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, 2016Commission 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 2,5Parque São QuirinoCampinasSão 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, 2016, there were 1,017,914,746 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. YesTNo£ 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£NoT 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. YesTNo£ 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/AT Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or an emerging growth company. See thedefinitions of "large accelerated filer," "accelerated filer," and "emerging growth company" in Rule 12b-2 of theExchange Act: Large Accelerated Filer  T

   Accelerated Filer  £Non‐accelerated Filer  £

   Emerging Growth Company£  If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicateby check mark if the registrant has elected not to use the extended transition period for complying with any newor revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.  ̈  Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: U.S. GAAP£IFRSTOther£ 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£NoT     † The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Boardto its Accounting Standards Codification after April 5, 2012.


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Table of Contents Page Contents FORWARD‐LOOKING STATEMENTS

   1CERTAIN TERMS AND CONVENTIONS

   1PRESENTATION OF FINANCIAL AND OTHER 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

   18ITEM 4A

   Unresolved Staff Comments

   67ITEM 5

   Operating and Financial Review and Prospects

   67ITEM 6

   Directors, Senior Management and Employees

   108ITEM 7

   MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

   117ITEM 8

   Financial Information

   118ITEM 9

   The Offer and Listing

   121ITEM 10

   Additional Information

   123ITEM 11

   Quantitative and Qualitative Disclosures About Market Risk

   142ITEM 12

   Description of Securities Other than Equity Securities

   143ITEM 13

   Defaults, Dividend Arrearages and Delinquencies

   144ITEM 14

   Material Modifications to the Rights of Security Holders and Use ofPROCEEDS

   144ITEM 15

   Controls and Procedures

   144ITEM 16A

   Audit Committee Financial Expert

   146ITEM 16B

   Code of Ethics

   146ITEM 16C

   Principal Accountant Fees and Services

   146ITEM 16D

   Exemptions from the Listing Standards for Audit Committees

   147ITEM 16E

   Purchases of Equity Securities by the Issuer and Affiliated Purchasers

   147ITEM 16F

   Change in Registrant’s Certifying Accountant

   147ITEM 16G

   Corporate Governance

   148 ****  i


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ITEM 16H

   Mine Safety Disclosure

   149ITEM 17

   Financial Statements

   149ITEM 18

   Financial Statements

   149ITEM 19

   Exhibits

   150GLOSSARY OF TERMS

   151SIGNATURES

   155
   ii


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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; andthe risk factors discussed under “Item 3.  Key Information—Risk Factors,” beginning on page 7.
 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 151.


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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, 2016, 2015, 2014, 2013, and 2012.  Our financial data as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016 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, 2014, 2013 and 2012 and for each of the two years ended December 31, 2013 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 31,2016(3)

   2016

   2015(4)

   2014(4)

   2013(4)

   2012(4)(5)US$

   R$

   R$

   R$

   R$

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

   5,864

   19,112

   20,599

   17,399

   14,634

   14,891Cost of electric energy services:Cost of electric energy

   3,437

   11,200

   13,312

   10,643

   8,197

   8,253Operating cost

   690

   2,249

   1,907

   1,672

   1,468

   1,378Services rendered to third parties

   416

   1,357

   1,049

   946

   1,010

   1,356Gross operating income

   1,321

   4,306

   4,331

   4,138

   3,960

   3,904Operating expenses:Sales expenses

   168

   547

   465

   403

   377

   468General and administrative expenses

   261

   849

   863

   774

   929

   724Other operating expenses

   119

   387

   358

   328

   285

   377Income from electric energy service

   774

   2,523

   2,645

   2,633

   2,370

   2,335Interest in associates and joint ventures

   96

   311

   217

   60

   121

   121Financial income (expense):Income

   368

   1,201

   1,143

   786

   699

   707Expense

   (814)

   (2,654)

   (2,551)

   (1,969)

   (1,671)

   (1,285)Net financial income (expenses)

   (446)

   (1,453)

   (1,408)

   (1,183)

   (971)

   (578)Income before taxes

   424

   1,381

   1,454

   1,511

   1,519

   1,878Social contribution

   (46)

   (151)

   (160)

   (169)

   (157)

   (178)Income tax

   (108)

   (351)

   (419)

   (455)

   (413)

   (493)Total taxes

   (154)

   (501)

   (579)

   (624)

   (570)

   (671)Net income

   270

   (879)

   875

   886

   949

   1,207Net income attributable to controlling shareholders

   276

   901

   865

   949

   937

   1,176Net income (loss) attributable to non‐controlling shareholders

   (7)

   (22)

   10

   (63)

   12

   31Earnings per share attributable to controlling shareholders(1):Basic

   0.27

   0.89

   0.85

   0.93

   0.92

   1.16Diluted

   0.27

   0.87

   0.83

   0.92

   0.90

   1.14Net income per ADS:Basic

   0.54

   1.77

   1.70

   1.86

   1.84

   2.31Diluted

   0.53

   1.74

   1.66

   1.83

   1.79

   2.28Dividends(2)

   66

   214

   205

   977

   931

   1,096Weighted average of number of common shares (in millions)(1)

   1,018

   1,018

   1,018

   1,018

   1,018

   1,018Dividends per share(1)(2)

   0.06

   0.21

   0.20

   0.96

   0.91

   1.08Dividends per ADS(2)

   0.13

   0.42

   0.40

   1.92

   1.83

   2.15
 
 (1) Reflects the capital increases that took place on April 29, 2015, and April 29, 2016 through the issuance of 30,739,955 and 24,900,531 shares, respectively.  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, 2016.


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Table of Contents (2) “Dividends” represent the total amount of dividends from net income for each period indicated, subject to approval of the shareholders at the general shareholders’ meeting to be held in the following year. (3) 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, 2016 of R$3.259to US$1.00.  The Brazilianrealrevalued significantly against the U.S. dollar during 2016, however, from R$3.905 to US$1.00 as of December 31, 2015.  The average of the month-end commercial selling rates during the year 2016 was R$3.483to US$1.00.  See “—Exchange Rates” below for more information regarding thereal/U.S. dollar exchange rate. (4) Data for 2014 and 2015 have been restated to reflect a change in presentation of the line item representing Changes in expected cash flows from Concession Financial Assets, which relates to our Distribution segment.  Since 2016 this line item has been included in Other operating revenues, within Net operating revenue, together with the other income related to the core activity of the asset.  This item was previously presented as part of Net financial expense.  We believe the new presentation more accurately reflects the business model of electricity distribution and provides a better representation of our operational and financial performance.  The reclassification does not affect total assets, equity, net income or cash flows.  For further information on this reclassification, see note 2.7 to our audited consolidated financial statements.  The selected historical financial data for 2013 and 2012 has not been restated to reflect the reclassification, and therefore is not fully comparable with the data for 2016, 2015 and 2014. (5) Data for 2012 has 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.


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Table of Contents BALANCE SHEET DATA  For the year ended December 31,2016(2)

   2016

   2015

   2014(3)

   2013

   2012(4)US$

   R$

   R$

   R$

   R$

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

   1,892

   6,165

   5,683

   4,357

   4,206

   2,435Consumers, concessionaires and licensees

   1,156

   3,766

   3,175

   2,251

   2,008

   2,205Derivatives

   50

   163

   627

   23

   2

   1Sector financial assets

   -

   -

   1,464

   611

   -

   -Other current assets

   394

   1,285

   1,559

   1,972

   1,048

   904Total current assets

   3,492

   11,379

   12,509

   9,215

   7,264

   5,545Noncurrent assets:Accounts receivable

   62

   203

   129

   123

   154

   162Derivatives

   197

   641

   1,651

   585

   317

   486Sector financial assets

   -

   -

   490

   322

   -

   -Financial asset of concession

   1,646

   5,363

   3,597

   2,835

   2,787

   2,343Investments in joint-ventures

   458

   1,494

   1,248

   1,099

   1,033

   1,022Property, plant and equipment

   2,980

   9,713

   9,173

   9,149

   7,717

   7,104Intangible Assets

   3,306

   10,776

   9,210

   8,930

   8,748

   9,180Other noncurrent assets

   798

   2,602

   2,525

   2,887

   3,022

   3,082Total noncurrent assets

   9,448

   30,792

   28,024

   25,930

   23,778

   23,379Total assets

   12,939

   42,171

   40,532

   35,144

   31,043

   28,294Current liabilities:Short‐term debt(1)

   1,052

   3,429

   3,641

   3,526

   1,837

   1,962Sector financial liabilities

   183

   598

   -

   22

   -

   -Other current liabilities

   1,532

   4,992

   5,884

   3,869

   3,068

   3,007Total current liabilities

   2,767

   9,018

   9,525

   7,417

   4,906

   4,969Noncurrent liabilities:Long‐term debt(1)

   5,748

   18,733

   18,093

   15,637

   15,187

   13,511Sector financial liabilities

   97

   317

   -

   -

   -

   -Other long‐term liabilities

   1,144

   3,729

   2,785

   2,693

   2,152

   2,553Noncurrent liabilities

   6,990

   22,780

   20,877

   18,330

   17,339

   16,064Non-controlling interest

   737

   2,403

   2,456

   2,454

   1,775

   1,510Net equity attributable to controlling shareholders

   2,445

   7,970

   7,674

   6,944

   7,024

   6,381Total liabilities and shareholders’ equity

   12,939

   42,171

   40,532

   35,144

   31,043

   28,294
 
 (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, 2016 of R$3.259 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 has 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.


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Table of Contents OPERATING DATA  For the year ended December 31,2016

   2015

   2014

   2013

   2012(4)Energy sold (in GWh):Residential

   16,473

   16,164

   16,501

   15,426

   14,567Industrial

   13,022

   12,748

   14,144

   14,691

   14,536Commercial

   9,720

   9,259

   9,437

   8,837

   8,714Rural

   2,474

   2,152

   2,326

   2,081

   2,093Public administration

   1,271

   1,278

   1,295

   1,234

   1,220Public lighting

   1,746

   1,649

   1,622

   1,586

   1,525Public services

   1,840

   1,797

   1,861

   1,820

   1,864Own consumption

   32

   33

   34

   34

   33Total energy sold to Final Consumers

   46,578

   45,082

   47,221

   45,709

   44,552Electricity sales to wholesalers (in GWh)

   21,459

   17,971

   14,988

   14,975

   14,429Total consumers (in thousands)(1)

   9,224

   7,751

   7,585

   7,386

   7,176Installed Capacity (in MW)(2)

   3,259

   3,164

   3,162

   2,988

   2,961Assured Energy (in GWh)(3)

   14,188

   13,550

   13,566

   12,758

   12,742Energy generated (in GWh)

   15,713

   17,066

   13,658

   11,427

   10,570
 
 (1) Represents active consumers (meaning consumers who are connected to the Distribution Network), rather than consumers invoiced at period‐end. (2) Commencing in 2016 we ceased to account for installed capacity of the Carioba (36 MW)thermoelectric plant and SHPP Cariobinha (1.3 MW), since these facilities are no longer active. (3) 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”. (4) 2012 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, 2016 of R$3.259to 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, 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

   4.195December 31, 2016

   3.259

   3.483

   3.119

   4.156
 
 (1) Average for period represents the average of the month‐end selling exchange rates during the relevant period.


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Table of Contents Month‐end

   Average for period(1)

   Low

   High(reaisper U.S. dollar)Month ended:October 2016

   3.181

   3.186

   3.119

   3.236November 2016

   3.397

   3.342

   3.202

   3.445December 2016

   3.259

   3.352

   3.259

   3.465January 2017

   3.127

   3.197

   3.127

   3.273February 2017

   3.099

   3.104

   3.051

   3.148March 2017

   3.093

   3.128

   3.077

   3.174April 2017 (through April 10)

   3.141

   3.120

   3.092

   3.141
 
 (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.


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Table of Contents 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 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 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 anual), 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 reduction 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 and authorizations, 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 or authorizations.  Depending on the gravity of the non‐compliance, these penalties could include the following: warning notices;fines per breach of up to 2.0% of the 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;


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Table of Contents 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; andtermination of the concession or authorization.
 In addition, the Brazilian government may terminate any of our concession agreements or authorizations 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 and authorizations.  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. 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”. In our Distribution business, we are required to forecast demand for electricity in the market.  If actual demand is different from our forecast, we could be forced to purchase or sell electricity in the spot market at prices that could lead to additional costs for us, which we may not be able to fully pass on to customers. Under the New Industry Model Law, an electricity distributor must contract in advance, through public bids, for 100% of the required electricity that it has forecast 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 under-forecast demand and purchase in advance less electricity than we need, in a manner for which we are considered liable under the New Industry Model Law and applicable regulation, we may be required to enter the spot market to purchase the additional electricity at prices substantially higher than under our long term purchase agreements.  We may be prevented from passing through this additional cost in full to consumers; and we would also be subject to penalties under applicable regulation.  On the other hand, if we over-forecast demand and purchase in advance more electricity than we need (for example, if a significant portion of our Potential Free Consumers migrate and purchase electricity in the Free Market), we may be required to sell the excess at prices substantially lower than under our concessions and authorizations.  In either circumstance, if there are significant differences between our forecast electricity needs and actual demand, 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”.


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Table of Contents Commercialization activity is subject to potential losses due to short-term variations in energy prices on the spot market.  In addition, we may not be able to buy electricity in the amount we need to meet our sales agreements, 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 Ordinance.  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 Ordinance No.  455/2012.  As a result, Ordinance No.  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”. 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 2016, according to data from the National Electrical System Operator (Operador Nacional do Sistema Elétrico), or ONS, approximately 76% 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 the Generation Scaling Factor, or GSF, therefore exposes operators of Hydroelectric Power Plants to spot price risk.  The GSF was activated in 2014, 2015 and 2016, requiring us to purchase energy, therefore 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 in our Generation segment, 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 were observed from 2013 through 2015, red tariff flags were applied throughout 2015 since introduction of the system in January 2015.  In 2016, due to an improvement in hydrological conditions, green tariff flags were applied in most months of the year.  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”.


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Table of Contents 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. 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 to Ordinance No.  515/2015 issued by the MME, the first revision of Assured Energy under this process was originally expected to be implemented for all Hydroelectric Power Plants (with the exception of SHPPs) in January 2017.  Since the application of the methodology of this new revision to each Power Plant is not yet available, however, the MME issued Ordinance No.  714/2016, pursuant to which the current Assured Energy for each Hydroelectric Power Plant will remain in effect until December 2017.  The first revision of Assured Energy is now expected to be implemented in January 2018.  We 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;


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Table of Contents construction and operational delays, or unanticipated cost overruns;the inability to win electricity auctions promoted by ANEEL; andunavailability of adequate funding. If we experience these or other problems, we may not be able to generate or distribute electricity in amounts consistent with our projections, which may have an adverse effect on our financial condition and results of operations. We are subject to environmental and health regulations that may become more stringent in the future and may result in increased liabilities and increased capital expenditures. Our activities are subject to comprehensive federal, state and municipal legislation, 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$1,011million in our Generation activities (R$954million in renewable sources and R$57 million in conventional sources), R$9,222 million in our Distribution activities, R$264 million in our commercialization and services activities and R$ 48 million in our transmission activities during the period from 2017 through 2021. At the date of this Annual Report, however, these planned capital expenditures have not yet been approved by our Board of Directors, and they therefore remain subject to change. 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.  In addition to the capital expenditures shown above, we invested R$51 million in 2016 and R$37 million in 2015 related to the construction of our transmission lines (under our Transmission activities), 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$2,722million in 2017 and approximately R$2,061 million in 2018, in each case subject to approval by our Board of Directors.  Of total budgeted capital expenditures over this period, R$3,772million are expected to be invested in our Distribution segment, R$846 million in our Renewable Generation segment and R$28 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$135 million in our commercialization and services activities.  We have already contractually committed to part of these expenditures, particularly in generation projects.  See “—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments”.  Planned capital expenditures for development of our generation capacity, and the related financing arrangements, are discussed in more detail under “Item 4.  Information on the Company—Generation of Electricity”.


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Table of Contents 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$1,724 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. 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, 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”. Our controlling shareholder’s interests could conflict with yours. On January 23, 2017, State Grid Brazil Power Participações Ltda., or State Grid Brazil, consummated the acquisition of common shares representing approximately 54.6% of our voting capital, pursuant to which it has the power to control us.  State Grid Brazil is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.  Our controlling shareholder may take actions that could be contrary to your interests, and our controlling shareholder will be able to prevent other shareholders, including you, from blocking these actions.  In particular, our controlling shareholder controls the outcome of decisions at shareholders’ meetings, and it can elect a majority of the members of our Board of Directors.  Our controlling shareholder can direct our actions in areas such as business strategy, financing, distributions, acquisitions and dispositions of assets or businesses.  Its decisions on these matters may be contrary to the expectations or preferences of our non-controlling shareholders, including holders of our ADSs.  For further information regarding State Grid Brazil’s acquisition and its announced intentions regarding shareholdings in our company, see “Item 4.  Information on the Company— Overview”. We are exposed to increases in prevailing market interest rates as well as foreign exchange rate risk. As of December 31, 2016, approximately 75% of our total indebtedness was denominated inreaisand indexed to Brazilian money‐market rates or inflation rates, or bore interest at floating rates.  The remaining 25% of our total indebtedness as of December 31, 2016 was denominated in foreign currency, substantially U.S. dollars, compared to approximately 32.0% as of December 31, 2015, although this foreign currency 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 these purchases from Itaipu.  Accordingly, when the Brazilianrealappreciates against the U.S. dollar, as was the case in 2016, our financing expenses decrease.


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Table of Contents 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, 2016, we had total debt of R$22,044million.  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, such as when we acquired RGE Sul in October 2016.  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, such as when we acquired RGE Sul in October 2016.  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. 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;


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Table of Contents 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; andother 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 (BB+) and again on February 17, 2016 (BB-); Fitch Ratings lowered its rating for Brazil from BBB- to BB+ on December 16, 2015 and later to BB with negative outlook on May 5, 2016; and Moody’s Investors Service downgraded Brazil to Ba2 with negative outlook on February 24, 2016 and has reaffirmed such rating on March 15, 2017. 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. 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.  Following the impeachment of former President Dilma Rousseff on August 31, 2016, uncertainty remains 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, which may 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 derived from changes in the political scenario and from the ongoing Lava Jato investigation, being conducted by the Office of the Brazilian Federal Prosecutor, and its impact on the Brazilian economy and political environment. Members of the Brazilian federal government and of the legislative branch, as well as senior officers of large state-owned companies, have faced allegations and, in certain cases, convictions related to crimes of political corruption, involving alleged bribes by means of kickbacks on contracts granted by the government to several infrastructure, oil and gas and construction companies.  The profits of these kickbacks allegedly financed the political campaigns of political parties of the government that were unaccounted for or not publicly disclosed, in addition to alleged personal enrichment of the recipients of the bribes. Certain of these companies are also facing investigations by the Brazilian Securities Commission (Comissão de Valores Mobiliários), or CVM, the U.S. Securities and Exchange Commission, or the SEC and the United States Department of Justice, or the DOJ. The potential outcome of these investigations is still uncertain, but they have already an adverse impact on the image and reputation of the implicated companies, political parties and on the general market perception of the Brazilian economy and political scenario.  We cannot predict whether such allegations and convictions will lead to further political and economic instability or whether new allegations or convictions against government officials will arise in the future.  In addition, we cannot predict the outcome of any such allegations and convictions nor their effect on the Brazilian economy. Developments in these proceedings and investigations could adversely affect our business, financial condition and results of operations.


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Table of Contents 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$2.656 on December 31, 2014; R$3.905 on December 31, 2015; and R$3.259on December 31, 2016.  On April 10, 2017, the exchange rate was R$3.141per US$1.00.  Therealmay continue to fluctuate significantly 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 2007 and 2016, the base interest rate in Brazil, or SELIC, varied between 7.25% p.a.  and 13.75% p.a., reaching its lowest level (7.25%) at the end of 2012.  On April 10, 2017, the SELIC rate was 12.25% 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. 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 1.6% in 2016.  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.


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Table of Contents 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 registration made by the custodian with the Brazilian Central Bank’s Information System, or the SISBACEN, for our common shares underlying the ADSs in Brazil, which permits the custodian to remit abroad proceeds related to dividends and other distributions with respect to the common shares.  If you surrender your ADSs and withdraw common shares, you will need to update your registration with the SISBACEN and enter into simultaneous foreign exchange transactions (without the effective remittance of funds) in order to re-enable the remittance abroad of proceeds related to the disposition of or distributions relating to the common shares.  Before entering into these foreign exchange transactions and updating the SISBACEN registration, you will not be able to remit abroad any proceeds relating to the common shares.  If you do not qualify under the foreign investment regulations you will generally be subject to less favorable tax treatment upon the sale of our common shares.  For further information, see “Item 10.  Additional Information— Allocation of Net Income and Distribution of Dividends-Payment of Dividends”. For the registration with the SISBACEN referred to above, as well as for entering into simultaneous foreign exchange transactions, 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 registration with SISBACEN may also be adversely affected by future legislative changes. Holders of ADSs may be unable to exercise preemptive rights with respect to our common shares. We may not be able to offer our common shares to U.S. holders of ADSs pursuant to preemptive rights granted to holders of our common shares in connection with any future issuance of our common shares unless a registration statement under the Securities Act is effective with respect to such common shares and preemptive rights, or an exemption from the registration requirements of the Securities Act is available.  We are not obligated to file a registration statement relating to preemptive rights with respect to our common shares, and we cannot assure you that we will file any such registration statement.  If such a registration statement is not filed and an exemption from registration does not exist, Citibank N.A., as depositary, will attempt to sell the preemptive rights, and you will be entitled to receive the proceeds of such sale.  However, these preemptive rights will expire if the depositary does not sell them, and U.S. holders of ADSs will not realize any value from the granting of such preemptive rights. The relative volatility and illiquidity of the Brazilian securities markets may substantially limit your ability to sell the common shares underlying the ADSs at the price and time you desire. Investing in securities that trade in emerging markets, such as Brazil, often involves greater risk than investing in securities of issuers in the United States, and such investments are generally considered to be more speculative in nature.  The Brazilian securities market is substantially smaller, less liquid, more concentrated and can be more volatile than major securities markets in the United States.  Accordingly, although you are entitled to withdraw the common shares underlying the ADSs from the depositary at any time, your ability to sell the common shares underlying the ADSs at a price and time at which you wish to do so may be substantially limited.  There is also significantly greater concentration in the Brazilian securities market than in major securities markets in the United States.  The ten largest companies in terms of market capitalization represented 54.9% of the aggregate market capitalization of theBM&FBOVESPA S.A.‐ Bolsa de Valores, Mercadorias & Futuros,or BM&FBOVESPA, as of December 31, 2016.The top ten stocks in terms of trading volume accounted for 42.8%, 39.3% and 46.3% of all shares traded on the BM&FBOVESPA in 2016, 2015, and 2014, respectively.


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Table of Contents 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 our 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 39,611GWh of electricity we distributed to approximately 9.2million consumers in 2016.  In electricity generation, our Installed Capacity at December 31, 2016 was 3,259 MW.  Through our subsidiary CPFL Renováveis, we are also involved in the building of one SHPP and two wind farms, as a result of which we expect to increase our Installed Capacity to 3,297 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 2016, the total amount of electricity sold by our commercialization subsidiaries was 90 GWh and 12,291 GWh to affiliated and unaffiliated parties, respectively. On September 2, 2016, our shareholder Camargo Correa entered into an agreement to sell its 23.6% stake in our company to State Grid Brazil Participações Ltda., or State Grid Brazil.  Following the announcement, other members of our controlling shareholders block also decided to sell their stakes to State Grid Brazil.  As a result, State Grid Brazil acquired approximately 54.6% of our voting capital.  State Grid Brazil is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.  The acquisition was approved by the Administrative Council for Economic Defense (Conselho Administrativo de Defesa Econômica – CADE), the Brazilian antitrust regulator, in September 2016 and by ANEEL in December 2016.  The acquisition was completed and control of our company was transferred to State Grid Brazil on January 23, 2017.  On February 16, 2017, State Grid Brazil announced that it intends to carry out a public tender offer to purchase all of the common shares of our company, at a price of  R$ 25.51 (US$ 8.28) per common share, in order to (i) cancel our registration as a Class A publicly-held company with the Brazilian Securities Commission (Comissão de Valores Mobiliários), or CVM; (ii) delist our company from the Novo Mercado section of the São Paulo Stock Exchange; (iii) delist our ADSs from the New York Stock Exchange and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the U.S. Securities and Exchange Commission. As per Significant Event Notice disclosed by both companies to the market on February 23, 2017, State Grid Brazil filled with CVM in February 22, 2017 requiring authorization for a Public Tender Offer for acquisition of CPFL Energia’s shares. Such request is currently under analysis by CVM. The following significant developments have occurred in our business since the beginning of 2014: In February 2014 CPFL Renováveis concluded the acquisition of 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.


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Table of Contents 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 2017 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.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 CPFL 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.  CPFL 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 to 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 spot 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 do 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 did not impact our consolidated financial statements for 2015.


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Table of Contents On 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 and Authorizations —Concessions”.In May 2016, two generation facilities at the Mata Velha SHPP commenced operations, over a year and a half ahead of schedule.  Mata Velha, located in Unaí, in the state of Minas Gerais, has Installed Capacity of 24 MW and average physical guarantee of 13.1 MW.  According to the A-5 auction of 2013, the plant’s energy trading agreement takes effect in January 2017.  Since the plant was completed ahead of schedule, a free market sale agreement was signed, valid until the A-5 2013 auction agreement takes effect.In May 2016, the Campo dos Ventos and São Benedito wind complexes started to enter into operations.  As of December 31, 2016, all nine wind farms in these complexes were operational.  The complexes have 231.0 MW (our share is 119 MW) of Installed Capacity and are located in the state of Rio Grande do Norte.On June 15, 2016, our subsidiary CPFL Jaguariúna Participações Ltda. agreed to acquire 100% of AES Sul Distribuidora Gaúcha de Energia S.A. (which subsequently changed its name to RGE Sul Distribuidora de Energia S.A., or RGE Sul) from AES Guaíba II Empreendimentos Ltda.  RGE Sul acts as an electric energy distributor in the State of Rio Grande do Sul and has the exclusive right for distribution of energy to the captive market of 118 cities in the State. The transaction closed on October 31, 2016, and the financial results of RGE Sul are reflected in our consolidated financial statements for November and December 2016.  The purchase price after adjustment amounted to R$1,592 million.  After accounting for R$95 million in cash and cash equivalents acquired within RGE Sul, our net cash outflow on acquisition of RGE Sul was R$1,497 million.


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Table of Contents The following chart provides an overview of our corporate structure at March 31, 2017:  Notes: (1) 51.54% stake of the availability of power and energy of Serra da Mesa HPP, regarding the Power Purchase Agreement between CPFL Geração and Furnas. (2) CPFL Energia holds RGE Sul through CPFL Jaguariúna.  Our core businesses are: Distribution.  In 2016, our nine fully‐consolidated distribution subsidiaries delivered 39,611 GWh of electricity to approximately 9.2 million consumers primarily in the states of São Paulo and Rio Grande do Sul.Conventional Generation.  At December 31, 2016, our conventional generation subsidiaries had Installed Capacity of 2,199 MW.  During 2016, we generated 9,216 GWh of electricity, and we had 9,952 GWh of Assured Energy at December 31, 2016, 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 51.60% 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) 39 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 423 MW, and (ii) one Small Hydroelectric Power Plants (Boa Vista II SHPP) under construction, scheduled to commence operations in 2020, and expected to have Installed Capacity of approximately 26.5 MW.  CPFL Renováveis also has 45 wind farms, of which (i) 43 wind farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, are operational and have aggregate Installed Capacity of 1,260 MW, and (ii) the remaining 2 wind farms are under construction, scheduled to commence operations in 2018, and expected to have Installed Capacity of approximately 48 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, 2016, our total consolidated Installed Capacity through our Renewable Generation segment (calculated on the proportional basis of our 51.60% interest in CPFL Renováveis) was 1,060 MW and we expect that our Renewable Generation segment will reach an Installed Capacity of 1,100 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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Table of Contents 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 2016, we sold 12,381GWh of electricity, of which 12,291GWh 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, 2016, our total consolidated Installed Capacity (calculated on the proportional basis of our 51.60% interest in CPFL Renováveis) was 3,259 MW, of which 2,199MW was generated through conventional sources and 1,060 MW 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.  Today, we continue to be the largest energy renewable generation group in terms of Installed Capacity in operation in Brazil and in South America, according to ANEEL and Bloomberg New Energy Outlook.


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Table of Contents Our total Installed Capacity at December 31, 2016 represents a 3.0% increase as compared to Installed Capacity of 3,164 MW at December 31, 2015, due to:  (i) the commencement of operations of the São Benedito and Campo dos Ventos wind complexes (nine wind farms) with aggregated installed capacity of 231 MW (our share is 119 MW); (ii) the commencement of operations of Mata Velha SHPP, with installed capacity of 24 MW (our share is 12 MW) and; (iii) ceasing of accounting for the installed capacity of thermoelectric plant Carioba (36 MW) and SHPP Cariobinha (1.3 MW), considering that these facilities are currently inactive.  By the end of 2020, when we expect the Boa Vista SHPPs and Pedra Cheirosa wind complex to become operational, we expect our total Installed apacity to reach 3,297 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 1,099 MW (calculated on the proportional basis of our 51.60% interest in CPFL Renováveis’ total portfolio of 2,129 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 46.3% of our consolidated net income in 2016.  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 nine 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.


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Table of Contents Our Service Territory   Distribution We are one of the largest electricity distributors in Brazil, based on the amount of electricity we delivered in 2016.  Our nine distribution subsidiaries together supply electricity to a region covering 302,001 square kilometers, primarily in the states of São Paulo and Rio Grande do Sul.  Their concession areas include 6791municipalities and a population of approximately 23 million people.  Together, they provided electricity to approximately 9.2million consumers as of December 31, 2016.  Our nine subsidiaries distributed approximately 12.3% of the total electricity distributed in Brazil in 2016, based on data from the EPE. Distribution Companies We have nine 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 4.3 million consumers at December 31, 2016.  In 2016, CPFL Paulista distributed 21,142 GWh of electricity, accounting for approximately 23.6% 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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Table of Contents 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, 2016.  In 2016, CPFL Piratininga distributed 8,594 GWh of electricity, accounting for approximately 9.6% 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 85,965 square kilometers in the state of Rio Grande do Sul with a population of approximately 4.0million 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, 2016.  In 2016, RGE supplied 8,026 GWh of electricity, accounting for approximately 38.5% of the total electricity distributed in the state of Rio Grande do Sul and 2.4% of the total electricity distributed in Brazil during the year.RGE Sul.  RGE Sul Distribuidora de Energia S.A., or RGE Sul, supplies electricity to a concession area covering 98,127 square kilometers in the state of Rio Grande do Sul with a population of approximately 3.4 million people.  Its concession area covers 118 municipalities, including the cities of Canoas, São Leopoldo, Novo Hamburgo, Santa Maria and Uruguaiana.  RGE Sul had approximately 1.3 million consumers at December 31, 2016.  In November and December 2016 (the two months during which RGE Sul was reflected in our financial results following our acquisition of RGE Sul), RGE Sul supplied 1,152 GWh of electricity.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 24 municipalities in the northwest part of the state of São Paulo and three municipalities in the state of Paraná.  In 2016, CPFL Santa Cruz distributed 1,032 GWh of electricity to approximately 209,000 consumers, accounting for approximately 1.2% 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 2016, CPFL Jaguari distributed 451 GWh of electricity to approximately 41,000 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 2016, CPFL Mococa distributed 204 GWh of electricity to approximately 47,000consumers.CPFL Leste Paulista.  Companhia Leste Paulista de Energia, or CPFL Leste Paulista, supplies electricity to a concession area covering 2,915square kilometers, which includes seven municipalities of the state of São Paulo.  In 2016, CPFL Leste Paulista distributed 287 GWh of electricity to approximately 58,000consumers.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 2016, CPFL Sul Paulista distributed 390 GWh of electricity to approximately 85,000 consumers.


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Table of Contents 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 nine 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. 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, 2016, our distribution networks consisted of 315,538 kilometers of distribution lines, including 450,247 distribution transformers.  Our nine distribution subsidiaries had 12,181 kilometers of High Voltage distribution lines between 34.5 kV and 138 kV.  At that date, we had 523 transformer substations for transforming High Voltage into Medium Voltages for subsequent distribution, with total transforming capacity of 17,316 mega‐volt amperes.  Of the industrial and commercial consumers in our concession area, 377 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 historical 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.  According to the same information, RGE Sul’s loss rates also compare favorably to the national average, although to a lesser degree than our three historical largest subsidiaries. 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 nine 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 341,899 inspections during 2016, which we believe led to a recovery of receivables estimated at more than R$47 million. *Power Outages* The following table sets forth the frequency and duration of electricity outages per consumer for the years ended December 31, 2016 and 2015 for each of our distribution subsidiaries: Year ended December 31, 2016CPFL Paulista

   CPFL Piratininga

   RGE

   RGESul(3)

   CPFL Santa Cruz

   CPFL Jaguari

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul PaulistaSAIFI1

   4.99

   3.80

   7.58

   9.39

   4.08

   6.07

   6.73

   5.66

   11.22SAIDI2

   7.61

   6.97

   14.45

   19.43

   5.60

   7.02

   10.58

   7.96

   14.90
 
 (1) Frequency of outages per consumer per year (number of outages). (2) Duration of outages per consumer per year (in hours). (3) Acquired by us on October 31, 2016.  RGE Sul was not a subsidiary of our company for the first 10 months of 2016.


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Table of Contents Year ended December 31, 2015CPFL Paulista

   CPFL Piratininga

   RGE

   RGESul(3)

   CPFL Santa Cruz

   CPFL Jaguari

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul PaulistaSAIFI1

   4.89

   4.31

   8.33

   8.42

   6.34

   4.61

   5.92

   5.67

   9.47SAIDI2

   7.75

   7.25

   15.98

   19.11

   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). (3) Acquired by us on October 31, 2016.  RGE Sul was not a subsidiary of our company in 2015. 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 2015, 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. 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.  RGE Sul’s duration and frequency of outages remain below the national average, however.  Following our acquisition of RGE Sul on October 31, 2016, we are currently in discussions with the regulator regarding planned investments designed to improve RGE Sul’s performance indicators, taking into account its current indicators and the characteristics of its concession area. 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 8.6% 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 2016, we invested approximately R$1,201 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$1,895 million for such purposes throughout 2017. We strive to improve response times for our repair services.  The quality indicators for the provision of energy by CPFL Paulista and CPFL Piratininga have maintained levels of excellence while complying with regulatory standards.  This was also mainly the result of our efficient operational logistics, including the strategic positioning of our teams and the technology and automation of our network and operation centers, together with a preventive maintenance and conservation plan. Purchases of Electricity Most of the electricity we sell is purchased from unrelated parties, rather than generated by our facilities.  In 2016, 10.3% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries (including our joint ventures). In 2016, we purchased 10,497GWh of electricity from the Itaipu Power Plant, amounting to 16.4% of the total electricity we purchased.  Itaipu is located on the border of Brazil and Paraguay and is subject to a bilateral treaty between the two countries pursuant to which Brazil has committed to purchasing specified amounts of electricity.  This treaty will expire in 2023.  Electric utilities operating under concessions in the midwest, south and southeast regions of Brazil are required by law to purchase a portion of the electricity that Brazil is obligated to purchase from Itaipu.  The amounts that these companies must purchase are governed by take-or-pay contracts with tariffs established in US$/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$25.78/kW.  Our purchases represent approximately 16.9% of Itaipu’s total supply to Brazil, disregarding the two-month period purchases of electricity by our distribution subsidiary RGE Sul, which control was acquired on October 31, 2016.  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.


