UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, 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, 2015Commission 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, 1510, 14th floor ‐ Suite 142CEP 04547‐005 Vila Olímpia ‐ São Paulo, São PauloFederative Republic of Brazil+55 11 3841‐8507(Address of principal executive offices) Gustavo Estrella+55 19 3756 8704 – gustavoestrella@cpfl.com.brRodovia Engenheiro Miguel Noel Nascentes Burnier, 1,755, km 2,5 – Parque São Quirino – Campinas, São Paulo ‐ 13088 140Federative Republic of Brazil(Name, telephone, e‐mail and/or facsimilenumber 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 whichregistered: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, 2015, there were 993,014,215 common shares, without par value, outstanding


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Indicate by check mark if the registrant is a well‐known seasoned issuer, as defined in Rule 405 of the Securities Act. YesxNo ̈ 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 ̈Nox 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. YesxNo ̈ 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/Ax 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 FilerxAccelerated 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 ̈IFRSxOther ̈ 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 ̈Nox


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Table of Contents Page Contents FORWARD‐LOOKING STATEMENTS

   1CERTAIN TERMS AND CONVENTIONS

   1PRESENTATION OF FINANCIAL INFORMATION

   2ITEM 1.

   Identity of Directors, Senior Management and Advisers

   2ITEM 2.

   Offer Statistics and Expected Timetable

   2ITEM 3.

   Key Information

   2ITEM 4.

   Information on the Company

   17ITEM 4A.

   Unresolved Staff Comments

   66ITEM 5.

   Operating and Financial Review and Prospects

   66ITEM 6.

   Directors, Senior Management and Employees

   102ITEM 7.

   Major Shareholders and Related Party Transactions

   112ITEM 8.

   Financial Information.

   117ITEM 9.

   The Offer and Listing

   119ITEM 10.

   Additional Information

   122ITEM 11.

   Quantitative and Qualitative Disclosures About Market Risk

   141ITEM 12.

   Description of Securities Other than Equity Securities

   142ITEM 13.

   Defaults, Dividend Arrearages and Delinquencies

   143ITEM 14.

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

   143ITEM 15.

   Controls and Procedures

   143ITEM 16A.

   Audit Committee Financial Expert

   145ITEM 16B.

   Code of Ethics

   145ITEM 16C.

   Principal Accountant Fees and Services

   146ITEM 16D.

   Exemptions from the Listing Standards for Audit Committees

   146ITEM 16E.

   Purchases of Equity Securities by the Issuer and Affiliated Purchasers

   147ITEM 16F.

   Change in Registrant’s Certifying Accountant

   147ITEM 16G.

   Corporate Governance

   147ITEM 16H.

   Mine Safety Disclosure

   148 ****  i


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ITEM 17.

   Financial Statements

   148ITEM 18.

   Financial Statements

   148ITEM 19.

   Exhibits

   149GLOSSARY OF TERMS

   150SIGNATURES

   154
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Table of Contents
 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”, “plan”, “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 regulatory, corporate, 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; ·interest rate fluctuation, inflation and exchange rate variation; ·actions taken by our major shareholders; ·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 150.


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Table of Contents
 PRESENTATION OF FINANCIAL AND OTHER INFORMATION Unless the context otherwise requires, all references herein to “we,” “us” or “our company” are references to CPFL Energia S.A., its consolidated subsidiaries and jointly controlled entities. All references herein to "real", "reais" or "R$" are to the Brazilianreal, the official currency of Brazil. All references to "U.S. dollars", "dollar" or "US$" are to U.S. dollars, the official currency of the United States. 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”).  Certain figures included in this annual report have been rounded; accordingly, figures shown as totals in certain tables may not be an exact arithmetic aggregation of the figures that precede them. 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, 2015, 2014, 2013, 2012, and 2011.  Our financial data as of December 31, 2015 and 2014 and for each of the three years in the period ended December 31, 2015 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 audited annual consolidated financial statements and the related notes included in this annual report.  Our financial data as of December 31, 2013, 2012 and 2011 and for each of the two years ended December 31, 2012 was derived from our audited annual consolidated financial statements that are not included in this annual report. The following tables present our selected financial data as of and for each of the periods indicated.


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Table of Contents
 STATEMENT OF OPERATIONS DATA For the year ended December 31,2015(4)

   2015

   2014

   2013

   2012(5)

   2011(5)US$

   R$

   R$

   R$

   R$

   R$(in millions, except per share and per ADS data)Net operating revenue

   5,175

   20,206

   17,306

   14,634

   14,891

   12,674Cost of electric energy services:Cost of electric energy

   3,409

   13,312

   10,643

   8,197

   8,253

   6,668Operating cost

   488

   1,907

   1,672

   1,468

   1,378

   1,070Services rendered to third parties

   269

   1,049

   946

   1,010

   1,356

   1,138Gross operating income

   1,008

   3,938

   4,044

   3,960

   3,904

   3,798Operating expenses:Sales expenses

   119

   465

   403

   377

   468

   364General and administrative expenses

   221

   864

   774

   929

   724

   595Other operating expense

   92

   357

   328

   285

   377

   213Income from electric energy service

   577

   2,252

   2,540

   2,370

   2,335

   2,625Interest in associates and joint ventures

   57

   217

   60

   121

   121

   82Financial income (expense):Income

   399

   1,558

   890

   699

   707

   753Expense

   (659)

   (2,573)

   (1,980)

   (1,671)

   (1,285)

   (1,156)Net financial income (expenses)

   (260)

   (1,015)

   (1,089)

   (971)

   (578)

   (403)Income before taxes

   372

   1,454

   1,511

   1,519

   1,878

   2,304Social contribution

   (41)

   (160)

   (169)

   (157)

   (178)

   (204)Income tax

   (107)

   (419)

   (455)

   (413)

   (493)

   (555)Total taxes

   (148)

   (579)

   (624)

   (570)

   (671)

   (759)Net income

   224

   875

   886

   949

   1,207

   1,545Net income attributable to controlling shareholders

   222

   865

   949

   937

   1,176

   1,493Net income (loss) attributable to non‐controlling shareholders

   3

   10

   (63)

   12

   31

   52Earnings per share attributable to controlling shareholders(1)(2):Basic

   0.22

   0.87

   0.96

   0.94

   1.18

   1.50Diluted

   0.22

   0.85

   0.94

   0.92

   1.17

   1.50Net income per ADS(1):Basic

   0.45

   1.74

   1.92

   1.88

   2.36

   3.00Diluted

   0.44

   1.70

   1.88

   1.84

   2.34

   3.00Dividends(3)

   53

   205

   977

   931

   1,096

   1,506Weighted average of number of common shares (in millions)(2)

   993

   993

   993

   993

   993

   993Dividends per share(1)(2)(3)

   0.05

   0.21

   0.98

   0.94

   1.10

   1.52Dividends per ADS(3)

   0.11

   0.41

   1.97

   1.88

   2.21

   3.03
  
 (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, 2011. (2) Considers the event occurred on April 29, 2015, related to the capital increase through the issuance of 30,739,955 shares. In accordance with IAS 33, when there is an increase in the number of shares without an increase in issued capital, the number of shares is adjusted


retrospectively for all prior periods presented. For more information see notes 25.1 and 26 of our audited consolidated financial statements for the year ended December 31, 2015.  
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Table of Contents
 (3) “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. (4) 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, 2015 of R$3.905 to US$1.00.  The Brazilianrealdevalued significantly against the U.S. dollar during 2015, however, from R$2.656 to US$1.00 as of December 31, 2014.  The average of the month-end commercial selling rates during the year 2015 was R$3.339 to US$1.00.  See “—Exchange Rates” below for more information regarding thereal/U.S. dollar exchange rate. (5) 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 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 currently record an amount for “net interest”.  With respect to IFRS 11 – Joint Arrangements, the results of the 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”) joint ventures are recognized using the equity method of accounting in 2015, 2014, 2013, 2012 and 2011.  
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Table of Contents
 BALANCE SHEET DATA For the year ended December 31,2015(2)

   2015

   2014(3)

   2013

   2012(4)

   2011(4)US$

   R$

   R$

   R$

   R$

   R$(in millions)Current assets:Cash and cash equivalents

   1,455

   5,683

   4,357

   4,206

   2,435

   2,663Consumers, concessionaires and licensees

   813

   3,175

   2,251

   2,008

   2,205

   1,861Derivatives

   161

   627

   23

   2

   1

   4Sector financial assets

   375

   1,464

   611

   -

   -

   -Other current assets

   399

   1,559

   1,972

   1,048

   904

   795Total current assets

   3,203

   12,509

   9,215

   7,264

   5,545

   5,323Noncurrent assets:Accounts receivable

   33

   129

   123

   154

   162

   182Derivatives

   423

   1,651

   585

   317

   486

   216Sector financial assets

   125

   490

   322

   -

   -

   -Financial asset of concession

   921

   3,597

   2,835

   2,787

   2,343

   1,377Investments in joint-ventures

   320

   1,248

   1,099

   1,033

   1,022

   1,006Property, plant and equipment

   2,349

   9,173

   9,149

   7,717

   7,104

   5,673Intangible Assets

   2,359

   9,210

   8,930

   8,748

   9,180

   8,535Other noncurrent assets

   647

   2,525

   2,887

   3,022

   3,082

   2,857Total noncurrent assets

   7,177

   28,024

   25,930

   23,778

   23,379

   19,846Total assets

   10,380

   40,532

   35,144

   31,043

   28,294

   25,169Current liabilities:Short‐term debt(1)

   932

   3,640

   3,526

   1,837

   1,962

   1,496Other current liabilities

   1,507

   5,885

   3,891

   3,068

   3,007

   2,819Total current liabilities

   2,439

   9,525

   7,417

   4,906

   4,969

   4,315Noncurrent liabilities:Long‐term debt(1)

   4,634

   18,093

   15,637

   15,184

   13,511

   10,317Other long‐term liabilities

   713

   2,785

   2,693

   2,155

   2,553

   1,879Noncurrent liabilities

   5,347

   20,877

   18,330

   17,339

   16,064

   12,196Non-controlling interest

   629

   2,456

   2,454

   1,775

   1,510

   1,485Net equity attributable to controlling shareholders

   1,965

   7,674

   6,944

   7,024

   6,381

   7,173Total liabilities and shareholders’ equity

   10,380

   40,532

   35,144

   31,043

   28,294

   25,169
  
 (1) Short‐term debt and long‐term debt include loans and financing, debentures, accrued interest on loans, financing and debentures and derivatives. (2) 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, 2015 of R$3.905 to US$1.00. (3) Data for 2014 have been restated due the completion of the accounting for the purchase price allocation related to acquisition of Dobrevê Energia S.A. - (“DESA”), as stated in note 15.4.2 of our audited consolidated financial statements for the year ended December 31, 2015. (4) 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 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 currently record an amount for “net interest”.  With respect to IFRS 11 – Joint Arrangements, the results of the 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”) joint ventures are recognized using the equity method of accounting in 2015, 2014, 2013, 2012 and 2011.   
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 OPERATING DATA For the year ended December 31,2015

   2014

   2013

   2012(3)

   2011(3)Energy sold (in GWh):Residential

   16,164

   16,501

   15,426

   14,567

   13,626Industrial

   12,748

   14,144

   14,691

   14,536

   14,718Commercial

   9,259

   9,437

   8,837

   8,714

   8,140Rural

   2,152

   2,326

   2,081

   2,093

   1,991Public administration

   1,278

   1,295

   1,234

   1,220

   1,154Public lighting

   1,649

   1,622

   1,586

   1,525

   1,495Public services

   1,797

   1,861

   1,820

   1,864

   1,823Own consumption

   33

   34

   34

   33

   33Total energy sold to Final Consumers

   45,082

   47,221

   45,709

   44,552

   42,979Electricity sales to wholesalers (in GWh)

   17,971

   14,988

   14,975

   14,429

   12,271Total consumers (in thousands)(1)

   7,751

   7,585

   7,386

   7,176

   6,952Installed Capacity (in MW)

   3,164

   3,162

   2,988

   2,961

   2,644Assured Energy (in GWh)(2)

   13,550

   13,566

   12,758

   12,742

   11,678Energy generated (in GWh)

   17,066

   13,658

   11,427

   10,570

   9,638
  
 (1) Represents active consumers (meaning consumers who are connected to the Distribution Network), rather than consumers invoiced at period‐end. (2) 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”. (3) 2012 and 2011 volume information was restated for purposes of comparison of operational and financial information, due to the adoption of IFRS 11 – Joint Arrangements.  Convenience Translations into U.S. Dollars Solely for the investor’s convenience, we have translated certain amounts included in this annual report fromreaisinto 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, 2015 of R$3.905 to US$1.00.  The translated amounts have been rounded.  These translations should not be considered as a representation that any such amounts have been, could have been or could be converted into U.S. dollars at that or at any other exchange rate, as of those dates or any other date.  In addition, the translations should not be construed as a representation that the amounts translated into U.S. dollars are in accordance with generally accepted accounting principles.  See “—Exchange Rates” below for more information regarding thereal/U.S. dollar exchange rate. Exchange Rates The Brazilian Central Bank allows thereal/U.S. dollar exchange rate to float freely, and it has intervened occasionally to control unstable movements in foreign exchange rates.  We cannot predict whether the Brazilian Central Bank or the Brazilian government will continue to let therealfloat freely or will intervene in the exchange rate market through a currency band system or otherwise.  Therealmay substantially depreciate or appreciate against the U.S. dollar.  For more information on these risks, see “Item 10.  Additional Information—Risk Factors—Risks Relating to Brazil”. The following table provides information on the selling exchange rate, expressed inreaisper U.S. dollar (R$/US$), for the periods indicated. Year‐end

   Average for period(1)

   Low

   High(reaisper U.S. dollar)Year ended:December 31, 2011

   1.876

   1.671

   1.535

   1.902December 31, 2012

   2.044

   1.958

   1.702

   2.112December 31, 2013

   2.343

   2.174

   1.953

   2.446December 31, 2014

   2.656

   2.360

   2.197

   2.740December 31, 2015

   3.905

   3.339

   2.575

   4.195
 
 (1) Average for period represents the average of the month‐end selling exchange rates during the relevant period. 6


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Table of Contents
 Month‐end

   Average for period(1)

   Low

   High(reaisper U.S. dollar)Month ended:October 2015

   3.859

   3.880

   3.739

   4.001November 2015

   3.851

   3.777

   3.701

   3.851December 2015

   3.905

   3.871

   3.748

   3.983January 2016

   4.043

   4.052

   3.986

   4.156February 2016

   3.980

   3.974

   3.865

   4.049March 2016

   3.559

   3.704

   3.559

   3.991April 2016 (through April 11)

   3.528

   3.623

   3.528

   3.692
  
 (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. 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 20 to 35 years.  The Brazilian  
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 Federal constitution requires all concessions relating to public services to 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, financial and other relevant standards, and provided 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, Law No. 9,074/95, Decree No. 7,805/12, Law No.12,783/13, Decree No. 8,461/15 and under concession contracts regarding renewal of concessions. Furthermore, we may alsobe subject to new regulations enacted by the Brazilian government that could retroactively affect the rules for renewal of our concessions and authorizations. The distribution concessions held by our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista were originally granted in 1999 for a sixteen‐year term and have recently been extended to July 2045.  The extensions were granted under the new laws and regulations regarding distribution concessions, so the concessions are now subject to the new targets and standards established by the Brazilian authorities.  There is as yet no precedent regarding how the authorities will act under these new laws and regulations, which include certain variables that are beyond our control and which may therefore impair our ability to fully achieve the relevant goals.  If we do not achieve the applicable goals, our distribution concessions and, therefore, our revenues could be adversely affected.  See “Item 4—Information on the Company— Concessions, Permissions and Authorizations —Concessions”. 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 that our distribution companies charge our consumers.  Our tariffs are determined under 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 allows for 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 the electricity we purchase and certain regulatory charges, including charges for the use of transmission and distribution facilities.  ANEEL generally carries out the RTP periodic tariff revision every four or five years (according to the terms of each concession agreement).  The objective of this periodic revision is to share gains with consumers and incentivize concessionaires to increase efficiency levels.   As such, it aims to identify variations in our costs and set a factor based on our operational efficiency that will be applied against the index of our ongoing annual tariff adjustments.  Extraordinary revisions of our tariffs may occur at any time, or may be requested by us.  Extraordinary revisions may have a negative effect on our results of operations or financial position, or may serve to offset unpredictable costs (such as taxes that significantly change our cost structure).  In addition, ANEEL currently reviews the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis, whereas previously all methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014. We cannot predict whether ANEEL will establish tariffs or methodologies that are favorable to us.See “Item 5.  Operating and Financial Review and Prospects—Background—Periodic Revisions—RTP”. We may not be able to comply with the terms of our concession agreements, authorizations and permissions, which could result in fines, other penalties and, depending on the gravity of the non‐compliance, in our concessions or authorizations being terminated. ANEEL may impose penalties on us in the event that we fail to comply with any provision of our concession agreements, authorizations and permissions.  Depending on the gravity of the non‐compliance, these penalties could include the following: ·warning notices;   8


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 ·fines per breach of up to 2.0% of the annual revenues generated by the relevant concession or authorization, or (if the relevant concession or authorization is non-operational) up to 2.0% of the estimated value of the energy that would have been produced for the twelve months prior to the breach; ·injunctions related to construction activities; ·restrictions on the operation of existing facilities and equipment; ·requiring the concessionaire’s controlling shareholders to carry out further capital expenditures (not applicable to authorizations); ·intervention by ANEEL in the management of the concessionaire; and ·termination of the concession or authorization. In addition, the Brazilian government may terminate any of our concessions agreements, authorizations and permissions by means of expropriation if it deems this to be the public interest. We are currently in compliance with all of the material terms of our concession agreements, authorizations and permissions. However, we cannot assure you that we will not be penalized by ANEEL for breaching our concession agreements or authorizations or that our concessions or authorizations will not be terminated in the future.  The compensation to which we are entitled upon expiration or early termination of our concessions or authorizations may not be sufficient for us to realize the full value of certain assets.  In addition, if any of our concession agreements or authorizations 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 or authorizations 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 through the cost of up to 105% of this electricity to consumers.  Over or under forecasting demand can have adverse consequences.  If we incorrectly forecast demand and we purchase less or more electricity than we need in a manner for which we are considered liable under applicable regulation, we may be prevented from passing through the costs of our electricity purchases in full to consumers, and we may also be forced to enter into the spot market to purchase electricity at prices substantially higher than under our long term purchase agreements (or sell it at prices substantially lower than under our concessions and authorizations).  For instance, the New Industry Model Law provides, among other restrictions, that if our forecast demand falls significantly short of actual electricity demand, we may be forced to make up the shortfall by purchasing in the spot market.  On the other hand, our forecast electricity demand may subsequently prove to be excessive if, for example, a significant portion of our Potential Free Consumers migrate and purchase electricity in the Free Market. 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” and “Item 4.  Information on the Company–Distribution–Purchases of Electricity”. We may not be able to buy electricity in the amount we need to meet our sales agreements in the Free Market, which may expose us to the spot market at prices substantially higher than under our long term agreements. On August 2, 2012, the Brazilian Ministry of Mines and Energy (MME) enacted Act. No. 455, which prohibitedex postadjustments to energy volume as of June 1, 2014 and required participants in the Free Market (although not Distributors) to register their expected consumption volume in advance with the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica), or CCEE, except in cases where they


specifically indicate that the agreement concerned is linked to the effective consumption volume.  However, the Brazilian Association of Electricity Traders (or ABRACEEL) obtained an injunction preventing implementation of the rule requiring advance registration of volume requirements under Act 455/2012.  As a result, Act 455/2012 has been suspended for all CCEE participants (Generators, Traders and Free Consumers), since it may not be applied selectively to a specific group.  If the injunction is lifted, and if our projected energy volume proves incorrect so that we purchase less or more electricity than we need in the Free Market, 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”.   9


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 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.  In 2015, according to data from the National Electrical System Operator (Operador Nacional do Sistema Elétrico), or ONS, approximately 71% of Brazil’s electricity supply came from Hydroelectric Power Plants. Brazil is subject to unpredictable hydrological conditions, with non‐cyclical deviations from average rainfall.  When hydrological conditions are poor, the ONS may dispatch Thermoelectric Power Plants, including those that we operate, to top up hydroelectric generation and maintain security levels in reservoirs and the electricity supply level in cases when the Hydroelectric Power Plants in Brazil, including those we operate, are unable to generate sufficient energy to honor their Assured Energy requirement in the Energy Reallocation Mechanism (Mecanismo de Realocação de Energia), or MRE.  This deficit of hydroelectric energy, referred to as called the Generation Scaling Factor, or GSF, therefore exposes operators of Hydroelectric Power Plants to spot price risk.  The GSF was activated in 2014 and 2015, requiring us to purchase energy from Thermoelectric Power Plants and leading to adverse results in our Generation segment.  Under Federal Law 13,203 of December 8, 2015, we have effectively capped our exposure to this risk for the life of our existing PPAs, and have covered the cash outlay from January 2015 to July 2020 through the GSF payment we made in 2015 regarding the electricity required to serve our consumers in the Regulated Market.  We remain exposed to this spot price risk, however, with respect to the cost of electricity required to serve our consumers in the Free Market.  For further information, see “Item 4.  Information on the Company—The Brazilian Power Industry—Generation Scaling Factor.” In the Distribution segment, thermoelectric generation can lead to additional energy purchase costs when the 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 were applied throughout 2015 since introduction of the 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 mandatory 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.   10


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 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.  According toPortariaNo. 515/2015 issued by the MME, the first revision of Assured Energy under this process is expected to be implemented for all Hydroelectric Power Plants (with the exception of SHPPs) in January 2017.  The methodology of this new revision has been published, but the application of the methodology to each Power Plant is not yet available.  We therefore cannot be certain how the MME’s revisions will affect the Assured Energy of each of our individual Power Plants, and whether it will increase or decrease our overall Assured Energy.  If the Assured Energy of a Power Plant is decreased, our ability to supply electricity under that plant’s power purchase agreements 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.  We expect similar revisions of Assured Energy under Decree 2,655/98 to continue to take place every five years. See “Item 4—Principal Regulatory Authorities—Ministry of Mines and Energy - MME”. 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, regulatory and/or 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.    11


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 We are subject to environmental and health regulations that may become more stringent in the future and may result in increased liabilities and increased capital expenditures. Our activities are subject to comprehensive federal, state and municipal legislation, the need to obtain and maintain licenses, 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 failure to comply with their regulations, or to obtain or maintain licenses.  These actions could include, among other things, the imposition of administrative and criminal sanctions, including fines and revocation of licenses.  The sanctions depend on the seriousness of the infraction, and any mitigating or aggravating circumstances applicable to the violator.  It is possible that enhanced environmental and health regulations will force us to allocate capital expenditures to compliance, and consequently, increase our level of investment or divert funds from existing planned investments, either of which 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$2,093 million in our generation activities (R$2,044 million in renewable sources and R$49 million in conventional sources), R$7,032 million in our distribution activities and R$515 million in our commercialization and services activities during the period from 2016 through 2020. Our ability to carry out this capital expenditure program depends on a variety of factors, including our ability to charge adequate tariffs for our services, our access to domestic and international capital markets and a variety of operating, regulatory and other contingencies.  We cannot be certain that we will have the financial resources to complete our proposed capital expenditure program, and failure to do so could have a material adverse effect on the operation and development of our business. We are strictly liable for any losses and damages resulting from inadequate provision of electricity services, and our contracted insurance policies may not fully cover such losses and damages. Under Brazilian law, we are strictly liable for direct and indirect losses and damages resulting from the inadequate provision of electricity distribution services.  In addition, our distribution facilities may, together with our transmission and generation utilities, be held liable for losses and 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.  Until all responsible parties are identified, liability for any losses and damages is attributed as follows: (i) 35.7% to distribution entities; (ii) 28.6% to transmission entities; and (iii) 35.7% to generation entities.  These percentages are based on the number of votes that each concessionaire has in general meetings of the ONS and, therefore, may change in the future.  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 (amounting to R$1,573 million for the last three fiscal years) in generation businesses other than hydroelectric power, principally wind and biomass generation.  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.   12


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 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, 2015, 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 23.58%, 29.45% and 15.06%, 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, 2015, approximately 68.0% of our total indebtedness was denominated inreaisand indexed to Brazilian money‐market rates or inflation rates, or bore interest at floating rates.  The remaining 32.0% of our total indebtedness as of December 31, 2015 was denominated in U.S. dollars, compared to approximately 18.0% as of December 31, 2014, although this U.S. dollar denominated debt is substantially subject to currency swaps that convert these obligations intoreais.  In addition, the costs of electricity purchased from the Itaipu Power Plant, or Itaipu, a Hydroelectric Power Plant that is one of our major suppliers, are indexed to the U.S. dollar exchange rate.  Our tariffs are adjusted annually in order to contemplate the losses or gains from such electricity acquisition.  Accordingly, when the Brazilianrealdepreciates against the U.S. dollar, as was the case in 2015, our financing expenses increase. Our indebtedness and debt service obligations could adversely affect our ability to operate our business and make payments on our debt. As of December 31, 2015, we had a debt of R$21,733 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 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.    13


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 The level of default by our consumers could adversely affect our business, operational results, and/or financial situation The level of default by our consumers may be affected by economic factors such as income levels, unemployment, interest rates, inflation and the price of energy.  The current macroeconomic situation in Brazil, combined with the increase in energy prices in recent years, could lead to an increase in default by our consumers.  Although we have implemented a number of measures to improve payment collection, we cannot assure you that these measures will be sufficient or effective in maintaining our consumer default at current levels.  If the level of default increases, our business, operational results and financial situation could be adversely affected. 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. Uncertainty over whether the Brazilian government will change policies or regulations affecting these or other factors may contribute to political and economic uncertainty in Brazil and to heightened volatility in Brazilian securities markets and securities issued abroad by Brazilian issuers.  Standard & Poor’s downgraded Brazil below investment grade on September 9, 2015; Fitch Ratings lowered its rating for Brazil from BBB- to BB+ on December 16, 2015; and Moody’s Investors Service downgraded Brazil to Ba2 with negative outlook on February 24, 2016. These downgrades reflected poor economic conditions, continued adverse fiscal developments and increased political uncertainty in Brazil. We cannot assure you that the Brazilian government will continue with its current economic policies, or that these and other developments in Brazil’s economy and government policies will not, directly or indirectly, adversely affect our business and results of operations.   14


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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. Currently, Brazilian markets are experiencing heightened volatility due to the uncertainties deriving from the ongoingLava Jatoand related investigations currently being conducted by the Brazilian Federal Police, the Office of the Brazilian Federal Prosecutor and other authorities, and their impact on the Brazilian economy and political environment.  Certain of the companies under investigation are also facing investigations by the Brazilian Securities Commission (Comissão de Valores Mobiliários), or CVM, and the SEC.  Members of the Brazilian federal government and of the legislative branch, as well as senior officers of large companies (including state-owned companies) have faced allegations of political corruption, money laundering and other related crimes relating to government contracts that were granted to several infrastructure, oil and gas and construction companies. The potential outcome of these investigations is uncertain, but they have already an adverse impact on market perception of the Brazilian economy and political environment.  We cannot predict whether these allegations and investigations will lead to further political and economic instability or whether new allegations against government officials will arise in the future.  In addition, we cannot predict the outcome of any such allegations or their effect on the Brazilian economy.  Any of these matters could adversely affect our business, financial condition and results of operations. Exchange rate instability may adversely affect our financial condition and results of operations and the market price of the ADSs and our common shares. The Brazilian currency has experienced frequent and substantial variations in relation to the U.S. dollar and other foreign currencies over the last decade.  The exchange rate of therealagainst the U.S. dollar was R$2.343 per US$1.00 on December 31, 2013; R$2.656 on December 31, 2014; and R$3.905 on December 31, 2015.  On April 11, 2016, the exchange rate was R$3.528per 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 therealalso 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, our ADSs. Inflation and interest rate policies may impact 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 realinterest rates in the world.  Between 2006 and 2015, the base interest rate in Brazil, or SELIC, varied between 7.25% p.a. and 18.00% p.a., reaching its lowest level (7.25%) at the end of 2012.  On April 11, 2016, the SELIC rate was 14.25% p.a.  Inflation has had and may in the future have significant effects on the Brazilian economy and our business.  Relatively lenient interest rate policies by the


government and Brazilian Central Bank 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.  Conversely, tight monetary policies with high interest rates may restrict Brazil’s growth and the availability of credit.   15


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 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 emerging economies 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 2.4% in 2015.  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, China 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. 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 common 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.  For further information, see “Item 10.Additional Information—Voting Rights of ADS Holders”. 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. For further information, see “Item 10.Additional Information— Allocation of Net Income and Distribution of Dividends-Payment of Dividends”. 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.    16


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 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 more speculative in nature.  The Brazilian securities market is substantially smaller, less liquid, more concentrated and can be more volatile than major securities markets in the United States.  Accordingly, although you are entitled to withdraw the common shares underlying the ADSs from the depositary at any time, your ability to sell the common shares underlying the ADSs at a price and time at which you wish to do so may be substantially limited.  There is also significantly greater concentration in the Brazilian securities market than in major securities markets in the United States.  The ten largest companies in terms of market capitalization represented 46.3% of the aggregate market capitalization of theBM&FBOVESPA S.A. ‐ Bolsa de Valores, Mercadorias & Futuros,or BM&FBOVESPA, as of December 31, 2015.  The top ten stocks in terms of trading volume accounted for 39.3%, 46.3% and 41.3% of all shares traded on the BM&FBOVESPA in 2015, 2014, and 2013, respectively.  ITEM 4.Information on the Company Overview We are a corporation (sociedade por ações) incorporated and existing under the laws of Brazil with the legal name CPFL Energia S.A.  Our principal executive offices are located at Rua Gomes de Carvalho, 1,510, 14th floor – Suite 142, Vila Olímpia, CEP 04547‐005, São Paulo, state of São Paulo, Brazil and its telephone number is +55 11 3841‐8507.  Our Investor Relations Department is located at Rodovia Engenheiro Miguel Noel Nascentes Burnier, Km 2.5, no 1,755, Parque São Quirino, CEP 13088-900, Campinas, state of São Paulo, Brazil, and its telephone number is +55 19 3756‐6083. 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 40,157 GWh of electricity we distributed to approximately 7.8 million consumers in 2015.  In electricity generation, our Installed Capacity at December 31, 2015 was 3,164 MW.  Through our interest in CPFL Renováveis, we are also involved in the building of two SHPP and 11 wind farms, as a result of which we expect to increase our Installed Capacity to 3,334 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 2015, the total amount of electricity sold by our commercialization subsidiaries was 0.485 GWh and 9,384 GWh to affiliated and unaffiliated parties, respectively.  
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 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 the start 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. ·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. ·In February 2014 CPFL Renováveis acquired Rosa dos Ventos Geração e Comercialização de Energia S.A., or Rosa dos Ventos for a acquisition price, after all adjustments, of 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 for two wind farms located on the coast of the state of Ceará: (i) Canoa Quebrada, which has Installed Capacity of 10.5 MW; and (ii) Lagoa do Mato, which has Installed Capacity of 3.2 MW.  Both wind farms 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, Dobrevê Energia S.A., or 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, through CPFL Geração, was reduced from 58.84% to 51.61%.  The facilities acquired from DESA consist of operational facilities with an Installed Capacity of 306 MW plus renewable generation construction projects with Installed Capacity of 50 MW, which are expected to start operations in 2016 and 2020.  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 15.4.2 to our audited annual consolidated financial statements.   18


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 ·In March 2014, CPFL Renováveis completed the last wind farm of the Atlântica Complex (Atlântica I, II, IV and V Wind Farms) 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 461.7 GWh of contracted energy. The Atlântica Complex windmills have been commencing operations in phases since November 2013. ·In June 2014, ANEEL certified the Macacos Complex (Pedra Preta, Costa Branca, Juremas and Macacos fields) fit for operation 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. The Macacos Complex, located in the city of João Câmara, in Rio Grande do Norte, has Installed Capacity of 78.2 MW and physical guarantee of 37.5 average MW. ·In September 2014, we established TI Nect Serviços de Informática Ltda. or Authi, a company that provides informatics, information technology maintenance, system updates, program development and customization and computer and peripheral equipment maintenance services. ·In October 2014, CPFL Eficiência Energética S.A., or ESCO, commenced operations.  CPFL ESCO, which is located in Jundiaí, in the state of São Paulo, provides consulting and management services related to energy efficiency improvements, rental of generation assets and research and development activities for energy-related programs. ESCO also provides the self-production services that were carried out by CPFL Serviços until October 2014. ·In January 2015 we established CPFL Transmissora Morro Agudo S.A., a subsidiary of CPFL Geração, which will operate electric energy transmission concessions and carry out construction, implementation, operation and maintenance of transmission facilities on the Basic Network in the Interconnected Power System. ·In April 2015, Morro dos Ventos II Wind farm commenced operations. Morro dos Ventos II, located in João Câmara, in the state of Rio Grande do Norte, has Installed Capacity of 29 MW and physical guarantee of 15.3 MW. From April 2015 until January 2016, when the 2011 A-5 auction energy sale contract came into effect, the energy generated by Morro dos Ventos II was injected into the system and sold in the short-term market. ·In April 2015, at the 21st A-5/2015 Energy Auction, CPFL Renováveis traded an average of 14.8 MW of contracted energy to be generated by the Boa Vista II SHPPs.  The contract will have a duration of 30 years. ·In an Extraordinary Shareholders’ Meeting held on September 30, 2015, our shareholders approved an internal transaction in which we transferred the Macaco Branco and Rio de Peixe plants from CPFL Centrais Geradoras Ltda. to CPFL Geração, in return for newly-issed shares of CPFL Geração in the amount of R$4 million, the book value of the plant transferred. This transaction has not produced effects in our consolidated financial statements for the period ended December 31, 2015. ·In December 9, 2015, distribution concessions held by our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista were extended to July 2045 due to application of Law No. 12,783/13 of 2013, which provided the renewal of certain type of distribution concession, subject to certain conditions, for a further term of up to 30 years. See “Item 4—Information on the Company— Concessions, Permissions and Authorizations —Concessions”. ·On April 13, 2016 our Chief Executive Officer Wilson Ferreira announced his intention to resign the post that he has held since 2002.  He will remain in office until July 1, 2016.  Our board of directors has approved Andre Dorf, currently the Chief Executive Officer of CPFL Renovaveis, to replace Mr. Ferreira as our Chief Executive Officer.  Mr. Ferreira and Mr. Dorf will work together on the transition until July 1.   19


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 The following chart provides an overview of our corporate structure at March 31, 2016:  Notes: (1) Controlling shareholders. (2) Includes the 0.5% stake of Caixa de Previdência dos Funcionários do Banco do Brasil. (3) Includes the 0.2% stake of Petros e Sistel pension funds. (4) Bounded shares, according to the Shareholders Agreement; (5) 51.54% stake of the availability of power and energy of Serra da Mesa HPP, pursuant to the Power Purchase Agreement between CPFL Geração and Furnas. Our core businesses are: ·Distribution.  In 2015, our eight fully‐consolidated distribution subsidiaries delivered 40,157 GWh of electricity to approximately 7.8 million consumers primarily in the states of São Paulo and Rio Grande do Sul. ·Conventional Generation.  At December 31, 2015, our conventional generation subsidiaries had Installed Capacity of 2,235 MW.  During 2015, we generated a total of 11,369 GWh of electricity, and we had 10,046 GWh of Assured Energy at December 31, 2015, 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 50 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. ·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 40 of our 50 Small Hydroelectric Power Plants.  These 40 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) two Small Hydroelectric Power Plants (Mata Velha SHPP and Boa Vista II SHPP) under construction to scheduled to commence operations in 2016 and 2020, respectively, and are expected to have Installed Capacity of approximately 24 MW and 26 MW.  CPFL Renováveis also has 45 wind farms, of which (i) 34 farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, are operational and have aggregate Installed Capacity of 1,029 MW, and (ii) the remaining 11 farms are under construction, scheduled to commence operations between 2016 and 2018, and are expected to have Installed Capacity of approximately 282 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, 2015, our total consolidated Installed Capacity through our Renewable Generation segment (calculated on the basis of our 51.61% interest in CPFL Renováveis) was 929 MW and we expect that our Renewable Generation segment will reach an Installed Capacity of 1,099 MW in 2020.  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”.  
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 ·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 2015, we sold 9,870 GWh of electricity, of which 9,384 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. In addition to our five operating segments above, we consolidate a number of activities known as “Other”.  The activities consolidated under Other consist of (i) two transmission assets held through CPFL Geração, of which one (CPFL Piracicaba) is operational and the other (CPFL Morro Agudo) is under construction, (ii) CPFL Telecom and (iii) our holding company expenses other than the amortization of intangible assets related to our concessions, which is allocated to our operational segments. 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 as market leader in renewable energy sources.At December 31, 2015, our total consolidated Installed Capacity (calculated on the basis of our 51.61% interest in CPFL Renováveis) was 3,164 MW, of which 2,235 MW was conventionally generated and 929 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.   21


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 Our total Installed Capacity at December 31, 2015 represents a 0.1% increase as compared to Installed Capacity of 3,162 MW at December 31, 2014, due to the start of commercial operations at the Morro dos Ventos II wind farm in April 2015, partially offset by the reduction in our interest in Epasa from 57,12% at December 31, 2014 to 53.34% at December 31, 2015.  By the end of 2020, when we expect the Mata Velha and Boa Vista SHPPs and the Campo dos Ventos, São Benedito and Pedra Cheirosa wind complexes to become operational, we expect our total Installed Capacity to reach 3,334 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 1,782 MW (calculated on the basis of our 51.61% interest in CPFL Renováveis’ total portfolio of 3,453 MW) of renewable generation projects to be developed by CPFL Renováveis in the coming years.  When electricity consumption in Brazil returns to growth, 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 71.5% of our consolidated net income in 2015.  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 Voltage and Medium Voltage customers) and Mobile Workforce Management.  This program is already delivering benefits, with 26,783 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 further stabilization of the regulatory environment in the Brazilian power industry in future may lead to 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.    22


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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 2015.  Our eight distribution subsidiaries together supply electricity to a region covering 204,061 square kilometers, primarily in the states of São Paulo and Rio Grande do Sul.  Their concession areas include 5611municipalities and a population of approximately 19 million people.  Together, they provided electricity to approximately 7.8 million consumers as of December 31, 2015.  Our eight subsidiaries distributed approximately 11.9% of the total electricity distributed in Brazil in 2015, 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 10.1 million people.  Its concession area covers 234 municipalities, including the cities of Campinas, Bauru, Ribeirão Preto, São José do Rio Preto, Araraquara and Piracicaba.  CPFL Paulista had approximately 4.2 million consumers at December 31, 2015.  In 2015, CPFL Paulista distributed


22,068 GWh of electricity, accounting for approximately 23.4% of the total electricity distributed in the state of São Paulo and 6.3% 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 6,785 square kilometers in the southern part of the state of São Paulo with a population of approximately 4.1 million people.  Its concession area covers 27 municipalities, including the cities of Santos, Sorocaba and Jundiaí.  CPFL Piratininga had approximately 1.7 million consumers at December 31, 2015.  In 2015, CPFL Piratininga distributed 9,236 GWh of electricity, accounting for approximately 9.8% of the total electricity distributed in the state of São Paulo and 2.6% 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 86,152 square kilometers in the state of Rio Grande do Sul with a population of approximately 4.0 million people.  Its concession area covers 255 municipalities, including the cities of Caxias do Sul, Gravataí, Passo Fundo and Bento Gonçalves.  RGE had approximately 1.5 million consumers at December 31, 2015.  In 2015, RGE supplied 8,011 GWh of electricity, accounting for approximately 33.4% of the total electricity distributed in the state of Rio Grande do Sul and 2.3% 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 11,850 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 2015, CPFL Santa Cruz distributed 1,042 GWh of electricity to approximately 205,000 consumers, accounting for approximately 1.1% of the total electricity distributed in the state of São Paulo and 0.3% 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 2 municipalities of the state of São Paulo.  In 2015, CPFL Jaguari distributed 492 GWh of electricity to approximately 39,000 consumers. ·CPFL Mococa.  Companhia Luz e Força de Mococa, or CPFL Mococa, supplies electricity to a concession area covering 1,884 square kilometers, which includes one municipality in the state of São Paulo and three municipalities in the state of Minas Gerais.  In 2015, CPFL Mococa distributed 204 GWh of electricity to approximately 46,000 consumers. ·CPFL Leste Paulista.  Companhia Leste Paulista de Energia, or CPFL Leste Paulista, supplies electricity to a concession area covering 2,915 square kilometers, which includes seven municipalities of the state of São Paulo.  In 2015, CPFL Leste Paulista distributed 285 GWh of electricity to approximately 57,000 consumers. ·CPFL Sul Paulista.  Companhia Sul Paulista de Energia, or CPFL Sul Paulista, supplies electricity to a concession area covering 3,783 square kilometers, which includes five municipalities of the state of São Paulo.  In 2015, CPFL Sul Paulista distributed 392 GWh of electricity to approximately 83,000 consumers. On December 9, 2015 the concessions held by CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista were extended to July 2045.  For further information on the extension of these concessions, see “—Our Concessions and Authorizations—Concessions.” 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, including Free Consumers and other concessionaires, are required to pay a tariff for using the system (Tarifa de Uso do Sistema de Distribuição), or TUSD.   24


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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, 2015, our distribution networks consisted of 247,422 kilometers of distribution lines, including 369,526 distribution transformers.  Our eight distribution subsidiaries had 9,986 km of High Voltage distribution lines between 34.5 kV and 138 kV.  At that date, we had 453 transformer substations for transforming High Voltage into Medium Voltages for subsequent distribution, with total transforming capacity of 14,865 mega‐volt amperes.  Of the industrial and commercial consumers in our concession area, 355 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 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 266,493 inspections during 2015, which we believe led to a recovery of receivables estimated at more than R$29 million. Power Outages The following table sets forth the frequency and duration of electricity outages per consumer for the years ended December 31, 2015 and 2014 for each of our distribution subsidiaries: Year ended December 31, 2015CPFL Paulista

   CPFL Piratininga

   RGE

   CPFL Santa Cruz

   CPFL Jaguari

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul PaulistaSAIFI1

   4.89

   4.31

   8.33

   6.34

   4.61

   5.92

   5.67

   9.47SAIDI2

   7.75

   7.25

   15.98

   8.46

   6.93

   7.04

   7.92

   11.51
  
 (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, 2014CPFL Paulista

   CPFL Piratininga

   RGE

   CPFL Santa Cruz

   CPFL Jaguari

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul PaulistaSAIFI1

   4.87

   4.20

   9.14

   5.29

   4.31

   7.26

   6.19

   6.91SAIDI2

   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) 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 2014, the most recent data available, 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 2015, 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 8.1% 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 2015, we invested approximately R$849 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$1,178 million for such purposes throughout 2016. We strive to improve response times for our repair services.  The quality indicators for the provision of energy by CPFL Paulista and CPFL Piratininga have maintained levels of excellence while complying with regulatory standards.  This was also mainly the result of our efficient operational logistics, including the strategic positioning of our teams and the technology and automation of our network and operation centers, together with a preventive maintenance and conservation plan. Purchases of Electricity Most of the electricity we sell is purchased from unrelated parties, rather than generated by our facilities.  In 2015, 11.2% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries (including our joint ventures). In 2015, we purchased 10,261 GWh of electricity from the Itaipu Power Plant, amounting to 17.5% of the total electricity we purchased.  Itaipu is located on the border of Brazil and Paraguay and is subject to a bilateral treaty between the two countries pursuant to which Brazil has committed to purchasing specified amounts of electricity.  This treaty will expire in 2023.  Electric utilities operating under concessions in the midwest, south and southeast regions of Brazil are required by law to purchase a portion of the electricity that Brazil is obligated to purchase from Itaipu.  The amounts that these companies must purchase are governed by take‐or‐pay contracts with tariffs established in US$/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$38.07/Kw.  Our purchases represent approximately 17.0% 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 2015, we paid an average of R$279.65 per MWh for purchases of electricity from Itaipu, compared with R$132.82 during 2014 and R$121.11 during 2013.  These figures do not include the transmission fee. We purchased 48,346 GWh of electricity in 2015 from generating companies other than Itaipu, representing 82.5% of the total electricity we purchased.  We paid an average of R$210.44 per MWh for purchases


of electricity from generating companies other than Itaipu, compared with R$201.79 per MWh in 2014 and R$147.30 per MWh in 2013.  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”.   26


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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 31,2015

   2014

   2013(in GWh)Energy purchased for resaleItaipu

   10,261

   10,417

   10,719Electric Energy Trading Chamber - CCEE

   2,946

   5,074

   2,974Proinfa Program

   1,058

   1,043

   1,019Energy purchased in the Regulated Market and through bilateral contracts

   44,342

   42,345

   42,980TOTAL

   58,607

   58,879

   57,692
  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 have been 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.  Since distribution companies are required to contract in advance, through public bids, for 100% of their forecast electricity needs and are only authorized to pass through the cost of up to 105% of this electricity to consumers, any involuntary quota to be purchased from generation companies whose concessions were renewed under Law 12,783/13 that takes a distributor’s energy volume to more than 105% of its forecast would lead to additional costs for the distributor.  As a result, Normative Resolution No. 706 of March 29, 2016 provided that the costs resulting from involuntary purchase quotas can be passed on to consumers, and the energy volume can be offset from electricity auctions from existing power generation facilities in the following years.  See “Item 3.  Key Information—Risk Factors—Our operating results depend on prevailing hydrological conditions.  Poor hydrological conditions may affect our results of operations” and “Item 3.  Key Information—Risk Factors—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”. Transmission Tariffs.  In 2015, we paid a total of R$1,465 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 23.6% of revenues from electricity sales in our Distribution segment in 2015. ·Residential consumers. Sales to final residential consumers accounted for 42.0% of our revenues from electricity sales in our Distribution segment in 2015. ·Commercial consumers.  Sales to final commercial consumers, which include service businesses, universities and hospitals, accounted for 22.5% of our revenues from electricity sales in our Distribution segment in 2015. ·Rural consumers.  Sales to final rural consumers accounted for 3.2% of our revenues from electricity sales in our Distribution segment in 2015. ·Other consumers.  Sales to other consumers, which include public and municipal services such as street lighting, accounted for 8.7% of our revenue of electricity sales in our Distribution segment in 2015. 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”.  
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 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 inreaisper 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 2015 and 2014.  These prices include taxes (ICMS, PIS and COFINS) and were calculated based on our revenues and the volume of electricity sold in 2015 and 2014.  Year ended December 31, 2015CPFL Paulista

   CPFL Piratininga

   RGE

   CPFL Santa Cruz

   CPFL Leste Paulista

   CPFL Sul Paulista

   CPFL Jaguari

   CPFL Mococa(R$/MWh)Residential

   589.00

   612.81

   671.50

   639.32

   574.85

   584.19

   543.00

   652.28Industrial

   561.40

   550.31

   533.24

   609.89

   509.75

   483.70

   460.79

   517.43Commercial

   557.18

   569.18

   655.85

   645.61

   547.01

   557.46

   511.06

   591.04Rural

   330.76

   391.27

   361.01

   408.32

   354.60

   367.52

   337.81

   389.43Other

   437.75

   418.14

   276.94

   354.28

   422.77

   422.89

   396.75

   442.72Total

   543.50

   565.51

   518.22

   544.61

   486.10

   510.87

   474.80

   545.21
 Year ended December 31, 2014CPFL 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

   437.22Industrial

   364.14

   330.51

   327.26

   384.69

   302.95

   286.98

   237.19

   302.98Commercial

   366.82

   352.67

   419.95

   421.79

   344.86

   356.49

   284.17

   388.85Rural

   203.82

   232.05

   220.55

   249.83

   213.03

   225.60

   184.13

   233.33Other

   280.68

   254.17

   186.10

   225.00

   255.96

   257.10

   208.68

   270.16Total

   357.14

   347.00

   331.10

   346.49

   301.75

   322.53

   252.07

   346.54
   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 Governo Federal) 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, which are set by ANEEL, consist of the three tariffs described under “Item 4.  Information on the Company—System Tariffs—TUSD”.  In 2015, tariff revenues for the use of our network by Free Consumers amounted to R$1,898 million.  The average tariff for the use of our network was R$119.92/MWh and R$58.97/MWh in 2015 and 2014, 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, and consumers of our subsidiary RGE, whose meters are read in intervals varying from one to three months. 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 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 the most recent data from ABRADEE, 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 over 90 days overdue.  Bills due and outstanding for over 360 days are classified as irrecoverable. 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 2015, we responded to approximately 39.4 million inquiries.  We also provide customer service through our branch offices, which handled approximately 5.6 million customer requests in 2015.  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 regulations, revenues from generation are based mainly on the 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 its Assured Energy, even if it does not actually generate all the energy.For more information, see “—The Brazilian Power Industry—Generation Scaling Factor”.  Conversely, if a generation facility’s output exceeds its Assured Energy, its incremental revenue is equal only to the costs associated with generating the additional energy.   29


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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 3,164 MW as of December 31, 2015.  Most of the electricity we produce comes from our Hydroelectric Power Plants.  We generated a total of 17,066GWh in 2015, 13,658 GWh in 2014 and 11,427 GWh in 2013, 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”). If less than the total Assured Energy is being generated (i.e., if the Generation Scaling Factor, or GSF, is less than 1.0), hydroelectric companies must purchase energy in the spot market to cover the energy shortage and meet their Assured Energy volumes under the MRE.  From 2005 to 2012, the GSF remained above 1.0.  Beginning in 2013, however, this scenario began to change, which led the GSF to remain below 1.0 for the whole of 2014, and in 2015 it ranged from 0.783 to 0.825, requiring electricity generators to purchase energy in the spot market, thereby incurring significant costs.  Under Federal Law 13,203, however, we renegotiate our power purchase agreements for the Regulated Market in December 2015, setting the GSF cost at a risk premium of R$9.50/MWh per year through the end of the power purchase agreement or the end of the concession, whichever occurs sooner.  For more information on the GSF and Federal Law 13,203, see “—The Brazilian Power Industry—Generation Scaling Factor”.  Conventional Generation Hydroelectric Power Plants At December 31, 2015, 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’ 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 Hydroelectric 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 CERAN Hydroelectric 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 Hydroelectric 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.   30


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 ·Monte Claro.  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.  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. ·14 de Julho.  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 GWh. Following a refurbishment of the CERAN Hydroelectric complex in 2013, we installed equipment on the Monte Claro Hydroelectric Power Plant in order to improve the free flow of water and increase the plant’s availability.  Following monitoring, however, this equipment did not operate satisfactorily and the project was cancelled.  We are currently assessing alternative measures in order to raise the electricity generated by the CERAN complex. 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 (24.73%), Votorantim Metais Níqueis S.A. (20.04%) 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.  We sell 40.0% of our share in the Assured Energy of this project to affiliates in our group and 60.0% 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 and responsibility for operation of these assets, and reducing the transmission line energy loss factor (regulatory loss).  As of December 31, 2015, this transfer had not been completed as ANEEL had not completed its evaluation of the proposal. 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).   31


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 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 per year.  On December 31, 2015, we owned an aggregate 53.34% interest in Termonordeste and Termoparaíba.  The Termonordeste and Termoparaíba Thermoelectric Power Plants are located in the city of João Pessoa, in the state of Paraíba.  The electricity from these power plants was sold in CCEARs, and part of this energy was purchased by our own distributors. The remaining facility, Carioba, 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, 2015, 10 of our 50 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 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. In addition, the concession agreements for Macaco Branco and Rio do Peixe were transferred from CPFL Centrais Geradoras to CPFL Geração on September 30, 2015 (see “–Overview”). ·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.   32


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 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 relating to 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. 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, 2015: Holding company

   Partic.

   Capacity (MW)

   Assured Energy (GWh)

   Placed in service

   Concession expiresOur share

   TOTAL

   Our share

   TOTALHydroelectric plants:Serra da Mesa

   CPFL Geração

   51.54%

   657.1

   1,275.0

   3,029.5

   5,878.0

   1998

   2039(1)Monte Claro

   CPFL Geração

   65%

   84.5

   130.0

   335.9

   516.8

   2004

   2036Barra Grande

   CPFL Geração

   25.01%

   172.6

   690.0

   833.9

   3,334.1

   2005

   2036Campos Novos

   CPFL Geração

   48.72%

   428.7

   880.0

   1,612.8

   3,310.4

   2007

   2035Castro Alves

   CPFL Geração

   65%

   84.5

   130.0

   364.4

   560.6

   2008

   203614 de Julho

   CPFL Geração

   65%

   65.0

   100.0

   284.7

   438.0

   2008

   2036Luis Eduardo Magalhães

   CPFL Jaguari de Geração

   6.93%

   62.5

   902.5

   319.7

   4,613.0

   2001

   2032Foz do Chapecó

   Chapecoense

   51%

   436.1

   855.0

   1,930.0

   3,784.3

   2010

   2036SUBTOTAL ‐ Hydroelectric plants

   

   

   1,991.0

   

   8,710.8Thermoelectric plants:Carioba

   CPFL Geração

   100%

   36.0

   36.0

   93.7

   93.7

   1954

   2027(2)EPASA facilities:Termonordeste

   CPFL Geração

   53.34%(4)

   91.1

   170.8

   578.5

   1,084.5

   2010

   2042Termoparaíba

   CPFL Geração

   53.34%(4)

   91.1

   170.8

   578.5

   1,084.5

   2011

   2042SUBTOTAL ‐ Thermoelectric plants

   

   

   218.2

   

   1,250.7Small Hydroelectric PlantsCariobinha

   CPFL Geração

   100%

   1.3

   1.3

   -

   -

   N/A

   2027(2)Lavrinha

   CPFL Centrais Geradoras

   100%

   0.3

   0.3

   2.1

   2.1

   N/A

   (3)Macaco Branco

   CPFL Geração

   100%

   2.4

   2.4

   14.5

   14.5

   N/A

   2042Pinheirinho

   CPFL Centrais Geradoras

   100%

   0.7

   0.7

   4.2

   4.2

   N/A

   (3)Rio do Peixe I

   CPFL Geração

   100%

   3.1

   3.1

   3.9

   3.9

   N/A

   2042Rio do Peixe II

   CPFL Geração

   100%

   15.0

   15.0

   46.8

   46.8

   N/A

   2042Santa Alice

   CPFL Centrais Geradoras

   100%

   0.6

   0.6

   3.6

   3.6

   N/A

   (3)São José

   CPFL Centrais Geradoras

   100%

   0.8

   0.8

   2.1

   2.1

   N/A

   (3)São Sebastião

   CPFL Centrais Geradoras

   100%

   0.7

   0.7

   4.6

   4.6

   N/A

   (3)Turvinho

   CPFL Centrais Geradoras

   100%

   0.8

   0.8

   2.2

   2.2

   N/A

   (3)SUBTOTAL – Small Hydroelectric Plants

   

   

   25.7

   

   84.0TOTAL – Conventional Generation

   

   

   2,234.9

   

   10,105.2
  
 (1) The concession for Serra da Mesa is held by Furnas. On May 30, 2014, the concession held by Furnas was formally extended to November 12, 2039.  We have a contractual right to 51.54% of the Assured Energy of this facility, under a 30‐year agreement. (2) Inactive power plant. (3) Hydroelectric projects with an Installed Capacity equal to or less than 3,000 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) 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. This right was exercised during February 2015, and as from March 1, 2015, CPFL Geração holds 53.34% of EPASA.  33


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Table of Contents Renewable Generation At December 31, 2015, 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. ·29 subsidiaries involved in the generation of electric energy through 40 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) two SHPPs (Mata Velha and Boa Vista II), with 50 MW of combined Installed Capacity, which are under construction and scheduled to commence operations in 2016 and 2020, respectively. ·45 subsidiaries involved in the generation of electric energy from wind sources.  Of this total, 34 farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, are operational and have aggregate Installed Capacity of 1,029 MW (or aggregate capacity of 1,032 MW based on the total industrial capacity of CPFL Renováveis’ assets).  The remaining 11 farms are under construction, scheduled to commence operations between 2016 and 2018, and are expected to have aggregate Installed Capacity of approximately 282 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.  
 34


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Table of Contents
 ·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 40 of our 50 (48 operational and two 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.   35


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Table of Contents
 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 plant has total Installed Capacity of 45 MW.  The plant has an Assured Energy of 112.1 GWh and all of its electricity is sold to CPFL Brasil. CPFL Bio Formosa.  In 2009, CPFL Brasil established the Baía 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 185.7 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 CPFL 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 controls the Ester Thermoelectric Power Plant, located in the municipality of Cosmópolis, in the state of São Paulo.  The assets have total Installed Capacity of 70 MW.  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, on average, 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 Ivaí, in the state of Paraná, and operations started on August 28, 2013.The total Installed Capacity of UTE Coopcana 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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Table of Contents
 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 6.8 GW as of December 2015 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 45 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 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 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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Table of Contents
 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 37.5 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 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. Morro dos Ventos II:Morro dos Ventos II wind farm, in the state of Rio Grande do Norte, has an Installed Capacity of 29 MW and aggregate Assured Energy of 15.3 MWavg.  This wind farm commenced operations in April 2015. 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, 2015: Capacity (MW)

   Assured Energy (GWh)

   Placed in service

   Facility upgraded

   Concession expiresOur share

   TOTAL

   Our share

   TOTALSmall Hydroelectric plants:Alto Irani

   10.8

   21.0

   61.9

   120.0

   2008

   

   2032Americana

   15.5

   30.0

   26.6

   51.5

   1949

   2002

   2027Andorinhas

   0.3

   0.5

   1.9

   3.7

   1940

   

   (2)Arvoredo

   6.7

   13.0

   35.1

   68.1

   2010

   

   2032Barra da Paciência

   11.9

   23.0

   67.3

   130.4

   2011

   

   2029Buritis

   0.4

   0.8

   1.6

   3.1

   1922

   

   2027(1)Capão Preto

   2.2

   4.3

   10.3

   20.0

   1911

   2008

   2027Chibarro

   1.3

   2.6

   7.3

   14.1

   1912

   2008

   2027Cocais Grande

   5.2

   10.0

   22.0

   42.6

   2009

   

   2029Corrente Grande

   7.2

   14.0

   38.6

   74.7

   2011

   

   2030Diamante

   2.2

   4.2

   7.2

   14.0

   2005

   

   2019Dourados

   5.6

   10.8

   31.6

   61.2

   1926

   2002

   2027Eloy Chaves

   9.7

   18.8

   52.4

   101.5

   1954

   1993

   2027Esmeril

   2.6

   5.0

   13.0

   25.2

   1912

   2003

   2027Figueiropolis

   10.0

   19.4

   56.5

   109.5

   2010

   

   2034Gavião Peixoto

   2.5

   4.8

   17.3

   33.5

   1913

   2007

   2027Guaporé

   0.4

   0.7

   2.5

   4.9

   1950

   

   (2)Jaguari

   6.1

   11.8

   20.3

   39.4

   1917

   2002

   2027Lençóis

   0.9

   1.7

   4.7

   9.1

   1917

   1988

   2027Ludesa

   15.5

   30.0

   95.8

   185.7

   2007

   

   2032Monjolinho

   0.3

   0.6

   0.5

   1.0

   1893

   2003

   2027(2)Ninho da Águia

   5.2

   10.0

   29.4

   56.9

   2011

   

   2029Novo Horizonte

   11.9

   23.0

   47.0

   91.1

   2011

   

   2032Paiol

   10.3

   20.0

   49.8

   96.5

   2010

   

   2032Pinhal

   3.5

   6.8

   16.7

   32.4

   1928

   1993

   2027
   38


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Table of Contents
 Capacity (MW)

   Assured Energy (GWh)

   Placed in service

   Facility upgraded

   Concession expiresOur share

   TOTAL

   Our share

   TOTALPirapó

   0.4

   0.8

   2.6

   5.1

   1952

   

   (2)Plano Alto

   8.3

   16.0

   44.1

   85.5

   2008

   

   2032Saltinho

   0.4

   0.8

   3.3

   6.4

   1950

   

   (2)Salto Góes

   10.3

   20.0

   50.2

   97.2

   2012

   

   2040Salto Grande

   2.4

   4.6

   11.7

   22.6

   1912

   2003

   2027Santa Luzia

   14.7

   28.5

   83.3

   161.4

   2007

   

   2037Santana

   2.2

   4.3

   11.8

   22.9

   1951

   2002

   2027São Gonçalo

   5.7

   11.0

   34.4

   66.6

   2010

   

   2030São Joaquim

   4.2

   8.1

   22.9

   44.4

   1911

   2002

   2027Socorro

   0.5

   1.0

   1.4

   2.7

   1909

   1994

   2027(1)Três Saltos

   0.3

   0.6

   1.9

   3.8

   1928

   

   2027(1)Varginha

   4.6

   9.0

   24.4

   47.2

   2010

   

   2029Várzea Alegre

   3.9

   7.5

   22.1

   42.7

   2011

   

   2029SUBTOTAL ‐ Small Hydroelectric Power Plants (our share)

   206

   399

   1,005

   1,948Thermoelectric biomass plants:Baldin (CPFL Bioenergia)

   23.2

   45.0

   57.9

   112.1

   2010

   

   2039Bio Alvorada

   25.8

   50.0

   81.5

   157.9

   2013

   

   2042Bio Buriti

   25.8

   50.0

   95.0

   184.1

   2011

   

   2040Bio Coopcana

   25.8

   50.0

   81.6

   158.0

   2013

   

   2042Bio Ester

   20.6

   40.0

   46.1

   89.4

   2010

   

   2029Bio Formosa

   20.6

   40.0

   49.7

   96.4

   2011

   

   2032Bio Ipê

   12.9

   25.0

   37.0

   71.7

   2012

   

   2040Bio Pedra

   36.1

   70.0

   110.3

   213.7

   2012

   

   2046SUBTOTAL ‐ Thermoelectric biomass plants (our share)

   191

   370

   560

   1,085Wind farm plantsAtlântica I

   15.5

   30.0

   59.2

   114.8

   2014

   

   2046Atlântica II

   15.5

   30.0

   58.3

   113.0

   2014

   

   2046Atlântica IV

   15.5

   30.0

   58.8

   113.9

   2014

   

   2046Atlântica V

   15.5

   30.0

   61.9

   120.0

   2014

   

   2046Bons Ventos

   25.8

   50.0

   74.0

   143.4

   2010

   

   2033Campo dos Ventos II

   15.5

   30.0

   67.8

   131.4

   2013

   

   2046Canoa Quebrada

   29.4

   57.0

   108.8

   210.9

   2010

   

   2032Canoa Quebrada (Rosa dos Ventos)

   5.4

   10.5

   1.7

   3.3

   2014

   

   2032Costa Branca

   10.7

   20.7

   44.3

   85.8

   2014

   

   2046Enacel

   16.3

   31.5

   46.2

   89.6

   2010

   

   2032Eurus I

   15.5

   30.0

   70.1

   135.8

   2014

   

   2046Eurus III

   15.5

   30.0

   72.8

   141.0

   2014

   

   2046Eurus VI

   4.1

   8.0

   14.3

   27.7

   2011

   

   2045Foz do Rio Choró

   13.0

   25.2

   33.3

   64.6

   2009

   

   2032Icaraizinho

   28.2

   54.6

   99.8

   193.4

   2009

   

   2032Juremas

   8.3

   16.1

   34.4

   66.6

   2014

   

   2046Lagoa do Mato

   1.7

   3.2

   0.7

   1.4

   2014

   

   2032Macacos

   10.7

   20.7

   44.3

   85.8

   2014

   

   2046Morro dos Ventos I

   14.9

   28.8

   61.1

   118.3

   2014

   

   2045Morro dos Ventos III

   14.9

   28.8

   62.9

   121.8

   2014

   

   2045Morro dos Ventos IV

   14.9

   28.8

   61.9

   120.0

   2014

   

   2045Morro dos Ventos VI

   14.9

   28.8

   59.2

   114.8

   2014

   

   2045Morro dos Ventos IX

   15.5

   30.0

   64.7

   125.3

   2014

   

   2045Morro dos Ventos II

   15.0

   29.2

   69.2

   134.0

   2015

   

   2047Paracuru

   13.0

   25.2

   56.9

   110.2

   2008

   

   2032Pedra Preta

   10.7

   20.7

   46.6

   90.2

   2014

   

   2046Praia Formosa

   54.2

   105.0

   130.4

   252.6

   2009

   

   2032Santa Clara I

   15.5

   30.0

   62.0

   120.1

   2011

   

   2045Santa Clara II

   15.5

   30.0

   57.7

   111.8

   2011

   

   2045Santa Clara III

   15.5

   30.0

   56.6

   109.6

   2011

   

   2045Santa Clara IV

   15.5

   30.0

   55.6

   107.8

   2011

   

   2045Santa Clara V

   15.5

   30.0

   56.1

   108.7

   2011

   

   2045Santa Clara VI

   15.5

   30.0

   55.6

   107.7

   2011

   

   2045Taiba

   8.5

   16.5

   30.3

   58.8

   2008

   

   2032SUBTOTAL ‐ Wind farms (our share)

   532

   1,029

   1,938

   3,754Solar power plantTanquinho

   0.6

   1.1

   1.0

   1.7

   2012

   

   -SUBTOTAL – Solar power plant (our share)

   1

   1

   1

   2TOTAL (our share only)

   929

   1,799

   3,504

   6,789
 
 (1) Hydroelectric projects with installed capacity equal to or less than 1,000 Kw that have a concession contract.  The legislation for SHPPS with installed capacity less than 1,000 Kw has changed and currently a Registration is required. The concession contracts are valid until the concession expires. (2) Hydroelectric projects with installed capacity equal to or less than 3,000 Kw that are registered with the regulatory authority and the administrator of power concessions but do not require concession or authorization processes for operating.


39

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Table of Contents  Expansion of Installed Capacity Despite the 2.1% decline in consumption in 2015 due to challenging economic environment, demand for electricity in Brazil is expected to return to growth in the coming years according to Energetic Studies Company (Empresa de Pesquisas Energéticas), or EPE.  To address this projected increase in demand and to improve our margins, we continue to expand our Installed Capacity in renewable generation.  CPFL Renováveis is constructing the Mata Velha and Boa Vista II SHPPs and the São Benedito, Campo dos Ventos and Pedra Cheirosa Wind Farms, which are expected to have an aggregate Installed Capacity of 332 MW (of which our consolidated share will be 170 MW).  We expect that the total generating capacity from these facilities will become fully operational by the end of 2020. 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 to us

   Estimated Assured Energy Available to us(MW)

   (GWh/yr)

   

   

   (%)

   (MW)

   (GWh/yr)São Benedito and Campo dos Ventos Complexes (nine companies)(1)

   231

   1,059

   2015

   2016

   51.61

   119

   547Pedra Cheirosa Complex (two companies)(2)

   51

   229

   2016

   2018

   51.61

   26

   118Mata Velha Small Hydro Power Plant (one company)

   24

   115

   2013

   2016

   51.61

   12

   59Boa Vista II Small Hydro Power Plant (one company)

   26

   130

   2015

   2020

   51.61

   13

   67TOTAL

   332

   1,533

   

   

   

   170

   791
 
 (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. (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, and are scheduled to commence operations in phases in the first half of 2016.  This project has a PPA in force until 2034 for the São Benedito Complex and 2033 for the Campo dos Ventos Complex. 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. Mata Velha SHPP.Mata Velha SHPP is located in the state of Minas Gerais. Mata Velha SHPP is expected to commence operations in the second quarter of 2016.  It will have an aggregate Installed Capacity of 24 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.


