessionaires’ exposure in the short-term market, due largely to allocation of the physical energy and power guarantee quotas and repeal of the plants’ authorization by ANEEL, the energy cost of the distributors increased significantly in 2012, 2013 and 2014.

As a result of this scenario and as the distribution concessionaires do not have control over these costs, on March 7, 2013, the Brazilian government issued Decree 7,945, amended by Decree 8,203/14 and further by Decree 8,221/14, which made certain changes in the contracting of energy and the objectives of the Energy Development Account - CDE charge:

i.pass-through of CDE funds to the distribution concessionaires in relation to the exposure in the hydrologic risk,  involuntary exposure, ESS – Energy Security, CVA ESS and Energy for the year of 2013 and January 2014;

ii.pass-through to the distribution concessionaires of costs related to involuntary exposure and output of the thermoelectric plants through the Electric Energy Commercialization Chamber - CCEE from February 2014 to December 2014. Additionally, Order 3,998 of September 30, 2014 included the hydrological risk of the renewed energy quotas as involuntary exposure, from July 2014.

A total amount of R$ 2,340,913 was recognized in 2014 as a result of these regulations (R$ 1,286,370 in 2013 and no amount in 2012).

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The effects of these items were registered as a reduction of the cost of electric energy under CDE/CCEE contribution against other credits under Accounts receivable - CDE/CCEE contribution (Note 12), in accordance with IAS 20 Accounting for Government Grants and Disclosure of Government Assistance.

In addition to the CDE contributions, the distribution subsidiaries received, via the CCEE, the financial excess of the Energy Reserve Account - CONER, regulated by REN 613/2014. The amount of R$ 437,297 is recorded under "System service charge – ESS" in 2014.

In the tariff review of April 2013 for the subsidiary CPFL Paulista, through Order 1144/2013, ANEEL granted full coverage of the positive balances of CVA calculated on energy purchased and the ESS charge for  2012, as well as positive amounts of the CVA for energy purchased in the availability auction, in the accrual period of January 2013. In the tariff review of October 2013 for the subsidiary CPFL Piratininga, through Order 1638/2013, ANEEL granted partially coverage of the positive amounts of the CVA calculated on energy purchased and the ESS charge for October 2012 to October 2013.

The resources provided by the CDE recognized in 2014 and 2013 are shown in the following table, per distributor controlled by the Company:

	2014
	Electricity purchased for resale				Electricity network usage charge		Total
	Involuntary exposure	Quotas and hydrological risk	Electricity purchased - CCEAR	Electricity purchased - tariff review	System service charges - ESS	System service charges - ESS - tariff review
CPFL Paulista	849,901	(6,241)	229,335	-	6	-	1,073,001
CPFL Piratininga	391,476	(357)	354,079	-	2	-	745,200
CPFL Santa Cruz	66,403	13	20,344	-	-	-	86,760
CPFL Leste Paulista	6,580	4	(4)	-	(10)	-	6,570
CPFL Sul Palista	6	5	11	-	-	-	22
CPFL Jaguari	(1,539)	(48)	2,001	-	-	-	414
CPFL Mococa	-	2	-	-	-	-	2
RGE	428,054	(98)	986	-	3	-	428,945
Total	1,740,881	(6,720)	606,752	-	1	-	2,340,913

	2013
	Electricity purchased for resale				Electricity network usage charge		Total
	Involuntary exposure	Quotas and hydrological risk	Electricity purchased - CCEAR	Electricity purchased - tariff review	System service charges - ESS	System service charges - ESS - tariff review
CPFL Paulista	161,087	10,868	-	327,252	217,464	44,207	760,878
CPFL Piratininga	76,735	395	-	167,901	88,166	(122)	333,076
CPFL Santa Cruz	8,689	(28)	-	15,514	16,082	(5,323)	34,934
CPFL Leste Paulista	1,092	(6)	-	-	6,487	-	7,573
CPFL Sul Palista	-	(11)	-	-	3,621	-	3,610
CPFL Jaguari	2,537	98	-	-	4,631	-	7,267
CPFL Mococa	-	(6)	-	-	2,717	-	2,711
RGE	53,593	(287)	-	2,153	72,310	8,553	136,321
Total	303,734	11,023	-	512,821	411,476	47,316	1,286,370

There were no resources provided by the CDE recognized in 2012.

F -80

 

( 29 )OPERATING COSTS AND EXPENSES

				Services rendered to third parties			Operating expenses									Total
	Operating costs							Sales		General			Other
	2014	2013	2012	2014	2013	2012	2014	2013	2012	2014	2013	2012	2014	2013	2012	2014	2013	2012
Personnel	528,056	425,349	415,862	2	-	30	110,759	106,111	104,343	213,654	192,142	177,023	-	-	-	852,471	723,602	697,258
Post-employment benefit	48,165	61,665	33,332	-	-	-	-	-	-	-	-	-	-	-	-	48,165	61,665	33,332
Materials	102,959	92,562	89,526	1,286	2,661	1,757	4,658	4,117	2,965	8,925	6,806	9,120	-	-	-	117,827	106,145	103,368
Outside services	172,422	178,809	174,326	2,511	2,464	2,356	109,264	100,301	107,603	241,826	205,450	256,949	-	-	-	526,022	487,024	541,233
Depreciation and Amortization	767,117	664,601	619,568	-	-	-	32,049	33,689	33,046	75,779	59,964	41,598	-	-	-	874,946	758,253	694,213
Costs related to infrastructure construction	-	-	-	942,267	1,004,399	1,351,550	-	-	-	-	-	-	-	-	-	942,267	1,004,399	1,351,550
Other	53,640	44,531	45,093	(13)	(6)	(18)	145,968	132,379	220,188	233,446	464,253	239,673	328,000	285,148	376,898	761,041	926,304	881,834
Collection charges	264	-	-	-	-	-	54,070	52,372	49,053	-	-	-	-	-	-	54,334	52,372	49,053
Allowance for doubtful accounts	-	-	-	-	-	-	83,699	70,324	163,811	-	-	-	-	-	-	83,699	70,324	163,811
Leases and rentals	29,331	26,181	28,484	-	-	-	-	11	88	15,627	12,390	9,210	-	-	-	44,958	38,582	37,782
Publicity and advertising	736	871	106	-	-	-	127	212	26	17,262	13,179	22,604	-	-	-	18,125	14,262	22,736
Legal, judicial, indemnities and penalties	-	-	-	-	-	-	-	-	-	192,464	429,883	187,420	-	-	-	192,464	429,883	187,420
Donations, contributions and subsidies	-	-	-	-	-	-	6,579	8,003	5,815	4,204	3,935	2,337	-	-	-	10,783	11,938	8,151
Inspection fee	-	-	-	-	-	-	-	-	-	-	-	-	20,894	27,422	30,136	20,894	27,422	30,136
Loss/(Gain) on disposal and decommissioning and other losses on noncurrent assets	-	-	6,276	-	-	-	-	-	-	-	-	-	20,726	(39,253)	48,051	20,726	(39,253)	54,328
Intangible of concession amortization	-	-	-	-	-	-	-	-	-	-	-	-	285,018	296,977	284,713	285,018	296,977	284,713
Financial compensation for water resources utilization	14,835	10,515	4,235	-	-		-	-		-	-		-	-		14,835	10,515	4,235
Other	8,474	6,963	5,991	(13)	(6)	(18)	1,493	1,457	1,394	3,889	4,866	18,104	1,361	2	13,997	15,204	13,282	39,468
Total	1,672,359	1,467,516	1,377,706	946,052	1,009,518	1,355,675	402,698	376,597	468,146	773,630	928,614	724,364	328,000	285,148	376,898	4,122,739	4,067,393	4,302,788

F -81

 

( 30 )FINANCIAL INCOME AND EXPENSES

	2014	2013	2012
Financial Income
Income from financial investments	430,714	316,617	200,860
Arrears of interest and fines	146,992	143,429	167,346
Monetary adjustment of tax credits	25,309	8,425	9,932
Monetary adjustment of escrow deposits	74,500	118,406	50,605
Monetary and exchange adjustments	49,144	43,615	49,437
Adjustment to expected cash flow (note 11)	104,642	-	159,195
Discount on purchase of ICMS credit	17,382	21,446	18,917
PIS and COFINS on insterest on shareholders' equity	(12,809)	(15,368)	(19,218)
Other	54,563	62,637	69,889
Total	890,436	699,208	706,963
Financial Expense
Debt charges	(1,542,593)	(1,291,762)	(1,072,622)
Monetary and exchange variations	(247,591)	(182,022)	(120,342)
Adjustment to expected cash flow (note 11)	-	(66,851)	-
(-) Capitalized borrowing costs	12,269	57,184	48,172
Public utilities	(10,649)	(11,690)	(11,128)
Other	(191,325)	(175,511)	(128,816)
Total	(1,979,890)	(1,670,651)	(1,284,736)
Net financial expense	(1,089,454)	(971,443)	(577,773)

Interest was capitalized at an average rate of 8.12% p.a. (8.24% p.a. in 2013 and 7.85% p.a. in 2012) on qualifying assets, in accordance with IAS 23.