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Table of Contents The Itaipu Power Plant has an exclusive transmission network.  Distribution companies pay a fee for the use of this network. In 2016, we paid an average of R$192.99 per MWh for purchases of electricity from Itaipu, compared with R$279.65 during 2015 and R$132.82 during 2014.  These figures do not include the transmission fee. We purchased 53,478 GWh of electricity in 2016 from generating companies other than Itaipu, representing 83.6% of the total electricity we purchased.  We paid an average of R$ 164.77 per MWh for purchases of electricity from generating companies other than Itaipu, compared with R$210.44 per MWh in 2015 and R$201.79 per MWh in 2014.  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”. 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 31,2016

   2015

   2014(in GWh)Energy purchased for resaleItaipu

   10,497

   10,261

   10,417Electric Energy Trading Chamber - CCEE

   1,195

   2,946

   5,074Proinfa Program

   1,058

   1,058

   1,043Energy purchased in the Regulated Market and through bilateral contracts

   51,225

   44,342

   42,345TOTAL

   63,975

   58,607

   58,879
  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 above the replacement contracts 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”.


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Table of Contents Transmission Tariffs.  In 2016, we paid a total of R$1,351 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 17.7% of revenues from electricity sales in our Distribution segment in 2016.Residential consumers.  Sales to final residential consumers accounted for 46.2% of our revenues from electricity sales in our Distribution segment in 2016.Commercial consumers.  Sales to final commercial consumers, which include service businesses, universities and hospitals, accounted for 23.2% of our revenues from electricity sales in our Distribution segment in 2016.Rural consumers.  Sales to final rural consumers accounted for 3.6% of our revenues from electricity sales in our Distribution segment in 2016.Other consumers.  Sales to other consumers, which include public and municipal services such as street lighting, accounted for 9.3% of our revenue of electricity sales in our Distribution segment in 2016.
 Retail Distribution Tariffs.  We classify our consumers into two different groups, Group A consumers and Group B consumers, based on the voltage level at which electricity is supplied to them.  Each consumer is placed in a certain tariff level defined by law and based on its respective classification.  Some discounts are available depending on the consumer classification, tariff level or environment for trading (Free Consumers and generators).  Group B consumers pay higher tariffs.  Tariffs in Group B vary by type of consumer (residential, rural, other categories and public lighting).  Consumers in Group A pay lower tariffs, decreasing from A4 to Al, because they are supplied electricity at higher voltages, which requires lower use of the energy distribution system.  The tariffs we charge for sales of electricity to Final Consumers are determined pursuant to our concession agreements and regulations ratified by ANEEL.  These concession agreements and related regulations establish a cap on tariffs that provides for annual, periodic and extraordinary adjustments.  For a discussion of the regulatory regime applicable to our tariffs and their adjustment, see “—The Brazilian Power Industry”. Group A consumers receive electricity at 2.3 kV or higher.  Tariffs for Group A consumers are based on the voltage level at which electricity is supplied, and the time of day electricity is supplied.  The consumers may opt for a different tariff applicable in peak periods in order to optimize the use of the electric network.  Tariffs for Group A consumers consist of two components:  the TUSD and the tariff for energy consumption, or TE.  The TUSD, expressed 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.


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Table of Contents The following tables set forth our average retail prices for each consumer category for 2016 and 2015.  These prices include taxes (ICMS, PIS and COFINS) and were calculated based on our revenues and the volume of electricity sold in 2016 and 2015. Year ended December 31, 2016CPFL Paulista

   CPFL Piratininga

   RGE

   RGE Sul(1)

   CPFL Santa Cruz

   CPFL Leste Paulista

   CPFL Sul Paulista

   CPFL Jaguari

   CPFL Mococa(R$/MWh)Residential

   591.80

   679.76

   665.32

   742.37

   665.54

   599.01

   616.72

   580.38

   650.89Industrial

   569.16

   575.46

   496.30

   582.93

   584.23

   524.54

   460.80

   466.23

   536.60Commercial

   571.80

   609.34

   654.51

   734.76

   650.17

   567.98

   577.97

   531.61

   617.03Rural

   322.86

   419.32

   332.16

   275.02

   404.93

   352.51

   379.15

   353.03

   382.57Other

   434.09

   436.56

   262.92

   505.37

   333.73

   435.06

   419.70

   405.37

   437.20Total

   546.79

   612.09

   501.75

   590.87

   537.89

   499.18

   521.06

   490.20

   549.57
  Year ended December 31, 2015CPFL Paulista

   CPFL Piratininga

   RGE

   RGE Sul(2)

   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
  (1)Average retail prices of RGE Sul reflect the two-month period (November and December 2016) following our acquisition of RGE Sul on October 31, 2016. (2)Average retail prices of RGE Sul are not presented, since RGE Sul was not a subsidiary of our company in 2015. 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. 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 2016, tariff revenues for the use of our network by Free Consumers amounted to R$2,057 million.  The average tariff for the use of our network was R$130.88/MWh and R$119.92/MWh in 2016 and 2015, 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.


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Table of Contents 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 2016, we responded to approximately 46.4 million inquiries.  We also provide customer service through our branch offices, which handled approximately 7.6 million customer requests in 2016.  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. 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 3,259 MW as of December 31, 2016.  Most of the electricity we produce comes from our Hydroelectric Power Plants.  We generated a total of 15,713GWh in 2016, 17,066 GWh in 2015 and 13,658 GWh in 2014, 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”.


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Table of Contents Conventional Generation Hydroelectric Power Plants At December 31, 2016, 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 former 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 1,515.5 GWh per year.  We sell our participation in the Assured Energy of this Complex to affiliates in our group.  These facilities are operated by CERAN, under CPFL Geração’s supervision. Monte Claro.  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.


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Table of Contents In addition, discussions with ANEEL and other entities in the transmission sector are ongoing regarding the conditions under which we will transfer the Monte Claro Substation to the Basic Network, which would eliminate maintenance costs and our responsibility for operation of the Substation. Barra Grande.  This facility became fully operational in May 2006 with a total Installed Capacity of 690 MW and total Assured Energy of 3,334.1 GWh per year.CPFL Geração owns a 25.01% interest in this plant.  The other shareholders of the joint venture are Alcoa (42.18%), CBA (Companhia Brasileira de Alumínio) (15.0%), DME (Departamento Municipal de Eletricidade de Poços de Caldas) (8.82%), andCamargo Corrêa Cimentos S.A.(9.0%).  We sell our participation in the Assured Energy of this facility to affiliates in our group. Campos Novos.  We own a 48.72% interest in ENERCAN, a joint venture formed by a consortium of private and public sector companies that was granted a 35‐year concession in May 2000 to construct, finance and operate the Campos Novos Hydroelectric Facility.  The plant was constructed on the Canoas River in the state of Santa Catarina, and became fully operational in May 2007 with a total Installed Capacity of 880 MW and Assured Energy of 3,310.4 GWh per year, of which our interest is 1,612.9 GWh per year.  The other shareholders of ENERCAN are CBA (33.14%), Votorantim Metais Níqueis S.A.  (11.63%) 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).  The transfer process was completed in October 2016. Luis Eduardo Magalhães.  We own a 6.93% interest in the Assured Energy from the Luis Eduardo Magalhães Power Plant, also known as UHE Lajeado.  The plant is located on the Tocantins River in the state of Tocantins and became fully operational in November 2002 with a total Installed Capacity of 902.5 MW and Assured Energy of 4,613 GWh per year.  The plant was built by Investco S.A., a consortium comprised of Lajeado Energia, EDP (Energias de Portugal), CEB (Companhia Energética de Brasília) and Paulista Lajeado (which we acquired in 2007). Thermoelectric Power Plants We operate three Thermoelectric Power Plants.  Termonordeste, which commenced operations in December 2010, and Termoparaíba, which commenced operations in January 2011 under ANEEL authorizations, are powered by fuel oil from the EPASA complex, with total Installed Capacity of 341.5 MW and total Assured Energy of 2,169.9 GWh per year.  On December 31, 2016, 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.  Commencing 2016 we have ceased to include Carioba in our installed capacity since the facility is inactive.


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Table of Contents Small Hydroelectric Power Plants At December 31, 2016, 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.
 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.


34

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Table of Contents 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, 2016: 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%

   172.5

   690.0

   833.7

   3,334.1

   2005

   2036Campos Novos

   CPFL Geração

   48.72%

   428.8

   880.0

   1,612.9

   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%

   -

   -

   -

   -

   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

   578.9

   1,084.5

   2011

   2042SUBTOTAL ‐ Thermoelectric plants

   

   

   182.2

   

   1,157.4Small Hydroelectric PlantsCariobinha

   CPFL Geração

   100%

   -

   -

   -

   -

   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

   

   

   24.4

   

   84.0TOTAL – Conventional Generation

   

   

   2,197.6

   

   9,952.2
 
 (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 plants.  On July 8, 2016, ANEEL published Order n° 1.776/2016, which recommended that MME terminate the Cariobinha UHE, without reversal of assets. (3) Hydroelectric projects with an Installed Capacity equal to or less than 5,000 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.  Renewable Generation At December 31, 2016, through our subsidiary CPFL Geração, we owned a 51.60% 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%.


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Table of Contents 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 Power 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 eight Brazilian states and its business contributes to the local and regional economic and social development. At the date of this Annual Report, CPFL Renováveis consists of the generation entities described below.  All Installed Capacity and Assured Energy numbers stated in the discussion below refer to the full capacity of the plant in question rather than our consolidated share of such energy, which only reflects our interest in the plant. 28 subsidiaries involved in the generation of electric energy through 40 Small Hydroelectric Power Plants, consisting of (i) 39 SHPPs that are operational, with aggregate Installed Capacity of 423 MW, located in the states of São Paulo, Santa Catarina, Rio Grande do Sul, Paraná, Minas Gerais and Mato Grosso, and (ii) one SHPP (Boa Vista II), with 26.5 MW of Installed Capacity, which is under construction and scheduled to commence operations in 2020.49 subsidiaries involved in the generation of electric energy from wind sources.  Of this total, 43 farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, are operational and have aggregate Installed Capacity of 1,260.2 MW.  The remaining two farms are under construction, scheduled to commence operations in 2018, and are expected to have Installed Capacity of approximately 48 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.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 5 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.


36

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Table of Contents CPFL Renováveis operates 40 of our 50 (39 operational and 1 under construction) Small Hydroelectric Power Plants primarily under the concession and registration regime, all located in the state of São Paulo, Minas Gerais, Mato Grosso, Paraná, Santa Catarina and Rio Grande do Sul. There have been several revisions, mainly consisting of reductions, to CPFL Renováveis’ Assured Energy, on account of reductions in the expected operational performance. The automation of these power plants allows us to carry out control, supervision and operations remotely.  Since CPFL Energia acquired CPFL Renováveis’ renewable business, we have established an operational center for the management and monitoring of our power plants in Jundiaí, 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 Limpoor MDL), and the corresponding mechanism stablished by the Paris Agreement (Mecanismo de Desenvolvimento  Sustentável, or MDS), yet to be regulated, 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 issues related to the boiler format and methodology of the approval process. We currently have eight biomass‐fueled thermoelectric plants under the authorization regime, located in the states of São Paulo, Minas Gerais, Rio Grande do Norte and Paraná. CPFL Bioenergia.  In partnership with Baldin Bioenergia, we have constructed a co‐generation plant in the city of Pirassununga, in the state of São Paulo, that became operational in August 2010.  This co‐generation plant has total Installed Capacity of 45 MW.  The plant has an Assured Energy of 112.1 GWh and all 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 MWa 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 183.6 GWh in force until 2030 with CPFL Brasil.


37

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Table of Contents 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 71.5 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.  CPFL 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 40 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. 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 Abeeólica (Brazilian Wind Power Association) indicate a wind energy potential of 500 GW in Brazil, a volume that greatly exceeds the country’s current total Installed Capacity of 10.6 GW as of December 2016 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.


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Table of Contents We currently have 43 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. 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.


39

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Table of Contents 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 29.1 MW and aggregate Assured Energy of 15.3 MWavg.  This wind farm commenced operations in April 2015. São Benedito and Campo dos Ventos Complexes.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 have an Installed Capacity of 231 MW and aggregate Assured Energy of 1,059.1 GWh/year.  This project has a PPA in force until 2034 for the São Benedito Complex and 2033 for the Campo dos Ventos Complex. The following table sets forth certain information relating to our principal renewable facilities, held by CPFL Renováveis (51.60% our share) in operation as of December 31, 2016: 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

   

   2032Mata Velha

   12.4

   24.0

   59.2

   114.8

   2016Monjolinho

   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

   2027Pirapó

   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)

   218

   423

   1,065

   2,063


40

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Table of Contents Capacity (MW)

   Assured Energy (GWh)

   Placed in service

   Facility upgraded

   Concession expiresOur share

   TOTAL

   Our share

   TOTALThermoelectric 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 I

   13.0

   25.2

   61.5

   119.1

   2016

   

   2046Campo dos Ventos II

   15.5

   30.0

   67.8

   131.4

   2013

   

   2046Campo dos Ventos III

   13.0

   25.2

   60.6

   117.4

   2016

   

   2046Campo dos Ventos V

   13.0

   25.2

   59.2

   114.8

   2016

   

   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

   

   2045São Domingos

   13.0

   25.2

   63.7

   123.5

   2016

   

   2032Taiba

   8.5

   16.5

   30.3

   58.8

   2008

   

   2032Ventos de São Benedito

   15.2

   29.4

   68.5

   132.7

   2016

   

   2032Ventos de Santo Dimas

   15.2

   29.4

   68.5

   132.7

   2016

   

   2032Ventos de São Martinho

   7.6

   14.7

   292.1

   565.9

   2016

   

   2032Ventos de Santa Mônica

   15.2

   29.4

   68.5

   132.7

   2016

   

   2032Ventos de Santa Úrsula

   14.1

   27.3

   68.5

   132.7

   2016

   

   2032SUBTOTAL ‐ Wind farms (our share)

   651

   1,260

   2,612

   5,060Solar power plantTanquinho

   0.6

   1.1

   1.0

   1.7

   2012

   

   -SUBTOTAL – Solar power plant (our share)

   1

   1

   1

   2TOTAL (our share only)

   1,060

   2,054

   4,236

   8,208
 
 (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 5,000 kW has changed and currently only a registration is required.  The concession contracts are valid until the concession expires. (2) Hydroelectric projects with installed capacity equal to or less than 5,000 kW that are registered with the regulatory authority and the administrator of power concessions but do not require concession or authorization processes for operating.


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Table of Contents Expansion of Installed Capacity Despite the 0.9% decline in consumption in 2016 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 Boa Vista II SHPP and the Pedra Cheirosa wind complex, which are expected to have an aggregate Installed Capacity of 75 MW (of which our consolidated share will be 39 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)Pedra Cheirosa Complex (two companies)(1) (2)

   

   48

   

   229

   

   2016

   

   2018

   

   51.60

   

   25

   

   118Boa Vista II Small Hydro Power Plant (one company)

   

   26.5

   

   123

   

   2017

   

   2020

   

   51.60

   

   13

   

   64TOTAL

   

   74

   

   351

   

   

   

   

   

   

   

   38

   

   181
 (1) Pedra Cheirosa I and II. (2) This project was reviewed and the Installed Capacity has changed from 51 MW to 48 MW. Although the inferior installed capacity, more efficient energy generators will generate the same volume of energy.  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. Boa Vista II SHPP.Boa Vista SHPP is located in the state of Minas Gerais.  Boa Vista SHPP is expected commence operations in 2020.  The SHPP construction commenced in February 2017.  It will have an aggregate Installed Capacity of 26 MW and aggregate Assured Energy of 123 GWh/year.  The energy was sold in the A-5/2015 Energy Auction, held in 2015. Electricity Commercialization We carry out electricity commercialization activities mainly through our subsidiary CPFL Brasil.  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


42

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Table of Contents providing agency services to Free Consumers and Power Generators before the CCEE and other agents, such as guidance on their operational requirements. As a retailer trade company CPFL Brasil is also responsible for the energy load of Free and Special Consumers, centralizing the management of contracts and the relationship with the Electric Energy Trading Chamber (CCEE).  Companies do not need to be CCEE members, which simplifies the process.  The focus of CPFL Brasil’s activities in retail market are potentially Free Consumers, such as retail chains, banks, supermarkets, universities, among others. 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, 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, which offers service relating to climatization, cogeneration, motive power and lighting for the creation of customized solutions in power efficiency, and promotes savings, sustainability and power security.  CPFL ESCO also offers distributed photovoltaic generation services, a source of generation that injects power into the distribution company grid directly.  This kind of generation reduces the use of the transmission system and requires less generation of centralized power plants, benefiting the consumer and the energy sector as a whole.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.


43

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Table of Contents 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:Nect provides administrative services such as human resources, materials purchasing and logistics, maintenance and administrative infrastructure for the companies within our group.  Nect 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 in Brazil are subject to three types of contractual framework, depending on their generation capacity: Pursuant to Law No.  9,074/1995 (as amended by Law No.  13,360/2016), only hydroelectric generation projects with a capacity greater than 50,000 kW are now implemented through concessions granted by ANEEL following a public bidding process (which leads to 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 agreement, the public bidding note and regulations applicable at the time of the request for renewal.  ANEEL has the power to deny a request to extend a concession period.Hydroelectric Power Plants with capacity greater than 5,000 kW but equal to or lower than 50,000 kW now only require regulatory authorization from ANEEL, as opposed to a concession.  Authorizations are renewable at the discretion of ANEEL on a case‐by‐case basis.  ANEEL must provide justification for its decisions and any renewal must foster the public interest.Hydroelectric Power Plants with capacity equal to or less than 5,000 kW only require registration with ANEEL rather than a concession agreement or an authorization.


44

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Table of Contents Other generation projects such as wind farms, solar and Thermoelectric Power Plants are implemented through an authorization from ANEEL, without a public bid or concession.  The only exceptions are Thermoelectric Power Plants with a capacity greater than 50,000 kW and which have been designated as a service in the public interest:  these projects are also subject to public bidding and concession procedures, similar to hydroelectric projects with a capacity greater than 50,000 kW mentioned above. For further information about concessions and authorizations, see “—Concessions and Authorizations—Concessions”. 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 1998012/1997

   

   RGE Sul

   

   Rio Grande do Sul

   

   30 years from November 1997013/1997

   

   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 5,000 kW, operates under a regulatory registration 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 ANEEL


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Table of Contents Concession no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodThermoelectric 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)

   -  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

   30 yearsDispatch No. 1990

   CPFL Renováveis

   Andorinhas

   Rio Grande do Sul

   (3)

   (3)002/2011

   CPFL Renováveis

   Buritis

   São Paulo

   up to November 2027

   (3)002/2011

   CPFL Renováveis

   Capão Preto

   São Paulo

   up to November 2027

   (3)002/2011

   CPFL Renováveis

   Chibarro

   São Paulo

   up to November 2027

   (3)Resolution No. 475

   CPFL Renováveis

   Diamante

   Mato Grosso

   up to November 2027

   (3)002/2011

   CPFL Renováveis

   Dourados

   São Paulo

   up to November 2027

   30 years004/2011

   CPFL Renováveis

   Eloy Chaves

   São Paulo

   up to November 2027

   30 years002/2011

   CPFL Renováveis

   Esmeril

   São Paulo

   up to November 2027

   30 years002/2011

   CPFL Renováveis

   Gavião Peixoto

   São Paulo

   up to November 2027

   (3)Resolution No. 1,987/2005

   CPFL Renováveis

   Guaporé

   Rio Grande do Sul

   (3)

   (3)004/2011

   CPFL Renováveis

   Jaguari

   São Paulo

   up to November 2027

   30 years002/2011

   CPFL Renováveis

   Lençóis

   São Paulo

   up to November 2027

   (3)004/2011

   CPFL Renováveis

   Monjolinho

   São Paulo

   up to November 2027

   (3)


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Table of Contents Concession no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal period004/2011

   CPFL Renováveis

   Pinhal

   São Paulo

   up to November 2027

   30 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

   (3)002/2011

   CPFL Renováveis

   São Joaquim

   São Paulo

   up to November 2027

   20 years004/2011

   CPFL Renováveis

   Socorro

   São Paulo

   up to November 2027

   (3)003/2011

   CPFL Renováveis

   Santana

   São Paulo

   up to November 2027

   (3)003//2011

   CPFL Renováveis

   Três Saltos

   São Paulo

   up to November 2027

   (3)
  
 (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 greater than 5,000 kW that were granted through a concession process with the regulatory authority and the administrator of power concessions, prior to changes made by Law No.  13,360/2016.  Pursuant to Law No.  13,360/2016, only Hydroelectric Power Plants with capacity greater than 50,000 kW now require a concession; those with capacity of more than 5,000 kW up to 50,000 kW are subject to an authorization from ANEEL; and those with capacity equal to or less than 5,000 kW only require registration with ANEEL rather than a concession or authorization. (3) Hydroelectric projects with an Installed Capacity equal to or less than 5,000 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.  Since November 17, 2016, due to changes made by Law No.  13,360/2016, hydroelectric projects with an Installed Capacity equal to or less than 5,000 kW no longer require concession or authorization processes for operating, but only registration with ANEEL. (5) The Macaco Branco and Rio do Peixe concessions were transfered from CPFL Centrais Geradoras to CPFL Geração in Septemer 30, 2015 (see “–Overview”).  Authorizations Conventional generation Authorization no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodThermoelectric plantsResolution 2,277

   EPASA

   Termoparaíba Thermoelectric Power Plant

   Paraíba

   35 years from December 7, 2007

   At the discretion of MMEResolution 2,277

   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

   30 yearsResolution No. 587

   SPE Alto Irani Energia S.A.

   Alto Irani

   Santa Catarina

   30 years from October 30, 2002

   30 yearsResolution No. 606

   SPE Arvoredo Energia S.A.

   Arvoredo

   Santa Catarina

   30 years from November 7, 2002

   30 years


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Table of Contents Authorization no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodResolution No. 348

   SPE Barra da Paciência Energia S.A.

   Barra da Paciência

   Minas Gerais

   30 years from December 20, 1999

   30 yearsResolution No.540

   SPE Cachoeira Grande Energia S.A.

   Cachoeira Grande(*)

   Minas Gerais

   30 years from October 15, 2003

   30 yearsResolution No. 349

   SPE Cocais Grande Energia S.A.

   Cocais Grande

   Minas Gerais

   30 years from December 23, 1999

   30 yearsResolution No. 17

   SPE Corrente Grande Energia S.A.

   Corrente Grande

   Minas Gerais

   30 years fromJanuary 17, 2000

   30 yearsResolution No. 198

   Figueirópolis Energética S.A.

   Figueirópolis

   Mato Grosso

   30 years from May 04, 2004

   30 yearsResolution No. 705

   Ludesa Energética S.A.

   Ludesa

   Santa Catarina

   30 years from december 17, 2002

   30 yearsResolution No. 262

   Mata Velha Energética S.A.

   Mata Velha

   Minas Gerais

   30 years from May 16, 2002

   30 yearsResolution No. 370

   SPE Ninho da Águia Energia S.A.

   Ninho da Águia

   Minas Gerais

   30 years from December 30, 1999

   30 yearsResolution No. 652

   Novo Horizonte Energética S.A.

   Novo Horizonte

   Paraná

   30 years from november 26, 2002

   30 yearsResolution No. 406

   SPE Paiol Energia S.A.

   Paiol

   Minas Gerais

   30 years from August 07, 2002

   30 yearsResolution No. 607

   SPE Plano Alto Energia S.A.

   Plano Alto

   Santa Catarina

   30 years from November 7, 2002

   30 yearsResolution No. 2510

   SPE Salto Góes Energia S.A.

   Salto Góes

   Santa Catarina

   30 years from August 19, 2010

   30 yearsResolution No.718

   SPE Santa Cruz Energia S.A

   Santa Cruz(*)

   Minas Gerais

   30 years from December 18, 2002

   30 yearsResolution No. 13

   SPE São Gonçalo Energia S.A.

   São Gonçalo

   Minas Gerais

   30 years from January 14, 2000

   30 yearsOrdinance No. 352

   SPE Santa Luzia Energética S.A.

   Santa Luzia

   Santa Catarina

   35 years from December 21, 2007

   30 yearsResolution No. 355

   SPE Varginha Energia S.A.

   Varginha

   Minas Gerais

   30 years from December 23, 1999

   30 yearsResolution No. 367

   SPE Várzea Alegre Energia S.A.

   Várzea Alegre

   Minas Gerais

   30 years from December 30, 1999

   30 yearsOrdinance No. 502

   SPE Boa Vista II Energia S.A.

   Boa Vista II

   Minas Gerais

   35 years from November 09, 2015

   30 yearsThermoelectric 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 authorityOrdinance No. 129

   CPFL Bio Pedra S.A.

   Pedra Thermoelectric Power Plant

   São Paulo

   35 years from February 28, 2011

   At the discretion of the granting authority


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Table of Contents Authorization no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodWind 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 authorityOrdinance No. 557

   Macacos Energia S.A.

   Macacos

   Rio Grande do Norte

   35 years from September 29, 2011

   At the discretion of the granting authority


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Table of Contents Authorization no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodOrdinance 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 authorityResolution No. 4562

   Ventos de Santo Dimas Energias Renovaveis Ltda.

   Ventos de Santo Dimas

   Rio Grande do Norte

   30 years from March 07, 2014

   At the discretion of the granting authority


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Table of Contents Authorization no.

   Independent Power Producers / Concessionaire

   Plant

   State

   Term

   Maximum renewal periodResolution 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 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, 2016 was R$9,713 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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Table of Contents 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, 2016, the Installed Capacity of power generation in Brazil was 150,390 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 133,000 km of transmission lines with voltage equal to or greater than 230 kV and processing capacity of over 325,000 MVA from the state of Rio Grande do Sul through the state of Amazonas. According to the EPE, electricity consumption in Brazil decreased by 0.9% in 2016, reaching 464,001 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.


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Table of Contents Currently, approximately 31% 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 2.2% of the market share. The Distribution segment in Brazil remains fragmented, with six companies controlling approximately 51% of the market.  We are the largest player, with 14.3% 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.


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Table of Contents 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 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.


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Table of Contents 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”.


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Table of Contents 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.  Authorizations have a term of up to 35 years, and can be renewed, at the discretion of the granting authority, for up to 20 years, pursuant to Law No.  9,074/1995. 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.  Independent Power Producers and concessionaire companies are subject to a series of penalties for the failure to comply with provisions of the authorizations.  The following penalties may be applied:  (i) warning notices; (ii) fines per breach of up to 2.0% of the annual revenues generated by the relevant authorization, or, if the relevant authorization is non-operational, up to 2.0% of the estimated value of the energy that would have been produced for the 12 months prior to the breach; (iii) injunctions related to construction activities; (iv) restrictions on the operation of existing facilities and equipment; (v) intervention; or (vi) termination of the authorization. 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. 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.


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Table of Contents The New Industry Model Law introduced material changes to the regulation of the power industry, with the intention to (i) provide incentives to private and public entities to build and maintain generation capacity and (ii) assure the supply of electricity within Brazil at adequate tariffs through competitive public electricity auction processes.  The key features of the New Industry Model Law include: Creation of two “environments” for the trading of electricity, including:  (i) the Regulated Market, a more stable market in terms of supply of electricity; and (ii) a market specifically addressed to certain participants (i.e., Free Consumers and commercialization companies), called the Free Market, that permits a certain degree of competition.

Restrictions on certain activities of Distributors, so as to require them to focus on their core business of distribution, to promote more efficient and reliable services to Captive Consumers.

Elimination of self‐dealing, in order to provide an incentive to Distributors to purchase electricity at the lowest available prices rather than buying electricity from related parties.

Maintenance of contracts entered into prior to the New Industry Model Law, in order to provide regulatory stability for transactions carried out before its enactment.
 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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Table of Contents 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 5,000 kW and equal or inferior to 30,000 kW, (ii) hydroelectric generators with capacity superior to 5,000 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”.


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Table of Contents 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. 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 23 auctions for new generation projects, 16 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.


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Table of Contents 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% 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$533.82, according to ANEEL’s Resolution 2,190/2016.  Before such Resolution, the maximum value of PLD was R$422.56 (Resolution No.  2,002/2015) and R$388.48 (Resolution No.  1,832/2014). 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.


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Table of Contents 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.


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Table of Contents 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.


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Table of Contents 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.


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Table of Contents 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, a yellow tariff flag was applied for the month of March and green tariff flags were applied from April to October 2016.  In November, a yellow tariff flag was applied but in December a green tariff flag was applied once again.  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.


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Table of Contents 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.


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Table of Contents In 2013, due to adverse hydrological conditions, the ONS dispatched a number of Thermoelectric Power Plants, leading to increased costs.  These dispatches caused a significant increase in the ESS‐SE.  Since the ESS‐SE charge applies only to distribution companies (although it can subsequently be passed on by them to consumers) and to Free Consumers, the CNPE decided, through Resolution No. 03/2013, to spread the cost by extending the ESS‐SE charge to all players in the electrical energy industry.  This decision increased the cost base of our subsidiaries in businesses other than Distribution (since they cannot pass on the cost to consumers), principally our Generation segment.  However, certain industry participants, including our Generation subsidiaries, are contesting the validity of Resolution No.  03/2013 and have obtained a court injunction, which was confirmed by the Brazilian Federal Supreme Court, exempting them from the ESS‐SE. Fee for the Use of Water – CFURH The New Industry Model Law requires that holders of a concession and authorization to use water resources must pay a fee of 7.00% 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.


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Table of Contents 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).   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 and RGE Sul in April 2018 and for RGE in June 2018.  See “—Background—Periodic Revisions —RTP”. 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.


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Table of Contents 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 2017.  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. 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. In May 2016, two generation facilities at the Mata Velha SHPP commenced operations, over a year and a half ahead of schedule.  Mata Velha, located in Unaí, in the state of Minas Gerais, has Installed Capacity of 24 MW and average physical guarantee of 13.1 MW.  According to the A-5 auction of 2013, the plant’s energy trading agreement took effect in January 2017.  Since the plant was completed ahead of schedule, a free market sale agreement was signed, valid until the A-5 2013 agreement took effect. On June 15, 2016, our subsidiary CPFL Jaguariúna Participações Ltda. agreed to acquire 100% of AES Sul Distribuidora Gaúcha de Energia S.A.  (which subsequently changed its name to RGE Sul Distribuidora de Energia S.A., or RGE Sul) from AES Guaíba II Empreendimentos Ltda.RGE Sul acts as an electric energy distributor in the State of Rio Grande do Sul and has the exclusive right for distribution of energy to the captive market of 118 cities in the State.  The transaction closed on October 31, 2016, and the financial results of RGE Sul are reflected in our consolidated financial statements for November and December 2016.  The purchase price after adjustment amounted to R$1,592 million.  After accounting for R$95 million in cash and cash equivalents acquired within RGE Sul, our net cash outflow on acquisition of RGE Sul was R$1,497 million. In December 2016, the last 15 of 110 wind turbines of the Campo dos Ventos wind complex (consisting of the São Domingos, Ventos de São Martinho and Campo dos Ventos I, III and V Wind Farms) and São Benedito wind complex (consisting of the Ventos de São Benedito, Ventos de Santo Dimas, Santa Mônica and Santa Úrsula Wind Farms) started to enter into operations.  The first wind turbines commenced operations in May 2016.  The complexes have 231 MW of Installed Capacity.  The Campo dos Ventos and São Benedito wind farms are located in the state of Rio Grande do Norte.  By the end of 2020, when we expect the Boa Vista SHPPs and Pedra Cheirosa wind complex to become operational, we expect our total Installed Capacity to reach 3,297 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 2016, sales to Captive Consumers represented 67.9% of the volume of electricity we delivered and 72.8% of our operating revenues, compared to 69.7% of the volume of electricity we delivered and 65.7% of our operating revenues in 2015.  These proportions may decline if consumers migrate from captive to free status. Our operating revenues and our margins depend substantially on the tariff‐setting process, and our Management focuses on maintaining a constructive relationship with ANEEL, the Brazilian government and other market participants so that the tariff‐setting process fairly reflects our interests and those of our consumers and shareholders.  For a description of tariff regulations, see “Item 4.  Information on the Company—The Brazilian Power Industry—Distribution Tariffs”.


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Table of Contents Tariffs are determined separately for each of our nine 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 and RGE Sul, 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, CPFL Jaguari, RGE and RGE Sul, 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.  No extraordinary revision occurred in 2016.
 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 2013 through the date of this annual report.  Rates of tariff increase should be evaluated in light of the Brazilian inflation rate.  See “—Background—Brazilian Economic Conditions”.


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Table of Contents CPFL Paulista

   CPFL Piratininga

   RGE

   RGE Sul

   CPFL Santa Cruz

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul Paulista

   CPFL Jaguari2013Economic adjustment(1)

   4.53%

   9.69%

   ‐10.66%

   (6)

   12.15%

   ‐1.83%

   7.96%

   6.98%

   10.76%Regulatory adjustment(2)

   0.95%

   ‐2.27%

   0.34%

   (6)

   ‐2.82%

   8.83%

   ‐1.47%

   ‐4.71%

   ‐8.06%Total adjustment

   5.48%

   7.42%

   ‐10.32%

   (6)

   9.32%

   7.00%

   6.48%

   2.27%

   2.71%2014Economic adjustment(1)

   14.56%

   15.81%

   18.83%

   (6)

   9.89%

   2.00%

   ‐4.74%

   ‐3.16%

   1.17%Regulatory adjustment(2)

   2.62%

   3.92%

   2.99%

   (6)

   4.96%

   ‐4.07%

   ‐2.93%

   ‐2.35%

   ‐4.90%Total adjustment

   17.18%

   19.73%

   21.82%

   (6)

   14.86%

   ‐2.07%

   ‐7.67%

   ‐5.51%

   ‐3.73%2015Economic adjustment(1)

   37.31%

   40.22%(4)

   -8.07%

   (6)

   22.01%

   28.90%

   28.82%

   30.24%

   40.07%Regulatory adjustment(2)

   4.14%

   16.15%(4)

   4.31%

   (6)

   12.67%

   ‐5.55%

   ‐8.02%

   ‐5.36%

   ‐1.61%Total adjustment

   41.45%

   56.37%(4)

   -3.76%

   (6)

   34.68%

   23.34%

   20.80%

   24.88%

   38.46%2016Economic adjustment(1)

   -0.29%

   -5.35%

   -0.67%

   (6)

   11.59%(5)

   11.90%(5)

   17.01%(5)

   16.89%(5)

   17.01%(5)Regulatory adjustment(2)

   10.18%

   -7.19%

   -0.81

   (6)

   10.92% (5)

   4.67%(5)

   4.03%(5)

   7.46%(5)

   12.45%(5)Total adjustment

   9.89%

   -12.54%

   -1.48%

   (6)

   22.51%(5)

   16.57%(5)

   21.04%(5)

   24.35%(5)

   29.46%(5)2017Economic adjustment(1)

   2.13%

   (3)

   (3)

   (3)

   1.37%

   3.45%

   3.18%

   0.98%

   3.88%Regulatory adjustment(2)

   -2.93%

   (3)

   (3)

   (3)

   -2.65%

   -1.80%

   -2.42%

   0.66%

   -1.83%Total adjustment

   -0.80%

   (3)

   (3)

   (3)

   -1.28%

   1.65%

   0.76%

   1.64%

   2.05%
  
 (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 RGE Sul occurs in June and for CPFL Piratininga, in October. (4)       Represents the effect of Periodic Revisions – RTP for CPFL Piratininga that occurred in 2015, considering that there is no Annual Adjustment – RTA in the year of Periodic Revisions – RTP. (5)       Represents the effect of Periodic Revisions – RTP for CPFL Santa Cruz, CPFL Mococa, CPFL Leste Paulista, CPFL Sul Paulista and CPFL Jaguari that occurred in 2016, considering that there is no Annual Adjustment – RTA in the year of Periodic Revisions – RTP.  Additionally, 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. (6)       Tariffs defined prior to the acquisition of RGE Sul.  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 positively impacted our financial condition and results of operations. As of 2016, 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.