40

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Table of Contents  
 Boa Vista II SHPP.Boa Vista SHPP is located in the state of Minas Gerais. Boa Vista SHPP is expected commence operations in 2020.  It will have an aggregate Installed Capacity of 26 MW and aggregate Assured Energy of 130 GWh/year.  The energy was sold in the A-5/2015 Energy Auction, held in 2015. Electricity Commercialization We carry out electricity commercialization activities through our subsidiary CPFL Brasil as well as CPFL Meridional, CPFL Sul Geradora, CPFL Cone Sul and CPFL Planalto.  The key areas of this activity 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 “self-dealing” provisions under which distributors were permitted to purchase electricity from affiliated companies were eliminated under the New Industry Model Law, with the exception of those contracts approved by ANEEL prior to March 2004, before the law was enacted.  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, Nect Serviços and Authi, 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 gas co‐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.   41


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Table of Contents
 ·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 provides the “Serviço em Conta”, which enables us to charge business customers for additional products and services through their electricity bills. Operations related to collections and onlending company offering bill payment services were discontinued as of 2016. ·Nect Serviços:Nect Serviços provides administrative services such as human resources, materials purchasing and logistics, maintenance and administrative infrastructure for the companies within our group.  Nect Serviços aims to standardize processes and achieve productivity gains. ·Authi:Authi provides IT services, information technology maintenance, services related to system updates, program development and customization and computer and peripheral equipment maintenance services. 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. See “Item 3.  Risk Factors—We are uncertain as to the renewal of our concessions and authorizations”.  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, the public bidding note and regulations applicable at the time of the request for renewal.  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), except for Thermoelectric Power Plants granted by means of bidding procedures, which are deemed to be a public service and authorized under a concession agreement.  Renewal of   42


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Table of Contents
 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”.   43


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---



Table of Contents
 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

   Term014/1997

   CPFL Paulista

   São Paulo

   30 years from November 199709/2002

   CPFL Piratininga

   São Paulo

   30 years from October 1998013/1997

   RGE

   Rio Grande do Sul

   30 years from November 1997021/1999

   CPFL Santa Cruz

   São Paulo and Paraná

   30 years from July 2015015/1999

   CPFL Jaguari

   São Paulo

   30 years from July 2015017/1999

   CPFL Mococa

   São Paulo and Minas Gerais

   30 years from July 2015018/1999

   CPFL Leste Paulista

   São Paulo

   30 years from July 2015019/1999

   CPFL Sul Paulista

   São Paulo

   30 years from July 2015003/2013

   CPFL Transmissão

   São Paulo

   30 years from February 2013006/2015

   CPFL Morro Agudo

   São Paulo

   30 years from March 2015
  Regarding our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista, Law No. 12,783 of 2013 provided that this type of existing distribution concession could be renewed, subject to certain conditions, for a further term of up to 30 years.  Accordingly, we applied for renewal of these concessions in 2014, and on November 9, 2015 the MME issued a decision extending the concessions to July 2045.  The extension agreements were signed on December 9, 2015.  Since the extensions were granted under current laws and regulations regarding distribution concessions, the concessions are now subject to the current targets and standards set by the Brazilian authorities. The tables below summarize our generation business concessions.  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 periodHydroelectric plants005/2004

   CPFL Geração

   Serra da Mesa

   Goiás

   35 years from November 2004

   (1)008/2001

   CERAN

   14 de Julho, Castro Alves and Monte Claro

   Rio Grande do Sul

   35 years from March 2001

   At the discretion of ANEEL036/2001

   Barra Grande

   Barra Grande

   Rio Grande do Sul

   35 years from May 2001

   At the discretion of ANEEL043/2000

   ENERCAN

   Campos Novos

   Santa Catarina

   35 years from May 2000

   At the discretion of ANEEL005/1997

   Investco

   Luiz Eduardo Magalhães

   Tocantins

   35 years from December 1997

   At the discretion of ANEEL128/2001

   Foz do Chapecó

   Foz do Chapecó

   Santa Catarina and Rio Grande do Sul

   35 years from November 2001

   At the discretion of ANEELThermoelectric plants015/1997

   CPFL Geração

   UTE Carioba

   São Paulo

   30 years from November 1997

   30 yearsSmall Hydroelectric Plants015/1997

   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 Geração(5)

   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 Geração(5)

   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)

   ‐
 44


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Table of Contents  Renewable generation Concession no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodSmall Hydroelectric Plants003/2011

   CPFL Renováveis

   Americana

   São Paulo

   up to November 2027

   20 yearsDispatch No. 1990

   CPFL Renováveis

   Andorinhas

   Rio Grande do Sul

   (3)

   (3)002/2011

   CPFL Renováveis

   Buritis

   São Paulo

   up to November 2027

   20 years002/2011

   CPFL Renováveis

   Capão Preto

   São Paulo

   up to November 2027

   20 years002/2011

   CPFL Renováveis

   Chibarro

   São Paulo

   up to November 2027

   20 yearsResolution No. 475

   CPFL Renováveis

   Diamante

   Mato Grosso

   up to November 2027

   30 years002/2011

   CPFL Renováveis

   Dourados

   São Paulo

   up to November 2027

   20 years004/2011

   CPFL Renováveis

   Eloy Chaves

   São Paulo

   up to November 2027

   20 years002/2011

   CPFL Renováveis

   Esmeril

   São Paulo

   up to November 2027

   20 years002/2011

   CPFL Renováveis

   Gavião Peixoto

   São Paulo

   up to November 2027

   20 yearsResolution 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 years002/2011

   CPFL Renováveis

   Lençóis

   São Paulo

   up to November 2027

   20 years004/2011

   CPFL Renováveis

   Monjolinho

   São Paulo

   up to November 2027

   20 years004/2011

   CPFL Renováveis

   Pinhal

   São Paulo

   up to November 2027

   20 yearsDispatch 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 years002/2011

   CPFL Renováveis

   São Joaquim

   São Paulo

   up to November 2027

   20 years004/2011

   CPFL Renováveis

   Socorro

   São Paulo

   up to November 2027

   20 years003/2011

   CPFL Renováveis

   Santana

   São Paulo

   up to November 2027

   20 years003//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 agreement, expiring in 2028.  The concession for Serra da Mesa, held by Furnas, has been extended to November 12, 2039.  The renewal was approved by the MME in Ordinance No. 262 published on April 27, 2012. (2) Hydroelectric projects with an Installed Capacity higher than 3,000 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 3,000 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) Since August 29, 2013 CPFL Centrais Geradoras has held the unbundled generation activities of the Macaco Branco and Rio do Peixe I and II SHPPs, as required by Resolution No. 521/12 for their renewal, together with the generation activities of the Santa Alice, Lavrinha, São José, Turvinho, Pinheirinho and São Sebastião Micro Hydroelectric Power Plants. (5) The Macaco Branco and Rio do Peixe concessions were transfered from CPFL Centrais Geradoras to CPFL Geração in Septemer 30, 2015 (see “–Overview”).  45


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Table of Contents
 Authorizations Conventional generation Authorization no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodThermoelectric plants2277

   EPASA

   Termoparaíba Thermoelectric Power Plant

   Paraíba

   35 years from December 7, 2007

   At the discretion of MME2277

   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 periodSmall Hydroelectric plantsResolution No.357

   SPE Aiuruoca Energia S.A.

   Aiuruoca(*)

   Minas Gerais

   30 years from December 23, 1999

   At the discretion of the granting authorityResolution No.  587

   SPE Alto Irani Energia S.A.

   Alto Irani

   Santa Catarina

   30 years from October 30, 2002

   At the discretion of the granting authorityResolution No. 606

   SPE Arvoredo Energia S.A.

   Arvoredo

   Santa Catarina

   30 years from November 7, 2002

   At the discretion of the granting authorityResolution 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 authorityResolution No.540

   SPE Cachoeira Grande Energia S.A.

   Cachoeira Grande(*)

   Minas Gerais

   30 years from October 15, 2003

   At the discretion of the granting authorityResolution No.  349

   SPE Cocais Grande Energia S.A.

   Cocais Grande

   Minas Gerais

   30 years from December 23, 1999

   At the discretion of the granting authorityResolution No.  17

   SPE Corrente Grande Energia S.A.

   Corrente Grande

   Minas Gerais

   30 years fromJanuary 17, 2000

   At the discretion of the granting authorityResolution No. 198

   Figueirópolis Energética S.A.

   Figueirópolis

   Mato Grosso

   30 years from May 04, 2004

   At the discretion of the granting authority
   46


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Table of Contents  Resolution No. 440

   Laranjinha Energética S.A.

   Laranjinha

   Paraná

   30 years from February 06, 2006

   At the discretion of the granting authorityResolution No. 705

   Ludesa Energética S.A.

   Ludesa

   Santa Catarina

   30 years from december 17, 2002

   At the discretion of the granting authorityResolution No. 262

   Mata Velha Energética S.A.

   Mata Velha

   Minas Gerais

   30 years from May 16, 2002

   At the discretion of the granting authorityResolution 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 authorityResolution No. 652

   Novo Horizonte Energética S.A.

   Novo Horizonte

   Paraná

   30 years from november 26, 2002

   At the discretion of the granting authorityResolution No.  406

   SPE Paiol Energia S.A.

   Paiol

   Minas Gerais

   30 years from August 07, 2002

   At the discretion of the granting authorityResolution No.  607

   SPE Plano Alto Energia S.A.

   Plano Alto

   Santa Catarina

   30 years from November 7, 2002

   At the discretion of the granting authorityResolution No. 2510

   SPE Salto Góes Energia S.A.

   Salto Góes

   Santa Catarina

   30 years from August 19, 2010

   At the discretion of the granting authorityResolution No.718

   SPE Santa Cruz Energia S.A

   Santa Cruz(*)

   Minas Gerais

   30 years from December 18, 2002

   At the discretion of the granting authorityResolution No.  13

   SPE São Gonçalo Energia S.A.

   São Gonçalo

   Minas Gerais

   30 years from January 14, 2000

   At the discretion of the granting authorityOrdinance No. 352

   SPE Santa Luzia Energética S.A.

   Santa Luzia

   Santa Catarina

   35 years from December 21, 2007

   At the discretion of the granting authorityResolution No.  355

   SPE Varginha Energia S.A.

   Varginha

   Minas Gerais

   30 years from December 23, 1999

   At the discretion of the granting authorityResolution No.  367

   SPE Várzea Alegre Energia S.A.

   Várzea Alegre

   Minas Gerais

   30 years from December 30, 1999

   At the discretion of the granting authorityOrdinance No.  502

   SPE Boa Vista II Energia S.A.

   Boa Vista II

   Minas Gerais

   35 years from November 09, 2015

   At the discretion of the granting authorityThermoelectric biomass plantsResolution No. 2106

   CPFL Bioenergia

   Baldin Thermoelectric Power Plant

   São Paulo

   30 years from September 24, 2009

   At the discretion of the granting authorityResolution No. 3714

   SPE Alvorada S.A.

   Alvorada Thermoelectric Power Plant

   Minas Gerais

   30 years from October 29, 2012

   At the discretion of the granting authorityResolution 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 authorityResolution No. 3328

   SPE Coopcana S.A.

   Coopcana Thermoelectric Power Plant

   Paraná

   30 years from February 14, 2012

   At the discretion of the granting authorityResolution No.117

   Lacenas Participações Ltda.

   Ester Thermoelectric Power Plant

   São Paulo

   30 years fromMay 21, 1999

   At the discretion of the granting authorityResolution No. 259

   CPFL Bio Formosa S.A.

   Baía Formosa Thermoelectric Power Plant

   Rio Grande do Norte

   30 years fromMay 15, 2002

   At the discretion of the granting authorityResolution 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


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Table of Contents  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 authorityWind farm plantsOrdinance 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 authorityOrdinance 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 authorityOrdinance 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 authorityOrdinance 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 authorityResolution No. 093

   Bons Ventos Geradora de Energia S.A.

   Bons Ventos

   Ceará

   30 years from March 10, 2003

   At the discretion of the granting authorityOrdinance 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 authorityResolution 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 authorityResolution 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 authorityResolution 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 authorityResolution No. 680

   Bons Ventos Geradora de Energia S.A.

   Canoa Quebrada

   Ceará

   30 years from December 11, 2002

   At the discretion of the granting authorityResolution 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 authorityOrdinance 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 authorityResolution No. 625

   Bons Ventos Geradora de Energia S.A.

   Enacel

   Ceará

   30 years from November 13, 2002

   At the discretion of the granting authorityOrdinance 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 authorityOrdinance 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 authorityOrdinance 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 authorityResolution No. 306

   SIIF Cinco Geração e Comercialização de Energia S.A.

   Foz de Choró

   Ceará

   30 years fromJune  05, 2002

   At the discretion of the granting authorityResolution 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 authorityOrdinance No. 556

   SPE Juremas Energia S.A.

   Juremas

   Rio Grande do Norte

   35 years from September 29, 2011

   At the discretion of the granting authorityResolution 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


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Table of Contents  Ordinance No. 557

   Macacos Energia S.A.

   Macacos

   Rio Grande do Norte

   35 years from September 29, 2011

   At the discretion of the granting authorityOrdinance 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 authorityOrdinance 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 authorityOrdinance 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 authorityOrdinance 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 authorityOrdinance 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 authorityOrdinance 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 authorityResolution 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 authorityOrdinance 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 authorityResolution No. 307

   Eólica Formosa Geração e Comercialização de Energia S.A.

   Praia Formosa

   Ceará

   30 years fromJune  05, 2002

   At the discretion of the granting authorityOrdinance No. 609

   Santa Clara I Energia Renováveis Ltda.

   Santa Clara I

   Rio Grande do Norte

   35 years fromJuly 02, 2010

   At the discretion of the granting authorityOrdinance 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 authorityOrdinance No. 610

   Santa Clara III Energia Renováveis Ltda.

   Santa Clara III

   Rio Grande do Norte

   35 years fromJuly 02, 2010

   At the discretion of the granting authorityOrdinance No. 672

   Santa Clara IV Energia Renováveis Ltda.

   Santa Clara IV

   Rio Grande do Norte

   35 years fromJuly 30, 2010

   At the discretion of the granting authorityOrdinance 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 authorityOrdinance No. 670

   Santa Clara VI Energia Renováveis Ltda.

   Santa Clara VI

   Rio Grande do Norte

   35 years fromJuly 30, 2010

   At the discretion of the granting authorityResolution 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 authorityResolution 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 authorityResolution No. 778

   Bons Ventos Geradora de Energia S.A.

   Taíba Albatroz

   Ceará

   30 years from December 24, 2002

   At the discretion of the granting authorityResolution 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


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Table of Contents  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 authorityResolution 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 authorityOrdinance No. 387

   Pedra Cheirosa I Energia S.A.

   Pedra Cheirosa I

   Ceara

   35 years from August 04, 2014

   At the discretion of the granting authorityOrdinance No. 359

   Pedra Cheirosa II Energia S.A.

   Pedra Cheirosa II

   Ceara

   35 years from July 23, 2014

   At the discretion of the granting authorityResolution No. 5074

   São Domingos Energias Renováveis Ltda.

   São Domingos

   Rio Grande do Norte

   30 years from March 3, 201

   At the discretion of the granting authoritySolar power plantsOf.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 and Self-Generators A generation company classified as an Independent Power Producer under Brazilian law receives a concession or authorization to produce energy for sale to local distribution companies, Free Consumers and other types of consumers (excluding Captive Consumers). A generation company classified as a self-generator under Brazilian law receives a concession or authorization to produce energy for its own consumption.  A self-generator may, upon specific authorization by ANEEL, sell or trade any excess energy it is unable to consume. The prices that Independent Power Producers and self-generators may charge for the sale of energy to certain types of consumers are subject to tariffs established by ANEEL, whereas the sale price to other types of consumers can be freely negotiated between the parties. See “—Authorizations”. Concessionaires A company classified as a concessionaire under Brazilian law receives a concession to distribute, transmit or generate electric energy.  Since concessions 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 automatic.  The decision to extend a concession agreement is subject to compliance by the concessionaire with certain requirements and 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, 2015 was R$9,173 million.  No single one of our properties produces more than 10.0% of our total revenues.  Our facilities are generally adequate for our present needs and suitable for their intended purposes.


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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 Federal 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 have implemented an internal management system that complies with best environmental practices in all of our segments.  We have established a process to identify, evaluate and update matters relating to applicable environmental laws, as well as other requirements applicable to our environmental management system.  Additionally, our generation and distribution operating segments are subject to internal audits to ensure they are in compliance with our internal environmental policies, as well as 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, 2015, the Installed Capacity of power generation in Brazil was 140,858 MW.  Historically, approximately 65% 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 130,000 km of transmission lines with voltage equal to or greater than 230 kV and processing capacity of over 315,000 MVA from the state of Rio Grande do Sul through the state of Amazonas. According to the EPE, electricity consumption in Brazil decreased by 2.1% in 2015, reaching 464,700 GWh.  The MME and the EPE estimate that electricity consumption will grow by 4% per year, however, until 2024.  According to the ten-year expansion plan published by the MME and the EPE in order to satisfy this expected growth in demand, Brazil’s Installed Capacity is expected to reach 206.4GW by 2024, of which 117.0 GW


(56.7%) is projected to be hydroelectric, 33.0 GW (16.0%) is projected to be thermoelectric and nuclear and 56.4 GW (27.3%) is projected to be from other renewable sources.   51


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 Currently, approximately 33% 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 third 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 53% of the market.  We are the largest player, with 12.4% 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 member appointed by the MME also acts as Chairman of the Board of Directors.   52


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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 Federal 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 more complex 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 and subject to compliance by the concessionaire with certain requirements. 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.  The administrative 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.   53


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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 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 enabled holders of concessions that were due to expire in 2015, 2016 and 2017 to apply for early renewal, subject to certain conditions.  Renewal of generation concessions 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 established that if generation concessions operated by distribution companies are renewed under Law No. 12,783/13, the generation concession must be managed by an entity that is independent from the distribution company within twelve months after the renewal date.  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”). In the specific case of distribution concessions, in 2015 the Brazilian government enacted Decree No. 8,461/2015 establishing new standards that concessionaires must achieve, mainly regarding quality, management and price.  Within five years after the renewal date, the concessionaire must meet these standards and achieve annual targets.  If the annual targets are not achieved, the concessionaire’s controlling shareholders may be required to make further capital expenditures.  In addition, if the concessionaire fails to meet the annual targets for two consecutive years, or fails to meet any of the required standards at the end of the five-year term, the concession may be terminated or corporate control of the concessionaire may be transferred (see “—Risk Factos— We are uncertain as to the renewal of our concessions and authorizations”). 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 annual revenue (net of value‐added tax and services tax) of the concessionaire or, if the concession in default is non-operative, up to 2.0% of the estimated value of energy that would be produced by the concessionaire in the 12‐month period prior to the breach.  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. See “Item 3.  Key Information—Risk Factors—We may not be able to comply with the terms of our concession agreements, authorizations and permissions, which could result in fines, other penalties and, depending on the gravity of the non compliance, in our concessions or authorizations being terminated”.   54


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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‐generators 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.   55


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 ·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. 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, certain thermo-generation companies and affiliated 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 (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/realexchange 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”.  
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 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’s revenue is guaranteed and the distributors must bear the risk of a supply shortage.  Together, these agreements comprise the CCEARs. 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.  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. Free Consumers are divided into two types: Conventional Free Consumers and Special Free Consumers: ·Conventional Free Consumers are those whose contracted energy demand is at least 3 MW.  These consumers may opt to purchase conventional energy, entirely or partially, from another authorized selling agent under the terms of current legislation.  We refer to consumers who have exercised this option as “Conventional Free Consumers”. ·Special Free Consumers are individual or groups of consumers whose contracted energy demand is between 500 kV and 3 MW.  We refer to consumers who have exercised this option as “Special Free Consumers”.  Special Free Consumers may only purchase energy from renewable sources: (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.  State‐owned generators may sell electricity to Free Consumers; however, unlike private generators, they may only do so through an auction process. ·We also refer to consumers who meet the relevant demand requirement but have not exercised the option to migrate to the free market as “Potential Conventional Free Consumers” or “Potential Special Free Consumers”, as the case may be, and in general as “Potential Free Consumers”. 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 postbasis 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 postvolume 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 antecontract 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.   57


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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 Potential 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 22 auctions for new generation projects, 15 auctions specifically for existing power generation facilities, three auctions for alternative generation projects and nine auctions for biomass and wind power generation, qualified as “reserve energy”.  No later than August 1 of each year, distributors must provide their 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) and a maximum of 35 years for the reserve energy, being usually negotiated for 20-year contracts. 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.  A significant portion of 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.    58


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 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 for electricity 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 spot market will be the lower of the spot price (Preço de Liquidação de Diferenças), or PLD, and the Annual Reference Value. 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$422.56, according to ANEEL’s Resolution 2,002/2015.  Before such Resolution, the maximum value of PLD was R$388.48 (Resolution No. 1,832/2014). 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 transactions in the spot market. 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 currently 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‐generated 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.   59


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 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. 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, the Energy Development Account (Conta 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.    60


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 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. 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 ·irrecoverable 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.   61


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 Electricity distribution concessionaires are entitled to periodic revisions of their tariffs usually 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, ·incentivizing concessionaires to increase their efficiency levels, 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 oan operating expense target. Increases in productivity and the operating expense target are determined at each periodic review. Starting in the fourth periodic revision cicle, the service quality is determined at annual adjustment and periodic review. 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.  As of 2015, ANEEL now reviews the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis, whereas previously all methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.  For information regarding tariff revisions and methodologies, see “Item 5. Operating and Financial Review and Prospects—Background”and “Item 3. Key Information—Risk Factors— 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.”. Since 2013, variables such as the need to dispatch of thermal plants have caused distributors to incur extraordinary costs that exceed their ability to pay.  To cover the distributors’ involuntary exposure to these costs, a portion of the energy cost was reimbursed by the CDE Account (under Decree No. 7,945/2013) and the ACR account (under Decree No. 8,221/2014).  These reimbursements aimed to cover all or part of the costs incurred by distributors between January 2013 and December 2014 relating to (i) their involuntary exposure to the spot market and (ii) the dispatch of thermoelectric plants related to the CCEAR.  The CCEE, which manages the ACR account, obtained a credit facility from 13 banks to fund this payment.  Starting January 2015, distribution companies have been collecting additional electricity tariffs from consumers in order to amortize the CDE reimbursement over five years and the credit facility over 54 months.  The CDE quotas set by ANEEL in 2015 and passed through to consumers already take account of these obligations.  In addition, since these CDE and energy purchase costs remain


high, ANEEL increased tariffs by means of an Extraordinary Tariff Review (RTE) applicable to all distribution companies under Resolution No. 1,858 of February 27, 2015.  This RTE aims to pass through to consumers the forecast costs in the period from March 2015 to the date of the distribution company’s next tariff review or adjustment.   62


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 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.  At the beginning it consisted of a green (normal), yellow (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. As from February 1, 2016, the tariff system flag was modified by ANEEL, and currently consists of a green (normal), yellow (heightened) or two level of red (critical stage 1 and stage 2) tariff flags. 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. Due to the poor hydrological conditions that have been observed since 2013, red tariff flags have been applied from introduction of this system in January 2015 until February 2016. Due to improvement of hydrological conditions observed in the beginning of 2016, yellow tariff flags was applied for the month of March and green tariff flag is currently applied for the month of April. 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 up to 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 offers purchase guarantees of up to 20 years for energy generated from alternative sources, and this energy is acquired by distribution companies for delivery to Final Consumers. The purchase cost of this alternative energy is borne by the Final Consumers on a monthly basis (except for low income Final Consumers, who are exempt from such payments), based on an annual purchase estimation plan made by Eletrobras and approved by ANEEL.  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 starting from 2002. 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 between 3,000 kW and 30,000 kW; (ii) Hydroelectric Power Plants with capacity up to and including 3,000 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.    63


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 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 are 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 service generation companies must make monthly contributions to the RGR Fund at an annual rate equal to 2.5% of the company’s annual investments in fixed assets related to the rendering of public services, 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 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 service 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 the public 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. 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; (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 – System Service Charge 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 System (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.   64


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 Fee for the Use of Water – CFURH 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. ONS Fee The ONS Fee, a monthly fee due by distribution concessionaires, is used to fund the budget of the ONS in its role to coordinate and control the production and transmission of energy in the Interconnected Power System. 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 from Itaipu, 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. 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 (Tarifa de Energia de Otimização, or TEO), which covers the operation and maintenance costs of the plant.  This revenue or additional expense must be accounted for monthly by each generator. Generation Scaling Factor  The Generation Scaling Factor, or GSF, is a ratio that compares the sum of the volume of energy generated by all hydroelectric companies participating in the Energy Realocation Mechanism (Mecanismo de Realocação de Energia, or MRE) to the volume of Assured Energy that they committed to deliver in their contractual obligations.  If the GSF ratio is below 1.0, i.e., less than the total Assured Energy is being generated, hydroelectric companies must purchase energy in the spot market to cover the energy shortage and meet their Assured Energy volumes under the MRE.  From 2005 to 2012, the GSF remained above 1.0.  The GSF began to deteriorate in 2013, worsening in 2014 when the GSF remained below 1.0 for the entire year.  In 2015, the GSF ranged from 0.783 to 0.825, requiring  electricity generators to purchase energy in the spot market, thereby incurring significant costs.    65


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 Following discussions between generation companies and the Brazilian government regarding these costs, the government enacted Federal Law 13,203 on December 8, 2015.   This law addressed the GSF risk separately for the Regulated Market and the Free Market.  In the Regulated Market, Federal Law 13,203 allowed generation companies to renegotiate their power purchase agreements, setting the GSF cost at a risk premium of R$9.50/MWh per year through the end of the power purchase agreement or the end of the concession, whichever occurs sooner.  This risk premium payment will be paid to the Centralizing Account of the Resources from the Tariff Flags (Conta Centralizadora dos Recursos de Bandeiras Tarifárias, or CCRBT).  In December 2015, our subsidiaries Ceran, CPFL Jaguari Geração (Paulista Lajeado) and CPFL Renováveis, as well as joint ventures ENERCAN and Chapecoense opted to renegotiate their ACR contracts, and also cancelled their lawsuits. Therefore, the hydrologic risks were transferred to the Centralizing Account of the Resources from the Tariff Flags (Conta Centralizadora dos Recursos de Bandeiras Tarifárias, or CCRBT). For further information regarding the GSF and Federal Law 13,203, see note 28.2 to our audited annual consolidated financial statements.  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 annual 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 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 2015, ANEEL set a new methodology for the fourth cycle of periodic reviews.  For CPFL Piratininga, which had its periodic review in October 2015, tariffs were increased.  For CPFL Santa Cruz, CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista and CPFL Mococa, which had their periodic reviews in March 2016, average tariffs were also increased.  Periodic tariff reviews will be held for CPFL Paulista in April 2018 and for RGE in June 2018.  See “—Background—Periodic Revisions —RTP”. In March 2012, through our subsidiary CPFL Renováveis, we purchased 100% of the shares of the Atlântica I, Atlântica II, Atlântica IV and Atlântica V wind generation plants, which have an aggregate Installed Capacity of 120 MW.  The Atlântica Complex commenced operations in March 2014. 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 and has aggregate Installed Capacity of 157.5 MW.   66


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 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 an authorization from ANEEL to exploit electric energy from sugar cane biomass and has 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. 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 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 the Rosa dos Ventos wind farms (the Canoa Quebrada and Lagoa do Mato fields), with 13.7 MW of Installed Capacity.  In June 2014, the Macacos Complex (composed of the Macacos, Juremas, Pedra Preta and Costa Branca Wind Farms), commenced operations with 78.2 MW of Installed Capacity. In February 2014, CPFL Renováveis entered into an agreement with 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 15.4.2 to our audited annual consolidated financial statements. In April 2015, the Morro dos Ventos II Wind Farm commenced operations, with Installed Capacity of 29 MW.  Also in April 2015, at the A-5/21st New Energy Auction, CPFL Renováveis traded an average of 14.0 MW of contracted energy to be generated by Boa Vista II SHPP, located in the state of Minas Gerais, with 27 MW of Installed Capacity.  The contract obtained with the trade will be executed with the distribution companies that participated as energy purchasers in the auction.  The duration of the contract will be 25 years, with energy supply commencing on January 1, 2020.  The traded energy was sold at an average price of R$207.64 per MWh, with annual adjustments to be made in accordance with the IPCA. We expect the Mata Velha and Boa Vista II SHPPs and the Campo dos Ventos, São Benedito and Pedra Cheirosa wind complexes to become operational by 2020, increasing our Installed Capacity (after accounting for the decrease in our stake in CPFL Renováveis as a result of the acquisition of DESA in October 2014) to 3,301 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 2015, sales to Captive Consumers represented 69.7% of the volume of electricity we delivered and 65.7% of our


operating revenues, compared to 69.8% and 67.3%, respectively, in 2014.  These proportions may decline if consumers migrate from captive to free status.   67


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 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”. 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 as from February 2016, every March for CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari (prior to February 2016, the tariff adjustments for these distribution concessionaries occurred every February).  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, , CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari and RGE and every four years for CPFL Piratininga in order 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 to be applied to the third periodic revision cycle (2011 to 2014). As of 2015, ANEEL now reviews the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis, whereas previously all methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.  For additional information, see “Item 3.  Risk Factors— 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” 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, 2015.  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 take into account the extraordinary costs due to the full dispatch of thermal plants and distributors’ involuntary exposure.   68


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 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 2012 through the date of this annual report.  Rates of tariff increase should be evaluated in light of the Brazilian inflation rate.  See “—Background—Brazilian Economic Conditions”. CPFL Paulista

   CPFL Piratininga

   RGE

   CPFL Santa Cruz

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul Paulista

   CPFL Jaguari2012Economic 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%2013Economic 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%2014Economic 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%2015Economic adjustment(1)

   37.31%

   40.14%(4)

   -8.07%

   22.01%

   28.90%

   28.82%

   30.24%

   40.07%Regulatory adjustment(2)

   4.14%

   16.15%(4)

   4.31%

   12.67%

   ‐5.55%

   ‐8.02%

   ‐5.36%

   ‐1.61%Total adjustment

   41.45%

   56.29%(4)

   -3.76%

   34.68%

   23.34%

   20.80%

   24.88%

   38.46%2016Economic adjustment(1)

   -0.29%

   (3)

   (3)

   11.59%(5)

   11.90%(5)

   17.01%(5)

   16.89%(5)

   17.01%(5)Regulatory adjustment(2)

   10.18%

   (3)

   (3)

   10.92% (5)

   4.67%(5)

   4.03%(5)

   7.46%(5)

   12.45%(5)Total adjustment

   9.89%

   (3)

   (3)

   22.51%(5)

   16.57%(5)

   21.04%(5)

   24.35%(5)

   29.46%(5)
  
 (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 RGE and CPFL Piratininga occur in June and October, respectively. (4)   Represents the effect of Periodic Revisions — RTP for CPFL Piratinga that occurred in 2015, considering that there is no Annual Adjustment – RTA in the year of Periodic Revisions – RTP. (5)   On February 3, 2016, ANEEL changed the annual adjustment period for CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari to March every year.    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 method of recognizing which costs we may pass through to our consumers.  In addition, ANEEL approved the 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 methodology negatively impacted our financial condition and results of operations. On April 28, 2015, ANEEL established the methodology to be applied in the fourth periodic revision cycle (2015 to 2016) through Resolutions Nos. 648/2015, 649/2015, 650/2015, 652/2015, 657/2015, 660/2015, 682/2015, 685/2015 and 686/2015.  The fourth cycle maintains most of the parameters used for the third cycle, such as the definition, by ANEEL, of the costs we may pass to our consumers.  Some of the changes for the fourth cycle include a tariff incentive to the development of certain public policies and also the increased importance of the X Factor


component in the new tariff formula. Compared to the previous tariff cycle, the new methodology has positively impacted our financial condition and results of operations.  
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 As of 2015, ANEEL now reviews the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis, whereas previously all methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014. The following table sets forth the percentage change in our tariffs resulting from the first, second, third and fourth cycles of periodic revisions. First cycle

   Second cycle

   Third cycle

   Fourth cycleAdjustment date

   Economic adjustment

   Adjustment date

   Economic adjustment

   Adjustment date

   Economic adjustment

   Adjustment date

   Economic adjustment(%)

   

   (%)

   

   (%)

   

   (%)CPFL Paulista...

   April 2003

   20.66

   April 2008

   ‐14.00

   April 2013

   4.67(3)

   April 2018

   (4)CPFL Piratininga........

   October 2003

   10.14

   October 2007

   ‐12.77

   October 2011

   ‐3.95(1)(3)

   October 2015

   40.14RGE.................

   April 2003

   27.96

   April 2008

   2.34

   June 2013

   -10.27(3)

   June 2018

   (4)CPFL Santa Cruz.................

   February 2004

   17.14

   February 2008

   ‐14.41

   February 2012

   4.16 (1)(2)

   March 2016

   11.59CPFL Mococa..

   February 2004

   21.73

   February 2008

   ‐7.60

   February 2012

   7.18 (1)(2)

   March 2016

   11.90CPFL Leste Paulista............

   February 2004

   20.10

   February 2008

   ‐2.18

   February 2012

   ‐2.00 (1)(2)

   March 2016

   17.01CPFL Sul Paulista............

   February 2004

   12.29

   February 2008

   ‐5.19

   February 2012

   ‐4.48 (1)(2)

   March 2016

   16.89CPFL Jaguari....

   February 2004

   ‐6.17

   February 2008

   ‐5.17

   February 2012

   ‐7.15 (1)(2)

   March 2016

   17.01
  
 (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 -4.41% to ‐4.48 % for CPFL Sul Paulista, mainly because of a RAB reduction; and (v) Dispatch No. 167 of January 28, 2014 alters the tariff revision index of CPFL Jaguari only to the part relating to financial components, 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 4.53% to 4.67%.  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 ‐10.66% to ‐10.27%. (4)   The fourth cycle of periodic revisions for CPFL Paulista and RGE will take place in April and June 2018, respectively. 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 subsidiaries: CPFL Paulista

   CPFL Piratininga

   RGE

   CPFL Santa Cruz

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul Paulista

   CPFL Jaguari2013Economic 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%
  
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 Pursuant to Resolution No. 1,858/2015, tariffs were increased as follows to take into account the extraordinary costs incurred by the distribution companies due to full dispatch of thermal plants: CPFL Paulista

   CPFL Piratininga

   RGE

   CPFL Santa Cruz(1)

   CPFL Mococa(1)

   CPFL Leste Paulista(1)

   CPFL Sul Paulista(1)

   CPFL Jaguari(1)2015Economic adjustment

   0.0%

   0.0%

   0.0%

   0.0%

   0.0%

   0.0%

   0.0%

   0.0%Regulatory adjustment

   32.28%

   29.78%

   37.16%

   5.16%

   11.81%

   14.52%

   17.02%

   16.80%Total adjustment

   32.28%

   29.78%

   37.16%

   5.16%

   11.81%

   14.52%

   17.02%

   16.80%
  (1)   On April 07, 2015 ANEEL changed, through Resolution No. 1,870/2015, the Extraordinary Tariff Review – RTE of the distributors CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari, CPFL Mococa and CPFL Santa Cruz. This correction was necessary to change the value of the monthly quotas of CDE – energy related to ACR, intended for repayment of loans contracted by CCEE in the management of ACR account. The rates resulting from this rectification entered into force on April 8, 2015. Sales to Potential Free Consumers Brazilian regulations permit Potential Free Consumers to opt out of the Regulated Market and become Free Consumers who contract freely for electricity.   See “Item 4. Information on the Company—The New Industrial Model Law—The Free Market”.  Our Potential Free Consumers represent a relatively small portion of our total revenues, as compared to our Captive Consumers.  These revenues consist of energy sales and TUSD network charges.  If a Potential Free Consumer migrates from the Regulated Market and purchases energy in the Free Market, we no longer receive the energy sales revenues, but the Free Consumer is still required to pay us the TUSD network usage charge for their energy.  Regarding the reduction in energy sales revenues, we are able in some cases to reduce our energy purchases by the amount required to service these customers in the year of the consumer’s migration, while in other cases we are able to offset the excess by adjusting our energy purchases in future years.  Accordingly, we do not believe that the loss of Potential Free Consumers would have a material adverse effect on our results of operations. Historically, relatively few of our Potential Free Consumers have 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 Potential 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.  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 long-term implications for our financial results, are difficult to predict. 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 2015, we purchased 58,607 GWh, compared to 58,879 GWh in 2014.  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 2015, we purchased 10,261 GWh of electricity from Itaipu (17.5% of the electricity we purchased in terms of volume), as compared to 10,417 GWh (17.7% of the electricity we purchased in terms of


volume) in 2014.  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.  
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 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 (the Parcel A cost variation 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 set in U.S. dollars and are therefore subject to U.S. dollar exchange rates.  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”. 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) usually 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.  Furthermore, since January 2015, the electricity sector has implemented 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.  For further information on the tariff flags system, see“Item 4.  Information on the Company—The Brazilian Power Industry—Basis of Calculation of Distribution Tariffs”. 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 createsa 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 (see note 8 to our audited annual consolidated financial statements).  This leads to an adjustment to recognize the future increase (or decrease) in tariffs to take account of additional (or lower) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue recorded as Sector Financial Assets or Liabilities. On November 25, 2014, ANEEL approved an amendment to distribution concession contracts.  On December 10, 2014, our 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 (or 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.  
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 Operating Segments As discussed in note 31 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. In addition to our five operating segments above, we consolidate a number of activities known as “Other”.  The activities consolidated under Other consist of (i) two transmission assets held through CPFL Geração, of which one (CPFL Piracicaba) is operational and the other (CPFL Morro Agudo) is under construction, (ii) CPFL Telecom and (iii) our holding company expenses other than the amortization of intangible assets related to our concessions, which is allocated to our operational segments. 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 82.0% of our net operating revenue (79.0% in 2014), but its contribution to our net income was smaller in 2015 at 71.5% of our net income for the year (by comparison, our distribution activities accounted for 95.3% of our net income in 2014 and 76.5% in 2013). 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, 2015, 2014 and 2013 are presented in the following table: Distribution

   Conventional Generation

   Renewable Generation

   Commercialization

   Services2015Net operating revenue

   82.0%

   4.9%

   7.9%

   8.9%

   1.5%Net income

   71.5%

   32.3%

   -6.4%

   10.1%

   5.9%2014Net operating revenue

   79.0%

   6.9%

   8.0%

   12.6%

   2.0%Net income

   95.3%

   12.2%

   -19.0%

   15.3%

   3.2%2013Net operating revenue

   79.1%

   6.3%

   7.4%

   12.6%

   1.4%Net income

   76.5%

   32.9%

   -5.8%

   3.8%

   1.7%
  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, Small Hydroelectric Power Plants and a solar power plant.  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, 2015, our Renewable Generation Sources segment provided 7.9% of our operating income, but due to the significant financing costs incurred to finance these projects, the segment’s contribution to net income was negative (-6.4%). As of December 31, 2015, 8.9% 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 anotherwithin a segment, 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 elimination were carried through with respect to sales between segments.  As a result, sales from one segment to another have not been eliminated in the discussion of results by segment below.  We present below selected financial information of our five reportable segments as of and for the years ended December 31, 2015, 2014 and 2013:
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Table of Contents Distribution

   Conventional generation sources

   Renewable generation sources

   Commercialization

   Services

   Other (*)

   Elimination

   Total2015Net Revenue

   16,551,879

   572,553

   1,262,297

   1,716,348

   55,547

   47,246

   -

   20,205,869(-) Inter-segment Revenues

   22,318

   411,038

   335,979

   82,544

   239,088

   3,136

   (1,094,101)

   -Income from electric energy service

   1,163,426

   542,738

   460,772

   124,933

   30,617

   (70,396)

   -

   2,252,090Financial income

   1,155,428

   110,018

   131,354

   42,840

   44,098

   74,310

   -

   1,558,047Financial expense

   (1,278,258)

   (549,286)

   (599,303)

   (38,386)

   (4,858)

   (102,477)

   -

   (2,572,567)Income before taxes

   1,040,597

   320,354

   (7,176)

   129,386

   69,857

   (98,563)

   -

   1,454,454Income tax/social contribution

   (414,633)

   (37,570)

   (49,222)

   (41,282)

   (18,232)

   (18,239)

   -

   (579,177)Net Income

   625,964

   282,783

   (56,398)

   88,104

   51,625

   (116,802)

   -

   875,277Total Assets(**)

   22,138,086

   4,575,230

   11,868,943

   714,781

   317,845

   917,586

   -

   40,532,471Capital Expenditures and other intangible assets

   868,495

   6,910

   493,584

   2,432

   39,176

   17,199

   -

   1,427,796Depreciation and Amortization

   (587,059)

   (131,969)

   (540,578)

   (4,534)

   (12,633)

   (3,128)

   -

   (1,279,902)2014Net 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)

   -

   2,540,073Financial income

   552,918

   84,884

   98,991

   29,543

   6,380

   117,720

   -

   890,436Financial 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)

   -

   1,510,304Income 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)

   -

   886,443Total Assets(**)

   16,724,269

   4,414,196

   11,647,374

   507,960

   828,184

   1,022,454

   -

   35,144,436Capital Expenditures and other intangible assets

   702,386

   14,419

   250,803

   3,531

   90,707

   22

   -

   1,061,868Depreciation and Amortization

   (577,753)

   (136,447)

   (432,267)

   (4,471)

   (8,760)

   (265)

   -

   (1,159,964)


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Table of Contents  Distribution

   Conventional generation sources

   Renewable generation sources

   Commercialization

   Services

   Other (*)

   Elimination

   Total2013Net 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)

   -

   2,369,775Financial income

   504,463

   40,005

   55,083

   27,665

   13,876

   58,115

   -

   699,208Financial 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)

   -

   1,519,200Income 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)

   -

   949,036Total Assets(**)

   15,263,417

   4,515,880

   9,470,564

   342,516

   243,612

   1,206,806

   -

   31,042,796Capital Expenditures and other intangible assets

   844,804

   9,744

   827,704

   3,593

   48,646

   345

   -

   1,734,836Depreciation and Amortization

   (564,538)

   (133,514)

   (348,355)

   (4,106)

   (4,632)

   (86)

   -

   (1,055,231)
 
 (*)   Refers to recorded assets and transactions that are not related to any of our operating segments. (**) Intangible assets (net of amortization) recorded at the parent company level, were allocated to their respective segments.


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 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 segment 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. See “Item 3. Information on the Company—Risk Factors—Risks Relating to Brazil”. 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 are primarily indexed to the variation of the SELIC rate until they are 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”). 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, 2015, 2014 and 2013: 2015

   2014

   2013Growth in GDP (in reais)

   (3.8%)

   0.2%

   2.3%Unemployment rate ‐ % average(1)

   8.5%

   6.8%

   7.1%Credit to individuals (non‐earmarked resources) ‐ % GDP

   13.5%

   15.1%

   15.5%Growth in Retail Sales

   (4.0%)

   2.2%

   4.3%Growth (contraction) in Industrial Production

   (8.1%)

   (3.2%)

   1.1%Inflation (IGP‐M)(2)

   10.5%

   3.7%

   5.5%Inflation (IPCA)(3)

   10.7%

   6.4%

   5.9%Average exchange rate–US$1.00(4)

   R$3.339

   R$2.360

   R$2.174Year‐end exchange rate–US$1.00

   R$3.905

   R$2.656

   R$2.343Depreciation (appreciation) of therealvs. U.S. dollar

   47.0%

   13.4%

   14.6%
  
 Sources:Fundação Getúlio Vargas, the Instituto Brasileiro de Geografia e Estatísticaand the Brazilian Central Bank. (1)   Unemployment rate considering the National Household Sampling Survey (Pesquisa Nacional por Amostra de Domicílios, or PNAD), released by the Instituto Brasileiro de Geografia e Estatística (IBGE). (2)   Inflation (IGP‐M) is the general market price index measured by the Fundação Getúlio Vargas. (3)   Inflation (IPCA) is a broad consumer price index measured by the Instituto Brasileiro de Geografia e Estatística (IBGE) and the reference for inflation targets set forth by the Brazilian Monetary Council (Conselho Monetário Nacional, or CMN). (4)   Represents the average of the commercial selling exchange rates on the last day of each month during the period.


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 The Brazilian economic environment has been characterized by significant variations in economic growth rates, with 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.  In the following years, Brazilian economic activity recorded moderate results due to lower exports, unfavorable investor expectations and infrastructure deficiencies.  GDP grew at an average rate of 2.1% between 2009 and 2014.  In 2015 GDP contracted by approximately 3.8% as reductions in demand, combined with unfavorable political conditions aggravated by allegations of corruption, impacted economic activity.  These conditions also led to a significant devaluation of the Brazilianreal.  Standard & Poor’s downgraded Brazil below investment grade on September 9, 2015; Fitch Ratings lowered its rating for Brazil from BBB- to BB+ on December 16, 2015; and Moody’s Investors Service downgraded Brazil to Ba2 with negative outlook on February 24, 2016. These downgrades reflected the poor economic conditions, continued adverse fiscal developments and increased political uncertainty in Brazil. Our credit risk and debt securities are rated by Standard and Poor’s and Fitch Ratings.  These ratings reflect, among other factors, perspectives for the Brazilian electricity sector, the political and economic context, country risk, hydrological conditions in the areas where our power plants are located, our operational performance and debt levels, and the ratings and outlook of our controlling shareholders.  Our ratings were reduced in 2015 from AA+ to AA as a result of the downgrade of Brazil investment grade, due to changes in its economic and political scenarios as stated in the paragraph above.  Downgrades can increase our cost of capital and lead lenders to include additional financial covenants in the instruments that regulate our debt. In addition, income, employment, retail sales, especially household appliances, and credit availability, which are key indicators for energy consumption, posted poor performance in 2015.  The behavior of the domestic market, reflecting deteriorations in the labor market and household consumption, negatively affected our operations. Results of Operations—2015 compared to 2014 Net Operating Revenues Compared to the year ended December 31, 2014, our net operating revenues increased 16.8% (or R$2,900 million) in the year ended December 31, 2015, amounting to R$20,206 million.  The increase in operating revenue primarily reflected an increase in the average overall tariff adjustment, which combines the RTA, Tariff Flags and RTE effects on our distribution subsidiaries, applying particularly to electricity sales to Captive Consumers and TUSD revenue from Free Consumers in our concession areas.  In addition, we recognized an increase of R$1,596 million in revenue related to Sector Financial Assets and Liabilities, which equaled R$2,507 million in 2015 compared with R$911 million in 2014.  This revenue reflects timing differences between our budgeted costs included in the tariff at the beginning of the tariff period, and those actually incurred while it is in effect, creating a 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 (see note 8 to our audited annual consolidated financial statements).  This leads to an adjustment to recognize the future increase (or decrease) in tariffs to take account of additional (or lower) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue.  The increase in this item in 2015 was principally driven by the depreciation of thereal, leading to a future adjustment in tariffs to take account of the increased expenses in purchasing energy (in U.S. dollars) from the Itaipu generation facility. Net operating revenue for the year ended December 31, 2015, includes the net operating revenue from the assets acquired from WF2 (DESA) for the full twelve months, while net operating revenue for the year ended December 31, 2014 only includes net operating revenue from these assets for three months, as they were acquired in the fourth quarter of 2014.  Also included in net operating revenue are the revenues relating to the construction of concession infrastructure in the amount of R$1,047 million in the year ended December 31, 2015, which did not affect our results of operations, due to corresponding costs in approximately 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.


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 Sales by Destination Sales to Final Consumers Compared to the year ended December 31, 2014, our gross operating revenues from sales to Final Consumers (which includes TUSD revenue from captive consumers) increased 49.7% (or R$7,777 million) in the year ended December 31, 2015, to R$23,425 million. Our gross operating revenues primarily reflect sales to Captive Consumers in concession areas from our eight distribution subsidiaries as well as well as TUSD revenue from the use of our network by Captive Consumers, both being subject to tariff adjustment, as described below. Distribution companies’ tariffs are adjusted every year, in percentages specific to each category of consumer.  The month in which the tariff adjustment becomes effective varies. The adjustment for the largest subsidiaries occurred in April (CPFL Paulista), June (RGE) and October (CPFL Piratininga).  In the year ended December 31, 2015, energy prices increased by an average of 56.8%, mainly due to the positive average overall tariff adjustment of our distribution subsidiaries (consisting of RTA, Tariff Flags and RTE effects).  See note 27 to our audited annual consolidated financial statements.  Average prices for Final Consumers in 2015 were higher for all consumer categories: ·Residential and commercial consumers.  With respect to Captive Consumers (which represent 99.7% of the total amount sold to this category in our consolidated statements), average prices increased 53.6% for residential and 54.9% for commercial, due to the positive average overall tariff adjustment, as described above.  With respect to Free Consumers (which comprises only commercial consumers) the average price increased 31.6%. ·Industrial consumers.  Average prices increased 60.2% for Captive Consumers, mainly due to tariff adjustments, as described above.  With respect to Free Consumers, the average price for industrial consumers increased 42.8%.  The increase in the average price for industrial consumers was due to the tariff increase, which resulted from annual adjustment to tariffs in 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, 2015 decreased 4.5% compared to the year ended December 31, 2014.  The volume sold to residential and commercial categories, which accounts for 64.5% for our sales to Final Consumers, decreased 2.0% and 1.9%, respectively.  These decreases are a result of an increase in unemployment, decreasing real incomes and an increase in electricity tariffs.  Our results in these categories were also adversely affected by milder temperatures throughout the year. The volume sold to industrial consumers, which represented 23.6% of our sales to Final Consumers in 2015 (compared with 24.7% in 2014), decreased by 9.9% in the year ended December 31, 2015 compared to the year ended December 31, 2014.  Volumes to Captive Consumers in this category decreased 7.3%, while those in the Free Market decreased 14.4%, reflecting weaker performance in Brazilian economic activity, the recent decline in confidence in the Brazilian industrial sector and increased inventory held by Brazilian companies throughout the year.  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 consolidated financial statements under “Other Operating Revenues”. Sales to wholesalers Compared to the year ended December 31, 2014, our gross operating revenues from sales to wholesalers increased 12.5% (or R$392 million) to R$3,537 million in the year ended December 31, 2015 (10.4% of gross operating revenues), due mainly to an increase of 31.5% (or R$533 million) in sales of electricity to other concessionaires and licensees, composed of an increase of 10.7% in the volume sold and 18.8% in the average price.  This increase was offset by a decrease of 10.4% (or R$101 million) in sales of energy in the spot market, which represents the net effect of an increase of 82.2% in the volume of energy sold and a decrease of 50.8% in the average price compared to 2014.  The decrease of the average price can be explained by the decrease in the PLD ceiling price approved by ANEEL in 2015, which was R$388.48/MWh in 2015 compared to R$822.83/MWh in 2014.  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, 2014, our other gross operating revenues (which excludes TUSD revenue from captive consumers) increased 70.0% (or R$2,757 million) in the year ended December 31, 2015 to R$6,697 million (19.8% of our gross operating revenues), mainly due to: (i) the increase of R$1,596 million in revenue from Sector Financial Assets and Liabilities described above; (ii) an increase of 91.6% (or R$907 million) in TUSD revenue from the use of our network by Free Consumers that purchase electricity from other suppliers due to annual tariff adjustment on such contracts; (iii) the increase of 16.2% (or R$125 million) in revenue 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 10.8% (or R$102 million) in revenue from construction of concession infrastructure. 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) is calculated based on gross operating revenue from final consumers (billed), while federal PIS and COFINS taxes are calculated based on total gross operating revenue. The research and development and energy efficiency programs (regulatory charges) are calculated based on net operating revenue.  Other regulatory charges vary depending on the regulatory effect reflected in our tariffs.  These deductions represented 40.4% of our gross operating revenue in the year ended December 31, 2015 and 24.1% in the year ended December 31, 2014.  Compared to the year ended December 31, 2014, these deductions increased by 149.6% (or R$8,213 million) to R$13,703 million in 2015, mainly due to: (i) an increase of R$3,698 million in contributions made to the CDE Account as a result of the new quotas defined by ANEEL in 2015 (see note 27.6 to our audited annual consolidated financial statements); (ii) an increase of R$1,796 million in tariff flag revenues recognized in 2015, which are required to be paid into the Tariff Flag Resources Centralizing Account administered by the CCEE; (iii) an increase of 50.8% (or R$1,579 million) in ICMS, as a result of the rise of in our billed supply and; (iv) an increase of 57.5% (or R$1,084 million) in PIS and COFINS, mainly due to the increase in our gross operating revenues (the calculation base for these taxes). Sales by segment Distribution Compared to the year ended December 31, 2014, net operating revenues from our Distribution segment increased 21.2% (or R$2,896 million) to R$16,574 million in the year ended December 31, 2015.  This increase primarily reflected: (i) an increase related to annual tariff adjustments of our distribution subsidiaries due to the combined effect of RTA, Tariff Flags and RTE effects, which increased electricity sales to Captive Consumers in our concession areas by R$7,564 million; (ii) the R$1,596 million increase in the Sector Financial Assets and Liabilities item described above; (iii) an increase of R$911 million in TUSD revenue from the use of our network by Free Consumers that purchase electricity from other suppliers; (iv) an increase of R$620 million in sales to wholesalers, driven by an increase of 125.1% in the volume of energy sold in the spot market to other concessionaires and licensees, offset by a reduction of 38.7% in the average price; (v) an increase of R$132 million in revenue from construction of concession infrastructure and; (vi) an increase of R$125 million in revenue related to the low-income subsidy and discounts on tariffs reimbursed by funds from the CDE Account. Those increases were partially offset by an increase of R$8,210 million in deductions from operating revenues, mainly due to: (i) an increase of R$3,698 million in contributions made to the CDE Account due to new quotas defined by ANEEL in 2015 (see note 27.6 to our audited annual consolidated financial statements); (ii) the increase of R$1,796 million relating to the tariff flag revenues recognized in 2015, which are required to be paid into the Tariff Flag Resources Centralizing Account administered by the CCEE; (iii) an increase of 51.7% (or R$1,574 million) in ICMS, as a result of the increase in our billed supply and; (iv) an increase of 69.5% (or R$1,093 million) in PIS and COFINS, mainly due to the increase in our gross operating revenues (the calculation base for these taxes).


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 Generation (conventional sources) Net operating revenues from our Generation from Conventional Sources segment in the year ended December 31, 2015 amounted to R$984 million, a decrease of 17.4% (or R$207 million) compared to R$1,190 million in the year ended December 31, 2014.  This decrease was mainly due to: (i) a decrease of 92.0% (R$136 million) in revenue from energy sold in the spot market (which is the aggregated effect of a decrease of 13.0% in the volume sold in this period and a decrease of 90.8% in the average price).  This revenue comprises energy sold to other MRE participants who have not generated energy at their Assured Energy levels, as well as energy sold to parties who are not MRE participants.  For the year ended December 31, 2015, approximately 99% of the energy available to the spot market was sold to MRE participants, for which the tariff is fixed on an annual basis by ANEEL.  This tariff, known as Energy Optimization Tariff (Tarifa de Energia de Otimização, or TEO) was R$11.25/MWh for the year ended December 31, 2015.  For further details about MRE, see “Regulatory Charges—Energy Reallocation Mechanism” and; (ii) a decrease of 12.7% (or R$83 million) in sales to our distribution subsidiaries, which represents the net effect of an increase of 20.1% in the volume sold offset by a decrease of 27.3% in the average price of energy sold in this period. Generation (renewable sources) Net operating revenues from our Generation from Renewable Sources segment in the year ended December 31, 2015 amounted to R$1,598 million, an increase of 15.8% (or R$218 million) compared to R$1,380 million in the year ended December 31, 2014.  This increase was mainly due to: (i) an increase of 11.7% (R$162 million) in energy sold to other concessionaires and licensees, which reflects an increase of 9.8% in the volume and 1.8% in the average price of energy sold; (ii) an increase of R$31 million in other operational revenues  derived from insurance claims paid out to CPFL Bio Pedra, CPFL Coopcana and CPFL Alvorada; (iii) an increase of 17.3% (R$15 million) in revenue from energy sold in the spot market, which reflects an increase of 89.0% in the volume of energy sold offset by a decrease of 38.0% in the average price and; (iv) an increase of R$13 million in revenue from Free Consumers (Industrial and Commercial classes), to whom 37,656 MWh was sold in the year ended December 31, 2015, compared to no revenues in this category in the year ended December 31, 2014.  The increase of volume of energy sold mentioned in items (i) and (iii) reflects the acquisition of assets from WF2 (DESA) in the last quarter of 2014 and the commencement of operations at Morro dos Ventos II wind farm in April 2015. Commercialization Net operating revenues from our Commercialization segment in the year ended December 31, 2015 amounted to R$1,799 million, a decrease of 17.4% (or R$380 million) compared to R$2,179 million in the year ended December 31, 2014.  This decrease was mainly due to: (i) a decrease of 77.5% (or R$547 million) in revenue from sales to the CCEE, which reflects the decrease in the volume (28.8%) and average price (68.4%) of energy sold in comparison with the year ended December 31, 2014 and; (ii) a decrease of 6.6% (or R$54 million) in revenue from sales to other concessionaires and licensees, which is the result of a decrease of 30.8% in the average price offset by an increase of 34.9% in the volume of energy sold.  Those decreases were partially offset by (i) an increase of 22.2% (or 193 million) in revenue from Industrial Free Consumers, which reflects an increase of 42.8% in the average price offset by a reduction of 14.4% in the volume of energy sold and; (ii) a reduction of R$39 million in deductions from operating revenues (PIS and COFINS taxes), mainly due to the decrease in our gross operating revenues (the calculation base for these taxes). Services Net operating revenues from our Services segment in the year ended December 31, 2015 amounted to R$295 million, a decrease of 14.5% (or R$50 million) compared to R$345 million in the year ended December 31, 2014.  This decrease was mainly due to a decrease of R$68 million in revenue from construction contracts.  In addition, revenues from leasing and renting activities recorded a decrease of 80.6% (or R$10 million).  These decreases were offset by an increase of 7.0% (or R$20 million) in revenue from sales of products and services.


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 Income from Electric Energy Service by Destination Following discussions between generation companies and the Brazilian government regarding exposure to spot market costs under the GSF, the government enacted Federal Law 13,203 on December 8, 2015.   In the Regulated Market, Federal Law 13,203 allowed generation companies to renegotiate their concessions, setting the GSF cost at a risk premium of R$9.50/MWh per year through the end of the power purchase agreement or the end of the concession, whichever occurs sooner.  In December 2015, subsidiaries Ceran, CPFL Jaguari Geração (Paulista Lajeado) and CPFL Renováveis, as well as joint ventures ENERCAN and Chapecoense opted to renegotiate their ACR contracts, and also cancelled their lawsuits. Under the terms of the renegotiation, the hydrologic risks were transferred to the Centralizing Account of the Resources from the Tariff Flags (Conta Centralizadora dos Recursos de Bandeiras Tarifárias, or CCRBT). For further information regarding the GSF and Federal Law 13,203, see “Item 4.  Information on the Company—The Brazilian Power Industry—Generation Scaling Factor” and note 28.2 to our audited annual consolidated financial statements.  Cost of Electric Energy Electricity purchased for resale.  Compared to the year ended December 31, 2014, our costs to purchase energy for resale increased 16.6% (or R$1,689 million) in the year ended December 31, 2015, to R$11,847 million (66.0% of our total operating costs and operating expenses) from R$10,158 million for the year ended December 31, 2014 (representing 68.8% of our total operating costs and operating expenses), mainly due to an increase of 17.2% in the overall average price, reflecting: (i) an increase of R$1,486 million in purchases of energy from Itaipu reflecting an increase of 110.5% in the average price of energy purchased (inreais), caused by the average depreciation of 41.8% of therealagainst the U.S. dollar during 2015 and the increase of 46.1% of the tariff (which is established on an annual basis by ANEEL in US$/kW), offset by a 1.5% decrease in the volume of energy purchased; (ii) a decrease (which represents an increase of Cost of Electric Energy) of R$2,341 million in reimbursement of costs by the CDE Account in comparison with the year ended December 31, 2014; (iii) an increase of 4.0% (or R$355 million) in the cost of energy purchases in the Regulated Market, which represents the net effect of an increase of 4.7% in the volume of the energy purchased offset by a reduction of 0.7% in the average price. These increases were partially offset by: (i) a decrease of 76.0% (or R$2,294) million in cost from energy purchased in the Free Market (reflecting a decrease of 41.9% in the volume and 58.7% in the average price of energy purchased) and; (ii) an increase of R$257 million (or 19.1%) in tax credits (PIS and COFINS) from purchases of energy. Electricity network usage charges.  Compared to the year ended December 31, 2014, our charges for the use of our transmission and distribution system increased 201.7% (or R$979 million) to R$1,465 million in the year ended December 31, 2015, mainly as a result of: (i) an increase of R$882 million in the System Service Charges; (ii) an increase of R$ 120 million in the Basic Network Charges and; (iii) an increase of R$44 million in Reserve  Energy Charges.  These increases were offset by an increase of R$98 million in tax credits from network usage charges.  For further information about electricity network usage charges, see the explanatory note 28 to our audited annual consolidated 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.


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 Compared to the year ended December 31, 2014, our other costs and operating expenses increased 12.6% (or R$519 million) to R$4,642 million in the year ended December 31, 2015, mainly due to the following events: (i) an increase of R$103 million (or 10.9%) in expenses related to the construction of concession infrastructure; (ii) an increase of  R$102 million (or 11.7%) in depreciation and amortization expenses; (iii) an increase of R$87 million in personnel expenses under our collective bargaining agreements as well as an increase of 8.3% in our number of employees; (iv) an increase of R$71 million (or 36.9%) in legal, judicial and indemnity expenses; (v) an increase of R$43 million (or 51.6%) in allowance for doubtful accounts; (vi) recognition of R$39 million related to impairment losses of our subsidiaries, principally CPFL Telecom and to a lesser extent CPFL Total and; (vii) an increase of R$33 million in expenses from outsourced services. Income from Electric Energy Service Compared to the year ended December 31, 2014, our income from electric energy service decreased 11.3% (or R$288 million) to R$2,252 million in the year ended December 31, 2015, due to the net effect of an increase in our cost of generating and distributing electric energy and other operating costs and expenses (R$3,188 million) in a higher amount than the increase in our net operating revenue (R$2,900 million). Income from Electric Energy Service by Segment Distribution Compared to the year ended December 31, 2014, income from electric energy service from our Distribution segment decreased 27.4% (or R$439 million) to R$1,163 million in the year ended December 31, 2015, which represents the net effect in the income from electric energy service due to an increase of 21.8% (or R$2,896 million) in net operating revenues (as discussed above) and an increase of 27.6% (or R$3,335) 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, 2014, electricity costs increased 32.6% (or R$2,937 million), to R$11,947 million in the year ended December 31, 2015.  The cost of energy purchased for resale increased 23.1%, (or R$1,980 million), reflecting an increase of 22.0% in average prices, arising mainly from exchange rate variations in the energy purchases from Itaipu.  In addition, charges for the use of the transmission and distribution system increased 223.8% (or R$958 million) mainly due to: (i) an increase of R$877 million (or 271.9%) in System Service Charges; (ii) an increase of R$104 million (or 15.5%) in the Basic Network Charges; (iii) an increase of R$44 million in Reserve Energy Charges.  These increases in charges for the use of the transmission and distribution system were partially offset by an increase of R$98 million in tax credits from network usage charges. Other costs and operating expenses.  Compared to the year ended December 31, 2014, our other costs and operating expenses for the Distribution segment increased 13.0% (or R$398 million), to R$3,464 million in the year ended December 31, 2015, mainly due to: (i) an increase of R$132 million (or 15.0%) in expenses related to the construction of concession infrastructure; (ii) an increase of R$59 million in legal, judicial and indemnity expenses; (iii) an increase of R$53 million in personnel expenses due to a collective bargaining agreement negotiated in 2015 and an increase of 11.5% in the number of employees, partially offset by a lower distributions from our profit-sharing plan; (iv) an increase of R$49 million in outsourced services; (iv) an increase of R$44 million in expenses related to provision for doubtful receivables and; (v) an increase of R$20 million in depreciation and amortization expenses. Generation (conventional sources) Compared to the year ended December 31, 2014, income from electric energy service from our Conventional Generation segment increased 12.6% (or R$61 million) to R$543 million in the year ended December 31, 2015.  This increase was mainly due to a decrease of 17.4% in net operating revenue (or R$207 million, as discussed in the section “Sales by Segment” above) that was lower than the decrease in costs and operational expenses (reduction of R$267 million), reflecting a decrease of R$261 million in electricity purchased for resale, for which average prices decreased 59.8% in comparison with the period ended December 31, 2014.


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 Generation (renewable sources) Compared to the year ended December 31, 2014, income from electric energy service from our Renewable Generation segment increased 99.2% (or R$229 million) to R$461 million for the year ended December 31, 2015.  This increase was mainly due to an increase in net operating revenue of R$218 million (as discussed in the section “Sales by Segment” above) and a decrease of R$11 million in costs and operational expenses. This decrease  reflects a decrease of R$150 million in electricity purchased for resale, for which average prices decreased 59.8% in comparison with the period ended December 31, 2014.  Such decrease was offset by: (ii) an increase of R$80 million in depreciation and amortization expenses; (iii) an increase of R$24 million in expenses for outsourced services; (iv) an increase of R$22 million in charges for use of the transmission and distribution system; and (v) an increase of R$9 million in expenses from inventory and materials acquisitions. Commercialization Compared to the year ended December 31, 2014, income from electric energy service from our Commercialization segment decreased 39.1% (or R$80 million), to R$125 million in the year ended December 31, 2015.  This increase was due to the net effect of a decrease of 17.4% (or R$380 million as discussed in “Sales by Segment” section above) in net operating revenues in a higher amount than the decrease of 15.2% (or R$300 million) in costs and operational expenses.  The decrease in costs and expenses was mainly due to the decrease of R$305 million in electricity purchased for resale, reflecting a decrease of 16.2% in the volume of energy purchased offset by an increase of 0.5% in the average price.  In addition, the decrease in costs and expenses was offset by an increase of R$3 million in charges for use of the transmission and distribution system. Services Compared to the year ended December 31, 2014, income from electric energy service from our Services segment decreased 32.1% (or R$14 million), to R$31 million in the year ended December 31, 2015.  This decrease reflected the fact that net operating revenues decreased by 14.5% (or R$50 million), as discussed above, or more than the 11.8% (or R$36 million) decrease of costs and operational expenses.  The decrease in costs and expenses was mainly due to a decrease of R$65 million in expense related to construction contracts, related to the decrease in revenue from construction contracts mentioned in “Sales by Segment” above.  This decrease was partially offset by (i) the increase of R$24 million in personnel expenses due to an increase in the number of employees and due to collective bargain agreements and (ii) an increase of R$4 million in depreciation and amortization expenses. Net Income Net Financial Expense Compared with the year ended December 31, 2014, our net financial expense decreased 6.9% (or R$75 million), from R$1,089 million in 2014 to R$1,015 in the year ended December 31, 2015, mainly due to an increase of R$668 million in our financial income, offset by an increase of R$593 million in our financial expense. The increase in financial income is mainly due to following reasons: (i) an increase of R$310 million in income from adjustment of estimated cash flow of the Concession Financial Asset in 2015 (see note 11 to our consolidated audited financial statements); (ii) an increase of R$163 million in income from adjustment of Sector Financial Assets and Liabilities (see note 8 to our consolidated audited financial statements); (iii) an increase of R$72 million in income from monetary and exchange adjustments; (iv) an increase of R$69 million in interest and fine payments; (v) an increase of R$42 million in income from financial investments; and (vi) an increase of R$32 million in adjustment for inflation of tax credits.  Those increases were offset by an increase of R$53 million related to tax expenses on financial income (PIS and COFINS taxes), which is accounted for as a reduction of financial income. The reasons for the increase in financial expenses are: (i) an increase of R$439 million in financial expenses from monetary and exchange adjustments; and (ii) an increase of R$183 million in debt charges. Those increases in financial expenses were partially offset by an increase of R$33 million in capitalized borrowing costs, which is accounted as a decrease in financial expenses.


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 At December 31, 2015, we had R$14,793 million (R$15,709 million at December 31, 2014) in debt denominated inreais, which accrued both interest and inflation adjustments based on a variety of Brazilian indices and money market rates.  We also had the equivalent of R$6,940 million (R$3,441 million at December 31, 2014) 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 13.2% in 2015, compared to 10.5% in 2014, and the TJLP increased to 7% in 2015, compared to 5% in 2014. Income and Social Contribution Taxes Our net charge for income and social contribution taxes decreased from R$624 million in the year ended December 31, 2014 to R$579 million in the year ended December 31, 2015.  The effective rate of 39.8% on pretax income in the year ended December 31, 2015 was higher than the official rate of 34.0%, 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, 2014, and due to the factors discussed above, net income decreased 1.3% (or R$11 million), to R$875 million in the year ended December 31, 2015. Net Income by Segment In the year ended December 31, 2015, 71.5% of our net income derived from our Distribution segment, 32.3% from our Generation from Conventional Sources segment, (6.4)% from our Generation from Renewable Sources segment, 10.1% from our Commercialization segment, 5.9% from our Services segment and (13.3)% from Other. Distribution Compared to the year ended December 31, 2014, net income from our Distribution segment decreased 25.9%, or (R$218 million), to R$626 million in the year ended December 31, 2015, as a result of a decrease of 27.4% (or R$439 million) in income from electric energy service, a decrease of 10.1% (or R$47 million) in Income and Social Contribution Taxes and a decrease of 58.6% (or R$174 million) in net financial expenses. The decrease in net financial expenses was mainly due to: ·an increase of R$603 million in financial income, mainly due to: (i) an increase of R$310 million in financial income arising from an adjustment in the estimated cash flow of the financial assets related to our concessions (see note 11 to our consolidated audited financial statements); (ii) an increase of R$163 million in income from the adjustment of Sector Financial Assets and Liabilities (see note 8 to our consolidated audited financial statements); (iii) an increase of R$66 million in arrears of interest and fines; (iv) an increase of R$37 million in income from monetary and exchange adjustments; (v) an increase of R$32 million in income from financial investments; and (vi) an increase of R$31 million in adjustment for inflation of tax credits.  Those increases were offset by an increase of R$43 million in tax expenses on financial income (PIS and COFINS), which is accounted as a reduction of financial income. ·an increase of R$428 million in financial expenses. This increase was mainly due to an increase of R$418 million in financial expenses from debt charges and monetary and exchange rate variations as a result of higher indebtedness. Generation (conventional sources) Net income from our Generation from Conventional Sources segment increased by 162.3% (or R$175 million) to R$283 million during the year ended December 31, 2015 from R$108 million for the year ended December 31, 2014.  This increase is mainly due to the increase of 12.6% (or R$61 million) in income from electric energy service and the increase of 263.4% (or R$157 million) in equity interests in joint ventures (see note 13 to our


audited annual consolidated financial statements). These increases were partially offset by an increase of R$41 million increase in net financial expenses, which reflects an increase of R$67 million in financial expenses (mainly due to an increase of R$69 million in debt charges and monetary and exchange variations, due to the increase in our indebtedness), partly offset by an increase of R$25 million in financial income.


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  Generation (renewable sources) The net loss from our Generation from Renewable Sources segment decreased by 66.4% (or R$112 million) to R$56 million in the year ended December 31, 2015 compared to net loss of R$168 million in 2014, mainly due to an increase of 99.2% (or R$229 million) in income from electric energy service offset by an increase of 28.0% (or R$102 million) in net financial expenses.  The increase in net financial expenses was driven by an increase of R$169 million in debt expenses and monetary and exchange rate variations, offset by an increase of R$29 million in income from financial investments and an increase of R$28 million in capitalized borrowing costs. Commercialization Compared to the year ended December 31, 2014, net income from our Commercialization segment decreased 35.2% (or R$48 million), to R$88 million in the year ended December 31, 2015, reflecting a decrease of 39.1% (or R$80 million) in the income from electric service, offset mainly by a reduction of 40.6% (or R$28 million) in income and social contribution taxes expenses. Services Compared to the year ended December 31, 2014, net income from our Services segment increased 80.9% (or R$23 million), to R$52 million in the year ended December 31, 2015, reflecting an increase of R$43 million in net financial income (driven mainly by an increase of R$ 38 million in income from financial investments due to the increase in the average bank account balances), partially offset by a decrease of R$14 million in income from electric energy service and by an increase of R$6 million in income and social contribution taxes expenses. 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 our concession contracts were amended, we 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).  This revenue reflects timing differences between our budgeted costs included in the tariff at the beginning of the tariff period, and those actually incurred while it is in effect, creating a 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 (see note 8 to our audited annual consolidated financial statements).  This leads to an adjustment to recognize the future increase (or decrease) in tariffs to take account of additional (or lower) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue. 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 (through DESA) also contributed to the increase in net operating revenue.  Also included in net operating revenue are the revenues relating to the construction of concession infrastructure in the amount of R$945 million, which does not affect results, due to corresponding costs in approximately 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.