In the monetary and exchange variations caption it is included the effects of gains of R$160,052 (R$ 211,282 in 2013 and R$ 182,892 in 2012) on derivative instruments (note 35).

( 31 )SEGMENT INFORMATION

The Company’s operating segments are based on the internal financial information and management structure and are separated by type of business: electric energy distribution, conventional generation, renewable generation, commercialization and services rendered.

Profit or loss, assets and liabilities per segment include items directly attributable to the segment, as well as those that can be allocated on a reasonable basis, if applicable. Average prices used between 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 operating segment is shown below, in accordance with the criteria established by Company Management:

F -82

 

	Distribution	Generation (conventional sources)	Generation (Renewable sources)	Commercialization	Services	Other (*)	Elimination	Total
2014
Net revenue	13,658,786	722,623	982,613	1,790,822	151,037	61	-	17,305,942
(-) Intersegment revenues	19,668	467,761	397,630	387,788	193,483	-	(1,466,329)	-
Income from electric energy service	1,602,519	482,214	231,280	205,108	45,072	(26,119)	-	2,540,073
Financial income	552,918	84,884	98,991	29,543	6,380	117,720	-	890,436
Financial expense	(849,774)	(482,671)	(464,713)	(29,104)	(10,221)	(143,407)	-	(1,979,890)
Income before taxes	1,305,663	144,112	(134,442)	205,547	41,230	(51,806)	-	1,510,304
Income tax and social contribution	(461,264)	(36,291)	(33,645)	(69,543)	(12,687)	(10,430)	-	(623,860)
Net Income	844,400	107,820	(168,087)	136,003	28,543	(62,236)	-	886,443
Total Assets (**)	16,724,269	4,414,196	11,601,754	507,960	828,184	1,022,454	-	35,098,816
Capital Expenditures and other intangible assets	702,386	14,419	250,803	3,531	90,707	22		1,061,868
Depreciation and Amortization	(577,753)	(136,447)	(432,267)	(4,471)	(8,760)	(265)	-	(1,159,964)
2013
Net revenue	11,563,700	601,980	802,011	1,579,893	84,622	1,649	-	14,633,856
(-) Intersegment revenues	15,354	323,658	281,913	264,891	116,184	-	(1,002,001)	-
Income from electric energy service	1,550,951	559,784	214,750	52,060	13,333	(21,103)	-	2,369,775
Financial income	504,463	40,005	55,083	27,665	13,876	58,115	-	699,208
Financial expense	(906,153)	(338,783)	(314,243)	(22,601)	(4,358)	(84,513)	-	(1,670,651)
Income before taxes	1,149,261	381,874	(44,410)	57,123	22,852	(47,500)	-	1,519,200
Income tax and social contribution	(423,712)	(69,937)	(10,607)	(21,399)	(6,881)	(37,627)	-	(570,164)
Net Income	725,549	311,937	(55,017)	35,724	15,970	(85,127)	-	949,036
Total Assets (**)	15,263,417	4,515,880	9,470,564	342,516	243,612	1,206,806	-	31,042,796
Capital Expenditures and other intangible assets	844,804	9,744	827,704	3,593	48,646	345	-	1,734,836
Depreciation and Amortization	(564,538)	(133,514)	(348,355)	(4,106)	(4,632)	(86)	-	(1,055,231)
2012
Net revenue	12,391,730	558,547	608,223	1,284,069	46,855	1,452	-	14,890,875
(-) Intersegment revenues	22,138	269,688	210,260	602,332	124,968	-	(1,229,386)	-
Income from electric energy service	1,369,809	496,885	215,139	255,193	26,276	(28,210)	-	2,335,091
Financial income	558,130	32,809	56,461	39,389	4,777	15,397	-	706,963
Financial expense	(632,278)	(228,949)	(254,333)	(140,506)	8,475	(37,143)	-	(1,284,736)
Income before taxes	1,295,661	421,423	17,268	154,076	39,528	(49,957)	-	1,877,998
Income tax and social contribution	(469,081)	(72,756)	(9,256)	(52,000)	(12,856)	(54,987)	-	(670,937)
Net Income	826,580	348,667	8,011	102,075	26,672	(104,944)	-	1,207,062
Total Assets (**)	14,729,776	4,376,137	8,786,521	466,645	186,303	378,897	-	28,924,279
Capital Expenditures and other intangible assets	1,402,994	12,804	1,021,970	2,870	18,865	508	-	2,460,011
Depreciation and Amortization	(544,192)	(138,417)	(289,372)	(3,177)	(3,693)	(74)	-	(978,926)
(*) Other – refers basically to the assets and transactions recorded at CPFL Energy which are not related to any of the identified segments.
(**) Intangible assets (net of amortization) recorded at CPFL Energia, were allocated to their respective segments.

( 32 )RELATED PARTIES TRANSACTIONS

The Company’s controlling shareholders are as follows:

·ESC 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.

·Energia São Paulo Fundo de Investimento em Ações

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.

·Bonaire Participações S.A.

Company controlled by Energia São Paulo Fundo de Investimento em Ações.

·BB Carteira Livre I - Fundo de Investimento em Ações

Fund controlled by PREVI - Caixa de Previdência dos Funcionários do Banco do Brasil.

The direct and indirect interest in operating subsidiaries are described in note 1.

F -83

 

Controlling shareholders, associated companies, joint ventures and entities under common control that in some way exercise significant influence over the Company are considered to be related parties.

The main transactions are listed below:

a)Bank deposits and short-term investments–refer mainly to bank deposits and short-term financial investments with the Banco do Brasil, as mentioned in note 5. The Company and its subsidiaries also have an Exclusive Investment Fund, managed, by BB DTVM, among others.

b)Loans and Financing and Debentures– relate to funds raised from the Banco do Brasil in accordance with notes 17 and 18. The Company also guarantees certain loans raised by its subsidiaries and joint ventures, as mentioned in notes 17 and 18.

c)Other Financial Transactions – the amounts in relation to Banco do Brasil are bank costs and collection expenses.

d)Purchase and sale of energy and charges -Refers to energy purchased or sold by distribution, commercialization and generation subsidiaries through short or long-term agreements and tariffs for the use of the distribution system (TUSD). Such transactions, in the free Market, are carried out under conditions regarded by the Company as similar to market conditions at the time of the negotiation, in accordance with internal policies established in advance by Company Management. In the regulated market, the prices charged are set by mechanisms established by the Grantor.

e)Intangible assets, Property, plant and equipment, Materials and Service– refer 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.

f)Advances –advances for investments in research and development.

g)Intercompany loan -relates to (i) contracts with the joint venture EPASA, under contractual conditions of 113.5% of the CDI, maturing in January 2017; (ii) contracts with the non-controlling shareholder of the subsidiary CPFL Renováveis, the maturing by November 2015 with annual interest of 8% + IGP-M.

Certain subsidiaries have supplementary retirement plan maintained with Fundação CESP and offered to the employees of the subsidiaries. These plans hold investments in Company’s shares (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 subsidiaries CPFL Paulista, CPFL Piratininga and CPFL Geração renegotiated with the joint ventures BAESA, ENERCAN and Foz do Chapecó the original maturities of the energy purchase invoices for the period from June to December 2014, to a mature in January 2015.

The total remuneration of key management personnel in2014 was R$ 44,214 (R$ 33,680 in 2013). This amount comprises R$ 39,928 (R$ 36,382 in 2013 and R$32,794 in 2012) respect of short-term benefits, R$ 1,043 (R$ 973 in 2013 and R$1,109 in 2012) for post-employment benefits and an accrual of R$ 3,243 (reversal of accrual of R$ 3,675 in 2013 and accrual of R$ 6,342 in 2012) for other long-term benefits.