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Table of Contents 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)RGE Sul

   April 2003

   (5)

   April 2008

   (5)

   April 2013

   (5)

   April 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 Sul will take place in April 2018 and for RGE will take place in June 2018. (5)   Tariffs defined prior to the acquisition of RGE Sul.  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.


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Table of Contents The table below shows the impact of this extraordinary tariff adjustment on our subsidiaries: CPFL Paulista

   CPFL Piratininga

   RGE

   RGE Sul

   CPFL Santa Cruz

   CPFL Mococa

   CPFL Leste Paulista

   CPFL Sul Paulista

   CPFL Jaguari2013Economic adjustment

   -15.3%

   -11.3%

   -12.0%

   (1)

   -6.8%

   -7.6%

   -17.2%

   -18.4%

   -25.4%Regulatory adjustment

   -0.5%

   1.1%

   0.7%

   (1)

   3.7%

   1.8%

   2.3%

   0.0%

   0.1%Total adjustment

   -15.8%

   -10.2%

   -11.4%

   (1)

   -3.1%

   -5.8%

   -14.9%

   -18.4%

   -25.3%
  (1)   Tariffs defined prior to the acquisition of RGE Sul.  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

   RGE Sul

   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%

   (2)

   0.0%

   0.0%

   0.0%

   0.0%

   0.0%Regulatory adjustment

   32.28%

   29.78%

   37.16%

   (2)

   5.16%

   11.81%

   14.52%

   17.02%

   16.80%Total adjustment

   32.28%

   29.78%

   37.16%

   (2)

   5.16%

   11.81%

   14.52%

   17.02%

   16.80%
  (1)   On April 7, 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. (2)   Tariffs defined prior to the acquisition of RGE Sul. 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 2016, we purchased 63,975 GWh, compared to 58,607 GWh in 2015. 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.


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Table of Contents 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 2016, we purchased 10,497 GWh of electricity from Itaipu (16.4% of the electricity we purchased in terms of volume), as compared to 10,261 GWh (17.5% of the electricity we purchased in terms of volume) in 2015.  See “Item 4.  Information of the Company—Purchases of Electricity”.  The price of electricity from Itaipu is set in U.S. dollars to reflect the costs of servicing its indebtedness.  Accordingly, the price of electricity purchased from Itaipu increases in Brazilianreaiswhen therealdepreciates against the U.S. dollar (and decreases when therealappreciates).  The change in our costs for Itaipu electricity in any year is subject to the Parcel A Cost recovery mechanism described below. Most of the electricity we acquired in the Free Market was purchased by our commercialization subsidiary CPFL Brasil, which resells electricity to Free Consumers and other concessionaires and licensees (including our subsidiaries).  See “—The New Industry Model Law—The Free Market”. Recoverable Cost Variations—Parcel A Costs We use the CVA (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.


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Table of Contents On November 25, 2014, ANEEL approved an amendment to distribution concession contracts.  On December 10, 2014, our nine 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. Operating Segments As discussed in note 31 to our audited annual consolidated financial statements, we present our financial results in 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 represented 78.7% of our net operating revenue in 2016 (compared with 82.0% in 2015), but its contribution to our net income was smaller at 46.3% of our net income for the year, as further explained in “Results of Operations—2016 compared to 2015—Net Income” below (by comparison, our Distribution segment accounted for 71.5% of our net income in 2015 and 95.3% in 2014). The contributions of our Distribution, Conventional Generation, Renewable Generation, Commercialization and Services segments to the net operating revenues and net income for the years ended December 31, 2016, 2015 and 2014 are presented in the following table: Distribution

   Conventional Generation

   Renewable Generation

   Commercialization

   Services2016Net operating revenue

   78.7%

   5.2%

   8.8%

   10.9%

   2.1%Net income

   46.3%

   57.4%

   -16.0%

   12.8%

   6.1%2015Net operating revenue

   82.4%

   4.8%

   7.8%

   8.7%

   1.4%Net income

   71.5%

   32.3%

   -6.4%

   10.1%

   5.9%2014Net operating revenue

   79.2%

   6.8%

   7.9%

   12.5%

   2.0%Net income

   95.3%

   12.2%

   -19.0%

   15.3%

   3.2%
  Our Conventional Generation Sources segment consists in substantial part of Hydroelectric Power Plants, and our Renewable Generation Sources segment consists of wind farms, Biomass Thermoelectric Power Plants, 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, 2016, our Renewable Generation Sources segment provided 17.4% 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 (-16.0%).  As of December 31, 2016, 2.4% of the property, plant and equipment in our Renewable Generation Sources segment was under construction, compared to 8.9% as of December 31, 2015.


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Table of Contents 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 Conventional Generation Sources, Renewable Generation Sources, Commercialization and Services segments all sell electricity and provide services to our Distribution segment.  Our consolidated financial statements eliminate revenues and expenses that relate to sales from one subsidiary to another within 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, costs and expenses 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, 2016, 2015 and 2014:


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Table of Contents Distribution

   Conventional Generation Sources

   Renewable Generation Sources

   Commercialization

   Services

   Other (*)

   Elimination

   Total2016Net Revenue

   15,017,166

   593,775

   1,334,571

   2,024,350

   81,595

   60,633

   -

   19,112,089(-) Inter-segment Revenues

   22,526

   409,338

   338,357

   62,757

   318,770

   8,661

   (1,160,410)

   -Income from electric energy service

   1,253,557

   671,631

   439,961

   158,829

   65,363

   (66,734)

   -

   2,522,608Financial income

   781,365

   182,574

   132,653

   31,513

   10,742

   61,655

   -

   1,200,503Financial expense

   (1,331,973)

   (562,196)

   (667,344)

   (24,761)

   (5,272)

   (62,432)

   -

   (2,653,978)Income before taxes

   702,950

   603,424

   (94,730)

   165,581

   70,832

   (67,510)

   -

   1,380,547Income tax/social contribution

   (295,748)

   (98,530)

   (46,311)

   (53,225)

   (17,019)

   9,343

   -

   (501,490)Net Income

   407,202

   504,894

   (141,041)

   112,357

   53,813

   (58,167)

   -

   879,057Total Assets(**)

   22,887,786

   5,310,924

   12,427,137

   466,021

   345,372

   701,103

   -

   42,138,343Capital Expenditures and other intangible assets

   1,200,586

   24,044

   929,768

   3,713

   42,952

   4,199

   -

   2,205,262Depreciation and Amortization

   (591,334)

   (126,596)

   (553,169)

   (3,779)

   (12,870)

   (3,417)

   -

   (1,291,166)2015Net Revenue

   16,945,222

   572,553

   1,262,297

   1,716,348

   55,547

   47,246

   -

   20,599,212(-) Inter-segment Revenues

   22,318

   411,038

   335,979

   82,544

   239,088

   3,136

   (1,094,101)

   -Income from electric energy service

   1,556,770

   542,738

   460,772

   124,933

   30,617

   (70,396)

   -

   2,645,434Financial income

   740,628

   110,018

   131,354

   42,840

   44,098

   74,310

   -

   1,143,247Financial expense

   (1,256,801)

   (549,286)

   (599,303)

   (38,386)

   (4,858)

   (102,477)

   -

   (2,551,110)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

   13,752,040

   722,623

   982,613

   1,790,822

   151,037

   61

   -

   17,399,196(-) Inter-segment Revenues

   19,668

   467,761

   397,630

   387,788

   193,483

   -

   (1,466,329)

   -Income from electric energy service

   1,695,773

   482,214

   231,280

   205,108

   45,072

   (26,119)

   -

   2,633,327Financial income

   448,277

   84,884

   98,991

   29,543

   6,380

   117,720

   -

   785,794Financial expense

   (838,387)

   (482,671)

   (464,713)

   (29,104)

   (10,221)

   (143,407)

   -

   (1,968,503)Income before taxes

   1,305,663

   144,112

   (134,442)

   205,547

   41,230

   (51,806)

   -

   1,510,304


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Table of Contents Distribution

   Conventional Generation Sources

   Renewable Generation Sources

   Commercialization

   Services

   Other (*)

   Elimination

   TotalIncome 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)
 
 (*)   Refers to recorded assets and transactions that are not related to any of our operating reportable segments. (**) Intangible assets (net of amortization) recorded at the parent company level, allocated to their respective segments.  We also derive non‐material income at the parent company level that is not related to or included in the results of our reportable segments and is reflected in the column “Other” in the table above.  General expenses and indirect costs are generally allocated to the relevant 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.  Conversely, rising unemployment and decreasing household income tend to reduce demand and depress 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, 2016, 2015 and 2014:


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Table of Contents 2016

   2015

   2014Growth in GDP (in reais)(1)

   (3.6%)

   (3.8%)

   0.2%Unemployment rate ‐ % average(2)

   12.6%

   8.5%

   6.8%Credit to individuals (non‐earmarked resources) ‐ % GDP

   12.9%

   13.5%

   15.1%Growth in Retail Sales

   (6.4%)

   (4.0%)

   2.2%Growth (contraction) in Industrial Production

   (7.1%)

   (8.1%)

   (3.2%)Inflation (IGP‐M)(3)

   7.2%

   10.5%

   3.7%Inflation (IPCA)(4)

   6.3%

   10.7%

   6.4%Average exchange rate–US$1.00(5)

   R$3.483

   R$3.339

   R$2.360Year‐end exchange rate–US$1.00

   R$3.259

   R$3.905

   R$2.656Depreciation (appreciation) of therealvs. U.S. dollar

   (16.5%)

   47.0%

   13.4%
 
 Sources:Focus Report, Instituto Brasileiro de Geografia e Estatísticaand the Brazilian Central Bank. (1)    Source:Focus Report. (2)   Unemployment rate based on the National Household Sampling Survey (Pesquisa Nacional por Amostra de Domicílios, or PNAD), released by the Instituto Brasileiro de Geografia e Estatística (IBGE). (3)   Inflation (IGP‐M) is the general market price index measured by the Fundação Getúlio Vargas. (4)   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). (5)   Represents the average of the commercial selling exchange rates on the last day of each month during the period.  The years 2015 and 2016 in Brazil were marked by severe economic contraction, ongoing political crisis and poor economic indicators.  These factors, combined with adjustments to government spending budgets, resulted in negative GDP growth of 3.6% in 2016 and 3.8% in 2015, according to the Brazilian Central Bank.  In March 2017 the government announced that the last three months of 2016 marked the eighth consecutive quarter of negative GDP growth, the longest period of recession on record. As a result, employment levels, household income and debt service costs – all of which are key drivers for energy consumption – continued to worsen during 2016.  For example, the number of formal job vacancies fell by 7% from 2015 to 2016 according to a report by CAGED – Cadastro Geral de Empregados e Desempregados. The devaluation of the real and the increasing risk affecting Brazil resulted in successive downgrades of the country’s credit rating:  Standard & Poor’s (September 2015 and February 2016); Fitch Ratings (December 2015 and May 2016); Moody’s Investors Service (February 2016). These devaluations 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 classifications reflect, among other factors, the outlook for the Brazilian electricity sector, the political and economic context, country risk, hydrological conditions in the areas where our plants are located, our operational performance and our level of debt.  Our rating were reduced in 2016 from AA+ to AA- by Standard and Poor’s as a result of the downgrading of Brazil’s investment grade due to changes in economic and political scenarios, as mentioned in the paragraph above. Despite the downgrading of Brazil’s investment grade in September 2015, Fitch Ratings did not reduce our rating in 2016, have maintained it at AA. As of the date of this report, our ratings from both agencies have been sustained. Reclassification of information for 2015 and 2014 Data for 2014 and 2015 have been restated to reflect a change in presentation of the line item representing Changes in expected cash flows from Concession Financial Assets, which relates to our Distribution segment.  Starting in 2016 this line item has been included in Other operating revenues, within Net operating revenue, together with the other income related to the core activity of Distribution Segment.  This item was previously presented as part of Net financial income.  We believe the new presentation could more properly reflects the business model of electricity distribution and provides a better representation of our operational and financial performance.  The reclassification does not affect total assets, equity, net income or cash flows.  For further information on this reclassification, see note 2.7 to our audited consolidated financial statements.


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Table of Contents Results of Operations—2016 compared to 2015 Net Operating Revenues Compared to the year ended December 31, 2015, our net operating revenues decreased 7.2% (or R$1,487million) to R$19,112 million in the year ended December 31, 2016.  This decrease in operating revenue primarily reflected a negative variation of R$4,601 million in the Sector Financial Assets and Liabilities and the decrease of R$207 million in revenue from adjustment of expected cash flow related to the Concession Financial Asset, both discussed in the section “Other Operating Revenue” below. The above-mentioned decreases were offset by:  (i) a decrease of R$2,031 million in deductions from operating revenues, discussed in the section “Deductions from operating revenues” below; (ii) an increase of R$836 million in other operating revenues, discussed in “Other Operating Revenue” below; and (iii) an increase of R$573 million in our gross operating revenues from sales to Final Consumers, discussed in “Sales by Destination” below. The following discussion describes changes in our net operating revenues by destination and by segment, based on the items comprising our gross revenues. Sales by Destination Sales to Final Consumers Compared to the year ended December 31, 2015, our gross operating revenues from sales to Final Consumers (that is, our billed supply, which includes TUSD revenue from captive consumers) increased 2.4% (or R$573 million) in the year ended December 31, 2016, to R$23,998 million.  Our gross operating revenues primarily reflect sales to Captive Consumers in concession areas from our nine distribution subsidiaries, as well as TUSD revenue from the use of our network by Captive Consumers, both of which are subject to tariff adjustment as described below.  Our gross operating revenue also reflects sales to Free Consumers in commercial and industrial categories. Distribution companies’ tariffs are adjusted every year, in percentages that are specific to each category of consumer.  The month in which the annual tariff adjustment becomes effective varies, impacting both the year in which the tariff adjustment takes place as well as the following year.  The adjustments for our largest subsidiaries occur in April (CPFL Paulista), June (RGE) and October (CPFL Piratininga).  RGE Sul, which has been included in our consolidated income statements since November 1, 2016, has its annual tariff adjustment in April. In the year ended December 31, 2016, overall average energy prices decreased by 0.8%, mainly due to the combined effect of:  (i) the adoption of a green tariff flag during most of 2016, leading to a reduction of the average tariff when compared to the red tariff flag that applied in most of 2015; and (ii) the combined positive effect of tariff adjustments for 2015 and 2016 (Annual Adjustment – RTA or Periodic Revision – RTP, since there is no Annual Adjustment in the year of Periodic Revisions) for our distribution subsidiaries (discussed under “Regulated Distribution Tariffs”).  Overall average prices for Final Consumers in 2016 were higher for all consumer classes: Residential and commercial consumers.  With respect to Captive Consumers (which represent 98.5% of the total amount sold to this category in our consolidated financial statements), average prices increased 3.5% for residential and 3.8% for commercial, due to the positive average overall tariff adjustment, offset in part by lower prices linked to the green flag during most of 2016, as described above.  With respect to Free Consumers (which consists of commercial consumers only), the average price decreased 2.9%.

Industrial consumers.  Average prices increased 0.5%, mainly due to tariff adjustments and the adoption of the green flag during most of 2016 as described above.  With respect to Free Consumers, the average price for industrial consumers decreased 1.9%.  The decrease in the average price for industrial consumers was due to the tariff decrease, which resulted from renegotiations of tariffs in contracts with Free Consumers.
 The total volume of energy sold to Final Consumers in the year ended December 31, 2016 increased 3.3% compared to the year ended December 31, 2015.  This increase represents the combined effect of:


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Table of Contents (i) an increase of 33.5% (or 1,638 GW) in the volume of energy sold to Conventional Free Consumers (driven by increases of 1,210 GW to industrial and 421 GW to commercial consumers) by our commercialization subsidiaries, as a result of migration of consumers from Captive to the Free Consumer category; (ii) an increase of 405 GW in the volume of enery from renewable sources sold to Special Free Consumers (those consumers whose contracted energy demand between 500 kV and 3 MW, who may purchase energy from renewable sources only); (iii) the inclusion of RGE Sul’s distribution operations in our consolidated results for the last two months of 2016, which led to an increase of 1,141 GW, compared with no contribution in 2015; (iv) these effects were offset in part by a reduction of 4.2% (or 1,686 GW) in the volume sold by our distribution subsidiaries (other than RGE Sul, as discussed above) to Captive Consumers, mainly in the industrial (1,097 GW) and commercial (557 GW) categories, due to migration of some of these consumers to the “Free Consumer” category. The volume sold to residential and commercial categories, which accounts for 65.8% for our sales to Final Consumers, increased by 1.9% (or 308 GW) and 5.0% (or 461 GW), respectively.  These increases were due to the combined effect of: Residential:(i) the inclusion of RGE Sul’s distribution operations in our consolidated results for the last two months of 2016, which led to an increase of 426 GW sold to residential consumers, compared to no volume in 2015; (ii) offset in part by a reduction of 0.7% (or 118 GW) of the volume sold by our distribution subdidiaries (excluding RGE Sul) to the residential category, due to an increase in unemployment, decreasing real incomes and an increase in electricity tariffs.

Commercial:(i) an increase of 421 GW in the volume of energy sold to the commercial category by our commercialization subsidiaries, due to migration of consumers from captive to the free market; (ii) an increase of 405 GW in the volume of energy from renewable sources sold to commercial consumers who elected to become Special Free Consumers, whose contracted energy demand is between 500 kV and 3 MW, and are allowed to purchase energy only from renewable sources; (iii) the inclusion of RGE Sul’s distribution operations in our consolidated results for the last two months of 2016, which led to an increase of 191 GW sold to comercial consumers, compared to no volume in 2015; and (iv) partly offset by a reduction of 6.2% (or 557 GW) of energy sold to commercial consumers by our distribution subsidiaries, reflecting the migration of some consumers from the captive to the free market, as well as the impact of macroeconomic factors such as the increase in unemployment.
 The volume sold to industrial consumers, which represented 22.0% of our sales to Final Consumers in 2016 (compared with 23.6% in 2015), increased by 2.1% in the year ended December 31, 2016 compared to the year ended December 31, 2015.  Volumes to Captive Consumers in this category decreased 11.5%, which represents the net effect of a decrease of 1,097 GW related to our distribution subsidiaries (except RGE Sul) offset in part by 162 GW contributed by RGE Sul in the last two months of 2016 (compared to no volume in 2015).  The net decrease reflects the migration of industrial consumers from the captive to the free market.  Regarding Free Consumers, volumes sold increased by 26.2% (or 1,210 GW), reflecting the same migration of consumers, as well as improvements in Brazilian economic conditions during 2016.


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Table of Contents Sales to wholesalers Compared to the year ended December 31, 2015, our gross operating revenues from sales to wholesalers in the year ended December 31, 2016 decreased 1.2% (or R$41 million) to R$3,496 million (11.4% of gross operating revenues), due mainly to a decrease of 26.7% (or R$233 million) in sales of energy in the spot market (driven by lower average prices despite an increase of 43.9% in our volume sold).  This decrease was offset by:  (i) an increase of 6.6% (or R$148 million) in sales of electricity to other concessionaires and licensees, which represents the net effect of an increase of 15.0% in the volume of energy sold and a decrease of 7.2% in the average price compared to 2015; and (ii) an increase of 9.9% (or R$48 million) in sales of electricity from our facility Serra da Mesa to Furnas, driven by an increase of 9.6% in the average price, with the volume remaining relatively stable.  For more information on net operating revenues from our segments, see “—Sales by Segment”. Other operating revenues As mentioned above, commencing 2016 the line item representing Changes in expected cash flows from Concession Financial Assets (which relates to our Distribution segment) has been included in Other operating revenues, within Net operating revenue, together with the other income related to its core activity.  This item was previously presented as part of Net financial expense.  Data for 2015 and 2014 have been restated to reflect this reclassification. Compared to the year ended December 31, 2015, our other gross operating revenues (other than TUSD revenue from captive consumers) decreased 55% (or R$3,901 million) to R$3,189 million in the year ended December 31, 2016 (10.4% of our gross operating revenues), mainly due to: (i) a negative variation of R$4,601 million in revenue from Sector Financial Assets and Liabilities, which represented an expense of R$2,095 million in 2016 compared with revenue of R$2,507 million in 2015.  This expense 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 pay (or receive) cash to from consumers through subsequent tariffs or to pay to or receive from the granting authority any remaining amounts at the expiration of the concession.  This leads to an adjustment in order to recognize the future decrease (or increase) in tariffs to take account of lower (or additional) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue.  The decrease in this item in 2016 was driven mainly by a decrease of R$930 million in contributions to the Energy Development Account – CDE, a decrease of R$752 million related to electric energy cost and a decrease of R$731 million related to the pass-through from Itaipu.  For further information, see note 8 to our audited annual consolidated financial statements; and (ii) the decrease of R$207 million in revenue from adjustment of expected cash flow related to the Concession Financial Asset (see notes 2.7 and 3.1 of our audited annual consolidated financial statements). These decreases were partially offset by: (i) the increase of 41.4% (or R$370 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); (ii) an increase of 29.4% (or R$307 million) in revenue from construction of concession infrastructure; and (iii) an increase of 8.4% (or R$159 million) in TUSD revenue from the use of our network by Free Consumers who purchase electricity from other suppliers due to annual tariff adjustment on such contracts. 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 37.9% of our gross operating revenue in the year ended December 31, 2016 and 39.9% in the year ended December 31, 2015.  Compared to the year ended December 31, 2015, these deductions decreased by 14.8% (or R$2,031 million) to R$11,672 million in 2016, mainly due to:  (i) a decrease of R$1,366 million in tariff flag revenues recognized, which are required to be paid into the Tariff Flag Resources Centralizing Account administered by the CCEE; (ii) a decrease of R$609 million in contributions made to the CDE Account as a result of the new quotas defined by ANEEL in 2016 (see note 27.6 to our audited annual consolidated financial statements); and (iii) a decrease of 10.9% (or R$323 million) in PIS and COFINS taxes, mainly due to the decrease in our gross operating revenues (the calculation basis for these taxes).  These decreases were partially offset by an increase of 5.3% (or R$249 million) in ICMS tax, as a result of the increase in our billed supply.


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Table of Contents Sales by segment Distribution Compared to the year ended December 31, 2015, net operating revenues from our Distribution segment decreased 11.4% (or R$1,928 million) to R$15,040 million in the year ended December 31, 2016.  This decrease primarily reflected the decrease of R$4,011 million in gross operating revenue, due to the following fluctuations: (i) a negative variation of R$4,601 million in revenue from Sector Financial Assets and Liabilities, which posted an expense of R$2,095 million in 2016 compared with revenue of R$2,507 million in 2015 (see “Other Operating Revenues” above); (ii) the decrease of R$207 million in revenue from adjustment of expected cash flow related to the Concession Financial Asset (see “Other Operating Revenues” above); and (iii) a decrease of R$56 million in sales to wholesalers, driven by a decrease of 49.6% in the average price of energy sold in the spot market despite significant increases in our volume of energy sold; partially offset by: (i) an increase of R$370 million in revenue related to the low-income subsidy and discounts on tariffs reimbursed by funds from the CDE Account; (ii) an increase of R$295 million in revenue from construction of concession infrastructure; (iii) an increase of R$160 million in TUSD revenue from the use of our network by Free Consumers who purchase electricity from other suppliers; and (iv) an increase of 0.6% (or R$136 million) in revenue from sales to Final Consumers due to the combined effect of the R$677 million contribution from RGE Sul in the last two months of 2016 and the R$218 million positive average tariff adjustment from residential consumers, partially offset by a R$751 million reduction from commercial and industrial consumers due mainly to the migration of some of these consumers from the captive to the free market. These negative effects on gross operating revenue from our Distribution segment were partially offset by a decrease of 15.6% (R$2,083 million) in deductions from the segment’s operating revenues, mainly due to:  (i) a decrease of 76.1% (R$1,366 million) in deductions related to tariff flag revenues recognized, which are required to be paid into the Tariff Flag Resources Centralizing Account administered by the CCEE; (ii) a decrease of 15.4% (R$609 million) in contributions made to the CDE Account due to new quotas defined by ANEEL in 2016 (see note 27.6 to our audited annual consolidated financial statements); and (iii) a decrease of 13.8% (R$367 million) in deductions related to PIS and COFINS taxes, mainly due to the decrease in our gross operating revenues (the calculation base for these taxes).  These decreases were partially offset by an increase of 5.4% (R$247 million) in ICMS tax, as a result of the increase in our billed supply. Generation (conventional sources) Net operating revenues from our Generation from Conventional Sources segment in the year ended December 31, 2016 amounted to R$1,003 million, an increase of 2.0% (or R$20 million) compared to R$984 million in the year ended December 31, 2015, due mainly to the price-driven increase of 9.9% (R$48 million) in revenue from sales from our facility Serra da Mesa to Furnas.  This increase was partially offset by:  (i) a decrease of 4.5% (R$26 million) in revenue from sales to our distribution subsidiaries, which represents the net effect of a decrease of 15.2% in the volume sold offset by increases in average selling prices; and (ii) an increase of 5.8% (R$5 million) in PIS and COFINS tax deductions from revenue due to the increase in gross operating revenues from the segment (the basis of calculation for these taxes).


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Table of Contents Generation (renewable sources) Net operating revenues from our Generation from Renewable Sources segment in the year ended December 31, 2016 amounted to R$1,673 million, an increase of 4.7% (or R$75 million) compared to R$1,598 million in the year ended December 31, 2015.  This increase was due mainly to:  (i) an increase of R$90 million in revenue from Free Consumers in the Commercial sector, to R$96 million compared with R$6 million in 2015, driven by new volumes, principally from Special Free Consumers migrating from the captive market, offset by a decrease in average selling prices; and (ii) an increase of 4.5% (R$70 million) in revenue from sales to other concessionaires and licensees, driven by increases in average selling prices. These increases were partially offset by:  (i) a decrease of 56.7% (R$56 million) in revenue from energy sold in the spot market, driven by a significant decrease in average selling prices despite an increase of 14.8% in our volume of energy sold; (ii) a decrease of 58.1% (R$20 million) in other operational revenues in 2016, due principally to the fact that 2015 included R$29 million in insurance claims paid out to CPFL Bio Pedra and CPFL Coopcana; and (iii) an increase of 6.6% (R$6 million) in PIS and COFINS tax deductions from revenue due to the increase in gross operating revenues from the segment (the basis of calculation for these taxes). The increase of volume of energy sold both for free consumers and in the spot market reflects the commencement of operations at the Campos do Ventos and São Benedito Wind Complexes in April and July 2016, respectively. Commercialization Net operating revenues from our Commercialization segment in the year ended December 31, 2016 amounted to R$2,087 million, an increase of 16% (or R$288 million) compared to R$1,799 million in the year ended December 31, 2015.  This increase was mainly due to:  (i) an increase of 23.9% (R$254 million) in revenue from Industrial Free Consumers, driven by an increase of 26.2% in volumes; (ii) an increase of 212.8% (or R$97 million) in revenue from Commercial Free Consumers, driven by an increase of 222.3% in volumes; and (iii) an increase of R$57 million in other operational revenue, which reflected an indemnification payment received from generation companies that did not deliver the amounts of energy contracted for 2016. These increases were partially offset by:  (i) a decrease of 63.6% (R$101 million) in revenue from sales in the spot market, driven by a 45.7% decrease in volume; and (ii) an increase of 16.4% (R$30 million) in PIS and COFINS tax deductions from operating revenues, mainly due to the increase in gross operating revenues for the segment (the basis of calculation for these taxes). Services Net operating revenues from our Services segment in the year ended December 31, 2016 amounted to R$400 million, an increase of 35.9% (or R$106 million) compared to R$295 million in the year ended December 31, 2015.  This increase was mainly due to:  (i) an increase of R$67 million in revenues from construction and maintenance services; (ii) an increase of R$35 million in revenues from administrative and IT outsourcing; and (iii) an increase of R$28 million in revenues from rental of generation assests and from consulting and management services related to energy efficiency improvements. These increases were partially offset by: (i) a decrease of R$19 million in revenues from collections and payment services of our subsidiary CPFL Total; and (ii) an increase of 53.8% (or R$9 million) in PIS and COFINS tax deductions from operating revenues, mainly due to the increase in our gross operating revenues (the basis of calculation for these taxes). Income from Electric Energy Service by Destination Cost of Electric Energy Electricity purchased for resale.  Our costs for the purchase of energy for resale decreased 16.9% (or R$1,998million) in the year ended December 31, 2016, to R$9,849million (59.4% of our total operating costs and operating expenses) compared with R$11,847 million for the year ended December 31, 2015 (representing 66.0% of our total operating costs and operating expenses), mainly due to a decrease of 23.8% in average prices, reflecting:


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Table of Contents (i) a decrease of R$844 million in purchases of energy from Itaipu, reflecting a decrease of 31.0% in the average price of energy purchased (inreais), itself caused by a 32.3% decrease in the tariff (which is established on an annual basis by ANEEL in US$/kW) and 4.3% depreciation in the average rate of therealagainst the U.S. dollar during 2016 compared with 2015, offset by a 2.3% increase in the volume of energy purchased; (ii) a decrease of 72.5% (or R$711 million) in cost of energy purchased in the spot market, driven by a decrease of 43.7% in volume purchased; and (iii) a decrease of 7.1% (or R$655 million) in the cost of energy purchased in the Regulated Market, reflecting an increase of 15.5% in the volume of energy purchased, which was more than offset by reductions in average purchase prices. These decreases were partially offset by a decrease of R$209 million (or 17.1%) in PIS and COFINS tax credits related to purchases of energy. Electricity network usage charges.  Our charges for the use of our transmission and distribution system decreased 7.8% (or R$114 million) to R$1,351 million in the year ended December 31, 2016, mainly as a result of:  (i) a decrease of R$193 million in System Service Charges; and (ii) a decrease of R$13 million in Basic Network Charges.  These decreases were partially offset by (i) an increase of R$52 million in Reserve Energy Charges; (ii) an increase of R$29 million in Connection Charges; and (iii) a decrease of R$11 million in tax credits related to network usage charges (which represents an increase in electricity network usage charges).  For further information about electricity network usage charges, see 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. Compared to the year ended December 31, 2015, our other costs and operating expenses increased 16.1% (or R$747 million) to R$5,389 million in the year ended December 31, 2016, mainly due to the following events:  (i) an increase of 29.4% (or R$307 million) in expenses related to the construction of concession infrastructure; (ii) an increase of 16.5% (or R$155 million) in our personnel expenses, reflecting increased costs under our collective bargaining agreements as well as a 33.6% increase in our number of employees at year-end, although this was mainly due to the acquisition of RGE Sul and only impacted expenses in November and December; (iii) an increase of 16.5% (or R$92 million) in expenses related to outsourced services; (iv) an increase of R$67 million in expenses related to disposal of assets; (v) an increase of 6% (or R$59 million) in depreciation and amortization expenses; (vi) an increase of 35.7% (or R$50 million) in inventory consumption; and (vii) an increase of 39% (or R$49 million) in allowance for doubtful accounts. Those increases were offset by:  (i) an decrease of 31% (or R$82 million) in legal, judicial and indemnity expenses; and (ii) a decrease of 15.7% (or R$48 million) in expenses from Intangible Assets of Concession amortization. Income from Electric Energy Service Compared to the year ended December 31, 2015, our income from electric energy service decreased 4.6% (or R$122 million) to R$2,523 million in the year ended December 31, 2016, since our net operating revenue decreased by more in absolute terms (R$1,491 million) than the decrease in our cost of generating and distributing electric energy and other operating costs and expenses (R$1,368 million). Income from Electric Energy Service by Segment Distribution


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Table of Contents Compared to the year ended December 31, 2015, income from electric energy service from our Distribution segment decreased 19.5% (or R$303 million) to R$1,254 million in the year ended December 31, 2016.  As discussed above, net operating revenues from the segment decreased by 11.4% (or R$1,928 million) while costs and operational expenses related to the segment decreased by 10.5% (or R$1,625 million).  The main contributing factors to the changes in costs and operational expenses were as follows: Electricity costs.Compared to the year ended December 31, 2015, electricity costs decreased 18.3% (or R$2,187 million), to R$9,760 million in the year ended December 31, 2016. The cost of energy purchased for resale decreased 19.6%, (or R$2,065 million), reflecting: (i) a decrease of 29.4% (or R$844 million) in purchases of energy from Itaipu, as described above; (ii) a decrease of 10.2% (or R$805 million) in the cost of energy purchased in the Regulated Market, reflecting an increase of 11.8% in the volume of energy purchased, which was more than offset by lower prices; and (iii) a decrease of 74.4% (or R$628 million) in the cost of energy purchased in the spot market and from PROINFA contracts driven by a decrease of 60.5% in the volume purchased.  These decreases were partially offset by a decrease of 19.6% (or R$211 million) in PIS and COFINS tax credits related to purchases of energy. In addition, charges for the use of the transmission and distribution system decreased 8.8% (or R$122 million) mainly due to:  (i) a decrease of 34.5% (or R$191 million) in System Service Charges costs; and (ii) a decrease of R$16 million in Basic Network Charges cost.  These decreases in charges for the use of the transmission and distribution system were partially offset by:  (i) an increase of 95.2% (or R$52 million) in Reserve Energy Charges costs; (ii) an increase of 32.6% (or R$19 million) in Connection Charges costs; and (iii) a decrease of 8.2% (or R$11 million) in tax credits related to network usage charges (which represents an increase in electricity network usage charges). Other costs and operating expenses.  Compared to the year ended December 31, 2015, our other costs and operating expenses for the Distribution segment increased16.2% (or R$562 million), to R$4,026 million in the year ended December 31, 2016, mainly due to (i) an increase of 29.3% (or R$295 million) in expenses related to the construction of concession infrastructure; (ii) an increase of 24.2% (or R$128 million) in expenses related to outsourced services; (iii) an increase of 11.3% (or R$74 million) in personnel expenses due to the impact of a collective bargaining as well as and a 52.2% increase in the number of employees in this segment at year-end, although this was mainly due to the acquisition of RGE Sul and only impacted expenses in November and December; (iv) an increase of 38.4% (or R$47 million) in expenses related to provision for doubtful receivables; (v) an increase of 7.8% (or R$36 million) in depreciation and amortization expenses; (vi) an increase of 30.3% (or R$29 million) in expenses from inventory and equipment consumption; (vii) an increase of 93.1% (or R$26 million) in expenses related to loss on disposal of noncurrent assets; and (vii) an increase of 46.2% (or R$15 million) in expenses related to regulatory fines.  These increases were partially offset by a decrease of 21.1% (or R$52 million) in legal, judicial and indemnity expenses.