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 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”. Other operating revenues


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 Compared to the year ended December 31, 2013, our other gross operating revenues (which excludes TUSD revenue from captive consumers) 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) is calculated based on gross operating revenue from final consumers (billed), while federal PIS and COFINS taxes are calculated based on total gross operating revenue. The research and development and energy efficiency programs (regulatory charges) are calculated based on net operating revenue.  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) 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 to our 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 15.4 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 therealagainst 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 of R$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. Liquidity and Capital Resources Our credit risk and debt securities are rated by Standard and Poor’s and Fitch Ratings.  These ratings reflect, among other factors, perspectives for the Brazilian electricity sector, the political and economic context, country risk, hydrological conditions in the areas where our power plants are located, our operational performance and debt levels, and the ratings and outlook of our controlling shareholders.  Our ratings were reduced in 2015 from AA+ to AA as a result of the downgrade of Brazil investment grade, due to changes in the country ́s economic and political scenarios. Downgrades can increase our cost of capital and lead lenders to include additional financial covenants in the instruments that regulate our debt. On December 31, 2015, our working capital reflected an excess of current assets over current liabilities of R$2,984 million, an increase of R$1,186 million compared to R$1,798 million at December 31, 2014. The main causes of this increase were: (i)            an increase of R$1,325 million in cash and cash and equivalents due to net cash generation of R$2,558 million from operating activities and R$292 million from financing activities, offset by consumption of R$1,525 million in net cash from investing activities. (ii)           an increase of R$ 1,799 million in balances of consumers receivables (R$ 924 million) and of Sectorial Financial Assets net of linked liabilities (R$875 million); (iii)          an increase of R$604 million in derivative financial instruments;


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 Those increases were partially offset by: (iv)          an increase of R$1,812 million in accounts payable related to acquisition of materials and outsourced services (R$787 million), regulatory charges (R$808 million), income taxes and social contributions (R$217 million) and dividends payable (R$203 million). (v)           the reclassification of R$537 million from financial asset of concession account to intangible assets account due to extension of the term of our five distribution concessions. 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$2,558 million in the year ended December 31, 2015, compared to R$1,593 million in the year ended December 31, 2014 (increase of 60.6%).  The increase of R$965 million primarily reflects: (i)an increase of R$88 million of net income adjusted for the reconciliation of net cash; (ii)an increase of R$1,252 million in cash generating arising from increasing in operating liabilities, primarily due to regulatory charges (R$797 million) and accounts payable (R$316 million). (iii)net increase of R$389 million in operating assets (which represents an increase in the cash provided by operating activities), primarily accounts receivable from consumers (R$792 million), offset by a decrease of R$534 million in accounts receivable from the CDE/CCEE account; and (iv)a reduction of R$14 million in cash consumption from income tax and social contribution (R$276 million) net of payment of interest (R$267 million) 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.  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)an increase of interest and monetary adjustment of R$192 million (which represents an expense with no immediate cash outflow). Our net cash from financing activities recorded generation of cash of R$292 million in the year ended December 31, 2015 compared to consumption of cash of R$509 million in the year ended December 31, 2014.  This increase of R$801 million was due to: (i)an increase of R$1,346 million in fund raising from borrowings and debentures; (ii)a decrease of R$1,011 million in dividend payments; and (iii)an increase of R$1,478 million related to payments of loans, financing, debentures and derivatives.


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 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 borrowings 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 (iii)a decrease of R$1,820 million in payments of borrowings, debentures and derivatives and an increase of R$178 million in dividend payments (which represents a decrease in cash generated). Indebtedness The following table sets forth our current and noncurrent indebtedness (in millions) for the year ended December 31, 2015: 2015Current

   NoncurrentSecured debt

   929

   5,904Unsecured debt

   2,711

   12,189Total

   3,640

   18,093
  Our total indebtedness increased R$2,583 million, or 13.5%, from December 31, 2014 to December 31, 2015, mainly as result of: ·Issuances of debentures in the total amount of R$664 million by CPFL Renováveis in order to strengthen working capital and debt payments and to fulfill required investments for our renewable generation subsidiaries. ·New borrowings 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$921 million primarily to fulfill the biannual investment plan for our largest distribution subsidiaries (R$569 million) and services companies (R$9 million) as well as to fulfill required investments for our renewable generation subsidiaries (R$343 million); and ·New borrowings in the amount of R$2,968 million (of which R$2,612 million is U.S. dollar denominated debt) at most of our distribution subsidiaries and at CPFL Renováveis to improve working capital, finance debt payments, refinance maturing debt and fulfill required investments for our renewable generation subsidiaries. The increases listed above where partially offset by payment of debentures in the total amount of R$2,021 million by CPFL Energia (R$1,305 million), CPFL Geração (R$272 million), CPFL Piratininga (R$268 million) and WF2 (R$176 million). In 2016 and 2017, 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.


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 Terms of Outstanding Debt Total debt outstanding at December 31, 2015 (including accrued interest) was R$21,733 million.  Approximately R$6,940 million of our total outstanding debt, or 31.9%, 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$3,640 million of our total outstanding debt is due in 12 months. Our major categories of indebtedness are as follows: ·BNDES.  At December 31, 2015, we had R$5,656 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$3,955 million); (ii) financing of investment programs for our distribution subsidiaries, primarily CPFL Paulista, CPFL Piratininga and RGE (R$1,610 million); and (iii) loans to our subsidiaries CPFL Serviços, CPFL Brasil, CPFL Esco, CPFL Telecom and CPFL Transmissão (R$91 million). ·Debentures.  At December 31, 2015, we had indebtedness of R$7,070 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, 2015, we had R$1,622 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, 2015, we had R$466 million outstanding under a number of otherreal‐denominated facilities. The most significant part of thesereal-denominated facilities relates to our renewable energy subsidiaries (R$322 million) and our distribution subsidiaries (R$144 million).  They are indexed based on the CDI or TJLP and bear interest at different rates. ·Other U.S. dollar‐denominateddebt.  At December 31, 2015, we had the equivalent of R$6,940 million outstanding under other loans denominated in U.S. dollars (US$1,777 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 borrowings, 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) EBITDA divided by Finance Income (Costs); (iii) net indebtedness divided by the sum of net indebtedness and net equity; (iv) maintaining the debt coverage ratio and own capitalization ratio and (v) 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, 2015. For more information on our financial covenants, see explanatory notes 17 and 18 to our audited annual consolidated financial statements.


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 Uses of funds Our cash flow used for investing activities was R$1,525 million in the year ended December 31, 2015 compared with R$933 million in the year ended December 31, 2014.  This increase of R$592 million (63.4%) primarily reflects: (i)an increase of R$205 million in property, plant and equipment mainly due to investments in our renewable energy subsidiaries; (ii)an increase of R$161 million in intangible assets primarily due to investments in our distribution activities; and (iii)an increase of R$140 million in financial investments. 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. 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, 2015 we had outstanding debt maturing during the following 12 months in the total amount of R$3,640 million; and ·Dividends on a semiannual basis.  We did not pay dividends in 2015 (R$987 million in dividends paid in 2014).  See “Item 10.  Additional Information—Interest Attributable to Shareholders’ Equity” and Unconsolidated Statement of Cah Flow in Note 39 to our audited annual consolidated financial statements. CPFL Energia has adopted, since the second half of 2011, a pre‐funding strategy in order to access 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 2015 in relation to debt due in 2016 and will continue to apply it in 2016 in relation to debt due in 2017.  By applying this strategy, we aim to reduce CPFL Energia’s future cash flow exposure and its exposure to interest rate risk, as well as to maintain its liquidity level and its debt profile through debt refinancing actions. 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, 2015, 2014 and 2013: Year ended December 31,2015

   2014

   2013(in millions ofreais)Distribution

   868

   702

   845Conventional Generation

   7

   14

   10Renewable Generation

   494

   251

   828Commercialization and other investments

   59

   94

   52Total

   1,428

   1,062

   1,735


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 In addition to the capital expenditures shown above, we invested R$37 million for the year ended December 31, 2015 and R$57 million for the year ended December 31, 2014 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$2,812 million in 2016 and approximately R$1,911 million in 2017.  Of total budgeted capital expenditures over this period, R$2,567 million are expected to be invested in our Distribution segment, R$1,915 million in our Renewable Generation segment and R$27 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$214 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”. 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 April 29, 2015, in the Annual Shareholders' Meeting of CPFL Energia, shareholders representing 78.42% of CPFL Energia's capital stock followed the recommendation of the Board of Directors and approved the allocation of R$555 million from our accumulated profit for the year 2014 to our statutory reserve – working capital improvement account. Additionally, in the Extraordinary Shareholders' Meeting that took place on April 29, 2015, capitalization of this statutory reserve was approved by the shareholders and 30,739,955 new ordinary shares were issued. For the year ended December 31, 2015, Our Board of Directors approved dividend distribution of R$205 million, subject to the approval by shareholders in the Annual Shareholders' Meeting of CPFL Energia, which will take place on April 29, 2016. 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, 2015 (including our noncurrent contractual obligations). Payments due by periodTotal

   Less than 1 year

   1‐3 years

   4‐5 years

   After 5 years(in millions ofreais)Contractual obligations as of December 31, 2015:Suppliers

   3,162

   3,161

   1

   -

   -Debt obligations(1)

   30,301

   5,712

   13,819

   6,796

   3,974Public utilities (1)

   466

   25

   69

   118

   253Post-employment benefit (2)

   1,141

   -

   129

   199

   812Regulatory charges

   852

   852

   -

   -

   -Other

   208

   190

   -

   -

   18Total of Balance Sheet items (1)

   36,129

   9,940

   14,018

   7,114

   5,057Electricity purchase agreements (3)

   133,179

   10,252

   19,568

   20,600

   82,760Distribution and transmission systems service charges(4)

   27,385

   1,062

   2,967

   3,638

   19,717Premium of Hydrological Risk renegotiation (GSF)(5)

   234

   46

   -

   7

   181Generation projects (6)

   1,260

   962

   298

   -

   -Supplies

   3,044

   1,333

   946

   226

   538Total of other commitments

   165,102

   13,655

   23,779

   24,472

   103,197Total of contractual obligations

   201,231

   23,595

   37,797

   31,586

   108,253
  (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 2015 price.  See “—Background—Prices for Purchased Electricity” and note 36 to our audited annual consolidated financial statements. (4)   Estimated distribution and transmission system service charges until the end of our concessions. We have presented this obligation combined with “Electricity Purchase Agreements” until the fiscal year ended December 31, 2014. (5)   Estimated expenses for the payment of risk premium in connection with renegotiation of hydrological risk (see note 28.2 to our audited annual consolidated financial statements). (6)   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.


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Table of Contents  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 programs through strategic partnerships with national universities and research centers, and the vast majority of our resources are dedicated to innovation and development in new technologies applicable to our business. Our disbursements on research and development projects in the years ended December 31, 2015, 2014 and 2013 totaled  R$125 million, R$120 million and R$132 million, respectively. Off‐Balance Sheet Arrangements As of December 31, 2015, 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 2015 (in thousands ofreais)Modality

   Approval

   Company

   Debt

   Released

   BalanceBNDES / Investment - FINEM

   In 2014

   CPFL Santa Cruz

   25,360

   23,155

   2,205BNDES / Investment - FINEM I

   In 2014

   CPFL Leste Paulista

   13,045

   8,570

   4,475BNDES / Investment - FINEM

   In 2014

   CPFL Sul Paulista

   12,280

   9,132

   3,148BNDES / Investment - FINEM V

   In 2014

   CPFL Jaguari

   10,398

   5,384

   5,014BNDES / Investment - CCB Santander

   In 2014

   CPFL Mococa

   6,119

   3,040

   3,079BNDES / Investment - FINEM XIII

   In 2013

   CPFL Renováveis

   389,311

   356,181

   33,130BNDES / Investment - FINEP I

   In 2013

   CPFL Renováveis

   20,728

   6,921

   13,806(1)BNDES / Investment - FINEP II

   In 2014

   CPFL Renováveis

   379,948

   314,991

   64,957BNDES / Investment - FINEP III

   In 2014

   CPFL Renováveis

   88,095

   10,348

   77,747(1)BNDES / Investment - FINAME

   In 2014

   CPFL Transmissão Piracicaba

   23,824

   20,737

   3,087(1)BNDES / Investment - FINEM

   In 2014

   CPFL Telecom

   95,333

   34,918

   60,415BNDES / Investment - FINEM VII

   In 2014

   CPFL Paulista

   427,716

   254,119

   173,597BNDES / Investment - FINEM VI

   In 2014

   CPFL Piratininga

   194,862

   135,259

   59,603BNDES / Investment - FINEM VII

   In 2014

   RGE

   266,790

   174,518

   92,272BNDES / FINAME

   In 2015

   CPFL Serviços

   6,011

   5,144

   867BNDES / Investment - FINEM XXV

   In 2015

   CPFL Renováveis

   84,338

   75,732

   8,606BNDES / Investment - FINEM XXVI

   In 2015

   CPFL Renováveis

   764,109

   270,642

   493,467
  (1)Outstanding balance was canceled.


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  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 26,783 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 commercial 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, a weekly report published by the Brazilian Central Bank on April 1st, 2016, to evaluate market expectations with regards to the Brazilian economy, GDP is expected to decrease 3.7% in 2016 and increase 0.3% in 2017.  Since the global economic crisis of 2009, the Brazilian economy has been negatively affected by lower demand in foreign trade and deficient infrastructure in Brazil, which has resulted in GDP growth averaging 2.1% per year between 2009 and 2014.  In 2015, reduction in aggregate demand, combined with unfavorable political conditions, had negative consequences on the country’s economic activity and contributed to the devaluation of the Brazilian real, ultimately making 2015 another challenging year for the Brazilian economy.  Industrial production decreased 8.3% in 2015, which affected the labor market and therefore consumer spending.  Considering that Brazil currently has substantial international reserves and the real/U.S. dollar exchange rate is expected to remain at levels observed in 2015, potentially increasing Brazilian exports, official Brazilian Government projections indicate that the current recession should not be continue for many years, with signs of recovery expected by the end of 2016. Furthermore, inflation is expected to decrease in 2016, partially compensating the decline in real income observed in 2015.  Despite the increase in the unemployment rate observed in 2015, it remains at historically low levels (8.6% in 2015), reflecting Brazil’s potential as one of the largest consumer markets in the world.  Weak economic activity resulted in a decline in energy consumption in 2015, which also negatively affected sectors of the economy which are traditionally the least affected by economic crises. Based on the forecast economic scenario discussed above, we expect that negative economic results observed in 2015 and expected for 2016 to begin improving in 2017. 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 1,798 MW (of which our share is 929 MW) and 332 MW under construction (of which our share is 170 MW), as well as seeking out new projects. As of December 31, 2015, we had an Installed Capacity of 3,164 MW. In 2020, we expect to reach an Installed Capacity of 3,334 MW, when the Mata Velha and Boa Vista II SHPPs and Campo dos Ventos, São Benedito and Pedra Cheirosa I and II Wind Farm Complexes will have begun operations.  We also have a 3,453 MW (of which our share is 1,782 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.


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 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. Critical Accounting Policies In preparing our financial statements, we make estimates concerning a variety of matters.  Some of these matters are highly uncertain, and our estimates involve judgments we make based on the information available to us.  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. Our evaluations in 2014 and 2013 did not result in any significant impairment of our property, plant and equipment or intangible assets and investments. For the year ended 2015 we have recognized a loss of R$39 million related to provisions for impairment of long-lived assets (see notes 14.1 and 15.2 to audited annual consolidated financial statements). 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.


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 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 not recover such deferred tax assets, then such asset is not registered in the balance sheet of the company.  Also, if there are no evidences that allow us to expect 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. 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.


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 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 (concession financial asset).  The methodology adopted for marking these assets to market is based on the tariff review process for distributors.  This review, usually 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.   ITEM 6.Directors, Senior Management and Employees Directors and Senior Management Board of Directors Our Board of Directors’ main duties and responsibilities are established by Brazilian Corporate Law and our bylaws, and include, among others, the responsibility to determine our overall strategic guidelines, establish our general business policies, elect our executive officers and supervise their management. Our Board of Directors operates according to its Internal Rules (which establish, among other matters, the rules concerning the relationship between the Board of Directors and the committees, commissions and other departments of CPFL Energia and its subsidiaries), with due observance to the provisions of the Brazilian Corporate Law, our bylaws and the Shareholders' Agreement relating to the company. Under our bylaws, members of the Board of Directors are elected by the holders of our common shares at the annual general shareholders’ meeting.  According to our bylaws, our Board of Directors consists of a minimum

of seven members and a
maximum of nine members (with their respective alternate members).  Members
of the  Board of Directors serve one‐year terms, re‐election being
permitted provided that they may be removed at any time by our shareholders at
an extraordinary general meeting of shareholders.   Our bylaws do not
provide for a mandatory retirement age for our directors.  The Board of
Directors has one chairman and one vice-chairman, appointed among its members in
the first meeting following the election of the directors.  See "Item 7.
Major Shareholders and Related Party Transactions-Shareholders'
Agreement-Corporate Governance".


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 The Board of Directors
meets at least once a month, or whenever requested by the chairman in accordance
with our bylaws and the Internal Rules of the Board.  In the event of a
tie, the chairman will have the deciding vote.  See "Item 7. Major
Shareholders and Related Party Transactions-Shareholders' Agreement- Voting
Rights". 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 CPFL Energia, 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 CPFL
Energia (or its subsidiaries) that exceeds R$11,116,000.00, 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 (and his/her respective
alternate 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 more than 5.0% of voting shares may
request multiple voting (voto múltiplo) , which confers upon each
voting share a number of votes equal to the number of members of the Board of
Directors and gives the shareholder the right to accumulate his or her votes in
one sole candidate, or distribute them among several candidates. Currently, our Board
of Directors consists of seven members (six of them with alternate members), of
which one is independent (in accordance with the listing regulations of the New
Market segment of the BM&FBOVESPA, or theNovo Mercado, and our
bylaws).  Seven members of our current Board (and six alternate members)
were elected at our annual general meetings of shareholders held on April 29,
2015.  Their terms are expected to expire at our next annual general
meetings of shareholders, scheduled to take place on April
29, 2016. 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
    PositionMurilo Cesar Lemos dos Santos Passos
    68
    ChairmanDécio Bottechia Júnior
    50
    Vice‐ChairmanAlbrecht Curt Reuter Domenech
    68
    MemberDeli Soares Pereira
    66
    MemberFrancisco Caprino Neto
    55
    MemberLicio da Costa Raimundo
    47
    MemberAna Maria Elorrieta
    60
    Independent
Member
   Murilo Cesar Lemos dos
Santos Passos– Mr. Passos graduatedin 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 – Board of Industrial Development (CDI).  Between 1977 and 1992,
he worked at Companhia Vale do Rio Doce, where he served as Executive Forest
Product, Environment and Metallurgy Officer and also served as the CEO of
Celulose Nipo-Brasileira S.A. (Cenibra) and Florestas Rio Doce S.A. 
Between 1993 and 2006, he served as the Superintendent Officer at Bahia Sul
Celulose S.A. and Suzano Papel e Celulose S.A.  He was a member of the
Board of Directors of Brasil Agro Cia. Brasileira de Propriedades Agrícolas
between 2007 and2010.  Currently,
he is a member of the Management Committee of the Board of Directors of Suzano
Papel e Celulose S.A., the Notable Committee of the National Quality Foundation
(FNPQ), the Senior Board of the EcoFuture Institute and the Advisory Committee
to 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., Tegma Gestão Logística S.A. and Grupo CCR  Since 2010, he has been
the Chairman of our Board of Directors.


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 Décio Bottechia
Júnior– Mr. Bottechia graduated in Economics from the
Mackenzie Presbyterian University in 1990, and obtained a graduate degree in
Financial Management from São Judas Tadeu University in 1995, and Master’s and a
Doctorate degrees in Business Economics from the Catholic University of Brasília
(UCB) in 2005 and 2013, respectively.  Between 2002 and 2014, he served as
a Senior Advisor to Banco do Brasil.  He is also a member of the Fiscal
Council of ANABBPrev and serves as Planning Officer at Previ—Caixa de
Previdência dos Funcionários do Banco do Brasil.  Since 2015, he is the
Vice-Chairman of our Board of Directors. Albrecht Curt
Reuter Domenech– Mr. Reuter graduated in Civil Engineering from the
University of Puerto Rico in 1968, and obtained a Master’s degree in Business
Management from the Wharton School of the University of Pennsylvania (USA) in
1979.  He joined McKinsey & Company, Inc. in 1979 and retired in
2006.  He currently also serves as a member of the Board of Directors of
Construções Comercio Camargo Correa S.A. and of Companhia de Concessões
Rodoviárias S.A. (CCR). Since 2015, he is a member of our Board of
Directors. Deli Soares
Pereira– Mr. Pereiragraduatedin Social
Sciences from the University of São Paulo (USP) in 1979, and obtained a graduate
degree in Economics and Labor Relations Management from the Pontifical
University of São Paulo (PUC/SP) in 2009.  Between 2000 and 2013, he served
as an alternate member of the Boards of Directors of VALE S.A. and VALEPAR
S.A.  He has also served as a member of the Boards of Directors of Tigre
S.A. – Tubos e Conexões, between 2001 and 2003, and SOLPART Participações S.A.,
between 2006 and 2008.  He was a member of the Board of Directors of CPFL
Piratininga, CPFL Paulista, CPFL Geração and of our Board of Directors from 2004
to 2006.  Since 2013, he is a member of our Board of Directors. Francisco Caprino
Neto– Mr. Caprino Neto graduated in Metallurgical Engineering from the University of
São Paulo in 1983, and obtained a Master’s degree in Metallurgical Engineering
from the same institution in 1992.  He has served as the Head of the
Process Engineering Department and Planning and the Control Advisor for
Siderúrgica J.L. Aliperti S.A., and the Coordinator of Metallurgical Processes
for Aços Vilares S.A.  Between 200 and 2005, he was a member of the Boards
of Directors of CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE. 
Between 1996 and 2015, he has held executive positions at Camargo Corrêa S.A.
and its subsidiaries.  He also serves as a business consultant in FCaprino
Consultoria Empresarial- EIRELI.  He is certified to serve as a Board
member by the Brazilian Corporate Governance Institute (IBGC).  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 our Board of
Directors, from 2004 to April 2013, and an alternate member from April 2013 to
August 2014.  Currently, he is a sitting member of our Board of
Directors. Licio da Costa
Raimundo –Mr. Raimundo graduated in Economics from the University
of São Paulo in 1993, and obtained Master’s and Doctorate degrees from the
Institute of Economics of the University of Campinas, in 1997 and 2002,
respectively.  Between 2003 and 2005, he served as the Manager of the
Investment Planning Area of Fundação Petrobrás de Seguridade Social –
Petros.  Since 2001, he serves as a Senior Technical Advisor to the Finance
Department of the City of Campinas and, since 2013, as Investment Officer of
Fundação de Previdência Complementar do Servidor Público Federal -
Funpresp.  Since 2015, he is a member of our Board of Directors Ana Maria Elorrieta– Ms. Elorrieta
graduated in Accounting Sciences from the University of Buenos Aires (UBA) in
1973. In 1995, she became a partner of PwC Brasil, where she served until
December 2012. Over this period, she headed the Risk and Quality department in
Brazil and South America, represented PwC in international forums (PwC Global
Accounting Standards Board and Global Risk & Quality), and was a member of
the Territory Leadership Team. From 1997 to 2002, she participated in the
Workgroup to discuss Brazilian Accounting Standards promoted by the Federal
Accounting Council (CFC). From 1998 to 2003, she was a member of the
International Auditing and Assurance Standard Board (IAASB) of the International
Federation of Accountants (IFAC). In the Brazilian Institute of Accountants
(IBRACON), she was part of several administrations of the National Executive
Board from 1998 to 2004, and was director of technical affairs from 2004 to
2007, as well as president of the National Executive Board from 2009 to 2011.
From 2005 to 2014, she led the Latin America Coordinating Committee. She is an
acting associate of the Brazilian Corporate Governance Institute (IBGC) and a
certified BOARD MEMBER since 2013. Since 2014, she has been a member of the
Audit Committee of a closely held Brazilian mining company.


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 Executive Officers The main duties and responsibilities of the members of our board of executive officers are established by Brazilian Corporate Law and our bylaws, and include, among others, executing the decisions of our Board of Directors and day‐to‐day management of the Company. Under our bylaws, our board of executive officers is comprised of seven members that are appointed by our Board of Directors for a two‐year term, with the possibility of re‐election. Our current executive officers were elected at the Board of Directors’ meeting held on May 06, 2015. 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

   PositionWilson Ferreira Júnior

   56

   Chief Executive Officer(*)Gustavo Estrella

   41

   Chief Financial and Investor Relations OfficerLuis Henrique Ferreira Pinto

   54

   Chief Regulated Operations OfficerKarin Regina Luchesi

   39

   Chief Market Operations OfficerWagner Luiz Schneider de Freitas

   43

   Chief Planning and Business Management OfficerCarlos da Costa Parcias Junior

   55

   Chief Business Development OfficerLuiz Eduardo Fróes do Amaral Osório

   41

   Chief Legal and Institutional Relations Officer
 (*) On April 13, 2016 Mr. Ferreira announced his intention to resign as our Chief Executive Officer, the post that he has held since 2002.  He will remain in office until July 1, 2016.  Our board of directors has approved Andre Dorf, currently the Chief Executive Officer of CPFL Renovaveis, to replace Mr. Ferreira as our Chief Executive Officer.  Mr. Ferreira and Mr. Dorf will work together on the transition until July 1.  Wilson Ferreira Junior– Mr. Ferreira Junior graduated in Electrical Engineering from the Mackenzie Presbyterian University in 1981 and earned a degree in Business Administration from the same institution 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 completed several specialization programs, including: Occupational Safety and Health Engineering at Mackenzie University, in 1982, Marketing at Fundação Getúlio Vargas, in 1988, and Electricity Distribution Management at the Swedish Power Co., in 1992.  Between 1995 and 1998, he held several senior positions at the Companhia Energética de São Paulo (CESP), and served as the Distribution Officer.  Between 1998 and 2000, he served as the CEO of RGE, and, between 2000 and 2001, he served as the Chairman of the Board of Directors of Bandeirante Energia S.A.  He was the President of the Brazilian Association of Electric Power Distributors (ABRADEE) between 2009 and 2010.  Currently, he is 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 a member of the Board of Directors of WEG S.A.  Between 2002 and 2011, he was a member of the Board of Directors of CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE.  Between 2000 and 2011, he was the CEO of CPFL Paulista, and between 2001 and 2011, he was the CEO of CPFL Piratininga, CPFL Geração and CPFL Brasil.  He has also served as the CEO of CPFL Jaguariúna, Nect Serviços, and certain of our other subsidiaries.  He is currently the Chairman of the Board of Directors of CPFL Renováveis and of the Institution CPFL.  Since 2002, he has been our Chief Executive Officer. Gustavo Estrella– Mr. Estrella graduated from the State University of Rio de Janeiro (UERJ) in Business Administration in 1997.  He obtained a Master’s degree in Finance from the Brazilian Institute of Capital Markets (IBMEC/RJ) in 2000.  He has worked at Grupo Lafarge and at the companies Light and Brasil Telecom.  He has held positions at the Company since 2001, where he has served as Manager of Economic Planning and Finance, Director of Investor Relations and Director of Planning and Control.  Since 2013, he has served as the 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.  He is currently the 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.  Since 2013, he has been our Chief Financial Officer.


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 Luis Henrique Ferreira Pinto– Mr. Ferreira Pinto graduated in Electrical Engineering from the Engineering University of Barretos in 1985.  He obtained a graduate degree in Power Electric System Engineering at Federal University of Itajubá (EFEI) in 1990 and obtained a Master’s degree in Electrical Engineering at the State University of Campinas (UNICAMP) in 2001, without defending his thesis, holding two specializations, including a Master’s degree in Corporate Management obtained in 2004 and a Master’s degree in Financial Management, Controllership and Auditing obtained in 2011 from Fundação Getúlio Vargas (FGV).  He has held several positions at Companhia Paulista de Força e Luz (CPFL), serving as an Operations Planning Engineer between 1986 and 2000, the CPFL Transmission Service Division Manager between 2000 and 2001, the CPFL Electric System Planning Division Manager between 2001 and 2002, the Manager of the Operational Control Department at CPFL Paulista and CPFL Piratininga between 2002 and 2006, the Operations Officer at RGE between 2006 and 2009, and the Executive Officer at RGE between 2009 and 2011.  He was CPFL’s representative to the Interconnected Operations Coordination Group for the Electrical System in South/Southeastern Brazil - GCOI/GTPO/ELETROBRAS between 1986 and 1996, representative of the distributors Paulista, Piratininga and RGE to the work group for the Initial Public Offering (IPO) of CPFL Energia on the São Paulo and New York Stock Exchanges in 2006.  He has also served as the Coordinator of the Technical Losses Group at the Brazilian Association of Electricity Distributors (ABRADEE) between 2005 and 2006, and was a professor of the Course on Technical Losses in the Energy Sector at the COGI Foundation between 2005 and 2006.  He has also served as the CEO of RGE between June 2011 and April 2013 and as the CEO of CPFL Paulista and CPFL Piratininga between 2013 and 2015.  Since 2015, he has been our Chief Regulated Operations Officer. Karin Regina Luchesi– Ms. Luchesi graduated in Material Production Engineering from the Federal University of São Carlos in 2001 and obtained an Executive Master’s degree in Finance from Insper in 2010.  She began her career in the Electric Sector, at the Electric Power Trading Chamber - CCEE.  She has held several positions within our company since 2001, serving for seven years as Manager of the Department of Energy Purchase and Sale Contract Management.  In June 2011 she became Distribution Energy Sale Officer, while also acting as Energy Planning and Energy Management Officer from January to May 2014.  Since May, 2014, she has been the CEO of CPFL Generação, in addition to acting as an Officer at CPFL Transmissão, Paulista Lajeado and CPFL Jaguari de Geração and sitting on the Boards of Directors of CPFL Renováveis, CERAN, Chapecoense, Foz do Chapecó, ENERCAN, BAESA and EPASA.  Since 2015, she has been our Chief Market Operations Officer. Wagner Luiz Schneider de Freitas –Mr. Schneider de Freitas graduated in Metallurgical and Material Engineering from the Military Institute of Engineering (IME/RJ) in 1994 and obtained specializations in Material Engineering from the Federal University of Paraná (UFPR), in 1996, in Logistics from Logistical Institute of the Aeronautical Logistics (ILA), in 1997, and a Master’s degree in Mechanical and Aeronautical Engineering, Industrial Management and Strategic Development from the Intitute of Aeronatical Technology (ITA), in 2003.  Between 1998 and 2000, he was as a Quality Engineer at Volkswagen/Audi.  He was also a Quality Engineer at Embraer between 2000 and 2003 in São José dos Campos, São Paulo, and later an Operations and Quality Engineer in Fort Lauderdale, Florida, between 2003 and 2005.  He also served as a Senior Manager in São José dos Campos, São Paulo between 2005 and 2008.  He served as a consultant at McKinsey & Company between 2008 and 2010.  He served as the Operations Officer of Grupo Positivo between 2010 and 2012 and as the Research and Development Officer of Whirlpool - Embraco.  He currently serves as the Administrative Officer at CPFL Paulista, CPFL Piratininga, RGE, CPFL Geração and other subsidiaries of CPFL Energia.  Since 2015, he has been our Chief Planning and Business Management Officer. Carlos da Costa Parcias Junior– Mr. Parcias graduated in Economics from the Federal University of Rio de Janeiro (UFRJ) in 1984 and obtained a Master’s degree in Economics from the Pontifical Catholic University of Rio de Janeiro (PUC/RJ) in 1988.  He has held several senior leadership positions in the financial industry, serving as an advisor to the Presidency of BNDES, between 1990 and 1992, the Executive Officer at JP Morgan Brazil between 1992 and 1993, the Head of Capital Markets at BBA‐Creditanstalt Bank, between 1993 and 1995, as the CEO at BBA‐Capital Asset Management, between 1996 and 1998, as the Head of Investment Banking at Fleming Graphus between 1998 and 2000, and as the CEO at Icatu Gestão de Participações, between 2001 and 2003. Between 2004 and 2010, he managed his own Independent Financial Advisory Firm, focusing on mergers and acquisitions and private equity transactions.  In 2011, he was the Director of Equity Investments in Energy at Camargo Correa Holding Company.  Since 2012, he has been our Business Development Vice-President.


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 Luiz Eduardo Fróes do Amaral Osòrio –Mr. Osório graduated in Law from the Pontifical Catholic University of Rio de Janeiro (PUC/RJ) in 1999 and obtained a Master’s degree in Development Management from the School of International Service at American University, of Washington, D.C., 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.  Mr. Osório has held senior leadership and management positions in multinational companies such as AmBev, Diageo, Shell and Raízen.  In addition, 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 a sitting member of the Board of Directors of CPFL Renováveis and Instituto CPFL.  Since May 2014, he has been our Chief Institutional Relations and Legal Officer. Andre Dorf– Mr. Dorf graduated in Business Administration from Fundação Getúlio Vargas. He started his career in investment banking, where he held several positions between 1996 and 2003 in banks such as Banco Patrimônio de Investimento (JV with Salomon Brothers), Chase Manhattan Bank and JP Morgan (both in São Paulo and New York offices). Between 2003 and 2010, he held senior positions at Suzano Papel e Celulose, where he served as Chief Executive Officer of Suzano Energia Renovável (2010-2013), Executive Director – Strategy, Business Development and Investor Relations (2008-2010), Executive Director - Paper Business Unit (2005-2008) and Executive Director – Corporate Development, New Businesses and IT (2003-2005).  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 and may be composed of a minimum of three and a maximum of five members (and their respective alternate 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 (and her/his respective alternate member). See "Item 7. Major Shareholders and Related Party Transactions-Shareholders' Agreement- Corporate Governance". 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, 2015, with a mandate of one year, is composed of five members: William Bezerra Cavalcanti Filho (Chairman), Marcelo de Andrade, Adalgiso Fragoso de Faria, Carlos Alberto Cardoso Moreira 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 Our bylaws allow our Board of Directors to establish committees andad hoccommissions to assist the Board of Directors with strategic issues. Currently, there are three committees within the Company: the Management Processes Committee, the Human Resources Management Committee and the Related Parties Committee, all governed by the Internal Rules of Committees of the Board of Directors. See "Item 7. Major Shareholders and Related Party Transactions-Shareholders' Agreement- Corporate Governance". 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.  Until 2014, we had a Management Processes Committee and a Risk Management Commission, which was established ad hoc to update the Risk Management Policy.  In 2015, the Board of Directors approved the termination

of the Risk Management
Commission, which was merged with the Management Processes Committee, and
established the "Management Processes and Risks Committee".The members of this
committee are Fernando Luiz Aguiar Filho, João Ernesto de Lima Mesquita and
Augusto Etchebehere Tavares de Tavares.


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Table of Contents
 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-Presidents of 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 are Arthur Prado Silva, Francisco Caprino Neto and
Carlos Alberto Cardoso Moreira. Related Parties
Committee.  Our Related Parties Committee is responsible for
assisting the Board of Directors by: (i) evaluating the selection
procedures of suppliers and third‐party construction and other services from
related parties and ensuring these transactions are conducted fairly and
consistent with market practice and (ii) evaluating energy purchase or sale
agreements with related parties ensuring these transactions are conducted fairly
and consistent with market practice.  The members of this committee are
Paola Rocha Ferreira, Fernando Luiz Aguiar Filho, and Alexandre Jose Fava de
Souza Junior. In addition to the
advisory committees, our Board of Directors may createad hoccommissions, if
deemed necessary.  The main responsibilities of anad hoccommission include
evaluating and addressing specific matters that may arise.  In 2015, our
Board of Directors set up twoad hoccommissions: the Strategy Commission and the Finance and
Budget 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 the criteria for individual compensation levels. Pursuant to Article 17
of our bylaws, the Board of Directors is responsible for establishing the
individual monthly compensation due to the executive officers, with due
observance to the aggregate amount approved by the shareholders. 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. 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
2015: Compensation for the year ended December 31,
      2015Management Bodies
    Board of Directors
    Fiscal Council
    Executive Officers
    TotalNumber of members
    7members(1)
    5members(1)
    6.67members(1)Fixed annual compensation:
    (in thousands ofreais)Salary
    1,642
    720
    7,016
    9,378Direct or indirect benefits
    -
    -
    263
    263Other
    329
    144
    871
    1,344Variable compensation:Bonus
    -
    -
    5,568
    5,568Other
    -
    -
    -687
    -687Post‐employment benefits
    -
    -
    553
    553Total
      compensation
    1,971
    864
    13,584
    16,419
 
 (1)   Represents the
weighted average number of members.


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Table of Contents  The table below sets
forth the compensation paid by our subsidiaries to our management for
2015: Year ended December 31,
      2015Board of Directors
    Fiscal Council
    Executive OfficersFixed
    Fixed
    Total (fixed and
      variable)(in thousands ofreais)Subsidiaries(1)
    -
    ‐
    4,337
  
 (1)   Compensation
amounts include charges and accruals.  The table below shows the aggregate compensation expected to be paid directly by
CPFL Energia to the members of our Board of Directors and Fiscal Council and our
executive officers for 2016 (excluding any compensation to be paid by our
subsidiaries to such individuals):  Approved compensation for the year ending
      December 31, 2016(1)Management Bodies
    Board of Directors
    Fiscal Council
    Executive Officers
    TotalNumber of members
    7members(2)
    5members(2)
    7members(2)Fixed annual compensation:
    (in thousands ofreais)Salary
    1,844
    809
    8,038
    10,691Direct or indirect benefits
    -
    -
    321
    321Other
    369
    161
    2,251
    2,781Variable compensation:Bonus
    -
    -
    8,180
    8,180Other
    -
    -
    5,888
    5,888Post‐employment benefits
    -
    -
    729
    729Total compensation
    2,213
    971
    25,407
    28,590
  (1)Represents the expected compensation for a twelve-month
period (from May 2016 to April 2017), to be approved in the Annual Shareholders'
Meeting of CPFL Energia, which will take place on April 29, 2016. (2)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$43 million for 2015, including R$11 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.


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Table of Contents
 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.  Alternate members do not receive
any compensation, except when actually representing the relevant effective
member. Compensation of
Executive Officers Our executive officers
receive a fixed monthly salary (adjusted according to research annually carried
out by specialized companies), 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
weaim to
create a long‐term vision and foster commitment, aligning the interests of our
executive officers and our shareholders and rewarding positive results and the
sustainable creation of value. 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 (the executive officers of CPFL Energia, the Chief Executive
Officers of our controlled companies and eligible Directors and Managers of CPFL
Energia) 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.


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Table of Contents
 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. In 2015, 204,919
phantom stocks were granted, considering the valuation of the CPFL Energia,
divided by the number of shares available in the market. The total expense
amount accrued by us related to the ILP was R$2,477 as of December 31,
2015. 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, 2015: Pension Plans for Executive OfficersName of pension plan
    PGBL Bradesco
    PGBL Brasil PrevNumber of Executive Officer members
    5
    1Number of Executive Officer members eligible for
      retirement
    5
    1Early retirement provisions
    None
    NoneInflation-adjusted value of pension plan
      contributions held at year-end, excluding contributions made directly by
      beneficiaries (in thousands ofreais)
    1,002
    148Amount of pension plan contributions made during
      the year, excluding contributions made directly by beneficiaries (in
      thousands ofreais)*
    205
    4Provisions for early redemption by beneficiary, if
      any
    At any time, subject to vesting
rules.
    At any time, subject to vesting
  rules.
 
 (*)          
Inflation-adjusted.  Share
Ownership The total number of
common shares owned by our directors and executive officers as of March 31, 2016
was 115,972.  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, 2015, we had 9,890 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 31,2015
    2014
    2013Distribution
    5,248
    4,706
    4,503Conventional Generation
    106
    108
    106Renewable Generation
    391
    357
    329Commercialization
    48
    49
    51Services
    2,554
    2,367
    1,822Corporate staff
    1,543
    1,549
    1,580Total
    9,890
    9,136
    8,391


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Table of Contents  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 27 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 2015, we
reserved R$54 million (R$49 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, 2015.  Percentages in the following table
are based on 993,014,215 outstanding common shares. Common Shares
    (%)BB Carteira Livre I FIA
(1)
    262,698,037
    26.45ESC Energia S.A. (2)
    234,086,204
    23.57Energia São Paulo FIA (3)
    146,463,379
    14.75Bonaire Participações S.A.
    (4)
    1,238,334
    0.12Bradespar S.A. (5)
    52,156,383
    5.25BNDES Participações S.A.
    (6)
    66,914,177
    6.74Executive officers and directors as a
      group
    105,672
    0.01Total
    763,662,186
    76.90
  
 (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.


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 Shareholders’
Agreement Number of Shares
subject to the Shareholders' Agreement entered into on March 22, 2002, amended
on August 27, 2002, on November 5, 2003 and on December 6, 2007, or subject
shares: Shareholder
    Common Shares(*)
    (% in the Controlling Shareholder
      Block)BB Carteira Livre I FIA.
    262,698,037
    40.8ESC Energia S.A.
    234,086,204
    36.3Energia São Paulo FIA.
    146,463,379
    22.7Bonaire Participações S.A.
    1,238,334
    0.2Total
    644,485,954
    100.0
 (*) Pursuant to the Shareholders'
Agreement, any shares further issued by CPFL Energia resulting from a
subscription, a stock split and/or a stock bonus, which may increase the equity
stake of the abovementioned controlling shareholders in CPFL Energia's capital
stock, shall be held subject and bound to the Shareholders' Agreement. It is
worth noting that, the abovementioned controlling shareholders of  CPFL
Energia, or controlling shareholders, entered into an Untying Term, under which
they agreed that the shares issued by CPFL Energia by means of the Annual
Shareholders' Meeting held on April 29, 2015, as a result of a stock bonus, and
freely distributed to the controlling shareholders would not be subject and,
therefore, bound to the Shareholders' Agreement. Voting
Rights.  Our Shareholders’ Agreement, among ESC Energia,
BB Carteira Livre I FIA, Energia São Paulo FIA, Bonaire and us, as intervening
and consenting party, or Shareholders' Agreement, governs control of us and our
subsidiaries. Preliminary Meetings.Under
the Shareholders' Agreement, the controlling shareholders shall exercise the
voting rights attached to their common shares in CPFL Energia's capital stock
according to the terms of the Shareholders' Agreement, which include, among
other provisions, an obligation for the controlling shareholders to hold
preliminary meetings before any Shareholders' Meetings or certain Board of
Directors' meetings of CPFL Energia, its controlled companies or companies in
which CPFL Energia holds at least 10.0% of the capital stock, without
controlling them (or investee companies), with the purpose of previously
defining the direction of the vote to be casted by them (or their
representatives) in the relevant Shareholders' Meetings or Board of Directors'
meetings.  According to Section 5.4 of the Shareholders' Agreement, the
preliminary meetings are mandatory with regards to any matters to be approved in
a Shareholders' Meeting or to any matters which require the approval of a
qualified majority of the members of the Board of Directors, or which concern
the election of executive officers and the execution of agreements in an amount
exceeding R$40.1 million (nevertheless, any controlling shareholder may require
a preliminary meeting to resolve on any other matter to be submitted to the
approval of the members of the Board of Directors). All resolutions to be
decided in the preliminary meetings shall be subject to the approval by a simple
majority, except for those matters to be approved in a Shareholders' Meeting and
those matters which require the approval of a qualified majority of the members
of the Board of Directors, which shall be subject to the approval of the
controlling shareholders holding at least 80.0% of the subject shares (on March
31, 2016, BB Carteira Livre I FIA and ESC Energia S.A.). Pursuant to Section
5.5 of the Shareholders' Agreement, the controlling shareholders and their
representatives in the corporate bodies shall cause the suspension or the
postponement of any Shareholders' Meeting or Board of Directors' meeting called
to resolve on any matter that is subject to a preliminary meeting, whenever
(i) for any reason whatsoever, a preliminary meeting could not be held up
to the date of the Shareholders' Meeting or Board of Directors' meeting; or
(ii), the controlling shareholders could not reach a valid agreement on the
relevant matter, despite deliberating the relevant matter at a preliminary
meeting. Section 5.10 of the
Shareholders' Agreement provides that the chairperson of the Shareholders'
Meeting or the chairman of our Board of Directors shall not take into account
any vote casted by a representative of a controlling shareholder against any
provision of the Shareholders' Agreement or against any resolution approved in a
preliminary meeting, in which case any representative of the other controlling
shareholders will be entitled to, by providing a copy of the minutes of the
relevant preliminary meeting, require that the vote of the defaulting
controlling shareholder is considered and computed in the same manner agreed in
the preliminary meeting. In addition, section 5.11 of the Shareholders'
Agreement establishes that, if a representative of a controlling shareholders
fails to attend a Shareholders' Meeting or a Board of Directors' meeting, as the
case may be, or abstain from voting therein, the representative of any other
controlling shareholder attending the relevant meetings shall beentitled to vote, as
applicable, (i) in the relevant Shareholders' Meeting with the shares owned by
the absent or missing controlling shareholder, or (ii) in the relevant Board of
Directors' meeting on behalf of the absent or missing director.


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 Shareholders'
Meetings.Section 6 of the Shareholders' Agreement governs the
exercise of the voting rights by the controlling shareholders in any
Shareholders' Meeting of CPFL Energia.  Section 6.2 provides that the
resolutions to be taken in a Shareholders' Meeting require the approval of the
majority of the shareholders attending the meeting, except for the matters to
which the Law requires a qualified majority.  Section 6.3 also establishes
that, without prejudice to the provisions of Section 6.2, the controlling
shareholders are compelled to attend all Shareholders' Meetings of CPFL Energia
and exercise their voting rights aiming at ensuring that any resolution to be
taken therein are approved as agreed by the controlling shareholders in the
preliminary meeting, by the votes of the controlling shareholders holding at
least 80.0% of the subject shares (on March 31, 2016, BB Carteira Livre I FIA
and ESC Energia S.A.). Pursuant to Section 6.4 of the Shareholders' Agreement,
any vote casted by a controlling shareholder of CPFL Energia against the
resolutions approved in a preliminary meeting shall be held null (and the vote
shall be held invalid), without prejudice to the right of the other controlling
shareholders to foster the specific execution or claim a right for losses and
damages. See "Item 10. Additional Information–Memorandum of
Incorporation–Shareholders' Meetings". Board of Directors'
Meetings.Section 7 of the Shareholders' Agreement governs the
exercise of the voting rights by the members of the Board of Directors. 
Section 7.1 provides an obligation for the controlling shareholders to instruct
the members of the Board of Directors appointed by them to vote in the Board of
Directors' meetings according to the Shareholders' Agreement and the final
resolution taken by the controlling shareholders in the preliminary
meetings.  Sections 7.3 and 7.4 establish that the resolutions of the Board
of Directors shall be taken by the simple majority of its members attending a
Board of Directors' meeting, except for the following matters, which require the
approval of at least 70.0% of the directors appointed by the controlling
shareholders: ·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$40.1 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; ·amendments to 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 Shareholders' Agreement provides, in Sections
8.2.1 and 8.2.1.1, that the controlling shareholders shall jointly appoint six
members of the Board of Directors, of the seven total members, as
follows: ·three
appointed by ESC; ·two
appointed by BB Carteira Livre I FIA; and ·one
appointed by Energia São Paulo FIA/Bonaire. If the non-controlling
shareholders, exercising their rights under the corporate law, elect the
independent director required by the BM&FBOVESPA’sNovo
MercadoListing Rules, ESC, BB Carteira Livre I FIA 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, BB Carteira Livre I FIA and Energia São Paulo FIA/Bonaire shall
jointly appoint such independent director. According to
Section 8.2.4 of the Shareholders' Agreement, in the first meeting
following the election of the directors, (i) the chairman of our Board of
Directors shall be appointed among those directors appointed by the controlling
shareholder individually owning most part of the subject shares; and (ii) the
Vice-Chairman shall be appointed among those directors appointed by the second
controlling shareholder individually owning most part of the subject shares. Section 8.3 provides
that, in the event of multiple voting (voto múltiplo), the controlling
shareholders shall be compelled to distribute their votes aiming at reflecting
the proportionality of the composition of the Board of Directors described
above. Our Fiscal Council
consists of five members, appointed as follows: ·two
appointed by ESC; ·two
appointed by BB Carteira Livre I FIA; and ·one
appointed by Energia São Paulo FIA/Bonaire. Section 10.3.2
establishes that, if the non-controlling shareholders decide to appoint
(i) one member of our Fiscal Council, then ESC, BB Carteira Livre I FIA and
Bonaire shall be entitled to individually appoint one member of the Fiscal
Council and ESC and BB Carteira Livre I FIA shall be entitled to jointly appoint
the other member; and (ii) two members of our Fiscal Council, then ESC and
BB Carteira Livre I FIA shall be entitled to individually appoint one member of
the Fiscal Council and ESC, BB Carteira Livre I FIA and Bonaire shall be
entitled to jointly appoint the other member. The number of members
of the Board of Directors and the Fiscal Council nominated by each controlling
shareholder under the Shareholders’ Agreement is related to the current stakes
of the controlling shareholder in the controlling shareholder block.  If a
change in the stakes of any controlling shareholder in the enjoined shares
occurs, the number of members for which such controlling shareholder has the
right to nominate shall be adapted to reflect such modification so as to
maintain unchanged the number of members nominated by the controlling
shareholder whose stakes relative to the total of enjoined shares have not been
altered.


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 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. With regards to the
Advisory Committees, the Shareholders' Agreement establishes certain rules for
their relevant compositions and purposes, such as the right of the controlling
shareholders to appoint one member each of the Management Processes Committee,
the Human Resources Management Committee and the Related Parties
Committee. Transfer of
Shares.  Our Shareholders’ Agreement provides for certain
rights and obligations in the event of transfer of subject shares,
including: ·Right of First Refusal.  The controlling
shareholders 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, or whenever the subject shares of a controlling shareholder are
judicially seized or pledged. ·Tag‐along Rights.  A controlling shareholder
that decides not to exercise its right of first refusal has the option to sell,
together with the selling controlling shareholders, its subject shares to the
acquiring third party (pro rata, except if the purchase of the subject shares by
the third party results in such third party becoming the owner of most part of
the subject shares, in which case the controlling shareholders will be entitled
to sell all the subject shares held by them in the capital stock of CPFL
Energia). 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%. ·Tag‐along Rights of Energia São Paulo
FIA/Bonaire.  In the event of a sale, assignment or transfer of
subject shares by BB Carteira Livre I FIA 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 not exercised its right
of first refusal, it will have the right to sell its entire stake of subject
shares together with BB Carteira Livre I FIA or ESC, under the same terms and
conditions. Change of
Control.  In the event of direct or indirect change of
control of any of the controlling shareholders subject to the Shareholders’
Agreement, the remaining controlling shareholders have the right to acquire all
subject shares held, directly or indirectly, by the controlling shareholders
undergoing the change of control, paying for such shares an amount to be
determined by a recognized financial institution. The Shareholders'
Agreement provides for certain exceptions and further details on the transfer of
shares and change of control, such as in the event of transfer of shares to
affiliated companies, in which case, provided that observed certain conditions,
the right of first refusal shall not apply. Option
Agreement Our controlling
shareholders are also parties 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 concessioncompanies, and it has
equity participations in a significant Brazilian financial conglomerate and in a
global aluminum company.


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 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 borrowings.  For balances and further details please see note 32
to our audited annual consolidated financial statements. Our subsidiaries CPFL
Paulista, CPFL Piratininga and CPFL Geração 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
for further information on “Related Party Transactions”. ITEM 8.Financial Information Consolidated
Statements and Other Financial Information See
Item 18.  Financial Statements. 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$112.5 million as of December 31, 2015.  This amount consists of R$38
million where we believe the likelihood of loss is probable; R$28.5 million
where we believe the likelihood of loss is possible; and R$46 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$28 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$162 million as of December 31, 2015.  We believe that
the likelihood of loss is possible.


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 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$54
million as of December 31, 2015.  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$360 million in 2007 and R$54 million in 2011 (adjusted to R$746
million as of December 31, 2015 to account for inflation) in order to
prevent any attachment of assets by the tax authority and enable CPFL Paulista
to appeal the claim.  In January 2016, CPFL Paulista obtained court
decisions that authorized the replacement of the escrow deposits by financial
guarantees (letter of guarantee and performance bond), for which the withdrawals
on behalf of CPFL Paulista occurred in 2016. 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.
We believe that the likelihood of loss in both proceedings is
possible. CPFL Geração 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 Geração and Furnas are joint venture partners, although the concession for
the Serra da Mesa project is held by Furnas alone.  The plaintiffs, who
were owners of a lumberyard, seek compensation of R$1,493 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
Geração 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. CPFL Geração is
subject to a tax claim in the amount of approximately R$245 million as of
December 31, 2015 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$464 million as of December 31,
2015 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$48 million,
R$214 million and R$245 million, respectively, as of December 31, 2015,
alleging excess goodwill amortization forpurposes of
calculating IRPJ and CSLL taxes.  Our appeals in this case are awaiting
decision.  We believe that the likelihood of loss is possible.


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 An arbitration
proceeding was filed against CPFL Comercialização Brasil S.A., referring to
commercial partnership agreements executed with Pedra Agroindustrial and other
parties.  The proceeding is based on an alleged breach of contractual
obligations by us in three consortiums established for the construction and
operation of thermoelectric energy plants.  This proceeding is in the
evidentiary phase and we believe the risk to CPFL Comercialização Brasil S.A. is
remote, considering the Burden Sharing Agreement (Instrumento de Assunção de
Responsabilidades) CPFL Comercialização Brasil S.A. has executed with CPFL
Renováveis, under which CPFL Renováveis would assume any eventual obligations.
We believe that the likelihood of loss for CPFL Renováveis is possible. The
amount claimed totaled approximately R$181.6 million as of December 31,
2015.  CPFL Paulista is
subject to several tax collection proceedings filed by the city of Ribeirão
Preto, charging land use taxes for the years of 2005, 2007, 2008, 2009 and
2014.  We have submitted a defense for this claim, which was accepted due
to previously recognized unconstitutionality of the tax.  Currently, we are
waiting for the judgment of the appeal filed by the city of Ribeirão Preto. We
believe that the likelihood of loss is remote.  The amount claimed totaled
approximately R$245 million as of December 31, 2015. The Brazilian Federal
Revenue Authority filed a tax assessment notice and imposed a fine on Sul
Geradora Participações S.A., claiming IRF values on the payment of interest of
an operation in which Sul Geradora Participações S.A. was prepaid for energy
exports.  The Brazilian tax authority claims the Sul Geradora Participações
S.A. used resources obtained with this operation to acquire credits against
companies of its own corporate group and not to finance its exports.  We
filed a defense to these allegations, which was judged groundless.  We then
filed a voluntary appeal, which was allowed to proceed.  The Brazilian
Federal Revenue Authority filed a special appeal, which was allowed to proceed
and therefore maintained the notice assessment.  We are currently awaiting
a formal judgment to be delivered on the appeal filed by Sul Geradora
Participações S.A. We believe the likelihood of loss is possible.  The
amount claimed totaled approximately R$81 million as of December 31,
2015. The Brazilian Federal
Revenue Office imposed an infraction notice and a fine on CPFL Geração, charging
it with overdue taxes during the years of 2004, 2005, and 2006, resulting from
certain excess expenses and omission of revenues by the defendant.  We
filed an appeal to this case, which was judged groundless.  We have also
filed a voluntary appeal.  This case currently awaits a decision of the
aforementioned voluntary appeal.  We believe the likelihood of loss is
possible.  The amount claimed totaled approximately R$85 million as of
December 31, 2015. 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,
2015, our provisions for contingencies were approximately R$570 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, 2015, the
ADSs represented 4.7% of our shares and 14.7% of our current global public
float.


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 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. 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 inreaisper 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. Reaisper Common
      share
    U.S. dollars per ADSHigh
    Low
    High
    Low2010 (*)
    22.00
    17.42
    25.64
    19.102011 (*)
    26.50
    19.43
    30.56
    22.152012
    29.30
    21.28
    32.94
    20.752013
    23.57
    18.39
    22.78
    15.492014
    22.74
    15.42
    20.19
    12.562015
    21.20
    14.17
    14.40
    6.952014:First Quarter
    18.87
    15.42
    16.57
    12.85Second Quarter
    20.83
    17.70
    18.55
    15.79Third Quarter
    22.74
    19.11
    20.19
    15.55Fourth Quarter
    20.18
    17.18
    16.74
    12.562015:First Quarter
    20.46
    16.56
    14.40
    11.06Second Quarter
    21.20
    18.69
    14.21
    11.97Third Quarter
    19.81
    14.17
    12.58
    6.95Fourth Quarter
    16.71
    14.51
    9.12
    7.332016:January
    16.21
    13.87
    8.20
    6.75February
    17.15
    15.73
    8.70
    7.96March
    20.30
    16.75
    11.10
    8.65April (up to April 11)
    19.66
    18.43
    11.06
    10.08
 
 (*)   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.


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 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.); 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, business management processes,
corporate risk management, sustainability and financial policies.  Whenever
necessary,ad hoccommissions are installed to advise the Board of
Directors on specific issues, such as strategies, budget, new operations,
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 Mercadosegment.  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 2015, we
amended our bylaws, in order to include: (i) a capital increase through the
capitalization of profit reserves, with consequent stock bonus; (ii)
modifications in the composition of the Board of Executive Officers; (iii)
modifications in the scope of powers to approve certain matters by the Board of
Executive Officers; (iv) monetary adjustment of values expressly determined by
the Bylaws; and (v) language improvements and inclusion of cross references for
improved understanding of the Bylaws. 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.


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 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 fostering, sale
industry, building, and/or operating projects concerning electricity generation,
distribution, transmission and related services. Qualification of
Directors and Executive Officers 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. 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. Under our bylaws, the
net profit, as calculated under Brazilian Accounting Principles and adjusted
under Brazilian Corporate Law, for the preceding fiscal year, shall be allocated
as follows: (i) 5.0%, before any other allocation, to form the legal
reserve, until it reaches 20.0% of CPFL Energia’s capital stock (under Brazilian
Corporate Law, we are not forced to make any allocation to the legal reserve in
relation to any fiscal year in which the sum of the legal reserve and certain
capital reserves exceeds 30.0% of CPFL Energia’s capital stock); (ii) payment of
mandatory dividends; (iii) accrual of the reserve for adjustment of the
concession final assets, monthly, or in other periodicity defined by CPFL
Energia, with the profit or loss related to changes in expected cash flows of
the concession final assets of the controlled companies, recognized by CPFL
Energia through equity income and accounted for in the income statement of the
period, net of tax effects. The amount to be allocated for this reserve shall be
limited to the balance of the retained earnings or accumulated losses account,
after the possible accrual of reserve for contingences, tax incentives or
unearned profits (the realization of the reserve for adjustment of the
concession final assets shall occur at the end of the concessions of the
controlled companies, upon the payment of the indemnification by the government,
as well as by the write-off of the concession financial asset resulting from the
corporate sale or restructuring, and will result in the reversal of the
respective amounts to "retained earnings and accumulated losses"). The balance
of the reserve for adjustment of the concession final assets cannot exceed the
balance of the concession financial asset recorded in CPFL Energia's
consolidated financial statements; (iii) the remaining profit, except as
otherwise resolved by the Shareholders' Meeting, shall be allocated to the
workingcapital reinforcement
reserve, the total of which shall not exceed the amount of the subscribed
capital stock; and (iv) in the event of loss in the year, the accrued reserves
may be used to absorb the remaining loss, after absorption by the other
reserves, with the revenue for adjustment of the concession financial assets and
the legal reserve, in this order, the last to be absorbed.


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 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, through a unanimous decision in a General
Shareholders’ Meeting, decide to distribute dividends in an amount lower than
the mandatory distribution or retain the net profit exclusively for purposes of
fundraising by means of non-convertible debentures. 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,
among other matters, on the payment of an annual dividend.  Additionally,
interim dividends may be declared by our Board of Directors. Any interim
dividend paid may be set off against the amount of the mandatory dividend
payable for the fiscal year in which the interim dividend was paid. 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 do
Brasil S.A. as of January 1, 2011.  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. 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 thedepositary’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. In order to do so, the holder must be a duly qualified investor under
Resolution No. 4,373 by registering with the CVM and the Brazilian Central Bank
and appointing a representative in Brazil.


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 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. 3.691, dated December 16,
2013, 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 make distributions to
shareholders of interest on shareholders' equity and treat such payments as a
deductible expense for purposes of calculating Brazilian corporate and social
contribution purposes on net profit.  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 as interest on shareholders’
equity) for the period in respect of which the payment is made; or ·50.0% of
the sum of retained profits 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%, or 25.0% %, if the Non-Brazilian
holder is domiciled in a Favorable Tax Jurisdiction.  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
(gross up).  If we distribute interest attributed to shareholder’s equity
in any year, and that distribution is not accounted for as part of mandatory
distribution, Brazilian income tax would be borne by the shareholders.  For
IFRS accounting purposes, interest attributable to shareholders’ equity is
reflected as a dividend payment. Under our bylaws,
interest attributable to shareholders’ equity may be treated as a dividend for
purposes of the mandatory dividend.


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 In 2015, our Board of
Directors approved a declaration of dividends in the amount of R$205 million (or
R$0.206871098 per common share) from our 2015 net income and to be paid to our
shareholders as a mandatory dividend in 2016 as required under Brazilian
Corporate Law.  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 also
approved the allocation of R$393 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 shareholders’
meetings, shareholders are generally empowered to take any action relating to
our corporate purpose and to pass such resolutions as they deem necessary. 
Shareholders’ meetings may be ordinary, such as the annual meeting, or
extraordinary.  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 shareholders’ meeting immediately following such
fiscal year.  The election of our directors and members of our fiscal
council (and the definition of the aggregate compensation to be paid to the
members of the Board of Directors, the fiscal council and the executive
officers), 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, among others provided under Brazilian
Corporate Law and/or our bylaws, may only be taken at a special shareholders’
meeting: ·amendment
to 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; ·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;


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 ·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 our participation in a group of companies (as defined in Brazilian Corporate
Law); ·approval
of the dissolution of CPFL Energia; ·reduction
of capital stock ·the
increase in CPFL Energia's capital stock, as well as the issuance of convertible
debentures or subscription warrants (bônus de
subscrição) beyond the limits of the authorized capital; ·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 inspect and monitor our management, in accordance with the Brazilian
Corporation Law; ·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 holding a
shareholders’ meeting shall consist 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.  There are
certain exceptions to the general rule, as in the case of a shareholders'
meeting with the purposes of (i) amending our bylaws, which shall only be held
with the presence 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; and (ii) appointing a financial institution responsible for our
valuation, in the event of cancellation of our registration with the CVM as a
publicly‐held company, which shall only be held with the presence of
shareholders representing at least 20.0% of our issued and outstanding voting
capital on the first call and any percentage on the second call.


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 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
or casting votes remotely (subject to the conditions provided under Brazilian
Corporate Law) at a shareholders’ meeting is required to ratify any proposed
action, with abstentions not taken into account (except for the provisions of
the Shareholders' Agreement. See 'Item 7 - Major Shareholders and Related
Party Transaction- Shareholders' Agreement"). However, other qualified quorums
may be imposed under Brazilian Corporate Law and the by-laws. An example of an
exception is the requirement under Brazilian Corporate Law due to which the
affirmative vote of shareholders representing at least one‐half of our issued
and outstanding voting capital is required to, among other matters: ·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; ·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. The
call notice must contain the date, time, place and agenda of the meeting, and in
case of amendments to the bylaws, the indication of the relevant matters. 
CVM Rule No. 481, of December 17, 2009, or CVM Rule No. 481, requires that
additional information is disclosed in the meeting call notice for certain
matters. For example, in the event of an election of directors, the meeting call
notice shall disclose, among other information, the minimum percentage of equity
interest required from a shareholder to request the adoption of multiple voting
procedures, as well as the relevant ballot paper for casting votes
remotely. 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, without prejudice to others
provided under Brazilian Corporate Law, 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;


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 ·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; any matter which entitles the
shareholders to exercise their withdrawal right; and ·merger,
spin-off, stock swap merger or consolidation with at least one public-held
company enrolled with CVM in a certain category (category A). Location of our
Shareholders’ Meetings Our shareholders’
meetings take place at our head offices in the city of São Paulo, state of São
Paulo.  Brazilian Corporate Law allows our shareholders to hold meetings
outside our head offices in the event of force majeure, provided that the
meetings are held in the City of São Paulo and the relevant notice contains a
clear indication of the place where the meeting will occur. Who May Call our
Shareholders’ Meetings Subject to the
provisions of the Brazilian Corporate Law and our bylaws, our Board of Directors
may ordinarily call ou shareholders’ meetings. These 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 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, in certain
cases, 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. For shareholders who are legal persons, in accordance with the
understanding of the Joint Committee of CVM issued in a meeting held on November
4, 2014 (CVM Proceeding RJ2014/3578), there is no need for the proxy to be (i) a
shareholder or manager of the Company, (ii) a lawyer, or (iii) a financial
institution. Recent amendments to
CVM Rule No. 481 have also ruled the right of our shareholders casting votes
remotely.  For such purposes, (i) we are requested to provide our
shareholders, up to one month before the date scheduled for certain
shareholders' meetings, with the ballot paper to cast votes remotely, and (ii)
our shareholders are requested to send back the relevant ballot paper directly
to us (by post or e-mail), or by giving instructions to certain authorized
services providers, no later than 7 days before the date scheduled for the
shareholders' meeting.We may request
rectifictions in the ballot paper sent by shareholders wishing to cast votes
remotely.  In certain specific cases and under certain conditions, we might
provide our shareholders with a more beneficial deadline or mechanism to send
back the ballot papers, or to attend our shareholders' meetings (for example, by
means of an electronically system which may allow them to remotely attend our
meetings).


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 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 According to CVM Rule
no 559/2015, whenever the contracts related to the ADSs program allow, the ADS
holders may instruct the depositary to vote the number of common shares that
their ADSs represent, otherwise the depositary shall exercise the voting rights
related to such shares in the best interest of the ADS holders. 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.  Pursuant to Brazilian
Corporate Law, our shareholders also have a general preemptive right to
subscribe for any convertible debentures and subscription warrants that we may
issue.  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.  Pursuant to Brazilian Corporate Law, holders are permitted to
transfer or dispose of their preemptive right for consideration. Pursuant to Brazilian
Corporate Law and our bylaws, our Board of Directors may decide to increase our
share capital within the limit of the authorized capital. Whenever such increase
is made through a stock exchange, through a public offering or through an
exchange of shares in a public which purpose is to acquire control of another
company, the Board of Directors is entitled to exclude the preemptive rights or
reduce the exercise period of such rights. 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; (vi) a change in our corporate form; (vii)
approval of our participation in a group of companies (as defined in Brazilian
Corporate Law); (viii) if the company resulting from a merger, spin-off or
consolidation with another company, which is a successor of a public-held
company, does not register itself with the CVM as a publicly‐held company,
within the deadlines provided under Brazilian Corporate Law; or (ix) stock swap
merger of the Company with another company, so that the Company becomes a
wholly-owned subsidiary of that company. Even shareholders who did not vote or
were not present at the relevant meeting may exercise this withdrawal
right.


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 If our shareholders
wish to withdraw from the Company due to a merger or a participation in a group
of companies, such right may only be exercised provided that the Company’s
shares have neither liquidity nor dispersion 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, except in certain specific cases provided for in Brazilian Corporate
Law.  After a term provided under Brazilian Corporate Law, 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. 4,373,
issued by the National Monetary Council on September 29, 2014, or Resolution
No. 4,373, provides that foreign investors may invest in financial and
capital markets in Brazil, including through the issuance of depositary receipts
in foreign markets in respect of shares of Brazilian issuers. 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 electronic
registration 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. 4,373/2014.  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”. 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
commonshares 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.


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 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 the financial and capital markets of
Brazil, including shares issued by Brazilian publicly trade corporations,
provided that the applicable requirements are met, especially those provided
under Resolution No. 4,373. According to
Resolution No. 4,373, investments of foreign investors shall be made in Brazil
pursuant to the same instruments and operational modalities available to the
investors resident or domiciled in Brazil.  The definition of foreign
investor includes individuals, legal entities, funds and other collective
investment entities, resident, domiciled or headquartered abroad. Pursuant to Resolution
4,373, among the requirements applicable to the investment of foreign investors
in the Brazilian financial and capital markets, the foreign investors must: (i)
appoint at least one representative in Brazil, which must be a financial
institution or other institution authorized by the Brazilian Central Bank to
operate in Brazil.  The local representative appointed by the foreign
investor shall be responsible for performing and updating the registration of
the investments made by the foreign investor to the Brazilian Central Bank, as
well as the registration of the foreign investor with the CVM; (ii) obtain a
registry as foreign investor with the CVM, through the representative appointed
pursuant to item (i) above; and (iii) establish or contract one or more
custodians authorized by CVM to perform custody activities. Securities and other
financial assets held by foreign investors pursuant to Resolution No. 4,373
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, or be registered
with clearing houses or other entities that provide services of
registration, clearing and settlement duly licensed by the Brazilian
Central Bank or the CVM.  In the case of Depositary Receipts (DRs), the
record must be made by the Brazilian custodian entity on behalf of the foreign
depositary institution. For purposes of the
mandatory registry with the Brazilian Central Bank of foreign investments in the
Brazilian financial and capital markets, Resolution No. 4,373 expressly provides
that simultaneous foreign exchange transactions (i.e. without effective transfer
of funds) shall be required in specific situations, including (i) conversion of
credits held by foreign investors in Brazil into foreign investment in Brazilian
companies; (ii) transfer of investments made in depositary receipts into foreign
direct investments (orinvestimento externo direto) or investments in the Brazilian
financial and capital markets; and (iii) transfer of investments in the
Brazilian financial and capital markets into foreign direct
investments. In addition,
Resolution No. 4,373 does not allow foreign investors to perform investments
outside of organized markets, except as expressly authorized by CVM through
specific regulation.  Pursuant to CVM Rule No. 560/15, the exceptions
for investments outside of organized markets include subscription, stock bonus,
initial purchase offers and the exercise of put options due to initial purchase
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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. 4,373, 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, or “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. 10,833/03.  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. 4,373, or a 4,373 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 4,373 Holder and (2) is not a
Favorable Tax Jurisdiction Resident; or by (B) a Non‐Brazilian Holder that
(1) is a 4,373 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. In addition, the Brazilian law governing the taxation of the capital
gains derived by Non-Resident Holders has been modified recently, increasing the
rates applicable in both cases mentioned above. As of 2017, such rates will
depend on the amount of the capital gain. The final tax burden will vary from
15% to 22.5%. 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%. In
such cases, the new rates of 15% to 22.5% shall also apply, starting in 2017.
Exception is made 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% (15% to 22.5% as of 2017) 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 incometax at the rate of 15%
(15% to 22.5% as of 2017) 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 4,373 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 should consult 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 4,373 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. 11,727/08 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. 1,037/10 and
Law No. 11,727/08.  If the Brazilian tax authorities determine that
the concept of “privileged tax regime” provided by Law No. 11,727/08 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.