Transactions between related parties involving controlling shareholders, entities under common control or with significant influence and joint ventures:

F -84

 

	Assets		Liabilities		Revenues			Expenses
	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013	2014	2013	2012	2014	2013	2012
Bank deposits and short-term investments
Banco do Brasil S.A.	161,832	115,968	-	-	12,126	6,331	7,687	2	-	1
Loans and financing, debentures and derivatives contracts
Banco do Brasil S.A.	-	-	1,322,926	1,638,769	-	-	-	174,673	88,646	129,222
Other financial transactions
Banco do Brasil S.A.	-	-	-	-	-	1,224	1,633	6,271	6,031	5,483
JBS S/A (**)	-	-	-	-	-	78	4,010	-	-	-
BAESA – Energética Barra Grande S.A.	-	-	-	-	-	-	-	3,228	-	-
Foz do Chapecó Energia S.A.	-	-	-	-	-	-	-	6,262	1,277	-
ENERCAN - Campos Novos Energia S.A.	-	-	-	-	-	-	-	5,005	1,021	-
Advances
BAESA – Energética Barra Grande S.A.	-	-	826	862	-	-	-	-	-	-
Foz do Chapecó Energia S.A.	-	-	1,170	1,222	-	-	-	-	-	-
ENERCAN - Campos Novos Energia S.A.	-	-	1,436	1,496	-	-	-	-	-	-
EPASA - Centrais Elétricas da Paraiba	-	-	526	549	-	-	-	-	-	-
Energy purchase and sale and charges
Afluente Transmissão de Energia Elétrica S.A.	-	-	40	24	-	-	-	1,342	1,048	1,375
Arizona 1 Energia Renovável S.A	-	-	-	-	-	-	-	826	-	-
Baguari I Geração de Energia Elétrica S.A.	-	-	5	5	-	-	-	252	234	-
Braskem S.A. (ex-Copesul)	-	-	-	-	694	20,916	-	-	-	-
Caetite 2 Energia Renovável S.A.	-	-	-	-	-	-	-	757	636	-
Caetité 3 Energia Renovável S.A.	-	-	-	5	-	-	-	765	642	-
Calango 1 Energia Renovável S.A.	-	-	-	-	-	-	-	914	1,044	-
Calango 2 Energia Renovável S.A.	-	-	-	-	-	-	-	782	-	-
Calango 3 Energia Renovável S.A.	-	-	-	-	-	-	-	914	-	-
Calango 4 Energia Renovável S.A.	-	-	-	-	-	-	-	848	-	-
Calango 5 Energia Renovável S.A.	-	-	-	-	-	-	-	901	-	-
Camargo Correa Cimentos S.A.	-	-	-	-	-	-	7,561	-	-	-
Companhia de Eletricidade do Estado da Bahia – COELBA	833	728	-	-	12,606	12,427	6,362	-	-	-
Companhia Energética de Pernambuco - CELPE	920	545	-	-	6,304	19,096	6,351	-	-	-
Companhia Energética do Ceara - COELCE (**)							1,937
Companhia Energética do Rio Grande do Norte - COSERN	280	223	-	191	2,404	8,125	2,624	1,063	1,070	-
Eldorado Brasil Celulose S.A.	-	-	-	-	1,050	-	-	-	-	-
Energética Águas da Pedra S.A.	-	-	117	120	-	-	-	3,959	3,746	3,512
Estaleiro Atlântico Sul S.A.	-	-	-	-	7,584	6,106	-	-	-	-
Fras-le	-	-	-	-	-	6	-	-	-	-
Goiás Sul Geração de Enegia S.A.	-	-	-	-	-	-	-	155	145	-
Mel 2 Energia Renovável S.A.	-	-	-	-	-	-	-	617	523	-
MULTINER S/A	-	-	-	-	-	207	-	-	-	-
NC ENERGIA S.A.	-	-	-	-	1,837	22,576	19,813	-	-	-
Petrobrás							3,207			34,143
Raposo Tavares	-	-	-	-	-	21	-	-	-	-
Rio PCH I S.A.	-	-	217	220	-	-	4,732	7,441	7,066	1,353
SE Narandiba S.A.	-	-	-	-	-	-	-	142	117	141
Serra do Facão Energia S.A. - SEFAC	-	-	470	547	-	-	-	19,837	18,602	15,876
Tavex Brasil S.A	-	-	-	-	8,087	11,368	18,448	-	-	-
ThyssenKrupp Companhia Siderúrgica do Atlântico	-	-	188	178	557	346	-	7,056	6,280	5,841
Vale Energia S.A.	7,371	6,960	-	-	87,077	89,671	77,041	-	-	-
VALE S.A.	-	-	-	-	-	-	2,877	7,483	1,419	21,024
BAESA – Energética Barra Grande S.A.	-	-	89,202	29,568	-	-	497	101,263	75,951	182,003
Foz do Chapecó Energia S.A.	1,430	-	172,804	111,019	16,841	3,936	14,152	311,878	327,385	303,670
ENERCAN - Campos Novos Energia S.A.	583	544	154,678	103,252	6,702	9,376	6,264	221,590	232,815	209,814
EPASA - Centrais Elétricas da Paraiba	-	2	28,632	17,094	24,363	75,781	6,869	214,978	107,348	74,761
Intangible assets, Property, plant and equipment, Materials and Service
Banco do Brasil S A	-	-	-	-	-	-	-	163	-	-
Barrocão Empreendimento Imobiliário SPE Ltda.	-		-	-	-	67	-	-	-	-
Boa Vista Empreendimento Imobiliário SPE Ltda.	-	2	-	-	-	50	35	-	-	-
Brasil Telecom										737
BRASKEM Qpar S.A.	-	-	-	-	15	-	-	-	-	-
CCDI 29 Empreendimento Imobiliário Ltda	-	-	-	-	31,500	-	-	-	-	-
Celesc - Centrais Elétricas Sta Catarina	-	-	-	-	-	-	-	-	1,078	-
Cia.de Saneamento Básico do Estado de São Paulo - SABESP	11	85	35	36	50	1,002	42	4	27	43
Companhia Energética do Rio Grande do Norte - COSERN	-	-	-	-	19	-	-	-	-	-
Concessionária do Sistema Anhanguera - Bandeirante S.A. (*)	-	-	-	-	-	-	-	-	50	50
Concessionárias de Rodovias do Oeste de São Paulo	-	-	-	-	-	-	262	-	-	-
Construções e Comércio Camargo Corrêa S.A.	-	-	-	-	-	-	-	-	-	970
Embraer	-	-	-	-	-	36	-	-	-	-
Estaleiro Atlântico Sul S.A.	-	-	-	-	12	-	-	-	-	-
Ferrovia Centro-Atlântica S.A.	-	507	-	-	-	1,526	112	-	-	100
OI S.A. e Brasil Telecom S.A.	-	-	-	-	-	-	-	-	-	653
HM 11 Empreendimento Imobiliário SPE Ltda	-	-	-	-	-	9	-	-	-	-
HM 12 Empreendimento Imobiliário SPE Ltda	-	-	-	-	-	9	12	-	-	-
HM 25 Empreendimento Imobiliário SPE Ltda.	-	-	-	-	-	63	-	-	-	-
HM Engenharia e Construções S.A.	-	-	-	-	24	-	-	-	-	-
Hortolândia 4A Empreendimento Imobiliário SPE Ltda	-	-	-	-	-	41	-	-	-	-
Indústrias Romi S.A.	4	4	-	-	45	43	40	-	-	-
InterCement Brasil S.A	-	-	-	-	60	53	1,545
Itaúsa	-	-	-	-	-	-	-	-	270	-
Jaguariúna III Empreendimento Imobiliário SPE Ltda.	-	-	-	-	-	56	-	-	-	-
LUPATECH	-	-	-	-	-	-	-	-	3	-
Randon	-	-	76	-	-	-	-	76	-	-
Renovias Concessionária S.A. (*)	-	-	-	-	-	-	-	-	6	8
Rodovias Integradas do Oeste - SP Vias (*)	-	26	-	28	-	300	578	-	-	24
MRS Logística S.A	119	-	-	-	119	168	-	-	-	-
Petrobrás Biocombustível S.A.	-	9	-	-	-	208	30	-	-	-
Recanto dos Sonhos Empreendimento Imobiliário SPE	-	-	-	-	-	-	60	-	-	-
SAMM - Sociedade de Atividades em Multimídia Ltda.(*)	-	306	-	-	-	627	409	-	-	-
Sumaré Matão Empreendimento Imobiliário SPE Ltda.	-	-	-	-	-	-	45	-	-	122
TOTVS S.A.	-	-	2	42	-	-	-	70	2,766	1,942
Ultrafértil S.A	149	-	-	-	226	-	-	-	-	-
Vale Fertilizantes S.A	18	-	-	-	36	-	-	-	-	-
BAESA – Energética Barra Grande S.A.	-	66	-	-	1,465	1,367	1,298	-	-	-
Foz do Chapecó Energia S.A.	-	-	-	-	1,491	1,499	1,330	-	-	-
ENERCAN - Campos Novos Energia S.A.	-	-	-	-	1,465	1,367	1,298	-	-	-
EPASA - Centrais Elétricas da Paraíba S.A.	393	-	-	-	715	5,185	-	-	-	-
Other revenue
OI S.A. e Brasil Telecom S.A.	-	-	-	-	-	-	12,051	-	-	-
Intercompany loans
EPASA - Centrais Elétricas da Paraíba S.A.	94,385	86,655	-	-	10,629	5,585	-	-	-	-
Acionista não controlador - CPFL Renováveis	6,281	6,862	-	-	864	1,041	-	-	-	-
Dividends and Interest on shareholders’ equity
BAESA – Energética Barra Grande S.A.	96	48	-	-	-	-	-	-	-	-
Chapecoense Geração S.A.	12,128	21,744	-	-	-	-	-	-	-	-
ENERCAN - Campos Novos Energia S.A.	24,816	16,054	-	-	-	-	-	-	-	-
EPASA - Centrais Elétricas da Paraiba	14,891	14,891	-	-	-	-	-	-	-	-
(*) Related party until December 31, 2013
(**) Related party until December 31, 2012

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( 33 )INSURANCE

The subsidiaries maintain insurance policies with coverage 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	2014	2013	2012
Non current assets	Fire, Lightning, Explosion, Machinery breakdown, Electrical Damage and Engeneering Risk	6,810,183	6,241,881	5,712,235
Transport	National Transport	299,487	634,171	180,766
Stored Materials	Fire, Lightning, Explosion and Robbery	170,300	262,883	50,935
Automobiles	Comprehensive Cover	4,962	5,327	6,536
Civil Liability	Electric Energy Distributors	168,000	166,000	128,000
Personnel	Group Life and Personal Accidents	193,020	163,597	172,736
Other	Operational risks and other	279,897	311,755	347,213
Total		7,925,850	7,785,615	6,598,421
Information not examined by the independent auditors.