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Table of Contents Generation (conventional sources) Compared to the year ended December 31, 2015, income from electric energy service from our Conventional Generation segment increased 23.7% (or R$129 million) to R$672 million in the year ended December 31, 2016.  This increase was mainly due to an increase of 2% in net operating revenue (or R$20 million, as discussed in the section “Sales by Segment” above), combined with the decrease of 24.9% (or R$110 million) in costs and operational expenses, reflecting mainly a decrease of R$127 million in electricity purchased for resale, driven by a 30.2% decrease in volumes combined with lower prices in comparison with the period ended December 31, 2015.  This decrease was partially offset by an increase of 7.2% (or R$16 million) in other costs and operating expenses, mainly due to:  (i) recognition of R$7 million expense related to amortization of GSF costs and (ii) an increase of 30% (or R$5 million) in expenses from asset leasing. Generation (renewable sources) Compared to the year ended December 31, 2015, income from electric energy service from our Renewable Generation segment decreased 4.5% (or R$21 million) to R$440 million for the year ended December 31, 2016.  This decrease was mainly due to the increase of 8.4% (or R$95 million) in costs and operational expenses, which exceeded in absolute terms the increase of 4.5% (or R$75 million) in net operating revenue (as discussed in the section “Sales by Segment” above). The increase in costs and operational expenses mainly reflects:  (i) an increase of R$75 million in expenses related to impairment charges (R$40 million) and other write-downs of noncurrent assets (R$35 million); (ii) an increase of 21.2% (or R$32 million) in expenses for outsourced services; (iii) an increase of 4.5% (or R$17 million) in depreciation and amortization expenses; (iv) an increase of 21.8% (or R$12 million) in personnel expenses due to the collective bargaining agreement negotiated; and (v) an increase of 14.4% (or R$11 million) in charges for use of the transmission and distribution system. These increases in costs were partially offset by a decrease of 62.2% (or R$89 million) in cost from energy purchased in the Free Market driven by decreases in average prices. Commercialization Compared to the year ended December 31, 2015, income from electric energy service from our Commercialization segment increased 27.1% (or R$34 million), to R$159 million in the year ended December 31, 2016.  This increase was due to the net effect of the increase of 16% (or R$288 million) in net operating revenues of the segment, as discussed in “Sales by Segment” section above, which exceeded the increase of 15.2% (or R$254 million) in costs and operational expenses.  The increase in costs and expenses was mainly due to an increase of 17.4% (or R$307 million) in the cost of energy purchased in the Regulated Market, driven by an increase of 26.2% in the volume of energy purchased partly offset by lower purchase prices.  This increase was partly offset by:  (i) a reduction of 98.2% (or R$32 million) in the cost of energy purchased in the free market, driven by lower average prices and a 22.8% reduction in the volume of energy purchased; and (ii) an increase of 15.3% (or R$25 million) in tax credits related to energy purchases (which represents an increase in electricity network usage charges). Services Compared to the year ended December 31, 2015, income from electric energy service from our Services segment increased 113.5% (or R$35 million), to R$65 million in the year ended December 31, 2016.  This increase was due to the net effect of the increase of 35.9% (or R$106 million) in net operating revenues, as discussed in “Sales by Segment” section above, which exceeded the increase of 26.9% (or R$71 million) in costs and operational expenses.  The increase in costs and expenses was mainly due to:  (i) the increase of R$41 million in personnel expenses due to an increase in the number of employees and due to collective bargaining agreements; and (ii) an increase of R$29 million in expenses from purchases of operating materials and equipment. Net Income Net Financial Expense


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Table of Contents Compared with the year ended December 31, 2015, our net financial expense increased 3.2% (or R$46 million), from R$1,408 million in 2015 to R$1,453in the year ended December 31, 2016, mainly due to an increase of R$103 million in our financial expenses, partly offset by an increase of R$57 million in our financial income. The reasons for the increase in financial expenses are:  (i) an increase of 5% (or R$86 million) in debt charges; (ii) an increase of R$24 million in financial expenses from monetary adjustments of Sector Financial Liabilities; and (iii) an increase of 2.4% (or R$17 million) in financial expenses from monetary and exchange adjustments.  These increases in financial expenses were partially offset by an increase of 49.4% (or R$23 million) in capitalized borrowing costs, which is accounted for as a decrease in financial expenses. The increase in financial income is mainly due to following reasons:  (i) an increase of 41.2% (or R$195 million) in income from financial investments; (ii) an increase of 14% (or R$30 million) in interest and fine payments; and (iii) an increase of 21.6% (or R$26 million) in income from monetary and exchange adjustments.  These increases were partially offset by (i) a reduction of 79.9% (or R$130 million) in income from adjustment of Sector Financial Assets and Liabilities (see note 8 to our consolidated audited financial statements); (ii) a decrease of 58.4% (or R$49 million) in income from adjustment of escrow deposits; and (iii) a decrease of R$25 million in adjustment of tax credits. At December 31, 2016, we had R$16,452million (compared with R$14,793 million at December 31, 2015) in debt denominated inreais, which accrued both interest and inflation adjustments based on a variety of Brazilian indices and money market rates.  The CDI interbank rate increased to 14% in 2016, compared to 13.2% in 2015; and the TJLP increased to 7.5% in 2016, compared to 7% in 2015.  We also had the equivalent of R$5,502 million (compared with R$6,940 million at December 31, 2015) of debt denominated in foreign currency, principally U.S. dollars.  In order to reduce the exchange rate risk with respect to this foreign currency‐denominated debt and variations in interest rates, we implement a policy of using exchange and interest rate derivatives. Income and Social Contribution Taxes Our net charge for income and social contribution taxes decreased to R$501 million in the year ended December 31, 2016 compared with R$579 million in the year ended December 31, 2015.  Our effective rate of 36.3% on pretax income in the year ended December 31, 2016 was higher than the official rate of 34%, principally due to our inability to use certain tax loss carryforwards.  This 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, 2015, and due to the factors discussed above, net income increased 0.4% (or R$4 million), to R$879 million in the year ended December 31, 2016. Net Income by Segment In the year ended December 31, 2016, 46.3% of our net income derived from our Distribution segment, 57.4% from our Generation from Conventional Sources segment, negative 16% from our Generation from Renewable Sources segment, 12.8% from our Commercialization segment, 6.1% from our Services segment and negative 6.6% from Other.  For the equivalent contributions from our segments in 2015 and 2014, see the table under “Background – Operating Segments” earlier in this Item 5.


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Table of Contents Distribution Compared to the year ended December 31, 2015, net income from our Distribution segment decreased 34.9%, (or R$219 million), to R$407 million in the year ended December 31, 2016, as a result of a decrease of 19.5% (or R$303 million) in income from electric energy service and an increase of 6.7% (or R$35 million) in net financial expenses, partly offset by a decrease of 28.7% (or R$119 million) in Income and Social Contribution Taxes expenses. The increase in the segment’s net financial expenses was mainly due to: an increase of R$75 million in financial expenses, mainly due to an increase of R$108 million in financial expenses from debt charges and monetary and exchange rate variations as a result of higher indebtedness, partially offset by an decrease of R$31 million in other financial expenses, mainly interest on intercompany loans and Tax on Financial Transactions (Impostos sobre Operações Financeirasor IOF); partly offset by

an increase of R$41 million in financial income, mainly due to:  (i) an increase of 126.5% (or R$207 million) in income from financial investments; and (ii) an increase of 13.6% (or R$29 million) in arrears of interest and fines.  These increases were partly offset by:  (i) a decrease of 79.6% (or R$130 million) in income from the adjustment of Sector Financial Assets and Liabilities (see note 8 to our consolidated audited financial statements); and (ii) a reduction of 56.6% (or R$48 million) in income from adjustment of escrow deposits.
 Generation (conventional sources) Net income from our Generation from Conventional Sources segment increased by 78.5% (or R$222 million) to R$505 million during the year ended December 31, 2016 from R$283 million for the year ended December 31, 2015.  This increase is mainly due to:  (i) the increase of 23.7% (or R$129 million) in income from electric energy service; (ii) the increase of 43.6% (or R$95 million) in equity interests in joint ventures (see note 13 to our audited annual consolidated financial statements); and (iii) a decrease of 13.6% (or R$60 million) in net financial expenses.  These increases were partially offset by an increase of 162.3% (or R$61 million) in Income and Social Contribution Taxes expenses. The decrease in net financial expenses was due mainly to:  (i) an increase of 102.9% (or R$52 million) in income from financial investments; and (ii) an increase of 106.1% (or R$35 million) in positive monetary and exchange variations.  These increases were partially offset by an increase of R$13 million in debt charges and negative monetary and exchange variations, due mainly to the increase in our indebtedness level. Generation (renewable sources) The net loss from our Generation from Renewable Sources segment increased by 150.1% (or R$85 million) to R$141 million in the year ended December 31, 2016 compared to net loss of R$56 million in 2015, mainly due to the combined effect of the decrease of 4.5% (or R$21 million) in income from electric energy service and an increase of 14.3% (or R$67 million) in net financial expenses and, slightly offset by a decrease of R$3 million in Income and Social Contribution Taxes expenses. The increase in net financial expenses was driven by an increase of R$92 million in debt expenses and monetary and exchange rate variations, offset by an increase of R$22 million in capitalized borrowing costs, which is accounted for as a decrease in financial expenses. Commercialization Compared to the year ended December 31, 2015, net income from our Commercialization segment increased 27.5% (or R$24 million), to R$112 million in the year ended December 31, 2016, reflecting the combined effect of an increase of 27.1% (or R$34 million) in the income from electric energy service and a slight decrease of R$2 million of net financial income, partly offset by an increase of R$12 million in Income and Social Contribution Taxes expenses.


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Table of Contents Services Compared to the year ended December 31, 2015, net income from our Services segment increased 4.2% (or R$2 million), to R$54 million in the year ended December 31, 2016.  This relatively stable number reflects an increase of 113.5% (or R$35 million) in the segment’s income from electric energy service, partially offset by a decrease of 86.1% (or R$34 million) in net financial income (driven mainly by a decrease of R$37 million in income from financial investments due to the reduction in average bank account balances).  Income and social contribution taxes expenses for the segment decreased by R$1 million. Results of Operations—2015 compared to 2014 Net Operating Revenues Compared to the year ended December 31, 2014, our net operating revenues increased 18.4% (or R$3,200 million) in the year ended December 31, 2015, amounting to R$20,599 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. 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 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:


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Table of Contents Residential and commercial consumers.  With respect to Captive Consumers (which represent 99.7% of the total amount sold to this category in our consolidated financial 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 (10.3% 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”. Other operating revenues Compared to the year ended December 31, 2014, our other gross operating revenues (other than TUSD revenue from captive consumers) increased 75.8% (or R$3,057 million) in the year ended December 31, 2015 to R$7,091 million (20.7% 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 R$300 million in income from adjustment of estimated cash flow of the Concession Financial Asset in 2015 (see note 27 to our consolidated audited financial statements); (iv) 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 (v) 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).


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Table of Contents Sales by segment Distribution Compared to the year ended December 31, 2014, net operating revenues from our Distribution segment increased 23.2% (or R$3,196 million) to R$16,968 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$300 million in income from adjustment of estimated cash flow of the Concession Financial Asset in 2015 (see note 27 to our consolidated audited financial statements) (vi) an increase of R$132 million in revenue from construction of concession infrastructure and; (vii) 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). 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.


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Table of Contents 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$29 million in other operational revenues  derived from compensation for loss of profit under an insurance claim paid out to CPFL Bio Pedra and CPFL Coopcana; (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. 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”.


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Table of Contents 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 19.1% (R$191 million) 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. 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 increased 0.5% (or R$12 million) to R$2,645 million in the year ended December 31, 2015, due to the net effect of an increase in our net operating revenue (R$3,200 million) in a higher amount than the increase in our cost of generating and distributing electric energy and other operating costs and expenses (R$3,188 million).


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Table of Contents 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 8.2% (or R$139 million) to R$1,557 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 23.2% (or R$3,196 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 229.2% (or R$956 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$97 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. 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.


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Table of Contents 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 increased 19.0% (or R$225 million), from R$1,183 million in 2014 to R$1,408 in the year ended December 31, 2015, mainly due to an increase of R$583 million in our financial expense, offset by an increase of R$357 million in our 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. The increase in financial income is mainly due to following reasons: (i) 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); (ii) an increase of R$72 million in income from monetary and exchange adjustments; (iii) an increase of R$69 million in interest and fine payments; (iv) an increase of R$42 million in income from financial investments; and (v) an increase of R$32 million in adjustment for inflation of tax credits.  Those increases were offset by an increase of R$57 million related to tax expenses on financial income (PIS and COFINS taxes), which is accounted for as a reduction of financial income. 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).


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Table of Contents 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 8.2% (or R$139 million) in income from electric energy service, a decrease of 10.1% (or R$47 million) in expenses from Income and Social Contribution Taxes and an increase of 32.3% (or R$126 million) in net financial expenses. The increase in net financial expenses was mainly due to: an increase of R$418 million in financial expenses.  This increase was substantially 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.an increase of R$292 million in financial income, mainly due to:  (i) 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); (ii) an increase of R$66 million in arrears of interest and fines; (iii) an increase of R$37 million in income from monetary and exchange adjustments; (iv) an increase of R$32 million in income from financial investments; and (v) 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. 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.  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.


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Table of Contents 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. 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 Brazil’s downgrade from investment grade, due to changes in the country’s economic and political scenario, as discussed earlier in this Item 5.  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, 2016, our working capital reflected an excess of current assets over current liabilities of R$2,361 million, a decrease of R$623 million compared to R$2,984 million at December 31, 2015.  The main causes of this decrease were: (i) a decrease of R$2,060 million in net Sectorial Financial Assets and Liabilities balances, from an asset position of R$1,464 million in 2015 to a liability position of R$598 million in 2016; and (ii) a decrease of R$469 million in derivative financial instruments; Those decreases were partially offset by: (i) an increase of R$591 million in our Consumers Receivables balance; (ii) a decrease of R$486 million in our Regulatory Charges balance; (iii) an increase of R$482 million in our cash and cash and equivalents, due to net cash generation of R$4,684 million from operating activities, partly offset by net cash usage of R$3,865 million in investing activities and R$337 million in financing activities; (iv) a decrease of R$433 million in our Trade Payables balance; (v) a decrease of R$294 million in our short‐term debt balance, which includes loans and financing, debentures and related accrued interest; and (vi) a decrease of R$302 million in our Other Current Assets and Liabilities balances. 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 order in which such line items appear in our financial statements.


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Table of Contents Our net cash provided by operating activities was R$4,634 million in the year ended December 31, 2016, compared to R$2,558 million in the year ended December 31, 2015 (an increase of R$2,076 million or 81.2%).  The increase primarily reflects: (i)

   an increase of R$465 million in net income, adjusted for the reconciliation of net cash;(ii)

   net decrease of R$5,527 million in operating assets (which represents an increase in the cash provided by operating activities), primarily driven by sectorial financial assets (R$3,353 million) and accounts receivable from consumers (R$849 million);(iii)

   a decrease of R$3,341 million in cash generation arising from increases in operating liabilities, primarily due to accounts payables (R$1,570 million) and regulatory charges (R$1,323 million); and(iv)

   an increase of R$575 million in cash consumption in income tax and social contributions (R$600 million), offset by payments of interest (R$25 million). 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 (an increase of R$965 million or 60.6%).  The increase 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 from financing activities recorded a consumption of cash of R$337 million in the year ended December 31, 2016 compared to generation of cash of R$292 million in the year ended December 31, 2015.  This decrease of R$629 million was due to: (i)

   a decrease of R$758 million in fund-raising from borrowings and debentures;(ii)

   an increase of R$227 million related to payment of dividends; and(iii)

   a reduction of R$315 million related to payments of loans, financing, debentures and derivatives. 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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Table of Contents Indebtedness The following table sets forth our current and noncurrent indebtedness (in millions) for the year ended December 31, 2016: 2016Current

   NoncurrentSecured debt

   875

   13,038Unsecured debt

   2,548

   5,583Total

   3,423

   18,621
  Our total indebtedness increased R$311 million, or 1.4%, from December 31, 2015 to December 31, 2016, as result of new debentures issued and other debt incurred, mainly: Issuances of debentures in the amount of R$620 million by CPFL Energia; R$400 million by CPFL Brasil; R$350 million by CPFL Renováveis; and R$50 million by CPFL Geração.  Additionally, the acquisition of RGE Sul in 2016 increased our debentures balance at year-end by R$1,100 million.

Incurrence of new debt denominated in U.S. dollars, principally in the amount of R$826 million by CPFL Geração; R$236 million by CPFL Paulista; R$236 million by CPFL Piratininga; R$236 million by RGE; and R$64 million by other distribution subsidiaries.  This debt was incurred in order to improve working capital, finance debt payments, refinance maturing debt and fulfill required investments for our renewable generation subsidiaries.
 The increases listed above were partially offset by repayments of debt during the year in the aggregate amount of R$4,017 million. In 2017 and 2018, 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 Brazilian electric energy sector. Moreover, through fundraising we seek to maintain the liquidity of our group and a favorable debt profile through extending the average maturity of our debt and reducing its cost. Terms of Outstanding Debt Our total debt outstanding at December 31, 2016 (including accrued interest) was R$22,044 million.  Approximately R$5,502 million of our total outstanding debt, or 25%, was denominated in foreign currency, principally U.S. dollars.  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations.  Of our total outstanding debt, R$3,423 million is due in 12 months. Our major categories of indebtedness are as follows: BNDES.  At December 31, 2016, we had R$5,471 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$3,987 million); (ii) financing of investment programs for our distribution subsidiaries, primarily CPFL Paulista, CPFL Piratininga and RGE (R$1,387 million); and (iii) loans to our subsidiaries CPFL Serviços, CPFL Brasil, CPFL Esco, CPFL Telecom and CPFL Transmissão Piracicaba (R$97 million).

Debentures.  At December 31, 2016, we had indebtedness of R$9,000 million outstanding under several series of debentures issued by CPFL Energia, CPFL Paulista, CPFL Piratininga, RGE, RGE Sul, 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.


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Table of Contents Working capital.  At December 31, 2016, we had R$1,354million 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, 2016, we had R$755 million outstanding under a number of otherreal‐denominated facilities.  Thesereal-denominated facilities relate to our renewable energy subsidiaries (R$653 million) and our distribution subsidiaries (R$102 million).  They are indexed based on the CDI or TJLP and bear interest at different rates.

Other foreign currency‐denominateddebt.  At December 31, 2016, we had the equivalent of R$5,502 million outstanding under other loans denominated in foreign currency, principally U.S. dollars (US$1,688 million).  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations.
 For more details on our borrowings, debentures and derivatives please see notes 17, 18 and 35 to our audited annual consolidated financial statements. Financial and Operating Covenants We are subject to financial and operating covenants under our financial instruments and those of our subsidiaries.  The main parameters established by financial institutions under these instruments are:  (i) net indebtedness divided by EBITDA; (ii) EBITDA divided by Finance Income (Costs); (iii) net indebtedness divided by the sum of net indebtedness and net equity; (iv) maintaining the debt coverage ratio and own capitalization ratio and (v) other restrictions such as restrictions on the payment of dividends to our subsidiaries.  Certain of these covenants require us to calculate the metrics used for covenant compliance on an as adjusted basis, to reflect proportional consolidation of the financial position and results of operations of all companies in which we hold 10% or more of the voting stock, and to reflect our equivalent stake in each company that we control with less than 100% (such as CPFL Energias Renováveis S.A.  and Ceran – Companhia Energética Rio das Antas). Our Management and that of our subsidiaries monitor these ratios systematically and constantly to ensure that we and our subsidiaries remain in compliance with these contractual conditions.  In the opinion of our Management, we were in compliance with these covenants as at December 31, 2016, with the exception of three subsidiaries of CPFL Renováveis (SPE Ninho da Águia Energia S.A., SPE Paiol Energia S.A. and SPE Várzea Alegre Energia S.A), which as of December 31, 2016 were not in compliance with their debt coverage ratios requiring cash generation of 1.2 times the debt service amount for the period.  The affected indebtedness, which totaled R$ 87 million at December 31, 2016, was accounted for in current liabilities.  Early maturity of the debt due to non-compliance with the debt coverage ratio agreed was not declared at December 31, 2016 and on March 7, 2017, the subsidiaries obtained a waiver from BNDES to determine the debt coverage ratio for the second semester of  2016. Failure to comply with the covenant also did not result in early maturity of other debts with specific cross-default conditions. For more information on our financial covenants, see explanatory notes 17 and 18 to our audited annual consolidated financial statements. Uses of funds Our cash flow used for investing activities was R$3,815million in the year ended December 31, 2016 compared with R$1,525 million in the year ended December 31, 2015.  This increase of R$2,290 million (150.2%) primarily reflects: (i)

   net cash outflow (R$1,497 million) related to the acquisition of RGE Sul, after accounting for acquired cash (see note 13.4 of our audited annual consolidated financial statements);(ii)

   an increase of R$477 million in property, plant and equipment mainly due to investments in our renewable energy subsidiaries; and


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Table of Contents (iii)

   an increase of R$333 million in intangible assets primarily due to investments in our distribution activities. 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. 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 of maturing debt.  At December 31, 2016 we had outstanding debt maturing during the following 12 months in the total amount of R$3,423 million; andDividends on a semiannual basis.  We paid R$205 millionin dividendsin 2016 (we paid no dividends in 2015).  See “Item 10.  Additional Information—Interest Attributable to Shareholders’ Equity” and the Unconsolidated Statement of Cash 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.  We may either retire the debt due in advance or carry cash to improve our liquidity.  We continued to employ this strategy during 2016 in relation to debt due in 2017 and expect to continue to apply it in 2017 in relation to debt due in 2018.  By applying this strategy, we aim to reduce CPFL Energia’s future cash flow exposure and our exposure to interest rate risk, as well as to maintain our liquidity level and 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 Renewable Generation projects.  The following table sets forth our capital expenditures for years ended December 31, 2016, 2015 and 2014: Year ended December 31,2016

   2015

   2014(in millions ofreais)Distribution

   1,201

   868

   702Conventional Generation

   8

   7

   14Renewable Generation

   979

   494

   251Commercialization and other investments

   51

   59

   94Total

   2,239

   1,428

   1,062
 In addition to the capital expenditures shown above, we invested R$51 million for the year ended December 31, 2016 (R$37 million for the year ended December 31, 2015), related to the construction of our transmission lines (under our Transmission activities), which according to the requirements of IFRIC 12, it was recorded as “Financial Asset of Concession” in noncurrent assets.


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Table of Contents We plan to make capital expenditures aggregating approximately R$2,722million in 2017 and approximately R$2,061 million in 2018. At the date of this Annual Report, however, these planned capital expenditures have not yet been approved by our Board of Directors, and they therefore remain subject to change. Of total planned capital expenditures over this period, R$3,772million are expected to be invested in our Distribution segment, R$846 million in our Renewable Generation segment and R$28 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$137 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”. In addition, 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 – has increased our operational efficiency.  We have already deployed 26,783 smart meters in the field, reaching the conclusion of the project implementation.  Currently, our nine distribution companies are already operating under the new data dispatch system for emergency commercial services.  In 2017, we expect to begin the implementation of the Distribution Automation project at our seven distribution companies located in São Paulo state.  The goal is to reach 100% of reclosers in the distribution grid with RF Mesh (Radio Frequency Mesh) network and improve the availability and reliability of communications in order to reduce the SAIDI (System Average Interruption Duration Index). 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 distributions of R$205 million, equivalent to R$0.206868475 per share.  On April 29, 2016, at our Annual Shareholders’ Meeting, shareholders representing 74.12% of our share capital followed our Board of Directors’ recommendation and approved the allocation of net profits and distribution of dividends as follows: December 31, 2015Profit for the year

   864,940Realization of other comprehensive income

   26,119Prescribed dividends

   5,597Profit basis 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
  See note 25.6 to our audited annual consolidated financial statements for additional information. For the year ended December 31, 2016, our Board of Directors approved dividend distribution of R$213,960, equivalent to R$0.210194546per share, subject to the approval by shareholders in our Annual Shareholders’ Meeting, which is scheduled to take place on April 28, 2017.  See note 25.7 to our audited annual consolidated financial statements for additional information.


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Table of Contents Contractual Obligations The following table summarizes our contractual obligations and commitments as of December 31, 2016 (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, 2016:Suppliers

   3,131

   

   3,002

   

   130

   

   -

   

   -Debt obligations(1)

   28,938

   

   5,320

   

   15,481

   

   4,806

   

   3,331Public utilities (1)

   367

   

   26

   

   44

   

   62

   

   235Post-employment benefit  (2)

   2,456

   

   99

   

   445

   

   460

   

   1,451Regulatory charges

   375

   

   375

   

   -

   

   -

   

   -Other

   260

   

   194

   

   45

   

   -

   

   22Total of Balance Sheet items (1)

   35,527

   

   9,016

   

   16,145

   

   5,328

   

   5,038Electricity purchase agreements (3)

   141,552

   

   12,022

   

   23,388

   

   22,479

   

   83,662Distribution and transmission systems service charges(4)

   46,960

   

   2,032

   

   6,916

   

   8,573

   

   29,439Premium of Hydrological Risk renegotiation (GSF)(5)

   320

   

   18

   

   -

   

   36

   

   266Generation projects (6)

   1,569

   

   1,560

   

   9

   

   -

   

   -Supplies

   3,885

   

   1,820

   

   1,254

   

   315

   

   497Total of other commitments

   194,286

   

   17,452

   

   31,556

   

   31,404

   

   113,865Total of contractual obligations

   229,813

   

   26,468

   

   47,711

   

   36,732

   

   118,902
 
 (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 2016 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. (5)   Estimated expenses for the payment of risk premium in connection with renegotiation of hydrological risk. (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. 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, 2016, 2015 and 2014 totaled R$147million, R$125 million and R$120 million, respectively.


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Table of Contents Off‐Balance Sheet Arrangements As of December 31, 2016, 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 2016 (in thousands ofreais)Modality

   Approval

   Company

   Debt

   Released

   BalanceBNDES / Investment - FINEM XIX

   In 2012

   CPFL Renováveis

   34,543

   33,543

   1,000BNDES / Investment - FINEM XXI

   In 2012

   CPFL Renováveis

   47,000

   43,000

   4,000BNDES / Investment - FINAME I

   In 2012

   CPFL Renováveis

   4,691

   3,753

   938BNDES / Investment - CCB Santander

   In 2013

   CPFL Mococa

   6,119

   5,916

   203(1)BNDES / Investment - FINEM XIII

   In 2013

   CPFL Renováveis

   391,245

   356,181

   35,064BNDES / Investment - FINEP III

   In 2013

   CPFL Renováveis

   23,031

   6,921

   16,109BNDES / Investment - FINEM XIII

   In 2013

   CPFL Renováveis

   383,748

   379,948

   3,800BNDES / Investment - FINEM

   In 2014

   CPFL Santa Cruz

   25,360

   23,155

   2,205(1)BNDES / Investment - FINEM I

   In 2014

   CPFL Leste Paulista

   13,045

   8,570

   4,475(1)BNDES / Investment - FINEM

   In 2014

   CPFL Sul Paulista

   12,280

   9,132

   3,148(1)BNDES / Investment - FINEM V

   In 2014

   CPFL Jaguari

   10,398

   7,562

   2,836(1)BNDES / Investment - FINEP II

   In 2014

   CPFL Renováveis

   88,095

   10,348

   77,747BNDES / Investment - FINEM

   In 2014

   CPFL Telecom

   95,333

   34,918

   60,415BNDES / Investment - FINEM VII

   In 2014

   CPFL Paulista

   427,716

   281,194

   146,522(1)BNDES / Investment - FINEM VI

   In 2014

   CPFL Piratininga

   194,862

   143,125

   51,737(1)BNDES / Investment - FINEM VII

   In 2014

   RGE

   266,790

   195,643

   71,147(1)BNDES / FINAME

   In 2015

   CPFL Serviços

   6,011

   5,144

   867BNDES / Investment - FINEM XXV

   In 2015

   CPFL Renováveis

   84,338

   82,409

   1,929BNDES / Investment - FINEM XXVI

   In 2015

   CPFL Renováveis

   764,109

   489,670

   274,439BNDES / Investment - FINEM XXVII

   In 2015

   CPFL Renováveis

   69,103

   67,628

   1,475BNDES / FINAME

   In 2016

   CPFL Serviços

   12,277

   11,886

   391BNDES / FINAME

   In 2016

   CPFL Esco

   1,543

   1,525

   18
  (1)Outstanding balance was canceled.  Trend Information 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). Growth in our market is heavily influenced by economic growth, in particular, rates of employment, household 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. Since the global economic crisis of 2009, the Brazilian economy has been negatively affected by lower demand in foreign trade and deficient local infrastructure.  This led to GDP growth averaging 2.1% per year between 2009 and 2014, following a prior period of higher growth.  The years 2015 and 2016, however, were marked by severe economic contraction, ongoing political crisis and poor economic indicators.  These factors, combined with adjustments to government spending budgets, resulted in negative GDP growth of 3.6% in 2016 and 3.8% in 2015, according to the Brazilian Central Bank.  In March 2017 the government announced that the last three months of 2016 marked the eighth consecutive quarter of negative GDP growth, the longest period of recession on record.  According to the Brazilian Central Bank’s Focus Report, Brazilian industrial production decreased by 6.7% in 2016 and 8.3% in 2015. As a result, employment levels, household income and debt service costs – all of which are key drivers for energy consumption – continued to worsen during 2016.  For example, the number of formal job vacancies fell by 7% from 2015 to 2016 according to a report by CAGED –Cadastro Geral de Empregados e Desempregados.


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Table of Contents 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 2,054 MW (of which our share is 1,060 MW) and 75 MW under construction (of which our share is 39 MW), as well as seeking out new projects. As of December 31, 2016, we had an Installed Capacity of 3,259 MW.  In 2020, we expect to reach an Installed Capacity of 3,297 MW, when the Boa Vista II SHPPs and Pedra Cheirosa I and II Wind Farm Complexes will have begun operations.  We also have a 2,987 MW (of which our share is 1,542 MW) portfolio to be developed over the coming years through CPFL Renováveis.  In addition, we will continue to seek out new projects in the conventional energy sector. In the Commercialization and Services segment, our main objective is to maintain our leading position, in terms of market share, in order to guarantee our above‐average profitability.  In addition, we expect to expand our portfolio of services, retain the loyalty of our customers and expand our services to new markets. Since our founding, we have employed a growth strategy based on operational excellence through innovation and technology, synergy, financial discipline and the accumulation of value.  We plan to continue this in the future in order to consolidate our strong position in the energy industry. 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 evaluation in 2014 did not result in any significant impairment of our property, plant and equipment or intangible assets and investments.  In 2016 and 2015, we recorded an impairment loss of R$48 million and R$39 million, respectively, related to noncurrent assets (see notes 14.1 and 15.2 of our consolidated financial statements.


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Table of Contents Impairment of Financial Assets A financial asset not measured at fair value through profit or loss is reassessed at each reporting date to determine whether there is objective evidence that it is impaired.  Impairment can occur after the initial recognition of the asset and have a negative effect on the estimated future cash flows. The Company and its subsidiaries consider evidence of impairment of receivables and held‐to‐maturity investment securities for both specific asset and at a collective level for all significant securities.  Receivables and held‐to‐maturity investment securities that are not individually significant are collectively assessed for impairment by grouping together the securities with similar risk characteristics. In assessing collective impairment the Company uses historical trends of the probability of default, timing of recoveries and the amount of loss incurred, adjusted for Management’s judgment as to whether the assumptions and current economic and credit conditions are such that the actual losses are likely to be higher or lower than suggested by historic trends. An impairment loss of a financial asset is recognized as follows: Amortized cost:  as the difference between the carrying amount and the present value of the estimated future cash flows discounted at the asset’s original effective interest rate.  Losses are recognized in profit or loss and shown in an allowance account against receivables.  Interest on the impaired asset continues to be recognized through the unwinding of the discount.  When a subsequent event indicates that the amount of impairment loss has decreased, this reduction is reversed to credit through profit or loss.

Available‐for‐sale:  as the difference between the acquisition cost, net of any principal repayment and amortization of the principal, and the current fair value, less any impairment loss previously recognized in profit or loss.  Losses are recognized in profit or loss.
 In the case of financial assets registered at amortized cost and/or debt instruments classified as available‐for‐sale, if an increase (gain) is identified in periods subsequent to recognition of the loss, the impairment loss is reversed through profit or loss.  However, any subsequent recovery in the fair value of an impaired available‐for‐sale security is recognized in other comprehensive income. Pension Liabilities We sponsor pension plans and disability and death benefit plans covering substantially all of our employees.  The determination of the amount of our obligations for pension benefits depends on certain actuarial assumptions, including discount rate, inflation, etc. Deferred Tax Assets and Liabilities We account for income taxes in accordance with IFRS, which requires an asset and liability approach to recording current and deferred taxes.  Accordingly, the effects of differences between the tax basis of assets and liabilities and the amounts recognized in our financial statements have been treated as temporary differences for the purpose of recording deferred income tax. We regularly review our deferred tax assets for recoverability.  If evidences are not enough to prove that it is more likely than not that we will 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.


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Table of Contents Provision for Tax, Civil and Labor Risks We and our subsidiaries are party to certain legal proceedings in Brazil arising in the normal course of business regarding tax, labor, civil and other matters. Accruals for provision for tax, civil and labor risks are estimated based on historical experience, the nature of the claims, and the current status of the claims.  The evaluation of these risks is performed by various specialists, inside and outside of the company.  Accounting for provision for tax, civil and labor risks requires significant judgment by Management concerning the estimated probabilities and ranges of exposure to potential liability.  Management’s assessment of our exposure to provision for tax, civil and labor risks could change as new developments occur or more information becomes available.  The outcome of the risks could vary significantly and could materially impact our consolidated results of operations, cash flows and financial position. Financial instruments Financial instruments can be measured at fair values or at recognized costs, depending on certain factors.  Those measured at fair value were recognized based on quoted prices in an active market, or assessed using pricing models, applied individually for each transaction, taking into consideration the future payment flows, based on the conditions contracted, discounted to present value at market interest rate curves, based on information obtained from the BM&FBOVESPA and the National Association of Financial and Capital Market Institutions (Associação Brasileira das Entidades dos Mercados Financeiros e de Capitais) websites, when available.  Accordingly, the market value of a security corresponds to its maturity value (redemption value) marked to present value by the discount factor (relating to the maturity date of the security) obtained from the market interest graph in Brazilianreais. Financial assets classified as available‐for‐sale refer to the right to compensation to be paid by the Brazilian government on reversion of the assets of the distribution concessionaires (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.Investments in infrastructure (application of IFRIC 12 – Service Concession Arrangements).  Since the concession term is contractually defined, intangible assets acquired as investment in infrastructure have a pre‐determined useful life.  We account for the amortization of these assets using a curve that reflects the consumption standard as compared to the expected profits.Public utilities.  We account for the amortization of intangible assets relating to our use of a public asset using the straight‐line method for the remaining term of the concession.