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 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 are required 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. 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. See (-Interest Atrributable to Shareholders'
Equity). 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 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 4,373
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 byinvestors) and holders
are urged to consult their own tax advisors regarding their specific tax
situations.  This discussion 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; ·realestate 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 inreaisis 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 thereaisreceived 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 thereaisequal to their U.S. dollar value on the date of
receipt.  If anyreaisactually 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.  Becausesuch 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 adistribution 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, 2015, approximately 32.0% of our indebtedness was denominated in U.S. dollars.  Also at December 31, 2015, we had swap agreements that offset the exchange rate risk with respect to R$6,893 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$86 million (R$27 million if considering an hypothetical favorable 25.0% change in foreign currency exchange rates), 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, 2015, the amount of such liabilities, net of such assets and after giving effect to swaps, was R$12,150 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, 2015, would result in a net additional cash outflow of approximately R$607 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 ADSsDelivery 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 deliveredDistribution 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 madeDistribution 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 madeDistribution 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 madeDepositary 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 2015 we received the following payments from the depositary: (i) US$85,714 (or US$60,000 net of withholding income tax); and (ii) US$434,286 (or US$304,000 net of withholding income tax) for expenses incurred by us relating to the ADR program, including expenses related to the first year of the agreement between the depositary and us. ITEM 13.Defaults, Dividend Arrearages and Delinquencies None. ITEM 14.Material Modifications to the Rights of Security Holders and Use ofPROCEEDS 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, 2015.  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, 2015 based on the updated criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO in 2013. Based on such assessment and criteria, our Management has concluded that our internal control over financial reporting was effective as of December 31, 2015. In 2015 we implemented a new version of the billing system at our subsidiary RGE, the SAP Costumer Care System (CCS), which our Management has evaluated as a material change in our internal control over financial reporting. We have rigorously tested the new system before its implementation. Also, the related changes in our business processes and internal control over financial reporting have been dully recorded and assessed by our management for the year ended December 31, 2015. Our management believes the new system will generate productivity gains and improve our internal processes.   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, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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.


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 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, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) 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, 2015 of the Company and our report dated April 15, 2016 expressed an unqualified opinion on those financial statements. /s/ DELOITTE TOUCHE TOHMATSUAuditores Independentes  Campinas, São Paulo, BrazilApril 15, 2016  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. ITEM 16B.Code of Ethics We consider ethics to be an essential value for our 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 athttp://cpfl.riweb.com.br/Download.aspx?id=234243(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).


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  We finished reviewing our Code of Ethics in 2015, whereby suggestions from our employees and outside stakeholders have been implemented. The final version of our Code of Ethics was approved by our Board of Directors in January 27, 2016. Dissemination through all CPFL’s subsidiaries, employees and outside stakeholders will occur during 2016.  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, 2015 and 2014.  Our independent accounting firm was Deloitte Touche Tohmatsu Auditores Independentes for the years ended December 31, 2015 and 2014. Year ended December 31,2015

   2014(in thousands ofreais)Audit fees

   4,477

   5,978Audit‐related fees

   1,782

   2,098Tax fees

   257

   197All other fees

   ‐

   ‐Total

   6,516

   8,273
  “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 2015 and 2014, respectively. “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, 2015 and 2014, 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, 2015 and 2014, 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.


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 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 Exchange303A.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.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) monitoring the selection process of the Vice-Presidents of CPFL Energia and CEOs of controlled companies; (iii) defining criteria for compensation of the executive officers, including long and short‐term incentive plans, (iv) defining performance goals of the executive officers, (v) coordinating evaluation procedures of the executive officers, (vi) preparation of the plan of succession for executive officers and (vii) 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, to a certain degree, 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.


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Table of Contents  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 Exchange303A.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.
  ITEM 16H.Mine Safety Disclosure Not applicable. ITEM 17.Financial Statements Not applicable. ITEM 18.Financial Statements See pages F‐1 through F‐96, incorporated herein by reference.


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 ITEM 19.Exhibits No.

   Description1.1

   Amended and Restated Bylaws of CPFL Energia S.A. (together with an English version).2.1

   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.


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  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. 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. CCC Account: Fuel Usage Quota Account (Conta de Consumo de Combustível). CDE Account: Energetic Development Account (Conta de Desenvolvimento Energético). CCEAR: Agreements on Energy Commercialization in the Regulated Market (Contratos de Comercialização de Energia no Ambiente Regulado). CCEE: Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica).The short‐term electricity market, established in 1998 through the Power Industry Law, which replaced the prior system of regulated generation prices and supply contracts, formerly known as the Wholesale Energy Market. CNPE: National Energy Policy Council (Conselho Nacional de Política Energética). Concession Law: Federal Law No. 8,987, enacted on February 13, 1995, which 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. Conventional Free Consumers: Consumers whose contracted energy demand is at least 3 MW.  These consumers may opt to purchase conventional energy, entirely or partially, from another authorized selling agent under the terms of current legislation.  We refer to consumers who have exercised this option as “Conventional Free Consumers,” and those who meet the demand requirements but have not exercised the option to migrate to the free market as “Potential Conventional Free Consumers.”


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 DistributionNetwork: Electric network system that distributes energy to end consumers within a concession area. Distributor: An entity supplying electric energy to a group of consumers by means of a Distribution Network. EnergyAgreement: Agreement under which a generator commits to supply a certain amount of electricity and assumes the risk that its electricity supply could be adversely affected by hydrological conditions and low reservoir levels, which could interrupt the supply of electricity.  In such a case, the generator would be required to purchase electricity elsewhere in order to comply with its supply commitments. EPE: Energetic Studies Company (Empresa de Pesquisas Energéticas). ESS: System Service Charge (Encargo de Serviço do Sistema). FinalConsumer: A party that uses electricity for its own needs. 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. IGP-M: Market General Price Index (Índice Geral de Preços – Mercadopublished byFundação Getútlio Vargas). 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:According to ANEEL, a class of nominal system voltages lower than 2.3 kV. 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.


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 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). MVA:Mega Volt Ampère. ONS: National Electric System Operator (Operador Nacional do Sistema Elétrico). Parcel A Costs: Costs that are not under the control of the Distributor, including, among others, the following: (i) costs of electricity purchased pursuant to CCEARs; (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 in assets necessary to energy distribution activities, as well as maintenance and operational costs. PLD: Spot price used to valuate the energy traded in the spot market (Preço de Liquidação de Diferenças). Potential Conventional Free Consumers: Consumers who meet the relevant contracted demand requirements but have not exercised the option to migrate to the free market as Conventional Free Consumers. Potential Special Free Consumers:Consumers who meet the relevant contracted demand requirements but have not exercised the option to migrate to the free market as Special Free Consumers. PPT: Thermoelectric Priority Program (Programa Prioritário de Termeletricidade). Proinfa Program: Electric Energy Alternative Sources Incentive Program (Programa de Incentivo às Fontes Alternativas de Energia Elétrica). PRORET: Tariff Regulation Proceedings (Procedimentos de Regulação Tarifária). 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).


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 RTP: PeriodicTariff Revision (revisão tarifária periódica) SHPP or Small Hydroelectric Power Plants: Power projects with capacity from 3 MW to 30 MW. Special Free Consumers:Individual or groups of consumers whose contracted energy demand is between 500 kV and 3 MW.  Special Free Consumers may only purchase energy from renewable sources: (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. TE: Energy Tariff (Tarifa de Energia). TFSEE: Tax on the Supervision of Electrical Services (Taxa de Fiscalização de Serviços de Energia Elétrica). TEO:Energy Optimization Tariff (Tarifa de Energia de Otimização) 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. TSEE: Social Tariff for Electricity (Tarifa Social de Energia Elétrica). TUSD:Tariff for the Use of the Distribution System (Tarifa de Uso dos Sistemas Elétricos de Distribuição). TUST: Tariff for the Use of the Transmission System (Tarifa de Uso dos Sistemas Elétricos de Transmissão). UBP: Use of a Public Asset (Uso de Bem Público) 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 15, 2016. 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




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Deloitte Touche TohmatsuAv. Dr. José Bonifácio Coutinho Nogueira, 150 - 5o andarCampinas - SP - 13091-611 Brasil

   Tel: + 55 (19) 3707-3000Fax:+ 55 (19) 3707-3001www.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 ofCPFL Energia S.A.and subsidiaries (the “Company”) as of December 31, 2015 and 2014, 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, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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 ofCPFL Energia S.A.and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, inaccordance 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, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 15,2016 expressed an unqualified opinion on the Company's internal control over financial reporting.

DELOITTE TOUCHE TOHMATSU

Auditores Independentes

Campinas, São Paulo, Brazil

April 15,2016



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CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AT DECEMBER 31, 2015 AND 2014 (In thousands of Brazilian reais - R$)
  ASSETS

   

   Dec 31, 2015

   

   Dec 31, 2014 (*)CURRENT ASSETSCash and cash equivalents (note 5)

   

   5,682,802

   

   4,357,455Consumers, concessionaires and licensees (note 6)

   

   3,174,918

   

   2,251,124Dividends and interest on capital (note 13)

   

   91,392

   

   54,483Securities

   

   23,633

   

   5,324Taxes recoverable (note 7)

   

   475,211

   

   329,638Derivatives (note 35)

   

   627,493

   

   23,260Sector financial asset (note 8)

   

   1,464,019

   

   610,931Materials and Supplies

   

   24,129

   

   18,505Leases (note 10)

   

   12,883

   

   12,396Concession financial asset (note 11)

   

   9,630

   

   540,094Other receivables (note 12)

   

   922,541

   

   1,011,495TOTAL CURRENT ASSETS

   

   12,508,652

   

   9,214,704NONCURRENT ASSETSConsumers, concessionaires and licensees (note 6)

   

   128,946

   

   123,405Associates, subsidiaries and parent company (note 32)

   

   84,265

   

   100,666Escrow Deposits (note 22)

   

   1,227,527

   

   1,162,477Taxes recoverable (note 7)

   

   167,159

   

   144,383Sector financial assets (note 8)

   

   489,945

   

   321,788Derivatives (note 35)

   

   1,651,260

   

   584,917Deferred tax assets (note 9)

   

   334,886

   

   938,496Leases (note 10)

   

   34,504

   

   35,169Concession financial asset (note 11)

   

   3,597,474

   

   2,834,522Investments at cost

   

   116,654

   

   116,654Other receivables (note 12)

   

   560,014

   

   388,828Investments (note 13)

   

   1,247,631

   

   1,098,769Property, Plant and Equipment (note 14)

   

   9,173,217

   

   9,149,486Intangible assets (note 15)

   

   9,210,338

   

   8,930,171TOTAL NONCURRENT ASSETS

   

   28,023,819

   

   25,929,732TOTAL ASSETS

   

   40,532,471

   

   35,144,436
   The accompanying notes are an integral part of these financial statements.


F - 1

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CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AT DECEMBER 31, 2015 AND 2014 (In thousands of Brazilian reais - R$)
  LIABILITIES AND EQUITY

   

   Dec 31, 2015

   

   Dec 31, 2014 (*)CURRENT LIABILITIESTrade payables (note 16)

   

   3,161,210

   

   2,374,147Interest on debts (note 17)

   

   118,267

   

   97,525Interest on debentures (note 18)

   

   232,227

   

   293,108Borrowings (note 17)

   

   2,831,654

   

   1,093,500Debentures (note 18)

   

   458,165

   

   2,042,075Private pension plan (note 19)

   

   802

   

   85,374Regulatory charges (note 20)

   

   852,017

   

   43,795Taxes, fees and contributions (note 21)

   

   653,342

   

   436,267Dividends and interest on capital payable

   

   221,855

   

   19,086Estimated payroll

   

   79,924

   

   70,252Derivatives (note 35)

   

   981

   

   38Sector financial liability (note 8)

   

   -

   

   21,998Use of public asset (note 23)

   

   9,457

   

   4,000Other payables (note 24)

   

   904,971

   

   835,941TOTAL CURRENT LIABILITIES

   

   9,524,873

   

   7,417,104NONCURRENT LIABILITIESTrade payables (note 16)

   

   633

   

   633Interest on debts (note 17)

   

   120,659

   

   60,717Interest on debentures (note 18)

   

   16,487

   

   -Borrowings (note 17)

   

   11,592,206

   

   9,426,634Debentures (note 18)

   

   6,363,552

   

   6,136,400Private pension plan (note 19)

   

   474,318

   

   518,386Deferred tax liabilities (note 9)

   

   1,432,594

   

   1,401,009Provision for tax, civil and labor risks (note 22)

   

   569,534

   

   508,151Derivatives (note 35)

   

   33,205

   

   13,317Use of public asset (note 23)

   

   83,124

   

   80,992Other payables (note 24)

   

   191,148

   

   183,766TOTAL NONCURRENT LIABILITIES

   

   20,877,460

   

   18,330,004EQUITY (note 25)Issued capital

   

   5,348,312

   

   4,793,424Capital reserves

   

   468,082

   

   468,082Legal reserve

   

   694,058

   

   650,811Statutory reserve - concession financial asset

   

   585,451

   

   330,437Statutory reserve - working capital improvement

   

   392,972

   

   554,888Accumulated comprehensive income

   

   185,321

   

   145,893Equity attributable to owners of the Company

   

   7,674,196

   

   6,943,535Non-controlling interests

   

   2,455,942

   

   2,453,794TOTAL EQUITY

   

   10,130,138

   

   9,397,329TOTAL LIABILITIES AND EQUITY

   

   40,532,471

   

   35,144,436(*) Include the effects of note 15.4.2
    The accompanying notes are an integral part of these financial statements.


F - 2

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CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PROFIT OR LOSS FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013 (In thousands of Brazilian reais - R$, except for earnings per share)
  2015

   

   2014

   

   2013NET OPERATING REVENUE (note 27)

   

   20,205,869

   

   17,305,942

   

   14,633,856COST OF ELECTRIC ENERGY SERVICESCost of electric energy (note 28)

   

   (13,311,747)

   

   (10,643,130)

   

   (8,196,687)Cost of operation (note 29)

   

   (1,907,197)

   

   (1,672,359)

   

   (1,467,516)Cost of services rendered to third parties (note 29)

   

   (1,049,101)

   

   (946,052)

   

   (1,009,518)GROSS PROFIT

   

   3,937,825

   

   4,044,401

   

   3,960,135Operating expenses (note 29)Selling expenses

   

   (464,583)

   

   (402,698)

   

   (376,597)General and administrative expenses

   

   (863,499)

   

   (773,630)

   

   (928,614)Other operating expenses

   

   (357,653)

   

   (328,000)

   

   (285,148)INCOME FROM ELECTRIC ENERGY SERVICES

   

   2,252,090

   

   2,540,073

   

   2,369,775Equity interests in associates and joint ventures (note 13)

   

   216,885

   

   59,684

   

   120,868FINANCE INCOME (COSTS) (note 30)Finance income

   

   1,558,047

   

   890,436

   

   699,208Finance costs

   

   (2,572,567)

   

   (1,979,890)

   

   (1,670,651)(1,014,520)

   

   (1,089,454)

   

   (971,443)PROFIT BEFORE TAXES

   

   1,454,454

   

   1,510,304

   

   1,519,200Social contribution (note 9)

   

   (160,162)

   

   (168,989)

   

   (156,756)Income tax (note 9)

   

   (419,015)

   

   (454,871)

   

   (413,408)(579,177)

   

   (623,860)

   

   (570,164)PROFIT FOR THE YEAR

   

   875,277

   

   886,443

   

   949,036Profit attributable to owners of the Company

   

   864,940

   

   949,177

   

   937,419Profit (loss) attributable to noncontrolling interests

   

   10,337

   

   (62,733)

   

   11,618Earnings per share attributable to owners of the Company:Basic (note 26)

   

   0.87

   

   0.96

   

   0.94Diluted (note 26)

   

   0.85

   

   0.94

   

   0.92
  The accompanying notes are an integral part of these financial statements.


F - 3

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CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013 (In thousands of Brazilian reais - R$)
  2015

   

   2014

   

   2013Profit for the year

   

   875,277

   

   886,443

   

   949,036Other comprehensive incomeItems that will not be reclassified subsequently to profit and loss:- Actuarial gains (losses), net of tax effects

   

   65,547

   

   (225,720)

   

   460,226Comprehensive income for the year

   

   940,825

   

   660,724

   

   1,409,262Attributable to owners of the Company

   

   930,488

   

   723,457

   

   1,397,645Attributable to noncontrolling interests

   

   10,337

   

   (62,733)

   

   11,618
  The accompanying notes are an integral part of these financial statements.


F - 4

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CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013 (In thousands of Brazilian reais - R$)
  Earning reserves

   

   

   

   Accumulated

   

   

   

   

   

   Noncontrolling interestsRetained

   

   

   

   

   

   

   

   

   

   Private

   

   

   

   

   

   Accumulated

   

   OtherIssued

   

   Capital

   

   Legal

   

   earnings

   

   Concession

   

   Working capital

   

   

   

   Deemed

   

   pension

   

   Retained

   

   

   

   comprehensive

   

   equity

   

   Totalcapital

   

   reserves

   

   reserve

   

   reserve

   

   financial asset

   

   improvement

   

   Dividends

   

   cost

   

   plan

   

   earnings

   

   Total

   

   income

   

   component

   

   equityBalance 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

   

   7,891,129Total comprehensive incomeProfit for the year

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   937,419

   

   937,419

   

   -

   

   11,617

   

   949,036Other comprehensive income - actuarial gains

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   460,226

   

   -

   

   460,226

   

   -

   

   -

   

   460,226Internal changes of shareholders'equity- Realization of deemed cost of property, plant and equipment

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (39,336)

   

   -

   

   39,336

   

   -

   

   (1,895)

   

   1,895

   

   -- Tax on realization of deemed cost

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   13,374

   

   -

   

   (13,374)

   

   -

   

   644

   

   (644)

   

   -- Recognition of retained earnings reserve

   

   -

   

   -

   

   -

   

   108,987

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (108,987)

   

   -

   

   -

   

   -

   

   -- Recognition of legal reserve

   

   -

   

   -

   

   46,871

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (46,871)

   

   -

   

   -

   

   -

   

   -- Transfer to statutory reserve

   

   -

   

   -

   

   -

   

   (326,899)

   

   326,899

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -- Recognition of statutory reserve in the year

   

   -

   

   -

   

   -

   

   -

   

   (61,863)

   

   -

   

   -

   

   -

   

   -

   

   61,863

   

   -

   

   

   

   

   

   -- Other changes in noncontrolling interests

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (68)

   

   (68)Capital transactions with owners- Prescribed dividends

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   5,172

   

   5,172

   

   -

   

   -

   

   5,172- Interim dividends

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (363,049)

   

   (363,049)

   

   -

   

   (2,301)

   

   (365,349)- Additional dividend proposed

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   567,802

   

   -

   

   -

   

   (567,802)

   

   -

   

   -

   

   -

   

   -- Additional dividend approved

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (455,906)

   

   -

   

   -

   

   -

   

   (455,906)

   

   -

   

   (17,589)

   

   (473,495)- Noncontrolling interests' capital increase in subsidiaries

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   3,566

   

   3,566- IPO - CPFL Renováveis

   

   -

   

   59,308

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   59,308

   

   -

   

   269,191

   

   328,500Balance 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

   

   8,798,718Total comprehensive incomeProfit for the year

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   949,177

   

   949,177

   

   -

   

   (62,733)

   

   886,443Other comprehensive income - actuarial losses

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (225,720)

   

   -

   

   (225,720)

   

   -

   

   -

   

   (225,720)-

   

   

   

   

   

   -Internal changes in equity

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   -

   

   

   

   

   

   -- Realization of deemed cost of property, plant and equipment

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (39,478)

   

   -

   

   39,478

   

   -

   

   (2,254)

   

   2,254

   

   -- Tax on realization of deemed cost

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   13,422

   

   -

   

   (13,422)

   

   -

   

   766

   

   (766)

   

   -- Recognition of legal reserve

   

   -

   

   -

   

   47,459

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (47,459)

   

   -

   

   -

   

   -

   

   -- Realization/reversal of retained earnings reserve

   

   -

   

   -

   

   -

   

   (108,987)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   108,987

   

   -

   

   -

   

   -

   

   -- Changes in statutory reserve in the year

   

   -

   

   -

   

   -

   

   -

   

   65,400

   

   554,888

   

   -

   

   -

   

   -

   

   (620,288)

   

   -

   

   -

   

   -

   

   -- Other changes in noncontrolling interests

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (33)

   

   (33)-

   

   

   

   

   

   -Capital transactions with owners

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   -

   

   

   

   

   

   -- Prescribed dividends

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   5,722

   

   5,722

   

   -

   

   -

   

   5,722- Interim dividends

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (422,195)

   

   (422,195)

   

   -

   

   (2,382)

   

   (424,576)- Additional dividend aproved

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (567,802)

   

   -

   

   -

   

   -

   

   (567,802)

   

   -

   

   (27,156)

   

   (594,958)- Redemption of capital reserve of noncontrolling interests

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (2,189)

   

   (2,189)- Capital increase in subsidiaries with no change in control

   

   -

   

   362

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   362

   

   -

   

   760

   

   1,123- Gain (loss) on equity interest with no change in control

   

   -

   

   (207)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (207)

   

   -

   

   207

   

   -- Business combination - CPFL Renováveis / DESA

   

   -

   

   180,297

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   180,297

   

   -

   

   653,366

   

   833,663- Business combination - CPFL Renováveis / DESA - effect of subsidiary's noncontrolling interests (*)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   119,137

   

   119,137Balance at December 31, 2014 (*)

   

   4,793,424

   

   468,082

   

   650,811

   

   -

   

   330,437

   

   554,888

   

   -

   

   483,610

   

   (337,718)

   

   -

   

   6,943,535

   

   17,003

   

   2,436,791

   

   9,397,329Total comprehensive incomeProfit for the year

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   864,940

   

   864,940

   

   -

   

   10,337

   

   875,277Other comprehensive income - actuarial gains

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   65,547

   

   -

   

   65,547

   

   -

   

   -

   

   65,547-

   

   

   

   

   

   -Internal changes of shareholders'equity

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   -

   

   

   

   

   

   -- Realization of deemed cost of property, plant and equipment

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (39,574)

   

   -

   

   39,574

   

   -

   

   (2,550)

   

   2,550

   

   -- Tax on realization of deemed cost

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   13,455

   

   -

   

   (13,455)

   

   -

   

   867

   

   (867)

   

   -- Recognition of legal reserve

   

   -

   

   -

   

   43,247

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (43,247)

   

   -

   

   -

   

   -

   

   -- Changes in statutory reserve in the year

   

   -

   

   -

   

   -

   

   -

   

   255,013

   

   392,972

   

   -

   

   -

   

   -

   

   (647,985)

   

   -

   

   -

   

   -

   

   -- Other changes in noncontrolling interests

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (48)

   

   (48)-

   

   

   

   

   

   -Capital transactions with owners- Capital increase

   

   554,888

   

   -

   

   -

   

   -

   

   -

   

   (554,888)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -- Prescribed dividends

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   5,597

   

   5,597

   

   -

   

   -

   

   5,597- Additional dividend approved

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (205,423)

   

   (205,423)

   

   -

   

   (8,147)

   

   (213,570)- Capital increase in subsidiaries with no change in control

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   7

   

   7Balance at December 31, 2015

   

   5,348,312

   

   468,082

   

   694,058

   

   -

   

   585,451

   

   392,972

   

   -

   

   457,491

   

   (272,171)

   

   -

   

   7,674,196

   

   15,320

   

   2,440,623

   

   10,130,138(*) Includes the effects of note 15.4.2
   The accompanying notes are an integral part of these financial statements


F - 5

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|Table of Contents
|-----------------

CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWSFOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013 (In thousands of Brazilian reais – R$)
  2015

   

   2014

   

   2013OPERATING CASH FLOWProfit before taxes

   

   1,454,454

   

   1,510,304

   

   1,519,200ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIESDepreciation and amortization

   

   1,279,902

   

   1,159,964

   

   1,055,230Provision for tax, civil and labor risks

   

   258,539

   

   191,228

   

   316,787Allowance for doubtful debts

   

   126,879

   

   83,699

   

   70,324Interest on debts, inflation adjustment and exchange rate changes

   

   1,519,819

   

   1,486,061

   

   1,294,281Pension plan expense

   

   60,184

   

   48,165

   

   61,665Share of loss of investees

   

   (216,885)

   

   (59,684)

   

   (120,868)Impairment

   

   38,956

   

   -

   

   -Loss on disposal of noncurrent assets

   

   16,309

   

   20,726

   

   7,248Deferred taxes (PIS and COFINS)

   

   19,138

   

   24,946

   

   28,328Others

   

   (5,825)

   

   (2,431)

   

   (5,218)4,551,470

   

   4,462,978

   

   4,226,977DECREASE (INCREASE) IN OPERATING ASSETSConsumers, concessionaires and licensees

   

   (1,055,143)

   

   (265,103)

   

   129,731Dividends and interest on capital received

   

   24,050

   

   40,374

   

   112,607Taxes recoverable

   

   (62,041)

   

   (134)

   

   42,176Escrow deposits

   

   22,827

   

   65,732

   

   101,310Sectorial financial asset

   

   (858,860)

   

   (932,719)

   

   -Receivables - amounts from the Energy Development Account - CDE / CCEE

   

   181,141

   

   (352,379)

   

   (145,571)Concession financial (transmission companies)

   

   (44,243)

   

   (62,299)

   

   (15,480)Other operating assets

   

   (82,278)

   

   20,634

   

   (15,245)INCREASE (DECREASE) IN OPERATING LIABILITIESTrade payables

   

   787,063

   

   470,982

   

   191,089Other taxes and social contributions

   

   412,703

   

   193,357

   

   (130,405)Other liabilities with private pension plan

   

   (112,172)

   

   (118,897)

   

   (85,546)Regulatory charges

   

   808,223

   

   11,415

   

   (78,397)Tax, civil and labor risks paid

   

   (247,512)

   

   (188,000)

   

   (184,070)Sectorial financial liability

   

   (23,170)

   

   21,998

   

   -Payables - amounts provided by the CDE

   

   19,696

   

   25,807

   

   9,246Other operating liabilities

   

   107,930

   

   84,467

   

   12,468CASH FLOWS PROVIDED BY OPERATIONS

   

   4,429,684

   

   3,478,213

   

   4,170,890Interest paid on debts and debentures

   

   (1,595,649)

   

   (1,333,570)

   

   (1,093,465)Income tax and social contribution paid

   

   (276,061)

   

   (552,070)

   

   (559,879)NET CASH FROM OPERATING ACTIVITIES

   

   2,557,974

   

   1,592,573

   

   2,517,546INVESTING ACTIVITIESPrice paid in business combination net of cash acquired

   

   -

   

   (68,464)

   

   -Cash incorporated in business combination

   

   -

   

   139,293

   

   -Capital increase in investees

   

   -

   

   (45,445)

   

   -Gain on sales of interest in joint ventures

   

   10,454

   

   -

   

   -Purchases of property, plant and equipment

   

   (550,003)

   

   (345,049)

   

   (882,588)Securities, pledges and restricted deposits

   

   (147,914)

   

   (7,839)

   

   41,392Purchases of intangible assets

   

   (877,793)

   

   (716,818)

   

   (852,248)Sale of noncurrent assets

   

   10,586

   

   43,024

   

   80,945Intragroup loans

   

   29,776

   

   949

   

   (81,456)Repayment of advances to suppliers

   

   -

   

   67,342

   

   -Others

   

   -

   

   -

   

   (584)NET CASH USED IN INVESTING ACTIVITIES

   

   (1,524,894)

   

   (933,007)

   

   (1,694,539)FINANCING ACTIVITIESIPO of subsidiary

   

   -

   

   -

   

   328,500Capital increase by noncontrolling interests

   

   7

   

   1,123

   

   -Borrowings and debentures raised

   

   4,532,167

   

   3,186,384

   

   5,958,322Repayment of principal of borrowings and debentures

   

   (4,037,685)

   

   (2,559,771)

   

   (4,272,655)Repayment of derivatives

   

   (135,309)

   

   (119,628)

   

   (226,796)Repayment for business combinations

   

   (61,709)

   

   -

   

   -Dividends and interest on capital paid

   

   (5,204)

   

   (1,016,641)

   

   (838,990)NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES

   

   292,267

   

   (508,533)

   

   948,381NET INCREASE IN CASH AND CASH EQUIVALENTS

   

   1,325,347

   

   151,033

   

   1,771,388CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR

   

   4,357,455

   

   4,206,422

   

   2,435,034CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR

   

   5,682,802

   

   4,357,455

   

   4,206,422
   The accompanying notes are an integral part of these financial statements


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CPFL ENERGIA S.A. NOTES TO THE FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013 (Amounts in thousands of Brazilian reais – R$, unless otherwise stated)  ( 1 )OPERATIONS
 CPFL Energia S.A. (“CPFL Energia” or “Company”) is a publicly-held corporation incorporated for the principal purpose of operating as a holding company, with equity interests in other companies primarily engaged in electric energy distribution, generation and commercialization activities in Brazil. The Company’s registered office is located at Rua Gomes de Carvalho, 1510 - 14o andar - Sala 142 - Vila Olímpia - São Paulo - SP - Brazil. The Company has direct and indirect interests in the following subsidiaries and joint ventures (information on the concession area, number of consumers, energy production capacity and related data are not audited by the independent auditors):  Energy distribution

   

   Company type

   

   Equity interest

   

   Location (state)

   

   Number of municipalities

   

   Approximate number of consumers (in thousands)

   

   Concession period

   

   End of the concessionCompanhia Paulista de Força e Luz ("CPFL Paulista")

   

   Publicly-held corporation

   

   Direct 100%

   

   Interior of São Paulo

   

   234

   

   4,218

   

   30 years

   

   November 2027Companhia Piratininga de Força e Luz ("CPFL Piratininga")

   

   Publicly-held corporation

   

   Direct 100%

   

   Interior of São Paulo

   

   27

   

   1,659

   

   30 years

   

   October 2028Rio Grande Energia S.A. ("RGE")

   

   Publicly-held corporation

   

   Direct 100%

   

   Interior of Rio Grande do Sul

   

   255

   

   1,444

   

   30 years

   

   November 2027Companhia Luz e Força Santa Cruz ("CPFL Santa Cruz")

   

   Privately-held corporation

   

   Direct 100%

   

   Interior of São Pauloand Paraná

   

   27

   

   205

   

   30 years

   

   July 2045Companhia Leste Paulista de Energia ("CPFL Leste Paulista")

   Privately-held corporation

   

   Direct 100%

   

   Interior of São Paulo

   

   7

   

   57

   

   30 years

   

   July 2045Companhia Jaguari de Energia ("CPFL Jaguari")

   

   Privately-held corporation

   

   Direct 100%

   

   Interior of São Paulo

   

   2

   

   39

   

   30 years

   

   July 2045Companhia Sul Paulista de Energia ("CPFL Sul Paulista")

   

   Privately-held corporation

   

   Direct 100%

   

   Interior of São Paulo

   

   5

   

   83

   

   30 years

   

   July 2045Companhia Luz e Força de Mococa ("CPFL Mococa")

   

   Privately-held corporation

   

   Direct 100%

   

   Interior of São Pauloand Minas Gerais

   

   4

   

   46

   

   30 years

   

   July 2045
  Installed power (MW)Energy generation (conventional and renewable sources)

   

   Company type

   

   Equity interest

   

   Location (state)

   

   Number of plants / type of energy

   

   Total

   

   CPFL shareCPFL Geração de Energia S.A.("CPFL Geração")

   

   Publicly-held corporation

   

   Direct 100%

   

   São Paulo and Goiás

   

   1 Hydropower, 4 SHPs (a) and 1 Thermal

   

   729

   

   729CERAN - Companhia Energética Rio das Antas ("CERAN")

   

   Privately-held corporation

   

   Indirect65%

   

   Rio Grande do Sul

   

   3 Hydropower

   

   360

   

   234Foz do Chapecó Energia S.A.("Foz do Chapecó")

   

   Privately-held corporation

   

   Indirect51%

   

   Santa Catarina andRio Grande do Sul

   

   1 Hydropower

   

   855

   

   436Campos Novos Energia S.A.("ENERCAN")

   

   Privately-held corporation

   

   Indirect48.72%

   

   Santa Catarina

   

   1 Hydropower

   

   880

   

   429BAESA - Energética Barra Grande S.A.("BAESA")

   

   Publicly-held corporation

   

   Indirect25.01%

   

   Santa Catarina andRio Grande do Sul

   

   1 Hydropower

   

   690

   

   173Centrais Elétricas da Paraíba S.A.("EPASA")

   

   Privately-held corporation

   

   Indirect57.13%

   

   Paraíba

   

   2 Thermal

   

   342

   

   182Paulista Lajeado Energia S.A.("Paulista Lajeado")

   

   Privately-held corporation

   

   Indirect59.93% (b)

   

   Tocantins

   

   1 Hydropower

   

   903

   

   63CPFL Energias Renováveis S.A. ("CPFL Renováveis")

   

   Publicly-held corporation

   

   Indirect58.84%

   

   (c)

   

   (c)

   

   (c)

   

   (c)CPFL Centrais Geradoras Ltda ("CPFL Centrais Geradoras")

   

   Limited liability company

   

   Direct 100%

   

   São Paulo

   

   6 LHPs (g)

   

   4

   

   4
  Energy commercialization

   

   Company type

   

   Core activity

   

   Equity interestCPFL Comercialização Brasil S.A. ("CPFL Brasil")

   

   Privately-held corporation

   

   Energy commercialization

   

   Direct 100%Clion Assessoria e Comercialização de Energia Elétrica Ltda.("CPFL Meridional")

   

   Limited liability company

   

   Commercialization and provision of energy services

   

   Indirect 100%CPFL Comercialização Cone Sul S.A. ("CPFL Cone Sul")

   

   Privately-held corporation

   

   Energy commercialization

   

   Indirect 100%CPFL Planalto Ltda. ("CPFL Planalto")

   

   Limited liability company

   

   Energy commercialization

   

   Direct 100%CPFL Brasil Varejista S.A. ("CPFL Basil Varejista")

   

   Privately-held corporation

   

   Energy commercialization

   

   Indirect 100%


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Provision of services

   

   Company type

   

   Core activity

   

   Equity interestCPFL Serviços, Equipamentos, Industria e Comércio S.A.("CPFL Serviços")

   

   Privately-held corporation

   

   Manufacturing, commercialization, rental and maintenance of electro-mechanical equipment and service provision

   

   Direct 100%NECT Serviços Administrativos Ltda ("Nect")

   

   Limited liability company

   

   Provision of administrative services

   

   Direct 100%CPFL Atende Centro de Contatos e Atendimento Ltda. ("CPFL Atende")

   

   Limited liability company

   

   Provision of call center services

   

   Direct 100%CPFL Total Serviços Administrativos Ltda. ("CPFL Total")

   

   Limited liability company

   

   Collection services

   

   Direct 100%CPFL Eficiência Energética S.A ("CPFL ESCO")

   

   Privately-held corporation

   

   Energy efficiency management

   

   Direct 100%TI Nect Serviços de Informática Ltda. ("Authi") (f)

   

   Limited liability company

   

   Provision of IT services

   

   Direct 100%CPFL GD S.A ("CPFL GD") (h)

   

   Privately-held corporation

   

   Provision of maintenance services for energy generation companies

   

   Indirect 100%
  Others

   

   Company type

   

   Core activity

   

   Equity interestCPFL Jaguariúna Participações Ltda ("CPFL Jaguariuna")

   

   Limited liability company

   

   Holding company

   

   Direct 100%CPFL Jaguari de Geração de Energia Ltda ("Jaguari Geração")

   

   Limited liability company

   

   Holding company

   

   Direct 100%Chapecoense Geração S.A. ("Chapecoense") (d)

   

   Privately-held corporation

   

   Holding company

   

   Indirect 51%Sul Geradora Participações S.A. ("Sul Geradora")

   

   Privately-held corporation

   

   Holding company

   

   Indirect 99.95%CPFL Telecom S.A ("CPFL Telecom")

   

   Privately-held corporation

   

   Telecommunication services

   

   Direct 100%CPFL Transmissão Piracicaba S.A ("CPFL Transmissão")

   

   Privately-held corporation

   

   Energy transmission services

   

   Indirect 100%CPFL Transmissora Morro Agudo S.A ("CPFL Transmissão Morro Agudo") (e)

   

   Privately-held corporation

   

   Energy transmission services

   

   Indirect 100%
  (a)   SHP – Small Hydropower Plant. (b)   Paulista Lajeado has a 7% share in the installed power of Investco S.A. (5.94% interest in total capital). (c)   CPFL Renováveis has operations in the states of São Paulo, Minas Gerais, Mato Grosso, Santa Catarina, Ceará, Rio Grande do Norte, Paraná and Rio Grande do Sul and its main activities are: (i) holding investments in companies of the renewable energy segment; (ii) identification, development, and exploration of generation potentials; and (iii) sale of electric energy. At December 31, 2015, CPFL Renováveis had a portfolio of 126 projects with installed capacity of 2,909.2 MW (1,799.3 MW in operation), as follows: ·Hydropower generation: 47 SHP’s (557.7 MW) with38SHPs in operation (399MW) and 9 SHPs under development (158.7 MW); ·Wind power generation: 70 projects (1,980.4 MW) with 34projects in operation (1,029.2MW) and 36projects under construction/development (951.2 MW); ·Biomass power generation: 8 plants in operation (370MW); ·Solar power generation:1solar plant in operation (1.1MW). (d)   The joint venture Chapecoense has as its direct subsidiary Foz do Chapecó and fully consolidates its financial statements. (e)   In January 2015, approval was granted for establishing CPFL Transmissão Morro Agudo, a subsidiary of CPFL Geração. The new subsidiary’s objective is to operate electric energy transmission concessions, including activities of construction, implementation, operation and maintenance of installations for transmission of power from the basic grid of the Brazilian National Interconnected System (“SIN”).


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(f)    In September 2014, the direct subsidiary Authi was established in order to provide information technology services, maintenance of such technology, system upgrading, development and customization of programs and maintenance of computers and peripheral equipment. (g)   LHP – Large Hydropower Plant (h)   In August 2015, the company CPFL GD was established as a wholly owned subsidiary of CPFL ESCO, mainly aimed at providing services and general consulting for the electric energy market and selling goods related to central electric energy stations. As determined in an Order from the Federal Minister of Mines & Energy in November 2015, subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista and CPFL Mococa signed on December 9, 2015 the 5th amendment to concession agreement No. 17/1999-ANEEL, which expired on July 7, 2015. Accordingly, the term of these subsidiaries for engaging in electric energy distribution activities was extended for another 30 years, hence expiring on July 7, 2045. The amendment was formalized in accordance with Law No. 12,783 of January 11, 2013, of Decree No. 7,805 of September 14, 2012, and Decree No. 8,461 of June 2, 2015, which established the terms and conditions for such extension relating to operational and economic-financial criteria. The new amendment required from the subsidiaries the compliance with the following criteria: (i) efficiency in relation to the quality of the service performed, (ii) efficiency in terms of economic-financial management, (iii) operational and economic rationality, and (iv) tariff moderation. The compliance with such indicators will be monitored by the Regulatory Agency - ANEEL, and an administrative proceeding may be filed in the event of non-compliance.  ( 2 )PRESENTATION OF THE FINANCIAL STATEMENTS
 2.1 Basis of presentation The financial statements have been prepared in accordance with International Financial Reporting Standards - IFRS, issued by the International Accounting Standard Board – IASB. Management states that all information material to the financial statements is being disclosed and corresponds to what is used in managing the Company. The consolidated financial statements were approved by Management and authorized for issue on April 08, 2016. 2.2 Basis of measurement The financial statements have been prepared on the historical cost basis except for the following items recorded in the statements of financial position: 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. The classification of the fair value measurement in the level 1, 2 or 3 categories (depending on the degree of observance of the variables used) is presented in note 35 – Financial Instruments. 2.3 Use of estimates and judgments The preparation of financial statements requires the Company’s 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, the Company’s management reviews the estimates and assumptions on an ongoing basis, based on previous experience and other relevant factors. Adjustments resulting from revisions to accounting estimates are recognized in the period in which the estimates are revised and applied on a prospective basis. The main accounts that require the adoption of estimates and assumptions, which are subject to a greater degree of uncertainty and may result in a material adjustment if these estimates and assumptions suffer significant changes in subsequent periods, are: ·Note 6 – Consumers, concessionaires and licensees; ·Note 8 – Sector financial asset and liability; ·Note 9 – Deferred tax assets and liabilities; ·Note 10 – Leases;


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·Note 11 – Concession financial asset; ·Note 12 – Other receivables (Allowance for doubtful debts); ·Note 14 – Property, plant and equipment and impairment; ·Note 15 – Intangible assets and impairment; ·Note 19 – Private pension plan; ·Note 22 – Provision for tax, civil and labor risks and escrow deposits; ·Note 24 – Other payables (provision for socio environmental costs); ·Note 27 – Net operating revenue; ·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 sum-up of the amounts. Consequently, when summed up, the amounts stated in thousands of reais may not tally with the rounded totals. 2.5 Segment information An operating segment is a component of the Company (i) that engages in operating activities from which it earns revenues and incurs 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 individual financial information is available. The Company’s management uses reports to make strategic decisions, segmenting the business into: (i) electric energy distribution activities (“Distribution”); (ii) electric energy generation from conventional sources activities (“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. The presentation of the operating segments includes items directly attributable to them, as well as any allocations required, including intangible assets. 2.6 Information on equity interests The Company's equity interests in 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 stated at cost by the subsidiary Paulista Lajeado in Investco S.A., all other entities are fully consolidated. At December 31, 2015 and 2014, the noncontrolling interests recognized in the financial statements refer to the interests held by third parties in subsidiaries CERAN, Paulista Lajeado and CPFL Renováveis.  ( 3 )SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 The significant accounting policies used in preparing the Company’s financial statements are set out below. These policies have been consistently applied to all periods presented. 3.1 Concession agreements IFRIC 12 – Service Concession Arrangements establish general guidelines for the recognition and measurement of obligations and rights related to concession agreements and apply to situations in which the granting authority 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. When these definitions are met, the infrastructure of distribution concessionaires is segregated at the time of construction in accordance with the IFRS requirements, so that the following are recognized in the financial statements (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.


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The concession financial asset 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), and takes into consideration changes in the estimated cash flow, mainly based on factors such as new replacement price, and adjustment for (i) Extended Comprehensive Consumer Price Index (“IPCA”) for the subsidiaries CPFL Paulista, CPFL Piratininga and RGE and (ii) General Market Price Index (“IGP-M”) for the other distribution companies. The financial asset is classified as available-for-sale, with the corresponding cash flow changes entry in a finance income or cost account in the statement of profit or loss for the year (note 4). The remaining amount is recognized as intangible asset 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 recognized in accordance with IAS 11 – Construction Contracts, against a financial asset corresponding to the amount subject to right to receive cash (indemnity). Residual amounts classified as intangible assets are amortized over the concession period 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 the constructions by using 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 construction revenue and costs are therefore presented in the statement of profit or loss for the year in the same amounts. 3.2 Financial instruments - Financial assets Financial assets are recognized initially on the date that they are originated or on the 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 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 into any of the previous categories. Subsequent to initial recognition, interest calculated using the effective interest method is recognized in the statement of profit or loss as part of the net finance costs. Changes in fair value of these financial assets are recognized in other comprehensive income. The accumulated result in 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 to match the effects of recognition of income and expenses to


obtain more relevant and consistent accounting information, or (iii) derivatives. These liabilities are measured at fair value and any change in their fair value is subsequently recognized in profit or loss.


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ii.Other financial liabilities (not measured at fair value through profit or loss): these are other financial liabilities not classified into the previous category. They are measured initially at fair value net of any cost attributable to the transaction and subsequently measured at amortized cost using the effective interest rate method. The Company recognizes financial guarantees when these are granted to non-controlled entities or when the financial guarantee is granted 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 recognizing (i) a liability corresponding to the risk of non-payment of the debt, which is amortized against finance income simultaneously and in proportion to amortization of the debt, and (ii) an asset equivalent to the right to compensation by the guaranteed party or a prepaid expense under the 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, guarantees are measured periodically at the higher of the amount determined in accordance with IAS 37 and the amount initially recognized less accumulated amortization. Financial assets and liabilities are offset and presented at their net amount when, and only when, there is a legal right to offset the amounts and the intent to realize the asset and settle the liability simultaneously. The classifications of financial instruments are described in 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 Leases At the inception of an agreement, one shall determine whether such agreement is or contains a lease. A specific asset is the subject of a lease if fulfillment of the agreement is dependent on the use of that specified asset. An agreement conveys the right to use the asset if the agreement conveys to the lessee the right to control the use of the underlying asset. Leases in which substantially all the risks and rewards are retained by 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 that 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 the lower of the leased asset’s 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 finance leases in which the Company or its subsidiaries act as lessors, receivables from lessees are initially recognized based on the fair value of the leased asset. In both cases, the finance income/cost is recognized in the statement of profit or loss over the term of the lease agreement 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 Granting Authority.


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Gains and losses on disposal/ write-off of an item of property, plant and equipment are determined by comparing the proceeds from disposal with the carrying amount of the asset, and are recognized net within other operating income/expenses. 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, through Resolution No. 20 of February 3, 1999, amended by Normative Resolution No. 691 of December 8, 2015, releases Public Electric Energy Utility concessionaires from prior authorization for release of assets of no use to the concession, but determines that the proceeds from the disposal be deposited in a restricted bank account for use in the concession.  3.5 Intangible assets Includes rights related to non-physical assets such as goodwill and concession exploration rights, software and rights-of-way. Goodwill that arises on the acquisition of subsidiaries is measured based on 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 with indefinite useful lives, if any, are not subject to amortization and are tested annually for impairment. Negative goodwill is recognized as a gain in the statement of profit or loss 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 and amortized over the remaining period of the concessions, on a straight-line basis or based on the profit curves projected for the concessionaires, as applicable.  ii.Investments in infrastructure (application of IFRIC 12 – Service Concession Arrangements): under the electric energy distribution concession agreements with the subsidiaries, the recognized intangible asset corresponds to the concessionaires' right to charge the consumers for use of the concession infrastructure. Since the exploration term is defined in the agreement, intangible assets with defined useful lives are amortized over the concession period in proportion to a curve that reflects the consumption pattern in relation to the economic benefits. For further information see note 3.1.  Items comprised in the infrastructure are directly tied to the Company’s electric energy distribution operation and cannot be removed, disposed of, assigned or pledged in mortgage without the prior and express authorization of ANEEL. ANEEL, through Resolution No. 20 of February 3, 1999, amended by Normative Resolution No. 691 of December 8, 2015, releases Public Electric Energy Utility concessionaires from prior authorization for release of assets of no use to the concession, but determines that the proceeds from the disposal be deposited in a restricted bank account for use in the concession.  iii.Use of public asset: upon certain generation concessions were granted with the condition of payments to the federal government for use of public asset. On the signing date of the respective agreements the Company’s subsidiaries recognized 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 period 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.


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The Company and its subsidiaries consider evidence of impairment of receivables and held-to-maturity securities for both specific asset and at a collective level for all significant securities. Receivables and held-to-maturity 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 historical 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 as a credit through profit or loss. II.Available-for-sale: as the difference between the acquisition cost, net of any reimbursement and principal repayment, 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 carried 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 amount. Other assets subject to amortization are tested for impairment whenever events or changes in circumstances 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 intangible 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 and pension plans, recognized under 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 the statement of profit or loss in the periods during which the services are rendered. ii.Defined benefit plan: The net obligation is calculated as the difference between the present value of the actuarial obligation based on assumptions, biometric studies and interest rates in line with market rates, and the fair value of the plan assets 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 or expense) is calculated by applying the discount rate at the beginning of the period to the net amount of the defined benefit asset or liability. When applicable, the cost of past services is recognized immediately in profit or loss.


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If the plan records a surplus and it becomes necessary to recognize an asset, the recognition is limited to 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 capital Under Brazilian law, the Company is required to distribute a mandatory minimum annual dividend of 25% of profit adjusted in accordance with the Company ́s bylaws. In conformity with 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. According to Law 6,404/76, they will therefore be held in equity, in the “additional dividend proposed” account, as they do not meet the present obligation 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 capital determined in a half-yearly statement of income. An interim dividend and interest on capital declared at the base date of June 30 is only recognized as a liability in the Company's financial statement after the date of the Board of Directors' decision. Interest on capital is treated in the same way as dividends and is also stated in changes in equity. Withholding income tax on interest on capital is debited against equity when proposed by Management, as it fulfills the obligation criteria at that time. 3.10 Revenue recognition Operating revenue 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 economic benefits will flow to the entity, the associated costs can be reliably estimated, and the amount of the operating revenue can be reliably measured. Revenue from electric energy distribution is recognized when the energy is supplied. Unbilled revenue related to the monthly billing cycle is recognized based on the actual amount of energy provided in the month and the annualized loss rate. Revenue from energy generation sales is recognized based on the assured energy and at tariffs specified in the terms of the contract or the current market price, as applicable. Revenue from energy sales is recognized 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 total revenue. Service revenue is recognized when the service is provided, under a service agreement between the parties. Revenue from construction contracts is recognized based on the percentage of completion method, and losses, if any, are recognized the statement of profit or loss as incurred. 3.11 Income tax and social contribution Income tax and social contribution expenses are calculated and recognized in accordance with the legislation in force and comprise current and deferred taxes. Income tax and social contribution are recognized in the statement of profit or loss except to the extent that they relate to items recognized directly in equity or other comprehensive income, when the net amounts of these tax effects are already recognized, and those arising from the initial recognition in business combinations. Current taxes are the expected taxes payable or receivable/recoverable on the taxable profit or loss. Deferred taxes are recognized for temporary differences between the carrying amounts of assets and liabilities for accounting purposes and the equivalent amounts used for tax purposes and for tax loss carryforwards. The Company and certain subsidiaries recognize in their financial statements the effects of tax 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 tax assets related to benefits of merged goodwill, which are amortized in proportion to the individual projected profit for the remaining period of each concession agreement.


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Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to taxes levied by the same tax authority on the same taxable entity. Deferred income tax and social contribution assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related 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 these amounts will be received by the Company. They are recognized 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 recovery 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 of offsetting discounts granted and expenses already incurred in order to provide immediate financial support 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 should be set at a price level (price cap) that ensures the economic and financial equilibrium of the concession. Therefore, the concessionaires and licensees 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, according to each concession agreement, the periodic review for purposes of reconciliation of part of Parcel B (controllable costs) and adjustment of Parcel A (non-controllable costs). The distributors' revenue is mainly comprised of the sale of electric energy and for the delivery (transport) of the 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 a breakdown of the revenue: ·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”, are 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. It is this parcel that actually 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 actually incurred, or an obligation to pay if the budgeted costs are higher than those actually incurred. On November 25, 2014, according to Order No. 4,621, the ANEEL approved an amendment to the distribution companies’ concession agreements, to include a specific clause that assures the indemnification for outstanding balances (assets or liabilities) of any insufficient collection or reimbursement for the tariffs resulting from termination of the concession for any reason. On December 10, 2014, our eight distribution subsidiaries signed the amendments to the concession agreements. The amendments include a specific clause that assures the indemnification for outstanding balances (assets or liabilities) of any insufficient collection or reimbursement for the tariffs resulting from termination of the concession for any reason (“Sector Financial asset and liability”). These contractual


amendments assure, from their signing date, the unconditional right (and impose the obligation) to receive (or deliver) cash or another financial instrument. This event therefore eliminated any uncertainty as to the realization of the asset and settlement of the liability. Accordingly, the Company and its distribution subsidiaries start to recognize, prospectively, the components of Parcel A and other financial components, such as financial assets and liabilities (note 8), against the line item sector financial asset in other operating income (note 27). After the initial recognition, the sector asset and liability balances are mainly adjusted for inflation based on the variation in the Special Clearance and Escrow System rate (“SELIC”), based on their respective nature.


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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 Company and subsidiaries in exchange for control of the acquiree. Costs related to the acquisition are generally recognized in profit or loss, when incurred. The noncontrolling interests are initially measured either at fair value or at the noncontrolling interests’ 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 concession intangible asset) 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 concession intangible asset) and net liabilities assumed exceeds the consideration transferred, a bargain purchase is identified and the gain is recognized in the statement of profit or loss at the acquisition date. 3.16 Basis of consolidation (i) Business combinations The Company measures goodwill as the fair value of the consideration transferred including the recognized amount of any non-controlling interest in the acquiree, less the recognized fair value of the identifiable assets acquired and liabilities assumed, all measured at 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 purposes of 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 the subsidiaries. Prior to consolidation into the Company's financial statements, the financial statements of subsidiaries CPFL Geração, CPFL Brasil, CPFL Jaguari Geração and CPFL Renováveis are fully consolidated into those of their subsidiaries. Intragroup 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 noncontrolling interests is stated in equity and in the statements of profit or loss and comprehensive income in each period presented. The balances of joint ventures, as well as the Company’s interest in each of them are described in note 13.2. (iii) Acquisition of noncontrolling interests Accounted for as transaction among shareholders. Consequently, no asset or goodwill is recognized as a result of such transaction. 3.17 New standards and interpretations adopted


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A number of IASB standards were issued or revised and are mandatory for accounting periods beginning on January 1, 2015: a) Amendments to IAS 19 (R) – Defined Benefit Plans: Employee Contributions The amendments to IAS 19 clarify how an entity should account for contributions made by employees or third parties to defined benefit plans. In the cases when the formal clauses of the plan specify contributions from employees or third parties the accounting procedures depend on whether or not the contributions are dependent on the number of years of service: ·If contributions are not dependent on the service, theaccounting affects the revaluation of the liability or asset associated to the defined benefit. ·If contributions are dependent on the service, the accounting reduces the service cost. If the contribution is dependent on the number of years of service, the entity should attribute it to the period of service using the method defined in paragraph 70 of IAS 19 (R). If the contribution amount is not dependent on the number of years of service, the entity can reduce the service cost in the period in which the service is rendered, or reduce the service cost attributing the contributions to the employee’s period of service, or reduce the service cost attributing the employee’s period of service, in accordance with paragraph 70 of IAS 19 (R). These amendments were applied and there was no impact on the disclosures or amounts recognized in the consolidated financial statements for the year ended December 31, 2015. b) Amendments to IFRSs – Annual Improvements to IFRSs 2010-2012 Cycle and Annual Improvements to IFRSs 2011-2013 Cycle (effective beginning on or after July 1, 2014) The amendments included in the Annual Improvements to IFRS 2010-2012 Cycle and 2011-2013 Cycle did not have material impact on the disclosures or amounts recognized in the Company’s consolidated financial statements for the year ended December 31, 2015. 3.18 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, 2015. Consequently, the Company has not adopted them: a) IFRS 9 - Financial instruments IFRS 9 is effective for the financial statements of an entity prepared in accordance with IFRS for annual periods beginning on or after January 1, 2018 and earlier application is permitted. The standard establishes new requirements for classification and measurement of financial assets and liabilities. Financial assets are classified into 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 the statement of profit or loss, unless such recognition results in a mismatching in the statement of profit or loss. In relation to the impairment of financial assets, IFRS 9 requires an expected credit loss model, as opposed to an incurred credit loss under IAS 39. The expected credit loss model requires an entity to account for expected credit losses and changes in those expected credit losses at each reporting date to reflect changes in credit risk since initial recognition. In other words, it is no longer necessary for a credit event to have occurred before credit losses are recognized. Regarding the modifications related to hedge accounting, IFRS 9 retains three types of hedge accounting mechanisms currently available in IAS 39. Under IFRS 9, greater flexibility has been introduced to the types of risks components of non-financial items that are eligible for hedge accounting. In addition, the effectiveness test has been overhauled and replaced with the principle of an “economic relationship”. Retrospective assessment of hedge effectiveness is also no longer required. Enhanced disclosure requirements about an entity’s risk management have also been introduced. The Company’s distribution subsidiaries have material assets classified as “available-for-sale”, in accordance with the current requirements of IAS 39. These assets represent the right to indemnity at the end of the


concession period of the distribution subsidiaries. The designation of these instruments as available-for-sale occurs due to the non-classification in the other three categories described in IAS 39 (loans and receivables, fair value through profit or loss and held-to-maturity). Management’s preliminary opinion is that, should these assets be classified as measured at fair value through profit or loss according to the new standard, the effects of the subsequent remeasurement of this asset would be recognized in profit or loss for the year. Thus, there will not be material impacts on the Company’s consolidated financial statements.


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Moreover, as the Company and its subsidiaries do not apply hedge accounting, Management concluded that there will not be material impact on the information disclosed or amounts recorded in its consolidated financial statements as a result of the amendments to standard. As regards the changes of the calculation of impairment of financial instruments, the Company is assessing the impacts of the adoption in its consolidated financial statements. b) IFRS 14 - Regulatory deferral 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 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 January 1, 2016. Earlier application is permitted. As the Company and its subsidiaries are not first-time adopters of IFRS, there will be no impacts on their financial statements. 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, it will supersede 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 2018, and its early adoption is permitted. The Company is assessing the potential impacts of the adoption of this new standard and preliminarily assess that they will not be material in its consolidated financial statements. 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 January 1, 2016. Based on a preliminary assessment of the amendments, the Company's management believes that the application of these amendments to IFRS 11, should these transactions materialize, may impact its consolidated financial statement in future periods. e) Amendments to IAS 16 and IAS 38 - Clarification of acceptable methods of depreciation and amortization


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The amendments to IAS 16 prohibit the use of the revenue based depreciation method for property, plant and equipment items. The amendments to IAS 38 introduced the rebuttable presumption that revenue is an inappropriate basis for amortizing an intangible asset. Such presumption can be rebuttable only in the two conditions set out: (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 January 1, 2016. The Company currently depreciates its property, plant and equipment by the straight-line method and amortizes the concession intangible asset based on the projected income curve of the concessionaires over the remaining period of the concession. These projections are reviewed annually. The balances of the subsidiary CPFL Renováveis are amortized over the remaining period of the exploration rights, by the straight-line method. In a preliminary analysis, the Company assessed that part of its intangible assets classified into item (i) use the profit curve as amortization method. Considering these amendments, this method will 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 period of the concessions. The preliminary and initial estimate of the impact is R$ 66,931 lower amortization between 2016 and 2020, generating higher profit, estimated at R$ 65,461. This effect will be offset against higher amortization between 2021 and 2036. f) Amendments to IAS 1 – Disclosure Initiatives The amendments to IAS 1 provide guidance as regards the application of the concept of materiality in practice. These amendments are effective for annual periods beginning on or after January 1, 2016. Based on a preliminary assessment, the Company’s management does not believe that the application of these amendments to IAS 1 will have a material impact on its consolidated financial statements. g) Amendments to IAS 27 – Equity Method in Separate Financial Statements. The amendments permit that an entity account for investments in subsidiaries, joint ventures and associates in its separate financial statements using one of the three methods: (i) at cost, (ii) in accordance with IFRS 9/IAS 39 or (iii) using the equity method, as described in IAS 28 – Investments in Associates and Joint Ventures and defines that the same accounting criterion should be applied to each category of investments. The amendments also define that when a parent company becomes or ceases to be an investment entity, it should account for the change as from the date in which the change occurs. These amendments are effective retrospectively for annual periods beginning on or after January 1, 2016. The Company estimates that there will not be impacts on its consolidated financial statements since its does not prepare separate financial statements. h) Amendments to IFRS 10 and IAS 28 – Sale of Contribution of Assets between an Investor and its associate or joint venture. The amendments to IFRS 10 and IAS 28 address situations that involve the sale or contribution of assets between an investor and its associate or joint venture. Specifically, gains and losses resulting from loss of control of a subsidiary that does not represent a business in a transaction with an associate or joint venture that is accounted for using the equity method are recognized in the parent company's profit or loss only proportionally to the “unrelated investor’s” interest in this associate or joint venture. Similarly, gains and losses resulting from revaluation of investments retained in some former subsidiary (that has become an associate or joint venture accounted for using the equity method) at fair value are recognized in the profit or loss of the former parent company proportionally to the "unrelated investor’s"' interest in the new associate or joint venture. These amendments are effective prospectively to annual periods beginning on or after January 1, 2016. The Company’s management believes that the application of these amendments to IFRS 10, should these transactions occur, may impact its consolidated financial statements in future periods. i) Amendments to IFRS 10, IFRS 12 and IAS 28 – Investment Entities: Applying the Consolidation Exception


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The amendments to IFRS 10, IFRS 12 and IAS 28 clarify that the relief from preparing financial statements is applicable to a parent entity that is a subsidiary of an investment entity, even if the investment entity assesses all its subsidiaries at fair value in accordance with IFRS 10. The amendments also clarify that the requirement for an investment entity to consolidate a subsidiary that renders services related to investment activities of the former is applicable only to subsidiaries that are not investment entities. These amendments are effective retrospectively for annual periods beginning on or after January 1, 2016. The Company’s management does not believe that the application of the amendments to IFRS 10, IFRS 12 and IAS 28 will have a material impact on its consolidated financial statements since the Company is not an investment entity and does not have a subsidiary, associate or joint venture that qualifies as an investment entity. j) Annual Improvements to IFRSs 2012 – 2014 Cycle j.1)Amendments to IFRS 5 – Non-current Assets held for Sale and Discontinued Operations: Introduce specific guidance in IFRS 5 as to when an entity reclassifies an asset (or disposal group) from "held for sale" to "held for distribution to owners" (or vice versa). The amendments clarify that such change should be considered as a continuity of the original disposal plan and, therefore, the requirements in IFRS 5 in relation to the change of the disposal plan are not applicable. The amendments also clarify the guidance as regards the discontinuance of accounting of assets classified as "held for distribution". j.2)Amendments to IFRS 7 – Financial Instruments: Disclosures (with amendments reflected in IFRS 1): provide additional guidance to clarify if a service agreement contains a continuing involvement in a transferred asset for purposes of the required disclosures related to assets transferred. j.3)Amendments to IAS 19 (R) – Employee Benefits: clarify that the rate used for discount of post-retirement benefit obligations should be determined based on  the market yield at the end of the reporting period for high quality corporate bonds. The assessment of the coverage of a market for high quality corporate bonds should be at the level of the currency (that is, the same currency in which the benefits will be paid). For currencies for which there is no highly liquidity market for these high quality corporate bonds, the base should be the market yield on government bonds denominated in that currency at the end of the reporting period. j.4)Amendments to IAS 34 – Interim Financial Statements: require that the information related to paragraph 16A of IAS 34 be included either in the interim financial statements or incorporated by reference in another part of the interim financial report that is available to users under the same terms and at the same time of the interim financial statements. Based on a preliminary assessment, the Company’s management believes that the application of these amendments will not have a material effect on the disclosures and amounts recognized in its consolidated financial statements. k) IFRS 16 Leases Issued on January 13, 2016, establishes, in the lessee’s view, a new form for accounting for leases currently classified as operating leases, which are now recognized similarly to leases classified as finance leases. As regards the lessors, it virtually retains the requirements of IAS 17, including only some additional disclosure aspects. IFRS 16 is effective for annual periods beginning or on after January 1, 2019, and its early adoption is permitted as long as the entities also early adopt IFRS 15 - Revenues from contracts with customers. The Company is assessing the potential impacts of the adoption of this new standard.  ( 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 on 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 defines fair value as the estimated pricefor an unforced transaction for the saleof the 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


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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 an asset could be exchanged on the date of valuation between knowledgeable and willing parties in an unforced transaction between market participants on the measurement date. 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 are 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 theBolsa de Valores, Mercadorias e Futuros“BM&FBOVESPA”) andAssociação 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 at the end of the concession agreement. The methodology adopted for marking these assets to fair value 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 granting authority (“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. 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 granting authority and uses the IPCA or the IGP-M as the best estimates for adjusting the original base to the fair value at subsequent dates, in accordance with the tariff review process.  ( 5 )CASH AND CASH EQUIVALENTS
  Dec 31, 2015

   

   Dec 31, 2014Bank balances

   148,224

   

   177,872Short-term financial investments

   5,534,578

   

   4,179,583Overnight investment (a)

   26,914

   

   84,512Bank certificates of deposit (b)

   1,255,666

   

   557,018Repurchase agreements secured on debentures (b)

   433,693

   

   15,985Investment funds (c)

   3,818,305

   

   3,522,069Total

   5,682,802

   

   4,357,455
  (a)Current account balances, which earn daily interest by investment in repurchase agreements secured on debentures and interest of 15% of the variation in the Interbank Certificate of Deposit (CDI). (b)Short-term investments in Bank Certificates of Deposit (CDB) and repurchase agreements secured on 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 100.9% of the CDI, subject to floating rates tied to the CDI linked to federal government bonds, CDBs, financial bills and secured debentures of major financial institutions, with low credit risk.  ( 6 )CONSUMERS, CONCESSIONAIRES AND LICENSEES
 The balance derives mainly from the supply of electric energy. The following table shows the breakdown at December 31, 2015 and 2014:


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Past due

   

   TotalAmounts coming due

   

   until 90 days

   

   > 90 days

   

   Dec 31, 2015

   

   Dec 31, 2014CurrentConsumer classesResidential

   340,541

   

   394,199

   

   59,085

   

   793,826

   

   469,318Industrial

   207,355

   

   99,979

   

   58,086

   

   365,420

   

   171,072Commercial

   156,922

   

   84,740

   

   21,597

   

   263,259

   

   148,120Rural

   50,397

   

   12,037

   

   1,823

   

   64,257

   

   36,319Public administration

   64,502

   

   14,675

   

   776

   

   79,953

   

   47,076Public lighting

   67,366

   

   10,045

   

   793

   

   78,204

   

   45,151Public utilities

   72,191

   

   8,397

   

   117

   

   80,706

   

   48,777Billed

   959,275

   

   624,073

   

   142,278

   

   1,725,626

   

   965,833Unbilled

   881,307

   

   -

   

   -

   

   881,307

   

   705,318Financing of consumers' debts

   149,899

   

   24,436

   

   22,700

   

   197,035

   

   103,512Free energy

   163,266

   

   5,901

   

   394

   

   169,561

   

   227,986CCEE transactions

   321,468

   

   5,711

   

   3,927

   

   331,105

   

   334,403Concessionaires and licensees

   10,770

   

   -

   

   -

   

   10,770

   

   18,6602,485,984

   

   660,121

   

   169,298

   

   3,315,403

   

   2,355,713Allowance for doubtful debts

   

   

   

   

   

   

   (140,485)

   

   (104,588)Total

   

   

   

   

   

   

   3,174,918

   

   2,251,124NoncurrentFinancing of consumers' debts

   101,585

   

   -

   

   -

   

   101,585

   

   96,547Free energy

   4,768

   

   -

   

   -

   

   4,768

   

   4,139CCEE transactions

   41,301

   

   -

   

   -

   

   41,301

   

   41,301147,654

   

   -

   

   -

   

   147,654

   

   141,988Allowance for doubtful debts

   

   

   

   

   

   

   (18,708)

   

   (18,583)Total

   

   

   

   

   

   

   128,946

   

   123,405
  Financing of Consumers' Debts -Refers to the negotiation of overdue receivables from consumers, principally public administration. Payment of some of these receivables 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 debts are recognized based on the best estimates of the subsidiaries’ Management for unsecured amounts or amounts that are not expected to be collected. Electric Energy Trading Chamber (CCEE) transactions -The amounts refer to the sale of electric energy on the spot market. The noncurrent amounts mainly comprise: (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 allowance was recognized for these transactions. Concessionaires and Licensees- Refer basically to receivables for the supply of electric energy to other concessionaires and licensees, mainly by the subsidiaries CPFL Geração, CPFL Brasil and CPFL Renováveis. Allowance for doubtful debts Movements in the allowance for doubtful debts are shown below:


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Consumers, concessionaires and licensees

   

   Otherreceivables(note 12)

   

   TotalAt December 31, 2012

   (128,478)

   

   (22,000)

   

   (150,479)Allowance for doubtful debts

   (111,768)

   

   3,999

   

   (107,769)Recovery of revenue

   35,016

   

   2,429

   

   37,445Write-off of accrued receivables

   71,984

   

   2,421

   

   74,405At December 31, 2013

   (133,247)

   

   (13,152)

   

   (146,399)Allowance for doubtful debts

   (129,482)

   

   (3,444)

   

   (132,925)Recovery of revenue

   49,363

   

   (136)

   

   49,227Write-off of accrued receivables

   90,196

   

   1,446

   

   91,642At December 31, 2014

   (123,171)

   

   (15,285)

   

   (138,456)Allowance for doubtful debts

   (170,131)

   

   (1,152)

   

   (171,283)Recovery of revenue

   44,338

   

   67

   

   44,405Write-off of accrued receivables

   89,770

   

   1,930

   

   91,700At December 31, 2015

   (159,194)

   

   (14,441)

   

   (173,634)Current

   (140,485)

   

   (12,460)

   

   (152,944)Noncurrent

   (18,708)

   

   (1,981)

   

   (20,690)
   ( 7 )TAXES RECOVERABLE
  Dec 31, 2015

   

   Dec 31, 2014CurrentPrepayments of social contribution - CSLL

   

   35,019

   

   21,951Prepayments of income tax - IRPJ

   

   76,920

   

   32,030Withholding income tax - IRRF on interest on capital

   

   11,150

   

   21,044Income tax and social contribution to be offset

   

   100,658

   

   51,236Withholding income tax - IRRF

   

   125,392

   

   88,249State VAT - ICMS to be offset

   

   63,450

   

   66,641Social Integration Program - PIS

   

   8,543

   

   7,527Contribution for Social Security financing - COFINS

   

   40,126

   

   38,098National Social Security Institute - INSS

   

   12,660

   

   1,846Other

   

   1,292

   

   1,015Total

   

   475,211

   

   329,638NoncurrentSocial contribution to be offset - CSLL

   

   57,439

   

   46,555Income tax to be offset - IRPJ

   

   23,765

   