( 34 )RISK MANAGEMENT  

The business of the Company and its subsidiaries mainly comprises the generation, commercialization and distribution of electric energy.  As public utilities concessionaires, the operations and/or tariffs of its principal subsidiaries are regulated by ANEEL.

Risk management structure:

TheBoard of Directors is responsible fordirecting the way the business is run, which includes monitoring of business risks, exercised by means of the corporate risk management model used by the Company. The responsibilities of the Executive Board are to develop the mechanisms for measuring the impact of the exposure and probability of its occurrence, supervising the implementation of risk mitigation measures and informing the Board of Directors. It is assisted in this process by: i) the Corporate Risk Management Committee, whose mission is to assist in identifying the main business risks, analyzing measurement of the impact and probability and assessing the mitigation measures used; ii) the Risk Management, Internal Control and Consolidated Processes Division, responsible for developing the Company’s Corporate Risk Management model in respect of strategy (policy, direction and risk maps), processes (planning, measurement, monitoring and reporting), systems and governance.

The risk management policies are establishedto identify, analyze and treat the risks faced by the Company and its subsidiaries,and includes reviewing the model adopted whenever necessary to reflect changes in market conditions and in the Company's activities, with a view to developing an environment of disciplined and constructive control.

In its supervisory role, the Company’s Board of Directors also counts on the support of the Management Procedures Committee to provide guidance for the Internal Auditing work and in preparing proposals for improvements. The Internal Auditing team conducts both periodic and “ad hoc” reviews in order to ensure alignment of the procedures to directives and strategies set by the shareholders and management.

The Fiscal Council’s responsibilities include certifying that Management has the means to identify and prevent, through the use of an appropriated information system, (a) the main risks to which the Company is exposed, (b) the probability that these will materialize and (c) the measures and plans adopted.

The main market risk factors affecting the businesses are as follows:

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Exchange rate risk:This risk derives from the possibility of the subsidiaries to incur in losses and cash constraints due to fluctuations in currency exchange rates, increasing the balances of liabilities denominated in foreign currency. 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 quantification of this risk is presented in note 35. The Company’s subsidiaries’ operations are also exposed to exchange variations on the purchase of electric energy from Itaipu. The compensation mechanism - CVA protects the companies against possible losses.

Interest rate Risk:This risk derives from the possibility of the Company and its subsidiaries to incurr in 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 presented in note 35.

Credit risk:This risk arises from the possibility of the subsidiaries incurring losses resulting from difficulties in collecting 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 primarily generated by hydropower plants. A prolonged period of low rainfall 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 comprehensive electric energy saving programs or other rationing programs, as in 2001. The hydrological situation in the Southeast, Mid-West and Northeast regions, are unfavorable on the beginning of 2015. Consequently, the current energy scenario for the Interconnected System requires attention and monitoring, especially during the wet season of these regions, which ends in April.

Risk of acceleration of debts:The Company and its subsidiaries have loans and financing agreements and debentures with restrictive clauses (covenants) normally applicable to these kinds of arrangement, involving compliance with economic and financial ratios. These covenants are monitored and do not restrict the capacity to operate normally, if met at the contractual intervals or if prior agreement is obtained from the creditors for failure to meet.

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 accordance 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 distributor to the final consumers. In accordance with Law 8,987/1995, the fixed tariffs should insure the economic and financial balance of the concession contract at the time of the tariff review, which could result in lower results than expected by the electric energy distributors, albeit offset in subsequent periods by other adjustments.

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 routinely contract derivatives, always with the appropriate levels of approval, only in the event of exposure that Management regards as arisk. The Company and its subsidiaries do not enter into transactions involving exotic or speculative derivatives.

F -87

 

( 35 )FINANCIAL INSTRUMENTS  

The main financial instruments, classified in accordance with the group’s accounting practices, are:

					December 31, 2014		December 31, 2013
	Note	Category	Measurement	Level (*)	Accounting balance	Fair value	Accounting balance	Fair value
Asset
Cash and cash equivalent	5	(a)	(2)	Level 1	2,593,650	2,593,650	2,105,618	2,105,618
Cash and cash equivalent	5	(a)	(2)	Level 2	1,763,805	1,763,805	2,100,804	2,100,804
Financial investments		(a)	(2)	Level 1	5,324	5,324	24,806	24,806
Derivatives	35	(a)	(2)	Level 2	608,176	608,176	318,490	318,490
Financial asset of concession - distribution	11	(b)	(2)	Level 3	3,296,837	3,296,837	2,771,593	2,771,593
					8,267,792	8,267,792	7,321,312	7,321,312
Liability
Loans and financing - principal and interest	17	(c)	(1)	Level 2	7,240,164	6,266,957	7,221,542	6,416,990
Loans and financing - principal and interest	17 (**)	(a)	(2)	Level 2	3,438,212	3,438,212	2,008,454	2,008,454
Debentures - Principal and interest	18	(c)	(1)	Level 2	8,471,583	7,997,074	7,791,402	7,859,140
Derivatives	35	(a)	(2)	Level 2	13,354	13,354	2,950	2,950
					19,163,313	17,715,598	17,024,348	16,287,534
(*) Refers to the hierarchy for determination of fair value
(**) As a result of the initial designation of this financial liability, the financial statements showed a gain of R$100,193 (R$ 51,238 in 2013).
Key
Category:	Measurement:
(a) - Measured at fair value through profit or loss	(1) - Measured at amortized cost
(b) - Available for sale	(2) - Mensured at fair value
(c) - Other finance liabilities

The financial instruments for which the recorded amounts approximate to their fair values at the date of these financial statements, due to the nature of these financial instruments, are:

��Financial assets: (i) consumers, concessionaires and licensees, (ii) leases, (iii) receivable from associates, subsidiaries and parent company, (iv) receivables from resources provided by CDE/CCEE, (v) financial asset of concession - transmission, (vi) pledges, funds and tied deposits, (vii) services rendered to third parties, (viii) Collection agreements, (ix) sector financial asset.

·Financial liabilities: (i) suppliers, (ii) regulatory charges, (iii) public utility, (iv) consumers and concessionaires, (v) Nacional scientific and technological development fund - FNDCT, (vi) energy research company - EPE, (vii) collection agreement, (viii) reversal fund, (ix) Business combination payable, (x) tariff discount CDE (xi) sector financial liability.

a) Valuation of financial instruments

As mentioned in note 4, the fair value of a security relates 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.

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);

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· Level 3: inputs for the instruments that are not based on observable market data.

Since the distribution subsidiaries have classified their financial asset of concession as available-for-sale, 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 net income was of R$ 104,642 (gain of R$ 66,851 in 2013 and gain of R$ 159,195 in 2012), and the main assumptions are disclosed in note 11.

The Company recognizes in “Investments at cost” in the financial statements the 5.94% interest held by the indirect subsidiary Paulista Lajeado Energia S.A. in the total capital of Investco S.A. (“Investco”), in the form of 28,154,140 common shares and 18,593,070 preferred shares. Investco’sshares 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.

b) Derivatives

The Company and its subsidiaries have the policy of using derivatives to reduce their risks of variations in exchange and interest rates, without any speculative purposes. The Company and its subsidiaries have exchange rate derivatives compatible with the exchange rate risks net exposure, including all the assets and liabilities tied to exchange rates.

The derivative instruments entered into 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 the majority of the derivatives entered into by the subsidiaries have their terms fully aligned with the debts protected (note 17), and in order to obtain more relevant and consistent accounting information through the recognition of income and expenses, these debts were designated at fair value, for accounting purposes. Other debts with different terms from their respective 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.