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Table of Contents Revenue recognition – unbilled revenue Revenue from electric energy distribution is recognized when the energy is supplied. Our distribution subsidiaries perform the reading of energy consumed by our customers based on different reading routines (schedule and routes) for different classes of customers. The invoice is issued in a monthly basis, and comprises the actual volumes consumed (in MWh) for each customer until the date of such reading, which may comprise only part of the month. As a result of different reading schedules as mentioned above, part of the energy distributed during the month is not billed to the customers at the end of the month and, consequently, an estimate is developed by Management in order to recognize the total amount of energy distributed. Such revenue is recorded as “unbilled revenue”, and is calculated based on the total volume of energy distributed by our distribution subsidiaries during the month, adjusted by technical and commercial losses annualized rates.  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 and our bylaws. 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. 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, or, in his/her absence, the vice-chairman will have the deciding vote. 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.


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Table of Contents Currently, our Board of Directors consists of seven members, of which two are independents (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 were elected at our extraordinary general meeting of shareholders held on February 16, 2017.  Their terms are expected to expire at our next annual general meetings of shareholders, scheduled to take place on April 28, 2017. 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

   PositionHu Yuhai

   53

   ChairmanChen Daobiao

   48

   Vice-chairmanQu Yang

   51

   MemberZhao Yumeng

   43

   MemberAndre Dorf

   44

   MemberAntonio Kandir

   63

   Independent MemberAna Maria Elorrieta

   61

   Independent Member
   Hu Yuhai- Mr.  Hu graduated in Electrical Power Engineering from the Beijing Institute of Agricultural Machinery, and later earned a master’s degree in Industrial Engineering from the University of Tianjin.  He began his career at State Grid Tianjin Electric Power Company, where he held positions as Chief Engineer of subsidiary City Distribution Company, Vice President, President of Transmission Company, and Deputy Chief Engineer, Director of Marketing of Electric Energy, and Vice President in charge of capital construction.  He then held the position of Deputy Director General of the Construction Department of State Grid Corporation of China (or SGCC, our indirect controlling shareholder), and also served as Senior Vice President in the State Grid Henan Electric Power Company and State Grid Jiangsu Electric Power Company.  Currently, he is the President & CEO of State Grid International Development Co., Ltd (or SGID, a wholly-owned subsidiary of SGCC and an indirect controlling shareholder of our company). Chen Daobiao– Mr.  Chen graduated in Electrical Power Systems and Automation from Huazhong University of Science and Technology in 1990, and earned a masters degree in Business Administration from the Royal Melbourne Institute of Technology.  He began his career in 1990 in the electric power sector of State Grid Group in Nanjing Electric Power Company, where he served as Deputy Chief Engineer and Director of Operations Department from 2004 to 2005 and Vice President from 2005 to 2007.  He was also Vice President at the Lianyungang Electric Power Company from 2008 to 2009, President of the Huaian Electric Power Company from 2008 to 2009 and the Nantong Electric Power Company from 2009 to 2011, Senior Vice President of the State Grid Shanghai Electric Power Company from 2011 to 2015, and Deputy Director General of the Construction Department of State Grid Corporation of China from 2015 to 2016.  In 2016, he was the Vice Officer of the Economic Information Sector for Organization of Development and Global Cooperation of Energy Interconnection, then Senior Vice President of State Grid International Development Co., Ltd. Qu Yang– Mr.  Qu graduated in Electrical Power Systems and Automation from Chengdu University of Science and Technology in 1986.  He has worked in the State Grid group since 1986.  He began his career in Henan Transmission and Transformation Engineering Company, where he worked from 1986 to 2003.  Between 2003 and 2006, he served as Deputy Chief Engineer and Director at the Henan Transmission and Transformation Engineering Company for State Grid Henan Electric Power Company’s Vietnam office.  He held the position of Deputy Director of State Grid Henan Electric Power Company in Vietnam from 2006 to 2008, Deputy Director at the General Office of the International Cooperation Department of the State Grid Corporation of China from 2008 to 2009, Deputy Director of the International Business Department of State Grid International Development Co., Ltd from 2009 to 2010, and Director from 2011 to 2014 of the Business Development Department of State Grid Brazil Holding SA.  Since 2014, he has been Vice President at State Grid Brazil Holding SA. Zhao Yumeng– Mr.  Zhao graduated in Eletromagnetic Instruments and Measuring from Huazhong University of Science and Technology in 1994 and later earned a Master’s degree in Business Administration from the Royal Melbourne Institute of Technology and a Master’s degree in Electrical Power Systems and Automation from Hefei University of Technology.  He began his career in 1994 in the electric power sector of State Grid Group.  He held the position of Head of the Marketing Department at Hefei Electric Power Company from 2004 to 2006.  He was also the manager of the Marketing Department of State Grid Anhui Electric Power Company in 2006, Vice-President of Xuancheng Electric Power Company from 2006 to 2009, President of Chuzhou Electric Power Company from 2009 to 2013 and has been President of Anqing Electric Power Company since 2013.  He is currently the President Assistant of State Grid International Development Co., Ltd.


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Table of Contents Antonio Kandir– Mr.  Kandir graduated in Mechanic Engineering at Escola Politécnica of the Universidade de São Paulo (USP), earned a masters degree in economics from the Universidade Estadual de Campinas - UNICAMP and a Ph.D.  in Economics from the Universidade Estadual de Campinas – UNICAMP.  Mr.  Kandir was Minister of Planning and Budget of the State, a Congressman, President of theConselho Nacional de Desestatização, Governor of the Inter-American Development Bank, Special Secretary of Economic Policy, President of theInstituto de Pesquisa Econômica Aplicada(IPEA), Presiding Officer of Kandir e Associados S/C Ltda from 1992 to 1994 and coordinator of studies of Itaú Planejamento e Engenharia from 1981 to 1982, with responsibility for private equity and hedge funds.  Partner at Governança & Gestão Investimentos Ltda.  (since 2004) and GG Capital  Investimentos Ltda from 2012 to 2016.  He also worked as a professor at the Universidade Estadual de Campinas - UNICAMP, the Pontifícia Universidade Católica de São Paulo from 1984 to 1985 and was an Assistant Faculty Fellow at the University of Notre Dame in 1987.  He currently sits on the boards of directors of the following companies:  (i) CSU Cadsystem, a technology services provider; (ii) Amil Saúde, a healthcare insurance company; (iii) Companhia Providência Indústria e Comércio, a nonwoven fabrics company; (iv) GOL Linhas Aéreas Inteligentes, an aviation company; and (v) Banco Ribeirão Preto, a financial institution.  None of these companies is part of the CPFL Energia group, or controlled by a shareholder holding more than 5% of the common shares of CPFL Energia. 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 participated in the National Executive Board during several administrations 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 has been a certified board member since 2013.  Since 2014, she has also been a member of the Audit Committee of a closely held Brazilian mining company. 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’ meetings held on May 6, 2015 and on April 13, 2016, respectively. 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

   PositionAndre Dorf

   44

   Chief Executive OfficerGustavo Estrella

   43

   Chief Financial and Investor Relations OfficerLuis Henrique Ferreira Pinto

   56

   Chief Regulated Operations OfficerKarin Regina Luchesi

   40

   Chief Market Operations OfficerWagner Luiz Schneider de Freitas

   45

   Chief Planning and Business Management OfficerCarlos da Costa Parcias Junior

   56

   Chief Business Development OfficerLuiz Eduardo Fróes do Amaral Osório

   43

   Chief Legal and Institutional Relations Officer


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Table of Contents 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 (in both the 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). He is currently a member of the board of directors of CPFL Renováveis and he also served as the CEO of CPFL Renováveis from 2013 to 2016. Since July 2016, Mr. Dorf 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. 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 Energia’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 2004.  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.


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Table of Contents 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. Luiz Eduardo Fróes do Amaral Osório –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. 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). 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 February 16, 2017 with a mandate lasting until our next shareholders’ meeting, set to take place on April 28, 2017, is composed of three members:  Pan Yuehui, Zhang Ran and Luiz Augusto Marques Paes.Pan Yuehui is also an officer of ESC Energia S.A. (one of our shareholders), the financial director of State Grid Brazil Holding S.A., chairman of the fiscal council of Belo Monte Transmissora de Energia S.A. and a member of the fiscal council of Paranaiba Transmissora de Energia S.A.


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Table of Contents 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, Risks and Sustentability Committee, the Human Resources Management Committee and the Related Parties Committee, all governed by the Internal Rules of Committees of the Board of Directors. The committees do not have decision‐making authority and their recommendations are not binding upon the Board of Directors. Management Processes, Risks and Sustainability Committee.  Our Management Processes, Risks and Sustainability Committee supports the Board of Directors in examining and monitoring the following processes:  (i) supervising internal audit; (ii) supervising risk management and compliance activities; (iii) supervising  the Sustainability Platform and the Ethics System, including the channels for reporting complaints; and (iv) improvements in business management processes.  The members of this committee are Liu Yunwei, Fu Zhangyan and Fabio Fernandes Medeiros. 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) preparing 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 Chen Daobiao, Zhang Li and Daniela Sguassabia Domingues. 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 Ding Hongwu, Li Fu and Marcelo Amaral Moraes. 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 2016, 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.


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Table of Contents 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 2016: Compensation for the year ended December 31, 2016Management Bodies

   Board of Directors

   Fiscal Council

   Executive Officers

   TotalNumber of members

   7members(1)

   4.92members(1)

   7members(1)Fixed annual compensation:

   (in thousands ofreais)Salary

   1,771

   790

   8,178

   10,739Direct or indirect benefits

   -

   -

   480

   480Other

   354

   158

   3,891

   4,403Variable compensation:Bonus

   -

   -

   9,799

   9,799Other

   -

   -

   3,927

   3,927Post‐employment benefits

   -

   -

   600

   600Total compensation

   2,125

   948

   26,875

   29,948
 
 (1)Represents the weighted average number of members.  The table below sets forth the compensation paid by our subsidiaries to our management for 2016: Year ended December 31, 2016Board of Directors

   Fiscal Council

   Executive OfficersFixed

   Fixed

   Total (fixed and variable)(in thousands ofreais)Subsidiaries(1)

   -

   -

   6,008
 
 (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 2017 (excluding any compensation to be paid by our subsidiaries to such individuals): Approved compensation for the year ending December 31, 2017(1)Management Bodies

   Board of Directors

   Fiscal Council

   Executive Officers

   TotalNumber of members

   7members(2)

   3members(2)

   7members(2)Fixed annual compensation:

   (in thousands ofreais)Salary

   646

   221

   7,215

   8,082Direct or indirect benefits

   -

   -

   238

   238Other

   129

   44

   4,111

   4,284Variable compensation:Bonus

   -

   -

   11,311

   11,311Other

   -

   -

   5,377

   5,377Post‐employment benefits

   -

   -

   628

   628Total compensation

   775

   265

   28,880

   29,920
  (1)Represents the expected compensation for a twelve-month period (from May 2017 to April 2018), to be approved in the Annual Shareholders’ Meeting of CPFL Energia, which is scheduled to take place on April 28, 2017. (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$58 million for 2016, including R$7 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, to align market practices and to provide for the retention of executives 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 (Plano de Incentivo de Longo Prazo), 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 (or, if such matrix is replaced, another instrument of compulsory distribution) 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 2016, 169,407 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$3.3 million as of December 31, 2016. 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, 2016: Pension Plans for Executive OfficersName of pension plan

   PGBL Bradesco

   PGBL Brasil PrevNumber of Executive Officer members

   5

   2Number of Executive Officer members eligible for retirement

   5

   2Early retirement provisions

   None

   NoneInflation-adjusted value of pension plan contributions held at year-end, excluding contributions made directly by beneficiaries (in thousands ofreais)

   1,063

   148Amount of pension plan contributions made during the year, excluding contributions made directly by beneficiaries (in thousands ofreais)*

   311

   90Provisions 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, 2017 was 23,750.  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, 2016, we had 13,217 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 31,2016

   2015

   2014Distribution

   7,985

   5,248

   4,706Conventional Generation

   95

   106

   108Renewable Generation

   430

   391

   357Commercialization

   48

   48

   49Services

   3,102

   2,554

   2,367Corporate staff

   1,557

   1,543

   1,549Total

   13,217

   9,890

   9,136


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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 2016, we reserved R$68 million (R$56 million of which are booked in current liabilities) for our employee profit sharing program. In addition, part of each employee’s compensation is linked to performance goals.  Employees are evaluated based on criteria such as quality of work product, adherence to safety protocols and productivity.  Our performance evaluation system is designed to evaluate required skill as well, and enables us to evaluate the development of our employees. ITEM 7.MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS Major Shareholders The following table sets forth information relating to the beneficial ownership of our common shares by our major shareholders (beneficial owners of 5.0% or more of our common shares) as of February 28, 2017, reflecting the consummation of the acquisition of control of our company by State Grid Brazil.  Percentages in the following table are based on 1,017,914,746 outstanding common shares. Common Shares

   

   (%)State Grid Brazil Power Participações Ltda.(1)

   556,164,817

   

   54.64Caixa de Previdência dos Funcionários do Banco do Brasil – PREVI (2)

   98,589,229

   

   9.69BNDES Participações S.A. (3)

   68,592,097

   

   6.74Bradespar S.A. (4)

   53,464,240

   

   5.25Executive officers and directors as a group

   23,750

   

   0.00Total

   776,834,133

   

   76.32
 
 (1) State Grid Brazil Power Participações Ltda. is our controlling shareholder.  It holds 322,078,613 shares directly (or 31.64%) and 234,086,204 shares indirectly (or 23.00%) through its wholly-owned subsidiary ESC Energia S.A.  State Grid Brazil Power Participações Ltda. is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China. (2) Caixa de Previdência dos Funcionários do Banco do Brasil – PREVI is a pension fund sponsored by Banco do Brasil S.A.The Brazilian government owns a majority of the voting capital of Banco do Brasil. (3) BNDES Participações S.A. is a subsidiary of BNDES, a federal public bank linked to the Brazilian Ministry of Development, Industry and External Trade. (4) Bradespar S.A. is the beneficial owner of these shares, which are held indirectly through Antares Holdings Ltda. and Brumado Holdings Ltda. State Grid Brazil acquired control of our company on January 23,2017.  On February 16, 2017, State Grid Brazil announced that it intends to carry out a public tender offer to purchase all of the common shares of our company, at a price of  R$ 25.51 (US$ 8.28) per common share, in order to (i) cancel our registration as a Class A publicly-held company with the Brazilian Securities Commission (Comissão de Valores Mobiliários), or CVM; (ii) delist our company from the Novo Mercado section of the São Paulo Stock Exchange; (iii) delist our ADSs from the New York Stock Exchange and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the U.S. Securities and Exchange Commission. As per Significant Event Notice disclosed by both companies to the market on February 23, 2017, State Grid Brazil filled with CVM in February 22, 2017 requiring authorization for a Public Tender Offer for acquisition of CPFL Energia’s shares. Such request is currently under analysis by CVM.


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Table of Contents The shareholders’ agreement that was in effect relating to our shares prior to State Grid Brazil’s acquisition of control of our company was terminated in connection with that acquisition.  There is currently no shareholders’ agreement in place. Related Party Transactions One of our principal shareholders is ESC, which is currently controlled by State Grid Brazil Power Participações Ltda. The controlling shareholder of ESC was, until January 23, 2017, the Camargo Corrêa Group. Camargo Corrêa Group is one of the largest privately‐held industrial conglomerates in Brazil, with controlling equity interests in leading Brazilian engineering and construction, cement, footwear, and textiles companies. Camargo Corrêa Group also shares equity control of important Brazilian steel and highway concession companies, and it has equity participations in a significant Brazilian financial conglomerate and in a global aluminum company. During the year ended December 31, 2016, we have conducted transactions with the former shareholders of ESC (Camargo Corrêa Group) 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 jointventures, 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.
 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 former controlling shareholders, Energia São Paulo FIA. We and our subsidiaries engage in financing transactions with Banco do Brasil as lender.  Banco do Brasil is the sponsor of the Caixa de Previdência dos Funcionários do Banco do Brasil – PREVI pension fund, which was one of our controlling shareholder until January 23, 2017. For balances under the above-mentioned transactions, and further details of our related party transaction in general, please see note 32 to our audited annual consolidated financial statements. Additionally, our distribution subsidiaries pay tariffs to transmission subsidiaries of State Grid Brazil Power Participações Ltda. transmission subsidiaries, held previously to acquisition of CPFL Energia occurred January 23, 2017. These tariffs are paid in order to use transmission network connected to the ONS, considering thar distribution companies have signed contracts with the ONS and the transmission companies (represented by the ONS) entitling them to the use of the transmission network. ITEM 8.Financial Information Consolidated Statements and Other Financial Information See Item 18.  Financial Statements.


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Table of Contents 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$133.8million as of December 31, 2016.  This amount consists of R$40.5 million where we believe the likelihood of loss is probable; R$43.7million where we believe the likelihood of loss is possible; and R$49.6 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$40.5 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 - PROCON) 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 appealed in the administrative sphere against this tax claim but the appeal was denied in November 2016. Following the denial of the administrative appel, CPFL Piratininga has filled a proceeding in the judicial sphere. The amount claimed totaled approximately R$208 million as of December 31, 2016.  We believe that the likelihood of loss is possible. 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.  On February 2017, following the decision of a special appeal, we have made another payment, as an escrow deposit, which amounted R$206 million, related to the interest accrued to the original escrow deposit. This tax claim has also resulted in other proceedings, which total R$ 1.1 billion and are pending decision by the higher courts. 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 new 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$1,742 million as of December 31, 2016 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.


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Table of Contents CPFL Geração is subject to a tax claim in the amount of approximately R$323 million as of December 31, 2016 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$498 million as of December 31, 2016 regarding corporate income tax (IRPJ) and social contributions (CSLL) levied in relation to the period from 1999 to 2003.  The claim alleges excess goodwill amortization in the 10‐year period under Law 9,532/97; excess asset depreciation charges; and the exclusion from the basis of tax calculation of certain inflation-related adjustments to items within Parcel A, known as CVA.  RGE is awaiting a court decision on its challenge to this claim.  We believe that the likelihood of loss is possible.  This claim has generated a number of admistrative proceedings.  In 2016, RGE filed a claim to suspend two of those administrative proceedings until the aforementioned tax claim is judged upon, as the result of this claim indirectly affects the other proceedings, despite the fact that they relate to different periods.  The chance of loss in this proceeding is possible and the potential losses amount to R$ 101 million as of December 2016. CPFL Santa Cruz (two proceedings), CPFL Geração and RGE are also subject to tax claims in the amounts of R$111 million, R$234 million and R$268 million, respectively, as of December 31, 2016, alleging excess goodwill amortization for purposes of calculating IRPJ and CSLL taxes.  Our appeals in this case are awaiting decision.  We believe that the likelihood of loss is possible. 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$218million as of December 31, 2016.  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 several appeals filed by the city of Ribeirão Preto.  We believe that the likelihood of loss is remote.  The amount claimed totaled approximately R$389 million as of December 31, 2016. 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.  Thus, Sul Geradora filed a lawsuit, as the proceeding still awaits a first instance judgment.  We believe the likelihood of loss is possible.  The amount claimed totaled approximately R$85 million as of December 31, 2016. The Brazilian Federal Revenue Office imposed an infraction notice and a fine on CPFL Geração, charging it with overdue taxes during 2011, resulting from omission of non-operating revenues by the defendant as well as compensate accumulated losses above the existent balance.  We filed an appeal to this case, and we are currently awaiting a decision of such appeal.  We believe the likelihood of loss is possible.  The amount claimed totaled approximately R$ 318 million as of December 31, 2016. 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$ 92 million as of December 31, 2016.


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Table of Contents CPFL Piratininga has commenced proceedings seeking the right to deduct in full the value of theContribuição Social sobre o Lucro(CSLL) based on the income tax (Imposto sobre a Renda) for the 2002 base year and all subsequent years.  The initial request and CPFL Piratininga’s appeal were both denied, although CPFL Piratininga has now applied for a special and extraordinary appeal.  We have depostited the full amount of the procedural costs in escrow. We believe the likelihood of a loss is probable and amounts to R$ 140 million as of December 2016. CPFL Paulista is the defendant in an indemnification proceeding for material damages and loss of profits commenced by Mr.  Sebastião José Ismael, alleging an undue reduction in energy affecting his irrigation system for palm heart plants.  CPFL Paulista made payments relating to the alleged damage and is currently in arbitration regarding the amount of any loss of profits.  We believe the likelihood of a loss is probable up to R$ 5 million and possible up to R$ 86 million as of December 31, 2016. CPFL Piratininga is the defendant in an environmental proceeding commenced by the Attorney-General of the State of São Paulo seeking to modify existing maintenance criteria on 10 transmission lines that run close to the Parque Estadual da Serra do Mar because of the destruction of vegetation.  We believe the risk of loss is possible but the amount cannot currently be estimated. RGE is a defendant in a Public Civil Action that relates to the legality of subcontracting maintenance services on electric energy networks.  The instruction phase of the proceeding has passed and we are currently awaiting the sentence.  We believe the likelihood of loss is possible, and the risk amounted R$ 181 million as of December 31, 2016. 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, 2016, our provisions for contingencies were approximately R$833 million, reflecting our ongoing contingency monitoring and risk control.  Our Management believes that none of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition.  See note 22 to our audited annual consolidated financial statements for more information on the status of our litigation. Dividend Policy For our policy on dividend distributions, see “Item 10.  Additional Information—Allocation of Net Income and Distribution of Dividends”. ITEM 9.The Offer and Listing Trading Markets Our common shares are listed on the BM&FBOVESPA, and our ADSs are listed on the New York Stock Exchange.  Each ADS represents two shares.  The ADSs commenced trading on the NYSE on September 29, 2004.  As of December 31, 2016, the ADSs represented 3.0% of our shares and 9.5% of our current global public float. State Grid Brazil acquired control of our company on January 23,2017.  On February 16, 2017, State Grid Brazil announced that it intends to carry out a public tender offer to purchase all of the common shares of our company, at a price of  R$ 25.51 (US$ 8.28) per common share, in order to (i) cancel our registration as a Class A publicly-held company with the Brazilian Securities Commission (Comissão de Valores Mobiliários), or CVM; (ii) delist our company from the Novo Mercado section of the São Paulo Stock Exchange; (iii) delist our ADSs from the New York Stock Exchange and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the U.S. Securities and Exchange Commission. As per Significant Event Notice disclosed by both companies to the market on February 23, 2017, State Grid Brazil filled with CVM in February 22, 2017 requiring authorization for a Public Tender Offer for acquisition of CPFL Energia’s shares. Such request is currently under analysis by CVM.


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Table of Contents 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

   Low2011 (*)

   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

   6.952016:

   25.21

   13.87

   15.55

   6.752015: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:First Quarter

   20.30

   13.87

   11.10

   6.75Second Quarter

   20.81

   18.15

   12.86

   10.06Third Quarter

   24.32

   20.56

   15.16

   12.80Fourth Quarter

   25.21

   23.60

   15.55

   13.702017:January

   25.39

   25.17

   16.20

   15.49February

   25.58

   25.33

   16.64

   16.15March

   25.87

   25.46

   16.67

   15.93April (up to April 10)

   25.82

   25.79

   16.64

   16.36
 
 (*)   Prices were adjusted to reflect the change in the ratio of our ADSs and the simultaneous reverse stock split and forward stock split of our common shares. Corporate Governance Practices In 2000, the BM&FBOVESPA introduced three special listing segments, known as Level 1, Level 2 and theNovo Mercado, aiming at fostering a secondary market for securities issued by Brazilian companies with securities listed on the BM&FBOVESPA, by prompting such companies to follow good practices of corporate governance.  The listing segments were designed for the trading of shares issued by companies voluntarily undertaking to abide by corporate governance practices and disclosure requirements in addition to those already imposed by Brazilian law.  These rules generally increase shareholders’ rights and enhance the quality of information provided to shareholders and stakeholders.  In order to maintain high standards of corporate governance, we have signed an agreement with the BM&FBOVESPA to list our securities on theNovo Mercado. Our corporate governance guidelines apply to us and all of our subsidiaries and affiliated companies.  They aim at promoting interaction among our shareholders, Board of Directors, Fiscal Council and Board of Executive Officers.  Our Management has committed to focus on: 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);Fairness (fair treatment to our shareholders, our customers, suppliers, employees, creditors, government bodies, regulatory agencies, etc.);Accountability (accountability of our Management to our shareholders, and responsibility for their acts while in office); andCompliance (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.  In 2016, the Board of Directors approved an amendment to our Corporate Governance Guidelines, which specifies that the internal audit and corporate governance advisors report directly to the Board of Directors.


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Table of Contents 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. 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.


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Table of Contents Proposed changes to our Bylaws Certain proposed changes to our Bylaws will be submitted for a vote of our shareholders at an Extraordinary General Meeting convened for April 28, 2017.  These changes are summarized in the Proposal of the Management, which we made available to shareholders and reported on Form 6-K to the SEC on March 28, 2017. 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 financial 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 financial 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 financial 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 financial assets cannot exceed the balance of the concession financial asset recorded in CPFL Energia’s consolidated financial statements; (iv) the remaining profit, except as otherwise resolved by the Shareholders’ Meeting, shall be allocated to the working capital reinforcement reserve, the total of which shall not exceed the amount of the subscribed capital stock; and (v) 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. 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.


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Table of Contents 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 SISBACEN 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 SISBACEN 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 exchanges such proceeds for 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 income tax, except for (i) dividends declared based on profits generated prior to December 31, 1995, and (ii) in 2014 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 with the SISBACEN, which permits the depositary and the custodian to remit proceeds related to dividends and other distributions or sales proceeds with respect to the common shares represented by ADSs outside of Brazil.  In the event the holder exchanges the ADSs for common shares, the holder will need to update shareholder’s registration with the SISBACEN and enter into simultaneous foreign exchange transactions (without the effective remittance of funds) in order to re-enable the remittance of proceeds related to dividends and other distributions or sales.  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. If the holder is not a duly qualified investor and does not follow the procedures indicated in the above paragraph, he or she will not be able to remit abroad any proceeds relating to dividends and other distributions or sales. 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 income tax and social contribution on net profits.  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 certain equity accounts for the applicable period.  The deduction of the interest on shareholders’ equity payments for IRPJ and CSLL purposes is limited to the greater of:


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Table of Contents 50.0% of net income (determined 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 accrued profits and profit reserves as of the beginning of the year in respect of which such payment is made.
 The payment of interest on shareholders’ equity 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. In 2015, our Board of Directors approved a declaration of dividends amounted 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. 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. Dividend Policy We intend to declare and pay dividends and/or interest attributed to shareholders’ equity in amounts of at least 50.0% of our adjusted net income, in semi‐annual installments.  The amount of any of our distributions of dividends and/or interest attributed to shareholders’ equity will depend on a series of factors, such as our financial conditions, prospects, macroeconomic conditions, tariff adjustments, regulatory changes, growth strategies and other matters our Board of Directors and our shareholders may consider relevant.  In addition, covenants contained in our debt instruments may limit the amount of dividends and/or interest attributable to shareholders’ equity that we may make.  Within the context of our tax planning, we may in the future determine that it is to our benefit to distribute interest attributable to shareholders’ equity in lieu of dividends. Our Board of Directors may approve the distribution of dividends and/or interest attributed to shareholders’ equity, calculated based on our annual or semi‐annual financial statements or on financial statements relating to shorter periods, or also based on accrued profits recorded or on profits allocated to non‐profits reserve accounts in the annual or semi‐annual financial statements.  The declaration of annual dividends, including dividends in excess of the mandatory distribution, requires approval by the vote of the majority of the holders of our common shares.


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Table of Contents

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;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); andapproval 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;





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Table of Contents 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. 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.  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.


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Table of Contents 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;

capital increase or capital reduction;

issuance of debentures or subscription bonuses;

issuance of preferred shares;

reduction 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


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Table of Contents 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, subject to certain procedures governed by Brazilian Corporate Law.  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, among other provisions, the right of our shareholders casting votes remotely.  For such purposes and subject to certain procedures governed by Brazilian Corporate Law, (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.  In the case of instructions given to authorized services providers, such authorized services providers may accept instructions by any means that they usually use to communicate with the shareholders and also refuse to accept voting instructions from shareholders with outdated registry. We (and also certain authorized services providers) 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). The referred amendments to CVM Rule No.  481 have also ruled out the right of shareholders to ask for the inclusion of candidates and proposals in the ballot, to the extent that observed the percentage of a particular type of shares vis-à-vis the stock capital of the company (as provided for in CVM Rule No.  481, as amended) and the terms provided for in CVM Rule No.  481.  These requests must be made: (i) in the case of an annual general meeting:  on the first business day of the fiscal year in which the annual general meeting shall be held and up to 45 days before the date of such meeting; or (ii) in the case of an extraordinary general meeting to appoint members of the board of directors and/or the fiscal council:  on the first business day after an event that justifies the calling of an extraordinary general meeting for the election of members of the board of directors and/or the fiscal council and up to 35 days before the date of such meeting.  We may request rectifications to requests made by shareholders wishing to include proposals or candidates on the ballot.  A request made by a shareholder may be revoked at any time up to the relevant general meeting, upon notice by the requesting shareholder to the Investor Relations Officer, in which case any votes may be disregarded. 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.


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Table of Contents 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, subject to certain conditions provided under Brazilian Corporate Law. 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”.


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Table of Contents 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 SISBACEN.  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 remitting proceeds related to dividends, or distributions or the proceeds from any sale of common shares 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. The custodian has obtained an electronic registration with SISBACEN in the name of Citibank N.A., the depositary, with respect to the American Depositary Shares.  Under this electronic registration, the custodian and the depositary are able to remit outside Brazil the dividends and other distributions on our common shares represented by American Depositary Shares.  Any holder who exchanges American Depositary Shares for common shares will need to update his or her registration with the SISBACEN and enter into simultaneous foreign exchange transactions (without the effective remittance of funds) in order to be able to remit dividends and other distributions outside Brazil.  The holder may not be able to remit outside Brazil any distributions, or proceeds from dispositions of shares, util he or she has entered into these foreign exchange transactions and updated his or her SISBACEN registration.  If the holder converts the American Depositary Shares into a direct investment and obtains his or her electronic SISBACEN registration through the RDE-IED Registry, he or she may be subject to less favorable Brazilian tax treatment than a holder of American Depositary Shares.For further information, 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 common shares or ADSs.  The summary is based upon the tax laws of Brazil and regulations thereunder and on the tax laws of the United States and regulations thereunder as in effect on the date hereof, which are subject to change (possibly on a retroactive basis) and different interpretations.Holders of common shares or ADSs should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common shares or ADSs. Although there is currently no income tax treaty between Brazil and the United States, the tax authorities of the two countries have had discussions that may culminate in such a treaty.  No assurance can be given, however, as to whether or when a treaty will enter into force or how it will affect the U.S. holders (as defined below) of common shares or ADSs.  Prospective holders of common shares or ADSs should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common shares or ADSs in their particular circumstances.


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Table of Contents 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 the Brazilian financial and capital markets; (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, among others. 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.


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Table of Contents 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. 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. 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. 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.


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Table of Contents 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 rates varying from 15% to 22.5%, depending on the amount of the capital gain, 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 tax rate of 0.005% shall be applicable and withheld by the intermediary institution (i.e., a broker) that receives the order directly from the Non‐Resident Holder, which can be later offset against any income tax due on the capital gain earned by the Non‐Resident Holder.
 Any other gains assessed on a sale or disposition of the common shares that is not carried out on a Brazilian stock exchange are subject to income tax rates varying from 15% to 22.5%.  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 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 rates varying from 15% to 22.5% as of 2017 or 25%, in case of Non-Brazilian Holders in Low or Nil Tax Jurisdictions, as the case may be. The deposit of our common shares in exchange for ADSs will be subject to Brazilian income tax if the acquisition cost of the shares is lower than (1) the average price per share on a Brazilian stock exchange on which the greatest number of such shares were sold on the day of deposit, or (2) if no shares were sold on that day, the average price on the Brazilian stock exchange on which the greatest number of shares were sold in the 15 trading sessions immediately preceding such deposit.  In this case, the difference between the acquisition cost and the average price of the shares calculated as above will be considered to be a capital gain subject to withholding income tax at the rates varying from 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. 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.


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Table of Contents 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 rate applicable 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%. 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.


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Table of Contents U.S. Federal Income Tax Consequences This discussion is a summary of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of common shares or ADSs.  This discussion is based on the U.S. Internal Revenue Code of 1986, as amended, or the Code, its legislative history, existing final, temporary and proposed Treasury regulations, administrative pronouncements by the U.S. Internal Revenue Service, or the IRS, and judicial decisions, in each case as of the date hereof, all of which are subject to change (possibly on a retroactive basis) and to different interpretations. This discussion does not purport to be a comprehensive description of all of the U.S. federal income tax consequences that may be relevant to a particular holder (including tax considerations that arise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known by investors) and holders are urged to consult their own tax advisors regarding their specific tax situations.  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: 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.


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


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Table of Contents Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.  Subject to the below‐mentioned concerns by the U.S. Treasury Department regarding certain inconsistent actions taken by intermediaries and certain exceptions for short‐term and hedged positions, the U.S. dollar amount of dividends received by certain U.S. holders (including individuals) with respect to the ADSs will be subject to taxation at a maximum rate of 20.0% if the dividends represent “qualified dividend income”.  Dividends paid on the ADSs will be treated as qualified dividend income if (i) the ADSs are readily tradable on an established securities market in the United States and (ii) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a PFIC.  The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed.  However, no assurances can be given that the ADSs will be or will remain readily tradable.  See below for a discussion regarding our PFIC determination. Based on existing guidance, it is not entirely clear whether dividends received with respect to the common shares will be treated as qualified dividend income, because the common shares are not themselves listed on a U.S. exchange.  In addition, the U.S. Treasury Department has announced its intention to promulgate rules pursuant to which holders of common shares or ADSs and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to establish that dividends are treated as qualified dividends.  Because such procedures have not yet been issued, it is not clear whether we will be able to comply with them.U.S. holders of common shares or ADSs should consult their own tax advisors regarding the availability of the reduced dividend tax rate in the light of their own particular circumstances. 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.


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Table of Contents 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. 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.


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


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Table of Contents 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. 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, 2016, approximately 25% of our indebtedness was denominated in U.S. dollars.  Also at December 31, 2016, we had swap agreements that offset the exchange rate risk with respect to R$5,430 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$61 million (R$25 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.