   8,352State VAT - ICMS to be offset

   

   81,584

   

   79,223Social Integration Program - PIS

   

   350

   

   1,576Contribution for Social Security Funding - COFINS

   

   1,613

   

   7,305Others

   

   2,409

   

   1,372Total

   

   167,159

   

   144,383
  Withholding income tax - IRRF–The balances relate mainly to IRRF on financial investments. Social contribution to be offset – CSLL– In noncurrent, the balance refers basically to the final unappealable 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 Revenue Service in order to systematically offset the credit. State VAT - ICMS to be offset– In noncurrent, the balance refers mainly to the credit recorded on purchase of assets that results in the recognition of property, plant and equipment, intangible assets and financial assets.  ( 8 )SECTOR FINANCIAL ASSETS AND LIABILITIES
 The breakdown and changes for the year in the balances of Sector financial asset and liability is as follows:


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At December 31, 2014

   

   Operational revenue

   

   Finance income

   

   Receipt

   

   At December 31, 2015Recognition

   

   Realization

   

   Monetary adjustment

   

   Through tariff flags (note 27.5)

   

   Through CCEEParcel "A"CVA (*)CCC (**)

   58

   

   2

   

   (61)

   

   -

   

   -

   

   -

   

   -CDE (***)

   53,198

   

   517,380

   

   (85,775)

   

   32,430

   

   -

   

   -

   

   517,232Electric energy cost

   1,248,165

   

   423,879

   

   (892,002)

   

   115,593

   

   (827,974)

   

   (61,571)

   

   6,091ESS and EER (****)

   (622,243)

   

   244,334

   

   445,537

   

   (65,701)

   

   (276,136)

   

   -

   

   (274,209)Proinfa

   9,249

   

   (9,485)

   

   (5,297)

   

   (615)

   

   -

   

   -

   

   (6,148)Basic network charges

   154,593

   

   47,847

   

   (128,988)

   

   23,021

   

   -

   

   -

   

   96,474Passthrough from Itaipu

   (309,727)

   

   1,420,055

   

   171,606

   

   38,760

   

   -

   

   -

   

   1,320,695Transmission from Itaipu

   4,076

   

   14,603

   

   (4,234)

   

   1,025

   

   -

   

   -

   

   15,469Neutrality of sector charges

   (12,338)

   

   176,463

   

   16,453

   

   9,695

   

   -

   

   -

   

   190,273Overcontracting

   597,422

   

   146,174

   

   (151,648)

   

   11,568

   

   (193,607)

   

   (265,205)

   

   144,705Other financial components

   (211,735)

   

   95,608

   

   64,072

   

   (4,563)

   

   -

   

   -

   

   (56,618)TOTAL

   910,720

   

   3,076,861

   

   (570,337)

   

   161,213

   

   (1,297,717)

   

   (326,776)

   

   1,953,964Current assets

   610,931

   

   

   

   

   

   

   

   

   

   

   

   1,464,019Noncurrent assets

   321,788

   

   

   

   

   

   

   

   

   

   

   

   489,945Current liabilities

   (21,998)

   

   

   

   

   

   

   

   

   

   

   

   -
  (*) Deferred tariff costs and gains variations from Parcel “A” items (**) Fuel consumption account (***) Energy Development Account – CDE (****) System Service Charge (ESS) and Reserve Energy Charge (EER)  Receipt via injection from CCEE– TheANEEL disclosed Order No. 773 of March 27, 2015, which set the amounts of the resources from the Regulated Contracting Environment (“ACR account”) that were transferred in March 2015 to the subsidiaries relating to the months of November and December 2014.  a) CVA Refers to the variations of the Parcel A account, in accordance with note 3.14. These amounts are adjusted for inflation based on the SELIC rate and are compensated in the subsequent tariff processes. b) Neutrality of industry charges Refers to the neutrality of the industry charges contained in the electric energy tariffs, calculating the monthly differences between the amounts billed relating to such charges and the respective amounts considered at the time the distributors’ tariff was set. c) Energy overcontracting Electric energy distribution concessionaires are required 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 revenues derived from energy overcontracting will be passed through the tariffs, limited to 5% of the energy load requirement, as well as the costs related to electric energy deficits. These amounts are adjusted for inflation based on SELIC rate and are compensated in the subsequent tariff processes. d) Other financial components Refer mainly to (i) exposure to price differences between sub-markets imposed on the distribution agents which enter into Agreements for commercialization of electric energy in the regulated environment – CCEAR; (ii) financial guarantees related to compensation of the cost of the prior raising of guarantees required from the distributors in order to conduct commercial transactions between sector agents; and (iii) financial components granted to offset any tariff process recalculations performed by the ANEEL, to neutralize the effects for consumers.  ( 9 )DEFERRED TAX ASSETS AND LIABILITIES
 9.1- Breakdown of tax assets and liabilities


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December 31, 2015

   

   December 31, 2014Social contribution credit/(debit)Tax losses carryforwards

   152,200

   

   47,564Tax benefit of merged goodwill

   93,467

   

   107,359Deductible temporary differences

   (547,066)

   

   (294,473)Subtotal

   (301,399)

   

   (139,550)Income tax credit / (debit)Tax losses carryforwards

   417,600

   

   126,085Tax benefit of merged goodwill

   323,421

   

   367,944Deductible temporary differences

   (1,519,170)

   

   (819,339)Subtotal

   (778,150)

   

   (325,311)PIS and COFINS credit/(debit)Deductible temporary differences

   (18,159)

   

   2,348Total

   (1,097,708)

   

   (462,513)Total tax credit

   334,886

   

   938,496Total tax debit

   (1,432,594)

   

   (1,401,009)
  9.2 - Tax benefit of merged goodwill Refers to the tax asset 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 Instructions No. 319/99 and No. 349/01 issued by the Brazilian Securities and Exchange Commission (“CVM”). The benefit is realized proportionally to the tax amortization of the merged goodwill that gave rise to it, in accordance with the projected profit of the subsidiaries during the remaining concessions period, as shown in note 15.1.  December 31, 2015

   

   December 31, 2014Social contribution

   

   Income tax

   

   Social contribution

   

   Income taxCPFL Paulista

   55,123

   

   153,119

   

   61,819

   

   171,719CPFL Piratininga

   13,286

   

   45,597

   

   14,691

   

   50,417RGE

   25,058

   

   106,324

   

   28,496

   

   117,683CPFL Santa Cruz

   -

   

   -

   

   869

   

   2,733CPFL Leste Paulista

   -

   

   -

   

   387

   

   1,184CPFL Sul Paulista

   -

   

   -

   

   603

   

   1,892CPFL Jaguari

   -

   

   -

   

   312

   

   962CPFL Mococa

   -

   

   -

   

   182

   

   554CPFL Geração

   -

   

   18,380

   

   -

   

   20,800Total

   93,467

   

   323,421

   

   107,359

   

   367,944
  9.3 - Accumulated balances on nondeductible temporary differences


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December 31, 2015

   

   December 31, 2014Social contribution

   

   Income tax

   

   PIS/COFINS

   

   Social contribution

   

   Income tax

   

   PIS/COFINSDeductible temporary differencesProvision for tax, civil and labor risks

   33,806

   

   93,906

   

   -

   

   29,282

   

   81,340

   

   -Private pension fund

   1,867

   

   5,185

   

   -

   

   1,900

   

   5,277

   

   -Allowance for doubtful debts

   15,680

   

   43,556

   

   -

   

   12,422

   

   34,506

   

   -Free energy supply

   6,897

   

   19,158

   

   -

   

   6,210

   

   17,251

   

   -Research and development and energy efficiency programs

   16,060

   

   44,612

   

   -

   

   11,821

   

   32,836

   

   -Personnel-related provisions

   2,578

   

   7,161

   

   -

   

   3,303

   

   9,176

   

   -Depreciation rate difference

   6,797

   

   18,880

   

   -

   

   7,087

   

   19,685

   

   -Derivatives

   (219,524)

   

   (609,788)

   

   -

   

   -

   

   -

   

   -Recognition of concession - adjustment of intangible asset (IFRS)

   (9,031)

   

   (25,085)

   

   -

   

   (1,572)

   

   (4,368)

   

   -Recognition of concession - adjustment of financial asset (IFRS)

   (73,241)

   

   (202,271)

   

   (18,450)

   

   (45,322)

   

   (125,895)

   

   (2,838)Tariff review - provisional

   -

   

   -

   

   -

   

   4,579

   

   12,720

   

   5,186Actuarial losses (IFRS)

   26,351

   

   73,199

   

   -

   

   26,351

   

   73,199

   

   -Other adjustments (IFRS)

   (8,950)

   

   (24,860)

   

   -

   

   8,613

   

   23,788

   

   -Accelerated depreciation

   (34)

   

   (95)

   

   -

   

   (19)

   

   (54)

   

   -Others

   4,236

   

   11,054

   

   291

   

   4,511

   

   11,306

   

   -Nondeductible temporary differences - accumulated comprehensive income:Property, plant and equipment - adjustment of deemed cost (IFRS)

   (58,484)

   

   (162,456)

   

   -

   

   (61,792)

   

   (171,643)

   

   -Actuarial losses (IFRS)

   10,464

   

   29,064

   

   -

   

   12,672

   

   35,199Deductible temporary differences - Business combination - CPFL Renováveis

   

   

   

   

   -Deferred taxes - asset:Fair value of property, plant and equipment (negative value added of assets)

   24,248

   

   67,355

   

   -

   

   25,725

   

   71,458

   

   -Deferred taxes - liability:Value added derived from determination of deemed cost

   (29,132)

   

   (80,922)

   

   -

   

   (30,905)

   

   (85,847)

   

   -Value added of assets received from the former ERSA

   (86,495)

   

   (240,264)

   

   -

   

   (89,882)

   

   (249,671)

   

   -Intangible asset - exploration right/authorization in indirect subsidiaries acquired

   (193,927)

   

   (538,685)

   

   -

   

   (204,549)

   

   (568,192)

   

   -Other temporary differences

   (17,233)

   

   (47,874)

   

   -

   

   (14,907)

   

   (41,410)

   

   -Total

   (547,066)

   

   (1,519,170)

   

   (18,159)

   

   (294,473)

   

   (819,339)

   

   2,348
  9.4 - Reconciliation of the income tax and social contribution amounts recognized in the statements of profit or loss for 2015, 2014 and 2013  2015

   

   2014

   

   2013Social contribution

   

   Income tax

   

   Social contribution

   

   Income tax

   

   Social contribution

   

   Income taxProfit before taxes

   1,454,454

   

   1,454,454

   

   1,510,304

   

   1,510,304

   

   1,519,200

   

   1,519,200Adjustments to reflect the effective rate:Equity interest in associates and joint ventures

   (216,885)

   

   (216,885)

   

   (59,684)

   

   (59,684)

   

   (120,868)

   

   (120,868)Amortization of intangible asset acquired

   84,484

   

   108,797

   

   93,116

   

   119,477

   

   101,886

   

   131,161Tax incentives - PIIT(*)

   -

   

   -

   

   (10,914)

   

   (10,914)

   

   (10,882)

   

   (10,882)Effect of presumed profit regime

   (186,546)

   

   (244,541)

   

   17,467

   

   (25,827)

   

   (42,151)

   

   (74,675)REFIS(**) - Law No. 11.941/2009 - item 4

   -

   

   -

   

   -

   

   -

   

   (12,739)

   

   (12,739)Adjustment of revenue from excess demand and excess reactive power

   117,374

   

   117,374

   

   102,062

   

   102,062

   

   74,318

   

   74,318Tax incentive - operating profit

   -

   

   (85,760)

   

   -

   

   (71,380)

   

   -

   

   (53,200)Other permanent additions (exclusions), net

   42,310

   

   59,450

   

   56,652

   

   (1,661)

   

   50,489

   

   15,871Tax base

   1,295,192

   

   1,192,890

   

   1,709,002

   

   1,562,375

   

   1,559,254

   

   1,468,187Statutory rate

   9%

   

   25%

   

   9%

   

   25%

   

   9%

   

   25%Tax debit

   (116,567)

   

   (298,223)

   

   (153,810)

   

   (390,594)

   

   (140,333)

   

   (367,047)Recognized (unrecognized) tax credit, net

   (43,595)

   

   (120,792)

   

   (15,179)

   

   (64,277)

   

   (16,422)

   

   (46,361)Total

   (160,162)

   

   (419,015)

   

   (168,989)

   

   (454,871)

   

   (156,756)

   

   (413,408)Current

   (10,916)

   

   (1,944)

   

   (135,421)

   

   (330,600)

   

   (147,107)

   

   (374,874)Deferred

   (149,246)

   

   (417,071)

   

   (33,568)

   

   (124,272)

   

   (9,648)

   

   (38,534)
  (*) Technologic innovation program (**) Tax recovery program  Amortization of intangible asset acquired–Refers to the nondeductible portion of amortization of intangible assets derived from the acquisition of investees (note 15). Recognized (unrecognized) tax assets, net– the recognized tax assets refer to the amount of tax assets on tax loss carryforwards recorded as a result of review of projections of future profits. The unrecognized tax assets refer to losses generated for which currently there is no reasonable assurance that sufficient future taxable profits will be generated to absorb them.


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The deferred income tax and social contribution recognized directly in equity (other comprehensive income) in 2015, 2014 and 2013 were as follows:  2015

   

   2014

   

   2013Social contribution

   

   Income tax

   

   Social contribution

   

   Income tax

   

   Social contribution

   

   Income taxActuarial losses (gains)

   

   (84,635)

   

   (84,635)

   

   247,040

   

   247,040

   

   (431,529)

   

   (431,529)Limits on the asset ceiling

   

   7,984

   

   7,984

   

   -

   

   -Basis of calculation

   

   (76,651)

   

   (76,651)

   

   247,040

   

   247,040

   

   (431,529)

   

   (431,529)Statutory rate

   

   9%

   

   25%

   

   9%

   

   25%

   

   9%

   

   25%Calculated taxes

   

   6,899

   

   19,163

   

   (22,234)

   

   (61,760)

   

   38,838

   

   107,882Limitation on recognition (reversal) of tax credits

   

   (3,959)

   

   (10,998)

   

   16,590

   

   46,081

   

   (46,434)

   

   (128,980)Taxes recognized in other comprehensive income

   

   2,940

   

   8,165

   

   (5,644)

   

   (15,679)

   

   (7,596)

   

   (21,098)
  9.5 Unrecognized tax assets At December 31, 2015, the parent company has unrecognized tax loss carryforwards amounting to R$ 99,062, that could be recognized in the future, according to the annual reviews of projections of taxable profits income. Some subsidiaries have also income tax and social contribution credits on tax loss carryforwards that were not recognized because currently there is no reasonable assurance that sufficient future taxable profits will be generated to absorb them. At December 31, 2015, the main subsidiaries that have such income tax and social contribution credits are CPFL Renováveis (R$ 577,329), Sul Geradora (R$ 72,567), CPFL Telecom (R$ 23,614) and CPFL Jaguari Geração (R$ 1,723). These tax losses can be carried forward indefinitely.  ( 10 )LEASES
 The activities of provision services and lease of equipment for self-production of energy are carried out mainly by the subsidiary CPFL Eficiência Energética (note 13) which is the lessor, and the main risks and rewards of ownership of the assets are transferred to the lessees. The essence of the transaction is to lease self-production equipment in order to serve customers that require higher consumption of electricity in peak hours (when tariffs are higher) and provide maintenance and operation services for such equipment. The subsidiary constructs the power generation plant at the customer’s facilities. When the equipment enters into service, the customer makes monthly fixed payments and the revenue is recognized during the lease agreement period based on the agreement effective interest rate. The investments made in these finance lease projects are recognized at the present value of the minimum lease payments and these payments are treated as amortization of the accounts receivable and the operating revenues are recognized in profit or loss for the year at the effective interest rate implicit in the lease over the lease term. In 2015 these investments resulted in an operational revenue of R$11,164 (R$10,683 in 2014 and R$14,615 in 2013).  Dec 31, 2015

   

   Dec 31, 2014Gross investment

   

   

   

   

   83,854

   

   88,969Unrealized finance income

   

   

   

   

   (36,466)

   

   (41,403)Present value of minimum lease payments

   

   

   

   

   47,388

   

   47,566Current

   

   

   

   

   12,883

   

   12,396Noncurrent

   

   

   

   

   34,504

   

   35,169Up to 1 year

   

   1 to 5 years

   

   Over 5 years

   

   TotalGross investment

   16,432

   

   38,489

   

   28,933

   

   83,854Present value of minimum lease payments

   3,529

   

   23,100

   

   20,758

   

   47,388
  At December 31, 2015, there are no (i) unsecured residual values that benefit the lessor; (ii) provision for uncollectible minimum lease payments; or (iii) contingent payments recognized as revenue during the period.


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( 11 )CONCESSION FINANCIAL ASSET
  Distribution

   

   Transmission

   

   TOTALAt December 31, 2012

   2,377,240

   

   -

   

   2,377,240Current

   34,444

   

   -

   

   34,444Noncurrent

   2,342,796

   

   -

   

   2,342,796Additions

   521,168

   

   15,249

   

   536,417Spin-off of generation activity in distributors

   (12,862)

   

   -

   

   (12,862)Adjustment of expected cash flow

   (66,851)

   

   -

   

   (66,851)Income from financial asset measured at amortized cost

   -

   

   231

   

   231Receipts

   (34,444)

   

   -

   

   (34,444)Disposals

   (12,659)

   

   -

   

   (12,659)At December 31, 2013 (noncurrent)

   2,771,593

   

   15,480

   

   2,787,073Additions

   435,852

   

   59,576

   

   495,428Spin-off of generation activity in distributors

   (5,542)

   

   -

   

   (5,542)Adjustment of expected cash flow

   104,642

   

   -

   

   104,642Adjustment - financial asset measured at amortized cost

   -

   

   2,723

   

   2,723Disposals

   (9,708)

   

   -

   

   (9,708)At December 31, 2014

   3,296,837

   

   77,779

   

   3,374,616Current

   540,094

   

   -

   

   540,094Non current

   2,756,744

   

   77,779

   

   2,834,522Additions

   330,062

   

   37,469

   

   367,531Transfers for intagible assets - extended concessions

   (537,198)

   

   -

   

   (537,198)Adjustment of expected cash flow

   414,800

   

   -

   

   414,800Adjustment - financial asset measured at amortized cost

   -

   

   11,400

   

   11,400Cash inputs

   -

   

   (3,257)

   

   (3,257)Disposals

   (20,788)

   

   -

   

   (20,788)At December 31, 2015

   3,483,713

   

   123,391

   

   3,607,104Current

   -

   

   9,630

   

   9,630Noncurrent

   3,483,713

   

   113,761

   

   3,597,474
  The amount refers to the financial asset corresponding to the right established in the concession agreements of the energy distributors (measured at fair value) and transmitters (measured at amortized cost) to receive cash (i) in the distributors by compensation upon the return 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 revenue ("RAP"). For energy distributors, according to the current tariff model, the remuneration for this asset is recognized in profit or loss upon billing to consumers and the realization occurs upon receipt of the electric energy bills. Additionally, the difference to adjust the balance to its expected cash flows is recognized against a finance income and/or cost account in the statement of profit or loss for the year, based on the fair value (new replacement value - “VNR”) (finance income of R$ 414,800 in 2015, R$ 104,642 in 2014 and finance cost of R$ 66,851 in 2013). The “Transfer to intangible assets” line records the impacts of the extension of the distribution concessions of subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa, which transferred the amount of R$ 537,198 from the concession financial assets to intangible assets (note 15), corresponding to the right to explore the concession from July 2015 through June 2045 (see note 1). For the energy transmitters, the remuneration for this asset is recognized according to the internal rate of return, which takes into account the investment made and the allowed annual revenue (“RAP”) to be received during the remaining concession period. The adjustment of R$ 11,400 is recognized against other operating income (R$ 2,723 in 2014 and R$ 231 in 2013).  ( 12 )OTHER RECEIVABLES


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Current

   

   NoncurrentDec 31, 2015

   

   Dec 31, 2014

   

   Dec 31, 2015

   

   Dec 31, 2014Advances - Fundação CESP

   

   10,567

   

   11,569

   

   -

   

   -Advances to suppliers

   

   10,666

   

   15,934

   

   -

   

   -Pledges, funds and restricted deposits

   

   649

   

   8,007

   

   433,014

   

   290,839Orders in progress

   

   274,605

   

   262,076

   

   -

   

   -Services rendered to third parties

   

   6,987

   

   12,787

   

   -

   

   -Energy pre-purchase agreements

   

   -

   

   515

   

   31,375

   

   32,119Collection agreements

   

   90,451

   

   73,076

   

   -

   

   -Prepaid expenses

   

   61,602

   

   43,185

   

   19,579

   

   9,630GSF Renegotiation

   

   8,724

   

   -

   

   29,392

   

   -Receivables - Energy development account - CDE/CCEE

   

   341,781

   

   522,922

   

   -

   

   -Receivables - Business combination

   

   -

   

   -

   

   13,950

   

   13,950Advances to employees

   

   12,509

   

   10,945

   

   -

   

   -Allowance for doubtful debts (note 6)

   

   (12,460)

   

   (13,304)

   

   (1,981)

   

   (1,981)Indemnities for claims

   

   49,937

   

   -

   

   -

   

   -Other

   

   66,525

   

   63,783

   

   34,685

   

   44,270Total

   

   922,541

   

   1,011,495

   

   560,014

   

   388,828
  Pledges, funds and restricted deposits:refer to guarantees offered for transactions conducted in the CCEE and short-term investments required by the subsidiaries’ loans agreements. Orders in progress:encompass costs and revenues 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. Upon the closing of the respective projects, the balances are amortized against the respective liability recognized in Other Payables (note 24). Energy pre-purchase agreements:refer to prepayments made by subsidiaries, which will be settled with energy to be supplied in the future. GSF renegotiation: refers to the right to 2015 GSF reimbursement net of the agreed upon premium of subsidiaries Ceran, CPFL Jaguari Geração (Paulista Lajeado) and CPFL Renováveis, as consideration for the cost of electricity purchased for resale. This amount will be amortized as other operating expenses on a straight-line basis in the results of these subsidiaries between January 2016 and June 2020 (note 28.2). Collection agreements:refer to (i) agreements between the distributors and municipal governments and companies for collection through the electric energy bills and subsequent pass-through of amounts related to public lighting, newspapers, healthcare, residential insurance, etc.; and (ii) receipts by subsidiary CPFL Total, for subsequent pass-through to customers that use the collection services provided by such subsidiary. Receivables – Energy Development Account – CDE/CCEE:refer to: (i) low income subsidies totaling R$ 18,190 (R$ 18,549 at December 31, 2014) and (ii) other tariff discounts granted to consumers amounting to R$ 323,591 (R$ 504,373 as of December 31, 2014). Indemnities for claims:refer to the amounts receivable from insurance companies as indemnities for claims occurred in subsidiaries of CPFL Renováveis. On May 29, 2015, the distribution subsidiaries obtained preliminary injunctions authorizing non-payment of amounts owed for Energy Development Account (CDE) quotas up to the limit of the balances receivable from Eletrobrás relating to the CDE injection. The subsidiaries carried out matching of accounts of the accounts receivable by way of CDE injection and the CDE accounts payable (note 24) in September 2015, in view of the fact that the Eletrobrás settlement receipts in the amount of R$ 814,850 were issued as from September 25, 2015.  ( 13 )INVESTMENTS
  Dec 31, 2015

   

   Dec 31, 2014Permanent equity interests - equity methodBy joint venture's equity

   

   1,235,832

   

   1,085,835Fair value of assets, net

   

   11,799

   

   12,934Total

   

   1,247,631

   

   1,098,769


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In the financial statements, the investment balances relate to interests in entities accounted for by the equity method: Joint Ventures

   

   Share of equity

   

   Share of profit (loss)December 31, 2015

   

   December 31, 2014

   

   2015

   

   2014

   

   2013Baesa

   

   166,150

   

   163,662

   

   2,508

   

   10,583

   

   4,618Enercan

   

   473,148

   

   415,952

   

   74,677

   

   49,040

   

   67,640Chapecoense

   

   449,049

   

   399,979

   

   77,487

   

   21,285

   

   60,809EPASA

   

   147,485

   

   106,243

   

   63,348

   

   (20,041)

   

   (10,961)Fair value adjustments of assets, net

   

   11,799

   

   12,934

   

   (1,136)

   

   (1,182)

   

   (1,238)1,247,631

   

   1,098,769

   

   216,885

   

   59,684

   

   120,868
  13.1 - Dividends and Interest on capital At December 31, 2015 and 2014, the Company has the following amounts receivable from the joint ventures below, which financial statements are not consolidated, relating to dividends and interest on capital:  Dividends

   

   Interest on capital

   

   TotalInvestments

   December 31, 2015

   

   December 31, 2014

   

   December 31, 2015

   

   December 31, 2014

   

   December 31, 2015

   

   December 31, 2014Investco

   -

   

   -

   

   2,118

   

   2,552

   

   2,118

   

   2,552EPASA

   29,933

   

   14,891

   

   -

   

   -

   

   29,933

   

   14,891BAESA

   20

   

   96

   

   -

   

   -

   

   20

   

   96ENERCAN

   30,905

   

   24,816

   

   -

   

   -

   

   30,905

   

   24,816Chapecoense

   28,417

   

   12,128

   

   -

   

   -

   

   28,417

   

   12,12889,274

   

   51,931

   

   2,118

   

   2,552

   

   91,392

   

   54,483
   13.2 – Joint Ventures Summarized financial information on joint ventures at December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 is as follows:  December 31, 2015Joint venture

   

   Enercan

   

   Baesa

   

   Chapecoense

   

   EpasaCurrent assets

   

   292,133

   

   105,198

   

   356,493

   

   305,371Cash and cash equivalents

   

   112,387

   

   75,097

   

   239,192

   

   120,307Noncurrent assets

   

   1,253,002

   

   1,174,604

   

   3,079,957

   

   600,413Current liabilities

   

   264,721

   

   188,077

   

   447,142

   

   336,794Financial liabilities

   

   167,845

   

   182,215

   

   251,683

   

   180,190Noncurrent liabilities

   

   309,317

   

   427,284

   

   2,108,820

   

   292,490Financial liabilities

   

   265,095

   

   415,868

   

   2,108,109

   

   292,295Equity

   

   971,097

   

   664,442

   

   880,488

   

   276,500Net operating revenue

   

   523,055

   

   427,561

   

   729,511

   

   949,246Depreciation and amortization

   

   (53,733)

   

   (55,342)

   

   (130,652)

   

   (32,413)Interest income

   

   15,742

   

   8,426

   

   28,235

   

   11,275Interest expense

   

   (56,049)

   

   (22,555)

   

   (132,625)

   

   (29,778)Income tax expense

   

   (76,795)

   

   (5,165)

   

   (76,880)

   

   (32,869)Profit (loss) for the year

   

   153,269

   

   10,028

   

   151,935

   

   118,734Equity Interests and voting capital

   

   48.72%

   

   25.01%

   

   51.00%

   

   53.34% (*)*Up to January 31, 2015, CPFL Geração's interest in Epasa was 53.84%


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December 31, 2014Joint venture

   

   Enercan

   

   Baesa

   

   Chapecoense

   

   EpasaCurrent assets

   

   143,213

   

   71,178

   

   252,223

   

   337,891Cash and cash equivalents

   

   45,329

   

   19,178

   

   154,554

   

   96,588Noncurrent assets

   

   1,238,047

   

   1,210,974

   

   3,090,190

   

   637,190Current liabilities

   

   149,088

   

   138,909

   

   374,374

   

   480,948Financial liabilities

   

   91,723

   

   130,122

   

   313,222

   

   345,657Noncurrent liabilities

   

   378,465

   

   488,751

   

   2,183,767

   

   308,168Financial liabilities

   

   338,297

   

   479,329

   

   2,183,155

   

   307,622Equity

   

   853,707

   

   654,492

   

   784,272

   

   185,965Net operating revenue

   

   492,921

   

   395,440

   

   820,500

   

   1,220,511Depreciation and amortization

   

   (53,674)

   

   (50,554)

   

   (130,988)

   

   (32,339)Interest income

   

   14,295

   

   6,345

   

   26,208

   

   2,368Interest expense

   

   (40,572)

   

   (32,933)

   

   (135,463)

   

   (34,983)Income tax expense

   

   (50,112)

   

   (20,982)

   

   (21,751)

   

   16,862Profit (loss) for the year

   

   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, CPFL Geração's interest in Epasa was 52.75%
  December 31, 2013Joint venture

   

   Enercan

   

   Baesa

   

   Chapecoense

   

   EpasaNet operating revenue

   

   465,617

   

   277,940

   

   669,126

   

   585,535Depreciation and amortization

   

   (50,370)

   

   (51,736)

   

   (133,035)

   

   (32,298)Interest income

   

   14,480

   

   4,386

   

   12,049

   

   972Interest expense

   

   (45,363)

   

   (39,658)

   

   (140,427)

   

   (37,609)Income tax expense

   

   (69,620)

   

   (9,433)

   

   (60,844)

   

   10,750Profit (loss) for the year

   

   138,832

   

   18,462

   

   119,233

   

   (20,778)Equity Interests and voting capital

   

   48.72%

   

   25.01%

   

   51.00%

   

   52.75%
   Although holding more than 50% in EPASA and Chapecoense, CPFL Geração controls these investments jointly with other shareholders. The analysis of the classification of the type of investment is based on the Shareholders' Agreement of each joint venture. The borrowings from the BNDES obtained by the joint ventures ENERCAN, BAESA and Chapecoense establish restrictions on the payment of dividends to subsidiary CPFL Geração above the mandatory minimum dividend of 25% without the prior consent of the BNDES. 13.3 – Joint operation Through its wholly-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 (joint operation), CPFL Geração was assured 51.54% of the installed power of 1,275 MW (657 MW) and the assured energy of mean 671 MW (mean 345.4 MW) until 2028 (information on energy capacity measures not audited by the independent auditors). 13.4 – Capital increases 13.4.1 – EPASA On January 31, 2014, after carrying out a capital increase, subsidiary CPFL Geração began holding 57.13% of the capital stock of the joint venture EPASA, and the equity interests of certain other shareholders were diluted. According to the Shareholders Agreement in effect, these shareholders were assured the right to repurchase shares in order to re-comprise their stakes by March 1, 2015. This right was partially exercised by Eletricidade do Brasil S/A and OZ&M Incorporação e Participação Ltda. by February 25, 2015, which purchased from subsidiary CPFL Geração 10,704,756 common shares for the amount of R$ 10,454, generating a positive result of R$ 3,391, recorded in line item “Gain on disposal of noncurrent assets” (note 28). After this corporate operation, the ownership structure of the EPASA joint venture stood as follows:


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At February 25, 2015

   

   At December 31, 2014Shareholders

   

   Shares

   

   Interest - %

   

   Shares

   

   Interest - %CPFL Geração de Energia S/A

   

   150,941,659

   

   53.34

   

   161,646,415

   

   57.13Eletricidade do Brasil S/A

   

   118,100,009

   

   41.74

   

   107,903,763

   

   38.13Aruanã Energia S/A

   

   6,960,800

   

   2.46

   

   6,960,800

   

   2.46OZ&M Incorporação, Participação Ltda

   

   6,959,277

   

   2.46

   

   6,450,767

   

   2.28Total

   

   282,961,745

   

   100.00

   

   282,961,745

   

   100.00
  13.4.2 – CPFL Paulista and RGE On December 16, 2015, a Board of Directors’ Meeting approved capital increases of R$ 600,000 in CPFL Paulista and R$ 250,000 in RGE made by the parent company CPFL Energia. 13.4.3 – CPFL ESCO On August 26, 2015, a Board of Directors’ Meeting approved a capital reduction of R$ 360,000 in CPFL ESCO, for the parent company CPFL Energia.




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( 14 )PROPERTY, PLANT AND EQUIPMENT
  Land

   

   Reservoirs, dams and water mains

   

   Buildings, construction and improvements

   

   Machinery and equipment

   

   Vehicles

   

   Furniture and fittings

   

   In progress

   

   TotalAt December 31, 2012

   110,609

   

   1,116,551

   

   1,312,422

   

   3,908,751

   

   5,370

   

   15,986

   

   634,372

   

   7,104,060Historical cost

   117,394

   

   1,459,396

   

   1,677,795

   

   5,044,085

   

   10,772

   

   23,956

   

   634,372

   

   8,967,768Accumulated 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

   

   930,916Disposals

   -

   

   -

   

   -

   

   (1,071)

   

   (847)

   

   (24)

   

   (153)

   

   (2,095)Provision for socio environmental costs

   -

   

   -

   

   (17,747)

   

   -

   

   -

   

   -

   

   -

   

   (17,747)Transfers

   4,203

   

   13,988

   

   172,530

   

   373,362

   

   19,531

   

   543

   

   (584,156)

   

   -Transfers from/to other assets - cost

   (15)

   

   440

   

   (200)

   

   15,946

   

   17

   

   117

   

   422

   

   16,727Transfers 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)Write-off of depreciation

   -

   

   -

   

   -

   

   103

   

   527

   

   15

   

   -

   

   645Reclassification and transfers from/to other assets - depreciation

   -

   

   (947)

   

   38,524

   

   (35,808)

   

   22

   

   377

   

   -

   

   2,169Spin-off of generation activity in distributors - cost

   3,953

   

   5,420

   

   3,070

   

   7,443

   

   83

   

   (10)

   

   -

   

   19,959Spin-off of generation activity in distributors - depreciation

   -

   

   (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

   

   7,717,419Historical cost

   126,820

   

   1,375,993

   

   1,718,629

   

   5,671,053

   

   29,928

   

   24,277

   

   968,826

   

   9,915,527Accumulated 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

   

   338,475Disposals

   (1,772)

   

   -

   

   (12,723)

   

   (14,719)

   

   (1,804)

   

   (582)

   

   (71,760)

   

   (103,359)Reversal of provision for socio environmental costs

   -

   

   -

   

   9,193

   

   -

   

   -

   

   -

   

   -

   

   9,193Transfers, net

   500

   

   (3,674)

   

   156,986

   

   997,610

   

   14,862

   

   (92)

   

   (1,166,193)

   

   -Transfers from/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)Write-off of depreciation

   -

   

   -

   

   -

   

   404

   

   1,026

   

   482

   

   -

   

   1,911Business combination

   71,646

   

   264,146

   

   106,682

   

   844,162

   

   93

   

   240

   

   330,030

   

   1,616,999Spin-off of generation activity in distributors - cost

   -

   

   -

   

   460

   

   6,089

   

   -

   

   204

   

   -

   

   6,754Spin-off of generation activity in distributors - depreciation

   -

   

   -

   

   (32)

   

   (866)

   

   -

   

   (28)

   

   -

   

   (926)At December 31, 2014

   182,316

   

   1,185,614

   

   1,517,475

   

   5,832,005

   

   32,328

   

   11,660

   

   388,088

   

   9,149,486Historical cost

   197,393

   

   1,637,812

   

   1,976,212

   

   7,521,804

   

   43,081

   

   22,462

   

   388,088

   

   11,786,852Accumulated depreciation

   (15,077)

   

   (452,199)

   

   (458,737)

   

   (1,689,799)

   

   (10,753)

   

   (10,802)

   

   -

   

   (2,637,366)Additions

   -

   

   -

   

   168

   

   512

   

   -

   

   -

   

   583,538

   

   584,216Disposals

   (1,354)

   

   (414)

   

   (4,093)

   

   (21,773)

   

   (558)

   

   (284)

   

   -

   

   (28,477)Transfers

   2,338

   

   140

   

   61,615

   

   217,462

   

   10,436

   

   578

   

   (292,569)

   

   -Reclassification - cost

   (212)

   

   328,101

   

   (499,943)

   

   172,169

   

   22

   

   (137)

   

   -

   

   -Transfers from/to other assets - cost

   (24)

   

   2

   

   (6,548)

   

   6,598

   

   (1)

   

   (186)

   

   630

   

   471Depreciation

   (6,257)

   

   (68,562)

   

   (50,716)

   

   (370,076)

   

   (6,343)

   

   (1,926)

   

   -

   

   (503,881)Write-off of depreciation

   -

   

   139

   

   204

   

   3,572

   

   379

   

   186

   

   -

   

   4,480Reclassification - depreciation

   -

   

   (68,775)

   

   68,711

   

   151

   

   -

   

   (88)

   

   -

   

   -Transfers from/to other assets - depreciation

   -

   

   -

   

   -

   

   35

   

   -

   

   -

   

   -

   

   35Impairment

   -

   

   -

   

   (10,891)

   

   (16,565)

   

   (32)

   

   (106)

   

   (5,519)

   

   (33,112)At December 31, 2015

   176,807

   

   1,376,246

   

   1,075,982

   

   5,824,089

   

   36,230

   

   9,696

   

   674,166

   

   9,173,217Historical cost

   198,141

   

   1,965,641

   

   1,516,228

   

   7,878,838

   

   52,947

   

   22,323

   

   674,166

   

   12,308,285Accumulated depreciation

   (21,334)

   

   (589,395)

   

   (440,246)

   

   (2,054,749)

   

   (16,717)

   

   (12,627)

   

   -

   

   (3,135,068)Average depreciation rate 2015

   3.86%

   

   3.66%

   

   3.46%

   

   4.62%

   

   14.24%

   

   10.49%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%


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The balance of construction in progress refers mainly to works in progress of the operating subsidiaries and/or those under development, especially for CPFL Renováveis’ projects, which has construction in progress of R$ 612,083 in December 31, 2015 (R$ 262,225, in December 31, 2014). In 2015, mainly owing to the process of adapting their accounts to the newly defined ANEEL chart of accounts, subsidiaries Ceran and CPFL Renováveis carried out certain reclassifications, mainly involving the accounts “Buildings, civil works and benefits/improvements”, “Machinery and equipment” and “Reservoirs, dams and water pipelines”. These amounts are shown in the lines “Reclassification - cost” and “Reclassification – depreciation” and do not generate material effects on the statement of profit or loss for the year. In accordance with IAS 23, the interest on borrowings taken by subsidiaries to finance the works is capitalized during the construction phase. During 2015, R$ 34,212 was capitalized in the financial statements at a rate of 11.16% p.a. (R$ 4,236 in 2014 at a rate of 8.59% p.a. and R$ 48,339 in 2013 at a rate of 8.23% p.a.). For further details on assets under construction and borrowing costs, see note 30. In the financial statements, depreciation expenses are recognized in the statement of profit or loss in line item “depreciation and amortization” (note 29). At December 31, 2015, the total amount of property, plant and equipment pledged as collateral for borrowings, as mentioned in note 17, is approximately R$ 3,567,258, mainly relating to the subsidiary CPFL Renováveis (R$ 3,535,263). 14.1 Impairment testing For all the reporting years the Company assesses whether there are indicators of impairment of its assets that would require an impairment test. The assessment was based on external and internal information sources, taking into account fluctuations in interest rates, changes in market conditions and other factors. As the deterioration of the Brazilian economy has intensified, as at December 31, 2015 a provision for impairment of R$ 33,112 was recognized due to the assessment of the recoverable amount of the cash-generating units of subsidiaries CPFL Telecom (R$ 31,284) and CPFL Total (R$ 1,828). Such loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 29). Such provision for impairment was based on the assessment of the cash-generating units comprising fixed assets of subsidiaries CPFL Telecom and CPFL Total which, separately, are not featured as an operating segment and are allocated in the operating segment of Others and Services, respectively (note 31). Additionally, during 2015 the Company did not change the form of aggregation of the assets for identification of these cash-generating units. Fair value was measured by using the cost approach, a valuation technique that reflects the amount that would be required at present to replace the service capacity of an asset (normally referred to as the cost of substitution or replacement). A provision for impairment of assets was recognized owing to the unfavorable scenario for the business of these subsidiaries and it was calculated based on their fair values, net of selling expenses.  ( 15 )INTANGIBLE ASSETS


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Goodwill

   

   Concession right

   

   Other intangible assets

   

   TotalAcquired in business combinations

   

   Distribution infrastructure - operational

   

   Distribution infrastructure - in progress

   

   Public utilitiesAt December 31, 2012

   6,115

   

   4,611,347

   

   3,816,428

   

   633,313

   

   33,001

   

   80,108

   

   9,180,312Historical cost

   6,152

   

   6,815,774

   

   9,183,730

   

   633,313

   

   38,679

   

   156,661

   

   16,834,309Accumulated amortization

   (37)

   

   (2,204,427)

   

   (5,367,301)

   

   -

   

   (5,678)

   

   (76,553)

   

   (7,653,996)Additions

   -

   

   -

   

   -

   

   853,649

   

   -

   

   7,444

   

   861,093Amortization

   -

   

   (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 of generation activity in distributors

   -

   

   -

   

   (553)

   

   -

   

   -

   

   -

   

   (553)At December 31, 2013

   6,115

   

   4,312,381

   

   3,763,197

   

   574,131

   

   31,582

   

   60,922

   

   8,748,328Historical cost

   6,152

   

   6,811,237

   

   9,310,710

   

   574,131

   

   35,840

   

   156,023

   

   16,894,093Accumulated amortization

   (37)

   

   (2,498,856)

   

   (5,547,513)

   

   -

   

   (4,258)

   

   (95,100)

   

   (8,145,764)Additions

   -

   

   -

   

   -

   

   709,811

   

   -

   

   18,887

   

   728,698Amortization

   -

   

   (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)Disposal and transfer - other assets

   -

   

   -

   

   (21,279)

   

   159

   

   -

   

   16,357

   

   (4,763)Business combination

   -

   

   630,848

   

   -

   

   -

   

   -

   

   3,488

   

   634,336Spin-off of generation activity in distributors

   -

   

   -

   

   (299)

   

   -

   

   -

   

   13

   

   (286)At December 31, 2014

   6,115

   

   4,658,210

   

   3,734,606

   

   414,574

   

   30,162

   

   86,503

   

   8,930,171Historical cost

   6,152

   

   7,441,935

   

   9,526,355

   

   414,574

   

   35,840

   

   195,577

   

   17,620,433Accumulated amortization

   (37)

   

   (2,783,725)

   

   (5,791,748)

   

   -

   

   (5,678)

   

   (109,074)

   

   (8,690,262)Additions

   -

   

   -

   

   -

   

   879,851

   

   -

   

   9,298

   

   889,149Amortization

   -

   

   (302,665)

   

   (460,774)

   

   -

   

   (1,419)

   

   (12,604)

   

   (777,462)Transfer - intangible assets

   -

   

   -

   

   512,912

   

   (512,912)

   

   -

   

   -

   

   -Transfer - financial asset

   -

   

   -

   

   387

   

   (330,449)

   

   -

   

   -

   

   (330,062)Transfers from concession financial asset - extended concessions

   -

   

   -

   

   488,635

   

   48,563

   

   -

   

   -

   

   537,198Disposal and transfer - other assets

   -

   

   -

   

   (26,584)

   

   -

   

   -

   

   (6,228)

   

   (32,813)Impairment losses

   -

   

   -

   

   -

   

   -

   

   -

   

   (5,844)

   

   (5,844)At December 31, 2015

   6,115

   

   4,355,546

   

   4,249,182

   

   499,627

   

   28,743

   

   71,125

   

   9,210,338Historical cost

   6,152

   

   7,441,902

   

   10,348,857

   

   499,627

   

   35,840

   

   192,626

   

   18,525,003Accumulated amortization

   (37)

   

   (3,086,356)

   

   (6,099,675)

   

   -

   

   (7,097)

   

   (121,500)

   

   (9,314,665)
  The amortization of intangible assets is recognized in the statement of profit or loss in the following line items: (i) “depreciation and amortization” for amortization of distribution infrastructure intangible assets, use of public asset and other intangible assets; and (ii) “amortization of concession intangible asset” for amortization of the intangible asset acquired in business combination (note 29). As mentioned in note 11, the subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa made a transfer from concession financial assets to intangible assets in the amount of R$ 537,198, recognized in line item “Extension of concessions – transfer of financial asset”, whose amortization for the period from July to December 2015 was R$ 27,939. In accordance with IAS 23, the interest on borrowings taken by subsidiaries is capitalized for qualifying intangible assets. In the financial statements, in 2015, R$ 11,358 was capitalized (R$ 8,044 in 2014 and R$ 8,845 in 2013) at a rate of 7.53% p.a. (7.50% p.a. in 2014 and 8.32% p.a. in 2013). 15.1 Intangible asset acquired in business combinations The breakdown of the intangible asset related to the right to operate the concessions acquired in business combinations is as follows:


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December 31, 2015

   

   December 31, 2014

   

   Annual amortization rateHistorical cost

   

   Accumulated amortization

   

   Net value

   

   Net value

   

   2015

   

   2014

   

   2013Intangible asset - acquired in business combinationsIntangible asset acquired, not mergedParent companyCPFL Paulista

   304,861

   

   (187,033)

   

   117,829

   

   132,397

   

   4.78%

   

   5.10%

   

   6.03%CPFL Piratininga

   39,065

   

   (22,451)

   

   16,614

   

   18,371

   

   4.50%

   

   4.66%

   

   4.85%RGE

   3,150

   

   (1,560)

   

   1,590

   

   1,764

   

   5.51%

   

   5.70%

   

   5.86%CPFL Geração

   54,555

   

   (31,798)

   

   22,757

   

   25,509

   

   5.04%

   

   4.88%

   

   4.83%CPFL Santa Cruz

   9

   

   (9)

   

   -

   

   1

   

   15.86%

   

   16.22%

   

   16.40%CPFL Leste Paulista

   3,333

   

   (3,333)

   

   -

   

   513

   

   15.38%

   

   17.36%

   

   17.45%CPFL Sul Paulista

   7,288

   

   (7,288)

   

   -

   

   1,156

   

   15.86%

   

   17.53%

   

   16.94%CPFL Jaguari

   5,213

   

   (5,213)

   

   -

   

   713

   

   13.68%

   

   19.13%

   

   16.49%CPFL Mococa

   9,110

   

   (9,110)

   

   -

   

   1,041

   

   11.42%

   

   17.53%

   

   18.96%CPFL Jaguari Geração

   7,896

   

   (3,312)

   

   4,584

   

   5,086

   

   6.36%

   

   6.71%

   

   7.07%434,480

   

   (271,107)

   

   163,373

   

   186,550SubsidiariesCPFL Renováveis

   3,764,809

   

   (569,594)

   

   3,195,215

   

   3,352,524

   

   5.44%

   

   4.11%

   

   4.11%Others

   15,096

   

   (14,580)

   

   516

   

   9213,779,905

   

   (584,174)

   

   3,195,731

   

   3,353,444Subtotal

   4,214,385

   

   (855,281)

   

   3,359,104

   

   3,539,995Intangible asset acquired and merged – DeductibleSubsidiariesRGE

   1,120,266

   

   (838,715)

   

   281,551

   

   301,564

   

   1.79%

   

   1.75%

   

   1.89%CPFL Geração

   426,450

   

   (303,531)

   

   122,919

   

   139,103

   

   3.80%

   

   3.89%

   

   3.66%Subtotal

   1,546,716

   

   (1,142,246)

   

   404,470

   

   440,667Intangible asset acquired and merged – ReassessedParent companyCPFL Paulista

   1,074,026

   

   (690,257)

   

   383,770

   

   430,386

   

   4.34%

   

   4.61%

   

   5.39%CPFL Piratininga

   115,762

   

   (66,530)

   

   49,232

   

   54,439

   

   4.50%

   

   4.66%

   

   4.85%RGE

   310,128

   

   (158,975)

   

   151,153

   

   167,640

   

   5.32%

   

   5.50%

   

   5.65%CPFL Santa Cruz

   61,685

   

   (61,685)

   

   -

   

   6,054

   

   9.81%

   

   10.03%

   

   10.14%CPFL Leste Paulista

   27,034

   

   (27,034)

   

   -

   

   2,709

   

   10.02%

   

   14.45%

   

   14.47%CPFL Sul Paulista

   38,168

   

   (38,168)

   

   -

   

   4,184

   

   10.96%

   

   14.35%

   

   14.02%CPFL Mococa

   15,124

   

   (15,124)

   

   -

   

   1,266

   

   8.37%

   

   14.05%

   

   14.85%CPFL Jaguari

   23,600

   

   (23,600)

   

   -

   

   2,195

   

   9.30%

   

   15.33%

   

   14.28%CPFL Jaguari Geração

   15,275

   

   (7,457)

   

   7,818

   

   8,675

   

   5.61%

   

   5.91%

   

   6.23%Subtotal

   1,680,801

   

   (1,088,829)

   

   591,972

   

   677,548Total

   7,441,902

   

   (3,086,356)

   

   4,355,546

   

   4,658,210
  The intangible asset acquired in business combinations is associated to the right to operate the concessions and comprises: - Intangible asset acquired, not merged Refers basically to the intangible asset from acquisition of the shares held by non-controlling interests prior to adoption of IFRS 3. - Intangible asset acquired and merged - Deductible Refers to the intangible asset from the acquisition of subsidiaries that were merged into the respective equity, 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 requirements and avoid the amortization of the intangible asset resulting from the merger of parent company causing a negative impact on dividends paid to noncontrolling interests, the subsidiaries applied the concepts of CVM Instructions No. 319/1999 and No. 349/2001 to the intangible asset. A reserve was therefore recognized to adjust the intangible, against a special goodwill reserve on the merger of equity in each subsidiary, so that the effect of the transaction on the equity reflects the tax benefit of the merged intangible asset. These changes affected the Company's investment in subsidiaries, and in order to adjust this, a non-deductible intangible asset was recognized for tax purposes. For the balances relating to the subsidiary CPFL Renováveis, the amortization is recognized for the remaining period of the respective operation authorizations, using the straight-line method. For the other balances, the amortization rates for intangible assets acquired in business combination are based on the projected income


curves of the concessionaires for the remaining concession period, and these projections are reviewed annually.


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15.2 Impairment test For all the reporting years, the Company assesses whether there are indicators of impairment of its assets that would require an impairment test. The assessment was based on external and internal information sources, taking into account fluctuations in interest rates, changes in market conditions and other factors. At December 31, 2015, as the deterioration of the Brazilian economy has intensified, an impairment loss of R$ 5,844 was recognized, related to the assessment of the recoverable amount of the cash-generating units of subsidiaries CPFL Telecom (R$ 1,835) and CPFL Total (R$ 4,009). Such loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 29). Such provision for impairment was based on the assessment of these cash-generating units formed by the intangible assets of subsidiaries CPFL Telecom and CPFL Total, which, separately, do not feature an operating segment and are allocated to the operating segment of Others and Services, respectively (note 31). Additionally, during 2015 the Company did not change the form of aggregation of the assets for identification of these cash-generating units. For fair value measurement the cost approach was used, this is a valuation technique that reflects the amount that would be currently required to replace the service capacity of an asset (normally referred to as cost of substitution or replacement).The recognition of the provision for impairment of assets was due to the unfavorable scenario for the businesses of these subsidiaries and was calculated based on their fair values net of selling expenses.  15.3 2013 IPO of CPFL Renováveis In August 2013, the Company completed the initial public offer of 28 million common shares, secondary offer of 43.9 million common shares and complementary offer of 1.2 common shares of the subsidiary CPFL Renováveis, totaling 73.1 million shares in the amount of R$ 914,686. The transaction resulted in a gross funding (i) of R$ 364,687 in the initial and complementary offer; and (ii) R$ 549,999 in the secondary offer. Fund-raising costs of R$ 36,187 were incurred in the transaction. As a result, the Company, through the subsidiary CPFL Geração, had its interest in CPFL Renováveis diluted from 63% to 58.84% on August 31, 2013, and a positive impact of R$ 59,308 related to the change in the equity interest which, in accordance with IFRS 10, was recognized as a transaction with shareholders and accounted for directly in equity, in a capital reserve account.  15.4 Business combinations 15.4.1 – 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 not audited by the independent auditors). On February 28, 2014, the acquisition of Rosa dos Ventos was completed, for the total price was R$ 103,358, which includes: (i) 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 on the acquisition a) Considerations


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Rosa dos VentosFebruary 28, 2014Consideration transferred:Consideration transferred in cash and cash equivalents by the acquirer

   

   70,296Price adjustment paid to sellers according to contractual clause

   

   634Total of consideration transferred

   

   70,930
  b) Assets acquired and liabilities assumed 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 for 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 value was allocated to goodwill for this transaction. The allocation of the amount paid is based on economic/financial valuation reports. The subsidiary's management does not expect the amount allocated as the right to operate the acquisition to be tax-deductible and has therefore recognized deferred income tax and social contribution for the difference between the allocated amount and the tax base of this asset. The accounting for the Rosa dos Ventos acquisition was concluded. We show below the assets acquired and liabilities assumed of Rosa dos Ventos at fair value:  Rosa dos VentosFebruary 28, 2014Current assetsCash and cash equivalents

   

   2,466Other current assets

   

   6,231Non current assetsFiduciary investments

   

   4,223Propert, plant and equipment

   

   50,102Intangible - exploitation rights

   

   67,741Deffered taxes credits

   

   570Other assets

   

   307Current liabilities

   

   3,797Non current liabilitiesLoans, Financings and Debentures

   

   32,934Deferred taxes on exploitation rights

   

   23,032Provision for decommissioning costs

   

   947Net assets acquired

   

   70,930Consideration transferred

   

   70,930
  c) Net cash outflow on acquisition of subsidiary


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Rosa dos VentosFebruary 28, 2014Consideration transferred in cash

   

   

   

   70,930Less: Balance of cash and cash equivalent acquired

   

   

   

   (2,466)Net cash

   

   

   

   68,464
  d) Financial information on net operating revenue and profit of the subsidiary acquired included in the 2014 consolidated financial statements: Net operating revenues

   

   Net income (loss)2014

   

   2014Rosa dos Ventos March 01, 2014 to Dec 31, 2014

   

   15,166

   

   7,711
  The Company's consolidated information for 2014 includes 10 (ten) months of operations of the subsidiary Rosa dos Ventos.


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15.4.2 – Acquisition of Dobrevê Energia S.A. (“DESA”) In February 2014, the subsidiaries CPFL Renováveis and CPFL Geração signed an association agreement, whereby CPFL Renováveis merged WF2 Holding S.A. (“WF2”), wholly owner of DESA’s shares on the acquisition date. Arrow – Fundo de Investimentos e Participações (“FIP Arrow”) held all shares of WF2. On October 1, 2014,after all the conditions precedent had been fulfilled, the acquisition was concluded. The shareholders of both CPFL Renováveis and FIP Arrow approved the Protocol of Merger and the Termination of the Association Agreement at Extraordinary General Meetings with the approvals coming into effect on October 1, 2014. Therefore, on October 1, 2014, FIP Arrow contributed to CPFL Renováveis the net assets of WF2 as a capital increase, in turn CPFL Renováveis issued to FIP Arrow 61,752,782 new common shares, whereby FIP Arrow became a shareholder of CPFL Renováveis, with an interest of 12.27%. After the capital increase, CPFL Renováveis merged WF2, dissolving that company, and CPFL Renováveis now holds directly 100% of DESA shares and, consequently, DESA is now a subsidiary of CPFL Renováveis. The exchange ratio for 100% of the shares of WF2 for 12.27% of the shares of CPFL Renováveis (after the issuance of new common shares) was freely negotiated and agreed between the parties and reflects the best valuation of WF2 and CPFL Renováveis. This association between CPFL Renováveis and DESA resulted in a business combination in accordance with IFRS 3 (R) – Business Combination since CPFL Renováveis now holds the control of WF2 and paid for obtaining the control of such company through the issuance of new shares. As a result of this issuance of shares, the equity of CPFL Renováveis increased by R$ 833,663, which reflects the fair value of the shares issued by CPFL Renováveis that were transferred to FIP Arrow on the acquisition date and that represents the total price paid. The association was appraised at fair value using the income approach. As a result of this transaction, the Company, through the subsidiary CPFL Geração, had its interest in CPFL Renováveis reduced from 58.83% to 51.61%, with a gain on equity interest in the amount of R$180,297 which, in accordance with IFRS 10, was recognized as a capital transaction, that is, transaction with shareholders in the capacity of owners, and accounted for directly in CPFL Energia’s equity in the capital reserve account, as follows:  Before the capital increase

   

   After the capital increaseEquity attributable to:

   

   Number of shares

   

   % of equityinterest(1)

   

   Interest

   

   Number of shares

   

   % of equityinterest (2)

   

   Interest

   

   Increase in EquityCPFL Energia - controlling shareholder

   

   259,748,799

   

   58.83%

   

   2,037,289

   

   259,748,799

   

   51.61%

   

   2,217,587

   

   180,297Non-controlling shareholders

   

   181,781,079

   

   41.17%

   

   1,425,781

   

   243,533,861

   

   48.39%

   

   2,079,146

   

   653,366441,529,878

   

   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 on the acquisition of WF2 a) Assets acquired and liabilities assumed recognized on the acquisition date The total amount paid on the transaction (fair value of the shares issued by CPFL Renováveis) 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 has been amortized over the remaining period of the authorization related to the operation of the wind farms and SHPs acquired. The average term for all projects is estimated at 25 years. Consequently, as the total amount paid was temporarily allocated to identified assets and liabilities, no residual value 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 recognized deferred income tax and social contribution for the difference between the allocated amount and the tax base of this asset. Allocation of the amount paid for assets acquired and liabilities assumed was carried out using amounts provisionally calculated for the financial statements for the year ended December 31, 2014, based on analyses conducted by Management at the time such statements were prepared. The fair values presented were still pending confirmation until conclusion of the economic-financial valuation report prepared by an independent appraiser, which was finalized on September 30, 2015. As a consequence, reclassifications were made in the amounts at December 31, 2014, relating to: (i) increase in the fair value of property, plant and equipment, and reduction of intangible assets related to exploration rights, as


a consequence of the refining of the premises used for determination of the value of the tangible and intangible assets; (ii) conclusion of the allocation of the fair value of the provision for tax, civil and labor risks in the amount of R$ 17,293; and (iii) correlated effects of the matters described in sub-items (i) and (ii) above on the balances of deferred income tax and social contribution and the portion of equity attributable to non-controlling shareholders.


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The fair value of the adjusted assets and liabilities, as well as the allocation of the price paid, are as follows:  WF2preliminar

   

   WF2final positionOctober 01, 2014

   

   October 01, 2014Current assetsCash and cash equivalents

   139,293

   

   139,293Other assets

   32,274

   

   32,274Noncurrent assetsProperty, plant and equipment

   1,295,476

   

   1,569,594Intangible assets

   7,937

   

   7,937Intangible - exploitation rights

   784,459

   

   555,961Other assets

   98,264

   

   98,264Current liabilitiesLoans, Financings and Debentures

   102,996

   

   102,996Other accounts payable

   106,097

   

   106,097Noncurrent liabilitiesLoans, Financings and Debentures

   871,987

   

   871,987Deferred taxes debits

   280,234

   

   295,745Other accounts payable

   56,406

   

   73,699Net assets acquired

   939,983

   

   952,800Goodwill arising on acquisitionConsideration transfered

   833,663

   

   833,663(+) Non-controlling interest

   106,320

   

   119,137(-) Fair value of identifiable net assets acquired

   939,983

   

   952,800Goodwill

   -

   

   -
  Reclassification of the comparative balances In conformity with the requirements of IFRS – Business Combination, the Company reclassified the comparative balances at December 31, 2014 as if the accounting of such business combination, considering the closing balances, had been completed at the acquisition date. The reclassifications made did not have material effect on the profit for the year ended December 31, 2014, as previously presented. The reclassifications made are summarized as follows:


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·Assets:  December 31, 2014

   

   Adjustments

   

   December 31, 2014 (reclassified)AssetsCurrent

   9,214,704

   

   -

   

   9,214,704Non currentOthers

   6,751,305

   

   -

   

   6,751,305Investment

   1,098,769

   

   -

   

   1,098,769Property, plant and equipment

   8,878,064

   

   271,422

   

   9,149,486Intangible

   9,155,973

   

   (225,802)

   

   8,930,171TOTAL

   35,098,816

   

   45,620

   

   35,144,436
  ·Liabilities:  December 31, 2014

   

   Adjustments

   

   December 31, 2014 (reclassified)LiabilitiesCurrent

   7,417,104

   

   -

   

   7,417,104Non currentProvisions for tax, civil and labor risks

   490,858

   

   17,293

   

   508,151Deferred taxes debits

   1,385,498

   

   15,511

   

   1,401,009Other accounts payable

   16,420,844

   

   -

   

   16,420,844Total non current

   18,297,200

   

   32,804

   

   18,330,004Net equity attributable to controlling shareholders

   6,943,535

   

   -

   

   6,943,535Net equity attributable to noncontrolling shareholders

   2,440,978

   

   12,816

   

   2,453,794Shareholders equity

   9,384,513

   

   12,816

   

   9,397,329TOTAL

   35,098,816

   

   45,620

   

   35,144,436
   ·Statement of profit or loss for the year: As mentioned previously in this note, the effects on the profit or loss for the year ended December 31, 2014 are immaterial for purposes of restatement of the comparative balances. These effects result from the difference between the period for amortization of the exploration rights intangible assets and the period for depreciation of fixed assets, both recorded as expenses in the statement of profit or loss for the year. b) Net cash inflow on the acquisition No cash payment was made, considering that the acquisition was made through exchange of shares, there was only the incorporation of the cash of WF2 in the amount of R$139,293. c) Financial information on net operating revenue and profit of the subsidiary acquired included in the consolidated financial statements in 2014  Net operating revenues

   

   Net income2014

   

   2014DESA consolidated - Oct 01, 2014 to Dec 31, 2014

   

   48,036

   

   1,880
   The Company's consolidated financial statements for the year ended December 31, 2014 include 3 (three) months of operations of DESA. d) Noncontrolling interests


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Noncontrolling interests, consisting of 40% interest held by third parties in Ludesa Energética S.A., WF2's subsidiary, totaling R$119,137, was recognized in the consolidated financial statements on the acquisition date, based on its fair value. This interest was appraised at fair value using the income approach method.  15.4.3 – Combined financial information on net operating revenue and profit (loss) for 2014 if the acquisitions had occurred on January 1, 2014  Net operating revenues

   

   Net income (loss)2014

   

   2014CPFL Energia - presented

   

   17,305,942

   

   886,443Pro-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 subsidiaries for the period in which they were not subsidiaries and consequently were not consolidated by the Company. The pro forma adjustments of the profit take into account: (i) addition of the profit or loss of subsidiaries Rosa dos Ventos and DESA for the period in which they were not consolidated by the Company; (ii) inclusion of amortization of the operation right, net of tax effects, if the acquisition had occurred on January 1, 2014; (iii) exclusion of the effects of non-recurring consultancy expenses for the association with WF2; and (iv) inclusion of the financial effects of the debentures issued by WF2 to acquire DESA’ non-controlling interests.  ( 16 )TRADE PAYABLES
  December 31, 2015

   

   December 31, 2014CurrentSystem service charges

   203,961

   

   -Energy purchased

   2,402,823

   

   1,895,742Electricity network usage charges

   106,940

   

   125,860Materials and services

   331,809

   

   250,416Free energy

   115,676

   

   102,129Total

   3,161,210

   

   2,374,147NoncurrentMaterials and services

   633

   

   633
   ( 17 )INTEREST ON DEBTS AND BORROWINGS
  December 31, 2015

   

   December 31, 2014Interest - Currentand noncurrent

   

   Principal

   

   Total

   

   Interest - Currentand noncurrent

   

   Principal

   

   TotalCurrent

   

   Noncurrent

   

   

   

   Current

   

   NoncurrentMeasured at costLocal currencyInvestment

   

   17,775

   

   693,058

   

   4,970,715

   

   5,681,549

   

   10,430

   

   617,951

   

   4,734,696

   

   5,363,077Rental assets

   

   17

   

   687

   

   3,434

   

   4,138

   

   14

   

   631

   

   3,649

   

   4,294Financial Institutions

   

   179,656

   

   382,411

   

   1,350,746

   

   1,912,812

   

   128,920

   

   241,552

   

   1,395,644

   

   1,766,116Others

   

   764

   

   134,960

   

   10,002

   

   145,726

   

   709

   

   108,918

   

   14,223

   

   123,851Total at Cost

   

   198,212

   

   1,211,115

   

   6,334,897

   

   7,744,225

   

   140,074

   

   969,053

   

   6,148,211

   

   7,257,338Measured at fair valueForeign currencyFinancial Institutions

   

   40,714

   

   1,651,199

   

   5,560,517

   

   7,252,430

   

   18,168

   

   125,511

   

   3,353,468

   

   3,497,147Mark to Market

   

   -

   

   (29,269)

   

   (282,980)

   

   (312,249)

   

   -

   

   155

   

   (56,153)

   

   (55,998)Total at fair value

   

   40,714

   

   1,621,930

   

   5,277,536

   

   6,940,180

   

   18,168

   

   125,667

   

   3,297,315

   

   3,441,149Borrowing costs

   

   -

   

   (1,391)

   

   (20,227)

   

   (21,618)

   

   -

   

   (1,219)

   

   (18,891)

   

   (20,110)Total

   

   238,926

   

   2,831,654

   

   11,592,206

   

   14,662,787

   

   158,241

   

   1,093,500

   

   9,426,634

   

   10,678,376


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Measured at amortized cost

   

   December 31, 2015

   

   December 31, 2014

   

   Annual interest

   

   Amortization

   

   CollateralLocal currencyInvestmentCPFL PaulistaFINEM V

   

   70,293

   

   103,617

   

   TJLP + 2.12% to 3.3% (c)

   

   72 monthly installments from February 2012

   

   CPFL Energia guarantee and receivablesFINEM V

   

   5,384

   

   7,130

   

   Fixed rate 8% (c)

   

   90 monthly installments from August 2011

   

   CPFL Energia guarantee and receivablesFINEM V

   

   38,386

   

   45,937

   

   Fixed rate 5.5% (b)

   

   96 monthly installments from February 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   197,145

   

   245,445

   

   TJLP + 2.06% to 3.08% (e) (f)

   

   72 monthly installments from January 2014

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   10,412

   

   11,917

   

   Fixed rate 2.5% (a)

   

   114 monthly installments from June 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   191,022

   

   218,640

   

   Fixed rate 2.5% (a)

   

   96 monthly installments from December 2014

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   63,777

   

   -

   

   Fixed rate 6% (b)

   

   96 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   65,304

   

   -

   

   SELIC + 2.62% to 2.66% (h)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   130,774

   

   -

   

   TJLP + 2.12% to 2.66% (c) (d)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINAME

   

   33,808

   

   42,260

   

   Fixed rate 4.5%

   

   96 monthly installments from January 2012

   

   CPFL Energia guaranteeCPFL PiratiningaFINEM IV

   

   37,859

   

   55,807

   

   TJLP + 2.12% to 3.3% (c)

   

   72 monthly installments from February 2012

   

   CPFL Energia guarantee and receivablesFINEM IV

   

   1,736

   

   2,299

   

   Fixed rate 8% (c)

   

   90 monthly installments from August 2011

   

   CPFL Energia guarantee and receivablesFINEM IV

   

   19,962

   

   23,889

   

   Fixed rate 5.5% (b)

   

   96 monthly installments from February 2013

   

   CPFL Energia guarantee and receivablesFINEM V

   

   57,621

   

   71,737

   

   TJLP + 2.06% to 3.08% (e) (f)

   

   72 monthly installments from January 2014

   

   CPFL Energia guarantee and receivablesFINEM V

   

   2,735

   

   3,130

   

   Fixed rate 2.5% (a)

   

   114 monthly installments from June 2013

   

   CPFL Energia guarantee and receivablesFINEM V

   

   47,536

   

   54,409

   

   Fixed rate 2.5% (a)

   

   96 monthly installments from December 2014

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   39,605

   

   -

   

   SELIC + 2.62% to 2.66% (h)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   69,054

   

   -

   

   TJLP + 2.12% to 2.66% (c) (d)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   30,463

   

   -

   

   Fixed rate 6% (b)

   

   96 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINAME

   

   16,031

   

   20,039

   

   Fixed rate 4.5%

   

   96 monthly installments from January 2012

   

   CPFL Energia guaranteeRGEFINEM V

   

   42,549

   

   62,721

   

   TJLP + 2.12% to 3.3% (c)

   

   72 monthly installments from February 2012

   

   CPFL Energia guarantee and receivablesFINEM V

   

   14,725

   

   17,622

   

   Fixed rate 5.5% (b)

   

   96 monthly installments from February 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   105,322

   

   131,125

   

   TJLP + 2.06% to 3.08% (e) (f)

   

   72 monthly installments from January 2014

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   1,102

   

   1,261

   

   Fixed rate 2.5% (a)

   

   114 monthly installments from June 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   70,240

   

   80,396

   

   Fixed rate 2.5% (a)

   

   96 monthly installments from December 2014

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   43,522

   

   -

   

   Fixed rate 6% (b)

   

   96 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   59,348

   

   -

   

   SELIC + 2.62% to 2.66% (h)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   76,728

   

   -

   

   TJLP + 2.12% to 2.66% (d)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINAME

   

   8,045

   

   10,056

   

   Fixed rate 4.5%

   

   96 monthly installments from January 2012

   

   CPFL Energia guaranteeFINAME

   

   227

   

   287

   

   Fixed rate 10.0%

   

   90 monthly installments from May 2012

   

   Liens on assetsFINAME

   

   715

   

   -

   

   Fixed rate 10.0%

   

   66 monthly installments from October 2015

   

   Liens on assetsCPFL Santa CruzBank credit note - Unibanco

   

   -

   

   929

   

   TJLP + 2.9%

   

   54 monthly installments from December 2010

   

   CPFL Energia guarantee and receivablesFINEM

   

   10,306

   

   11,317

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   3,663

   

   3,334

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   7,382

   

   7,596

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL Leste PaulistaBank credit note - Unibanco

   

   -

   

   1,286

   

   TJLP + 2.9%

   

   54 monthly installments from June 2011

   

   CPFL Energia guarantee and receivablesFINEM

   

   3,850

   

   2,904

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   1,343

   

   1,179

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   2,709

   

   2,685

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL Sul PaulistaBank credit note - Unibanco

   

   -

   

   1,393

   

   TJLP + 2.9%

   

   54 monthly installments from June 2011

   

   CPFL Energia guarantee and receivablesFINEM

   

   2,734

   

   1,968

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   1,876

   

   1,553

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   3,803

   

   3,545

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL JaguariBank credit note - Unibanco

   

   -

   

   455

   

   TJLP + 2.9%

   

   54 monthly installments from December 2010

   

   CPFL Energia guarantee and receivablesBank credit note - Santander

   

   1,710

   

   1,968

   

   TJLP + 3.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeBank credit note - Santander

   

   808

   

   635

   

   UMBNDES + 2.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeFINEM

   

   2,745

   

   2,775

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   1,394

   

   1,104

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   2,826

   

   2,516

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL MococaBank credit note - Unibanco

   

   -

   

   608

   

   TJLP + 2.9%

   

   54 monthly installments from January 2011

   

   CPFL Energia guarantee and receivablesBank credit note - Santander

   

   2,200

   

   2,532

   

   TJLP + 3.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeBank credit note - Santander

   

   1,039

   

   817

   

   UMBNDES + 2.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeBank credit note - Santander

   

   1,932

   

   1,250

   

   UMBNDES + 1.9%

   

   96 monthly installments from October 2015

   

   CPFL Energia guaranteeBank credit note - Santander

   

   4,619

   

   4,335

   

   TJLP + 2.99% (f)

   

   96 monthly installments from October 2015

   

   CPFL Energia guarantee


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CPFL ServiçosFINAME

   

   1,509

   

   1,675

   

   Fixed rate 2.5% to 5.5%

   

   96 monthly installments from August 2014

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   357

   

   357

   

   Fixed rate 6%

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   864

   

   1,272

   

   Fixed rate 6% to 10%

   

   90 monthly installments from November 2012

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   13,049

   

   14,806

   

   Fixed rate 2.5% to 5.5%

   

   114 monthly installments from February 2013

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   60

   

   74

   

   TJLP + 4.2%

   

   90 monthly installments from November 2012

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   2,659

   

   2,860

   

   Fixed rate 6%

   

   90 monthly installments from October 2014

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   108

   

   108

   

   Fixed rate 6%

   

   96 monthly installments from June 2016

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   6,496

   

   6,909

   

   Fixed rate 6%

   

   114 monthly installments from June 2015

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   1,002

   

   -

   

   TJLP + 2.2% to 3.2% (c)

   

   56 monthly installments from July 2015

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   4,006

   

   -

   

   Fixed rate 9.5% to 10% (c)

   

   66 monthly installments from October 2015

   

   CPFL Energia guarantee and liens on equipmentCERANBNDES

   

   312,150

   

   360,217

   

   TJLP + 3.69% to 5%

   

   168 monthly installments from December 2005

   

   Pledge of shares, credit and concession rights, revenues and CPFL Energia guaranteeBNDES

   

   68,993

   

   54,604

   

   UMBNDES + 5% (1)

   

   168 monthly installments from February 2006

   

   Pledge of shares, credit and concession rights, revenues and CPFL Energia guaranteeCPFL TransmissãoFINAME

   

   19,466

   

   17,736

   

   Fixed rate 3.0%

   

   96 monthly installments from July 2015

   

   CPFL Energia guaranteeCPFL TelecomFINAME

   

   7,610

   

   7,588

   

   Fixed rate 6.0% (b)

   

   60 monthly installments from December 2016

   

   CPFL Energia guaranteeFINEM

   

   7,018

   

   6,187

   

   SELIC + 3.12% (h)

   

   60 monthly installments from December 2016

   

   CPFL Energia guaranteeFINEM

   

   21,544

   

   21,349

   

   TJLP + 2.12% to 3.12% (c)

   

   60 monthly installments from December 2016

   

   CPFL Energia guaranteeCPFL RenováveisFINEM I

   

   290,445

   

   321,088

   

   TJLP + 1.95%

   

   168 monthly installments from October 2009

   

   PCH Holding a joint and several debtor, letters of guaranteeFINEM II

   

   25,308

   

   28,605

   

   TJLP + 1.90%.