At December 31, 2014, the Company and its subsidiaries had the following swap operations:

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	Market values (accouting balance)
Company / strategy / counterparts	Assets	Liabilities	Fair value, net	Values at cost, net	Gain/(Loss) on marking to market	Currecy / index	Maturity range	Notional	Negotiation market
Derivatives for protection of debts designated at fair value
Exchange rate hedge
CPFL Paulista
Bank of America Merrill Lynch	110,899	-	110,899	105,758	5,142	dollar	July 2016	156,700	over the counter
Citibank	45,660	-	45,660	45,302	358	dollar	September 2016	85,750	over the counter
Morgan Stanley	45,844	-	45,844	45,561	282	dollar	September 2016	85,475	over the counter
Scotiabank	13,593	-	13,593	13,317	276	dollar	July 2016	49,000	over the counter
Bank of America Merrill Lynch	49,192	-	49,192	51,537	(2,344)	dollar	July 2016	340,380	over the counter
Citibank	12,628	-	12,628	14,786	(2,158)	dollar	March 2019	117,250	over the counter
Bank of Tokyo-Mitsubishi	11,489	-	11,489	14,795	(3,306)	dollar	March 2019	117,400	over the counter
Bank of America Merrill Lynch	13,108	-	13,108	13,396	(287)	dollar	September 2018	106,020	over the counter
Bank of America Merrill Lynch	15,636	-	15,636	16,117	(481)	dollar	March 2019	116,600	over the counter
J.P.Morgan	7,816	-	7,816	8,058	(242)	dollar	March 2019	58,300	over the counter
J.P.Morgan	73	-	73	1,353	(1,280)	dollar	December 2017	51,470	over the counter
J.P.Morgan	-	(1,482)	(1,482)	(140)	(1,343)	dollar	December 2017	53,100	over the counter
	325,939	(1,482)	324,457	329,840	(5,383)
CPFL Piratininga
Citibank	6,439	-	6,439	8,246	(1,807)	dollar	January 2017	151,875	over the counter
Citibank	8,103	-	8,103	8,081	22	dollar	August 2016	12,840	over the counter
Scotiabank	17,753	-	17,753	17,394	360	dollar	July 2016	64,000	over the counter
Santander	13,771	-	13,771	14,783	(1,012)	dollar	July 2016	100,000	over the counter
Citibank	12,628	-	12,628	14,786	(2,158)	dollar	March 2019	117,250	over the counter
HSBC	9,607	-	9,607	10,180	(573)	dollar	April 2018	55,138	over the counter
J.P.Morgan	9,646	-	9,646	10,182	(536)	dollar	April 2018	55,138	over the counter
	77,947	-	77,947	83,651	(5,703)
CPFL Santa Cruz
J.P.Morgan	4,869	-	4,869	4,805	64	dollar	July 2015	20,000	over the counter
Banco Santander	3,341	-	3,341	3,553	(212)	dollar	June 2016	20,000	over the counter
	8,210	-	8,210	8,358	(148)
CPFL Leste Paulista
Scotiabank	6,622	-	6,622	6,546	76	dollar	July 2015	25,000	over the counter
CPFL Sul Paulista
J.P.Morgan	2,556	-	2,556	2,522	34	dollar	July 2015	10,500	over the counter
Scotiabank	2,781	-	2,781	2,749	32	dollar	July 2015	10,500	over the counter
Santander	3,675	-	3,675	3,908	(233)	dollar	June 2016	22,000	over the counter
	9,013	-	9,013	9,180	(168)
CPFL Jaguari
Scotiabank	3,443	-	3,443	3,404	39	dollar	July 2015	13,000	over the counter
Santander	5,179	-	5,179	5,507	(328)	dollar	June 2016	31,000	over the counter
	8,622	-	8,622	8,911	(289)
CPFL Mococa
Scotiabank	2,914	-	2,914	2,880	33	dollar	July 2015	11,000	over the counter
CPFL Geração
HSBC	29,470	-	29,470	32,333	(2,863)	dollar	March 2017	232,520	over the counter
RGE
Citibank	53,250	-	53,250	55,096	(1,846)	dollar	April 2017	128,590	over the counter
J.P.Morgan	26,764	-	26,764	26,815	(50)	dollar	July 2016	94,410	over the counter
Bank of Tokyo-Mitsubishi	9,361	-	9,361	10,850	(1,489)	dollar	April 2018	36,270	over the counter
Bank of Tokyo-Mitsubishi	41,575	-	41,575	47,723	(6,148)	dollar	May 2018	168,346	over the counter
Citibank	5,358	-	5,358	6,182	(824)	dollar	May 2019	33,285	over the counter
HSBC	2,394	-	2,394	2,801	(407)	dollar	October 2017	32,715	over the counter
	138,702	-	138,702	149,466	(10,765)
CPFL Serviços
J.P.Morgan	664	-	664	830	(167)	dollar	October 2016	9,000	over the counter
CPFL Telecom
Itaú	74	-	74	81	(7)	dollar	November 2015	9,000	over the counter
Subtotal	608,176	(1,482)	606,693	632,076	(25,382)
Derivatives for protection of debts not designated at fair value
Exchange rate hedge
CPFL Geração
Votorantim	-	(1,040)	(1,040)	(196)	(844)	dollar	January 2015 to December 2016	57,424	over the counter
Price variation hedge
CPFL Geração
Santander	-	(535)	(535)	(64)	(472)	IPCA	April 2019	35,235	over the counter
J.P.Morgan	-	(535)	(535)	(64)	(472)	IPCA	April 2019	35,235	over the counter
	-	(1,071)	(1,071)	(128)	(943)
Hedge interest rate variation(1)
CPFL Paulista
Bank of America Merrill Lynch	-	(2,751)	(2,751)	(73)	(2,678)	CDI	July 2019	660,000	over the counter
J.P.Morgan	-	(1,328)	(1,328)	(19)	(1,309)	CDI	February 2021	300,000	over the counter
Votorantin	-	(415)	(415)	(4)	(412)	CDI	February 2021	100,000	over the counter
Santander	-	(431)	(431)	(3)	(428)	CDI	February 2021	105,000	over the counter
	-	(4,925)	(4,925)	(98)	(4,827)
CPFL Piratininga
J.P.Morgan	-	(458)	(458)	(12)	(446)	CDI	July 2019	110,000	over the counter
Votorantim	-	(492)	(492)	2	(494)	CDI	February 2021	135,000	over the counter
Santander	-	(351)	(351)	3	(354)	CDI	February 2021	100,000	over the counter
	-	(1,301)	(1,301)	(7)	(1,294)
RGE
HSBC	-	(2,084)	(2,084)	(55)	(2,029)	CDI	July 2019	500,000	over the counter
Votorantim	-	(784)	(784)	(14)	(770)	CDI	February 2021	170,000	over the counter
	-	(2,868)	(2,868)	(69)	(2,799)
CPFL Geração
Votorantim	-	(666)	(666)	79	(745)	CDI	August 2020	460,000	over the counter
Subtotal	-	(11,872)	(11,872)	(419)	(11,453)
Total	608,176	(13,354)	594,821	631,656	(36,835)
Current	23,260	(38)
Noncurrent	584,917	(13,317)
For further details of terms and information about debts and debentures, see notes 17 and 18.
(¹) The interest rate hedge swaps have half-yearly validity, so the notional value reduces in accordance with amortization of the debt.

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As mentioned above, certain subsidiaries opted to mark to market debts for which they have fully tied derivative instruments (note 17).

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 debts. For the years 2014, 2013 and 2012, the derivatives resulted in the following impacts on the result, which are accounted under monetary and exchange variations line in Financial Income and Expenses heading (see note 30):

			Gain (Loss)
Company	Hedged risk / transaction	2014	2013	2012
CPFL Energia	Interest rate variation	-	323	356
CPFL Energia	Mark to market	-	(469)	451
CPFL Paulista	Interest rate variation	1	933	-
CPFL Paulista	Exchange variation	96,017	150,500	60,219
CPFL Paulista	Mark to market	(21,297)	(38,759)	50,866
CPFL Piratininga	Interest rate variation	51	303	207
CPFL Piratininga	Exchange variation	35,808	61,673	20,949
CPFL Piratininga	Mark to market	(6,124)	(20,454)	19,711
RGE	Interest rate variation	(28)	798	498
RGE	Exchange variation	37,585	43,058	9,130
RGE	Mark to market	(7,170)	(11,380)	4,596
CPFL Geração	Interest rate variation	303	273	167
CPFL Geração	Exchange variation	21,650	18,428	8,261
CPFL Geração	Mark to market	(6,221)	(4,344)	5,676
CPFL Santa Cruz	Exchange variation	2,604	1,962	(789)
CPFL Santa Cruz	Mark to market	(115)	(486)	453
CPFL Leste Paulista	Exchange variation	1,453	3,435	(87)
CPFL Leste Paulista	Mark to market	(117)	(462)	653
CPFL Sul Paulista	Exchange variation	2,333	3,140	(226)
CPFL Sul Paulista	Mark to market	(163)	(658)	676
CPFL Jaguari	Exchange variation	2,146	2,398	138
CPFL Jaguari	Mark to market	(160)	(595)	454
CPFL Mococa	Exchange variation	427	1,966	130
CPFL Mococa	Mark to market	(70)	(301)	403
CPFL Serviços	Exchange variation	830	-	-
CPFL Serviços	Mark to market	(167)	-	-
CPFL Telecom	Exchange variation	81	-	-
CPFL Telecom	Mark to market	(6)	-	-
		159,653	211,282	182,892

c) Sensitivity Analysis

In compliance with IFRS 7, 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.