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Table of Contents 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, 2016, the amount of such liabilities, net of such assets and after giving effect to swaps, was R$9,353 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, 2016, would result in a net additional cash outflow of approximately R$282 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. 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.


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Table of Contents 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; (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 2016 we received US$520,000 (or US$364,000 net of withholding income tax) from the depositary 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, 2016.  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.


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Table of Contents 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. 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, 2016 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, 2016. On October 31, 2016, we consummated the acquisition of all of the shares of the capital stock of RGE Sul (formerly AES Sul Distribuidora Gaúcha de Energia S.A.).  Pursuant to SEC guidance, if a registrant consummates a material purchase business combination during its fiscal year, management may exclude the internal control over financial reporting of the acquired business from management’s report on internal control over financial reporting for that fiscal year.  On that basis, our management excluded from its report the internal control over financial reporting of RGE Sul, which total assets and net operating revenues represent9.7% and2.7%, respectively, of our consolidated total assets and net revenues as of and for the year ended December 31, 2016.  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, 2016, based on the criteria established in Internal Control Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management's Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at RGE Sul Distribuidora Gaucha S.A. (formerly AES Sul Distribuidora Gaúcha de Energia S.A.), which was acquired on October 31, 2016 which total assets and net operating revenues represent 9.7% and 2.7% of total assets and net operating revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2016. Accordingly, our audit did not include the internal control over financial reporting at RGE Sul Distribuidora Gaucha S.A. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards (“IFRS”), issued by the International Accounting Standards Board (“IASB”). 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 IFRSissued by IASBand that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, 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, 2016 of the Company and our report dated April 17, 2017 expressed an unqualified opinion on those financial statements and included an explanatory paragraph stating that the statements of income for the years ended December 31, 2015 and 2014 have been retrospectively adjusted as a result of changes in the accounting policyadopted by the Company regardingthe classification of adjustmentsin theexpected cash flows related to the concession financial asset. Campinas, São Paulo, Brazil April 17, 2017 /s/ DELOITTE TOUCHE TOHMATSU Auditores Independentes


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Table of Contents 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, Pan Yuehui, 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?Arquivo=c8hbijtPBCqQTNpMfzWTDw==(This URL is intended to be an inactive textual reference only.  It is not intended to be an active hyperlink to our website.  The information on our website, which might be accessible through a hyperlink resulting from this URL, is not and shall not be deemed to be, incorporated into this annual report).  We 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 occurred 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 public accounting firm during the years ended December 31, 2016 and 2015.  Our independent registered public accounting firm was Deloitte Touche Tohmatsu Auditores Independentes for the years ended December 31, 2016 and 2015. Year ended December 31,2016

   2015(in thousands ofreais)Audit fees

   4,888

   4,477Audit‐related fees

   1,583

   1,782Tax fees

   440

   257Total

   6,911

   6,516


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Table of Contents “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 2016 and 2015, 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, 2016 and 2015, 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, 2016 and 2015, respectively. Audit Committee Approval Policies and Procedures Our fiscal council currently serves as our audit committee for purposes of the Sarbanes‐Oxley Act of 2002.  Our fiscal council has not established pre-approval policies or procedures for recommending the engagement of our independent auditors for services to our Board of Directors.  Pursuant to Brazilian law, our Board of Directors is responsible for the engagement of independent auditors.  Brazilian law prohibits our independent auditors from providing any consulting services to our subsidiaries, or to us, that may impair their independence. ITEM 16D.Exemptions from the Listing Standards for Audit Committees Under the listed company audit committee rules of the NYSE and the SEC, we must comply with Exchange Act Rule 10A‐3, which requires that we establish an audit committee composed of members of the Board of Directors that meets specified requirements.  We have designated and empowered our fiscal council to perform the role of the audit committee in reliance on the exemption set forth in Exchange Act Rule 10A‐3(c)(3).  In our assessment, our fiscal council acts independently in performing the responsibilities of an audit committee under the Sarbanes‐Oxley Act and satisfies the other requirements of Exchange Act Rule 10A‐3. ITEM 16E.Purchases of Equity Securities by the Issuer and Affiliated Purchasers None. ITEM 16F.Change in Registrant’s Certifying Accountant Deloitte Touche Tohmatsu Auditores Independentes was appointed to act as our independent public accounting firm to audit our consolidated financial statements for the fiscal years ended December 31, 2015 and 2016 until the filing of this Form 20-F with the SEC.  Pursuant to CVM regulations, Brazilian public companies are required to rotate their independent public accounting firm every five years.   Due to the limitations set forth in these regulations, we did not seek to renew Deloitte Touche Tohmatsu Auditores Independentes’s contract when it was expired and Deloitte Touche Tohmatsu Auditores Independentes could not attempt to stand for reelection for CVM purposes.  On December 14, 2016, our Board of Directors approved the appointment of KPMG Auditores Independentes to act as our independent public accounting firm beginning with a review of our quarterly information for the first quarter of 2017. Deloitte Touche Tohmatsu Auditores Independentes’s reports on our financial statements for each of the fiscal years ended on December 31, 2015 and 2016 did not contain an adverse opinion or disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope or accounting principles.  During such fiscal years, there were no disagreements with Deloitte Touche Tohmatsu Auditores Independentes, whether or not resolved, on any matter of accounting principles or practices, financial statement disclosure, or scope of audit procedures, which disagreement, if not resolved to the satisfaction of Deloitte Touche Tohmatsu Auditores Independentes, would have caused Deloitte Touche Tohmatsu Auditores Independentes to make a reference to the subject matter of the disagreement in connection with its audit reports for such fiscal years. We have requested that Deloitte Touche Tohmatsu Auditores Independentes furnish us with a letter addressed to the SEC stating whether or not it agrees with the above statements.  A copy of this letter is filed as Exhibit 15.1 to this Form 20 F. We did not consult KPMG Auditores Independentes during our two most recent fiscal years or any subsequent interim period as to the application of accounting principles to a specified transaction, either completed or proposed, the type of audit opinion that might be rendered on our financial statements or any matter that was either the subject of a disagreement (as defined in Item 16F(a)(1)(iv) of Form 20 F) or a reportable event (as described in Item 16F(a)(1)(v) of Form 20 F).


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Table of Contents 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 State Grid Brazil Participações Ltda., an indirect subsidiary of State Grid Corporation of China. 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 two 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 three 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 l 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–101, incorporated herein by reference.


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Table of Contents ITEM 19.Exhibits No.

   Description1.1

   Amended and Restated Bylaws of CPFL Energia S.A. (together with an English version).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 2002.15.1

   Letter from Deloitte Touche Thomatsu Auditores Independentes to the SEC, dated April 17, 2017regarding the change in independent public accounting firm.
  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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Table of Contents 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.” DistributionNetwork:  Electric network system that distributes energy to end consumers within a concession area.


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Table of Contents 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 Getúlio 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. 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.


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Table of Contents 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). *RTP:*PeriodicTariff Revision (revisão tarifária periódica) SHPP or Small Hydroelectric Power Plants:  Power projects with capacity from 3 MW to 30 MW.


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Table of Contents 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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Table of Contents SIGNATURES Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant, CPFL Energia S.A., hereby certifies that it meets all of the requirements for filing on Form 20‐F and that it has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Campinas, state of São Paulo, Brazil, on April 17, 2017. CPFL ENERGIA S.A. By:/s/ Andre Dorf Name:    Andre Dorf Title:       Chief Executive Officer By:/s/ Gustavo Estrella Name:    Gustavo Estrella Title:       Chief Financial Officer





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Table of Contents  REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the Board of Directors and Shareholders ofCPFL 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, 2016 and 2015, 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, 2016. 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 consolidated financial position ofCPFL Energia S.A.and subsidiaries as of December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, inaccordance with International Financial Reporting Standards - IFRS, issued by the International Accounting Standards Board - IASB.





As discussed in note 2.7 to the consolidated financial statements, as a result of changes in the accounting policy adopted by the Company regarding the classification of adjustments in the expected cash flows related to the concession financial asset, the accompanying statements of income for the years ended December 31, 2015 and 2014, have been retrospectively adjusted and are restated as set out in IAS 8 - Accounting Policies, Changes in Accounting Estimates and Errors.





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, 2016, 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 17,2017 expressed an unqualified opinion on the Company's internal control over financial reporting.





Campinas, São Paulo, Brazil





April 17,2017





/s/ DELOITTE TOUCHE TOHMATSU





Auditores Independentes





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CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AT DECEMBER 31, 2016 AND 2015 (In thousands of Brazilian reais - R$)
  ASSETS

   

   Note

   

   Dec 31, 2016

   

   Dec 31, 2015CURRENT ASSETSCash and cash equivalents

   

   5

   

   6,164,997

   

   5,682,802Consumers, concessionaires and licensees

   

   6

   

   3,765,893

   

   3,174,918Dividend and interest on capital

   

   13

   

   73,328

   

   91,392Securities

   

   

   

   449

   

   23,633Taxes recoverable

   

   7

   

   403,848

   

   475,211Derivatives

   

   35

   

   163,241

   

   627,493Sector financial asset

   

   8

   

   -

   

   1,464,019Leases

   

   10

   

   19,281

   

   12,883Concession financial asset

   

   11

   

   10,700

   

   9,630Other receivables

   

   12

   

   777,451

   

   946,670TOTAL CURRENT ASSETS

   

   

   

   11,379,187

   

   12,508,652NONCURRENT ASSETSConsumers, concessionaires and licensees

   

   6

   

   203,185

   

   128,946Associates, subsidiaries and parent company

   

   32

   

   47,631

   

   84,265Escrow deposits

   

   22

   

   550,072

   

   1,227,527Securities

   

   

   

   62

   

   -Taxes recoverable

   

   7

   

   198,286

   

   167,159Sector financial assets

   

   8

   

   -

   

   489,945Derivatives

   

   35

   

   641,357

   

   1,651,260Deferred tax assets

   

   9

   

   922,858

   

   334,886Leases

   

   10

   

   50,541

   

   34,504Concession financial asset

   

   11

   

   5,363,144

   

   3,597,474Investments at cost

   

   

   

   116,654

   

   116,654Other receivables

   

   12

   

   715,650

   

   560,014Investments

   

   13

   

   1,493,753

   

   1,247,631Property, plant and equipment

   

   14

   

   9,712,998

   

   9,173,217Intangible assets

   

   15

   

   10,775,613

   

   9,210,338TOTAL NONCURRENT ASSETS

   

   

   

   30,791,805

   

   28,023,819TOTAL ASSETS

   

   

   

   42,170,992

   

   40,532,471
  The accompanying notes are an integral part of these consolidated financial statements.


F - 1

---



CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AT DECEMBER 31, 2016 AND 2015 (In thousands of Brazilian reais - R$)
  LIABILITIES AND EQUITY

   

   Note

   

   Dec 31, 2016

   

   Dec 31, 2015CURRENT LIABILITIESTrade payables

   

   16

   

   2,728,130

   

   3,161,210Interest on debts

   

   17

   

   129,364

   

   118,267Interest on debentures

   

   18

   

   305,180

   

   232,227Borrowings

   

   17

   

   1,746,284

   

   2,831,654Debentures

   

   18

   

   1,242,095

   

   458,165Private pension plan

   

   19

   

   33,209

   

   802Regulatory charges

   

   20

   

   366,078

   

   852,017Taxes, fees and contributions

   

   21

   

   681,544

   

   653,342Dividend

   

   25

   

   232,851

   

   221,855Estimated payroll

   

   

   

   131,707

   

   79,924Derivatives

   

   35

   

   6,055

   

   981Sector financial liability

   

   8

   

   597,515

   

   -Use of public asset

   

   23

   

   10,857

   

   9,457Other payables

   

   24

   

   807,623

   

   904,971TOTAL CURRENT LIABILITIES

   

   

   

   9,018,492

   

   9,524,873NONCURRENT LIABILITIESTrade payables

   

   16

   

   129,781

   

   633Interest on debts

   

   17

   

   144,709

   

   120,659Interest on debentures

   

   18

   

   29,153

   

   16,487Borrowings

   

   17

   

   11,023,685

   

   11,592,206Debentures

   

   18

   

   7,423,519

   

   6,363,552Private pension plan

   

   19

   

   1,019,233

   

   474,318Taxes, fees and contributions

   

   21

   

   26,814

   

   -Deferred tax liabilities

   

   9

   

   1,324,134

   

   1,432,594Provision for tax, civil and labor risks

   

   22

   

   833,276

   

   569,534Derivatives

   

   35

   

   112,207

   

   33,205Sector financial liability

   

   8

   

   317,406

   

   -Use of public asset

   

   23

   

   86,624

   

   83,124Other payables

   

   24

   

   309,292

   

   191,148TOTAL NONCURRENT LIABILITIES

   

   

   

   22,779,832

   

   20,877,460SHAREHOLDERS ́ EQUITY

   

   25Issued capital

   

   

   

   5,741,284

   

   5,348,312Capital reserves

   

   

   

   468,014

   

   468,082Legal reserve

   

   

   

   739,102

   

   694,058Statutory reserve - concession financial asset

   

   

   

   702,928

   

   585,451Statutory reserve - working capital improvement

   

   

   

   545,505

   

   392,972Additional dividend proposed

   

   

   

   7,820

   

   -Accumulated other comprehensive income

   

   

   

   (234,633)

   

   185,3217,970,021

   

   7,674,196Equity attributable to noncontrolling interests

   

   

   

   2,402,648

   

   2,455,942TOTAL SHAREHOLDERS ́ EQUITY

   

   

   

   10,372,668

   

   10,130,138TOTAL LIABILITIES AND SHAREHOLDERS ́ EQUITY

   

   

   

   42,170,992

   

   40,532,471
  The accompanying notes are an integral part of these consolidated financial statements.


F - 2

---



CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 and 2014 (In thousands of Brazilian reais - R$, except for earnings per share)
  Note

   

   2016

   

   2015 *Restated

   

   2014 *RestatedNET OPERATING REVENUE

   

   27

   

   19,112,089

   

   20,599,212

   

   17,399,196COST OF ELECTRIC ENERGY SERVICESCost of electric energy

   

   28

   

   (11,200,242)

   

   (13,311,747)

   

   (10,643,130)Cost of operation

   

   29

   

   (2,248,795)

   

   (1,907,197)

   

   (1,672,359)Cost of services rendered to third parties

   

   29

   

   (1,357,032)

   

   (1,049,101)

   

   (946,052)GROSS PROFIT

   

   

   

   4,306,020

   

   4,331,167

   

   4,137,655Operating expenses

   

   29Sales expenses

   

   

   

   (547,251)

   

   (464,583)

   

   (402,698)General and administrative expenses

   

   

   

   (849,416)

   

   (863,499)

   

   (773,630)Other Operating Expense

   

   

   

   (386,746)

   

   (357,653)

   

   (328,000)INCOME FROM ELECTRIC ENERGY SERVICES

   

   

   

   2,522,608

   

   2,645,433

   

   2,633,327Equity interests in associates and joint ventures

   

   13

   

   311,414

   

   216,885

   

   59,684FINANCE INCOME (COSTS)

   

   30Finance income

   

   

   

   1,200,503

   

   1,143,247

   

   785,794Finance costs

   

   

   

   (2,653,977)

   

   (2,551,110)

   

   (1,968,503)(1,453,474)

   

   (1,407,863)

   

   (1,182,708)PROFIT BEFORE TAXES

   

   

   

   1,380,547

   

   1,454,454

   

   1,510,304Social contribution

   

   9

   

   (150,859)

   

   (160,162)

   

   (168,989)Income tax

   

   9

   

   (350,631)

   

   (419,015)

   

   (454,871)(501,490)

   

   (579,177)

   

   (623,860)PROFIT FOR THE YEAR

   

   

   

   879,057

   

   875,277

   

   886,443Profit attributable to the owners of the Company

   

   

   

   900,885

   

   864,940

   

   949,177Profit (loss) attributable to noncontrolling interests

   

   

   

   (21,828)

   

   10,337

   

   (62,733)Earnings per share attributable to owners of the Company:Basic

   

   26

   

   0.89

   

   0.85

   

   0.93Diluted

   

   26

   

   0.87

   

   0.83

   

   0.92
 (*) Includes the effects of note 2.7. The accompanying notes are an integral part of these consolidated financial statements.


F - 3

---



CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 and 2014 (In thousands of Brazilian reais - R$)
  2016

   

   2015

   

   2014Profit for the year

   

   879,057

   

   875,277

   

   886,443Other comprehensive incomeItems that will not be reclassified subsequently to profit and loss- Actuarial gains (losses), net of tax effects

   

   (394,175)

   

   65,547

   

   (225,720)Total Comprehensive income for the year

   

   484,882

   

   940,825

   

   660,724Attributable to owners of the Company

   

   506,709

   

   930,488

   

   723,457Attributable to noncontrolling interests

   

   (21,828)

   

   10,337

   

   (62,733)
   The accompanying notes are an integral part of these consolidated financial statements.


F - 4

---



CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 and 2014 (In thousands of Brazilian reais - R$)
  Earning reserves

   

   Accumulated comprehensive income

   

   

   

   

   

   Noncontrolling interestsStatutory reservesRetained

   

   Concession

   

   Working

   

   

   

   

   

   Private

   

   

   

   

   

   Accumulated

   

   OtherIssued

   

   Capital

   

   Legal

   

   earnings

   

   financial

   

   capital

   

   

   

   Deemed

   

   pension

   

   Retained

   

   

   

   comprehensive

   

   equity

   

   Totalcapital

   

   reserves

   

   reserve

   

   reserve

   

   asset

   

   improvement

   

   Dividends

   

   cost

   

   plan

   

   earnings

   

   Total

   

   income

   

   component

   

   equityBalance 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 equityChanges in 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 ownersPrescribed dividends

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   5,722

   

   5,722

   

   -

   

   -

   

   5,722Interim 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

   

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

   -

   

   (207)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (207)

   

   -

   

   207

   

   -Business combination - CPFL Renováveis / DESA

   -

   

   180,297

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   180,297

   

   -

   

   653,366

   

   833,663Business 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

   

   -

   

   -

   

   65,547Internal changes of shareholders'equityChanges in 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 ownersCapital increase

   554,888

   

   -

   

   -

   

   -

   

   -

   

   (554,888)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Prescribed dividends

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   5,597

   

   5,597

   

   -

   

   -

   

   5,597Additional 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

   

   -

   

   585,450

   

   392,972

   

   -

   

   457,491

   

   (272,170)

   

   -

   

   7,674,196

   

   15,320

   

   2,440,623

   

   10,130,140Total comprehensive incomeProfit for the year

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   900,885

   

   900,885

   

   -

   

   (21,828)

   

   879,057Other comprehensive income - actuarial gains

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (394,175)

   

   -

   

   (394,175)

   

   -

   

   -

   

   (394,175)Internal changes of shareholders'equityRealization of deemed cost of property, plant and equipment

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (39,058)

   

   -

   

   39,058

   

   -

   

   (2,649)

   

   2,649

   

   -Tax on realization of deemed cost

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   13,280

   

   -

   

   (13,280)

   

   -

   

   901

   

   (901)

   

   -Recognition of legal reserve

   -

   

   -

   

   45,044

   

   -

   

   -

   

   -

   

   -

   

   

   

   -

   

   (45,044)

   

   -

   

   -

   

   -

   

   -Changes in statutory reserve in the year

   -

   

   -

   

   -

   

   -

   

   117,478

   

   545,505

   

   -

   

   -

   

   -

   

   (662,983)

   

   -

   

   -

   

   -

   

   -Other changes in noncontrolling interests

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (1,176)

   

   (1,176)Capital transactions with ownersCapital increase

   392,972

   

   -

   

   -

   

   -

   

   -

   

   (392,972)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Prescribed dividends

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   3,144

   

   3,144

   

   -

   

   -

   

   3,144Dividend proposal approved

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   7,820

   

   -

   

   -

   

   (7,820)

   

   -

   

   -

   

   -

   

   -Dividend distributed to noncontrolling interests

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (30,827)

   

   (30,827)Dividend proposal approved

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (213,960)

   

   (213,960)

   

   -

   

   -

   

   (213,960)Capital increase in subsidiaries with no change in control

   -

   

   (68)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (68)

   

   -

   

   535

   

   467Balance at December 31, 2016

   5,741,284

   

   468,014

   

   739,102

   

   -

   

   702,928

   

   545,505

   

   7,820

   

   431,713

   

   (666,346)

   

   -

   

   7,970,021

   

   13,572

   

   2,389,076

   

   10,372,668
  The accompanying notes are an integral part of these consolidated financial statements   F - 5


---



CPFL ENERGIA S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWSFOR THE YEARS ENDED DECEMBER 31, 2016, 2015 and 2014 (In thousands of Brazilian reais – R$)
  2016

   

   2015

   

   2014OPERATING CASH FLOWProfit before taxes

   

   1,380,547

   

   1,454,454

   

   1,510,304ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIESDepreciation and amortization

   

   1,291,165

   

   1,279,902

   

   1,159,964Provision for tax, civil and labor risks

   

   228,292

   

   258,539

   

   191,228Allowance for doubtful debts

   

   176,349

   

   126,879

   

   83,699Interest on debts, inflation adjustment and exchange rate changes

   

   2,052,959

   

   1,519,819

   

   1,486,061Pension plan expense

   

   76,638

   

   60,184

   

   48,165Equity interests in associates and joint ventures

   

   (311,414)

   

   (216,885)

   

   (59,684)Impairment

   

   48,291

   

   38,956

   

   -Loss on disposal of noncurrent assets

   

   83,576

   

   16,309

   

   20,726Deferred taxes (PIS and COFINS)

   

   (8,579)

   

   19,138

   

   24,946Others

   

   (1,832)

   

   (5,825)

   

   (2,431)5,015,992

   

   4,551,470

   

   4,462,978DECREASE (INCREASE) IN OPERATING ASSETSConsumers, concessionaires and licensees

   

   (205,828)

   

   (1,055,143)

   

   (265,103)Dividends and interest on capital received

   

   83,356

   

   24,050

   

   40,374Taxes recoverable

   

   128,453

   

   (62,041)

   

   (134)Escrow deposits

   

   756,171

   

   22,827

   

   65,732Sectorial financial asset

   

   2,494,223

   

   (858,860)

   

   (932,719)Receivables - amounts from the Energy Development Account - CDE / CCEE

   

   186,052

   

   181,141

   

   (352,379)Concession financial assets (transmission companies)

   

   (55,134)

   

   (44,243)

   

   (62,299)Other operating assets

   

   265,404

   

   (82,278)

   

   20,634INCREASE (DECREASE) IN OPERATING LIABILITIESTrade payables

   

   (782,963)

   

   787,063

   

   470,982Other taxes and social contributions

   

   (63,986)

   

   412,703

   

   193,357Other liabilities with private pension plan

   

   (77,183)

   

   (112,172)

   

   (118,897)Regulatory charges

   

   (514,935)

   

   808,223

   

   11,415Tax, civil and labor risks paid

   

   (216,998)

   

   (247,512)

   

   (188,000)Sectorial financial liability

   

   288,144

   

   (23,170)

   

   21,998Payables - amounts provided by the CDE

   

   (70,907)

   

   19,696

   

   25,807Other operating liabilities

   

   (148,967)

   

   107,930

   

   84,467CASH FLOWS PROVIDED BY OPERATIONS

   

   7,080,894

   

   4,429,684

   

   3,478,213Interest paid on debts and debentures

   

   (1,570,985)

   

   (1,595,649)

   

   (1,333,570)Income tax and social contribution paid

   

   (875,883)

   

   (276,061)

   

   (552,070)NET CASH FROM OPERATING ACTIVITIES

   

   4,634,026

   

   2,557,974

   

   1,592,573INVESTING ACTIVITIESPrice paid in business combination net of cash acquired

   

   (1,496,675)

   

   -

   

   (68,464)Cash incorporated in business combination

   

   -

   

   -

   

   139,293Capital increase in investees

   

   -

   

   -

   

   (45,445)Gain on sales of interest in joint ventures

   

   -

   

   10,454

   

   -Purchases of property, plant and equipment

   

   (1,026,867)

   

   (550,003)

   

   (345,049)Securities, pledges and restricted deposits

   

   (125,517)

   

   (147,914)

   

   (7,839)Purchases of intangible assets

   

   (1,211,082)

   

   (877,793)

   

   (716,818)Sale of noncurrent assets

   

   -

   

   10,586

   

   43,024Intragroup loans

   

   44,922

   

   29,776

   

   949Repayment of advances to suppliers

   

   -

   

   -

   

   67,342NET CASH USED IN INVESTING ACTIVITIES

   

   (3,815,219)

   

   (1,524,894)

   

   (933,007)FINANCING ACTIVITIESCapital increase by noncontrolling interests

   

   467

   

   7

   

   1,123Borrowings and debentures raised

   

   3,774,355

   

   4,532,167

   

   3,186,384Repayment of principal of borrowings and debentures

   

   (4,016,693)

   

   (4,037,685)

   

   (2,559,771)Repayment of derivatives

   

   158,242

   

   (135,309)

   

   (119,628)Repayment for business combinations

   

   (21,234)

   

   (61,709)

   

   -Dividends and interest on capital paid

   

   (231,749)

   

   (5,204)

   

   (1,016,641)NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES

   

   (336,612)

   

   292,267

   

   (508,533)NET INCREASE IN CASH AND CASH EQUIVALENTS

   

   482,195

   

   1,325,347

   

   151,033CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR

   

   5,682,802

   

   4,357,455

   

   4,206,422CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR

   

   6,164,997

   

   5,682,802

   

   4,357,455
  The accompanying notes are an integral part of these consolidated financial statements   F - 6


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CPFL ENERGIA S.A. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 and 2014 (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 ofSão Paulo

   

   234

   

   4,311

   

   30 years

   

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

   

   Publicly-held corporation

   

   Direct 100%

   

   Interior ofSão Paulo

   

   27

   

   1,695

   

   30 years

   

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

   

   Publicly-held corporation

   

   Direct 100%

   

   Interior ofRio Grande do Sul

   

   255

   

   1,461

   

   30 years

   

   November 2027RGE Sul Distribuidora de Energia S.A. ("RGE Sul") (a)

   

   Publicly-held corporation

   

   Indirect100%

   

   Interior ofRio Grande do Sul

   

   118

   

   1,320

   

   30 years

   

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

   

   Privately-held corporation

   

   Direct 100%

   

   Interior of São Pauloand Paraná

   

   27

   

   209

   

   30 years

   

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

   

   Privately-held corporation

   

   Direct 100%

   

   Interior ofSão Paulo

   

   7

   

   58

   

   30 years

   

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

   

   Privately-held corporation

   

   Direct 100%

   

   Interior ofSão Paulo

   

   2

   

   41

   

   30 years

   

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

   

   Privately-held corporation

   

   Direct 100%

   

   Interior ofSão Paulo

   

   5

   

   85

   

   30 years

   

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

   

   Privately-held corporation

   

   Direct 100%

   

   Interior of São Pauloand Minas Gerais

   

   4

   

   47

   

   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

   

   3 Hydropower plants (b)

   

   1,295

   

   688CERAN - Companhia Energética Rio das Antas ("CERAN")

   

   Privately-held corporation

   

   Indirect65%

   

   Rio Grande do Sul

   

   3 Hydropower plants

   

   360

   

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

   

   Privately-held corporation

   

   Indirect51% (e)

   

   Santa Catarina andRio Grande do Sul

   

   1 Hydropower plant

   

   855

   

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

   

   Privately-held corporation

   

   Indirect48.72%

   

   Santa Catarina

   

   1 Hydropower plant

   

   880

   

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

   

   Publicly-held corporation

   

   Indirect25.01%

   

   Santa Catarina andRio Grande do Sul

   

   1 Hydropower plant

   

   690

   

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

   

   Privately-held corporation

   

   Indirect53.34%

   

   Paraíba

   

   2 Thermal plants

   

   342

   

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

   

   Privately-held corporation

   

   Indirect59.93% (c)

   

   Tocantins

   

   1 Hydropower plant

   

   903

   

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

   

   Publicly-held corporation

   

   Indirect51.60%

   

   (d)

   

   (d)

   

   (d)

   

   (d)CPFL Centrais Geradoras Ltda. ("CPFL Centrais Geradoras")

   

   Limited liability company

   

   Direct 100%

   

   São Paulo and Minas Gerais

   

   6 small hydropower plants

   

   4

   

   4
  F - 7


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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 Brasil Varejista")

   

   Privately-held corporation

   

   Energy commercialization

   

   Indirect 100%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")

   

   Limited liability company

   

   Provision of IT services

   

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

   

   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 ("CPFL Jaguari Geração")

   

   Limited liability company

   

   Holding company

   

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

   

   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 Piracicaba")

   

   Privately-held corporation

   

   Energy transmission services

   

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

   

   Privately-held corporation

   

   Energy transmission services

   

   Indirect 100%
 a)RGE Sul Distribuidora de Energia S.A. (“RGE Sul”) is a publicly-held corporation engaged in providing electricity distribution services in all forms, and these activities are regulated by the Brazilian Electricity Regulatory Agency (“ANEEL”), linked to the Ministry of Mines and Energy. Additionally, RGE Sul is authorized to participate in programs that aim at other forms of energy, technology and services, including exploration of activities directly or indirectly derived from the use of assets, rights and technologies held by it. The CPFL Group took over the control of RGE Sul, formerly named AES Sul Distribuidora Gaúcha S.A., on October 31, 2016.For further details see note 15.3 – acquisition of AES Sul Distribuidora Gaúcha de Energia S.A.  (“AES Sul”). b)CPFL Geração has 51.54% of assured energy and power of the Serra da Mesa hydropower plant, whose concession is owned by Furnas. The small hydropower plant Cariobinha and the thermoelectric plant Carioba are inactive while they await the position of the Ministry of Mines and Energy on the early termination of their concession and are not included in the table. c)Paulista Lajeado has a 7% share in the installed power of Investco S.A. (5.94% interest in total capital). d)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, 2016, CPFL Renováveis had a portfolio of 126 projects with installed capacity of 2,904.1 MW (2,054.3 MW in operation), as follows: ·Hydropower generation: 47 SHP’s (555.3 MW) with39SHPs in operation (423MW) and 8 SHPs under development (132.3 MW);   F - 8


---



·Wind power generation: 70 projects (1,977.7 MW) with 43projects in operation (1,260.2MW) and 27projects under construction/development (717.5 MW); ·Biomass power generation: 8 plants in operation (370MW); ·Solar power generation:1solar plant in operation (1.1MW). e)The joint venture Chapecoense has as its direct subsidiary Foz do Chapecó and fully consolidates its financial statements. ( 2 )PRESENTATION OF THE CONSOLIDATED 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 17, 2017. 2.2 Basis of measurement The consolidated 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 consolidated 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 9 – Deferred tax assets and liabilities; ·Note 11 – Concession Financial Asset ·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 27 – Net operating revenue; 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.   F - 9


---



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 use 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, further details see note 31. 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, 2016 and 2015, the noncontrolling interests recognized in the financial statements refer to the interests held by third parties in subsidiaries CERAN, Paulista Lajeado and CPFL Renováveis.  2.7 Restatements in the 2015 and 2014 financial statements The Company and its energy distribution subsidiaries, for a better presentation of their operating and financial performance, concluded that the adjustment of the expected cash flow of the indemnifiable concession financial asset of the distribution subsidiaries, originally presented in the line item of finance income, with in finance income (costs), could be more properly classified in the group of Net Operating Revenue, together with the other income related to their core activity. This allocation reflects more accurately the energy distribution business model and allows a better presentation regarding the performance. This conclusion is based on the fact that:   i.

   Investing in infrastructure is an essential activity of the electricity distribution business whose model is to construct, maintain and operate this infrastructure;ii.

   Most players in distribution activity, as well as Transmission companies, have already adopted such classification, which improves comparability of financial statements among industry companies;iii.