   

   144 monthly installments from June 2011

   

   CPFL Energia guarantee, liens on assets and assignment of credit rightsFINEM III

   

   528,528

   

   565,890

   

   TJLP + 1.72%

   

   192 monthly installments from May 2013

   

   CPFL Energia guarantee, plegde of shares, liens on assets, assignment of credit rightsFINEM V

   

   90,678

   

   101,723

   

   TJLP + 2.8% to 3.4%

   

   143 monthly installments from December 2011

   

   PCH Holding 2 and CPFL Renováveis as joint and several debtors.FINEM VI

   

   79,457

   

   84,176

   

   TJLP + 2.05%

   

   192 monthly installments from October 2013

   

   Pledge of CPFL Renováveis shares, assignment of receivablesFINEM VII

   

   156,737

   

   176,252

   

   TJLP + 1.92 %

   

   156 monthly installments from October 2010

   

   Pledge of shares, assignment of rights, liens on machinery and equipmentFINEM IX

   

   32,289

   

   39,581

   

   TJLP + 2.15%

   

   120 monthly installments from May 2010

   

   Pledge of shares of subsidiary and liens on machinery and equipmentFINEM X

   

   528

   

   827

   

   TJLP

   

   84 monthly installments from October 2010

   

   Pledge of shares, assignment of rights, liens on machinery and equipmentFINEM XI

   

   115,676

   

   126,670

   

   TJLP + 1.87% to 1.9%

   

   168 monthly installments from January 2012

   

   CPFL Energia guarantee, pledge of shares, liens on assets, assignment of credit rightsFINEM XII

   

   335,894

   

   357,620

   

   TJLP + 2.18%

   

   192 monthly installments from July 2014

   

   CPFL Energia guarantee, liens on assets, joint assignment of credit rights, pledge of sharesFINEM XIII

   

   296,891

   

   315,596

   

   TJLP + 2.02% to 2.18%

   

   192 monthly installments from November 2014

   

   Pledge of shares and machinery and equipment of SPE , assignment of rightsFINEM XIV

   

   11,599

   

   19,707

   

   TJLP + 3.50%

   

   120 monthly installments from June 2007

   

   Liens on machinery and equipment , assignment of receivables, pledge of grantor rights - ANEEL, pledge of sharesFINEM XV

   

   31,227

   

   35,392

   

   TJLP + 3.44%

   

   139 monthly installments from September 2011

   

   Assignment of receivables, pledge of grantor rigths - ANEEL, pledge of sharesFINEM XVI

   

   8,500

   

   10,581

   

   Fixed rate 5.50%

   

   101 monthly installments from September 2011

   

   Assignment of receivables, pledge of grantor rights - ANEEL, pledge of sharesFINEM XVII

   

   490,786

   

   525,541

   

   TJLP + 2.18%

   

   192 monthly installments from January 2013

   

   Liens on machinery and equipment, assignment of receivables, pledge of grantor rights - ANEEL, pledge of shares and reserve accountFINEM XVIII

   

   18,481

   

   23,200

   

   Fixed rate 4.5%

   

   102 monthly installments from June 2011

   

   CPFL Energia guarantee, liens on assets , assignment of credit rightsFINEM XIX

   

   31,381

   

   33,488

   

   TJLP + 2.02%

   

   192 monthly installments from January 2014

   

   CPFL Energia guarantee, liens on assets, joint assignment of credit rights, pledge of sharesFINEM XX

   

   52,091

   

   59,533

   

   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 receivablesFINEM XXI

   

   42,765

   

   45,636

   

   TJLP + 2.02%

   

   192 monthly installments from January 2014

   

   CPFL Energia guarantee, liens on assets, joint assignment of credit rights, pledge of sharesFINEM XXII

   

   45,828

   

   52,375

   

   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 receivablesFINEM XXIII

   

   2,305

   

   2,882

   

   Fixed rate 4.5%

   

   102 monthly installments from June 2011

   

   CPFL Energia guarantee, liens on assets , assignment of credit rightsFINEM XXIV

   

   136,528

   

   163,476

   

   Fixed rate 5.5%

   

   108 monthly installments from January 2012

   

   CPFL Energia guarantee, liens on assets, joint assignment of credit rightsFINEM XXV

   

   79,010

   

   -

   

   TJLP + 2.18%

   

   192 monthly installments from June 2015

   

   Pledge of shares and grantor rights, liens on assets and assignment of credit rightsFINEM XXVI

   

   270,768

   

   -

   

   TJLP + 2.75%

   

   192 monthly installments from July 2017

   

   Pledge of shares and grantor rights, liens on assets, assignment of credit rights and reserve accountFINAME IV

   

   3,327

   

   3,773

   

   Fixed rate 2.5%

   

   96 monthly installments from February 2015

   

   Pledge of CPFL Renováveis shares,pledge of shares and reserve account of SPE, assignment of receivablesFINEP I

   

   1,890

   

   2,382

   

   Fixed rate 3.5%

   

   61 monthly installments from October 2014

   

   Bank guaranteeFINEP II

   

   10,383

   

   10,366

   

   TJLP - 1.00%

   

   85 monthly installments from June 2017

   

   GuaranteeFINEP III

   

   6,374

   

   6,945

   

   TJLP + 3.00%

   

   73 monthly installments from July 2015

   

   GuaranteeBNB I

   

   108,835

   

   117,516

   

   Fixed rate 9.5% to 10%

   

   168 monthly installments from January 2009

   

   LiensBNB II

   

   165,324

   

   172,430

   

   Fixed rate 10% (J)

   

   222 monthly installments from May 2010

   

   CPFL Energia guaranteeBNB III

   

   30,837

   

   32,591

   

   Fixed rate 9.5%

   

   228 monthly installments from July 2009

   

   Guarantee, liens on assets, assignment of credit rightsNIB

   

   72,739

   

   74,197

   

   IGPM + 8.63%

   

   50 quarterly installments from June 2011

   

   No guaranteeBridge BNDES IV

   

   -

   

   49,492

   

   TJLP + 2.40%

   

   1 installment in January 2016

   

   GuaranteeBanco do Brasil

   

   31,014

   

   36,739

   

   Fixed rate 10.00%

   

   132 monthly installment from June 2010

   

   Shareholders support, pledge of shares and grantor rights, assignment of receivables, performance bond, guarantee and civil liabilityCPFL BrasilFINEP

   

   1,864

   

   2,657

   

   Fixed rate 5%

   

   81 monthly installments from August 2011

   

   Receivables


F - 46

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|Table of Contents
|-----------------

Purchase of assetsCPFL ESCOFINAME

   

   3,544

   

   4,135

   

   Fixed rate 4.5% to 8.7%

   

   96 monthly installments from March 2012

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   117

   

   158

   

   Fixed rate 6%

   

   72 monthly installments from October 2016

   

   CPFL Energia guaranteeFINAME

   

   261

   

   -

   

   TJLP + 2.70%

   

   48 monthly installments from October 2016

   

   CPFL Energia guaranteeFINAME

   

   216

   

   -

   

   SELIC + 2.70%

   

   48 monthly installments from October 2016

   

   CPFL Energia guaranteeFinancial institutionsCPFL EnergiaSantander - working capital

   

   331,343

   

   -

   

   86.40% of CDI

   

   1 installment in January 2016

   

   No guaranteeCPFL PaulistaBanco do Brasil - Working capital

   

   -

   

   105,500

   

   107% of CDI

   

   1 installment in April 2015

   

   CPFL Energia guaranteeBanco do Brasil - Working capital

   

   -

   

   73,758

   

   98.50% of CDI (f)

   

   4 annual installments from July 2012

   

   CPFL Energia guaranteeBanco do Brasil - Working capital

   

   331,549

   

   291,036

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeCPFL PiratiningaBanco do Brasil - Working capital

   

   -

   

   6,784

   

   98.50% of CDI (f)

   

   4 annual installments from July 2012

   

   CPFL Energia guaranteeBanco do Brasil - Working capital

   

   58,353

   

   51,222

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeRGEBanco do Brasil - Working capital

   

   -

   

   31,894

   

   98.50% of CDI (f)

   

   4 annual installments from July 2012

   

   CPFL Energia guaranteeCPFL Santa CruzBanco do Brasil - Working capital

   

   43,764

   

   38,417

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   7,637

   

   8,083

   

   CDI + 0.27% (f)

   

   12 semiannual installments from June 2015

   

   CPFL Energia guaranteeCPFL Leste PaulistaBanco IBM - Working capital

   

   6,587

   

   7,419

   

   100.0% of CDI

   

   14 semiannual installments from December 2012

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   23,790

   

   25,666

   

   CDI + 0.1%

   

   12 semiannual installments from October 2014

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   17,268

   

   7,969

   

   CDI + 0.27%

   

   12 semiannual installments from March 2015

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   8,052

   

   10,307

   

   CDI + 0.27% to 1.33 (f)

   

   12 semiannual installments from June 2015

   

   CPFL Energia guaranteeCPFL Sul PaulistaBanco do Brasil - Working capital

   

   27,850

   

   24,447

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   8,914

   

   4,036

   

   CDI + 0.27% to 1.33 (f)

   

   12 semiannual installments from June 2015

   

   CPFL Energia guaranteeCPFL JaguariBanco do Brasil - Working capital

   

   3,846

   

   3,376

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   13,266

   

   15,064

   

   100.0% of CDI

   

   14 semiannual installments from December 2012

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   12,825

   

   13,836

   

   CDI + 0.1%

   

   12 semiannual installments from October 2014

   

   CPFL Energia guaranteeCPFL MococaBanco do Brasil - Working capital

   

   25,198

   

   22,119

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   4,305

   

   4,888

   

   100.0% of CDI

   

   14 semiannual installments from December 2012

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   14,663

   

   15,519

   

   CDI + 0.27%

   

   12 semiannual installments from March 2015

   

   CPFL Energia guaranteeCPFL ServiçosBanco IBM - Working capital

   

   5,111

   

   6,316

   

   CDI + 0.10%

   

   11 semiannual installments from June 2013

   

   CPFL Energia guaranteeCPFL GeraçãoBanco do Brasil - Working capital

   

   642,124

   

   637,635

   

   109.5% of CDI

   

   1 installment in March 2019

   

   CPFL Energia guaranteeCPFL RenováveisHSBC

   

   290,679

   

   322,336

   

   CDI + 0.5% (i)

   

   8 annual installment from June 2013

   

   Pledge of sharesCPFL TelecomBanco IBM - Working capital

   

   35,689

   

   38,489

   

   CDI + 0.18%

   

   12 semiannual installments from August 2014

   

   CPFL Energia guaranteeOthersEletrobrásCPFL Paulista

   

   3,931

   

   5,414

   

   RGR + 6% to 6.5%

   

   monthly installments from August 2006

   

   Receivables and promissory notesCPFL Piratininga

   

   88

   

   239

   

   RGR + 6%

   

   monthly installments from August 2006

   

   Receivables and promissory notesRGE

   

   7,658

   

   9,746

   

   RGR + 6%

   

   monthly installments from August 2006

   

   Receivables and promissory notesCPFL Santa Cruz

   

   1,029

   

   1,601

   

   RGR + 6%

   

   monthly installments from January 2007

   

   Receivables and promissory notesCPFL Leste Paulista

   

   532

   

   747

   

   RGR + 6%

   

   monthly installments from February 2008

   

   Receivables and promissory notesCPFL Sul Paulista

   

   544

   

   808

   

   RGR + 6%

   

   monthly installments from August 2007

   

   Receivables and promissory notesCPFL Jaguari

   

   24

   

   41

   

   RGR + 6%

   

   monthly installments from June 2007

   

   Receivables and promissory notesCPFL Mococa

   

   170

   

   222

   

   RGR + 6%

   

   monthly installments from January 2008

   

   Receivables and promissory notesOther

   

   131,751

   

   105,034Subtotal local currency - Cost

   

   7,744,225

   

   7,257,338


F - 47

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|Table of Contents
|-----------------

Foreign CurrencyMeasured at fair valueFinancial InstitutionsCPFL EnergiaSantander

   

   293,660

   

   -

   

   US$ + 1.547% (3)

   

   1 installment in February 2016

   

   No guaranteeBradesco

   

   154,665

   

   -

   

   US$ + 1.72% (2) (f)

   

   1 installment in June 2016

   

   No guaranteeSantander

   

   197,044

   

   -

   

   US$ + 1.918% (3)

   

   1 installment in September 2016

   

   No guaranteeCPFL PaulistaBank of America Merrill Lynch

   

   397,324

   

   270,248

   

   US$ + 3.69 % (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesBank of America Merrill Lynch

   

   -

   

   399,887

   

   US$ + Libor 3 months + 1.48% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesBank of America Merrill Lynch

   

   175,750

   

   119,561

   

   US$+Libor 3 months+1.70% (4)

   

   1 installment in September 2018

   

   CPFL Energia guarantee and promissory notesBank of Tokyo-Mitsubishi

   

   195,524

   

   -

   

   US$+Libor 3 months+0.88% (3)(g)

   

   1 installment in February 2020

   

   CPFL Energia guarantee and promissory notesBank of Tokyo-Mitsubishi

   

   195,380

   

   132,887

   

   US$+Libor 3 months+0.80% (3)(f)

   

   4 semiannual installments from September 2017

   

   CPFL Energia guarantee and promissory notesBNP Paribas

   

   85,991

   

   -

   

   Euro + 1.6350% (3)

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   -

   

   133,585

   

   US$+Libor 6 months+1.77% (3)

   

   1 installment in September 2016

   

   CPFL Energia guarantee and promissory notesCitibank

   

   195,502

   

   132,962

   

   US$+Libor 3 months + 1.35% (4)

   

   1 installment in March 2019

   

   CPFL Energia guarantee and promissory notesCitibank

   

   227,397

   

   -

   

   US$ + Libor 3 months + 1.44% (3)

   

   1 installment in January 2020

   

   CPFL Energia guarantee and promissory notesHSBC

   

   338,504

   

   -

   

   US$ + Libor 3 months + 1.30% (3)

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   156,381

   

   106,383

   

   US$ + 2.28% to 2.32% (3)

   

   1 installment in December 2017

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   138,255

   

   -

   

   US$ + 2.36% to 2.39% (3)

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   98,891

   

   -

   

   US$ + 2.74% (3)

   

   1 installment in January 2019

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   59,080

   

   -

   

   US$ + 2.2% (3)

   

   1 installment in February 2018

   

   CPFL Energia guarantee and promissory notesMerrill Lynch

   

   587,094

   

   -

   

   US$ + Libor 3 months + 1.40% (3)

   

   1 installment in February 2018

   

   CPFL Energia guarantee and promissory notesMizuho Bank

   

   292,895

   

   199,235

   

   US$+Libor 3 months+1.55% (3)(f)

   

   3 semiannual installments from March 2018

   

   CPFL Energia guarantee and promissory notesMorgan Stanley

   

   196,502

   

   133,601

   

   US$ + Libor 6 months + 1.75% (3)

   

   1 installment in September 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   95,502

   

   64,958

   

   US$ + 3.3125% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesCPFL PiratiningaBank of America Merrill Lynch

   

   48,964

   

   -

   

   US$ + Libor 3 months + 1.15% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesBank of America Merrill Lynch

   

   97,849

   

   -

   

   US$ + Libor 3 months + 1.15% (3)

   

   1 installment in August 2016

   

   CPFL Energia guarantee and promissory notesBNP Paribas

   

   236,474

   

   -

   

   Euro + 1.6350% (3)

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   244,778

   

   -

   

   US$+Libor 3 months+1.41% (3)

   

   2 annual installments from January 2019

   

   CPFL Energia guarantee and promissory notesCitibank

   

   -

   

   21,401

   

   US$ + Libor 6 months + 1.69%(3)

   

   1 installment in August 2016

   

   CPFL Energia guarantee and promissory notesCitibank

   

   -

   

   167,050

   

   US$ + Libor 6 months + 1.14% (3)

   

   1 installment in January 2017

   

   CPFL Energia guarantee and promissory notesCitibank

   

   195,502

   

   132,962

   

   US$ + Libor 3 months + 1.35% (4)

   

   1 installment in March 2019

   

   CPFL Energia guarantee and promissory notesSantander

   

   177,268

   

   120,585

   

   US$ + 2.58% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   124,737

   

   84,843

   

   US$ + 3.3125% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   64,980

   

   -

   

   US$ + 2.08% (3)

   

   1 installment in August 2017

   

   CPFL Energia guarantee and promissory notesSumitomo

   

   195,938

   

   133,259

   

   US$+Libor 3 months+1.35% (3)(f)

   

   1 installment in April 2018

   

   CPFL Energia guarantee and promissory notesRGEBank of Tokyo-Mitsubishi

   

   70,439

   

   47,908

   

   US$ + Libor 3 months + 0.82%(3)

   

   1 installment in April 2018

   

   CPFL Energia guarantee and promissory notesBank of Tokyo-Mitsubishi

   

   320,602

   

   218,046

   

   US$ + Libor 3 months + 0.83%(3)

   

   1 installment in May 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   58,683

   

   39,912

   

   US$ + Libor 3 months + 1.25%(4)

   

   2 annual installments from May 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   274,426

   

   186,593

   

   US$+Libor 6 months+1.45% (3)

   

   1 installment in April 2017

   

   CPFL Energia guarantee and promissory notesHSBC

   

   53,260

   

   36,223

   

   US$ + Libor 3 months + 1.30% (4)

   

   1 installment in October 2017

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   239,453

   

   -

   

   US$ + 2.78% (3)

   

   1 installment in February 2018

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   139,466

   

   -

   

   US$ + 1.35% (3)

   

   1 installment in February 2016

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   -

   

   126,126

   

   US$ + 2.64% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesCPFL Santa CruzJ.P. Morgan

   

   -

   

   25,864

   

   US$ + 2.38% (3)

   

   1 installment in July 2015

   

   CPFL Energia guarantee and promissory notesSantander

   

   34,679

   

   23,590

   

   USD + 2.544% (3)

   

   1 installment in June 2016

   

   CPFL Energia guarantee and promissory notesCPFL Leste PaulistaScotiabank

   

   -

   

   32,926

   

   US$ + 2.695% (3)

   

   1 installment in July 2015

   

   CPFL Energia guarantee and promissory notesCPFL Sul PaulistaJ.P. Morgan

   

   -

   

   13,578

   

   US$ + 2.38% (3)

   

   1 installment in July 2015

   

   CPFL Energia guarantee and promissory notesSantander

   

   38,147

   

   25,949

   

   USD + 2.544% (3)

   

   1 installment in June 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   -

   

   13,829

   

   US$ + 2.695% (3)

   

   1 installment in July 2015

   

   CPFL Energia guarantee and promissory notesCPFL JaguariSantander

   

   53,752

   

   36,564

   

   USD + 2.544% (3)

   

   1 installment in June 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   -

   

   17,122

   

   US$ + 2.695% (3)

   

   1 installment in July 2015

   

   CPFL Energia guarantee and promissory notesCPFL MococaScotiabank

   

   -

   

   14,488

   

   US$ + 2.695% (3)

   

   1 installment in July 2015

   

   CPFL Energia guarantee and promissory notesCPFL GeraçãoHSBC

   

   390,757

   

   265,779

   

   US$+Libor 3 months + 1.30% (3)

   

   1 installment in March 2017

   

   CPFL Energia guarantee and promissory notesCPFL ServiçosJ.P. Morgan

   

   14,760

   

   10,040

   

   US$ + 1.75% (3)

   

   1 installment in October 2016

   

   CPFL Energia guarantee and promissory notesCPFL TelecomBanco Itaú

   

   -

   

   9,202

   

   US$ + 2.35% (3)

   

   1 installment in November 2015

   

   CPFL Energia guarantee and promissory notesPaulista LajeadoBanco Itaú

   

   42,862

   

   -

   

   US$ + 3.196% (4)

   

   1 installment in March 2018

   

   CPFL Energia guarantee and promissory notesCPFL BrasilScotiabank

   

   53,317

   

   -

   

   US$ + 2.779% (3)

   

   1 installment in August 2018

   

   CPFL Energia guarantee and promissory notesMark to market

   

   (312,249)

   

   (55,998)Total Foreign Currency - fair value

   6,940,180

   

   3,441,149Borrowing costs (*)

   

   (21,618)

   

   (20,110)Total - Consolidated

   

   14,662,787

   

   10,678,376The subsidiaries hold swaps converting the operating cost of currency variation to interest tax variation in reais. corresponding to :(1) 143.85% of CDI

   

   (2) 95.2% of CDI

   

   

   

   (3) 99% to 109% of CDI

   

   (4) 109.1% to 119% of CDIEffective rate:(a) 30% to 40% of CDI

   

   (c) 60.1% to 70% of CDI

   

   (e) 80.1% to 90% of CDI

   

   (g) 110.1% to 120% of CDI

   

   (i) CDI + 0.73%(b) 40.1% to 50% of CDI

   

   (d) 70.1% to 80% of CDI

   

   (f) 100.1% to 120% of CDI

   

   (h) 120.1% to 130% of CDI

   

   (J) Fixed rate 10.57%
  (*) In accordance with IAS 39, this refers to the fundraising costs attributable to issuance of the respective debts.


F - 48

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In conformity with IAS 32 and 39, the Company and its subsidiaries classified their debts 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 as financial liabilities of borrowings measured at fair value is to compare the effects of recognition of income and expense derived from marking derivatives to market, tied to the borrowings, in order to obtain more relevant and consistent accounting information. At December 31, 2015, the total balance of the borrowings measured at fair value was R$ 6,940,180 (R$ 3,441,149 as of December 31, 2014). Changes in the fair values of these borrowings are recognized in the finance income/cost of the subsidiaries. Accumulated gains of R$ 312,249 (R$ 55,998 at December 31, 2014) on marking the borrowings to market, less losses of R$ 184,518 (R$25,382 at December 31, 2014) of marking to market the derivative financial instruments contracted as a hedge against foreign exchange variations (note 35), resulted in a total net gain of R$ 127,731 (R$30,616 at December 31, 2014). The maturities of the principal of borrowings are scheduled as follows: 2017

   1,892,9912018

   4,289,5642019

   2,284,5352020

   1,067,0282021

   490,8092022 to 2026

   1,326,0762027 to 2031

   505,8562032 to 2036

   18,328Subtotal

   11,875,186Mark to Market

   (282,980)Total

   11,592,206
  The main indexes used for adjusting borrowings for inflation and the indebtedness profile in local and foreign currency, already considering the effects of the derivative instruments, are as follows:  Accumulated variation

   

   % of debtIndex

   

   December 31, 2015

   

   December 31, 2014

   

   December 31, 2015

   

   December 31, 2014IGP-M

   

   10.54

   

   3.69

   

   0.50

   

   0.69UMBND

   

   47.00

   

   13.27

   

   0.49

   

   0.53TJLP

   

   6.21

   

   5.00

   

   27.67

   

   36.50CDI

   

   13.18

   

   10.81

   

   61.60

   

   49.26Others

   

   

   

   

   

   9.74

   

   13.01100.00

   

   100.00


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Main borrowings in the year:  R$ thousandCompany

   

   Bank / credit line

   

   Total approved

   

   Released in 2015

   

   Released net of fundraising costs

   

   Interest

   

   UtilizationLocal currency:Investment:CPFL Paulista

   

   FINEM VII

   

   427,716

   

   254,119

   

   253,161

   

   Quarterly

   

   Subsidiary's investment planCPFL Piratininga

   

   FINEM VI

   

   194,862

   

   135,259

   

   134,625

   

   Quarterly

   

   Subsidiary's investment planRGE

   

   FINEM VII

   

   266,790

   

   174,518

   

   173,789

   

   Quarterly

   

   Subsidiary's investment planCPFL Santa Cruz

   

   FINEM (a)

   

   25,360

   

   1,264

   

   1,264

   

   Quarterly

   

   Subsidiary's investment planCPFL Leste Paulista

   

   FINEM (a)

   

   13,045

   

   1,915

   

   1,915

   

   Quarterly

   

   Subsidiary's investment planCPFL Sul Paulista

   

   FINEM (a)

   

   12,280

   

   2,187

   

   2,187

   

   Quarterly

   

   Subsidiary's investment planCPFL Jaguari

   

   FINEM (a)

   

   10,398

   

   1,274

   

   1,274

   

   Quarterly

   

   Subsidiary's investment planCPFL Mococa

   

   Bank credit notes - Santander (a)

   

   6,119

   

   516

   

   516

   

   Quarterly

   

   Subsidiary's investment planRGE

   

   FINAME (a)

   

   746

   

   746

   

   746

   

   Quarterly

   

   Subsidiary's investment planCPFL Serviços

   

   FINAME (a)

   

   6,011

   

   5,144

   

   5,144

   

   Quarterly

   

   Purchase of vehicles and equipmentCPFL Transmissão Piracicaba

   

   FINAME (a)

   

   23,824

   

   3,020

   

   3,020

   

   Quarterly

   

   Purchase of vehicles and equipmentCPFL ESCO

   

   FINAME (a)

   

   461

   

   461

   

   461

   

   Quarterly

   

   Acquisition of electrical equipment and vehiculesCPFL Renováveis

   

   FINEM XXV

   

   84,338

   

   75,732

   

   75,732

   

   Monthly

   

   Subsidiary's investment planCPFL Renováveis

   

   FINEM XXVI

   

   764,109

   

   270,642

   

   268,117

   

   Monthly

   

   Subsidiary's investment planFinancial institutions:CPFL Energia

   

   Working capital - Bank credit notes - Santander (a)

   

   300,000

   

   300,000

   

   294,383

   

   With the principal

   

   Working capital improvementCPFL Leste Paulista

   

   Working capital - Bank credit notes - Banco IBM (a)

   

   7,563

   

   7,563

   

   7,563

   

   Semiannual

   

   Working capital improvementCPFL Sul Paulista

   

   Working capital - Bank credit notes - Banco do Brasil (a)

   

   4,791

   

   4,791

   

   4,791

   

   Semiannual

   

   Working capital improvementCPFL Renováveis

   

   Votorantim - Promissory notes (a)

   

   50,000

   

   50,000

   

   50,000

   

   With the principal

   

   Subsidiary's investment plan (SHPs)2,197,667

   

   1,288,405

   

   1,277,941(a) The agreement has no restrictive covenants.R$ thousandCompany

   

   Bank / credit line

   

   Total approved

   

   Released in 2015

   

   Released net of fundraising costs

   

   Interest

   

   Destination of the resourcesForeign currency:Financial institutions:CPFL Energia

   

   Bank credit notes - Banco Santander (a)

   

   200,000

   

   200,000

   

   200,000

   

   With the principal

   

   Extend the debt profileCPFL Energia

   

   FRN - Banco Santander (a)

   

   187,750

   

   187,750

   

   187,750

   

   With the principal

   

   Working capital improvementCPFL Energia

   

   Working capital - Law 4131 - Bradesco (a)

   

   149,208

   

   149,208

   

   147,865

   

   With the principal

   

   Working capital improvementCPFL Paulista

   

   Working capital - Law 4131 - Bank of Tokyo-Mitsubishi

   

   142,735

   

   142,735

   

   141,308

   

   Quarterly

   

   Working capital improvementCPFL Paulista

   

   Working capital - Law 4131 - BNP Paribas

   

   63,896

   

   63,896

   

   63,896

   

   Semiannual

   

   Working capital improvementCPFL Paulista

   

   Working capital - Law 4131 - Citibank

   

   156,600

   

   156,600

   

   156,600

   

   Quarterly

   

   Working capital improvementCPFL Paulista

   

   Working capital - Law 4131 - HSBC Bank

   

   227,673

   

   227,673

   

   227,673

   

   Quarterly

   

   Working capital improvementCPFL Paulista

   

   Working capital - Law 4131 - JP Morgan

   

   203,771

   

   203,771

   

   203,771

   

   Semiannual

   

   Working capital improvementCPFL Paulista

   

   Working capital - Law 4131 - Bank of America Merrill Lynch

   

   405,300

   

   405,300

   

   405,300

   

   Quarterly

   

   Working capital improvementCPFL Piratininga

   

   Working capital - Law 4131 - BNP Paribas

   

   175,714

   

   175,714

   

   175,714

   

   Semiannual

   

   Working capital improvementCPFL Piratininga

   

   Working capital - Law 4131 - Citibank

   

   169,837

   

   169,837

   

   169,837

   

   Quarterly

   

   Working capital improvementCPFL Piratininga

   

   Working capital - Law 4131 - Scotiabank

   

   55,440

   

   55,440

   

   55,440

   

   Semiannual

   

   Working capital improvementCPFL Piratininga

   

   Working capital - Law 4131 - Bank of America Merrill Lynch (a)

   

   124,250

   

   124,250

   

   124,250

   

   Quarterly

   

   Working capital improvementRGE

   

   Working capital - Law 4131 - JP Morgan

   

   171,949

   

   171,949

   

   171,949

   

   Semiannual

   

   Working capital improvementRGE

   

   Working capital - Law 4131 - JP Morgan (a)

   

   100,000

   

   100,000

   

   100,000

   

   Semiannual

   

   Working capital improvementCPFL Brasil

   

   Working capital - Law 4131 - Scotiabank

   

   45,360

   

   45,360

   

   45,360

   

   Semiannual

   

   Working capital improvementPaulista Lajeado

   

   Bank credit notes - Banco Itaú (a)

   

   35,000

   

   35,000

   

   35,000

   

   Semiannual

   

   Working capital improvement2,614,482

   

   2,614,482

   

   2,611,7124,812,149

   

   3,902,887

   

   3,889,653(a) The agreement has no restrictive covenants.
  RESTRICTIVE COVENANTS BNDES: Borrowings from the BNDES restrict the subsidiaries CPFL Paulista, CPFL Piratininga, RGE, Ceran and CPFL Telecom to: (i) not paying dividends and interest on capital totaling more than the minimum mandatory dividend laid down by law without after fulfillment of all 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 ratios: ·Net indebtedness divided by EBITDA – maximum of 3.5; ·Net indebtedness divided by the sum of net indebtedness and Equity – maximum of 0.90. CPFL Geração The borrowings from theBNDES raised by the indirect subsidiary CERANestablish: ·Maintaining the debt service coverage ratio at 1.3 during the amortization period;


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·Restrictions on the payment of dividends to the subsidiary CPFL Geração above the minimum mandatory dividend of 25% without the prior approval of the BNDES. CPFL Telecom Maintaining, by the Company, the following ratios: ·Equity / (Equity + Net Bank Debt) of more than 0.28; ·Net Bank Debt / Adjusted EBITDA of less than 3.75.  CPFL Renováveis (calculated in indirect subsidiary CPFL Renováveis and its subsidiaries, except when mentioned in each specific item): FINEM I and FINEM VI ·Maintaining the debt service coverage ratio (cash balance for the prior 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 2015 and 2014, the subsidiary obtained a waiver from the BNDES for determination of the debt service coverage ratio for FINEM VI for the years ended December 31, 2015 and 2014, respectively. FINEM II and FINEM XVIII ·Restrictions on the payments of dividends if a debt service coverage ratio of 1.0 or more and a general indebtedness ratio of 0.8 or less are not achieved. FINEM III ·Maintaining Equity/(Equity + Net Bank Debt) ratio 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. FINEM V ·Maintaining the debt service coverage ratio at 1.2; ·Maintaining the own capitalization ratio at 30% or more. In December 2014, the subsidiary obtained a waiver from Banco do Brasil for determination of the debt service coverage for the year ended December 31, 2014. FINEM VII, FINEM X and FINEM XXIII ·Maintaining the annual debt service coverage ratio at 1.2; ·Distribution of dividends limited to the Total Liabilities/ ex-Dividend Equity ratio of less than 2.33. FINEM IX, FINEM XIII and FINEM XXV ·Maintaining the Debt Service Coverage Ratio at 1.3 or more. FINEM XXVI ·Maintaining the Debt Service Coverage Ratio of the SPEs at 1.3 or more during the effective period of the agreement; ·Maintaining the consolidated Debt Service Coverage Ratio at 1.3, or more, determined in the annual consolidated financial statements of the subsidiary Turbina 16 (“T-16”), during the effective period of the agreement. FINEM XI and FINEM XXIV ·Maintaining a Net Bank Debt/EBITDA ratio of 3.75 or less, determined in the Company's annual consolidated financial statements. FINEM XII


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·Maintaining the Debt Service Coverage Ratio of the indirect subsidiaries Campo dos Ventos II Energias Renováveis S.A., SPE Macacos Energia S.A., SPE Costa Branca Energia S.A., SPE Juremas Energia S.A. and SPE Pedra Preta Energia S.A. 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, defined by Equity/Total Assets ratio, at 30% or more of the project’s total investment, and a debt service coverage ratio at 1.3 or more during the amortization period. In June 2015, the Company obtained from the Brazilian Development Bank (BNDES) waiver of its obligation to calculate the two ratios above in relation to the six months period ended June 30, 2015. FINEM XV and FINEM XVI ·Maintaining the quarterly equity ratio at 25% or more, defined by the ratio of Equity to Total Assets; ·Maintaining the quarterly debt service coverage ratio at 1.2 or more during the amortization period. FINEM XVII ·Maintaining the debt service coverage ratio at 1.2 or more during the amortization period; ·Maintaining the annual consolidated debt service coverage ratio at 1.3 or more, determined in the consolidated financial statements of Desa Eólicas S.A. FINEM XIX, FINEM XX, FINEM XXI and FINEM XXII ·Maintenance of Debt Service Coverage Ratio of 1.2 or more during the effective period of the agreement; ·Maintenance of Net Debt/EBITDA ratio of 6.0 or less in 2014, 5.6 in 2015, 4.6 in 2016 and 3.75 in 2017 and thereafter, determined in the consolidated financial statements of CPFL Renováveis during the effective period of the agreement; ·Maintenance of an Equity/(Equity + Net Debt) ratio of 0.41 or more from 2014 to 2016 and 0.45 in 2017 and thereafter, determined in the consolidated financial statements of CPFL Renováveis, during the effective period of the agreement. In December 2014, the Company obtained a waiver from the BNDES for calculation of the debt service coverage ratio and the Net Debt/EBITDA ratio, fulfillment mandatory for the parent company for the year ended December 31, 2014. In December 2015, the Company obtained waiver from the BNDES involving the latter’s concurrence with non-fulfillment of the debt service coverage ratio without acceleration of maturity of the debt being declared in relation to the year ended December 31, 2015. HSBC ·From 2014, there is the obligation to maintain the Net Debt/ EBITDA ratio of less than 4.50 in June 2014, 4.25 in December 2014, 4.0 in June 2015 and 3.50 in the other half yearly periods until settlement. NIB ·Maintaining the half-yearly debt service coverage ratio at 1.2; ·Maintaining an indebtedness ratio of 70% or less; ·Maintaining a financing Coverage Ratio of 1.7 or more.  Banco do Brasil ·Maintaining the annual debt service coverage ratio at 1.2 or more during the amortization period.


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Foreign currency borrowings - Bank of America Merrill Lynch (except for CPFL Piratininga), J.P. Morgan (except for RGE*), Citibank, Morgan Stanley, Scotiabank, Bank of Tokyo-Mitsubishi, Santander (except for CPFL Energia), Sumitomo, Mizuho, HSBCand BNP Paribas(Law 4,131) The foreign currency borrowings taken under Law 4,131 are subject to certain restrictive covenants, 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 Finance Income (Costs) – minimum of 2.25. (*) Loan with balance of R$ 139,466 at December 31, 2015 and maturity on February 22, 2016. For purposes of determining covenants, the definition of EBITDA for the Company takes into consideration mainly the consolidation of subsidiaries, associates and joint ventures based on the Company’s interest in those companies (for EBITDA and assets and liabilities). Various borrowings of the direct and indirect subsidiaries are subject to acceleration of maturities in the event of changes in the Company’s ownership structure or in the ownership 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 control block. Furthermore, failure to comply with the obligations or restrictions mentioned can result in default in relation to other contractual obligations (cross default), depending on each borrowing 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 Management’s opinion, all restrictive covenants and clauses are adequately complied with at December 31, 2015.  ( 18 )DEBENTURES AND INTERESTS ON DEBENTURES


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December 31, 2015

   

   December 31, 2014Issue

   

   Current and noncurrent interest

   

   Current

   

   Noncurrent

   

   Total

   

   Current and noncurrent interest

   

   Current

   

   Noncurrent

   

   TotalParent Company4th Issue

   Single series

   

   -

   

   -

   

   -

   

   -

   

   15,020

   

   1,290,000

   

   -

   

   1,305,020CPFL Paulista6th Issue

   Single series

   

   47,292

   

   -

   

   660,000

   

   707,292

   

   38,673

   

   -

   

   660,000

   

   698,6737th Issue

   Single series

   

   29,546

   

   -

   

   505,000

   

   534,546

   

   24,291

   

   -

   

   505,000

   

   529,29176,838

   

   -

   

   1,165,000

   

   1,241,838

   

   62,964

   

   -

   

   1,165,000

   

   1,227,964CPFL Piratininga3rd Issue

   Single series

   

   -

   

   -

   

   -

   

   -

   

   7,571

   

   260,000

   

   -

   

   267,5716th Issue

   Single series

   

   7,882

   

   -

   

   110,000

   

   117,882

   

   6,446

   

   -

   

   110,000

   

   116,4467th Issue

   Single series

   

   13,749

   

   -

   

   235,000

   

   248,749

   

   11,304

   

   

   

   235,000

   

   246,30421,631

   

   -

   

   345,000

   

   366,631

   

   25,320

   

   260,000

   

   345,000

   

   630,320RGE6th Issue

   Single series

   

   35,828

   

   -

   

   500,000

   

   535,828

   

   29,298

   

   -

   

   500,000

   

   529,2987th Issue

   Single series

   

   9,946

   

   -

   

   170,000

   

   179,946

   

   8,177

   

   -

   

   170,000

   

   178,17745,774

   

   -

   

   670,000

   

   715,774

   

   37,475

   

   -

   

   670,000

   

   707,475CPFL Santa Cruz1st Issue

   Single series

   

   568

   

   -

   

   65,000

   

   65,568

   

   480

   

   -

   

   65,000

   

   65,480CPFL Brasil2nd Issue

   Single series

   

   2,794

   

   -

   

   228,000

   

   230,794

   

   2,346

   

   -

   

   228,000

   

   230,346CPFL Geração3rd Issue

   Single series

   

   -

   

   -

   

   -

   

   -

   

   7,687

   

   264,000

   

   -

   

   271,6875th Issue

   Single series

   

   13,382

   

   -

   

   1,092,000

   

   1,105,382

   

   11,236

   

   -

   

   1,092,000

   

   1,103,2366th Issue

   Single series

   

   23,531

   

   -

   

   460,000

   

   483,531

   

   19,446

   

   -

   

   460,000

   

   479,4467th Issue

   Single series

   

   16,770

   

   -

   

   635,000

   

   651,770

   

   13,739

   

   -

   

   635,000

   

   648,7398th Issue

   Single series

   

   3,153

   

   -

   

   80,024

   

   83,177

   

   2,903

   

   -

   

   72,390

   

   75,29356,835

   

   -

   

   2,267,024

   

   2,323,859

   

   55,012

   

   264,000

   

   2,259,390

   

   2,578,401CPFL Renováveis1st Issue - SIIF (*)

   1st to 12th series

   

   788

   

   38,965

   

   467,577

   

   507,329

   

   798

   

   36,640

   

   476,329

   

   513,7671st Issue - PCH Holding 2

   Single series

   

   616

   

   8,701

   

   140,792

   

   150,109

   

   57,991

   

   8,701

   

   149,492

   

   216,1841st Issue - Renováveis

   Single series

   

   6,579

   

   43,000

   

   365,500

   

   415,079

   

   5,795

   

   21,500

   

   408,500

   

   435,7952nd Issue - Renováveis

   Single series

   

   11,894

   

   -

   

   300,000

   

   311,894

   

   9,603

   

   -

   

   300,000

   

   309,6033rd Issue - Renováveis

   Single series

   

   4,589

   

   -

   

   296,000

   

   300,589

   

   -

   

   -

   

   -

   

   -1st Issue - WF2

   Single series

   

   -

   

   -

   

   -

   

   -

   

   2,984

   

   30,000

   

   -

   

   32,9842nd Issue - WF2

   Single series

   

   -

   

   -

   

   -

   

   -

   

   10,582

   

   132,000

   

   -

   

   142,5821st Issue - DESA

   Single series

   

   862

   

   17,500

   

   17,500

   

   35,862

   

   716

   

   -

   

   35,000

   

   35,7162nd Issue - DESA

   Single series

   

   16,487

   

   -

   

   65,000

   

   81,487

   

   6,022

   

   -

   

   65,000

   

   71,0221st Issue - T-16

   Single series

   

   1,810

   

   277,200

   

   -

   

   279,010

   

   -

   

   -

   

   -

   

   -1st Issue - Campos dos Ventos V

   Single series

   

   374

   

   42,000

   

   -

   

   42,374

   

   -

   

   -

   

   -

   

   -1st Issue - Santa Úrsula

   Single series

   

   275

   

   30,800

   

   -

   

   31,075

   

   -

   

   -

   

   -

   

   -44,274

   

   458,165

   

   1,652,369

   

   2,154,808

   

   94,491

   

   228,841

   

   1,434,321

   

   1,757,653Borrowing costs (**)

   

   

   -

   

   -

   

   (28,842)

   

   (28,842)

   

   -

   

   (766)

   

   (30,311)

   

   (31,077)248,714

   

   458,165

   

   6,363,552

   

   7,070,430

   

   293,108

   

   2,042,075

   

   6,136,400

   

   8,471,583(*) These debentures can be converted into shares and, therefore, are considered in the calculation of the dilutive effect for earnings per share (note 26)(**) In accordance with IAS 39, this refers to borrowings costs attributable to issuance of the respective debt instruments.


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Issue

   

   Quantity issued

   

   Annual Remuneration

   

   Annual effective rate

   

   Amortization conditions

   

   CollateralParent Company4th Issue

   Single series

   

   129.000

   

   CDI + 0.40%

   

   CDI + 0.51%

   

   1 installment in May 2015

   

   UnsecuredCPFL Paulista6th Issue

   Single series

   

   660

   

   CDI + 0.8% (2)

   

   CDI + 0.87%

   

   3 annual installments from July 2017

   

   CPFL Energia guarantee7th Issue

   Single series

   

   50,500

   

   CDI + 0.83% (3)

   

   CDI + 0.89%

   

   4 annual installments from February 2018

   

   CPFL Energia guaranteeCPFL Piratininga3rd Issue

   Single series

   

   260

   

   107% of CDI

   

   108.23% of CDI

   

   1 installment in April 2015

   

   CPFL Energia guarantee6th Issue

   Single series

   

   110

   

   CDI + 0.8% (2)

   

   CDI + 0.91%

   

   3 annual installments from July 2017

   

   CPFL Energia guarantee7th Issue

   Single series

   

   23,500

   

   CDI + 0.83% (2)

   

   CDI + 0.89%

   

   4 annual installments from February 2018

   

   CPFL Energia guaranteeRGE6th Issue

   Single series

   

   500

   

   CDI + 0.8% (2)

   

   CDI + 0.88%

   

   3 annual installments from July 2017

   

   CPFL Energia guarantee7th Issue

   Single series

   

   17,000

   

   CDI + 0.83% (3)

   

   CDI + 0.88%

   

   4 annual installments from February 2018

   

   CPFL Energia guaranteeCPFL Santa Cruz1st Issue

   Single series

   

   650

   

   CDI + 1.4%

   

   CDI + 1.52%

   

   2 annual instalments from June 2017

   

   CPFL Energia guaranteeCPFL Brasil2nd Issue

   Single series

   

   2,280

   

   CDI + 1.4%

   

   CDI + 1.48%

   

   2 annual instalments from June 2017

   

   CPFL Energia guaranteeCPFL Geração3rd Issue

   Single series

   

   264

   

   107% of CDI

   

   108.23% of CDI

   

   1 installment in April 2015

   

   CPFL Energia guarantee5th Issue

   Single series

   

   10,920

   

   CDI + 1.4%

   

   CDI + 1.48%

   

   2 annual instalments from June 2017

   

   CPFL Energia guarantee6th Issue

   Single series

   

   46,000

   

   CDI + 0.75% (1)

   

   CDI + 0.75%

   

   3 annual instalments from August 2018

   

   CPFL Energia guarantee7th Issue

   Single series

   

   63,500

   

   CDI + 1.06%

   

   CDI + 1.11%

   

   1 installment in April 2019

   

   CPFL Energia guarantee8th Issue

   Single series

   

   1

   

   IPCA + 5.86% (1)

   

   103.33% of CDI

   

   1 installment in April 2019

   

   CPFL Energia guaranteeCPFL Renováveis1st Issue - SIIF

   1st to 12th series

   

   432,299,666

   

   TJLP + 1%

   

   TJLP + 1% + 0.6%

   

   39 semi-annual installments from 2009

   

   Liens1st Issue - PCH Holding 2

   Single series

   

   1,581

   

   CDI + 1.6%

   

   CDI + 1.8%

   

   9 annual installments from June 2015

   

   CPFL Renováveis guarantee1st Issue - Renováveis

   Single series

   

   43,000

   

   CDI + 1.7%

   

   CDI + 1.82%

   

   Annual installments from May 2015

   

   Assignment of dividends of BVP and PCH Holding2nd Issue - Renováveis

   Single series

   

   300,000

   

   114.0% of CDI

   

   115.43% of CDI

   

   5 annual instalments from June 2017

   

   Unsecured3rd Issue - Renováveis

   Single series

   

   29,600

   

   117.25% of CDI

   

   120.64% of CDI

   

   1 installment in May 2020

   

   Unsecured1st Issue - WF2

   Single series

   

   12

   

   CDI + 1.5%

   

   CDI + 1.5%

   

   1 installment in March 2015

   

   Unsecured2nd Issue - WF2

   Single series

   

   20

   

   CDI + 2%

   

   CDI + 2%

   

   1 installment in November 2015

   

   Unsecured1st Issue - DESA

   Single series

   

   20

   

   CDI + 1.75%

   

   CDI + 1.75%

   

   3 semi-annual installments from May de 2016

   

   Unsecured2nd Issue - DESA

   Single series

   

   65

   

   CDI + 1.34%

   

   CDI + 1.34%

   

   3 semi-annual installments from April de 2018

   

   Unsecured1st Issue - T-16

   Single series

   

   27,720

   

   112.75% of CDI

   

   116.94% of CDI

   

   1 installment in December 2016

   

   CPFL Renováveis guarantee1st Issue - Campos dos Ventos V

   Single series

   

   4,200

   

   112.75% of CDI

   

   116.94% of CDI

   

   1 installment in December 2016

   

   CPFL Renováveis guarantee1st Issue - Santa Úrsula

   Single series

   

   3,080

   

   112.75% of CDI

   

   116.94% of CDI

   

   1 installment in December 2016

   

   CPFL Renováveis guaranteeThe 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(2) 107% to 107.9% of CDI(3) 108% to 108.1% of CDI
  The maturities of the debentures recognized in noncurrent liabilities are scheduled as follows: 2017

   

   1,207,2282018

   

   1,765,3582019

   

   1,910,9812020

   

   667,1472021

   

   445,5742022 to 2026

   

   308,6802027 to 2031

   

   58,585Total

   

   6,363,552
  Main debentures issuances during the year R$ thousandCompany

   

   Issue

   

   Quantity issued

   

   Released in 2015

   

   Released net of issuance costs

   

   Interest

   

   UtilizationCPFL Renováveis - Parent company

   

   3rd issue - Single series

   

   29,600

   

   296,000

   

   293,596

   

   Semiannual

   

   Improvement of the liquidity level and extension of the debt profileCPFL Renováveis - T-16

   

   1st issue - Single series

   

   27,720

   

   277,200

   

   275,659

   

   Semiannual

   

   Subsidiary's investment planCPFL Renováveis - Campo dos Ventos V

   

   1st issue - Single series

   

   4,200

   

   42,000

   

   41,757

   

   Semiannual

   

   Subsidiary's investment planCPFL Renováveis - Santa Úrsula

   

   1st issue - Single series

   

   3,080

   

   30,800

   

   30,618

   

   Semiannual

   

   Subsidiary's investment plan646,000

   

   641,629


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RESTRICTIVE COVENANTS The debentures are subject to certain restrictive covenants, which 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 (6th and 7th issues), CPFL Piratininga (6th and 7th issues), RGE (6th and 7th issues), CPFL Geração (5th , 6th , 7th and 8th 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 Finance Income (Costs) - minimum of 2.25; For purposes of determination of covenants, the definition of EBITDA, in the Company, takes into consideration the consolidation of subsidiaries, associates and joint ventures based on the Company’s interest in those companies (for EBITDA and assets and liabilities). CPFL Renováveis The issues of debentures for the year ended December 31, 2015 contain clauses that require the subsidiary CPFL Renováveis to maintain the following financial ratios: - 1st issue of CPFL Renováveis ·Operating debt service coverage ratio - minimum of 1.00; ·Debt service coverage ratio - minimum of 1.05; ·Net indebtedness divided by EBITDA - maximum of 5.6 in 2015, 5.4 in 2016, 4.6 in 2017, 4.0 in 2018 and 2019 and 3.75 from 2020; ·EBITDA divided by Net finance costs - minimum of 1.75. The subsidiary obtained approval from the debentureholders for non-compliance with the following: i.Debt Service Coverage ratio related to the calculation of June 2015, through the General Meeting of Debentureholders held on June 30, 2015. ii.Debt Service Coverage ratio related to the calculation of December 2015, through the General Meeting of Debentureholders held on December 21, 2015. - 2nd issue of CPFL Renováveis ·Net indebtedness divided by EBITDA - maximum of 5.6 in 2015, 5.4 in 2016, 4.6 in 2017, 4.0 in 2018 and 2019 and 3.75 from 2020. - 3rd issue of CPFL Renováveis ·Net indebtedness divided by EBITDA - maximum of 5.6 in 2015, 5.4 in 2016, 4.6 in 2017, 4.0 in 2018 and 2019 and 3.75 from 2020. - 1st issue of the indirect subsidiary PCH Holding 2 S.A ·Maintaining the Debt Service Coverage ratio of the subsidiary Santa Luzia at 1.2 or more from September 2014. ·Net indebtedness divided by EBITDA - maximum of 5.6 in 2015, 5.4 in 2016, 4.6 in 2017, 4.0 in 2018 and 2019 and 3.75 from 2020. - 2nd issue of 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. - 1st issue of T-16 (Turbina 16 Energia) ·Maintaininga consolidated Net Debt/EBITDA ratio at no more than 5.6 for the year 2015. - 1st issue of Campos dos Ventos V Energias Renováveis ·Maintaininga consolidated Net Debt/EBITDA ratio at no more than 5.6 for the year 2015.


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- 1st issue of Santa Úrsula Energias Renováveis ·Maintaininga consolidated Net Debt/EBITDA ratio at no more than 5.6 for the year 2015. Various debentures of subsidiaries and joint ventures are subject to acceleration of maturities in the event of changes in the Company’s ownership structure or in the ownership 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, except unless at least one of the shareholders (Camargo Corrêa and Previ) remains directly or indirectly in the Company’s controlling block. Failure to comply with the restrictions mentioned can result in default in relation to other contractual obligations (cross default),depending on each agreement. The Management of the Company and its subsidiaries monitor those ratios systematically and constantly for the conditions to be fulfilled. In Management’s opinion, all restrictive covenants and clauses are adequately complied with at December 31, 2015.  ( 19 )PRIVATE PENSION PLAN
 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. Additionally, the subsidiary’s Managers may opt for a Free Benefit Generator Plan – “PGBL” (defined contribution), operated by either Banco do Brasil or Bradesco. - CPFL Piratininga As a result of the spin-off of Bandeirante Energia S.A. (subsidiary’s predecessor), the subsidiary CPFL Piratininga assumed the responsibility for the actuarial liabilities of that company’s employees retired and terminated until the date of spin-off, as well as for the obligations relating to the active employees transferred to CPFL Piratininga. On April 2, 1998, the Secretariat of Pension Plans – “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 grants a Proportional Supplementary Defined Benefit (BSPS), in the form of a lifetime income convertible into a pension to participants enrolled until March 31, 1998, in 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.


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b) Defined Benefit Plan - in force after March 31, 1998 – defined-benefit type plan, which grants 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 granting of the lifetime income, convertible (or not) into a pension, and accordingly starts to generate actuarial liabilities for the subsidiary. Additionally, the subsidiary’s Managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Bradesco. - RGE A defined benefit type plan, with a benefit level equal to 100% of the adjusted average of the most recent salaries, less the presumed Social Security benefit, with a Segregated Net Asset managed by ELETROCEEE. Only those whose employment 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 hired 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 participate in 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 Bradesco.  19.2 – Movements in the defined benefit plans  December 31, 2015CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total liabilitiesPresent value of actuarial obligations

   

   3,793,259

   

   961,329

   

   90,609

   

   278,985

   

   5,124,182Fair value of plan's assets

   

   (3,355,589)

   

   (951,021)

   

   (80,332)

   

   (287,202)

   

   (4,674,144)Present value of net obligations (fair value of assets)

   

   437,670

   

   10,308

   

   10,277

   

   (8,217)

   

   450,038Effect of asset ceiling

   

   -

   

   -

   

   -

   

   8,217

   

   8,217Net actuarial liability recognized in the statement of financial position

   

   437,670

   

   10,308

   

   10,277

   

   -

   

   458,255December 31, 2014CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total liabilitiesPresent value of actuarial obligations

   

   3,820,563

   

   986,972

   

   88,621

   

   279,283

   

   5,175,439Fair value of plan's assets

   

   (3,315,422)

   

   (913,589)

   

   (85,360)

   

   (273,019)

   

   (4,587,390)Present value of net obligations recognized in the statement of financial position

   505,140

   

   73,383

   

   3,261

   

   6,264

   

   588,048December 31, 2013CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total liabilitiesPresent value of actuarial obligations

   

   3,599,853

   

   919,441

   

   82,167

   

   245,371

   

   4,846,832Fair value of plan's assets

   

   (3,235,768)

   

   (874,546)

   

   (83,309)

   

   (242,325)

   

   (4,435,948)Present value of net obligations (fair value of assets)

   

   364,085

   

   44,895

   

   (1,142)

   

   3,046

   

   410,884Effect of asset ceiling

   

   -

   

   -

   

   1,142

   

   -

   

   1,142Net actuarial liability recognized in the statement of financial position

   

   364,085

   

   44,895

   

   -

   

   3,046

   

   412,025


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The movements in the present value of the actuarial obligations and the fair value of the plan’s assets are as follows:  CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total liabilitiesPresent value of actuarial obligations at December 31, 2012

   

   4,431,699

   

   1,159,779

   

   101,714

   

   298,014

   

   5,991,206Gross current service cost

   

   1,485

   

   6,099

   

   167

   

   359

   

   8,110Interest on actuarial obligations

   

   380,340

   

   99,150

   

   8,740

   

   25,727

   

   513,957Participants' contributions transferred during the year

   

   60

   

   1,582

   

   12

   

   927

   

   2,581Actuarial gain on changes 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 actuarial obligations at December 31, 2013

   

   3,599,853

   

   919,441

   

   82,167

   

   245,371

   

   4,846,832Gross current service cost

   

   1,160

   

   3,937

   

   152

   

   (43)

   

   5,206Interest on actuarial obligations

   

   404,925

   

   104,090

   

   9,250

   

   27,748

   

   546,013Participants' contributions transferred during the year

   

   14

   

   1,700

   

   -

   

   783

   

   2,497Actuarial loss: effect of changes in demographic assumptions

   

   35,892

   

   10,484

   

   1,113

   

   4,379

   

   51,868Actuarial loss: effect of changes in financial assumptions

   

   89,187

   

   16,695

   

   3,089

   

   19,387

   

   128,358Benefits paid during the year

   

   (310,468)

   

   (69,375)

   

   (7,150)

   

   (18,342)

   

   (405,335)Present value of actuarial obligations at December 31, 2014

   

   3,820,563

   

   986,972

   

   88,621

   

   279,283

   

   5,175,439Gross current service cost

   

   1,183

   

   3,733

   

   160

   

   (131)

   

   4,945Interest on actuarial obligations

   

   425,465

   

   110,425

   

   9,944

   

   31,490

   

   577,324Participants' contributions transferred during the year

   

   12

   

   1,842

   

   -

   

   611

   

   2,465Actuarial loss: effect of changes in demographic assumptions

   

   (226)

   

   (614)

   

   (12)

   

   (6)

   

   (858)Actuarial loss: effect of changes in financial assumptions

   

   (98,399)

   

   (70,590)

   

   (400)

   

   (11,884)

   

   (181,273)Benefits paid during the year

   

   (355,339)

   

   (70,439)

   

   (7,704)

   

   (20,378)

   

   (453,860)Present value of actuarial obligations at December 31, 2015

   

   3,793,259

   

   961,329

   

   90,609

   

   278,985

   

   5,124,182
  CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total assetsFair value of actuarial assets at December 31, 2012

   

   (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 loss (gain)

   

   60,636

   

   18,260

   

   2,067

   

   (12,871)

   

   68,092Benefits paid during the year

   

   310,468

   

   69,375

   

   7,150

   

   18,342

   

   405,335Fair value of actuarial 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 loss (gain)

   

   60,636

   

   18,260

   

   2,067

   

   (12,871)

   

   68,092Benefits paid during the year

   

   310,468

   

   69,375

   

   7,150

   

   18,342

   

   405,335Fair value of actuarial assets at December 31, 2014

   

   (3,315,422)

   

   (913,589)

   

   (85,360)

   

   (273,019)

   

   (4,587,390)Expected return during the year

   

   (375,527)

   

   (105,413)

   

   (9,691)

   

   (31,686)

   

   (522,317)Participants' contributions transferred during the year

   

   (12)

   

   (1,842)

   

   -

   

   (611)

   

   (2,465)Sponsors' contributions

   

   (81,111)

   

   (22,936)

   

   (1,687)

   

   (7,593)

   

   (113,327)Actuarial loss (gain)

   

   61,144

   

   22,320

   

   8,702

   

   5,329

   

   97,495Benefits paid during the year

   

   355,339

   

   70,439

   

   7,704

   

   20,378

   

   453,860Fair value of actuarial assets at December 31, 2015

   

   (3,355,589)

   

   (951,021)

   

   (80,332)

   

   (287,202)

   

   (4,674,144)


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19.3 Movements in recognized assets and liabilities recognized The movements in net liability are as follows:  CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total liabilitiesNet actuarial liabiliy at December 31, 2012

   

   657,231

   

   174,222

   

   8,353

   

   26,136

   

   865,942Expenses (income) recognized in the statement of profit or loss

   

   44,234

   

   15,562

   

   481

   

   1,388

   

   61,665Sponsors' contributions transferred during the year

   

   (56,266)

   

   (18,243)

   

   (1,207)

   

   (8,336)

   

   (84,052)Actuarial gain on changes in financial assumptions

   

   (281,114)

   

   (126,646)

   

   (7,627)

   

   (16,142)

   

   (431,529)Net actuarial liability at December 31, 2013

   

   364,085

   

   44,895

   

   -

   

   3,046

   

   412,025Other contributions

   

   14,458

   

   394

   

   69

   

   504

   

   15,425Total liability

   

   378,543

   

   45,289

   

   69

   

   3,550

   

   427,450Current

   

   

   

   

   

   

   

   

   

   76,810Noncurrent

   

   

   

   

   

   

   

   

   

   350,640
  CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total liabilitiesNet actuarial liability at December 31, 2013

   

   364,085

   

   44,895

   

   -

   

   3,046

   

   412,025Expenses (income) recognized in the statement of profit or loss

   

   40,365

   

   7,979

   

   77

   

   (256)

   

   48,165Sponsors' contributions transferred during the year

   

   (85,024)

   

   (24,930)

   

   (1,809)

   

   (7,421)

   

   (119,184)Actuarial loss: effect of changes in demographic assumptions

   

   35,892

   

   10,484

   

   1,113

   

   4,379

   

   51,868Actuarial loss: effect of changes in financial assumptions

   

   149,823

   

   34,955

   

   3,880

   

   6,515

   

   195,173Net actuarial liability at December 31, 2014

   

   505,140

   

   73,383

   

   3,261

   

   6,264

   

   588,048Other contributions

   

   15,171

   

   456

   

   65

   

   20

   

   15,712Total liability

   

   520,311

   

   73,839

   

   3,326

   

   6,284

   

   603,760Current

   

   

   

   

   

   

   

   

   

   85,374Noncurrent

   

   

   

   

   

   

   

   

   

   518,386
  CPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   Total liabilitiesNet actuarial liability at December 31, 2014

   

   505,140

   

   73,383

   

   3,261

   

   6,264

   

   588,048Expenses (income) recognized in the statement of profit or loss

   

   51,121

   

   8,745

   

   413

   

   (95)

   

   60,184Sponsors' contributions transferred during the year

   

   (81,111)

   

   (22,936)

   

   (1,687)

   

   (7,593)

   

   (113,327)Actuarial loss: effect of changes in financial assumptions

   

   (226)

   

   (614)

   

   (12)

   

   (6)

   

   (858)Actuarial loss: effect of changes in demographic assumptions

   

   (37,254)

   

   (48,270)

   

   8,302

   

   (6,555)

   

   (83,777)Effect of asset ceiling

   

   -

   

   -

   

   -

   

   7,984

   

   7,984Net actuarial liability at December 31, 2015

   

   437,670

   

   10,308

   

   10,277

   

   -

   

   458,255Other contributions

   

   16,149

   

   526

   

   63

   

   127

   

   16,865Total liability

   

   453,819

   

   10,834

   

   10,340

   

   127

   

   475,120Current

   

   

   

   

   

   

   

   

   

   802Noncurrent

   

   

   

   

   

   

   

   

   

   474,318
  19.4Expected contributions and benefits The expected contributions to the plans for 2016 are shown below:  2016CPFL Paulista

   62,571CPFL Piratininga

   16,341CPFL Geração

   1,331RGE

   8,345Total

   88,588
    The subsidiaries negotiated with Fundação CESP a grace period for payment of the principal of the monthly contributions for the respective plans during the period from September 2015 to August 2017, with resumption of these payments as from September 2017.


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The expected benefits to be paid by the foundations in the next 10 years are shown below:  2016

   

   2017

   

   2018

   

   2019

   

   2020 to 2025

   

   TotalCPFL Paulista

   346,646

   

   363,011

   

   378,559

   

   395,620

   

   2,695,839

   

   4,179,675CPFL Piratininga

   75,159

   

   79,392

   

   84,152

   

   89,863

   

   654,350

   

   982,916CPFL Geração

   8,214

   

   8,596

   

   8,945

   

   9,343

   

   64,037

   

   99,135RGE

   23,026

   

   24,697

   

   25,965

   

   27,382

   

   193,557

   

   294,627Total

   453,045

   

   475,696

   

   497,621

   

   522,208

   

   3,607,783

   

   5,556,353
  At December 31, 2015, the average duration of the defined benefit obligation was 8.3 years for CPFL Paulista, 9.6 years for CPFL Piratininga, 8.4 years for CPFL Geração and 9.1 years for RGE. 19.5 Recognition of private pension plan income and expense The external actuary’s estimate of the expenses (income) to be recognized in 2016 and the expense (income) recognized in 2015, 2014 and 2013 is as follows:  2016 EstimatedCPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   TotalService cost

   

   761

   

   2,509

   

   68

   

   16

   

   3,354Interest on actuarial obligations

   

   458,646

   

   117,039

   

   10,960

   

   33,889

   

   620,534Expected return on plan assets

   

   (407,158)

   

   (116,891)

   

   (9,742)

   

   (35,488)

   

   (569,279)Effect of asset ceiling

   

   -

   

   -

   

   -

   

   1,041

   

   1,041Total expense (income)

   

   52,249

   

   2,657

   

   1,286

   

   (542)

   

   55,6502015 ActualCPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   TotalService cost

   

   1,183

   

   3,733

   

   160

   

   (131)

   

   4,945Interest on actuarial obligations

   

   425,465

   

   110,425

   

   9,944

   

   31,490

   

   577,324Expected return on plan assets

   

   (375,527)

   

   (105,413)

   

   (9,691)

   

   (31,686)

   

   (522,317)Effect of asset ceiling

   

   -

   

   -

   

   -

   

   232

   

   232Total expense (income)

   

   51,121

   

   8,745

   

   413

   

   (95)

   

   60,1842014 ActualCPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   TotalService cost

   

   1,160

   

   3,937

   

   152

   

   (43)

   

   5,206Interest on actuarial obligations

   

   404,925

   

   104,090

   

   9,250

   

   27,748

   

   546,013Expected return on plan assets

   

   (365,720)

   

   (100,048)

   

   (9,459)

   

   (27,961)

   

   (503,188)Effect of asset ceiling

   

   -

   

   -

   

   134

   

   -

   

   134Total expense (income)

   

   40,365

   

   7,979

   

   77

   

   (256)

   

   48,1652013 ActualCPFL Paulista

   

   CPFLPiratininga

   

   CPFL Geração

   

   RGE

   

   TotalService cost

   

   1,485

   

   6,098

   

   167

   

   359

   

   8,109Interest on actuarial obligations

   

   380,340

   

   99,150

   

   8,740

   

   25,727

   

   513,957Expected return on plan assets

   

   (337,591)

   

   (89,686)

   

   (8,560)

   

   (24,698)

   

   (460,535)Effect of asset ceiling

   

   -

   

   -

   

   134

   

   -

   

   134Total expense

   

   44,234

   

   15,562

   

   481

   

   1,388

   

   61,665


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The main assumptions taken into consideration in the actuarial calculation at the end of the reporting period were as follows: December 31, 2015

   

   December 31, 2014

   

   December 31, 2013Nominal discount rate for actuarial liabilities:

   12.67% p.a.

   

   11.46% p.a.

   

   11.72% p.a.Nominal Return Rate on Assets:

   12.67% p.a.

   

   11.46% p.a.

   

   11.72% p.a.Estimated Rate of nominal salary increase:

   6.79% p.a.

   

   8.15% p.a.

   

   7.10% p.a.Estimated Rate of nominal benefits increase:

   0.00% p.a.

   

   0.00% p.a.

   

   0.00% p.a.Estimated long-term inflation rate (basis for determining the nominal rates above)

   5.00% p.a.

   

   5.00% p.a.