If the risk exposure is considered an asset, the risk to be taken into account is a reduction in the pegged indexes, resulting in a negative impact on the income of the Company and its subsidiaries.  Similarly, if the risk exposure is considered a liability, the risk is of an increase in the pegged indexes and the consequent negative effect on income.  The Company and its subsidiaries therefore quantify the risks in terms of the net exposure of the variables (dollar, CDI, IGP-M, IPCA and TJLP), as shown below:

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c.1) Exchange ratesvariation

Considering the level of net exchange rate exposure at December 31, 2014 is maintained, the simulation of the effects by type of financial instrument for three different scenarios would be:

	Exposure (R$ thousand)(1)	Risk	Exchange depreciation of 10,5% (*)	Exchange appreciation of 25,0% (**)	Exchange appreciation of 50,0% (**)
Financial liability instruments	(3,498,455)		(367,336)	599,111	1,565,559
Derivatives - plain vanilla swap	3,570,114		374,861	(611,383)	(1,597,627)
	71,659	Drop in the dollar	7,524	(12,272)	(32,067)
Total	71,659		7,524	(12,272)	(32,067)
(1) Exchange rate at December 31, 2014: R$ 2.66.
(*) As per foreign exchange rate curves obtained from information provided by the BM&F. The exchange rate considered was R$ 2.94.
(**) The percentage of exchange depreciation are related to the information provided by the BM&F. As the net exposure is an asset, the risk is of a drop in the dollar and the exchange rate is therefore appreciated by 25% and 50% in relation to the probable dollar.

c.2) Variation in interest rates

Assuming (i) the scenario of net exposure of the financial instruments indexed to variable interest rates at December 31, 2014 is maintained, and (ii) the respective accumulated annual indexes for 2014 remain stable (CDI 10.81% p.a.; IGP-M 3.69% p.a.; TJLP  5.00% p.a.; IPCA 6.41% p.a.), the effects on the Company’s 2014 financial statements would be a net financial expense of R$ 1,098,178 (CDI R$ 873,130, IGP-M R$ 2,738, TJLP R$ 222,015 and IPCA R$295). In the event of fluctuations in the indexes in accordance with the three scenarios described below, the effect on the net financial expense would as follows:

Instruments	Exposure (R$ thousand)	Risk	Scenario I (*)	Raising index by 25% (**)	Raising index by 50% (**)
Financial asset instruments	4,661,995		100,233	251,282	402,330
Financial liability instruments	(9,693,073)		(208,401)	(522,457)	(836,512)
Derivatives - plain vanilla swap	(3,045,980)		(65,489)	(164,178)	(262,868)
	(8,077,058)	CDI apprec.	(173,657)	(435,353)	(697,050)
Financial liability instruments	(74,197)	IGP-M apprec.	(1,684)	(2,790)	(3,895)
Financial liability instruments	(4,440,303)	TJLP apprec.	(22,202)	(83,256)	(144,310)
Financial liability instruments	(75,293)		(866)	(2,289)	(3,712)
Derivatives - plain vanilla swap	70,688	IPCA apprec.	813	2,149	3,485
	(4,605)		(53)	(140)	(227)
Total increase	(12,596,162)		(197,595)	(521,539)	(845,482)
(*) The CDI, IGP-M, TJLP and IPCA indexes considered of 12.96%, 5.96%, 5.5% and 7.56%, respectively, were obtained from information available in the market.
(**) The percentage of raising index were applied to Scenario I indexes.

d) Liquidity analysis

The Company manages liquidity risk by continuously monitoring forecast and actual cash flows, and by matching the maturity profiles of its financial liabilities. The table below sets out details of the contractual maturities of the financial liabilities as at December 31, 2014, taking into account principal and interest, and is based on the undiscounted cash flow, considering the earliest date on which the Company and its subsidiaries have to settle their respective obligations.

F -92

 

December 31, 2014	Note	Weighted average interest rates	Less than 1 month	1-3 months	3 months to 1 year	1-3 years	4-5 years	Over 5 years	Total
Suppliers	16		2,324,995	48,256	896	633	-	-	2,374,779
Loans and financing - principal and interest	17	9.68%	213,831	248,497	1,508,835	5,205,573	4,227,887	3,070,115	14,474,738
Derivatives	35		3	3	31	2,485	6,364	4,467	13,354
Debentures - principal and interest	18	12.49%	74,417	135,191	2,764,083	2,800,423	4,402,183	1,600,049	11,776,346
Regulatory charges	20		42,266	1,529	-	-	-	-	43,795
Public utility	23	15.56%	333	666	3,001	7,988	7,992	65,012	84,992
Other	24		16,295	127,507	70,419	16,152	-	17,750	248,123
Consumers and concessionaires			15,062	34,648	-	-	-	-	49,710
National scientific and technological development fund - FNDCT			822	647	-	-	-	-	1,469
Energy research company - EPE			410	323	-	-	-	-	734
Collections agreement			-	91,889	-	-	-	-	91,889
Fund for reversal			-	-	-	-	-	17,750	17,750
Business combination			-	-	70,419	16,152	-	-	86,571
Total			2,672,140	561,649	4,347,265	8,033,254	8,644,427	4,757,394	29,016,128

( 36 )COMMITTMENTS

The Company’s commitments in relation to long-term energy purchase agreements and plant construction projects are as of December 31, 2014, as follows:

Commitments at December 31, 2014	Duration	Up to 1 year	1 - 3 years	4 - 5 years	Over 5 years	TOTAL
Energy purchase contracts (except Itaipu)	Up to 35 years	8,874,761	16,997,483	17,317,122	59,696,884	102,886,250
Itaipu	Up to 30 years	1,687,268	3,544,257	3,526,339	16,558,434	25,316,299
Power plant constrution projets (a)	Up to 12 years	172,977	876,431	146	-	1,049,554
Material and services suppliers	Up to 19 years	1,262,405	806,401	68,558	169,359	2,306,723
TOTAL		11,997,412	22,224,572	20,912,165	76,424,677	131,558,826

(a)The power plant construction projects include commitments made basically to construction related to the subsidiaries in the renewable energy segment.

( 37 )NON CASH TRANSACTION

	December 31, 2014	December 31, 2013	December 31, 2012
Transactions resulting from business combinations
Loans, financing and debentures	(1,009,877)	-	(556,706)
Property, plant and eqiupment acquired through business combination	1,345,577	-	695,093
Intangible asset acquired in business combination, net of tax effects	562,453	-	514,644
Other net assets acquired through business combination	6,440	-	82,841
	904,593	-	735,872
Cash acquired in the business combination	(141,759)	-	(28,278)
Acquisition price payable	-	-	(1,408)
Transferred consideration by issuance of shares	(833,663)	-	-
(Cash acquired in business combination) / price paid in business combination net of cash acquired	(70,829)	-	706,186
Other transactions
Provision for socio-environmental costs capitalized in property, plant and equipment	-	-	33,528
Reversal of provisions for socio-environmental costs capitalized in property, plant and equipment	9,193	(17,747)	(66,773)
Interest capitalized in property, plant and equipment	4,225	48,328	32,527
Interest capitalized in intangible concessoin asset - distribution infrastructure	8,044	8,845	15,645
Financial asset of concession transfer and intangible to property, plant and equipment refered to spin-off of generation assets	5,828	-	-
Transfers between property, plant and equipment and other assets	16,430	18,896	-
Capital reserve realization against receivables	2,189	-	-

F -93

 

( 38 )RELEVANT FACT AND SUBSEQUENT EVENT

38.1 Annual Tariff Adjustment – CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa

On February 3, 2015, ANEEL published the Resolutions fixing the tariff adjustments of the subsidiaries of CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa as from that date. The details of the adjustments are shown below:

Distributor	Resolution n°	Annual Tariff Review - RTA	Effect perceived by consumers (*)
CPFL Santa Cruz	1,850	34.68%	27.96%
CPFL Leste Paulista	1,852	20.80%	24.89%
CPFL Jaguari	1,853	38.46%	45.70%
CPFL Sul Paulista	1,851	24.88%	28.38%
CPFL Mococa	1,849	23.34%	29.28%

(*) Information unaudited

38.2Loans and financing

CPFL Energia

A meetingof the Board of Directors held on January 29, 2015 approved fundraising, in the Company, amounting to R$ 1,000,000which funds will be used to extend the debt maturity.

Theamount of R$500,000had been released by thedatethese financialstatements were approved for one year maturity.

On February 24, 2015, the Company prepaid the 4^th debenture issue, the total balance including interests in December 31, 2014 was R$ 1,304,406.