   Increase of inflation rates observed over the past few years has contributed to the rise of Concession Financial Asset’s carrying amount, which has contributed for the increasing relevance of such income in company’s consolidated income statement.  According to the guidance in IAS 8 – Accounting Policies, Changes in Accounting Estimates and Errors, the Company and its subsidiaries changed their accounting policy and made the retrospective reclassifications in their statements of profit or loss, originally issued on April 8, 2016. The reclassifications made do not change the total assets, equity, profit and cash flows for the year. For comparability purposes, these reclassifications are presented below: ·Statement of Profit or Loss   F - 10


---



2015

   

   Reclassifications

   

   2015(Restated)

   

   2014

   

   Reclassifications

   

   2014(Restated)NET OPERATING REVENUE

   

   20,205,869

   

   393,343

   

   20,599,212

   

   17,305,942

   

   93,254

   

   17,399,196COST OF ELECTRIC ENERGY SERVICESCost of electric energy

   

   (13,311,747)

   

   

   

   (13,311,747)

   

   (10,643,130)

   

   

   

   (10,643,130)Cost of operation

   

   (1,907,197)

   

   

   

   (1,907,197)

   

   (1,672,359)

   

   

   

   (1,672,359)Cost of services rendered to third parties

   

   (1,049,101)

   

   

   

   (1,049,101)

   

   (946,052)

   

   

   

   (946,052)GROSS PROFIT

   

   3,937,825

   

   393,343

   

   4,331,168

   

   4,044,401

   

   93,254

   

   4,137,655Operating expensesSales expenses

   

   (464,583)

   

   

   

   (464,583)

   

   (402,698)

   

   

   

   (402,698)General and administrative expenses

   

   (863,499)

   

   

   

   (863,499)

   

   (773,630)

   

   

   

   (773,630)Other Operating Expense

   

   (357,653)

   

   

   

   (357,653)

   

   (328,000)

   

   

   

   (328,000)INCOME FROM ELECTRIC ENERGY SERVICES

   

   2,252,090

   

   393,343

   

   2,645,433

   

   2,540,073

   

   93,254

   

   2,633,327Equity interests in associates and joint ventures

   

   216,885

   

   

   

   216,885

   

   59,684

   

   

   

   59,684FINANCE INCOME (COSTS)Finance income

   

   1,558,047

   

   (414,800)

   

   1,143,247

   

   890,436

   

   (104,642)

   

   785,794Finance costs

   

   (2,572,567)

   

   21,457

   

   (2,551,110)

   

   (1,979,890)

   

   11,388

   

   (1,968,502)(1,014,520)

   

   (393,343)

   

   (1,407,863)

   

   (1,089,454)

   

   (93,254)

   

   (1,182,708)PROFIT BEFORE TAXES

   

   1,454,454

   

   -

   

   1,454,454

   

   1,510,303

   

   -

   

   1,510,303Social contribution

   

   (160,162)

   

   

   

   (160,162)

   

   (168,989)

   

   

   

   (168,989)Income tax

   

   (419,015)

   

   

   

   (419,015)

   

   (454,871)

   

   

   

   (454,871)(579,177)

   

   -

   

   (579,177)

   

   (623,860)

   

   -

   

   (623,860)PROFIT FOR THE YEAR

   

   875,277

   

   -

   

   875,277

   

   886,443

   

   -

   

   886,443
 ( 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 The 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. 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 distribution subsidiaries. The financial asset is classified as available-for-sale, with the corresponding cash flow changes entry in the Net Operating Revenue in the statement of profit or loss for the year (notes 2.7 and 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.   F - 11


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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 Operating  Revenue for the variations on the expected cash flows of distribution companies, and 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. 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 36.   F - 12


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- 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, recorded in Net Operating Revenues. In both cases, the 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. 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.   F - 13


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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, up to December 31, 2015, 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. Effective January 1, 2016, in compliance with the amendments to IAS 16 and to IAS 38, the Company adopted prospectively, for all cases, the straight-line amortization method over the remaining concession period. Accordingly, for 2016, the expense relating to the amortization of the concession intangible asset decreased by R$ 24,627; 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. 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.   F - 14


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- 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 (i) its value in use and (ii) 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. 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.   F - 15


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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 The operating revenue in the normal course of the subsidiaries’ activities is measured at the fair value of the consideration received or receivable. The operating revenue is recognized when there is persuasive evidence that all significant risks and rewards were transferred to the buyer, it is probable that future economic benefits will flow to the entity, the associated costs can be reliably measured, and the amount of the operating revenue can be reliably measured. The revenue from electric energy distribution is recognized when the energy is supplied. The energy distribution subsidiaries perform the reading of their customers based on a reading routine (calendar and reading route) and invoice monthly the consumption of MWh based on the reading performed for each consumer. As a result, part of the energy distributed during the month is not billed at the end of the month and, consequently, an estimate is developed by Management and recorded as “Unbilled”. This unbilled revenue estimate is calculated using as a base the total volume of energy of each distributor made available in the month and the annualized rate of technical and commercial losses. The revenue from energy generation sales is recognized based on the assured energy and at tariffs specified in the terms of the supply contracts or the current market price, as appropriate. The revenue from energy trading is recognized based on bilateral contracts with market agents and properly registered with the Electric Energy Trading Chamber – CCEE. No single consumer accounts for 10% or more of the Company’s total revenue. The revenue from services provided is recognized when the service is provided, under a service agreement between the parties. The 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 on a straight line basis for the remaining period of each concession agreement. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to 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)   F - 16


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Government grants are only recognized when it is reasonably certain that these amounts will be received by the Company and its subsidiaries. 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. The subsidies received through funds from the CDE (notes 27) have the main purpose of offsetting discounts granted 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 temporary 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. 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. At the acquisition date, assets and liabilities are recognized at fair value, except for: (i) deferred taxes, (ii) employee benefits and (iii) equity instruments. 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 noncontrolling 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   F - 17


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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, CPFL Renováveis and CPFL ESCO 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 issued and effective A number of IASB standards were issued or revised and are mandatory for accounting periods beginning on January 1, 2016: a) 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. Considering that the Company and its subsidiaries are not first-time adopters of IFRS, IFRS 14 was not applicable to the group. b) 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. The application of the amendments to IFRS 11 did not have material impacts on the Company’s consolidated financial statements for the year ended December 31, 2016 since there were no acquisitions of joint ventures during the year. Should these transactions occur, there may be impacts on the consolidated financial statements in future periods. c) Amendments to IAS 16 and IAS 38 - Clarification of acceptable methods of depreciation and amortization The amendments to IAS 16 prohibit the use of the revenue based depreciation method 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:   F - 18


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(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. With the beginning of the effective period of the amendments, the Company started adopting prospectively the straight-line amortization method for the concession intangible asset, over the remaining concession period. As a result of such amendment the Company experienced a reduction in the amortization expense by R$ 24,627 in 2016. d) Amendments to IAS 1 – Disclosure Initiatives The amendments to IAS 1 provide guidance as regards the application of the concept of materiality in practice. The application of the amendments to IAS 1 did not have material impacts on the disclosures or amounts recognized in the Company’s consolidated financial statements for the year ended December 31, 2016. e) Amendments to IAS 27 – Equity Method in Separate Financial Statements The amendments deal with the permitted methods to account for investments in subsidiaries, joint ventures and associates in separate financial statements. Considering that the Company does not prepare consolidated financial statements, the application of the amendments to IAS 27 did not have impacts on its financial statements for the year ended December 31, 2016. f) 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. The application of the amendments to IFRS 10 and IAS 28 did not have material impacts on the Company’s consolidated financial statements for the year ended December 31, 2016 since there were no sales or contributions of assets between the Company and its subsidiaries, associates or joint ventures during the year. Should these transactions occur, there may be impacts on the consolidated financial statements in future periods. g) Amendments to IFRS 10, IFRS 12 and IAS 28 – Investment Entities: Applying the Consolidation Exception The amendments to IFRS 10, IFRS 12 and IAS 28 bring clarifications about exemption from preparing consolidated financial statements for entities whose subsidiary is an investment entity. Considering that the Company is not an investment entity and it does not have a subsidiary, associate or joint venture that qualifies as an investment entity, the application of the amendments to IFRS 10, IFRS 12 and IAS 28 did not have material impact on its consolidated financial statements for the year ended December 31, 2016. h) Annual Improvements to IFRSs 2012 – 2014 Cycle The application of the amendments did not have material impacts on the disclosures and amounts recognized in the Company’s consolidated financial statements for the year ended December 31, 2016. 3.18 New standards and interpretations issued but not yet effective 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, 2016. 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.   F - 19


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This standard establishes new requirements for classification and measurement of financial assets and liabilities. Financial assets are classified into three categories: (i) measured at fair value through profit or loss; and (ii) measured at amortized cost, based on the business model within which they are held and the characteristics of their contractual cash flows; and; (iii) measured at fair value through other comprehensive income. 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. 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 potential impacts of the adoption of this standard. b) 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: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract and (v) 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.  c) 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.   F - 20


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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. d)Amendments to IAS 12 – Recognition of deferred tax assets for unrealized losses Issued on January 19, 2016, the amendments to IAS 12 clarify the requirements for recognition of deferred tax assets for unrealized losses on debt instruments and the method to assess the existence of probable future taxable profits for the realization of deductible temporary differences, to address the diversity in practice. The amendments to IAS 12 are effective for annual periods beginning on or after January 1, 2017 with earlier application permitted. The Company’s management believes that the application of the amendments to IAS 12 tends not to cause material impacts on its consolidated financial statements. e)Amendments to IAS 7 – Disclosure initiative Issued on January 29, 2016, the amendments to IAS 7 Disclosure Initiative require an entity to provide disclosures that enable users of financial statements to evaluate changes in liabilities arising from financing activities. For this, the IASB requires the disclosure of the following changes in liabilities arising from financing activities: (i) changes in cash flows from financing activities; (ii) changes arising from obtaining or losing control of subsidiaries or other businesses; (iii) effect of exchange rate changes; (iv) changes in fair values; and (v) other changes. The IASB defines liabilities arising from financing activities as liabilities "for which cash flows have been, or will be, classified in the Statements of Cash Flows as cash flows from financing activities ". It also emphasizes that the new disclosure requirements refer similarly to changes in financial assets, if they meet the same definition. Finally, the amendments indicate that the changes in liabilities arising from financing activities should be disclosed separately from changes in other assets and liabilities. The amendments to IAS 7 are effective for annual periods beginning on or after January 1, 2017 with earlier application permitted. As the amendments were disclosed in a period of time shorter than one year before the mandatory period of application, entities are not required to present comparative information on the early application of the amendments. The Company’s management believes that the application of the amendments to IAS 7 will result in changes in the classification of amounts of the company’s statements of cash flows for future periods, without other material impacts on its consolidated financial statements. f)Amendments to IFRS 2 – Classification and measurement of share-based payment transactions Issued on June 20, 2016, the amendments provide requirements to account for: a)Effects of vesting and non-vesting conditions in the measurement of cash-settled share-based payments; b)Share-based payment transactions with a net settlement feature, for withholding obligations; and c)A modification in the terms and conditions of a share-based payment that changes the transaction from cash-settled to equity-settled. The amendments to IFRS 12 are effective for annual periods beginning on or after January 1, 2018 with early application permitted. The Company is assessing the potential impacts of the adoption of these amendments. g)Amendments to IFRS 4 – Application of IFRS 9 – Financial instruments with IFRS 4 – Insurance contracts Issued on September 12, 2016, the amendments deal with concerns arising from the implementation of IFRS 9 – Financial Instruments before the implementation of the new standard that will replace IFRS 4, for potential temporary volatilities in the reported results. As the Company does not apply the insurance standard, the Company’s management believes that the amendments to IFRS 4 will not have impacts on its consolidated financial statements.  h)IFRIC 22 – Transactions and advances in foreign currency   F - 21


---



Issued on December 8, 2016, IFRIC 22 deals with the exchange rate to be used in transactions involving the consideration paid or received in advance in transactions in foreign currency. The IFRIC is effective for annual periods beginning on or after January 1, 2018 with early application permitted. The transactions in foreign currency of the Company and its subsidiaries are currently restricted to debt instruments with international financial institutions, measured at fair value, and the purchase of Itaipu energy. As the assets and liabilities measured at fair value are not within the scope of the IFRIC and there are no advance payments on Itaipu transactions, the Company’s management believes that IFRIC 22 will not have material impacts on its consolidated financial statements. i)Amendments to IAS 40 – Investment property Issued on December 8, 2016, the amendments to IAS 40 clarify the requirements relating to transfers from or to investment property.  The amendments are effective for annual periods beginning on or after January 1, 2018 with early application permitted. The Company’s management believes that the amendments will not have material impacts on its consolidated financial statements. j)Annual Improvements to IFRSs 2014 – 2016 Cycle Annually IASB discusses and decides on the proposed improvements to IFRS, as they arise during the year. Issued on December 8, 2016, the improvements are related to: j.1)   Amendments to IFRS 1 – Early application of IFRS: excludes from the standard some exceptions existing for application in the transition period of entities recently adopters of IFRS. j.2)   Amendments to IFRS 12 – Disclosure of interests in other entities: clarifies the scope of the standard as regards the interests of entities in other entities that are classified as available for sale or discontinued operations in accordance with IFRS 5. j.3)  Amendments to IAS 28 – Investments in Associates and Joint Ventures: clarifies if an entity has an "investment by investment" option to measure investees at fair value in accordance with IAS 28 by a risk capital organization. Based on the preliminary assessment, the Company’s management believes that the application of these amendments will not have a material impact on the disclosures and amounts recognized in its consolidated financial statements.  ( 4 )DETERMINATION OF FAIR VALUES
 A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and / or disclosure purposes based on the following methods. When applicable, further information 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 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.   F - 22


---



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 distribution concessionaire adjusts the position of the financial asset base for compensation at the amounts ratified by the granting authority and uses the IPCA 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, 2016

   

   Dec 31, 2015Bank balances

   170,884

   

   148,224Short-term financial investments

   5,994,112

   

   5,534,578Overnight investment (a)

   95,034

   

   26,914Bank certificates of deposit (b)

   2,357,187

   

   1,255,666Repurchase agreements secured on debentures (b)

   58,616

   

   433,693Investment funds (c)

   3,483,274

   

   3,818,305Total

   6,164,997

   

   5,682,802
  (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 101.7% of the CDI. (c)Exclusive Fund investments, with daily liquidity and interest equivalent, on average, of 100.4% 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, 2016 and 2015:   F - 23


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Amounts coming due

   

   Past due

   

   Totaluntil 90 days

   

   > 90 days

   

   Dec 31, 2016

   

   Dec 31, 2015CurrentConsumer classesResidential

   423,499

   

   429,169

   

   79,711

   

   932,380

   

   793,826Industrial

   222,168

   

   83,207

   

   81,451

   

   386,826

   

   365,420Commercial

   178,567

   

   88,230

   

   50,314

   

   317,111

   

   263,259Rural

   67,575

   

   21,850

   

   8,019

   

   97,444

   

   64,257Public administration

   64,009

   

   24,064

   

   6,275

   

   94,348

   

   79,953Public lighting

   57,049

   

   10,287

   

   5,805

   

   73,142

   

   78,204Public utilities

   74,792

   

   15,752

   

   6,959

   

   97,503

   

   80,706Billed

   1,087,660

   

   672,559

   

   238,534

   

   1,998,754

   

   1,725,626Unbilled

   1,095,188

   

   -

   

   -

   

   1,095,188

   

   881,307Financing of consumers' debts

   118,357

   

   20,792

   

   31,834

   

   170,982

   

   197,035CCEE transactions

   194,177

   

   4,619

   

   90,964

   

   289,761

   

   169,561Concessionaires and licensees

   381,982

   

   678

   

   7,673

   

   390,333

   

   331,105Others

   39,974

   

   -

   

   -

   

   39,974

   

   10,7702,917,338

   

   698,648

   

   369,005

   

   3,984,991

   

   3,315,403Allowance for doubtful accounts

   

   

   

   

   

   

   (219,098)

   

   (140,485)Total

   

   

   

   

   

   

   3,765,893

   

   3,174,918NoncurrentFinancing of consumers' debts

   198,875

   

   -

   

   -

   

   198,875

   

   101,585Free Energy

   5,436

   

   -

   

   -

   

   5,436

   

   4,768CCEE transactions

   41,301

   

   -

   

   -

   

   41,301

   

   41,301245,612

   

   -

   

   -

   

   245,612

   

   147,654Allowance for doubtful accounts

   

   

   

   

   

   

   (42,427)

   

   (18,708)Total

   

   

   

   

   

   

   203,185

   

   128,946
  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 accounts 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 accounts Movements in the allowance for doubtful accounts are shown below:   F - 24


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Consumers, concessionaires and licensees

   

   Otherreceivables(note 12)

   

   TotalAs of December 31, 2013

   (133,247)

   

   (13,152)

   

   (146,399)Allowance - reversal (recognition)

   (129,482)

   

   (3,444)

   

   (132,925)Recovery of revenue

   49,363

   

   (136)

   

   49,227Write-off of accrued receivables

   90,196

   

   1,446

   

   91,642As of December 31, 2014

   (123,171)

   

   (15,285)

   

   (138,456)Allowance - reversal (recognition)

   (170,131)

   

   (1,152)

   

   (171,283)Recovery of revenue

   44,338

   

   67

   

   44,405Write-off of accrued receivables

   89,770

   

   1,930

   

   91,700As of December 31, 2015

   (159,194)

   

   (14,441)

   

   (173,634)Business combination

   (70,636)

   

   (16,187)

   

   (86,823)Allowance - reversal (recognition)

   (258,377)

   

   (969)

   

   (259,347)Recovery of revenue

   82,393

   

   605

   

   82,998Write-off of accrued receivables

   144,289

   

   3,000

   

   147,289As of December 31, 2016

   (261,525)

   

   (27,992)

   

   (289,517)Current

   (219,098)

   

   (27,992)

   

   (247,090)Noncurrent

   (42,427)

   

   -

   

   (42,427)
  ( 7 )TAXES RECOVERABLE
  Dec 31, 2016

   

   Dec 31, 2015CurrentPrepayments of social contribution - CSLL

   14,141

   

   35,019Prepayments of income tax - IRPJ

   35,534

   

   76,920Withholding income tax - IRRF on interest on capital

   3,642

   

   11,150Income tax and social contribution to be offset

   94,268

   

   100,658Withholding income tax - IRRF

   115,189

   

   125,392State VAT - ICMS to be offset

   82,090

   

   63,450Social Integration Program - PIS

   9,062

   

   8,543Contribution for Social Security Funding - COFINS

   39,984

   

   40,126National Social Security Institute - INSS

   6,374

   

   12,660Others

   3,564

   

   1,292Total

   403,848

   

   475,211NoncurrentSocial contribution to be offset - CSLL

   55,498

   

   57,439Income tax to be offset - IRPJ

   10,037

   

   23,765State VAT - ICMS to be offset

   122,415

   

   81,584Social Integration Program - PIS

   800

   

   350Contribution for Social Security Funding - COFINS

   3,687

   

   1,613Others

   5,849

   

   2,409Total

   198,286

   

   167,159
 Withholding income tax - IRRF– relates mainly to IRRF on financial investments. Social contribution to be offset – CSLL– In noncurrent, refers basically to the final unappealable favorable decision in a lawsuit filed by the subsidiary CPFL Paulista. The subsidiary CPFL Paulista is awaiting the authorization for utilization of credit from the Federal Revenue in order to carry out its subsequent offset. 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.  F - 25


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( 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:   As of December 31, 2015

   

   Operating revenue

   

   Finance income/cost

   

   Receipt

   

   

   

   As of December 31, 2016Deferred

   

   Approved

   

   Total

   

   Constitution

   

   Through billing

   

   Monetary adjustment

   

   Tariff flag(note 27.5)

   

   Business Combination

   

   Deferred

   

   Approved

   

   TotalParcel "A"

   1,490,744

   

   519,838

   

   2,010,582

   

   (644,484)

   

   (1,260,579)

   

   28,166

   

   (687,673)

   

   (18,213)

   

   (762,573)

   

   190,369

   

   (572,203)CVA (*)CDE (**)

   407,295

   

   109,937

   

   517,232

   

   (612,336)

   

   (329,898)

   

   (4,020)

   

   -

   

   16,561

   

   (342,161)

   

   (70,301)

   

   (412,462)Electric energy cost

   (466,337)

   

   472,428

   

   6,091

   

   81,164

   

   (179,617)

   

   (101,982)

   

   (417,883)

   

   (134,041)

   

   (506,490)

   

   (239,777)

   

   (746,267)ESS and EER (***)

   (25,128)

   

   (249,081)

   

   (274,209)

   

   (225,794)

   

   385,941

   

   (56,038)

   

   (269,352)

   

   (91,527)

   

   (406,568)

   

   (124,411)

   

   (530,979)Proinfa

   (814)

   

   (5,334)

   

   (6,148)

   

   51,060

   

   (19,335)

   

   7,219

   

   -

   

   2,111

   

   3,492

   

   31,414

   

   34,906Basic network charges

   28,185

   

   68,289

   

   96,474

   

   19,517

   

   (84,894)

   

   (1,449)

   

   -

   

   7,539

   

   27,527

   

   9,660

   

   37,187Pass-through from Itaipu

   1,281,279

   

   39,416

   

   1,320,695

   

   (116,276)

   

   (921,201)

   

   197,581

   

   -

   

   109,124

   

   147,012

   

   442,911

   

   589,923Transmission from Itaipu

   11,372

   

   4,097

   

   15,469

   

   8,102

   

   (13,754)

   

   2,163

   

   -

   

   2,948

   

   7,646

   

   7,281

   

   14,927Neutrality of industry charges

   187,765

   

   2,508

   

   190,273

   

   198,274

   

   (171,420)

   

   15,730

   

   -

   

   73,609

   

   142,091

   

   164,375

   

   306,466Overcontracting

   67,127

   

   77,578

   

   144,705

   

   (48,195)

   

   73,600

   

   (31,037)

   

   (439)

   

   (4,537)

   

   164,878

   

   (30,782)

   

   134,096Other financial components

   (92,098)

   

   35,480

   

   (56,618)

   

   (195,758)

   

   6,126

   

   (20,498)

   

   -

   

   (75,968)

   

   (182,958)

   

   (159,759)

   

   (342,717)Refunds related to judicial injuctions (note 27.4)

   -

   

   -

   

   -

   

   (223,356)

   

   31,419

   

   (17,088)

   

   -

   

   -

   

   (76,615)

   

   (132,410)

   

   (209,025)Others

   (92,098)

   

   35,480

   

   (56,618)

   

   27,598

   

   (25,294)

   

   (3,410)

   

   -

   

   (75,968)

   

   (106,343)

   

   (27,349)

   

   (133,692)Total

   1,398,646

   

   555,318

   

   1,953,964

   

   (840,241)

   

   (1,254,453)

   

   7,668

   

   (687,673)

   

   (94,181)

   

   (945,530)

   

   30,612

   

   (914,918)Current assets

   

   

   

   

   1,464,019

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   -Noncurrent assets

   

   

   

   

   489,945

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   -Current liabilities

   

   

   

   

   -

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   (597,515)Noncurrent liabilities

   

   

   

   

   -

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   

   (317,406)
  As of December 31, 2014

   

   Operating revenue

   

   Finance income/cost

   

   Receipt

   

   As of December 31, 2015Deferred

   

   Approved

   

   Total

   

   Constitution

   

   Through billing

   

   Monetary adjustment

   

   Tariff flag(note 27.5)

   

   Through CCEE

   

   Deferred

   

   Approved

   

   TotalParcel "A"

   906,018

   

   216,436

   

   1,122,453

   

   2,981,253

   

   (634,409)

   

   165,776

   

   (1,297,717)

   

   (326,776)

   

   1,490,744

   

   519,838

   

   2,010,582CVA (*)CCC (****)

   -

   

   58

   

   58

   

   2

   

   (61)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -CDE (**)

   34,765

   

   18,432

   

   53,198

   

   517,380

   

   (85,775)

   

   32,430

   

   -

   

   -

   

   407,295

   

   109,937

   

   517,232Electric energy cost

   965,339

   

   282,826

   

   1,248,165

   

   423,879

   

   (892,002)

   

   115,593

   

   (827,974)

   

   (61,571)

   

   (466,337)

   

   472,428

   

   6,091ESS and EER (***)

   (536,082)

   

   (86,161)

   

   (622,243)

   

   244,334

   

   445,537

   

   (65,701)

   

   (276,136)

   

   -

   

   (25,128)

   

   (249,081)

   

   (274,209)Proinfa

   1,112

   

   8,137

   

   9,249

   

   (9,485)

   

   (5,297)

   

   (615)

   

   -

   

   -

   

   (814)

   

   (5,334)

   

   (6,148)Basic network charges

   130,446

   

   24,148

   

   154,593

   

   47,847

   

   (128,988)

   

   23,021

   

   -

   

   -

   

   28,185

   

   68,289

   

   96,474Pass-through from Itaipu

   (231,683)

   

   (78,044)

   

   (309,727)

   

   1,420,055

   

   171,606

   

   38,760

   

   -

   

   -

   

   1,281,279

   

   39,416

   

   1,320,695Transmission from Itaipu

   3,204

   

   872

   

   4,076

   

   14,603

   

   (4,234)

   

   1,025

   

   -

   

   -

   

   11,372

   

   4,097

   

   15,469Neutrality of industry charges

   (1,561)

   

   (10,777)

   

   (12,338)

   

   176,463

   

   16,453

   

   9,695

   

   -

   

   -

   

   187,765

   

   2,508

   

   190,273Overcontracting

   540,478

   

   56,945

   

   597,422

   

   146,174

   

   (151,648)

   

   11,568

   

   (193,607)

   

   (265,205)

   

   67,127

   

   77,578

   

   144,705Other financial components

   (199,574)

   

   (12,161)

   

   (211,735)

   

   95,608

   

   64,072

   

   (4,563)

   

   -

   

   -

   

   (92,098)

   

   35,480

   

   (56,618)Total

   706,444

   

   204,275

   

   910,720

   

   3,076,861

   

   (570,337)

   

   161,213

   

   (1,297,717)

   

   (326,776)

   

   1,398,646

   

   555,318

   

   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(**) Energy Development Account – CDE(***) System Service Charge (ESS) and Reserve Energy Charge (EER)(****) Fuel Consumption Account – CCC
 **** 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   F - 26


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Refers mainly to: (i) excess demand and excess reactive power that, from the 4th cycle of periodic tariff review, became a financial component that will only be amortized upon the approval of the 5th cycle of periodic tariff review, for subsidiaries CPFL Piratininga, CPFL Santa Cruz, CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista, CPFL Mococa (ii) financial guarantees related to the compensation of the cost of the previous offering of guarantees required from distributors for carrying out commercial transactions among the industry’s agents, (iii) financial components related to the recalculations of the tariff processes, to neutralize the effects to consumers, and (iv)  Abrace judicial injunction in accordance with Order No. 1.576/2016.  ( 9 )DEFERRED TAX ASSETS AND LIABILITIES
 9.1- Breakdown of tax assets and liabilities  Dec 31, 2016

   

   Dec 31, 2015Social contribution credit (debit)Tax losses carryforwards

   123,389

   

   152,200Tax benefit of merged goodwill

   86,377

   

   93,467Temporarily nondeductible differences

   (332,750)

   

   (547,066)Subtotal

   (122,984)

   

   (301,399)Income tax credit (debit)Tax losses carryforwards

   358,683

   

   417,600Tax benefit of merged goodwill

   295,987

   

   323,421Temporarily nondeductible differences

   (923,383)

   

   (1,519,170)Subtotal

   (268,713)

   

   (778,150)PIS and COFINS credit (debit)Temporarily nondeductible differences

   (9,580)

   

   (18,159)Total

   (401,276)

   

   (1,097,708)Total tax credit

   922,858

   

   334,886Total tax debit

   (1,324,134)

   

   (1,432,594)
 9.2 - Tax benefit of merged intangible asset Refers to the tax asset calculated on the intangible 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 intangible that gave rise to it, during the remaining concessions period, as shown in note 15.  December 31, 2016

   

   December 31, 2015Social contribution

   

   Income tax

   

   Social contribution

   

   Income taxCPFL Paulista

   50,497

   

   140,270

   

   55,123

   

   153,119CPFL Piratininga

   12,251

   

   42,044

   

   13,286

   

   45,597RGE

   23,629

   

   97,584

   

   25,058

   

   106,324CPFL Geração

   -

   

   16,090

   

   -

   

   18,380Total

   86,377

   

   295,987

   

   93,467

   

   323,422
    F - 27


---



9.3 - Accumulated balances of nondeductible temporary differences  December 31, 2016

   

   December 31, 2015Social contribution

   

   Income tax

   

   PIS/COFINS

   

   Social contribution

   

   Income tax

   

   PIS/COFINSTemporarily nondeductible differencesProvision for tax, civil and labor risks

   45,065

   

   125,182

   

   -

   

   33,806

   

   93,906

   

   -Private pension fund

   1,711

   

   4,753

   

   -

   

   1,867

   

   5,185

   

   -Allowance for doubtful debts

   26,543

   

   73,729

   

   -

   

   15,680

   

   43,556

   

   -Free energy supply

   7,718

   

   21,440

   

   -

   

   6,897

   

   19,158

   

   -Research and development and energy efficiency programs

   17,474

   

   48,538

   

   -

   

   16,060

   

   44,612

   

   -Personnel-related provisions

   3,422

   

   9,506

   

   -

   

   2,578

   

   7,161

   

   -Depreciation rate difference

   6,200

   

   17,223

   

   -

   

   6,797

   

   18,880

   

   -Derivatives

   (54,368)

   

   (151,023)

   

   -

   

   (219,524)

   

   (609,788)

   

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

   (8,355)

   

   (23,208)

   

   -

   

   (9,031)

   

   (25,085)

   

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

   (104,080)

   

   (287,990)

   

   (6,157)

   

   (73,241)

   

   (202,271)

   

   (18,450)Actuarial losses (IFRS/CPC)

   25,390

   

   70,527

   

   -

   

   26,351

   

   73,199

   

   -Financial instruments (IFRS/CPC)

   (10,022)

   

   (27,838)

   

   -

   

   (8,950)

   

   (24,860)

   

   -Accelerated depreciation

   (73)

   

   (204)

   

   -

   

   (34)

   

   (95)

   

   -Others

   4,491

   

   12,281

   

   (3,423)

   

   4,236

   

   11,054

   

   291Temporarily nondeductible differences - accumulated comprehensive income:Property, plant and equipment - adjustment of deemed cost (IFRS/CPC)

   (55,223)

   

   (153,398)

   

   -

   

   (58,484)

   

   (162,456)

   

   -Actuarial losses (IFRS/CPC)

   49,698

   

   138,051

   

   -

   

   10,464

   

   29,064

   

   -Temporarily nondeductible differences - Business combination - CPFL RenováveisDeferred taxes - asset:Fair value of property, plant and equipment (negative value added of assets)

   22,771

   

   63,252

   

   -

   

   24,248

   

   67,355

   

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

   (27,472)

   

   (76,310)

   

   -

   

   (29,132)

   

   (80,922)

   

   -Value added derived from determination of deemed cost

   (78,443)

   

   (217,897)

   

   -

   

   (86,495)

   

   (240,264)

   

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

   (183,443)

   

   (509,563)

   

   -

   

   (193,927)

   

   (538,685)

   

   -Other temporary differences

   (21,754)

   

   (60,435)

   

   -

   

   (17,233)

   

   (47,874)

   

   -Total

   (332,750)

   

   (923,383)

   

   (9,580)

   

   (547,066)

   

   (1,519,171)

   

   (18,159)
  9.4 - Reconciliation of the income tax and social contribution amounts recognized in the statements of income for the years ended December 31, 2016, 2015 and 2014
  2016

   

   2015

   

   2014Social contribution

   

   Income tax

   

   Social contribution

   

   Income tax

   

   Social contribution

   

   Income taxProfit before taxes

   1,380,547

   

   1,380,547

   

   1,454,454

   

   1,454,454

   

   1,510,304

   

   1,510,304Reconciliation to reflect effective rate:Equity interest in associates and joint ventures

   (311,414)

   

   (311,414)

   

   (216,885)

   

   (216,885)

   

   (59,684)

   

   (59,684)Amortization of intangible asset acquired

   48,649

   

   62,756

   

   84,484

   

   108,797

   

   93,116

   

   119,477Tax incentives - PIIT (*)

   (7,820)

   

   (7,820)

   

   -

   

   -

   

   (10,914)

   

   (10,914)Effect of presumed profit regime (**)

   (175,110)

   

   (234,827)

   

   (186,546)

   

   (244,541)

   

   17,467

   

   (25,827)Adjustment of revenue from excess demand and excess reactive power

   119,272

   

   119,272

   

   117,374

   

   117,374

   

   102,062

   

   102,062Tax incentive - operating profit

   -

   

   (112,232)

   

   -

   

   (85,760)

   

   -

   

   (71,380)Other permanent additions (exclusions), net

   14,240

   

   (16,243)

   

   42,310

   

   59,450

   

   56,652

   

   (1,661)Tax base

   1,068,364

   

   880,040

   

   1,295,193

   

   1,192,890

   

   1,709,002

   

   1,562,375Statutory rate

   9%

   

   25%

   

   9%

   

   25%

   

   9%

   

   25%Tax credit (debit)

   (96,153)

   

   (220,010)

   

   (116,567)

   

   (298,223)

   

   (153,810)

   

   (390,594)Recognized (unrecognized) tax credit, net

   (54,706)

   

   (130,621)

   

   (43,595)

   

   (120,792)

   

   (15,179)

   

   (64,277)Total

   (150,859)

   

   (350,631)

   

   (160,162)

   

   (419,015)

   

   (168,989)

   

   (454,871)Current

   (244,015)

   

   (623,183)

   

   (10,916)

   

   (1,944)

   

   (135,421)

   

   (330,600)Deferred

   93,156

   

   272,552

   

   (149,246)

   

   (417,071)

   

   (33,568)

   

   (124,272) (*) Technologic innovation program
 (**) in the ordinary regime, taxes are calculated based on the profit, net of certain costs and expenses. Taxes calculated by presumed profit uses a profit presumption established by law.  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.  9.5 Income tax and social contribution amounts recognized in equity   F - 28


---



The deferred income tax and social contribution recognized directly in equity (other comprehensive income) in 2016, 2015 and 2014 were as follows:   2016

   

   2015

   

   2014Social Contribution

   

   Income tax

   

   Social Contribution

   

   Income tax

   

   Social Contribution

   

   Income taxActuarial losses (gains)

   527,436

   

   527,436

   

   (84,635)

   

   (84,635)

   

   247,040

   

   247,040Limits on the asset ceiling

   (8,738)

   

   (8,738)

   

   7,984

   

   7,984

   

   -

   

   -Basis of calculation

   518,698

   

   518,698

   

   (76,651)

   

   (76,651)

   

   247,040

   

   247,040Statutory rate

   9%

   

   25%

   

   9%

   

   25%

   

   9%

   

   25%Calculated taxes

   (46,683)

   

   (129,675)

   

   6,899

   

   19,163

   

   (22,234)

   

   (61,760)Limitation on recognition (reversal) of tax credits

   13,720

   

   38,112

   

   (3,959)

   

   (10,998)

   

   16,590

   

   46,081Taxes recognized in other comprehensive income

   (32,962)

   

   (91,562)

   

   2,940

   

   8,165

   

   (5,644)

   

   (15,679)
  9.6 Unrecognized deferred tax assets As of December 31, 2016, the parent company has tax credits on tax loss carryforwards that were not recognized amounting to R$ 85,717 since currently there is not probable that taxable profits will be available in the future. This amount can be recognized in the future, according to the annual reviews of taxable profit projections. 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, 2016, the main subsidiaries that have such income tax and social contribution credits are CPFL Renováveis (R$ 785,660), RGE Sul (R$272,820), Sul Geradora (R$ 72,596), CPFL Telecom (R$ 34,783), CPFL Jaguariúna (R$2,777) and CPFL Jaguari Geração (R$ 1,648). 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 ESCO 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 2016 these investments resulted in an operational revenue of R$17,156 (R$11,164 in 2015 an R$10,683 in 2014).  Dec 31, 2016

   

   Dec 31, 2015Gross investment

   132,930

   

   83,854Unrealized finance income

   (63,108)

   

   (36,466)Present value of minimum lease payments

   69,822

   

   47,388Current

   19,281

   

   12,883Noncurrent

   50,541

   

   34,504Up to 1 year

   

   1 to 5 years

   

   Over 5 years

   

   TotalGross investment

   27,455

   

   59,640

   

   45,835

   

   132,930Present value of minimum lease payments

   19,281

   

   33,094

   

   17,447

   

   69,822
   F - 29


---



At December 31, 2016, there are no (i) unsecured residual values that benefit the lessor; (ii) provision for uncollectible minimum lease payments; (iii) contingent payments recognized as revenue during the period nor (iv) no provision for impairment is required.  ( 11 )CONCESSION FINANCIAL ASSET
  Distribution

   

   Transmission

   

   ConsolidatedAs of December 31, 2013

   2,771,593

   

   15,480

   

   2,787,073Current

   -

   

   -

   

   -Noncurrent

   2,771,593

   

   15,480

   

   2,787,073Additions

   435,852

   

   59,576

   

   495,428Spin-off generation activity on the distribuition

   (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)As of December 31, 2014

   3,296,837

   

   77,779

   

   3,374,616Current

   540,094

   

   -

   

   540,094Noncurrent

   2,756,744

   

   77,779

   

   2,834,522Additions

   330,062

   

   37,469

   

   367,531Transfers to intangible 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 - RAP

   -

   

   (3,257)

   

   (3,257)Disposals

   (20,788)

   

   -

   

   (20,788)As of December 31, 2015

   3,483,713

   

   123,391

   

   3,607,104Current

   -

   

   9,630

   

   9,630Noncurrent

   3,483,713

   

   113,761

   

   3,597,474Business combination

   876,281

   

   -

   

   876,281Additions

   655,456

   

   50,580

   

   706,036Adjustment of expected cash flow

   203,452

   

   -

   

   203,452Adjustment - financial asset measured at amortized cost

   -

   

   16,088

   

   16,088Cash inputs - RAP

   -

   

   (9,727)

   

   (9,727)Disposals

   (25,392)

   

   -

   

   (25,392)As of December 31, 2016

   5,193,511

   