   

   5.00% p.a.General biometric mortality table:

   AT-2000 (-10)

   

   AT-2000 (-10)

   

   AT-83Biometric table for the onset of disability:

   Low light

   

   Low light

   

   Mercer DisabilityExpected turnover rate:

   ExpR_2012**

   

   ExpR_2012*

   

   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(**) FUNCESP experience, with aggravation of 40%
  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, 2015 and 2014 managed by Fundação CESP and ELETROCEEE. The tables also show the distribution of the guarantee resources established as target for 2016, obtained in light of the macroeconomic scenario in December 2015. Assets managed by the plans are as follows:  Assets managed by Fundação CESP

   

   Assets managed by ELETROCEEECPFL Paulista and CPFL Geração

   

   CPFL Piratininga

   

   RGEQuoted in an active market

   

   Not quoted in an active market

   

   Quoted in an active market

   

   Not quoted in an active market

   

   Quoted in anactive market

   

   Not quoted in anactive market2015

   

   2014

   

   2015

   

   2014

   

   2015

   

   2014

   

   2015

   

   2014

   

   2015

   

   2014

   

   2015

   

   2014Fixed rate

   

   80%

   

   75%

   

   -

   

   -

   

   84%

   

   78%

   

   -

   

   -

   

   73%

   

   61%

   

   -

   

   -Federal governament bonds

   

   57%

   

   65%

   

   -

   

   -

   

   54%

   

   65%

   

   -

   

   -

   

   56%

   

   42%

   

   -

   

   -Corporate bonds (financial institutions)

   

   5%

   

   5%

   

   -

   

   -

   

   10%

   

   9%

   

   -

   

   -

   

   4%

   

   5%

   

   -

   

   -Corporate bonds (non financial institutions)

   

   1%

   

   1%

   

   -

   

   -

   

   1%

   

   2%

   

   -

   

   -

   

   5%

   

   8%

   

   -

   

   -Multimarket funds

   

   16%

   

   2%

   

   -

   

   -

   

   19%

   

   2%

   

   -

   

   -

   

   8%

   

   6%

   

   -

   

   -Other fixed income investments

   

   1%

   

   2%

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Variable income

   

   13%

   

   18%

   

   -

   

   -

   

   12%

   

   18%

   

   -

   

   -

   

   14%

   

   24%

   

   -

   

   -CPFL Energia's share

   

   5%

   

   6%

   

   -

   

   -

   

   4%

   

   5%

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Investiment funds - shares

   

   8%

   

   12%

   

   -

   

   -

   

   8%

   

   13%

   

   -

   

   -

   

   14%

   

   24%

   

   -

   

   -Structured investments

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   11%

   

   14%

   

   -

   

   -Equity funds

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   10%

   

   12%

   

   -

   

   -Real estate funds

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1%

   

   1%

   

   -

   

   -Multimarket fund

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1%

   

   -

   

   -Real estate

   

   -

   

   -

   

   4%

   

   4%

   

   -

   

   -

   

   2%

   

   2%

   

   -

   

   -

   

   1%

   

   1%Transactions with participants

   

   -

   

   -

   

   2%

   

   2%

   

   -

   

   -

   

   2%

   

   2%

   

   -

   

   -

   

   1%

   

   1%Other investments

   

   -

   

   -

   

   1%

   

   1%

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Escrow deposits and others

   

   -

   

   -

   

   1%

   

   1%

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -93%

   

   93%

   

   7%

   

   7%

   

   96%

   

   96%

   

   4%

   

   4%

   

   98%

   

   98%

   

   2%

   

   2%
  The plan assets do not include any properties occupied or assets used by the Company. The fair value of the shares stated in line item "Shares of CPFL Energia" in the assets managed by Fundação CESP is R$ 245,380 at December 31, 2015 (R$ 288,061 at December 31, 2014).


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Target for 2016Fundação CESP

   

   Fundação ELETROCEEECPFL Paulista and CPFL Geração

   

   CPFL Piratininga

   

   RGEFixed income investments

   

   81.0%

   

   83.9%

   

   81.0%Variable income investments

   

   11.2%

   

   9.8%

   

   14.0%Real estate

   

   3.9%

   

   1.8%

   

   1.0%Transactions with participants

   

   1.5%

   

   1.8%

   

   1.0%Structured investments

   

   0.2%

   

   0.3%

   

   3.0%Investments abroad

   

   2.1%

   

   2.4%

   

   0.0%100.0%

   

   100.0%

   

   100.0%
  The allocation target for 2016 was based on the recommendations for allocation of assets made at the end of 2015 by Fundação CESP and ELETROCEEE, in their Investment Policy. This target may change at any time during 2016, in 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), 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 long-term profitability 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 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. 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 statement of financial position, according to IAS 19. 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

   

   TOTALDefined benefit plan obligation

   

   3,793,259

   

   961,329

   

   90,609

   

   278,985

   

   5,124,182
  Assumptions

   

   Assumptions report (A)

   

   Increase / (Decrease) (B)

   

   Projected (A+B)

   

   CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   Increase (decrease) in total defined benefit plan obligationNominal discount (p.a.)

   

   12,67%

   

   -0.25%

   

   12.42%

   

   79,544

   

   23,406

   

   1,929

   

   6,412

   

   111,2910.25%

   

   12.92%

   

   (76,589)

   

   (22,423)

   

   (1,855)

   

   (6,155)

   

   (107,022)Life expectancy (years)

   

   AT-2000(-10)

   

   -1 year

   

   

   

   (63,988)

   

   (12,079)

   

   (1,485)

   

   (3,659)

   

   (81,211)+1 year

   

   

   

   62,082

   

   11,584

   

   1,446

   

   3,508

   

   78,620
   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-M, IPCA and SELIC, which are the indexes for adjustment of the actuarial liabilities of the Company’s plans (defined benefit plans), representing the matching between assets and liabilities.


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Management of the Company’s benefit plans is monitored by the Investment and Pension Plan 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 investment managers of Fundação CESP, which occurs at least quarterly. In addition to controlling market risks by the unplanned divergence methodology, as required by law, Fundação CESP and Fundação ELETROCEEE 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 and Fundação ELETROCEEE’s Investment Policy imposes additional restrictions that, along those established by law, define the percentage of diversification for investments in assets issued or underwritten by the same legal entity.  ( 20 )REGULATORY CHARGES
  December 31, 2015

   

   December 31, 2014Fee for the use of water resources

   2,482

   

   1,676Global reversal reserve - RGR

   17,446

   

   15,993ANEEL inspection fee

   1,764

   

   1,553Energy development account - CDE

   526,196

   

   24,570FUST and FUNTEL

   3

   

   2Tariff flags and others

   304,127

   

   -Total

   852,017

   

   43,795
   Energy development account – CDE– refers to the (i) annual CDE quota for the year 2015 in the amount of R$ 401,347 (R$ 24,570 at December 31, 2014); (ii) quota intended for CDE injection for the period from January 2013 to January 2014 in the amount of R$ 45,618; and (iii) quota intended for injection into the Regulated Contracting Environment (ACR) account for the period from February to December 2014, in the amount of R$ 79,231. The subsidiaries conducted a matching of accounts between the amount of CDE payable and the accounts receivable – CDE injection (note 12) as from September 2015, in view of the fact that the Eletrobrás settlement receipts in the amount of R$ 814,850 were issued as from September 25, 2015. Tariff flags and others– refer basically to the amount to be passed on to the Centralizing Account for Tariff Flag Resources (“CCRBT”) (note 27.5).  ( 21 )TAXES, FEES AND CONTRIBUTIONS
  December 31, 2015

   

   December 31, 2014ICMS (State VAT)

   384,151

   

   266,489PIS (tax on revenue)

   33,199

   

   15,096COFINS (tax on revenue)

   159,317

   

   69,701IRPJ (corporate income tax)

   30,751

   

   35,304CSLL (social contribution on net income)

   12,498

   

   22,242Others

   33,427

   

   27,434Total

   653,342

   

   436,267
    ( 22 )PROVISION FOR TAX, CIVIL AND LABOR RISKS AND ESCROW DEPOSITS


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December 31, 2015

   

   December 31, 2014Provision for tax, civil and labor risks

   

   Escrow Deposits

   

   Provision for tax, civil and labor risks

   

   Escrow DepositsLaborVarious

   171,989

   

   78,345

   

   125,641

   

   82,857CivilVarious

   194,530

   

   112,909

   

   185,741

   

   120,696TaxFINSOCIAL

   29,917

   

   84,092

   

   27,585

   

   77,576Income Tax

   138,524

   

   886,271

   

   120,054

   

   829,589Other

   15,920

   

   63,600

   

   23,480

   

   51,755184,362

   

   1,033,964

   

   171,119

   

   958,920Other

   18,654

   

   2,310

   

   25,650

   

   4Total

   569,534

   

   1,227,527

   

   508,151

   

   1,162,477
  The movements in the provision for tax, civil and labor risks are shown below:  December 31, 2014

   

   Addition

   

   Reversal

   

   Payment

   

   Monetary Restatement

   

   December 31, 2015Labor

   125,641

   

   202,844

   

   (63,330)

   

   (113,380)

   

   20,215

   

   171,989Civil

   185,741

   

   138,947

   

   (53,723)

   

   (117,432)

   

   40,996

   

   194,530Tax

   171,119

   

   8,968

   

   (2,861)

   

   (6,099)

   

   13,234

   

   184,362Others

   25,650

   

   3,255

   

   (1,556)

   

   (10,601)

   

   1,905

   

   18,654508,151

   

   354,015

   

   (121,469)

   

   (247,512)

   

   76,349

   

   569,534
   The provision for tax, civil and labor risks was based on the assessment of the risks of losing the lawsuits to which the Company and its subsidiaries are parties, where the likelihood of loss is probable in the opinion of the outside legal counselors and the Management of the Company and its subsidiaries. The principal pending issues relating to litigation, lawsuits and tax assessments are summarized below: a)Labor:The main labor lawsuits relate to claims filed by former employees or labor unions for payment of salary adjustments (overtime, salary parity, severance payments and other claims). b)Civil Bodily injury –refer mainlyto claims for indemnities relating to accidents in the subsidiaries' electrical grids, damage to consumers, vehicle accidents, etc. Tariff increase –refer to various claims by industrial consumers as a result of tariff increases imposed by DNAEE Administrative Rules 38 and 45, of February 27 and March 4, 1986, when the “Plano Cruzado” economic plan price freeze was in effect. c)Tax FINSOCIAL– refer to legal challenges of the subsidiary CPFL Paulista of the rate increase and collection of FINSOCIAL during the period from June 1989 to October 1991. Income Tax– the provision of R$ 129,907 (R$120,094 at December 31, 2014) recognized by the subsidiary CPFL Piratininga refers to the lawsuit for tax deductibility of CSLL in the determination of corporate income tax - IRPJ. Other– refer to other lawsuits in progress at the judicial and administrative levels resulting from the subsidiaries' operations, related to tax matters involving INSS, FGTS and SAT. Possible losses


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The Company and its subsidiaries are parties to other lawsuits in which Management, supported by its external legal counselors, believes that the chances of a successful outcome are possible, due to a solid defensive position in these cases therefore no provision was registered for 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. The claims relating to possible losses, at December 31, 2015, were as follows: (i) R$ 659,636 labor (R$ 459,303 at December 31, 2014) related mainly to workplace accidents, hazardous duty premium, overtime, etc.; (ii) R$ 697,242 civil (R$ 481,575 at December 31, 2014) related mainly to bodily injury, environmental impacts and tariff increases; (iii) R$ 3,600,368 tax (R$ 3,216,981 at December 31, 2014), related mainly to ICMS, FINSOCIAL, PIS and COFINS and Income tax, 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 in the estimated amount of R$ 1,051,363 and (iv) R$ 71,514 regulatory at December 31, 2015 (R$ 39,739 at December 31, 2014). The possible regulatory loss includes mainly the collection of the system service charge - ESS, established in the CNPE Resolution 3 of March 6, 2013. The total amount of the risk is R$ 31,282, related mainly to indirect subsidiaries CPFL Brasil (R$ 7,117), CPFL Renováveis (R$ 12,642), Ceran (R$ 9,819), and CPFL Jaguari Geração (Paulista Lajeado) (R$ 2,024). As regards labor contingencies, the Company informs that there is discussion about the possibility of changing the inflation adjustment index adopted by the Labor Court. Currently there is a decision of the Federal Supreme Court (STF) that suspends the change taken into effect by the Superior Labor Court (TST), which intended to change the index currently adopted by the Labor Court (“TR”), the IPCA-E. The Supreme Court considered that the TST’s decision entailed an unlawful interpretation and was not compliant with the determination of the effects of prior court decisions, violating its competence to decide on a constitutional matter. In view of such decision, and until there is a new decision by the STF, the index currently adopted by the Labor Court (“TR”) remains valid. Accordingly, the management of the Company and its subsidiaries considers the risk of loss as possible and, as this matter still requires definition by the Courts, it is not possible to reliably estimate the amounts involved. Escrow deposits – income tax:of the total amount of R$ 886,271, R$ 745,903 (R$ 703,073 at December 31, 2014) 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 Fundação CESP, related to the employees’ pension plan, due to the renegotiation and novation of the debt in that year. In inquiring the Brazilian Federal Revenue (“RFB”), the subsidiary obtained a favorable reply in Note MF/SRF/COSIT/GAB No. 157, of April 9, 1998, and used the tax deductibility of the expense, thereby generating a tax loss in that year. Despite the favorable decision of the Brazilian Federal Revenue (RFB), the subsidiary was challenged by the tax authorities and made escrow deposits. In January 2016, the subsidiary obtained court decisions that authorized the replacement of the escrow deposits by financial guarantees (letter of guarantee and performance bond), for which the withdrawals on behalf of the subsidiaries occurred in 2016. There is an appeal by the Office of Attorney-General of the National Treasury in one of the cases, with suspensive effect, which is awaiting judgment by the Federal Regional Court. Based on the updated position of the attorneys handing the case, Management’s opinion is that the risk of loss is possible. Based on the opinion of their external legal advisers, Management of the Company and its subsidiaries consider that the registered amounts represent best estimate.  ( 23 )USE OF PUBLIC ASSET
  Subsidiary

   

   December 31, 2015

   

   December 31, 2014

   

   Number of remaining installments

   

   Interest ratesCERAN

   

   92,581

   

   84,992

   

   243

   

   IGP-M + 9.6%p.a.Current

   

   9,457

   

   4,000Noncurrent

   

   83,124

   

   80,992
    ( 24 )OTHER PAYABLES


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Current

   

   NoncurrentDecember 31, 2015

   

   December 31, 2014

   

   December 31, 2015

   

   December 31, 2014Consumers and concessionaires

   

   53,959

   

   49,710

   

   -

   

   -Energy efficiency program - PEE

   

   295,745

   

   267,123

   

   35,597

   

   13,370Research & Development - P&D

   

   84,943

   

   105,125

   

   36,426

   

   12,389National scientific and technological development fund - FNDCT

   

   4,115

   

   1,469

   

   -

   

   -Energy research company - EPE

   

   2,065

   

   734

   

   -

   

   -Reversion fund

   

   -

   

   -

   

   17,750

   

   17,750Advances

   

   141,228

   

   85,683

   

   10,041

   

   23,849Provision for socio environmental costs and asset retirement

   

   -

   

   -

   

   53,378

   

   49,938Payroll

   

   13,136

   

   12,232

   

   -

   

   -Profit sharing

   

   49,227

   

   55,659

   

   5,099

   

   7,413Collection agreements

   

   130,282

   

   91,889

   

   -

   

   -Guarantees

   

   -

   

   -

   

   28,531

   

   31,479Tariff discounts - CDE

   

   54,749

   

   35,053

   

   -

   

   -Business combination

   

   29,935

   

   70,419

   

   -

   

   16,152Others

   

   45,587

   

   60,844

   

   4,326

   

   11,425Total

   

   904,971

   

   835,941

   

   191,148

   

   183,766
  Consumers and concessionaires:refer to liabilities with consumers 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 recognized 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 adjustment for inflation at the SELIC rate, through the date of their 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 asset retirement: refers mainly to provisions recognized by the subsidiary 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 accrued against property, plant and equipment 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 the achievement of operating and financial targets previously established; (ii)Long-Term Incentive Program: refers to the Long-Term Incentive Plan for Executives, which involves rewarding the latter with financial resources, based on the behavior of the Company’s shares on the market and expectations for appreciation, as well as the Company’s results, using parametric calculation formulas and granting of Virtual Value Units (“UVV”). The Plan does not contemplate distributing Company shares to such executives and only uses them for purposes of monitoring the expectations established in the Company’s Long-Term Strategic Plan, likewise approved by the Board of Directors. The currently effective plan is in effect from 2014 to 2020 and calls for grants relating to 2014, 2015 and 2016. The effective period is thus 6 years, with a grace period of two years for the first conversion of each annual grant. The conversion term for each grant is gradual, in a period of up to 5 years and in 3 conversions (33/33/34%). The incentive program calls for partial realization, according to the relationship between expected appreciation and that effectively accrued, as per Strategic Plan expectation, there being a minimum expected results trigger, as well as attainment higher than initially projected, limited to 150%. Tariff discounts – CDE:refers to the difference between the tariff discount granted to consumers and the amounts received via the CDE. Business acquisition:refer to the amounts recognized by the subsidiary CPFL Renováveis, mainly in relation to the acquisition of noncontrolling interests. This amount is derived from the merger of WF2 (note 15.4) on October 1, 2014. Before WF2 acquisition by CPFL Renováveis, the acquiree had signed an agreement for the


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purchase of shares and other covenants from the noncontrolling shareholders of DESA, then holders of 21.14% of the voting and total capital of DESA. Under such agreement, the noncontrolling shareholders undertake to dispose of all their shares at the total amount of R$ 203,000, under the terms and subject to the conditions established in the agreement. The remaining amount of R$ 16,190 outstanding at December 31, 2015 has been paid in five quarterly installments, the last of which paid on January 29, 2016. The amount of each quarterly installment was adjusted for inflation at the CDI rate +1.2% a year, calculated on a pro rata basis.  ( 25 )EQUITY
 The shareholders’ interest in the Company’s equity at December 31, 2015 and 2014 is shown below:  Number of sharesDecember 31, 2015

   

   December 31, 2014Shareholders

   

   Common shares

   

   Interest %

   

   Common shares

   

   Interest %BB Carteira Livre I FIA

   

   262,698,037

   

   26.45%

   

   288,569,602

   

   29.99%Caixa de Previdência dos Funcionários do Banco do Brasil - Previ

   

   29,756,032

   

   3.00%

   

   477,700

   

   0.05%Camargo Correa S.A.

   

   26,764

   

   0.00%

   

   837,860

   

   0.09%ESC Energia S.A.

   

   234,086,204

   

   23.57%

   

   234,092,930

   

   24.33%Bonaire Participações S.A.

   

   1,238,334

   

   0.12%

   

   1,200,000

   

   0.12%Energia São Paulo FIA

   

   146,463,379

   

   14.75%

   

   141,929,430

   

   14.75%Fundação Petrobras de Seguridade Social - Petros

   

   1,816,119

   

   0.18%

   

   1,759,900

   

   0.18%Fundação Sistel de Seguridade Social

   

   -

   

   0.00%

   

   19,500

   

   0.00%BNDES Participações S.A.

   

   66,914,177

   

   6.74%

   

   64,842,768

   

   6.74%Antares Holdings Ltda.

   

   16,552,110

   

   1.67%

   

   16,039,720

   

   1.67%Brumado Holdings Ltda.

   

   35,604,273

   

   3.59%

   

   34,502,100

   

   3.59%Members of the Board of Directors

   

   -

   

   0.00%

   

   800

   

   0.00%Members of the Executive Board

   

   105,672

   

   0.01%

   

   102,300

   

   0.01%Other shareholders

   

   197,753,114

   

   19.91%

   

   177,899,650

   

   18.49%Total

   

   993,014,215

   

   100.00%

   

   962,274,260

   

   100.00%
  25.1Approval of capital increase and bonus in shares to be paid to shareholders – AGM/EGM At the Extraordinary General Meeting of April 29, 2015, a capital increase at CPFL Energia was approved, in order to strengthen the Company’s capital structure, through the capitalization of the Statutory Reserve for Working Capital Improvement in the amount of R$ 554,888, through the issuance of 30,739,955 common shares, which were distributed to shareholders as share bonus, pursuant to Article 169 of Law 6404/76. 25.2Capital reserves Refer basically to: (i) R$ 228,322 related to the CPFL Renováveis business combination in 2011, (ii) effect of the public offer of shares, in 2013, of the subsidiary CPFL Renováveis, as mentioned in note 15.3, amounting to R$ 59,308, as a result of the reduction of the indirect interest in CPFL Renováveis, (iii) effect of the acquisition of DESA, described in note 15.4.2, amounting to R$ 180,297 in 2014, and (iv) other movements with no change of control amounting to R$155. In accordance with IFRS 10, these effects were recognized as transactions between shareholders, directly in Equity. 25.3Earnings reserves Comprised of: i.Legal reserve, amounting to R$ 694,058; ii.Statutory reserve – concession financial asset: the distribution subsidiaries recognize in profit or loss the adjustment to the expected cash flow from the concession financial asset, however its financial realization will occur only upon the indemnity (at the end of the concession). As result, the Company recognizes a statutory reserve – concession financial asset for these amounts, supported by article 194 of Law 6404/76, until their financial realization. This statutory reserve amounts to R$ 585,451 at December 31, 2015 (R$ 330,437 at December 31, 2014). 25.4Accumulated comprehensive income The accumulated comprehensive income is comprised of: i.Deemed cost: refers to the recognition of the fair value adjustments of the deemed cost of the generating plants' property, plant and equipment, of R$ 457,491;


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ii.Private pension plan: The debt balance of R$ 272,171 refers to the effects recognized directly in comprehensive income, in accordance with IAS 19. 25.5Dividends During the year 2015 the Company declared the amount of R$ 205,423 as mandatory minimum dividends, as required by Law No. 6.404/76. 25.6Allocation of profit for the year The Company’s bylaws assure shareholders a minimum dividend of 25% of profit for the year, adjusted in accordance with the law. The proposed allocation of profit for the year is shown below:  December 31, 2015Profit for the year - Individual

   

   864,940Realization of comprehensive income

   

   26,119Prescribed dividends

   

   5,597Profit base for allocation

   

   896,656Legal reserve

   

   (43,247)Statutory reserve - concession financial asset

   

   (255,013)Statutory reserve - working capital improvement

   

   (392,972)Mandatory dividend

   

   (205,423)
  For this year, considering the current adverse economic scenario and the uncertainties regarding market projections for distribution companies, owing to energy efficiency campaigns and extraordinary increases in tariffs during 2015, Company Management is proposing allocating R$ 392,972 to the Statutory Reserve for Working capital improvement. 25.7 – Noncontrolling interests and joint ventures The disclosure of interests in subsidiaries, in accordance with IFRS 12, is as follows: 25.7.1 – Movements in non-controlling interests  CERAN

   

   CPFL Renováveis

   

   Paulista Lajeado

   

   TotalAt December 31, 2012

   205,091

   

   1,227,955

   

   77,355

   

   1,510,401Equity Interests and voting capital

   35.00%

   

   37.00%

   

   40.07%Equity attributable to noncontrolling interests

   24,380

   

   (19,851)

   

   7,088

   

   11,617Initial public offering - IPO

   -

   

   269,192

   

   -

   

   269,192Dividends

   (13,140)

   

   -

   

   (6,750)

   

   (19,890)Other movements

   -

   

   3,566

   

   (69)

   

   3,497At December 31, 2013

   216,331

   

   1,480,864

   

   77,624

   

   1,774,819Equity Interests and voting capital

   35.00%

   

   41.16%

   

   40.07%Equity attributable to noncontrolling interests

   13,145

   

   (72,782)

   

   (3,097)

   

   (62,733)Business combination

   -

   

   759,686

   

   -

   

   759,686Dividends

   (15,022)

   

   (7,417)

   

   (7,099)

   

   (29,538)Other movements

   -

   

   11,560

   

   (1)

   

   11,559At December 31, 2014

   214,454

   

   2,171,911

   

   67,427

   

   2,453,794Equity Interests and voting capital

   35.00%

   

   48.39%

   

   40.07%Equity attributable to noncontrolling interests

   25,990

   

   (20,611)

   

   4,958

   

   10,337Dividends

   (6,173)

   

   (2,818)

   

   843

   

   (8,147)Other movements

   -

   

   7

   

   (48)

   

   (41)At December 31, 2015

   234,271

   

   2,148,490

   

   73,182

   

   2,455,942Equity Interests and voting capital

   35.00%

   

   48.39%

   

   40.07%


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25.7.2 – Summarized financial information of subsidiaries that have interests of noncontrolling shareholders  The summarized financial information on subsidiaries in which there is noncontrolling interests at December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013 are as follows:  December 31, 2015

   

   CERAN

   

   CPFL Renováveis

   

   Paulista LajeadoCurrent assets

   

   203,205

   

   1,296,420

   

   39,916Cash and cash equivalents

   

   154,845

   

   871,503

   

   30,907Noncurrent assets

   

   997,049

   

   10,607,682

   

   126,147Current liabilities

   

   128,920

   

   1,174,865

   

   16,515Financial liabilities

   

   101,347

   

   929,758

   

   6,889Noncurrent liabilities

   

   401,988

   

   6,425,440

   

   40,908Financial liabilities

   

   401,988

   

   5,151,163

   

   40,908Equity

   

   669,346

   

   4,303,797

   

   108,639Equity attributable to owners of the Company

   

   669,346

   

   4,176,063

   

   108,639Equity attributable to noncontrolling interests

   

   -

   

   127,734

   

   -Net operating revenue

   

   281,374

   

   1,499,356

   

   31,225Depreciation and amortization

   

   (45,986)

   

   (540,578)

   

   (7)Interest income

   

   17,532

   

   115,639

   

   2,243Interest expense

   

   (40,801)

   

   (551,407)

   

   (1,206)Income tax expense

   

   (38,381)

   

   (49,221)

   

   (2,843)Profit (loss) for the year

   

   74,256

   

   (48,717)

   

   12,374Attributable to owners of the Company

   

   74,256

   

   (54,447)

   

   12,374Attributable to noncontrolling interests

   

   -

   

   5,730

   

   -Equity Interests and voting capital

   

   35.00%

   

   48.39%

   

   40.07%December 31, 2014

   

   CERAN

   

   CPFL Renováveis

   

   Paulista LajeadoCurrent assets

   

   138,684

   

   1,166,223

   

   13,756Cash and cash equivalents

   

   84,201

   

   828,411

   

   328Noncurrent assets

   

   1,040,545

   

   10,469,653

   

   116,751Current liabilities

   

   129,255

   

   1,019,960

   

   35,315Financial liabilities

   

   108,355

   

   786,660

   

   9,388Noncurrent liabilities

   

   437,249

   

   6,273,418

   

   -Financial liabilities

   

   437,249

   

   4,972,544

   

   -Equity

   

   612,726

   

   4,342,498

   

   95,192Equity attributable to owners of the Company

   

   612,726

   

   4,230,497

   

   95,192Equity attributable to noncontrolling interests

   

   -

   

   112,001

   

   -Net operating revenue

   

   327,066

   

   1,247,627

   

   42,771Depreciation and amortization

   

   (50,017)

   

   (432,267)

   

   (6)Interest income

   

   11,604

   

   87,131

   

   656Interest expense

   

   (40,441)

   

   (418,141)

   

   -Income tax expense

   

   (18,880)

   

   (33,645)

   

   (2,691)Profit (loss) for the year

   

   37,558

   

   (167,362)

   

   (7,728)Attributable to owners of the Company

   

   37,558

   

   (168,771)

   

   (7,728)Attributable to noncontrolling interests

   

   -

   

   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.


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December 31, 2013

   

   CERAN

   

   CPFL Renováveis

   

   Paulista LajeadoNet operating revenue

   

   270,511

   

   1,018,612

   

   65,641Depreciation and amortization

   

   (47,050)

   

   (348,355)

   

   (6)Interest income

   

   5,928

   

   46,793

   

   615Interest expense

   

   (44,957)

   

   (305,051)

   

   -Income tax expense

   

   (34,884)

   

   (10,607)

   

   (8,044)Profit (loss) for the year

   

   69,657

   

   (55,017)

   

   17,693Attributable to owners of the Company

   

   69,657

   

   (54,947)

   

   17,693Attributable to noncontrolling interests

   

   -

   

   (70)

   

   -Equity Interests and voting capital

   

   35.00%

   

   41.16%

   *

   40.07%* The net equity to noncontrolling shareholders until June, 2013, was 37%.
   ( 26 )EARNINGS PER SHARE
 Earnings per share – basic and diluted The calculation of the basic and diluted earnings per share at December 31, 2015, 2014 and 2013 was based on the profit attributable to controlling shareholders and the weighted average number of common shares outstanding during the reporting years. For diluted earnings per share, the calculation considered the dilutive effects of instruments convertible into shares, as shown below:  December 31, 2015

   

   December 31, 2014

   

   December 31, 2013NumeratorProfit attributable to controlling shareholders

   

   864,940

   

   949,177

   

   937,419DenominatorWeighted average number of shares held by shareholders

   

   993,014,215

   (**)

   993,014,215

   (**)

   962,274,260Earnings per share - basic

   

   0.87

   

   0.96

   

   0.97NumeratorProfit attributable to controlling shareholders

   

   864,940

   

   949,177

   

   937,419Dilutive effect of convertible debentures of subsidiary CPFL Renováveis (*)

   

   (19,811)

   

   (17,265)

   

   (25,016)Profit attributable to controlling shareholders

   

   845,129

   

   931,912

   

   912,403DenominatorWeighted average number of shares held by shareholders

   

   993,014,215

   (**)

   993,014,215

   (**)

   962,274,260Earnings per share - diluted

   

   0.85

   

   0.94

   

   0.95
  (*) Proportional to the percentage of the Company's interest in the subsidiary in the respective years. (**) Considers the event occurred on April 29, 2015, related to the capital increase through the issuance of 30,739,955 shares (note 25.1). In accordance with IAS 33, when there is an increase in the number of shares without an increase in capital, the number of shares is adjusted as if the event had occurred at the beginning of the latest reporting period.  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 indirect subsidiary CPFL Renováveis. The 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 effects calculated in the denominator of indirect subsidiary CPFL Renováveis for calculation of diluted earnings per share resulting from the subsidiary’s share-based payment plan were considered anti-dilutive in 2015, 2014 and 2013. For this reason, these effects were not included in the calculation for each year.




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( 27 )NET OPERATING REVENUE
  Number of Consumers (*)

   

   In GWh (*)

   

   R$ thousandRevenue from Electric Energy Operations

   

   2015

   

   2014

   

   2013

   

   2015

   

   2014

   

   2013

   

   2015

   

   2014

   

   2013Consumer classResidential

   

   6,906,580

   

   6,732,715

   

   6,523,553

   

   16,164

   

   16,501

   

   15,426

   

   9,833,419

   

   6,533,590

   

   5,710,050Industrial

   

   55,586

   

   56,920

   

   58,565

   

   12,748

   

   14,144

   

   14,691

   

   5,526,967

   

   3,871,868

   

   3,605,079Commercial

   

   473,333

   

   483,204

   

   491,057

   

   9,259

   

   9,437

   

   8,837

   

   5,266,432

   

   3,471,225

   

   2,956,069Rural

   

   245,238

   

   243,275

   

   245,687

   

   2,152

   

   2,326

   

   2,081

   

   750,209

   

   496,790

   

   415,075Public Administration

   

   51,359

   

   50,538

   

   49,443

   

   1,278

   

   1,295

   

   1,234

   

   674,530

   

   476,557

   

   407,094Public Lighting

   

   10,362

   

   9,917

   

   9,596

   

   1,649

   

   1,622

   

   1,586

   

   573,219

   

   315,072

   

   284,346Public Services

   

   8,402

   

   8,155

   

   7,961

   

   1,797

   

   1,861

   

   1,820

   

   879,288

   

   566,719

   

   486,609(-) Adjustment of revenues from excess demand and excess reactive power

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (79,362)

   

   (84,017)

   

   (59,731)Billed

   

   7,750,860

   

   7,584,724

   

   7,385,862

   

   45,049

   

   47,187

   

   45,675

   

   23,424,701

   

   15,647,804

   

   13,804,591Own comsuption

   

   -

   

   -

   

   -

   

   33

   

   34

   

   34

   

   -

   

   -

   

   -Unbilled (Net)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   202,726

   

   63,142

   

   73,536Emergency Charges - ECE/EAEE

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   3

   

   2

   

   (254)(-) Reclassification to Network Usage Charge - TUSD - Captive Consumers

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (8,118,085)

   

   (5,464,570)

   

   (5,287,096)Electricity sales to final consumers

   

   7,750,860

   

   7,584,724

   

   7,385,862

   

   45,082

   

   47,221

   

   45,709

   

   15,509,345

   

   10,246,379

   

   8,590,776Furnas Centrais Elétricas S.A.

   

   

   

   

   

   

   

   3,026

   

   3,026

   

   3,026

   

   485,846

   

   477,775

   

   441,961Other Concessionaires and Licensees

   

   

   

   

   

   

   

   10,656

   

   9,628

   

   10,918

   

   2,223,339

   

   1,690,711

   

   1,874,482(-) Reclassification to Network Usage Charge - TUSD - Captive Consumers

   

   

   

   -

   

   -

   

   -

   

   (46,982)

   

   -

   

   -Spot market energy

   

   

   

   

   

   

   

   4,289

   

   2,334

   

   1,031

   

   875,002

   

   976,377

   

   205,976Electricity sales to wholesalers

   

   

   

   

   

   

   

   17,971

   

   14,988

   

   14,975

   

   3,537,205

   

   3,144,864

   

   2,522,419Revenue due to network usage charge - TUSD - captive consumers

   

   

   

   

   

   

   

   

   

   

   

   8,165,066

   

   5,464,570

   

   5,287,096Revenue due to network usage charge - TUSD - free consumers

   

   

   

   

   

   

   

   

   

   

   

   1,898,138

   

   990,815

   

   965,737(-) Adjustment of revenues from excess demand and excess reactive power

   

   

   

   

   

   

   

   

   

   (16,884)

   

   (18,045)

   

   (14,587)Revenue from construction of concession infrastructure

   

   

   

   

   

   

   

   

   

   

   

   1,046,669

   

   944,997

   

   1,004,399Sector financial asset and liability (Note 8)

   

   

   

   

   

   

   

   

   

   

   

   

   

   2,506,524

   

   910,720

   

   -Amounts from energy development account - CDE

   

   

   

   

   

   

   

   

   

   

   

   

   

   895,538

   

   771,018

   

   627,832Other revenues and income

   

   

   

   

   

   

   

   

   

   

   

   

   

   367,356

   

   341,061

   

   355,694Other operating revenues

   

   

   

   

   

   

   

   

   

   

   

   

   

   14,862,408

   

   9,405,136

   

   8,226,172Total gross operating revenue

   

   

   

   

   

   

   

   

   

   

   

   

   

   33,908,958

   

   22,796,379

   

   19,339,367Deductions from operating revenueICMS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (4,686,039)

   

   (3,106,928)

   

   (2,777,486)PIS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (529,322)

   

   (335,937)

   

   (271,301)COFINS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (2,438,208)

   

   (1,547,783)

   

   (1,247,439)ISS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (8,204)

   

   (7,583)

   

   (5,545)Global reversal reserve - RGR

   

   

   

   

   

   

   

   

   

   

   

   

   

   (2,529)

   

   (2,362)

   

   (3,791)Fuel consumption account - CCC

   

   

   

   

   

   

   

   

   

   

   

   

   

   -

   

   -

   

   (34,432)Energy development account - CDE

   

   

   

   

   

   

   

   

   

   

   

   

   

   (3,970,013)

   

   (271,577)

   

   (155,249)Research and development and energy efficiency programs

   

   

   

   

   

   

   

   

   

   

   

   

   

   (158,516)

   

   (117,683)

   

   (111,243)PROINFA

   

   

   

   

   

   

   

   

   

   

   

   

   

   (90,910)

   

   (100,569)

   

   (99,244)Emergency charges - ECE/EAEE

   

   

   

   

   

   

   

   

   

   

   

   

   

   (1,796,226)

   

   (2)

   

   253IPI

   

   

   

   

   

   

   

   

   

   

   

   

   

   (100)

   

   (10)

   

   (34)FUST and FUNTEL

   

   

   

   

   

   

   

   

   

   

   

   

   

   (24)

   

   (2)

   

   -Inspection fee

   

   

   

   

   

   

   

   

   

   

   

   

   

   (22,997)

   

   -

   

   -(13,703,089)

   

   (5,490,436)

   

   (4,705,511)Net operating revenue

   

   

   

   

   

   

   

   

   

   

   

   

   

   20,205,869

   

   17,305,942

   

   14,633,856(*) Information not audited by the independent auditors
 27.1Adjustment of revenues from excess demand and excess reactive power The tariff regulation procedure (“Proret”), approved by ANEEL Normative Resolution No. 463 of November 22, 2011, determined that revenues received as a result of excess demand and excess reactive power, from the contractual tariff review date for the 3rd periodic tariff review cycle, should be accounted for as special obligations and would be amortized from the next tariff review. For subsidiary CPFL Piratininga, based on the 4th periodic tariff review cycle, as from May 2015 and for the subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista and CPFL Mococa, as from September 2015, due to the 4thperiodic tariff review cycle, such special obligation began to be amortized and the new amounts resulting from capping of demand and excess of reagents began to be appropriated in sector financial assets and liabilities, and they will only be amortized upon ratification of the 5th cycle of periodic tariff revision. 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 Normative Resolution No. 463, whereby the request for preliminary injunction relief was granted and the order to account for revenues from excess demand and excess reactive power as special obligations was suspended. The suspensive effect required by ANEEL in its interlocutory appeal was granted in June 2012 and the preliminary injunction relief originally granted in favor of ABRADEE was suspended. The subsidiaries are awaiting the court’s decision on the final treatment of these revenues. At December 31, 2015, these amounts are accrued under Special Obligations, in compliance with IAS 37, presented net in concession intangible asset. 27.2Extraordinary Tariff Review (“RTE”)


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On February 27, 2015, the ANEEL approved the result of the Extraordinary Tariff Revision (RTE) in order to re-establish the tariff coverage for electric energy distributors given the significant increase in the CDE quota for 2015 and the cost of purchasing electric energy (Itaipú tariff and exchange variation, and auctions of existing electric power and of adjustment). The tariffs resulting from this RTE were in effect from March 2, 2015 up to the date of the next readjustment or tariff revision for each distributor. With respect to subsidiaries CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari, CPFL Mococa and CPFL Santa Cruz, on April 7, 2015, by means of Ratification Resolution No. 1,870, the ANEEL adjusted the result of the RTE of February 27, in order to change the amount of the monthly CDE quota – Energy relating to the ACR account, intended for amortization of credit operations by the CCEE in management of the ACR account. The tariffs resulting from such adjustment or rectification are in effect as from April 8, 2015 up to the date of the next tariff revision for each distributor. The average effects for the distributors’ consumers were: Effect perceived by consumers (*)Subsidiary

   

   Total

   

   Group A

   

   Group BCPFL Paulista

   

   32.28%

   

   40.05%

   

   27.27%CPFL Piratininga

   

   29.78%

   

   40.49%

   

   21.47%RGE

   

   37.16%

   

   43.46%

   

   33.04%CPFL Santa Cruz

   

   5.16%

   

   5.70%

   

   4.86%CPFL Leste Paulista

   

   14.52%

   

   20.06%

   

   12.39%CPFL Jaguari

   

   16.80%

   

   18.48%

   

   13.25%CPFL Sul Paulista

   

   17.02%

   

   32.42%

   

   9.09%CPFL Mococa

   

   11.81%

   

   18.22%

   

   9.48%(*) Information not audited by the independent auditors
  27.3Periodic tariff review (“RTP”) and Annual tariff adjustment (“RTA”)  2015

   

   2014

   

   2013Subsidiary

   

   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

   

   41.45%

   

   4,67% (b)

   

   17.18%

   

   17.23%

   

   5.48%

   

   6.18%CPFL Piratininga

   

   October

   

   56.29%

   

   21,11% (b)

   

   19.73%

   

   22.43%

   

   7.42%

   

   6.91%RGE

   

   June

   

   33.48%

   

   -3,76% (b)

   

   21.82%

   

   22.77%

   

   -10.32%

   

   -10.64%CPFL Santa Cruz

   

   February (c)

   

   34.68%

   

   27.96%

   

   14.86%

   

   26.00%

   

   9.32%

   

   -0.94%CPFL Leste Paulista

   

   February (c)

   

   20.80%

   

   24.89%

   

   -7.67%

   

   -5.32%

   

   6.48%

   

   3.36%CPFL Jaguari

   

   February (c)

   

   38.46%

   

   45.70%

   

   -3.73%

   

   3.70%

   

   2.71%

   

   2.68%CPFL Sul Paulista

   

   February (c)

   

   24.88%

   

   28.38%

   

   -5.51%

   

   0.43%

   

   2.27%

   

   2.21%CPFL Mococa

   

   February (c)

   

   23.34%

   

   29.28%

   

   -2.07%

   

   -9.53%

   

   7.00%

   

   5.10%
  (a)Represents the average effect perceived by consumers, as a result of the elimination from the tariff base of financial components that had been added in the prior tariff adjustment (information not audited by the independent auditors). (b)Consumer perception in comparison to the Extraordinary Tariff Revision (RTE) described in note 27.2. (c)On February 3, 2016, ANEEL changed the RTA date of these subsidiaries, which will now be held on March 22 (note 38.3).  27.4Energy Development Account (CDE) – low-income and other tariff discounts Law No. 12,783 of January 11, 2013 determined that the amounts related to the low-income subsidy, as well as other tariff discounts shall be fully subsidized by amount from the CDE. Income of R$ 895,538 was recognized in 2015 (R$ 771,018 in 2014 and R$ 627,832 in 2013), of which R$ 66,313 for the low-income subsidy (R$ 78,028 in 2014 and R$ 69,231 in 2013) and R$ 829,225 for other tariff discounts (R$ 692,990 in 2014 and R$ 558,600 in 2013), against other receivables in line item “Other Receivables – Energy Development Account – CDE/CCEE” (note 12) and “Other Payables – Tariff discounts – CDE” (note 24). 27.5Tariff flags The system for application of Tariff Flags was created by means of Normative Resolution No. 547/2013, in effect as from January 1, 2015. Such mechanism can reflect the actual cost of the conditions for generation of electric energy in Brazil, mainly related to thermoelectric generation, energy security ESS, hydrologic risk and


involuntary exposure of electric energy distributors. The green flag indicates favorable conditions and the tariff does not rise. The yellow flag indicates less favorable conditions, and the red flag is set off in costlier conditions. In the latter cases, the tariff increases R$ 2.50 and R$ 5.50 (before tax effects), respectively, for each 100 KWh consumed, readjusted by means of Ratification Resolution (“REH”) No. 1,859/2015 as from March 1, 2015. In addition, as from September 1, 2015, as per REH No. 1,945/2015, the red flag tariff was altered to R$ 4.50 for every 100 KWh consumed.


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In 2015, the distribution subsidiaries billed their consumers the amount of R$ 1,796,226 in terms of tariff flags, recorded in line item "Tariff flags and others”. Out of this amount, after ratification by the ANEEL, R$ 1,297,717 was used to offset part of the sector financial assets (note 8), R$ 194,428 was passed on to the Centralizing Account for Tariff Flag Resources (“CCRBT”), created by means of Decree No. 8,401/2015 and administered by the CCEE, and R$ 304,079 continues outstanding, recorded under liabilities – regulatory fees (note 20). Furthermore, the CCRBT, created by means of Decree No. 8,401/2015 and administered by the CCEE, ratified the amount receivable of R$ 90,794 by subsidiary RGE, received in full by December 31, 2015. 27.6Energy Development Account – CDE By means of Ratification Resolution No. 1,857 of February 27, 2015, the ANEEL established the definitive annual quotas of the CDE for the year 2015. This quota comprises: (i) annual quota of the CDE – Usage account; and (ii) CDE – Energy quota, related to part of the CDE contributions received by the electric energy distribution concessionaires in the period from January 2013 to January 2014 (note 28), which should be paid by consumers and passed on to the CDE in up to five years as from the 2015 RTE. In addition, by means of Ratification Resolution No. 1,863 of March 31, 2015, the ANEEL established another quota intended for amortization of the ACR account (note 28), with payment and transfer to the CDE for an average period of five years as from the ordinary tariff process (RTA or RTP) for the year 2015.  ( 28 )COST OF ELECTRIC ENERGY
  In GWh (*)

   

   R$ thousandElectricity purchased for resale

   2015

   

   2014

   

   2013

   

   2015

   

   2014

   

   2013Itaipu Binacional

   10,261

   

   10,417

   

   10,719

   

   2,869,481

   

   1,383,604

   

   1,298,210Spot market

   2,946

   

   5,074

   

   2,974

   

   724,203

   

   3,018,523

   

   726,936PROINFA

   1,058

   

   1,043

   

   1,019

   

   256,806

   

   264,068

   

   233,152Energy purchased through auction in the regulated market and bilateral contracts

   44,342

   

   42,345

   

   42,980

   

   9,192,868

   

   8,837,459

   

   6,786,524Energy development account - CDE/CCEE

   -

   

   -

   

   -

   

   -

   

   (2,340,912)

   

   (827,578)PIS and COFINS credit

   -

   

   -

   

   -

   

   (1,196,579)

   

   (1,005,106)

   

   (748,526)Subtotal

   58,607

   

   58,879

   

   57,692

   

   11,846,779

   

   10,157,635

   

   7,468,718Electricity network usage chargeBasic network charges

   

   

   

   

   

   

   847,342

   

   727,341

   

   559,631Transmission from Itaipu

   

   

   

   

   

   

   51,236

   

   37,896

   

   34,716Connection charges

   

   

   

   

   

   

   56,312

   

   44,834

   

   44,470Charges for use of the distribution system

   

   

   

   

   

   

   40,332

   

   33,147

   

   29,542System service charges - ESS

   

   

   

   

   

   

   555,851

   

   (326,248)

   

   554,865Reserve energy charges

   

   

   

   

   

   

   54,762

   

   10,898

   

   33,194Amounts from the energy development account - CDE

   

   

   

   

   

   

   -

   

   (1)

   

   (458,792)PIS and COFINS credit

   

   

   

   

   

   

   (140,868)

   

   (42,372)

   

   (69,655)Subtotal

   

   

   

   

   

   

   1,464,967

   

   485,495

   

   727,969Total

   

   

   

   

   

   

   13,311,747

   

   10,643,130

   

   8,196,687(*) Information not audited by the independent auditors
   28.1 Amounts from CDE/CCEE – Law No. 12,783/2013, Decrees No. 7,945/2013, No. 8,203/2014 and No. 8,221/2014 and Order No. 3,998/2014 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 spot market, due largely to allocation of the physical energy and power guarantee quotas and repeal of the plants’ authorization by ANEEL, the distributors’ energy cost increased significantly in 2012, 2013, 2014 and 2015. 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 No. 7,945, amended by Decree No. 8,203/2014 and further by Decree No. 8,221/2014, which made certain changes in the contracting of energy and the objectives of the Energy Development Account - CDE charge:


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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; and 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$ 2,340,912 was recognized in 2014 as a result of these regulations (R$ 1,286,370 in 2013). During the year 2015, no amounts were received by the subsidiaries in relation to this transfer. The effects of these items were recognized as a reduction of the cost of electric energy under Amounts from CDE/CCEE against other receivables under Receivables – Energy Development Account – CDE/CCEE (note 12), in accordance with IAS 20 Accounting for Government Grants and Disclosure of Government Assistance. In addition to the amounts from CDE, the Company is receiving, through the CCEE, the financial excess of the Energy Reserve Account - CONER, regulated by REN 613/2014. The amount of R$ 107,827 is recognized in line item "System service charge – ESS" in 2015 (R$ 437,297 in 2014). In the tariff review of April 2013 for the subsidiary CPFL Paulista, through Order No. 1,144/2013, ANEEL granted full coverage of the positive amounts of CVA calculated on energy purchased and the ESS charge for 2012, as well as positive amounts of CVA for energy purchased in the availability auction, related to January 2013. In the tariff review of October 2013 for the subsidiary CPFL Piratininga, through Resolution No. 1,638/2013, ANEEL granted partial coverage of the positive amounts of CVA calculated on energy purchased and the ESS charge for October 2012 to October 2013. There were no resources provided by the CDE recognized in the year ended December 31, 2015. The table below shows the summary of the amounts from CDE per distributor controlled by the Company, recognized in the years ended December 31, 2014 and 2013:  2014Electricity purchased for resaleInvoluntary exposure

   

   Quotas and hydrological risk

   

   Electricity purchased - regulated market

   

   System service charges - ESS

   

   TotalCPFL Paulista

   849,901

   

   (6,241)

   

   229,335

   

   6

   

   1,073,001CPFL Piratininga

   391,476

   

   (357)

   

   354,079

   

   2

   

   745,200CPFL Santa Cruz

   66,403

   

   13

   

   20,344

   

   -

   

   86,760CPFL Leste Paulista

   6,580

   

   4

   

   (4)

   

   (10)

   

   6,570CPFL Sul Palista

   6

   

   5

   

   11

   

   -

   

   22CPFL Jaguari

   (1,539)

   

   (48)

   

   2,001

   

   -

   

   414CPFL Mococa

   -

   

   2

   

   -

   

   -

   

   2RGE

   428,054

   

   (98)

   

   986

   

   3

   

   428,945Total

   1,740,881

   

   (6,720)

   

   606,752

   

   1

   

   2,340,913
    2013Electricity purchased for resale

   

   Electricity network usage chargeInvoluntary exposure

   

   Quotas and hydrological risk

   

   Electricity purchased - tariff review

   

   System service charges - ESS

   

   System service charges - ESS - tariff review

   

   TotalCPFL Paulista

   161,087

   

   10,868

   

   327,252

   

   217,464

   

   44,207

   

   760,878CPFL Piratininga

   76,735

   

   395

   

   167,901

   

   88,166

   

   (122)

   

   333,076CPFL Santa Cruz

   8,689

   

   (28)

   

   15,514

   

   16,082

   

   (5,323)

   

   34,934CPFL Leste Paulista

   1,092

   

   (6)

   

   -

   

   6,487

   

   -

   

   7,573CPFL Sul Palista

   -

   

   (11)

   

   -

   

   3,621

   

   -

   

   3,610CPFL Jaguari

   2,537

   

   98

   

   -

   

   4,631

   

   -

   

   7,267CPFL Mococa

   -

   

   (6)

   

   -

   

   2,717

   

   -

   

   2,711RGE

   53,593

   

   (287)

   

   2,153

   

   72,310

   

   8,553

   

   136,321Total

   303,733

   

   11,023

   

   512,820

   

   411,478

   

   47,316

   

   1,286,370
   28.2 Generating Scaling Factor (“GSF”)


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The hydroelectric power plants (UHE’s) and some small hydroelectric plants (PCH’s) hooked up to the National Interconnected System (“SIN”) participate in the Energy Reallocation Mechanism (“MRE”), which functions as a water risks pool for such plants, since plants generate energy at the command of the National System Operator (”ONS”) and/or availability of water in the reservoirs. In other words, they have no direct control over the timing and amount of water for generation of energy. Participation in this mechanism is proportional to the Physical Guarantee of each plant, which also constitutes the energy sale contract limit for each plant. When the group of plants in the MRE generates more energy than the sum of their physical guarantees, denominated Secondary Energy, this excess is settled at the Difference Settlement Price (“PLD”) and prorated among the participating plants in proportion to their physical guarantees. On the other hand, if the generation of the group of plants is less than the sum of their physical guarantees, there will be a Generating Scaling Factor (“GSF”), with this power deficit also allocated in proportion to the physical guarantee of each plant and thus exposing it to the spot market, with the energy shortfall being valued at the PLD. In the years from 2005 to 2012, the annual GSF of the MRE was above 100%, thus not burdening the hydroelectric power generators. Beginning in 2013, however, this scenario began to change, and became aggravated in the years 2014 and 2015, when it was below 100% throughout the year. Renegotiation of the Hydrologic Risk for 2015 Law No. 13,203 of December 8, 2015 and ANEEL Normative Resolution No. 684 of December 11, 2015, established the conditions for renegotiation of the hydrologic risk for generation of electric energy for the agents participating in the MRE, with effect beginning in January 2015, attributing distinct rules for the contracts signed in the Regulated Contracting Environment (“ACR”) and the Free Contracting Environment (“ACL”). The renegotiation of the hydrologic risk of the portion relating to the ACR came about through transfer of the hydrologic risk (i.e.supply of water in reservoirs) to consumers by means of payment of a risk premium by the hydroelectric power generators of R$ 9.50/MWh up to the end of the contracts for sale of electric power or the end of the concession, whichever period is shorter. Payment of this premium and the GSF transfer will go to the Centralizing Account for Tariff Flag Resources (“CCRBT”). For the portion of the hydrologic risk relating to the ACL, the risk will be mitigating by the purchase of Reserve Energy, with the rights and obligations associated with this acquisition assumed by the hydroelectric power generators. In this case, the risk premium for the price was equivalent to R$ 2.10/MWh for the energy reserve intended for its use, which will be contributed to the Reserve Energy Account (CONER). The generators that adhered to the renegotiation should terminate the lawsuits against the grantor of the concessions, and pay a premium of risk related to the transfer of the GSF risk to CCRBT for 2015. In December 2015, subsidiaries Ceran, CPFL Jaguari Geração (Paulista Lajeado) and CPFL Renováveis, as well as joint ventures ENERCAN and Chapecoense signed on to the renegotiation of their ACR contracts, and also cancelled their lawsuits. Therefore, the hydrological risks were transferred to the CCRBT.




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( 29 )OPERATING COSTS AND EXPENSES
  2015Cost of operation

   

   Cost of services rendered to third parties

   

   Operating expenses

   

   TotalSelling

   

   General andadministrative

   

   OthersPersonnel

   596,021

   

   28

   

   123,812

   

   219,348

   

   -

   

   939,209Private pension plans

   60,184

   

   -

   

   -

   

   -

   

   -

   

   60,184Materials

   123,853

   

   1,008

   

   5,249

   

   9,825

   

   -

   

   139,935Third party services

   187,080

   

   2,777

   

   128,022

   

   241,115

   

   -

   

   558,994Depreciation and amortization

   870,427

   

   -

   

   21,826

   

   84,985

   

   -

   

   977,238Cost of infrastructure construction

   -

   

   1,045,301

   

   -

   

   -

   

   -

   

   1,045,301Others

   69,633

   

   (12)

   

   185,673

   

   308,226

   

   357,653

   

   921,173Collection fees

   -

   

   -

   

   56,990

   

   -

   

   -

   

   56,990Allowance for doubtful debts

   -

   

   -

   

   126,879

   

   -

   

   -

   

   126,879Leases and rentals

   31,687

   

   -

   

   (4)

   

   16,874

   

   -

   

   48,558Publicity and advertising

   339

   

   -

   

   34

   

   9,565

   

   -

   

   9,938Legal, judicial and indemnities

   10

   

   -

   

   -

   

   263,453

   

   -

   

   263,463Donations, contributions and subsidies

   -

   

   -

   

   16

   

   3,418

   

   -

   

   3,434Gain (loss) on disposal, retirement and other noncurrent assets

   -

   

   -

   

   -

   

   -

   

   16,309

   

   16,309Amortization of concession intangible asset

   -

   

   -

   

   -

   

   -

   

   302,665

   

   302,665Financial compensation for use of water resources

   13,768

   

   -

   

   -

   

   -

   

   -

   

   13,768Impairment

   -

   

   -

   

   -

   

   -

   

   38,956

   

   38,956Others

   23,829

   

   (12)

   

   1,759

   

   14,916

   

   (277)

   

   40,214Total

   1,907,197

   

   1,049,101

   

   464,583

   

   863,499

   

   357,653

   

   4,642,033
   2014Cost of operation

   

   Cost of services rendered to third parties

   

   Operating expenses

   

   TotalSelling

   

   General andadministrative

   

   OthersPersonnel

   528,056

   

   2

   

   110,759

   

   213,654

   

   -

   

   852,471Private pension plans

   48,165

   

   -

   

   -

   

   -

   

   -

   

   48,165Materials

   102,959

   

   1,286

   

   4,658

   

   8,925

   

   -

   

   117,827Third party services

   172,422

   

   2,511

   

   109,264

   

   241,826

   

   -

   

   526,022Depreciation and amortization

   767,117

   

   -

   

   32,049

   

   75,779

   

   -

   

   874,946Cost of infrastructure construction

   -

   

   942,267

   

   -

   

   -

   

   -

   

   942,267Others

   53,640

   

   (13)

   

   145,968

   

   233,446

   

   328,000

   

   761,041Collection fees

   264

   

   -

   

   54,070

   

   -

   

   -

   

   54,334Allowance for doubtful debts

   -

   

   -

   

   83,699

   

   -

   

   -

   

   83,699Leases and rentals

   29,331

   

   -

   

   -

   

   15,627

   

   -

   

   44,958Publicity and advertising

   736

   

   -

   

   127

   

   17,262

   

   -

   

   18,125Legal, judicial and indemnities

   -

   

   -

   

   -

   

   192,464

   

   -

   

   192,464Donations, contributions and subsidies

   -

   

   -

   

   6,579

   

   4,204

   

   -

   

   10,783Inspection fee

   -

   

   -

   

   -

   

   -

   

   20,894

   

   20,894Gain (loss) on disposal, retirement and other noncurrent assets

   -

   

   -

   

   -

   

   -

   

   20,726

   

   20,726Amortization of concession intangible asset

   -

   

   -

   

   -

   

   -

   

   285,018

   

   285,018Financial compensation for use of water resources

   14,835

   

   -

   

   -

   

   -

   

   -

   

   14,835Others

   8,474

   

   (13)

   

   1,493

   

   3,889

   

   1,361

   

   15,204Total

   1,672,359

   

   946,052

   

   402,698

   

   773,630

   

   328,000

   

   4,122,739
 2013Cost of operation

   

   Cost of services rendered to third parties

   

   Operating expenses

   

   TotalSelling

   

   General andadministrative

   

   OthersPersonnel

   425,349

   

   -

   

   106,111

   

   192,142

   

   -

   

   723,602Private pension plans

   61,665

   

   -

   

   -

   

   -

   

   -

   

   61,665Materials

   92,562

   

   2,661

   

   4,117

   

   6,806

   

   -

   

   106,145Third party services

   178,809

   

   2,464

   

   100,301

   

   205,450

   

   -

   

   487,024Depreciation and amortization

   664,601

   

   -

   

   33,689

   

   59,964

   

   -

   

   758,253Cost of infrastructure construction

   -

   

   1,004,399

   

   -

   

   -

   

   -

   

   1,004,399Others

   44,531

   

   (6)

   

   132,379

   

   464,253

   

   285,148

   

   926,304Collection fees

   -

   

   -

   

   52,372

   

   -

   

   -

   

   52,372Allowance for doubtful debts

   -

   

   -

   

   70,324

   

   -

   

   -

   

   70,324Leases and rentals

   26,181

   

   -

   

   11

   

   12,390

   

   -

   

   38,582Publicity and advertising

   871

   

   -

   

   212

   

   13,179

   

   -

   

   14,262Legal, judicial and indemnities

   -

   

   -

   

   -

   

   429,883

   

   -

   

   429,883Donations, contributions and subsidies

   -

   

   -

   

   8,003

   

   3,935

   

   -

   

   11,938Inspection fee

   -

   

   -

   

   -

   

   -

   

   27,422

   

   27,422Gain (loss) on disposal, retirement and other noncurrent assets

   -

   

   -

   

   -

   

   -

   

   (39,253)

   

   (39,253)Amortization of concession intangible asset

   -

   

   -

   

   -

   

   -

   

   296,977

   

   296,977Financial compensation for use of water resources

   10,515

   

   -

   

   -

   

   -

   

   -

   

   10,515Others

   6,963

   

   (6)

   

   1,457

   

   4,866

   

   2

   

   13,282Total

   1,467,516

   

   1,009,518

   

   376,597

   

   928,614

   

   285,148

   

   4,067,393




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( 30 )FINANCE INCOME (COSTS)
  2015

   

   2014

   

   2013Finance incomeIncome from financial investments

   472,745

   

   430,714

   

   316,617Late payment interest and fines

   215,923

   

   146,992

   

   143,429Adjustment for inflation of tax credits

   57,580

   

   25,309

   

   8,425Adjustment for inflation of escrow deposits

   84,683

   

   74,500

   

   118,406Adjustment for inflation and exchange rate changes

   121,609

   

   49,144

   

   43,615Adjustment of expected cash flow (note 11)

   414,800

   

   104,642

   

   -Discount on purchase of ICMS credit

   13,027

   

   17,382

   

   21,446PIS and COFINS on other finance income

   (52,849)

   

   -

   

   -PIS and COFINS on interest on capital

   (6,941)

   

   (12,809)

   

   (15,368)Adjustments to the sector financial asset (note 8)

   162,786

   

   -

   

   -Others

   74,685

   

   54,563

   

   62,637Total

   1,558,047

   

   890,436

   

   699,208Finance costsInterest on debts

   (1,725,252)

   

   (1,542,593)

   

   (1,291,762)Adjustment for inflation and exchange rate changes

   (686,575)

   

   (247,591)

   

   (182,022)Adjustment of expected cash flow (note 11)

   -

   

   -

   

   (66,851)Adjustments to the sector financial liability (note 8)

   (1,573)

   

   -

   

   -(-) Capitalized interest

   45,568

   

   12,269

   

   57,184Use of public asset

   (16,028)

   

   (10,649)

   

   (11,690)Others

   (188,707)

   

   (191,325)

   

   (175,511)Total

   (2,572,567)

   

   (1,979,890)

   

   (1,670,651)Finance costs, net

   (1,014,520)

   

   (1,089,454)

   

   (971,443)
   Interest was capitalized at an average rate of 10.25% p.a. (8.12% p.a. in 2014 and 8.24% p.a. in 2013) on qualifying assets, in accordance with IAS 23. In line items Adjustment for inflation and exchange rate changes, the amounts include the effects of gains of R$ 1,514,439 (R$ 159,653 in 2014 and R$ 211,282 in 2013) on derivative instruments (note 35).  ( 31 )SEGMENT INFORMATION
 The segregation of the Company’s operating segments is based on the internal financial information and management structure and is made by type of business: electric energy distribution, electric energy generation (conventional and renewable sources), electric energy commercialization and services rendered activities. 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. Prices charged between segments are based on similar market transactions. Note 1 presents the subsidiaries in accordance with their areas of operation and provides further information on each subsidiary and its business area and segment. The information segregated by segment is presented below, in accordance with the criteria established by the Company’s Management:


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Distribution

   

   Generation(conventional source)

   

   Generation(renewable source)

   

   Commercialization

   

   Services

   

   Others (*)

   

   Elimination

   

   Total2015Net operating revenue

   16,551,879

   

   572,553

   

   1,262,297

   

   1,716,348

   

   55,547

   

   47,246

   

   -

   

   20,205,869(-) Intersegment revenues

   22,318

   

   411,038

   

   335,979

   

   82,544

   

   239,088

   

   3,136

   

   (1,094,101)

   

   -Income from electric energy service

   1,163,426

   

   542,738

   

   460,772

   

   124,933

   

   30,617

   

   (70,396)

   

   -

   

   2,252,090Finance income

   1,155,428

   

   110,018

   

   131,354

   

   42,840

   

   44,098

   

   74,310

   

   -

   

   1,558,047Finance cost

   (1,278,258)

   

   (549,286)

   

   (599,303)

   

   (38,386)

   

   (4,858)

   

   (102,477)

   

   -

   

   (2,572,567)Profit (loss) before taxes

   1,040,597

   

   320,354

   

   (7,176)

   

   129,386

   

   69,857

   

   (98,563)

   

   -

   

   1,454,454Income tax and social contribution

   (414,633)

   

   (37,570)

   

   (49,222)

   

   (41,282)

   

   (18,232)

   

   (18,239)

   

   -

   

   (579,177)Profit (loss) for the year

   625,964

   

   282,783

   

   (56,398)

   

   88,104

   

   51,625

   

   (116,802)

   

   -

   

   875,277Total assets (**)

   22,138,086

   

   4,575,230

   

   11,868,943

   

   714,781

   

   317,845

   

   917,586

   

   -

   

   40,532,471Purchases of PP&E and intangible assets

   868,495

   

   6,910

   

   493,584

   

   2,432

   

   39,176

   

   17,199

   

   -

   

   1,427,796Depreciation and amortization

   (587,059)

   

   (131,969)

   

   (540,578)

   

   (4,534)

   

   (12,633)

   

   (3,128)

   

   -

   

   (1,279,902)2014Net operating 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)

   

   -

   

   2,540,073Finance income

   552,918

   

   84,884

   

   98,991

   

   29,543

   

   6,380

   

   117,720

   

   -

   

   890,436Finance cost

   (849,774)

   

   (482,671)

   

   (464,713)

   

   (29,104)

   

   (10,221)

   

   (143,407)

   

   -

   

   (1,979,890)Profit (loss) before taxes

   1,305,663

   

   144,112

   

   (134,442)

   

   205,547

   

   41,230

   

   (51,806)

   

   -

   

   1,510,304Income tax and social contribution

   (461,264)

   

   (36,291)

   

   (33,645)

   

   (69,543)

   

   (12,687)

   

   (10,430)

   

   -

   

   (623,860)Profit (loss) for the year

   844,400

   

   107,820

   

   (168,087)

   

   136,003

   

   28,543

   

   (62,236)

   

   -

   

   886,444Total assets (**)

   16,724,269

   

   4,414,196

   

   11,647,374

   

   507,960

   

   828,184

   

   1,022,454

   

   -

   

   35,144,436Purchases of PP&E and intangible assets

   702,386

   

   14,419

   

   250,803

   

   3,531

   

   90,707

   

   22

   

   -

   

   1,061,868Depreciation and amortization

   (577,753)

   

   (136,447)

   

   (432,267)

   

   (4,471)

   

   (8,760)

   

   (265)

   

   -

   

   (1,159,964)2013Net operating 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)

   

   -

   

   2,369,775Finance income

   504,463

   

   40,005

   

   55,083

   

   27,665

   

   13,876

   

   58,115

   

   -

   

   699,208Finance cost

   (906,153)

   

   (338,783)

   

   (314,243)

   

   (22,601)

   

   (4,358)

   

   (84,513)

   

   -

   

   (1,670,651)Profit (loss) before taxes

   1,149,261

   

   381,874

   

   (44,410)

   

   57,123

   

   22,852

   

   (47,500)

   

   -

   

   1,519,200Income tax and social contribution

   (423,712)

   

   (69,937)

   

   (10,607)

   

   (21,399)

   

   (6,881)

   

   (37,627)

   

   -

   

   (570,164)Profit (loss) for the year

   725,549

   

   311,937

   

   (55,017)

   

   35,724

   

   15,970

   

   (85,127)

   

   -

   

   949,036Total assets (**)

   15,263,417

   

   4,515,880

   

   9,470,564

   

   342,516

   

   243,612

   

   1,206,806

   

   -

   

   31,042,796Purchases of PP&E and intangible assets

   844,804

   

   9,744

   

   827,704

   

   3,593

   

   48,646

   

   345

   

   -

   

   1,734,836Depreciation and amortization

   (564,538)

   

   (133,514)

   

   (348,355)

   

   (4,106)

   

   (4,632)

   

   (86)

   

   -

   

   (1,055,231)
   (*) Others - Refer basically to assets and transactions not related to any of the identified segments (**) Intangible assets, net of amortization, were allocated to their respective segments At December 31, 2015 a loss was recognized for impairment of the assets relating to subsidiaries CPFL Telecom and CPFL Total, in the respective amounts of R$ 33,119 and R$ 5,837, presented in the "Others” and “Services" segments, respectively.  ( 32 )RELATED PARTY TRANSACTIONS
 The Company’s controlling shareholders are as follows: ·ESC Energia S.A. Company controlled by the Camargo Corrêa group, with operations in diversified segments, such as construction, cement, footwear, textiles, aluminum and highway concessions, among others. ·Energia São Paulo Fundo de Investimento em Ações Company 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. Controlling shareholders, associates 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 balances and short-term investments–refer mainly to bank balances and short-term investments with financial institutions, as mentioned in note 5. The Company and its subsidiaries also have an Exclusive Investment Fund.


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b)Borrowings, Debentures and Derivatives– refer to borrowings from financial institutions under the conditions described in notes 17 and 18. The Company is also the guarantor of certain borrowings raised by its subsidiaries and joint ventures, as described in notes 17 and 18. c)Other Financial Transactions– the expense amounts are bank costs and collection and bookkeeping expenses. d)Purchase and sale of energy and charges -refer basically 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, when conducted in the free market, are carried out under conditions considered by the Company as similar to market conditions at the time of the trading, according to internal policies previously established by the Company’s management. When conducted in the regulated market, the prices charged are set through mechanisms established by the regulatory authority. e)Intangible assets, Property, plant and equipment, Materials and Service– refer to the purchase of equipment, cables and other materials for use in distribution and generation activities and contracting of services such as construction and information technology consultancy. f)Advances –refer to advances for investments in research and development. g)Intragroup loans –refer to (i) contracts with the joint venture EPASA, under contractual conditions of 113.5% of the CDI, maturing in January 2017; and (ii) contracts with the non-controlling shareholder of the subsidiary CPFL Renováveis, with maturity defined for the date of distribution of earnings of the indirect subsidiary to its shareholders and remuneration of 8% p.a. + 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 usual 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 Chapecoense the extension of the original maturities of the energy purchase bills, previously from July to December 2015, to January 2016. The total compensation of key management personnel in 2015was R$ 43,208 (R$ 44,214 in 2014 and R$ 33,680 in 2013). This amount comprises R$ 44,061 (R$ 39,928 in 2014 and R$ 36,382 in 2013) in respect of short-term benefits, R$ 1,087 (R$ 1,043 in 2014 and R$ 973 in 2013) of post-employment benefits and a reversal of provision of R$ 1,940 (provision of R$ 3,243 in 2014 and a reversal of provision of R$ 3,675 in 2013) for other long-term benefits, and refers to the amount recognized on an accrual basis. Transactions between related parties involving controlling shareholders, entities under common control or with significant influence and joint ventures are as follows:


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Assets

   

   Liabilities

   

   Income

   

   ExpensesDec 31, 2015

   

   Dec 31, 2014

   

   Dec 31, 2015

   

   Dec 31, 2014

   

   2015

   

   2014

   

   2013

   

   2015

   

   2014

   

   2013Bank balances and short-term investmentsBanco Bradesco (**)

   4,097,770

   

   -

   

   1

   

   -

   

   351,086

   

   -

   

   -

   

   312

   

   -

   

   -Banco do Brasil S.A.