CPFL Paulista, CPFL Piratininga and RGE

Investment

A meeting of the Board of Directors in December 2014 approved contracting financing from the BNDES and Banco Safra for: (i) the amount of R$ 427,716 for the subsidiary CPFL Paulista; (ii) the amount of R$ 194,862 for the subsidiary  CPFL Piratininga; and (iii) the amount of R$ 266,790 for the subsidiary RGE. These are part of a FINEM´s credit line to be used in the subsidiaries' investment plans. On March 25, 2015, the following amounts were released: (i) R$6,002 for CPFL Paulista; (ii) R$121,747 for CPFL Piratininga and (iii) R$117,250 for RGE.

Financial institutions

Between January 1 and the date on which these financial statements were approved, the following amounts were released in relation to the Law 4,131 debt: (i) R$ 1,199,974 to the subsidiary CPFL Paulista, (ii) R$ 345,551 to the subsidiary CPFL Piratininga; (iii) R$ 271,949 to the subsidiary RGE, with final maturities to 2020. The funds raised will be used to extend the indebtedness and improve the working capital of the subsidiaries.

F -94

 

CPFL Renováveis

In January 2015, the subsidiary Mata Velha Energética S.A. issued its 1st promissory notes, amounting to R$ 50,000 maturing in July 2015. The objective is to improve working capital.

38.3CPFL Transmissora Morro Agudo S.A.

The incorporation of CPFL Transmissora Morro Agudo S.A., a subsidiary of CPFL Geração, was approved in January 2015, with the objective of operating and exploiting electric energy transmission concessions, including construction, implementation, operation and maintenance of transmission facilities of the basic network of the Interlinked National System.

38.4EPASA – change in share interest

After the capital increase on January 31, 2014, described in Note 13.4, certain shareholders of the joint venture EPASA had their interest diluted. As per the actual Shareholders Agreement, these shareholders were entitled to repurchase shares in order to reconstitute their interests, and accordingly,  Eletricidade do Brasil S/A and OZ&M Incoporação e Participação Ltda. partially exercised this right until February 25, 2015, and bought 10,704,756 common shares from CPFL Geração, amounting R$ 10,455.  Since this corporate transaction, the breakdown of the shares of the joint venture EPASA is as follows:

	December 31, 2014		February 25, 2015
Shareholders	Shares	Interest %	Shares	Interest %
CPFL Geração de Energia S/A	161,646,415	57.13	150,941,659	53.34
Eletricidade do Brasil S/A	107,903,763	38.13	118,100,009	41.74
Aruanã Energia S/A	6,960,800	2.46	6,960,800	2.46
OZ&M Incorporação, Participação Ltda	6,450,767	2.28	6,959,277	2.46
Total	282,961,745	100.00	282,961,745	100.00

38.5Tariff flags

The Tariff Flag system was created by Normative Resolution nº 547/13, and came into effect on January 1, 2015. This mechanism may reflect the actual cost of the electric energy generation conditions in Brazil, particularly in relation to thermal generation, ESS related to energy security, hydrological risk and involuntary exposure of the electric energy distributors. The green flag indicates favorable conditions and the tariff is not increased. The yellow flag indicates less favorable conditions and the red flag is used in more costly conditions, with increases of R$ 1.50  and R$ 3.00, respectively, (pre-taxes on sales) for every 100 kWh consumed. These amounts were increased on March 2, 2015 by Homologation Resolution nº 1.859/15, effective from March 1, 2015, to R$ 2.50 and R$ 5.50, respectively.

Additionally, Decree 8401/15 created the Tariff Flags Resources Centralization Account, administered by the CCEE. The net amount of the expenses covered by the flags mechanism and the income billed by the distributors will be reversed to this account and vice versa.

F -95

 

38.6RTE

On February 27, 2015, ANEEL approved the result of the Extraordinary Tariff Review - RTE with the objective of re-establishing the tariff coverage of the electric energy distributors in view of the significant increase in the 2015 CDE quota and the cost of purchasing energy (tariff and exchange variations from Itaipu and auction of existing energy and adjustments). The tariffs resulting from this RTE will be effective from March 2, 2015 to the date of each distributor's next ordinary meeting. The impact for consumers in the distribution subsidiaries' concession areas are as follows:

	Effect perceived by consumers (*)
Distributor	Total	Group A	Group B
CPFL Paulista	31.77%	40.05%	27.27%
CPFL Piratininga	29.29%	40.49%	21.47%
RGE	35.47%	43.36%	33.04%
CPFL Santa Cruz	9.15%	10.53%	9.78%
CPFL Leste Paulista	19.09%	24.74%	17.55%
CPFL Jaguari	22.85%	25.01%	18.79%
CPFL Sul Paulista	21.29%	37.67%	13.86%
CPFL Mococa	16.25%	23.83%	13.97%

(*) Unaudited information

This tariff event was approved without detriment to the Annual Tariff Adjustment - RTA or Periodic Tariff Review - RTP in 2015, in accordance with the distributors' concession agreements.

38.7Share bonus for shareholders

Aiming to improve the Company's capital structure the Board of Directors approved on March 25, 2015 to propose to the Extraordinary General Meeting the capitalization of the balance of the statutory reserve - working capital improvement by issuing new shares to the shareholders. This proposal will be submitted for approval of the Extraordinary General Meeting called for April 29, 2015.

F -96

 

( 39 )CONDENSED UNCONSOLIDATED FINANCIAL STATEMENTS

Since the condensed unconsolidated financial information required by Rule 12-04 of Regulation S-X is not required under IFRS issued by the International Accounting Standards Board - IASB, such information was not included in the original financial statements filed with the Brazilian Securities and Exchange Commissions – CVM. In order to attend the specific requirements of the Securities and Exchange Commission (the “SEC”), Management has incorporated the condensed unconsolidated information in these financial statements as part of the Form 20-F.

The condensed unconsolidated financial information of CPFL Energia, as of December 31, 2014 and December 31, 2013 and for the years ended on December 31, 2014, 2013 and 2012 presented herein were prepared considering the same accounting policies as described in note 3 to Company’s consolidated financial statements.

UNCONSOLIDATED BALANCE SHEETS

ASSETS	December 31, 2014	December 31, 2013
Cash and cash equivalents	799,775	990,672
Dividends and Interest on Equity	942,367	697,702
Other credits	50,047	31,858
Total current assets	1,792,189	1,720,232
Deferred Tax Credits	150,628	165,798
Investment	6,290,998	6,419,924
Other credits	84,472	83,857
Total non current assets	6,526,098	6,669,579
Total assets	8,318,287	8,389,811

LIABILITIES AND SHAREHOLDERS' EQUITY	December 31, 2014	December 31, 2013
Accrued interest on debentures	15,020	12,438
Debentures	1,289,386	-
Dividends and Interest on Equity	13,555	15,407
Other accounts payable	20,527	18,400
Total current liabilities	1,338,488	46,246
Debentures	-	1,287,912
Reserve for tax, civil and labor risks	725	260
Other accounts payable	35,540	29,358
Total non current liabilities	36,264	1,319,667
Shareholders' equity	6,943,535	7,023,899
Total liabilities and shareholders' equity	8,318,287	8,389,811

F -97

 

UNCONSOLIDATED STATEMENTS OF INCOME

	2014	2013	2012
NET OPERATING REVENUE	61	1,649	1,452
General and administrative expenses and other	(26,175)	(22,626)	(29,585)
Income from electric energy service	(26,114)	(20,977)	(28,134)
Interest in subsidiaries	1,011,185	1,022,779	1,281,414
Financial income/(expense)	(25,464)	(26,860)	(22,084)
Income before taxes	959,607	974,942	1,231,197
Social contribution and Income tax	(10,430)	(37,523)	(54,945)
Net Income	949,177	937,419	1,176,252
	2014	2013	2012
Net Income	949,177	937,419	1,176,252
Items that will not be reclassified subsequently to profit or loss:
Equity on comprehensive income of subsidiaries	(225,720)	460,226	(572,225)
Comprehensive income for the year	723,457	1,397,645	604,027

UNCONSOLIDATED STATEMENTS OF CASH FLOWS

OPERATING CASH FLOW	2014	2013	2012
Income before taxes	959,607	974,942	1,231,197
Adjustment to reconcile income to cash provided by operating activities
Interest in subsidiaries	(1,011,185)	(1,022,779)	(1,281,414)
Depreciation and amortization	173	76	65
Interest and monetary adjustment	142,278	81,189	30,028
Other	640	267	7
Changes in operating assets and liabilities
Dividends and Interest on Equity received	1,248,982	792,146	1,199,996
Recoverable taxes	1,564	21,797	47,539
Other operating assets and liabilities	3,904	(1,990)	8,820
Cash Flows provided by operations	1,345,963	845,648	1,236,238
Payments of interest on debts	(138,599)	(76,561)	(45,080)
Payment of taxes and social contributions	(21,463)	(27,551)	(39,976)
Net cash from operating activities	1,185,901	741,536	1,151,182
Investing activities
Capital increase in subsidiaries	(360,000)	(1,563)	(66,701)
Financial investments, pledges, funds and tied deposits	-	4,710	49,263
Increment of cash due to increase of interest in subsidiary	(27,153)	(59,342)	(55)
Other	(2,835)	(8,635)	2,291
Net cash from used in investing activities	(389,988)	(64,830)	(15,202)
Financing activities
Loans, financing and debentures obtained	-	1,287,180	-
Payments of loans, financing and debentures, net of derivatives	-	(299,535)	(149,827)
Payments of dividend and interest on shareholders’ equity	(986,811)	(815,514)	(1,393,507)
Net cash from provide by (used in) financing activities	(986,811)	172,131	(1,543,334)
(Decrease)/increase in cash and cash equivalents	(190,898)	848,837	(407,354)
Opening balance of cash and cash equivalents	990,672	141,835	549,189
Closing balance of cash and cash equivalents	799,775	990,672	141,835

F -98

 

Following is the information relating to CPFL Energia's unconsolidated condensed financial statements presented above:

a.Cash and cash equivalents:

	December 31, 2014	December 31, 2013
Bank balances	628	936
Investment funds	799,147	989,737
Total	799,775	990,672

Amounts invested in an Investment funds, involving investments subject to floating rates tied to the CDI in federal government bonds, CDBs, secured debentures of major financial institutions, with daily liquidity, low credit risk and interest equivalent, on average, to 101% of CDI.

b.Dividends and interest on equity:

	Dividends		Interest on Shareholders´ Equity		Total
Subsidiaries	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013
CPFL Paulista	755,625	389,872	10,570	34,879	766,195	424,751
CPFL Piratininga	-	117,816	-	11,267	-	129,083
CPFL Santa Cruz	14,000	19,764	-	3,916	14,000	23,681
CPFL Leste Paulista	-	10,323	-	940	-	11,263
CPFL Sul Paulista	-	21,095	-	2,165	-	23,260
CPFL Jaguari	-	11,422	-	723	-	12,145
CPFL Mococa	-	15,919	-	1,166	-	17,085
RGE	82,117	-	50,077	25,039	132,194	25,039
CPFL Jaguari Geração	4,039	4,709	-	-	4,039	4,709
CPFL Planalto	-	5,101	-	-	-	5,101
CPFL Serviços	17,182	9,080	4,583	1,601	21,765	10,681
CPFL Atende	-	1,389	-	624	-	2,013
Nect Serviços	3,793	7,696	-	-	3,793	7,696
CPFL Total	380	792	-	404	380	1,196
	877,136	614,978	65,231	82,725	942,367	697,702

c.Other credits:

	Current		Noncurrent
	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013
Recoverable taxes	49,071	29,874	-	-
Due from relative parties	-	-	12,089	8,948
Escrow deposits	-	-	546	92
Advance for future capital increase	-	-	55,157	59,397
Loans and financing guarantee’s subsidiaries	-	-	15,818	14,389
Other	976	1,984	861	1,032
Total	50,047	31,858	84,471	83,857

On December 31, 2014, the advance to future capital increase refers to the subsidiaries: (i) CPFL Paulista (R$ 12,493); (ii) CPFL Piratininga (R$ 15,511); (iii) CPFL Jaguariuna (R$ 110) and (iv) CPFL Telecom (R$ 27,043). On December 31, 2013, the advance for a future capital increase was related to the subsidiaries: (i) CPFL Piratininga (R$ 50,000); (ii) CPFL Telecom (R$ 9,357) and (iii) CPFL Jaguariúna (R$40).

F -99

 

d.Deferred tax credits

	December 31, 2014	December 31, 2013
Social contribution credit/(debit)
Tax losses carryforwards	41,133	41,245
Deductible temporary differences	348	511
Subtotal	41,481	41,756
Income tax credit / (debit)
Tax losses carryforwards	108,182	123,429
Deductible temporary differences	966	612
Subtotal	109,148	124,042
Total	150,628	165,798
Total tax credit	150,628	165,798

e.Investment:

The financial information of subsidiaries, joint ventures and of the associates are accounted for using the equity method of accounting.

		Investment Shareholders Equity Interest		Equity in Subsidiaries
Subsidiaries	Number of shares (thousand)	December 31, 2014	December 31, 2013	2014	2013	2012
CPFL Paulista	177,909	728,213	1,186,113	502,719	620,412	423,757
CPFL Piratininga	53,031,259	479,686	384,609	187,715	82,985	142,535
CPFL Santa Cruz	371,772	132,353	100,369	49,052	(143)	24,182
CPFL Leste Paulista	895,733	38,066	60,578	7,173	6,826	9,646
CPFL Sul Paulista	463,482	44,375	51,432	11,351	6,743	19,622
CPFL Jaguari	212,126	25,627	23,261	2,027	(6,631)	10,694
CPFL Mococa	121,761	26,260	34,145	10,248	15,482	7,100
RGE	807,168	1,300,685	1,254,557	177,672	126,851	320,757
CPFL Geração	205,487,716	2,035,286	2,116,833	16,499	239,561	318,149
CPFL Jaguari Geração (*)	40,108	34,685	48,356	(4,657)	8,962	10,185
CPFL Brasil	2,999	65,508	35,246	136,876	36,426	105,627
CPFL Planalto (*)	630	1,633	(115)	2,238	(702)	5,058
CPFL Serviços	66,620	23,013	77,078	5,719	7,445	9,140
CPFL Atende (*)	1	17,496	13,746	6,849	624	2,775
Nect (*)	2,059	9,458	5,999	10,812	5,796	5,750
CPFL Total (*)	19,005	24,417	20,893	10,327	3,226	2,683
CPFL Jaguariuna (*)	189,620	2,553	2,512	1	325	209
CPFL Telecom	19,900	(293)	(1,311)	(8,339)	(1,313)	(3)
CPFL Centrais Geradoras	14,976	22,439	16,041	4,720	1,065	-
CPFL ESCO (a)	10	409,385	10	1,602	-	-

Subtotal - by shareholders' equity of the subsidiary	5,420,845	5,430,352	1,130,604	1,153,940	1,417,867
Intangible asset of concession	870,152	989,572		-	-
Amortization of intangible assets of the concession	-	-	(119,419)	(131,161)	(136,453)
Total	6,290,998	6,419,924	1,011,185	1,022,779	1,281,414
(*) Number of quotes
(a) Former CPFL Participações until October 27, 2014.

F -100

 

Dividends received — The net cash provided by operating activities is comprised mainly by dividends received from the Company’s subsidiaries. Of the amounts recorded as receivables, R$ 1,248,982 was paid to the Company by the subsidiaries.  The dividends received are comprised as follows:

	2014	2013	2012
CPFL Paulista	424,751	-	305,920
CPFL Piratininga	246,693	-	116,634
CPFL Santa Cruz	26,007	-	15,936
CPFL Leste Paulista	39,587	-	10,738
CPFL Sul Paulista	39,883	-	16,681
CPFL Jaguari	10,752	-	17,586
CPFL Mococa	32,881	-	6,131
RGE	-	151,184	362,471
CPFL Geração	278,653	523,424	250,066
CPFL Brasil	106,464	109,530	73,409
CPFL Jaguari Geração	9,683	4,000	9,991
CPFL Planalto	5,591	-	7,595
CPFL Serviços	-	-	3,648
CPFL Atende	5,006	1,459	337
Chumpitaz	-	-	1,710
CPFL Total	7,999	2,549	1,143
Nect	11,256	-	-
Centrais Geradoras	3,776	-	-
TOTAL	1,248,982	792,146	1,199,996

Restriction of transfer of funds from subsidiaries - CPFL Paulista, CPFL Piratininga, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa, CPFL Jaguari, RGE, CPFL Geração, ENERCAN, CERAN, BAESA and Foz do Chapecó qualify as concessionaires.As such, any transfer of funds to the respective parent company, in the form of loans or advances, requires approval by ANEEL. This regulatory restriction does not apply to cash dividends determined in accordance with the Brazilian corporate law.

As described in note 17, CPFL Paulista, CPFL Piratininga, RGE, CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, and CERAN have restrictions relating to the payment of dividends, due to the debt covenants. In addition the joint ventures ENERCAN, BASEA, FOZ do Chapecó and EPASA also have restriction analogous to those described in note 13.2.

f.Accrued interest on debentures and debentures:

		December 31, 2014				December 31, 2013
		Interest	Current	Noncurrent	Total	Interest	Current	Noncurrent	Total
4th Issue	Single series	15,020	1,289,386	-	1,304,406	12,438	-	1,287,912	1,300,350

F -101

 

		Issued	Annual Remuneration	Annual Effective rate	Amortization Conditions	Collateral
4th Issue	Single series	129,000	CDI + 0.40%	CDI + 0.51%	1 installment in May 2015	Unsecured

As described in note 38.2, on February 24, 2015, the Company prepaid the 4^th debenture issue.

g.Other accounts payable:

The mainly account to pay that the Company has in non-current is due to loans and financing guarantee’s subsidiaries.

*************

F -102