   126,036

   

   161,832

   

   -

   

   -

   

   28,466

   

   12,126

   

   66,331

   

   4

   

   2

   

   -Borrowings, debentures and derivatives (*)Banco Bradesco (**)

   -

   

   -

   

   667,335

   

   -

   

   -

   

   -

   

   -

   

   85,505

   

   -

   

   -Banco do Brasil S.A.

   -

   

   -

   

   3,727,088

   

   4,487,092

   

   -

   

   -

   

   -

   

   459,889

   

   485,400

   

   88,646BNP Paribas (**)

   58,478

   

   -

   

   322,465

   

   -

   

   -

   

   -

   

   -

   

   8,978

   

   -

   

   -Other financial transactionsBanco Bradesco (**)

   1,344

   

   -

   

   1,259

   

   -

   

   166

   

   -

   

   -

   

   4,174

   

   -

   

   -Banco do Brasil S.A.

   -

   

   -

   

   879

   

   -

   

   80

   

   -

   

   -

   

   5,941

   

   6,304

   

   6,031Foz do Chapecó Energia S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,277ENERCAN - Campos Novos Energia S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,021AdvancesBAESA – Energética Barra Grande S.A.

   -

   

   -

   

   790

   

   826

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Foz do Chapecó Energia S.A.

   -

   

   -

   

   1,120

   

   1,170

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -ENERCAN - Campos Novos Energia S.A.

   -

   

   -

   

   1,377

   

   1,436

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -EPASA - Centrais Elétricas da Paraiba

   -

   

   -

   

   503

   

   526

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Energy purchase and sale and chargesAfluente Transmissão de Energia Elétrica S.A.

   -

   

   -

   

   27

   

   40

   

   -

   

   -

   

   -

   

   1,426

   

   1,342

   

   -Aliança Geração de Energia S.A

   -

   

   -

   

   1,364

   

   -

   

   1

   

   -

   

   -

   

   34,063

   

   -

   

   -Arizona 1 Energia Renovável S.A

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   883

   

   826

   

   -Baguari I Geração de Energia Elétrica S.A.

   -

   

   -

   

   6

   

   5

   

   -

   

   -

   

   -

   

   268

   

   252

   

   -Braskem S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   694

   

   20,916

   

   -

   

   -

   

   -Caetite 2 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   810

   

   757

   

   -Caetité 3 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   817

   

   765

   

   -Calango 1 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   977

   

   914

   

   -Calango 2 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   834

   

   782

   

   -Calango 3 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   977

   

   914

   

   -Calango 4 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   907

   

   848

   

   -Calango 5 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   963

   

   901

   

   -Companhia de Eletricidade do Estado da Bahia – COELBA

   655

   

   833

   

   -

   

   -

   

   14,491

   

   12,606

   

   12,427

   

   46

   

   -

   

   -Companhia Energética de Pernambuco - CELPE

   587

   

   920

   

   -

   

   -

   

   7,062

   

   6,304

   

   19,096

   

   206

   

   -

   

   -Companhia Energética do Rio Grande do Norte - COSERN

   227

   

   280

   

   -

   

   -

   

   2,580

   

   2,404

   

   8,125

   

   -

   

   1,063

   

   -Eldorado Brasil Celulose S.A.

   -

   

   -

   

   

   

   -

   

   -

   

   1,050

   

   -

   

   -

   

   -

   

   -Companhia Hidrelétrica Teles Pires S.A.

   -

   

   -

   

   1,548

   

   -

   

   17

   

   -

   

   -

   

   29,915

   

   -

   

   -ELEB Equipamentos Ltda

   -

   

   -

   

   -

   

   -

   

   4,036

   

   -

   

   -

   

   -

   

   -

   

   -Embraer

   -

   

   -

   

   -

   

   -

   

   26,615

   

   -

   

   -

   

   -

   

   -

   

   -Energética Águas da Pedra S.A.

   -

   

   -

   

   130

   

   117

   

   2

   

   -

   

   -

   

   4,260

   

   3,959

   

   -Estaleiro Atlântico Sul S.A.

   -

   

   -

   

   -

   

   -

   

   19,026

   

   7,584

   

   6,106

   

   -

   

   -

   

   -Fras-le

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   6

   

   -

   

   -

   

   -Goiás Sul Geração de Enegia S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   166

   

   155

   

   -InterCement Brasil S.A

   -

   

   -

   

   -

   

   -

   

   1

   

   -

   

   -

   

   -

   

   -

   

   -Itapebi Geração de Energia S.A

   -

   

   -

   

   -

   

   -

   

   1

   

   -

   

   -

   

   -

   

   -

   

   -Mel 2 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   632

   

   617

   

   -MULTINER S/A

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   207

   

   -

   

   -

   

   -NC ENERGIA S.A.

   -

   

   -

   

   -

   

   -

   

   5,336

   

   1,837

   

   22,576

   

   -

   

   -

   

   -Concessionária Auto Raposo Tavares S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   21

   

   -

   

   -

   

   -Norte Energia S.A.

   1

   

   -

   

   -

   

   -

   

   1

   

   -

   

   -

   

   -

   

   -

   

   -Rio PCH I S.A.

   -

   

   -

   

   242

   

   217

   

   -

   

   -

   

   -

   

   8,004

   

   7,441

   

   -Samarco Mineração S.A.

   -

   

   -

   

   -

   

   -

   

   1

   

   -

   

   -

   

   -

   

   -

   

   -Santista Jeanswear S/A

   -

   

   -

   

   -

   

   -

   

   4,491

   

   -

   

   -

   

   -

   

   -

   

   -SE Narandiba S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   166

   

   142

   

   -Serra do Facão Energia S.A. - SEFAC

   -

   

   -

   

   576

   

   470

   

   -

   

   -

   

   -

   

   20,916

   

   19,837

   

   -Tavex Brasil S.A

   -

   

   -

   

   -

   

   -

   

   -

   

   8,087

   

   11,368

   

   -

   

   -

   

   -Termopernambuco S.A.

   -

   

   -

   

   -

   

   -

   

   3

   

   -

   

   -

   

   -

   

   -

   

   -ThyssenKrupp Companhia Siderúrgica do Atlântico

   -

   

   -

   

   -

   

   188

   

   37,238

   

   557

   

   346

   

   6,965

   

   7,056

   

   -Vale Energia S.A.

   7,843

   

   7,371

   

   -

   

   -

   

   92,353

   

   87,077

   

   89,671

   

   -

   

   -

   

   -VALE S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   695

   

   7,483

   

   -BAESA – Energética Barra Grande S.A.

   -

   

   -

   

   88,441

   

   89,202

   

   60,080

   

   -

   

   -

   

   111,541

   

   104,491

   

   -Foz do Chapecó Energia S.A.

   -

   

   1,430

   

   142,596

   

   172,804

   

   4,996

   

   16,841

   

   3,936

   

   330,675

   

   318,140

   

   -ENERCAN - Campos Novos Energia S.A.

   667

   

   583

   

   140,496

   

   154,678

   

   23,283

   

   6,702

   

   9,376

   

   244,102

   

   226,595

   

   -EPASA - Centrais Elétricas da Paraiba

   -

   

   -

   

   19,807

   

   28,632

   

   15,243

   

   24,363

   

   75,781

   

   168,187

   

   214,978

   

   -Intangible assets, property, plant and equipment, materials and serviceBanco Bradesco S.A.(**)

   -

   

   -

   

   2

   

   -

   

   -

   

   -

   

   -

   

   19

   

   -

   

   -Banco do Brasil S A

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   170

   

   163

   

   -Barrocão Empreendimento Imobiliário SPE Ltda.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   67

   

   -

   

   -

   

   -Boa Vista Empreendimento Imobiliário SPE Ltda.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   50

   

   -

   

   -

   

   -BRASKEM Qpar S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   15

   

   -

   

   -

   

   -

   

   -CCDI 29 Empreendimento Imobiliário Ltda

   -

   

   -

   

   -

   

   -

   

   -

   

   31,500

   

   -

   

   -

   

   -

   

   -Celesc - Centrais Elétricas Sta Catarina

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,078Companhia de Saneamento Básico do Estado de São Paulo - SABESP

   65

   

   11

   

   42

   

   35

   

   1,034

   

   50

   

   1,002

   

   31

   

   4

   

   27Companhia Brasileira de Soluções e Serviços CBSS - Alelo (**)

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   576

   

   -

   

   -Companhia de Eletricidade do Estado da Bahia – COELBA

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   50

   

   -

   

   -Companhia Energética do Rio Grande do Norte - COSERN

   -

   

   -

   

   -

   

   -

   

   -

   

   19

   

   -

   

   -

   

   -

   

   -Concessionária do Sistema Anhanguera - Bandeirante S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   9

   

   -

   

   50Embraer

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   36

   

   -

   

   -

   

   -Estaleiro Atlântico Sul S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   12

   

   -

   

   -

   

   -

   

   -Ferrovia Centro-Atlântica S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,526

   

   22

   

   -

   

   -HM 11 Empreendimento Imobiliário SPE Ltda

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   9

   

   -

   

   -

   

   -HM 14 Empreendimento Imobiliário SPE Ltda

   14

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -HM 12 Empreendimento Imobiliário SPE Ltda

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   9

   

   -

   

   -

   

   -HM 25 Empreendimento Imobiliário SPE Ltda.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   63

   

   -

   

   -

   

   -HM Engenharia e Construções S.A.

   -

   

   -

   

   -

   

   -

   

   272

   

   24

   

   -

   

   -

   

   -

   

   -Hortolândia 4A Empreendimento Imobiliário SPE Ltda

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   41

   

   -

   

   -

   

   -Indústrias Romi S.A.

   -

   

   4

   

   -

   

   -

   

   68

   

   45

   

   43

   

   -

   

   -

   

   -InterCement Brasil S.A

   -

   

   -

   

   -

   

   -

   

   26

   

   60

   

   53

   

   -

   

   -

   

   -Itaúsa

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   270Jaguariúna III Empreendimento Imobiliário SPE Ltda.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   56

   

   -

   

   -

   

   -Logum Logística S.A.

   -

   

   -

   

   -

   

   -

   

   55

   

   -

   

   -

   

   -

   

   -

   

   -LUPATECH

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   2

   

   -

   

   3Mapfre Seguros Gerais S.A. (**)

   -

   

   -

   

   -

   

   -

   

   4

   

   -

   

   -

   

   1

   

   -

   

   -MRS Logística S.A

   -

   

   119

   

   -

   

   -

   

   -

   

   119

   

   168

   

   -

   

   -

   

   -Randon

   -

   

   -

   

   -

   

   76

   

   -

   

   -

   

   -

   

   -

   

   76

   

   -Rodovias Integradas do Oeste - SP Vias

   -

   

   -

   

   12

   

   -

   

   -

   

   -

   

   300

   

   -

   

   -

   

   -Samm - Soc. Atic. Multimídia Ltda

   -

   

   -

   

   -

   

   -

   

   1,463

   

   -

   

   627

   

   -

   

   -

   

   -Petrobrás Biocombustível S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   208

   

   -

   

   -

   

   -Santista Jeanswear S/A (**)

   -

   

   -

   

   -

   

   -

   

   21

   

   -

   

   -

   

   -

   

   -

   

   -TOTVS S.A.

   -

   

   -

   

   3

   

   2

   

   -

   

   -

   

   -

   

   44

   

   70

   

   2,766Ultrafértil S.A

   -

   

   149

   

   -

   

   -

   

   868

   

   226

   

   -

   

   -

   

   -

   

   -Vale Fertilizantes S.A

   39

   

   18

   

   -

   

   -

   

   45

   

   36

   

   -

   

   -

   

   -

   

   -BAESA – Energética Barra Grande S.A.

   -

   

   -

   

   -

   

   -

   

   1,354

   

   1,465

   

   1,367

   

   -

   

   -

   

   -Foz do Chapecó Energia S.A.

   -

   

   -

   

   -

   

   -

   

   1,483

   

   1,491

   

   1,499

   

   -

   

   -

   

   -ENERCAN - Campos Novos Energia S.A.

   -

   

   -

   

   -

   

   -

   

   1,354

   

   1,465

   

   1,367

   

   -

   

   -

   

   -EPASA - Centrais Elétricas da Paraíba S.A.

   1,104

   

   393

   

   -

   

   -

   

   720

   

   715

   

   5,185

   

   -

   

   -

   

   -Intragroup loansEPASA - Centrais Elétricas da Paraíba S.A.

   76,586

   

   94,385

   

   -

   

   -

   

   14,123

   

   10,629

   

   5,585

   

   -

   

   -

   

   -Noncontrolling shareholders - CPFL Renováveis

   7,680

   

   6,281

   

   -

   

   -

   

   1,475

   

   864

   

   1,041

   

   -

   

   -

   

   -Dividends and interest on capitalBAESA – Energética Barra Grande S.A.

   20

   

   96

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Chapecoense Geração S.A.

   28,417

   

   12,128

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -ENERCAN - Campos Novos Energia S.A.

   30,905

   

   24,816

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -EPASA - Centrais Elétricas da Paraiba

   29,933

   

   14,891

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -(*) Measured at amortized cost(**) Related part from January 1st, 2015




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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

   

   2015

   

   2014

   

   2013Noncurrent assets

   

   Fire, lightning, explosion, machinery breakdown, electrical damage and engeneering risk

   

   8,634,344

   

   6,810,183

   

   6,241,881Transport

   

   National transport

   

   319,834

   

   299,487

   

   634,171Stored Materials

   

   Fire, lightning, explosion and robbery

   

   171,585

   

   170,300

   

   262,883Automobiles

   

   Comprehensive cover

   

   6,544

   

   4,962

   

   5,327Civil Liability

   

   Electric energy distributors

   

   118,000

   

   168,000

   

   166,000Personnel

   

   Group life and personal accidents

   

   202,989

   

   193,020

   

   163,597Others

   

   Operational risks and others

   

   323,200

   

   279,897

   

   311,755Total

   

   

   

   9,776,496

   

   7,925,850

   

   7,785,615Information not audited by the independent auditors.
  ( 34 )RISK MANAGEMENT
 The business of the Company and its subsidiaries comprise mainly the generation, commercialization and distribution of electric energy. As public utilities concessionaires, the activities and/or tariffs of its principal subsidiaries are regulated by ANEEL. Risk management structure The Board of Directors is responsible for directing 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, overseeing the implementation of risk mitigation actions 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 actions taken; ii) the Risk Management and Internal Controls Division, responsible for coordination of the process for risk management, developing and maintaining updated methodologies for Corporate Management of Risks that involve the identification, measurement, monitoring and reporting of risks to which the CPFL Group is exposed. The risk management policy was established to identify, analyze and address 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 Groups’ 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 Processes and Risks Committee to provide guidance for the Internal Audit, Risk Management and Compliance works. The Internal Audit conducts both periodic and “ad hoc” reviews in order to ensure alignment of the processes to guidelines and strategies set by the shareholders and Management. The Fiscal Council is responsible for, among other attributions, certifying that Management has means to identify the risks on the preparation and disclosure of the financial statements to which the Company is exposed and for monitoring the effectiveness of the control environment. The main market risk factors affecting the businesses are as follows: Exchange rate risk:this risk derives from the possibility of the subsidiaries incurring losses and cash constraints due to fluctuations in exchange rates, increasing the balances of liabilities denominated in foreign currency and portion of the revenue of the joint venture ENERCAN from electric energy sale agreements with annual restatement of part of the tariff based on variation in the US$. The exposure in relation to raising funds in foreign currency is largely covered by contracting swap transactions, which allowed the Company and its subsidiaries to exchange the original risks of the transaction for the cost of the variation in the CDI. The exposure relating to the revenues of ENERCAN was hedged by contracting a zero-cost collar type of financial instrument, as described in note 35.b.1. The quantification of this risk is presented in note 35. The subsidiaries’


operations are also exposed to exchange variations on the purchase of electric energy from Itaipu. The compensation mechanism - CVA protects the subsidiaries against possible losses.


F - 82

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Interest rate Risk:this risk derives from the possibility of the Company and its subsidiaries incurring losses due to fluctuations in interest rates that increase finance costs related to borrowings and debentures. The subsidiaries have tried to increase the number of fixed rate borrowings or borrowings tied to indexes with lower rates and little fluctuation in the short and long terms. 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 managed by the sales and services segments through norms and guidelines applied in terms of the approval, guarantees required and monitoring of the operations. In the distribution segment, even though it is highly pulverized, the risk is managed through monitoring of defaults, collection measures and cutting off supply. In the generation segment there are contracts under the regulated environment (ACR) and bilateral agreements that call for the posting of guarantees. Risk of under/overcontracting from distributors:Risk inherent to the energy distribution business in the Brazilian market to which the distributors of the CPFL Group and all distributors in the market are exposed. Distributors can be prevented from fully passing through the costs of their electric energy purchases in two situations: (i) volume of energy contracted above 105% of the energy demanded by consumers and (ii) level of contracts lower than 100% of such demanded energy. In the first case, the energy contracted above 105% is sold in the CCEE and is not passed through to consumers, that is, in PLD scenarios lower than the purchase price of these contracts, there is a loss for the concession. In the second case, the distributors are required to purchase energy at the PLD price at the CCEE and do not have guarantees of full pass-through to the consumer tariffs, andthere is also a penalty for insufficiency of contractual guarantee. These situations may be mitigated if the distributors are able to justify the exposures or involuntary surpluses. Market risk of commercialization companies:This risk arises from the possibility of commercialization companies incurring losses due to variations in the spot prices that will value the positions of energy surplus or deficit of its portfolio in the free market. Risk of energy shortages: the energy sold by 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 conditions for storage of the National Interconnected System (SIN) have improved in recent months, despite the low storage levels in the Northeast sub-system. The improvement in SIN storage conditions, associated with the reduced demand verified in recent months and the availability of thermoelectric power generation, have significantly reduced the likelihood of additional load cuts. Risk of acceleration of debts: the Company has borrowing agreements and debentures with restrictive covenants normally applicable to these types of transactions, 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 set 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 tariffs set shall ensure the economic and financial equilibrium of the concession agreement at the time of the tariff review, but could result in lower adjustments than expected by the electric energy distributors. Financial instruments risk management The Company and its subsidiaries maintain operating and financial policies and strategies to protect the liquidity, safety and profitability of their assets. Accordingly, control and follow-up procedures are in place as regards 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 Luna and Bloomberg


software systems 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 a risk. The Company and its subsidiaries do not enter into transactions involving speculative derivatives.


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( 35 )FINANCIAL INSTRUMENTS
 The main financial instruments, classified in accordance with the group’s accounting practices, are:  December 31, 2015

   

   December 31, 2014Note

   

   Category

   

   Measurement

   

   Level (*)

   

   Carrying amount

   

   Fair value

   

   Carrying amount

   

   Fair valueAssetsCash and cash equivalents

   5

   

   (a)

   

   (2)

   

   Level 1

   

   4,353,488

   

   4,353,488

   

   2,593,650

   

   2,593,650Cash and cash equivalents

   5

   

   (a)

   

   (2)

   

   Level 2

   

   1,329,314

   

   1,329,314

   

   1,763,805

   

   1,763,805Securities

   

   

   (a)

   

   (2)

   

   Level 1

   

   23,633

   

   23,633

   

   5,324

   

   5,324Derivatives

   35

   

   (a)

   

   (2)

   

   Level 2

   

   2,269,932

   

   2,269,932

   

   608,176

   

   608,176Derivatives - Zero-cost collar

   35

   

   (a)

   

   (2)

   

   Level 3

   

   8,820

   

   8,820

   

   -

   

   -Concession financial asset - distribution

   11

   

   (b)

   

   (2)

   

   Level 3

   

   3,483,713

   

   3,483,713

   

   3,296,837

   

   3,296,83711,468,901

   

   11,468,901

   

   8,267,792

   

   8,267,792LiabilitiesBorrowings - principal and interest

   17

   

   (c)

   

   (1)

   

   Level 2 (***)

   

   7,725,978

   

   6,499,746

   

   7,240,164

   

   6,266,957Borrowings - principal and interest

   17 (**)

   

   (a)

   

   (2)

   

   Level 2

   

   6,936,808

   

   6,936,808

   

   3,438,212

   

   3,438,212Debentures - Principal and interest

   18

   

   (c)

   

   (1)

   

   Level 2 (***)

   

   7,070,430

   

   6,105,830

   

   8,471,583

   

   7,997,074Derivatives

   35

   

   (a)

   

   (2)

   

   Level 2

   

   31,745

   

   31,745

   

   13,354

   

   13,354Derivatives - Zero-cost collar

   35

   

   (a)

   

   (2)

   

   Level 2

   

   2,440

   

   2,440

   

   -

   

   -21,767,402

   

   19,576,570

   

   19,163,313

   

   17,715,598(*) Refers to the hierarchy for determination of fair value(**) As a result of the initial designation of this financial liability, the consolidated financial statements reported a gain of R$ 256,241 in 2015 (R$ 100,193 in 2014)(***) Only for disclosure purposes, in accordance with IFRS 7KeyCategory:

   

   

   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 carrying amounts approximate the fair values at the end of the reporting period, due to their nature, are: ·Financial assets: (i) consumers, concessionaires and licensees, (ii) leases, (iii) associates, subsidiaries and parent company, (iv) receivables – Energy Development Account – CDE/CCEE, (v) concession financial asset - transmission, (vi) pledges, funds and restricted deposits, (vii) services rendered to third parties, (viii) Collection agreements, (ix) sector financial asset. ·Financial liabilities: (i) trade payables, (ii) regulatory charges, (iii) use of public asset, (iv) consumers and concessionaires, (v) Nacional scientific and technological development fund - FNDCT, (vi) energy research company - EPE, (vii) collection agreement, (viii) reversal fund, (ix) payables for business combination, (x) tariff discount CDE (xi) sector financial liability. In addition, in 2015 there were no transfers between hierarchical levels of fair value. a) Valuation of financial instruments As mentioned in note 4, the fair value of a security corresponds to its maturity value (redemption value) adjusted to present value by the discount factor (relating to the maturity date of the security) obtained from the market interest curve, in Brazilian reais. IFRS 7 requires the classification in a three-level hierarchy for fair value measurement of financial instruments, based on observable and unobservable inputs related to the valuation of a financial instrument at the measurement date. IFRS 7 also defines observable inputs as market data obtained from independent sources and unobservable inputs that reflect market assumptions. The three levels of the fair value hierarchy are: · Level 1: quoted prices in an active market for identical instruments;


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· Level 2: observable inputs other than quoted prices in an active market that are observable for the asset or liability, directly (i.e.as prices) or indirectly (i.e.derived from prices); · Level 3: inputs for the instruments that are not based on observable market data. As the distribution subsidiaries have classified their concession financial asset as available-for-sale, the relevant factors for fair value measurement are not publicly observable. The fair value hierarchy classification is therefore level 3. The changes between years and the respective gains in profit for the year of R$ 414,800 (R$ 104,642 in 2014 and losses of R$ 66,851 in 2013), and the main assumptions are described in note 11. Additionally, the main assumptions used in the fair value measurement of the zero-cost collar derivative, the fair value hierarchy of which is Level 3, are disclosed in note 35 b.1. The Company recognizes in “Investments at cost” in the financial statements the5.94% 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. As Investco’sshares are not traded on the stock exchange and the main objective of its operations is to generate electric energy for commercialization by the shareholders holding 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 fluctuations 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 rate changes. 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. Furthermore, in 2015 subsidiary CPFL Geração contracted a zero-cost collar (see item b.1 below). As a large part of the derivatives entered into by the subsidiaries have their terms fully aligned with the hedged debts, 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 (note 17). Other debts with terms different from the derivatives contracted as a hedge continue to be recognized at amortized cost. Furthermore, the Company and its subsidiaries do not adopt hedge accounting for derivative instruments. At December 31, 2015, the Company and its subsidiaries had the following swap transactions, all traded on the over-the-counter market:  Fair values (carrying amounts)Company / strategy / counterparts

   

   Assets

   

   Liabilities

   

   Fair value, net

   

   Values at cost, net

   

   Gain (loss) on marking to market

   

   Currecy / index

   

   Maturity range

   

   Notional

   

   Trading marketDerivatives to hedge debts designated at fair valueExchange rate hedgeCPFL EnergiaSantander

   

   70,153

   

   -

   

   70,153

   

   70,419

   

   (266)

   

   dollar

   

   February 2016

   

   200,000

   

   over the counterSantander

   

   -

   

   (402)

   

   (402)

   

   1,244

   

   (1,646)

   

   dollar

   

   September 2016

   

   187,750

   

   over the counterBradesco

   

   -

   

   (578)

   

   (578)

   

   (172)

   

   (406)

   

   dollar

   

   June 2016

   

   149,208

   

   over the counter70,153

   

   (981)

   

   69,172

   

   71,492

   

   (2,319)CPFL PaulistaBank of America Merrill Lynch

   

   154,501

   

   -

   

   154,501

   

   150,005

   

   4,496

   

   dollar

   

   July 2016

   

   156,700

   

   over the counterMorgan Stanley

   

   106,718

   

   -

   

   106,718

   

   107,938

   

   (1,220)

   

   dollar

   

   September 2016

   

   85,475

   

   over the counterScotiabank

   

   42,946

   

   -

   

   42,946

   

   43,197

   

   (252)

   

   dollar

   

   July 2016

   

   49,000

   

   over the counterCitibank

   

   69,132

   

   -

   

   69,132

   

   77,079

   

   (7,947)

   

   dollar

   

   March 2019

   

   117,250

   

   over the counterBank of Tokyo-Mitsubishi

   

   68,577

   

   -

   

   68,577

   

   77,152

   

   (8,575)

   

   dollar

   

   March 2019

   

   117,400

   

   over the counterBank of America Merrill Lynch

   

   64,284

   

   -

   

   64,284

   

   69,553

   

   (5,268)

   

   dollar

   

   September 2018

   

   106,020

   

   over the counterBank of America Merrill Lynch

   

   72,644

   

   -

   

   72,644

   

   78,536

   

   (5,892)

   

   dollar

   

   March 2019

   

   116,600

   

   over the counterJ.P.Morgan

   

   36,320

   

   -

   

   36,320

   

   39,268

   

   (2,948)

   

   dollar

   

   March 2019

   

   58,300

   

   over the counterJ.P.Morgan

   

   23,296

   

   -

   

   23,296

   

   26,278

   

   (2,982)

   

   dollar

   

   December 2017

   

   51,470

   

   over the counterJ.P.Morgan

   

   21,801

   

   -

   

   21,801

   

   24,813

   

   (3,012)

   

   dollar

   

   December 2017

   

   53,100

   

   over the counterJ.P.Morgan

   

   9,187

   

   -

   

   9,187

   

   10,584

   

   (1,398)

   

   dollar

   

   January 2018

   

   27,121

   

   over the counterHSBC

   

   19,696

   

   -

   

   19,696

   

   22,458

   

   (2,763)

   

   dollar

   

   January 2018

   

   54,214

   

   over the counterHSBC

   

   73,843

   

   -

   

   73,843

   

   82,167

   

   (8,324)

   

   dollar

   

   January 2018

   

   173,459

   

   over the counterJ.P.Morgan

   

   23,500

   

   -

   

   23,500

   

   26,501

   

   (3,000)

   

   dollar

   

   January 2018

   

   67,938

   

   over the counterJ.P.Morgan

   

   22,782

   

   -

   

   22,782

   

   26,867

   

   (4,085)

   

   dollar

   

   January 2019

   

   67,613

   

   over the counterCitibank

   

   56,759

   

   -

   

   56,759

   

   65,880

   

   (9,122)

   

   dollar

   

   January 2020

   

   156,600

   

   over the counterBNP Paribas

   

   15,594

   

   -

   

   15,594

   

   17,958

   

   (2,364)

   

   euro

   

   January 2018

   

   63,896

   

   over the counterBank of Tokyo-Mitsubishi

   

   37,117

   

   -

   

   37,117

   

   50,467

   

   (13,350)

   

   dollar

   

   February 2020

   

   142,735

   

   over the counterJ.P.Morgan

   

   13,490

   

   -

   

   13,490

   

   15,812

   

   (2,323)

   

   dollar

   

   February 2018

   

   41,100

   

   over the counterBank of America Merrill Lynch

   

   155,157

   

   -

   

   155,157

   

   174,502

   

   (19,345)

   

   dollar

   

   February 2018

   

   405,300

   

   over the counterBank of America Merrill Lynch

   

   63,912

   

   -

   

   63,912

   

   60,980

   

   2,932

   

   dollar

   

   October 2018

   

   329,500

   

   over the counter1,151,256

   

   -

   

   1,151,256

   

   1,247,997

   

   (96,741)


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CPFL PiratiningaScotiabank

   

   56,092

   

   -

   

   56,092

   

   56,421

   

   (329)

   

   dollar

   

   July 2016

   

   64,000

   

   over the counterSantander

   

   68,863

   

   -

   

   68,863

   

   70,063

   

   (1,199)

   

   dollar

   

   July 2016

   

   100,000

   

   over the counterCitibank

   

   69,132

   

   -

   

   69,132

   

   77,079

   

   (7,947)

   

   dollar

   

   March 2019

   

   117,250

   

   over the counterHSBC

   

   38,081

   

   -

   

   38,081

   

   41,233

   

   (3,152)

   

   dollar

   

   April 2018

   

   55,138

   

   over the counterJ.P.Morgan

   

   38,117

   

   -

   

   38,117

   

   41,236

   

   (3,119)

   

   dollar

   

   April 2018

   

   55,138

   

   over the counterCitibank

   

   60,858

   

   -

   

   60,858

   

   70,954

   

   (10,096)

   

   dollar

   

   January 2020

   

   169,838

   

   over the counterBNP Paribas

   

   42,884

   

   -

   

   42,884

   

   49,385

   

   (6,501)

   

   euro

   

   January 2018

   

   175,714

   

   over the counterBank of America Merrill Lynch

   

   7,459

   

   -

   

   7,459

   

   7,829

   

   (370)

   

   dollar

   

   July 2016

   

   40,000

   

   over the counterBank of America Merrill Lynch

   

   10,941

   

   -

   

   10,941

   

   11,807

   

   (866)

   

   dollar

   

   August 2016

   

   84,250

   

   over the counterScotiabank

   

   4,321

   

   -

   

   4,321

   

   6,480

   

   (2,160)

   

   dollar

   

   August 2017

   

   55,440

   

   over the counter396,748

   

   -

   

   396,748

   

   432,488

   

   (35,740)CPFL Santa CruzSantander

   

   14,407

   

   -

   

   14,407

   

   14,634

   

   (227)

   

   dolar

   

   June 2016

   

   20,000

   

   over the counterCPFL Sul PaulistaSantander

   

   15,847

   

   -

   

   15,847

   

   16,098

   

   (250)

   

   dollar

   

   June 2016

   

   22,000

   

   over the counterCPFL JaguariSantander

   

   22,331

   

   -

   

   22,331

   

   22,683

   

   (353)

   

   dollar

   

   June 2016

   

   31,000

   

   over the counterCPFL GeraçãoHSBC

   

   149,331

   

   -

   

   149,331

   

   157,133

   

   (7,803)

   

   dollar

   

   March 2017

   

   232,520

   

   over the counterRGECitibank

   

   136,246

   

   -

   

   136,246

   

   142,257

   

   (6,011)

   

   dollar

   

   April 2017

   

   128,590

   

   over the counterBank of Tokyo-Mitsubishi

   

   29,835

   

   -

   

   29,835

   

   33,215

   

   (3,380)

   

   dollar

   

   April 2018

   

   36,270

   

   over the counterBank of Tokyo-Mitsubishi

   

   134,314

   

   -

   

   134,314

   

   149,757

   

   (15,443)

   

   dollar

   

   May 2018

   

   168,346

   

   over the counterCitibank

   

   22,352

   

   -

   

   22,352

   

   24,856

   

   (2,503)

   

   dollar

   

   May 2019

   

   33,285

   

   over the counterHSBC

   

   18,077

   

   -

   

   18,077

   

   19,689

   

   (1,613)

   

   dollar

   

   October 2017

   

   32,715

   

   over the counterJ.P.Morgan

   

   51,274

   

   -

   

   51,274

   

   58,921

   

   (7,647)

   

   dollar

   

   February 2018

   

   171,949

   

   over the counterJ.P.Morgan

   

   28,065

   

   -

   

   28,065

   

   28,246

   

   (182)

   

   dollar

   

   February 2016

   

   100,000

   

   over the counter420,162

   

   -

   

   420,162

   

   456,941

   

   (36,779)CPFL ServiçosJ.P.Morgan

   

   5,250

   

   -

   

   5,250

   

   5,504

   

   (254)

   

   dollar

   

   October 2016

   

   9,000

   

   over the counterCPFL Paulista LajeadoItaú

   

   4,749

   

   -

   

   4,749

   

   6,424

   

   (1,675)

   

   dollar

   

   March 2018

   

   35,000

   

   over the counterCPFL BrasilItaú

   

   2,989

   

   -

   

   2,989

   

   5,367

   

   (2,378)

   

   dollar

   

   August 2018

   

   45,360

   

   over the counterSubtotal

   

   2,253,222

   

   (981)

   

   2,252,242

   

   2,436,760

   

   (184,518)Derivatives to hedge debts not designated at fair valueExchange rate hedgeCPFL GeraçãoVotorantim

   

   16,710

   

   -

   

   16,710

   

   16,963

   

   (254)

   

   dollar

   

   December 2016

   

   44,282

   

   over the counterPrice index hedgeCPFL GeraçãoSantander

   

   -

   

   (713)

   

   (713)

   

   3,104

   

   (3,817)

   

   IPCA

   

   April 2019

   

   35,235

   

   over the counterJ.P.Morgan

   

   -

   

   (713)

   

   (713)

   

   3,104

   

   (3,817)

   

   IPCA

   

   April 2019

   

   35,235

   

   over the counter-

   

   (1,427)

   

   (1,427)

   

   6,208

   

   (7,635)Interest rate hedge (1)CPFL PaulistaBank of America Merrill Lynch

   

   -

   

   (6,931)

   

   (6,931)

   

   (827)

   

   (6,105)

   

   CDI

   

   July 2019

   

   660,000

   

   over the counterJ.P.Morgan

   

   -

   

   (3,967)

   

   (3,967)

   

   (305)

   

   (3,662)

   

   CDI

   

   February 2021

   

   300,000

   

   over the counterVotorantim

   

   -

   

   (1,291)

   

   (1,291)

   

   (98)

   

   (1,193)

   

   CDI

   

   February 2021

   

   100,000

   

   over the counterSantander

   

   -

   

   (1,351)

   

   (1,351)

   

   (103)

   

   (1,248)

   

   CDI

   

   February 2021

   

   105,000

   

   over the counter-

   

   (13,541)

   

   (13,541)

   

   (1,333)

   

   (12,207)CPFL PiratiningaJ.P.Morgan

   

   -

   

   (1,155)

   

   (1,155)

   

   (138)

   

   (1,017)

   

   CDI

   

   July 2019

   

   110,000

   

   over the counterVotorantim

   

   -

   

   (1,667)

   

   (1,667)

   

   (124)

   

   (1,542)

   

   CDI

   

   February 2021

   

   135,000

   

   over the counterSantander

   

   -

   

   (1,219)

   

   (1,219)

   

   (90)

   

   (1,129)

   

   CDI

   

   February 2021

   

   100,000

   

   over the counter-

   

   (4,041)

   

   (4,041)

   

   (353)

   

   (3,689)RGEHSBC

   

   -

   

   (5,251)

   

   (5,251)

   

   (626)

   

   (4,625)

   

   CDI

   

   July 2019

   

   500,000

   

   over the counterVotorantim

   

   -

   

   (2,283)

   

   (2,283)

   

   (177)

   

   (2,106)

   

   CDI

   

   February 2021

   

   170,000

   

   over the counter-

   

   (7,534)

   

   (7,534)

   

   (803)

   

   (6,731)CPFL GeraçãoVotorantim

   

   -

   

   (4,221)

   

   (4,221)

   

   (241)

   

   (3,980)

   

   CDI

   

   August 2020

   

   460,000

   

   over the counterSubtotal

   

   16,710

   

   (30,765)

   

   (14,055)

   

   20,441

   

   (34,496)Other derivatives (2)CPFL GeraçãoItaú

   

   2,843

   

   (1,830)

   

   1,012

   

   -

   

   1,012

   

   dollar

   

   September 2020

   

   34,858

   

   over the counterVotorantim

   

   1,989

   

   (610)

   

   1,379

   

   -

   

   1,379

   

   dollar

   

   September 2020

   

   34,858

   

   over the counterSantander

   

   3,989

   

   -

   

   3,989

   

   -

   

   3,989

   

   dollar

   

   September 2020

   

   42,100

   

   over the counterSubtotal

   

   8,820

   

   (2,440)

   

   6,380

   

   -

   

   6,380Total

   

   2,278,753

   

   (34,185)

   

   2,244,567

   

   2,457,201

   

   (212,634)Current

   

   627,493

   

   (981)Noncurrent

   

   1,651,260

   

   (33,205)For further details on terms and information on debts and debentures, see notes 17 and 18(1) The interest rate hedge swaps have half-yearly validity, so the notional value reduces according to the amortization of the debt.(2) Due to the characteristics of this derivative (zero-cost collar) the notional amount is presented in U.S. dollar.
  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 recognized 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 hedged debts. For the years 2015, 2014 and 2013, the derivatives resulted in the following impacts on the result, recognized in the line item of finance costs on adjustment for inflation and exchange rate changes:


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Gain (loss)Company

   

   Hedged risk / transaction

   

   2015

   

   2014

   

   2013CPFL Energia

   

   Exchange variation

   

   71,492

   

   -

   

   323CPFL Energia

   

   Mark to market

   

   (2,319)

   

   -

   

   (469)CPFL Paulista

   

   Interest rate variation

   

   (2,250)

   

   1

   

   933CPFL Paulista

   

   Exchange variation

   

   843,224

   

   96,017

   

   150,500CPFL Paulista

   

   Mark to market

   

   (98,738)

   

   (21,297)

   

   (38,759)CPFL Piratininga

   

   Interest rate variation

   

   (609)

   

   51

   

   303CPFL Piratininga

   

   Exchange variation

   

   300,652

   

   35,808

   

   61,673CPFL Piratininga

   

   Mark to market

   

   (32,431)

   

   (6,124)

   

   (20,454)RGE

   

   Interest rate variation

   

   (1,321)

   

   (28)

   

   798RGE

   

   Exchange variation

   

   291,612

   

   37,585

   

   43,058RGE

   

   Mark to market

   

   (29,946)

   

   (7,170)

   

   (11,380)CPFL Geração

   

   Interest rate variation

   

   2,600

   

   303

   

   273CPFL Geração

   

   Exchange variation

   

   122,294

   

   21,650

   

   18,428CPFL Geração

   

   Mark to market

   

   (7,896)

   

   (6,221)

   

   (4,344)CPFL Santa Cruz

   

   Exchange variation

   

   9,899

   

   2,604

   

   1,962CPFL Santa Cruz

   

   Mark to market

   

   (80)

   

   (115)

   

   (486)CPFL Leste Paulista

   

   Exchange variation

   

   4,596

   

   1,453

   

   3,435CPFL Leste Paulista

   

   Mark to market

   

   (76)

   

   (117)

   

   (462)CPFL Sul Paulista

   

   Exchange variation

   

   12,404

   

   2,333

   

   3,140CPFL Sul Paulista

   

   Mark to market

   

   (83)

   

   (163)

   

   (658)CPFL Jaguari

   

   Exchange variation

   

   16,616

   

   2,146

   

   2,398CPFL Jaguari

   

   Mark to market

   

   (63)

   

   (160)

   

   (595)CPFL Mococa

   

   Exchange variation

   

   2,022

   

   427

   

   1,966CPFL Mococa

   

   Mark to market

   

   (33)

   

   (70)

   

   (301)CPFL Serviços

   

   Exchange variation

   

   3,810

   

   830

   

   -CPFL Serviços

   

   Mark to market

   

   (87)

   

   (167)

   

   -CPFL Telecom

   

   Exchange variation

   

   3,204

   

   81

   

   -CPFL Telecom

   

   Mark to market

   

   6

   

   (6)

   

   -CPFL Paulista Lajeado

   

   Exchange variation

   

   4,626

   

   -

   

   -CPFL Paulista Lajeado

   

   Mark to market

   

   (1,675)

   

   -

   

   -CPFL Brasil

   

   Exchange variation

   

   5,367

   

   -

   

   -CPFL Brasil

   

   Mark to market

   

   (2,378)

   

   -

   

   -1,514,439

   

   159,653

   

   211,282
  b.1) Zero-cost collar derivative contracted by CPFL Geração In 2015, subsidiary CPFL Geração contracted US$ denominated put and call options, involving the same financial institution as counterpart, and which on a combined basis are characterized as an operation usually known as zero-cost collar. The contracting of this operation does not involve any kind of speculation, inasmuch as it is aimed at minimizing any negative impacts on future revenues of the joint venture ENERCAN, which has electric energy sale agreements with annual restatement of part of the tariff based on the variation in the US$. In addition, according to Management’s view, the current scenario is favorable for contracting this type of financial instrument, considering the high volatility implicit in dollar options and the fact that there is no initial cost for same. The total amount contracted was US$ 111,817, with due dates between October 1, 2015 and September 30, 2020. As at December 31, 2015, the total amount contracted was US$ 107,434, considering the options already settled in the 4th quarter of 2015. The exercise prices of the dollar options vary from R$ 4.20 to R$ 4.40 for the put options and from R$ 5.40 to R$ 7.50 for the call options. These options have been measured at fair value in a recurring manner, as required by IAS 39. The fair value of the options that are part of this operation has been calculated based on the following premises: Valuation technique(s) and key information

   We used the Black Scholes Option Pricing Model, which aims to obtain the fair price of the options involving the following variables: value of the asset, exercise price of the option, interest rate, term and volatility.Significant unobservable inputs

   Volatility determined based on the average market pricing calculations, future dollar and other variables applicable to this specific transaction, with average variation of 22.9%.Relationship between unobservable inputs and fair value (sensitivity)

   A slight rise in long-term volatility, analyzed on an isolated basis, would result in an insignificant increase in fair value. If the volatility were 10% higher and all the other variables remained constant, the net carrying amount (asset) would decrease by R$ 441, resulting in a net asset of R$ 5,939.


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Measurement of the fair value of these financial instruments, in the amount of R$ 7,902, of which R$ 10,342 refers to the measurement of the asset instruments and R$ 2,440 to the measurement of liability instruments, has been recognized in the statement of profit or loss for the year in line item Finance income, with no recognition of any effects in Other comprehensive income. The following table reconciles the opening and closing balances of the call and put options for the year ended December 31, 2015, as required by IFRS 13:  Assets

   

   LiabilitiesAt December 31, 2014

   -

   

   -Measurement at fair value

   10,342

   

   (2,440)Net cash received from settlement of flows

   (1,522)

   

   -At December 31, 2015

   8,820

   

   (2,440)
  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 results 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 the results. The Company and its subsidiaries therefore quantify the risks in terms of the net exposure of the variables (dollar, euro, CDI, IGP-M, IPCA and TJLP), as shown below: c.1) Exchange ratevariation Considering the level of net exchange rate exposure at December 31, 2015 is maintained, the simulation of the effects by type of financial instrument for three different scenarios would be:  Decrease (increase) - in thousands of Brazilian reaisInstruments

   

   Exposure R$ thousand (a)

   

   Risk

   

   Currency depreciation (b)

   

   Currency apreciation / depreciation of 25% (c)

   

   Currency apreciation / depreciation of 50% (c)Financial liability instruments

   

   (6,690,487)

   

   

   

   (1,019,131)

   

   908,274

   

   2,835,678Derivatives - Plain Vanilla Swap

   

   6,892,745

   

   

   

   1,049,940

   

   (935,731)

   

   (2,921,403)202,259

   

   drop in the dollar

   

   30,809

   

   (27,458)

   

   (85,725)Financial liability instruments

   

   (322,465)

   

   

   

   (49,792)

   

   (142,856)

   

   (235,920)Derivatives - Plain Vanilla Swap

   

   316,433

   

   

   

   48,860

   

   140,183

   

   231,507(6,032)

   

   euro apprec.

   

   (931)

   

   (2,672)

   

   (4,413)Total

   

   196,227

   

   

   

   29,878

   

   (30,130)

   

   (90,138)Increase - in thousands of Brazilian reaisInstruments

   

   Exposure R$ thousand (a)

   

   Risk

   

   Currency depreciation (b)

   

   Currency apreciation / depreciation of 25% (c)

   

   Currency apreciation / depreciation of 50% (c)Derivatives - Plain Vanilla Swap

   

   107,434

   

   

   

   (26,870)

   

   (65,621)

   

   (104,373)(a) Exchange rates at December 31, 2015 were R$ 3.90 for dollar and R$ 4.25 for euro.(b) As per foreign exchange rate curves obtained from information provided by BM&FBovespa. The exchange rates considered were R$ 4.50 and R$ 4.91, and the Currency depreciation rate considered were 15.23% and 15.44%, for dollar and euro, respectively.(c) The percentage of exchange depreciation are related to the information provided by BM&FBovespa.(d) Due to the characteristics of this derivative (zero-cost collar) the notional amount is presented in U.S. dollar.


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c.2) Interest rate variation Assuming that (i) the scenario of net exposure of the financial instruments indexed to variable interest rates at December 31, 2015 is maintained, and (ii) the respective accumulated annual indexes for 2015 remain stable (CDI 13.18% p.a.; IGP-M 10.54% p.a.; TJLP 6.21% p.a.; IPCA 10.67% p.a.), the effects on the Company’s 2016 financial statements would be a net finance cost of R$ 1,279,878 (CDI R$ 986,888, IGP-M R$ 7,667, TJLP R$ 284,521 and IPCA R$ 802). In the event of fluctuations in the indexes in accordance with the three scenarios described below, the effect on net finance cost would as follows:  Decrease (increase) - in thousands of Brazilian reaisInstruments

   

   Exposure R$ thousand

   

   Risk

   

   Scenario I (a)

   

   Raising index by 25% (b)

   

   Raising index by 50% (b)Financial asset instruments

   

   6,160,232

   

   

   

   161,398

   

   404,727

   

   648,056Financial liability instruments

   

   (8,601,345)

   

   

   

   (225,355)

   

   (565,108)

   

   (904,861)Derivatives - Plain Vanilla Swap

   

   (5,046,654)

   

   

   

   (132,222)

   

   (331,565)

   

   (530,908)(7,487,767)

   

   CDI apprec.

   

   (196,180)

   

   (491,946)

   

   (787,713)Financial liability instruments

   

   (72,739)

   

   IGP-M apprec.

   

   2,204

   

   838

   

   (527)Financial liability instruments

   

   (4,581,666)

   

   TJLP apprec.

   

   (36,195)

   

   (116,374)

   

   (196,553)Financial liability instruments

   

   (83,177)

   

   

   

   1,747

   

   (35)

   

   (1,817)Derivatives - Plain Vanilla Swap

   

   75,662

   

   

   

   (1,589)

   

   32

   

   1,653(7,514)

   

   IPCA apprec.

   

   158

   

   (3)

   

   (164)Total

   

   (12,149,686)

   

   

   

   (230,013)

   

   (607,486)

   

   (984,958)(a) The CDI, IGP-M, TJLP and IPCA indexes considered of 15.8%, 7.51%, 7.0% and 8.57%, respectively, were obtained from information available in the market.(b) The percentages of increase in indexes 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 at December 31, 2015, 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.  December 31, 2015

   

   Note

   

   Weighted average interest rates

   

   Less than1 month

   

   1-3 months

   

   3 monthsto 1 year

   

   1-3 years

   

   4-5 years

   

   More than5 years

   

   TotalTrade payables

   

   16

   

   

   

   3,155,024

   

   2,826

   

   3,361

   

   633

   

   -

   

   -

   

   3,161,842Borrowings - principal and interest

   

   17

   

   12.31%

   

   595,799

   

   780,466

   

   2,913,815

   

   8,654,047

   

   4,015,848

   

   3,062,584

   

   20,022,560Derivatives

   

   35

   

   

   

   -

   

   -

   

   981

   

   -

   

   21,426

   

   11,779

   

   34,186Debentures - principal and interest

   

   18

   

   14.82%

   

   92,770

   

   126,495

   

   1,201,363

   

   5,165,248

   

   2,758,553

   

   899,343

   

   10,243,772Regulatory charges

   

   20

   

   

   

   852,017

   

   -

   

   -

   

   -

   

   -

   

   -

   

   852,017Use of public asset

   

   23

   

   15.95%

   

   788

   

   5,270

   

   18,965

   

   69,172

   

   118,313

   

   253,232

   

   465,741Others

   

   24

   

   

   

   28,937

   

   163,930

   

   27,490

   

   -

   

   -

   

   17,750

   

   238,107Consumers and concessionaires

   

   

   

   

   

   11,307

   

   28,907

   

   13,745

   

   -

   

   -

   

   -

   

   53,959National scientific and technological development fund - FNDCT

   

   

   

   

   

   955

   

   3,161

   

   -

   

   -

   

   -

   

   -

   

   4,115Energy research company - EPE

   

   

   

   

   

   485

   

   1,580

   

   -

   

   -

   

   -

   

   -

   

   2,065Collections agreement

   

   

   

   

   

   -

   

   130,282

   

   -

   

   -

   

   -

   

   -

   

   130,282Reversal fund

   

   

   

   

   

   -

   

   -

   

   -

   

   -

   

   -

   

   17,750

   

   17,750Bussines combination

   

   

   

   

   

   16,190

   

   -

   

   13,745

   

   -

   

   -

   

   -

   

   29,935Total

   

   

   

   

   

   4,725,334

   

   1,078,988

   

   4,165,974

   

   13,889,100

   

   6,914,140

   

   4,244,688

   

   35,018,225
    ( 36 )COMMITTMENTS
 The Company’s commitments as regards long-term energy purchase agreements and plant construction projects at December 31, 2015, as follows:


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Commitments at December 31, 2015

   

   Duration

   

   Less than 1 year

   

   1-3 years

   

   4-5 years

   

   More than 5 years

   

   TotalEnergy purchase agreements (except Itaipu)

   

   Up to 30 years

   

   7,905,987

   

   14,852,772

   

   15,589,876

   

   59,267,009

   

   97,615,644Energy purchase from Itaipu

   

   Up to 30 years

   

   2,345,613

   

   4,714,829

   

   5,010,501

   

   23,492,838

   

   35,563,781Energy system service charges

   

   Up to 34 years

   

   1,062,027

   

   2,967,006

   

   3,638,288

   

   19,717,250

   

   27,384,570GSF renegotiation

   

   Up to 25 years

   

   46,016

   

   -

   

   7,166

   

   180,995

   

   234,177Power plant constrution projets

   

   Up to 18 years

   

   961,843

   

   298,299

   

   71

   

   -

   

   1,260,213Trade payables

   

   Up to 31 years

   

   1,333,362

   

   945,660

   

   226,395

   

   538,416

   

   3,043,83413,654,849

   

   23,778,566

   

   24,472,297

   

   103,196,508

   

   165,102,220
  The power plant construction projects include commitments made basically to construction related to the subsidiaries of the renewable energy segment.  ( 37 )NON-CASH TRANSACTION
  December 31, 2015

   

   December 31, 2014

   

   December 31, 2013Transactions resulting from business combinationsBorrowings and debentures

   

   -

   

   (1,009,877)

   

   -Property, plant and equipment acquired in business combination

   

   -

   

   1,616,999

   

   -Intangible asset acquired in business combination, net of tax effects

   

   -

   

   626,399

   

   -Deferred taxes on business combination

   

   -

   

   (305,259)

   

   -Other net assets acquired in business combination

   

   -

   

   (23,669)

   

   --

   

   904,593

   

   -Consideration paid with acquired cash

   

   -

   

   (70,930)

   

   -Consideration transferrred through share issue

   

   -

   

   (833,663)

   

   -Other transactionsProvision (reversal) for socio environmental costs capitalized in property, plant and equipment

   

   -

   

   9,193

   

   (17,747)Interest capitalized in property, plant and equipment

   

   34,212

   

   4,225

   

   48,328Interest capitalized in concession intangible asset - distribution infraestruture

   

   11,358

   

   8,044

   

   8,845Transfer from concession financial concession and intangible assets to property, plant and equipment as result of spin-off of generation activity in distributors

   

   -

   

   5,828

   

   -Transfer between property, plant and equipament and other assets

   

   2,928

   

   16,430

   

   18,896Realization of noncontrolling interests' capital reserve against receivables

   

   -

   

   2,189

   

   -
   ( 38 )RELEVANT FACT AND EVENT AFTER THE REPORTING PERIOD
 38.1Borrowings On January 20, 2016, approval was granted by the Board of Directors of subsidiaries CPFL Paulista, CPFL Piratininga, RGE and CPFL Geração for obtaining funds through foreign currency borrowings (with swap at the CDI rate), rural credits, bank credit notes, issue of debentures, assumption of debts, other working capital operations and/or rolling over of debts and current swaps, with maximum term of five years and amounts of up to the following per subsidiary: (i) CPFL Geração: R$ 1,300,000; (ii) CPFL Paulista: R$ 400,000; (iii) CPFL Piratininga: R$ 350,000 and (iv) RGE: R$ 450,000. 38.2Approval of Tariff Flags Orders No. 7 of January 5, 2016 and 265 of February 1, 2016 approved the amounts related to the tariff flags of November and December 2015 as follows:


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Subsidiary

   

   Order No. 7

   

   Order No. 265CPFL Paulista

   

   84,813

   

   78,667CPFL Piratininga

   

   33,341

   

   32,095CPFL Santa Cruz

   

   3,395

   

   3,155CPFL Leste Paulista

   

   1,062

   

   934CPFL Sul Paulista

   

   1,426

   

   1,362CPFL Jaguari

   

   1,854

   

   1,703CPFL Mococa

   

   773

   

   683RGE

   

   24,237

   

   23,642150,901

   

   142,241
  38.3Periodic Revisions — RTP of CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa On February 2, 2016, ANEEL published Ratification Resolution No. 2.017, extending the effective term of the electric energy tariffs of subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa through March 21, 2016, based on renewal of the concession and alteration of the date of its tariff process from February 3 to March 22 of each year. The table below shows the impact of this periodic revision of our subsidiaries mentioned above:  Subsidiary

   

   Month

   

   Periodic Review - RTPCPFL Santa Cruz

   

   March

   

   22.51%CPFL Leste Paulista

   

   March

   

   21.04%CPFL Jaguari

   

   March

   

   29.46%CPFL Sul Paulista

   

   March

   

   24.35%CPFL Mococa

   

   March

   

   16.57%
  38.4Bonuses in shares paid to shareholders On March 2016, in order to strengthen the Company’s capital structure, the Company’s management recommended to the Board of Directors that it propose to the General Meeting of Shareholders capitalization of the balance of the statutory reserve for working capital improvement, with issue of new shares in favor of the shareholders.




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( 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, 2015 and December 31, 2014 and for the years ended on December 31, 2015, 2014 and 2013 presented herein were prepared considering the same accounting policies as described in note 3 to Company’s consolidated financial statements.  UNCONSOLIDATED STATEMENTS OF FINANCIAL POSITION  ASSETS

   

   December 31, 2015

   

   December 31, 2014Cash and cash equivalents

   

   424,192

   

   799,775Dividends and interest on capital

   

   1,227,590

   

   942,367Derivatives

   

   70,153

   

   -Other receivables

   

   73,827

   

   50,047Total current assets

   

   1,795,763

   

   1,792,189Deferred tax assets

   

   140,389

   

   150,628Investments

   

   6,940,036

   

   6,290,998Other receivables

   

   72,282

   

   84,472Total noncurrent assets

   

   7,152,706

   

   6,526,098Total assets

   

   8,948,469

   

   8,318,287LIABILITIES

   

   December 31, 2015

   

   December 31, 2014Interest on debts

   

   38,057

   

   -Interest on debentures

   

   -

   

   15,020Borrowings

   

   935,196

   

   -Debentures

   

   -

   

   1,289,386Dividends and interest on capital

   

   212,531

   

   13,555Derivatives

   

   981

   

   -Other payables

   

   19,945

   

   20,527Total current liabilities

   

   1,206,708

   

   1,338,488Provision for tax, civil and labor risks

   

   1,635

   

   725Allowance for equity investment losses

   

   33,969

   

   -Other payables

   

   31,961

   

   35,540Total noncurrent liabilities

   

   67,565

   

   36,264Equity

   

   7,674,196

   

   6,943,535Total liabilities and equity

   

   8,948,469

   

   8,318,287


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UNCONSOLIDATED STATEMENTS OF PROFIT OR LOSS FOR THE YEAR  2015

   

   2014

   

   2013Net operating revenue

   

   1,157

   

   61

   

   1,649General and administrative expenses

   

   (29,911)

   

   (26,175)

   

   (22,626)Income from electric energy service

   

   (28,754)

   

   (26,114)

   

   (20,977)Equity interests in subsidiaries, associates and joint ventures

   

   926,951

   

   1,011,185

   

   1,022,779Net finance costs

   

   (22,948)

   

   (25,464)

   

   (26,860)Profit before taxes

   

   875,250

   

   959,607

   

   974,942Social contribution and income tax

   

   (10,309)

   

   (10,430)

   

   (37,523)Profit for the year

   

   864,940

   

   949,177

   

   937,4192015

   

   2014

   

   2013Profit for the year

   

   864,940

   

   949,177

   

   937,419Items that will not be reclassified subsequently to profit and lossEquity in comprehensive income of subsidiaries

   

   65,547

   

   (225,720)

   

   460,226Comprehensive income for the year

   

   930,488

   

   723,457

   

   1,397,645
  UNCONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEAR  2015

   

   2014

   

   2013OPERATING CASH FLOWProfit before taxes

   

   875,250

   

   959,607

   

   974,942ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIESEquity interests in subsidiaries, associates and joint ventures

   

   (926,951)

   

   (1,011,185)

   

   (1,022,779)Depreciation and amortization

   

   170

   

   173

   

   76Interest on debts, inflation adjustment and exchange rate changes

   

   94,588

   

   142,278

   

   81,189Other adjustments

   

   1,497

   

   640

   

   26744,553

   

   91,513

   

   33,695DECREASE (INCREASE) IN OPERATING ASSETS AND LIABILITIESDividends and interest on capital received

   

   627,014

   

   1,248,982

   

   792,146Taxes recoverable

   

   (12,350)

   

   1,564

   

   21,797Other operating assets and liabilities

   

   (2,526)

   

   3,905

   

   (1,990)CASH FLOWS PROVIDED BY OPERATIONS

   

   656,691

   

   1,345,964

   

   845,648Interest paid on debts and debentures

   

   (36,858)

   

   (138,599)

   

   (76,561)Income tax and social contribution paid

   

   (2,172)

   

   (21,463)

   

   (27,551)NET CASH FROM OPERATING ACTIVITIES

   

   617,661

   

   1,185,902

   

   741,536INVESTING ACTIVITIESCapital increase in investees

   

   (490,010)

   

   (360,000)

   

   (1,563)Financial investments, pledges, funds and restricted investments

   

   -

   

   -

   

   4,710Advance for future capital increase

   

   (52,680)

   

   (27,153)

   

   (59,342)Other investing activities

   

   10,298

   

   (2,835)

   

   (8,635)NET CASH USED IN INVESTING ACTIVITIES

   

   (532,392)

   

   (389,988)

   

   (64,830)FINANCING ACTIVITIESBorrowings and debentures raised

   

   829,997

   

   -

   

   1,287,180Repayment of principal of borrowings and debentures

   

   (1,290,000)

   

   -

   

   (299,535)Dividends and interest on capital paid

   

   (850)

   

   (986,811)

   

   (815,514)NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES

   

   (460,853)

   

   (986,811)

   

   172,131NET INCREASE IN CASH AND CASH EQUIVALENTS

   

   (375,584)

   

   (190,897)

   

   848,837CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR

   

   799,775

   

   990,672

   

   141,835CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR

   

   424,192

   

   799,775

   

   990,672


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Following is the information relating to CPFL Energia's unconsolidated condensed financial statements presented above: a.Cash and cash equivalents:  December 31, 2015

   

   December 31, 2014Bank balances

   311

   

   628Investment funds

   423,881

   

   799,147Total

   424,192

   

   799,775
    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 capital

   TotalSubsidiary

   December 31, 2015

   

   December 31, 2014

   

   December 31, 2015

   

   December 31, 2014

   

   December 31, 2015

   

   December 31, 2014CPFL Paulista

   612,585

   

   755,625

   

   52,383

   

   10,570

   

   664,968

   

   766,196CPFL Piratininga

   172,239

   

   -

   

   27,084

   

   -

   

   199,323

   

   -CPFL Santa Cruz

   19,527

   

   14,000

   

   7,517

   

   -

   

   27,044

   

   14,000CPFL Leste Paulista

   3,220

   

   -

   

   2,102

   

   -

   

   5,321

   

   -CPFL Sul Paulista

   3,848

   

   -

   

   1,986

   

   -

   

   5,834

   

   -CPFL Jaguari

   1,152

   

   -

   

   -

   

   -

   

   1,152

   

   -CPFL Mococa

   2,499

   

   -

   

   1,234

   

   -

   

   3,734

   

   -RGE

   67,815

   

   82,117

   

   64,073

   

   50,077

   

   131,887

   

   132,194CPFL Geração

   103,532

   

   -

   

   -

   

   -

   

   103,532

   

   -CPFL Centrais Geradoras

   1,185

   

   -

   

   -

   

   -

   

   1,185

   

   -CPFL Jaguari Geração

   1,667

   

   4,039

   

   -

   

   -

   

   1,667

   

   4,039CPFL Brasil

   41,176

   

   -

   

   1,601

   

   -

   

   42,777

   

   -CPFL Planalto

   458

   

   -

   

   -

   

   -

   

   458

   

   -CPFL Serviços

   12,026

   

   17,182

   

   -

   

   4,583

   

   12,026

   

   21,765Nect

   4,539

   

   3,793

   

   -

   

   -

   

   4,539

   

   3,793CPFL Total

   5,589

   

   -

   

   -

   

   -

   

   5,589

   

   -AUTHI

   634

   

   -

   

   -

   

   -

   

   634

   

   -CPFL ESCO

   9,565

   

   380

   

   6,354

   

   -

   

   15,920

   

   3801,063,256

   

   877,136

   

   164,334

   

   65,231

   

   1,227,590

   

   942,367
    c.Other receivables:  Current

   

   NoncurrentDecember 31, 2015

   

   December 31, 2014

   

   December 31, 2015

   

   December 31, 2014Recoverable taxes

   72,885

   

   49,071

   

   -

   

   -Due from relative parties

   -

   

   -

   

   2,814

   

   12,089Escrow deposits

   -

   

   -

   

   630

   

   546Advance for future capital increase

   -

   

   -

   

   52,680

   

   55,157Loans and financing guarantees of subsidiaries

   -

   

   -

   

   14,919

   

   15,818Other

   942

   

   976

   

   1,239

   

   861Total

   73,827

   

   50,047

   

   72,282

   

   84,471
   At December 31, 2015, the balances of advance for future capital increase refer to the following subsidiaries: (i) CPFL Serviços (R$31,000); (ii) CPFL Telecom (R$19,000) and (iii) Authi (R$2,600). At December 31, 2014, the balances of advance for future capital increase refer to the following 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).


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d.Deferred tax assets  December 31, 2015

   

   December 31, 2014Social contribution credit (debit)Tax losses carryforwards

   46,602

   

   41,133Deductible temporary differences

   (5,918)

   

   348Subtotal

   40,684

   

   41,481Income tax credit (debit)Tax losses carryforwards

   116,438

   

   108,182Deductible temporary differences

   (16,733)

   

   966Subtotal

   99,705

   

   109,148Total

   140,389

   

   150,628
  e.Investment: The financial information of subsidiaries and joint venturesare accounted for using the equity method of accounting.  December 31, 2015

   

   December 31, 2014

   

   2015

   

   2014

   

   2013Investment

   

   Number of shares (thousand)

   

   Equity interest

   

   Share of profit (loss) of investeesCPFL Paulista

   

   880,653

   

   1,352,393

   

   728,213

   

   298,203

   

   502,719

   

   620,412CPFL Piratininga

   

   53,096,770

   

   537,670

   

   479,686

   

   211,637

   

   187,715

   

   82,985CPFL Santa Cruz

   

   371,772

   

   131,149

   

   132,353

   

   12,424

   

   49,052

   

   (143)CPFL Leste Paulista

   

   892,772

   

   46,301

   

   38,066

   

   13,556

   

   7,173

   

   6,826CPFL Sul Paulista

   

   454,958

   

   55,233

   

   44,375

   

   16,201

   

   11,351

   

   6,743CPFL Jaguari

   

   209,294

   

   28,521

   

   25,627

   

   4,852

   

   2,027

   

   (6,631)CPFL Mococa

   

   117,199

   

   29,205

   

   26,260

   

   6,679

   

   10,248

   

   15,482RGE

   

   1,019,790

   

   1,580,807

   

   1,300,685

   

   145,804

   

   177,672

   

   126,851CPFL Geração

   

   205,487,717

   

   2,169,922

   

   2,035,286

   

   240,520

   

   16,499

   

   239,561CPFL Jaguari Geração (*)

   

   40,108

   

   42,729

   

   34,685

   

   6,670

   

   (4,657)

   

   8,962CPFL Brasil

   

   2,999

   

   51,779

   

   65,508

   

   81,929

   

   136,876

   

   36,426CPFL Planalto (*)

   

   630

   

   2,003

   

   1,633

   

   1,830

   

   2,238

   

   (702)CPFL Serviços

   

   1,480,835

   

   7,117

   

   23,013

   

   (17,952)

   

   5,719

   

   7,445CPFL Atende (*)

   

   13,991

   

   17,373

   

   17,496

   

   7,776

   

   6,849

   

   624Nect (*)

   

   2,059

   

   16,087

   

   9,458

   

   18,155

   

   10,812

   

   5,796CPFL Total (*)

   

   19,005

   

   19,930

   

   24,417

   

   5,836

   

   10,327

   

   3,226CPFL Jaguariuna (*)

   

   189,770

   

   2,496

   

   2,553

   

   (167)

   

   1

   

   325CPFL Telecom

   

   36,420

   

   (33,969)

   

   (293)

   

   (60,718)

   

   (8,339)

   

   (1,313)CPFL Centrais Geradoras (*)

   

   16,127

   

   19,972

   

   22,439

   

   4,740

   

   4,720

   

   1,065CPFL ESCO

   

   48,164

   

   66,038

   

   409,385

   

   35,194

   

   1,602

   

   -AUTHI (*)

   

   10

   

   1,913

   

   -

   

   2,537

   

   -

   

   1,153,940Subtotal - By subsidiary's equity

   

   

   

   6,144,668

   

   5,420,845

   

   1,035,705

   

   1,130,604

   

   -Amortization of fair value adjustments of assets

   

   

   

   -

   

   -

   

   (108,754)

   

   (119,419)

   

   (131,161)Total

   

   

   

   6,144,668

   

   5,420,845

   

   926,951

   

   1,011,185

   

   1,022,779Investment

   

   

   

   6,178,637

   

   5,420,845Allowance for equity investment losses

   

   

   

   (33,969)

   

   -(*) number of quotas
  Dividends received The net cash provided by operating activities is comprised mainly by dividends received from the Company’s subsidiaries. After the decisions made by the subsidiaries’ shareholders at their Annual and Extraordinary General Meetings (AGO/AGE), in the first half of 2015 the Company recognized the amount of R$ 577,651 by way of dividends and interest on capital for the year 2014. In addition, in 2015 the subsidiaries declared: (i) the amount of R$ 216,104 as interim dividends and interest on capital, relating to the interim results for 2015; and (ii) the amount of R$ 127,058 as mandatory minimum dividend for the year 2015. Out of the balance of dividends and interest on capital receivable at December 31, 2014, the amount of R$ 8,576 was revoked during 2015. Of the amounts recorded as accounts receivable, the amount of R$ 627,014 was paid by the subsidiaries to the Company in 2015.


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The dividends received are comprised as follows:  2015

   

   2014

   

   2013CPFL Paulista

   

   425,400

   

   424,751

   

   -CPFL Piratininga

   

   -

   

   246,693

   

   -CPFL Santa Cruz

   

   -

   

   26,007

   

   -CPFL Leste Paulista

   

   -

   

   39,587

   

   -CPFL Sul Paulista

   

   -

   

   39,883

   

   -CPFL Jaguari

   

   806

   

   10,752

   

   -CPFL Mococa

   

   -

   

   32,881

   

   -RGE

   

   113,012

   

   -

   

   151,184CPFL Geração

   

   -

   

   278,653

   

   523,424CPFL Brasil

   

   52,599

   

   106,464

   

   109,530CPFL Jaguari Geração

   

   998

   

   9,683

   

   4,000CPFL Planalto

   

   1,002

   

   5,591

   

   -CPFL Serviços

   

   7,683

   

   -

   

   -CPFL Atende

   

   7,899

   

   5,006

   

   1,459CPFL Total

   

   4,734

   

   7,999

   

   2,549Nect

   

   10,780

   

   11,256

   

   -CPFL Centrais Geradoras

   

   1,720

   

   3,776

   

   -CPFL ESCO

   

   380

   

   -

   

   -TOTAL

   

   627,014

   

   1,248,982

   

   792,146
   There are restrictions of transfer of funds from the concessionaires CPFL Paulista, CPFL Piratininga, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa, CPFL Jaguari, RGE, CPFL Geração, ENERCAN, CERAN, BAESA and Foz do Chapecó.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, CERAN and CPFL Telecom have restrictions relating to the payment of dividends, due to the debt covenants. In addition, the joint ventures ENERCAN, BAESA and Chapecoense also have restriction analogous to those described in note 13.2.  f.Interest on debentures and debentures:  December 31, 2015

   

   December 31, 2014Interest

   

   Current

   

   Noncurrent

   

   Total

   

   Interest

   

   Current

   

   Noncurrent

   

   Total4th Issue

   Single series

   

   -

   

   -

   

   -

   

   -

   

   15,020

   

   1,289,386

   

   -

   

   1,304,406
  In February 24, 2015, the Company prepaid the 4th debenture issue.  g.Other payables: The mainly accounts payable that the parent company has registered as noncurrent liabilities are due to loans and financing guarantees for subsidiaries.  h.Interest on debts and borrowings The balance of R$ 973,253 registered in current liabilities are related to (i) working capital line of R$331,343 and (ii) foreign borrowings of R$ 645,369, whose underlying derivatives resulted in an asset of R$ 69,172. Interest, amortization and collateral conditions are described in note 17.  *************


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