   180,333

   

   5,373,844Current

   -

   

   10,700

   

   10,700Noncurrent

   5,193,511

   

   169,633

   

   5,363,144
   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) 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 in Net Operating Revenue in the statement of profit or loss for the year (note 27), based on the fair value (new replacement value - “VNR” – note 4) (Net Operating  Revenue of R$186,148 in 2016, R$ 393,343 in 2015 and R$ 93,254 in 2014). The “Transfer to intangible assets” in 2015 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.  As the concession period was renewed, the Company exchanged the unconditional right to receive cash at the end of the concession period for an additional concession period of thirty years,that is, representing the exchange of the financial asset for an intangible asset to operate the concession. 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 and it takes into consideration the indemnity upon the reversal of assets to the


granting authority. The adjustment of R$ 16,088 is recognized against other operating income (R$11,400 in 2015 and R$ 2,723 in 2014).   F - 30


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( 12 )OTHER RECEIVABLES
  Current

   

   NoncurrentDec 31, 2016

   

   Dec 31, 2015

   

   Dec 31, 2016

   

   Dec 31, 2015Advances - Fundação CESP

   7,533

   

   10,567

   

   -

   

   -Advances to suppliers

   15,787

   

   10,666

   

   -

   

   -Pledges, funds and restricted deposits

   106,925

   

   649

   

   533,719

   

   433,014Orders in progress

   203,344

   

   274,605

   

   -

   

   -Services rendered to third parties

   9,385

   

   6,987

   

   -

   

   -Energy pre-purchase agreements

   -

   

   -

   

   27,302

   

   31,375Collection agreements

   1,273

   

   90,451

   

   -

   

   -Prepaid expenses

   65,668

   

   61,602

   

   20,942

   

   19,579GSF Insurance Premium

   12,722

   

   8,724

   

   28,935

   

   29,392Receivables - Eletrobras

   213,552

   

   341,781

   

   -

   

   -Receivables - Business combination

   -

   

   -

   

   

   

   13,950Advances to employees

   15,940

   

   12,509

   

   -

   

   -Indemnities for claims

   -

   

   49,937

   

   -

   

   -Others

   153,315

   

   90,653

   

   104,752

   

   34,685(-) Allowance for doubtful debts (note 6)

   (27,992)

   

   (12,460)

   

   -

   

   (1,981)Total

   777,451

   

   946,670

   

   715,650

   

   560,014
  Pledges, funds and restricted deposits: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 Insurance Premium:refers to the 2015 GSF premium paid in advance by the subsidiaries Ceran, CPFL Jaguari Geração (Paulista Lajeado) and CPFL Renováveis, related to the transfer of the hydrological risks to the Centralizing Account for Tariff Flag Resources (“CCRBT”), amortized as other operating expenses on a straight-line basis. Receivables –Eletrobras:refer to: (i) low income subsidies totaling R$ 17,239 (R$ 18,190 at December 31, 2015). (ii) other tariff discounts granted to consumers amounting to R$ 164,396 (R$ 323,591 as of December 31, 2015) and (iii) tariff discounts – judicial injunctions totaling R$ 31,917 (note 27.4). In 2016 the subsidiaries matched the receivables relating to Eletrobrás to the payables relating to theEnergy Development Account (CDE)(note 24) amounting to R$ 869,717, of which (i) R$ 659,258 based on a judicial injunction obtained in May 2015, and (ii) R$ 201,249 authorized by Order No. 1,576/2016. Indemnities for claims:refer to the amounts receivable from insurance companies by CPFL Renováveis as indemnities for claims occurred in 2015,  which was received during 2016.  ( 13 )INVESTMENTS
  Dec 31, 2016

   

   Dec 31, 2015Permanent equity interests - equity methodBy equity method of the subsidiary

   1,482,533

   

   1,235,832Fair value of assets, net

   11,219

   

   11,799Total

   1,493,753

   

   1,247,631
   F - 31


---



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

   

   Share of profit (loss)Joint ventures

   

   Dec 31, 2016

   

   Dec 31, 2015

   

   2016

   

   2015

   

   2014Baesa

   

   175,914

   

   166,150

   

   9,853

   

   2,508

   

   10,583Enercan

   

   562,701

   

   473,148

   

   117,112

   

   74,677

   

   49,040Chapecoense

   

   537,170

   

   449,049

   

   117,451

   

   77,487

   

   21,285EPASA

   

   206,749

   

   147,485

   

   67,577

   

   63,348

   

   (20,041)Fair value adjustments of assets, net

   

   11,219

   

   11,799

   

   (579)

   

   (1,136)

   

   (1,182)1,493,753

   

   1,247,631

   

   311,414

   

   216,885

   

   59,684
  13.1 - Dividends and Interest on capital
 At December 31, 2016 and 2015, the Company has the following amounts receivable from the joint ventures below, relating to dividends and interest on capital:  Dividend

   

   Interest on capital

   

   TotalInvestments

   

   Dec 31, 2016

   

   Dec 31, 2015

   

   Dec 31, 2016

   

   Dec 31, 2015

   

   Dec 31, 2016

   

   Dec 31, 2015Investco

   

   -

   

   -

   

   2,926

   

   2,118

   

   2,926

   

   2,118EPASA

   

   -

   

   29,933

   

   -

   

   -

   

   -

   

   29,933Baesa

   

   89

   

   20

   

   -

   

   -

   

   89

   

   20Enercan

   

   40,983

   

   30,905

   

   -

   

   -

   

   40,983

   

   30,905Chapecoense

   

   29,329

   

   28,417

   

   -

   

   -

   

   29,329

   

   28,417Total

   

   70,402

   

   89,274

   

   2,926

   

   2,118

   

   73,328

   

   91,392
  13.2 – Joint Ventures
 Summarized financial information on joint ventures at December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014 is as follows:  December 31, 2016Joint venture

   

   Enercan

   

   Baesa

   

   Chapecoense

   

   EpasaCurrent assets

   

   405,874

   

   54,703

   

   577,296

   

   257,082Cash and cash equivalents

   

   288,956

   

   18,946

   

   280,083

   

   85,709Noncurrent assets

   

   1,174,869

   

   1,117,120

   

   2,892,371

   

   562,462Current liabilities

   

   196,760

   

   116,192

   

   391,402

   

   172,401Borrowings and debentures

   

   87,560

   

   87,032

   

   137,753

   

   35,555Other financial liabilities

   

   7,848

   

   24,119

   

   78,372

   

   62,762Noncurrent liabilities

   

   229,085

   

   352,142

   

   2,024,989

   

   259,559Borrowings and debentures

   

   153,020

   

   63,196

   

   1,292,239

   

   218,891Other financial liabilities

   

   26,254

   

   276,600

   

   730,494

   

   28,686Equity

   

   1,154,897

   

   703,489

   

   1,053,275

   

   387,584Net operating revenue

   

   564,966

   

   239,730

   

   789,732

   

   548,145Operational costs and expenses

   

   (137,159)

   

   (76,985)

   

   (140,212)

   

   (328,093)Depreciation and amortization

   

   (53,888)

   

   (51,429)

   

   (126,770)

   

   (35,075)Interest income

   

   31,602

   

   9,115

   

   35,113

   

   10,329Interest expense

   

   (36,275)

   

   (23,961)

   

   (125,192)

   

   (23,128)Income tax expense

   

   (121,223)

   

   (20,401)

   

   (106,683)

   

   (28,011)Profit (loss) for the year

   

   240,363

   

   39,405

   

   212,294

   

   126,665Equity Interests and voting capital

   

   48.72%

   

   25.01%

   

   51.00%

   

   53.34%
   F - 32


---



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

   

   336,794Borrowings and debentures

   

   86,724

   

   111,422

   

   136,323

   

   57,269Other financial liabilities

   

   81,121

   

   70,793

   

   115,360

   

   122,921Noncurrent liabilities

   

   309,317

   

   427,284

   

   2,108,820

   

   292,490Borrowings and debentures

   

   240,336

   

   155,826

   

   1,404,553

   

   251,914Other financial liabilities

   

   24,759

   

   260,042

   

   703,556

   

   40,381Equity

   

   971,097

   

   664,442

   

   880,488

   

   276,500Net operating revenue

   

   523,055

   

   427,561

   

   729,511

   

   949,246Operational costs and expenses

   

   (196,480)

   

   (260,004)

   

   (149,219)

   

   (729,994)Depreciation 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, 2015, CPFL Geração's interest in Epasa was 53.84%
 2014Joint venture

   

   Enercan

   

   Baesa

   

   Chapecoense

   

   EpasaNet operating revenue

   

   492,921

   

   395,440

   

   820,500

   

   1,220,511Operational costs and expenses

   

   (254,575)

   

   (219,400)

   

   (451,408)

   

   (1,196,524)Depreciation 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, 2014, CPFL Geração's interest in Epasa was 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 Goiás 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). F - 33


---



( 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, 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)Provision for socio environmental costs

   -

   

   -

   

   9,193

   

   -

   

   -

   

   -

   

   -

   

   9,193Transfers

   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 combinations

   71,646

   

   264,146

   

   106,682

   

   844,162

   

   93

   

   240

   

   330,030

   

   1,616,999Spin-off generation activity on the distribuition - cost

   -

   

   -

   

   460

   

   6,089

   

   -

   

   204

   

   -

   

   6,754Spin-off generation activity on the distribuition - 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 losses

   -

   

   -

   

   (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)Additions

   -

   

   171

   

   -

   

   236

   

   -

   

   -

   

   1,084,612

   

   1,085,019Disposals

   -

   

   -

   

   (421)

   

   (6,705)

   

   (1,249)

   

   (779)

   

   (26,696)

   

   (35,850)Transfers

   8,325

   

   95,799

   

   177,902

   

   1,160,915

   

   22,467

   

   456

   

   (1,465,864)

   

   -Reclassification - cost

   (137)

   

   (1,434)

   

   (40,852)

   

   52,205

   

   12

   

   (39)

   

   (1,219)

   

   8,536Transfers from/to other assets - cost

   -

   

   3

   

   -

   

   (5,025)

   

   (167)

   

   (452)

   

   (10,523)

   

   (16,164)Depreciation

   (7,632)

   

   (75,659)

   

   (54,035)

   

   (377,529)

   

   (8,888)

   

   (1,676)

   

   -

   

   (525,420)Write-off of depreciation

   (7)

   

   1

   

   62

   

   4,694

   

   480

   

   254

   

   -

   

   5,484Reclassification - depreciation

   (1,211)

   

   (967)

   

   (5,374)

   

   (1,002)

   

   7

   

   11

   

   -

   

   (8,536)Transfers from/to other assets - depreciation

   -

   

   3

   

   (46)

   

   1,374

   

   150

   

   91

   

   -

   

   1,572Impairment losses

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (5,221)

   

   (5,221)Business Combination

   -

   

   -

   

   -

   

   2,140

   

   27,175

   

   -

   

   1,049

   

   30,364At December 31, 2016

   176,145

   

   1,394,162

   

   1,153,220

   

   6,655,391

   

   76,217

   

   7,562

   

   250,302

   

   9,712,998Historical cost

   206,330

   

   2,060,191

   

   1,652,934

   

   9,066,408

   

   106,920

   

   21,507

   

   250,302

   

   13,364,592Accumulated depreciation

   (30,185)

   

   (666,028)

   

   (499,714)

   

   (2,411,017)

   

   (30,704)

   

   (13,945)

   

   -

   

   (3,651,594)Average depreciation rate 2016

   3.86%

   

   3.69%

   

   3.30%

   

   4.19%

   

   14.31%

   

   10.01%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%
 F - 34


---



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$ 182,181 (R$ 612,083 at December 31, 2015). The amounts recognized in line item “Reclassification – cost”, related mainly to the subsidiary CPFL Renováveis, refer to transfers between groups of property, plant and equipment and do not change the amount of the depreciation expense recognized in the period since their respective useful lives were not changed. In accordance with IAS 23, the interest on borrowings taken by subsidiaries to finance the works is capitalized during the construction phase. During 2016, R$ 54,733 (R$ 34,212 in 2015 and R$4,236 in 2014) was capitalized in the financial statements at a rate of 11.70% p.a. (11.16% p.a. in 2015 and 8.59% p.a in 2014). In the financial statements, depreciation expenses are recognized in the statement of profit or loss in line item “depreciation and amortization” (note 29). At December 31, 2016, the total amount of property, plant and equipment pledged as collateral for borrowings, as mentioned in note 17, is approximately R$ 4,198,472, mainly relating to the subsidiary CPFL Renováveis (R$ 4,157,894). 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 Brazilian economic conditions have deteriorated even further during 2016, an additional impairment of  R$ 5,221 was recorded in subsidiary CPFL Telecom as a cash-generating unit (in 2015, R$ 31,284 in the subsidiary CPFL Telecom and R$ 1,828 in subsidiary CPFL Total). This loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 29). Such impairment was based on the assessment of the cash-generating units comprising fixed assets of subsidiaries which, separately, are not featured as an operating segment (note 31). Additionally, during 2016 and 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.  F - 35


---



( 15 )INTANGIBLE ASSETS
  Concession rightGoodwill

   

   Acquired in business combinations

   

   Distribution infrastructure - operational

   

   Distribution infrastructure - in progress

   

   Public utilities

   

   Other intangible assets

   

   TotalAs of 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)As of 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)As of 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

   

   18,525,004Accumulated Amortization

   (37)

   

   (3,086,356)

   

   (6,099,675)

   

   -

   

   (7,097)

   

   (121,500)

   

   (9,314,665)Additions

   -

   

   -

   

   -

   

   1,213,924

   

   -

   

   10,507

   

   1,224,431Amortization

   -

   

   (255,110)

   

   (498,891)

   

   -

   

   (1,419)

   

   (12,438)

   

   (767,858)Transfer - intangible assets

   -

   

   -

   

   610,032

   

   (610,032)

   

   -

   

   -

   

   -Transfer - financial asset

   -

   

   -

   

   9,452

   

   (664,908)

   

   -

   

   -

   

   (655,456)Disposal and transfer - other assets

   -

   

   (7,283)

   

   (48,346)

   

   -

   

   -

   

   (7,410)

   

   (63,040)Business combination

   -

   

   413,796

   

   1,229,074

   

   227,398

   

   -

   

   -

   

   1,870,268Impairment losses

   -

   

   (40,433)

   

   -

   

   -

   

   -

   

   (2,637)

   

   (43,070)As of December 31, 2016

   6,115

   

   4,466,516

   

   5,550,502

   

   666,008

   

   27,324

   

   59,147

   

   10,775,613Historical cost

   6,152

   

   7,602,941

   

   11,987,109

   

   666,008

   

   35,840

   

   183,138

   

   20,481,188Accumulated Amortization

   (37)

   

   (3,136,425)

   

   (6,436,607)

   

   -

   

   (8,516)

   

   (123,990)

   

   (9,705,575)
 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, in 2015 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 2016, R$ 13,349 was capitalized (R$ 11,358 in 2015 and R$ 8,044 in 2014) at a rate of 7.74% p.a. (7.53% p.a. in 2015 and 7.50% p.a. in 2014). 15.1Intangible 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:   F - 36


---



Dec 31, 2016

   

   Dec 31, 2015

   

   Annual amortization rateHistorical cost

   

   Accumulated amortization

   

   Net value

   

   Net value

   

   2016

   

   2015

   

   2014Intangible asset - acquired in business combinationsIntangible asset acquired, not mergedParent companyCPFL Paulista

   304,861

   

   (197,018)

   

   107,843

   

   117,829

   

   3.28%

   

   4.78%

   

   5.10%CPFL Piratininga

   39,065

   

   (23,746)

   

   15,319

   

   16,614

   

   3.31%

   

   4.50%

   

   4.66%RGE

   3,150

   

   (1,693)

   

   1,457

   

   1,590

   

   4.24%

   

   5.51%

   

   5.70%CPFL Geração

   54,555

   

   (33,643)

   

   20,912

   

   22,757

   

   3.38%

   

   5.04%

   

   4.88%Jaguari Geração

   7,896

   

   (3,582)

   

   4,314

   

   4,584

   

   3.41%

   

   6.36%

   

   6.71%409,527

   

   (259,682)

   

   149,845

   

   163,373SubsidiariesCPFL Renováveis

   3,717,093

   

   (722,065)

   

   2,995,028

   

   3,195,215

   

   5.39%

   

   4.35%

   

   4.11%RGE Sul

   101,055

   

   (1,531)

   

   99,524

   

   -

   

   9.09%

   

   -

   

   -RGE

   618

   

   (145)

   

   473

   

   516

   

   7.06%

   

   7.06%

   

   9.41%3,818,766

   

   (723,742)

   

   3,095,025

   

   3,195,731Subtotal

   4,228,294

   

   (983,424)

   

   3,244,869

   

   3,359,104Intangible asset acquired and merged – DeductibleSubsidiariesRGE

   1,120,266

   

   (862,342)

   

   257,924

   

   281,551

   

   2.11%

   

   1.79%

   

   1.75%RGE Sul

   312,741

   

   (4,759)

   

   307,982

   

   -

   

   9.09%

   

   -

   

   -CPFL Geração

   426,450

   

   (313,497)

   

   112,953

   

   122,919

   

   2.34%

   

   3.80%

   

   3.89%Subtotal

   1,859,457

   

   (1,180,598)

   

   678,859

   

   404,470Intangible asset acquired and merged – ReassessedParent companyCPFL Paulista

   1,074,026

   

   (722,461)

   

   351,565

   

   383,770

   

   3.00%

   

   4.34%

   

   4.61%CPFL Piratininga

   115,762

   

   (70,366)

   

   45,395

   

   49,232

   

   3.31%

   

   4.50%

   

   4.66%RGE

   310,128

   

   (171,659)

   

   138,469

   

   151,153

   

   4.09%

   

   5.32%

   

   5.50%Jaguari Geração

   15,275

   

   (7,917)

   

   7,358

   

   7,818

   

   3.01%

   

   5.61%

   

   5.91%Subtotal

   1,515,190

   

   (972,403)

   

   542,787

   

   591,972Total

   7,602,941

   

   (3,136,425)

   

   4,466,516

   

   4,355,546
 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 noncontrolling 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. 319/99 and No. 349/01 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. Effective January 1, 2016, in compliance with the amendments to IAS 16 and IAS 38, the Company and its subsidiaries started to adopt prospectively, for all cases, the straight-line method of amortization over the remaining concession period.   F - 37


---



15.2Impairment 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.  As the Brazilian economic conditions have deteriorated even further during 2016, an additional impairment of intangible of R$ 2,637 was recorded in subsidiary CPFL Telecom as a cash-generating unit (in 2015, R$ 1,835 in the subsidiary CPFL Telecom and R$ 4,009 in subsidiary CPFL Total). This loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 29). Furthermore, the subsidiary CPFL Renováveis recorded an impairment loss of R$40,433 on the intangible assets related to Aiuruoca.  Such provisions for impairment were based on the assessment of these cash-generating units formed by the intangible assets of those subsidiaries, which, separately, do not feature an operating segment (note 31). Additionally, during 2016 and 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 less cost to sell.  15.3Business combination – Acquisition of AES Sul On June 16, 2016, the Company disclosed in a Significant Event Notice that it had entered into an agreement to acquire through its wholly-owned subsidiary CPFL Jaguariúna Ltda., 100% of  the shares of AES Sul Distribuidora Gaúcha de Energia S.A. (“AES Sul”), currently RGE Sul,  until then held by AES Guaíba II Empreendimentos Ltda. (the “seller”), indirect wholly-owned subsidiary of The AES Corporation. On August 5, 2016, the transaction was approved by CADE (Brazilian antitrust agency) and, on September 9, 2016, it was authorized by ANEEL. The acquisition was completed on October 31, 2016 (“acquisition date”), after all the conditions precedent of the transaction were met. October 31, 2016 was the date in which the control of RGE Sul was taken over by CPFL Jaguariúna.  This acquisition resulted in a business combination in accordance with IFRS 3 (R) – “Business Combination” since CPFL Jaguariúna started to control RGE Sul. RGE Sul is a publicly-held corporation  engaged in providing public services of electricity distribution in any forms, and these activities are regulated by the National Agency of Electric Energy (“ANEEL”), linked to the Ministry of Mines and Energy. Additionally, RGE Sul is authorized to participate in programs that aim at other forms of energy, technology and services, including exploration of activities derived directly or indirectly from the use of assets, rights and technologies owned by it. Its administrative headquarters are located at Rua Dona Laura, 320 – 6o e 10o andar, Bairro Rio Branco, Porto Alegre, State of Rio Grande do Sul, Brazil. RGE Sul holds the concession for operation of its activities for a period of  thirty years, up to November 5, 2027, its concession area comprises 118 municipalities of the State of Rio Grande do Sul, located between the metropolitan region of Porto Alegre and the borders with Uruguay and Argentina, serving approximately 1.3 million consumers (information not audited by the independent auditors). The acquisition of RGE Sul is in line with the Company’s growth strategy, especially in the Distribution segment, with potential gains of scale for its operations. The Company also expects to obtain important synergies relating to the concession area of RGE Sul since another important distributor of the Group (RGE) holds concession in the state of Rio Grande do Sul. The consideration initially transferred was R$ 1,698,455, paid in cash, in a lump sum, on the acquisition date. This consideration was subsequently adjusted for changes in working capital and net debt of RGE Sul, occurred


in the period between December 31, 2015 and the acquisition date. The final value of the consideration, considering the price adjustment, was R$1,591,839.   F - 38


---



The acquisition related costs, registered as expenses in 2016, amounted R$6,692. Additional information to the acquisition (acquisition of RGE Sul) a)Consideration RGE SulOctober 31, 2016Consideration directly transferred to prior shareholders

   

   1,698,455Reimbursements due to adjustments related to agreement clauses

   

   (106,616)Consideration paid, net

   

   1,591,839
  b)Assets acquired and liabilities assumed on the acquisition date The total amount paid on the transaction was allocated on the acquisition date to the assets acquired and liabilities assumed at fair values, including the intangible assets related to the concession exploration right, which started to be amortized over the remaining concession period that will end in November 2027. Consequently, as the entire amount paid was provisionally allocated to identified assets and liabilities, no residual value was allocated as goodwill on this transaction. The initial accounting for the allocation of the amount paid to the assets acquired and liabilities assumed was provisionally determined at December 31, 2016 for the consolidated financial statements, based on analyses conducted by Management itself until the economic and the independent appraiser completes financial appraisal report. As the acquisition was only consummated on October 31, 2016, it was not possible to finalize an appraisal report prepared by an independent appraiser. The allocation of the price paid at the fair value of the assets and liabilities acquired is as follows: October 31, 2016(preliminary)Current assetsCash and cash equivalents

   

   95,164Consumers, concessionaries and licensees

   

   580,945Other current assets

   

   89,548Noncurrent assetsConsumers, concessionaries and licensees

   

   54,111Deferred tax assets

   

   204,176Concession financial asset

   

   876,281Intangible assets - Distribution infrastructure

   

   1,456,472Intangible acquired in this business combination

   

   413,796Other noncurrent assets

   

   147,784Current liabilitiesTrade payables

   

   (479,031)Debentures and borrowings

   

   (24,672)Taxes, fees and contributions

   

   (65,198)Sector financial asset

   

   (29,246)Regulatory charges

   

   (60,787)Other current liabilities

   

   (114,552)
 F - 39


---



Noncurrent liabilitiesDebentures and borrowings

   

   (1,131,949)Sector financial asset

   

   (64,935)Provision for tax, civil and labor risks

   

   (223,383)Other noncurrent liabilities

   

   (132,686)Net assets acquired

   

   1,591,839
 Goodwill arising on acquisitionConsideration paid, net

   

   1,591,839(-) Fair value of identifiable net assets acquired

   

   1,591,839Goodwill

   

   -
  The fair values presented above are provisional, and the confirmation of the amounts is pending until the economic and financial appraisal report, which is being prepared by an independent appraisal, is received: ·Consumers, Concessionaries and Licensees R$ 635,056 ·Concession financial asset: R$ 876,281 ·Intangible asset of the distribution infrastructure: R$ 1,456,472 ·Indemnification asset: R$ 30,000 ·Intangible acquired in a business combination: R$ 413,976 ·Contingent liabilities: R$ 223,283 The fair values of the concession financial asset and distribution infrastructure intangible assets was determined based on the best estimate of the fair value of the asset base (Regulatory Remuneration Base – “BRR”) of RGE Sul, considering the same assumptions adopted when preparing the report for Periodic Tariff Review purposes. Management expects to have the aforementioned report completed by October 2017. Moreover, no fair value adjustment of assets and liabilities was recognized in the period between the acquisition date and the consolidated financial statements reporting date.  c) Contingent consideration The share purchase agreement does not contain any clauses related to the contingent consideration to be paid to the seller.  d) Indemnification assets The agreement for purchase of 100% of the shares of RGE Sul establishes that CPFL Jaguariúna can be indemnified, up to the limit of 15% of the total amount paid, if in the future it suffers any loss , conditioned to the compliance with specific clauses derived from matters originated in the seller or in any of its subsidiaries established in the share purchase agreement. There are also specific clauses for two lawsuits (regulatory and environmental) in which the seller undertakes to indemnify fully CPFL Jaguariúna in case of cash outflows related to the lawsuits, and CPFL Jaguariúna undertakes to pass on to the seller any cash flows related to these lawsuits that come to be received in the future in order to neutralize any effect on these two specific matters. On the acquisition date, an indemnification asset of R$ 30,000 was recognized, relating to the environmental lawsuit (see item “e” below). This indemnification asset was recognized at the same amount of the fair value attributed to this contingent liability, which was also recognized on the acquisition date. Based on management assessment, no indemnification asset was recognized for the regulatory lawsuit for which there is a specific indemnification clause since no contingent liability related to this lawsuit was recognized on the acquisition date.    F - 40


---



e) Contingent liabilities recognized We present below the contingent liabilities provisionally recognized in the amount of R$ 145,443 on the acquisition date:  RGE SulOctober 31, 2016Labor lawsuits (i)

   

   53,958Civil lawsuits (i)

   

   53,174Regulatory lawsuits (i)

   

   5,850Environmental lawsuits (ii)

   

   30,000Tax lawsuits (i)

   

   2,461Preliminary contingent liabilities

   

   145,443Provisions recognized in the subsidiary

   

   77,940Provisions for tax, civil and labor risks

   

   223,383
   i.These amounts represent the fair values of the labor, civil, regulatory and tax lawsuits for which the likelihood of loss attributed on the acquisition date is “possible” or “remote”. Considering that the settlement of these lawsuits depends on third parties, either at the judicial or administrative level, it is not possible to estimate a schedule for the occurrence of any cash outflows associated with these contingent liabilities. No indemnification asset was recognized for these contingent liabilities. ii.Refers to the fair value attributed to a class action lawsuit for which the likelihood of loss attributed by Management, together with its legal counsel, is “possible” on  the acquisition date. This class action lawsuit seeks compensation for environmental damages occurred in a woodworking and pole manufacture unit that was operated, between 1997 and 2005, by RGE Sul together with its associate at that time AES Florestal. Until 1997, this unit was operated by the former concessionaire, Companhia Estadual de Energia Elétrica (CEEE). Indemnification asset in the same amount was recognized on the acquisition date.  f) Receivables acquired The fair value of the receivables acquired is R$ 635,056. The gross contractual amount of the receivables is R$ 703,672 and, based on Management’s best estimates R$ 68,616 are not expected to be received and represent, therefore, the portion that is expected to represent an impairment .  g) Net cash outflow on the acquisition Consideration paid, net

   

   1,591,839(-) Cash and cash equivalent balances acquired

   

   (95,164)Cash and cash equivalent transferred, net

   

   1,496,675
  h) Additional financial information i.Net Operating Revenue and loss of the subsidiary acquired included in the consolidated financial statements in 2016: 2016Net Operating Revenue

   

   Profit or loss, netRGE Sul (November 1 to December 31, 2016)

   

   522,677

   

   (27,687)
  The Company’s consolidated financial statements for the year ended December 31, 2016 include two (2) months of operations of RGE Sul. ii.Combined financial information on the Net Operating Revenue and Profit for 2016, if the acquisition had occurred on January 1, 2016.   F - 41


---









2016Net Operating Revenue

   

   Profit or loss, netCPFL Energia Consolidated

   

   19,112,089

   

   879,057Prof-forma adjustments (*)

   

   2,365,090

   

   (403,839)21,477,179

   

   475,218
 (*) The pro forma adjustments in the Net Operating Revenue consider the addition of the subsidiary’s Net Operating Revenue for the period in which it was not a subsidiary and, consequently, was not consolidated by the Company (from January 1st through October 31, 2016). The pro forma adjustments to profit for the year consider: (i) addition of the subsidiary’s result for the period in which it was not consolidated by the Company (from January 1st through October 31, 2016); (ii) inclusion of the amortization of the exploration right and the amortization of the fair value of the infrastructure of distribution, had the acquisition occurred on January 1, 2016.  ( 16 )TRADE PAYABLES
  Dec 31, 2016

   

   Dec 31, 2015CurrentSystem service charges

   59,935

   

   203,961Energy purchased

   1,868,950

   

   2,402,823Electricity network usage charges

   121,884

   

   106,940Materials and services

   545,468

   

   331,809Free energy

   131,893

   

   115,676Total

   2,728,130

   

   3,161,210NoncurrentEnergy purchased

   129,148

   

   -Materials and services

   633

   

   633Total

   129,781

   

   633
   The amounts of electricity supply recorded in noncurrent refer to the sale made by the indirect subsidiary RGE Sul in the period from September 1, 2000 to December 31, 2002, relating to the electricity purchase and sale transactions made on the Electric Energy Commercialization Chamber (CCEE) and adjusted, in 2002 and 2003, based on information and calculations prepared and disclosed by CCEE the payment of which is suspended due to the judicial injunction obtained by the indirect subsidiary until the judgment of the lawsuit (notes 6 and 24).  F - 42


---



( 17 )DEBTS, BORROWINGS AND INTEREST ON DEBTS AND BORROWINGS
  December 31, 2016

   

   December 31, 2015Interest - Current and Noncurrent

   

   Principal

   

   Total

   

   Interest - Current and Noncurrent

   

   Principal

   

   TotalCurrent

   

   Noncurrent

   

   

   

   Current

   

   NoncurrentMeasured at costLocal currencyInvestment

   17,827

   

   842,015

   

   4,606,227

   

   5,466,069

   

   17,775

   

   693,058

   

   4,970,715

   

   5,681,549Rental assets

   38

   

   1,034

   

   3,955

   

   5,028

   

   17

   

   687

   

   3,434

   

   4,138Financial Institutions

   234,096

   

   255,355

   

   1,517,251

   

   2,006,702

   

   179,656

   

   382,411

   

   1,350,746

   

   1,912,812Other

   50

   

   59,756

   

   42,370

   

   102,176

   

   764

   

   134,960

   

   10,002

   

   145,726Total at cost

   252,011

   

   1,158,159

   

   6,169,803

   

   7,579,974

   

   198,212

   

   1,211,115

   

   6,334,897

   

   7,744,225Measured at fair valueForeign currencyFinancial Institutions

   22,062

   

   595,101

   

   4,922,463

   

   5,539,626

   

   40,714

   

   1,651,199

   

   5,560,517

   

   7,252,430Mark to market

   -

   

   (1,764)

   

   (35,651)

   

   (37,415)

   

   -

   

   (29,269)

   

   (282,980)

   

   (312,249)Total at fair value

   22,062

   

   593,337

   

   4,886,812

   

   5,502,211

   

   40,714

   

   1,621,930

   

   5,277,536

   

   6,940,180Borrowing costs

   -

   

   (5,213)

   

   (32,930)

   

   (38,143)

   

   -

   

   (1,391)

   

   (20,227)

   

   (21,618)Total

   274,073

   

   1,746,284

   

   11,023,685

   

   13,044,041

   

   238,926

   

   2,831,654

   

   11,592,206

   

   14,662,787
 Measured at amortized cost

   

   Dec 31, 2016

   

   Dec 31, 2015

   

   Annual interest

   

   Amortization

   

   CollateralLocal currencyInvestmentCPFL PaulistaFINEM V

   

   37,078

   

   70,293

   

   TJLP + 2.12% to 3.3% (c)

   

   72 monthly installments from February 2012

   

   CPFL Energia guarantee and receivablesFINEM V

   

   3,638

   

   5,384

   

   Fixed rate 8% (c)

   

   90 monthly installments from August 2011

   

   CPFL Energia guarantee and receivablesFINEM V

   

   30,835

   

   38,386

   

   Fixed rate 5.5% (b)

   

   96 monthly installments from February 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   149,984

   

   197,145

   

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

   

   72 monthly installments from January 2014

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   8,907

   

   10,412

   

   Fixed rate 2.5% (a)

   

   114 monthly installments from June 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   163,404

   

   191,022

   

   Fixed rate 2.5% (a)

   

   96 monthly installments from December 2014

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   57,798

   

   63,777

   

   Fixed rate 6% (b)

   

   96 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   73,435

   

   65,304

   

   SELIC + 2.62% to 2.66% (h)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   132,622

   

   130,774

   

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

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINAME

   

   25,356

   

   33,808

   

   Fixed rate 4.5%

   

   96 monthly installments from January 2012

   

   CPFL Energia guaranteeCPFL PiratiningaFINEM IV

   

   19,970

   

   37,859

   

   TJLP + 2.12% to 3.3% (c)

   

   72 monthly installments from February 2012

   

   CPFL Energia guarantee and receivablesFINEM IV

   

   1,173

   

   1,736

   

   Fixed rate 8% (c)

   

   90 monthly installments from August 2011

   

   CPFL Energia guarantee and receivablesFINEM IV

   

   16,035

   

   19,962

   

   Fixed rate 5.5% (b)

   

   96 monthly installments from February 2013

   

   CPFL Energia guarantee and receivablesFINEM V

   

   43,836

   

   57,621

   

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

   

   72 monthly installments from January 2014

   

   CPFL Energia guarantee and receivablesFINEM V

   

   2,339

   

   2,735

   

   Fixed rate 2.5% (a)

   

   114 monthly installments from June 2013

   

   CPFL Energia guarantee and receivablesFINEM V

   

   40,664

   

   47,536

   

   Fixed rate 2.5% (a)

   

   96 monthly installments from December 2014

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   41,620

   

   39,605

   

   SELIC + 2.62% to 2.66% (h)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   65,778

   

   69,054

   

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

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   28,198

   

   30,463

   

   Fixed rate 6% (b)

   

   96 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINAME

   

   12,023

   

   16,031

   

   Fixed rate 4.5%

   

   96 monthly installments from January 2012

   

   CPFL Energia guaranteeRGEFINEM V

   

   22,444

   

   42,549

   

   TJLP + 2.12% to 3.3% (c)

   

   72 monthly installments from February 2012

   

   CPFL Energia guarantee and receivablesFINEM V

   

   11,828

   

   14,725

   

   Fixed rate 5.5% (b)

   

   96 monthly installments from February 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   80,126

   

   105,322

   

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

   

   72 monthly installments from January 2014

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   942

   

   1,102

   

   Fixed rate 2.5% (a)

   

   114 monthly installments from June 2013

   

   CPFL Energia guarantee and receivablesFINEM VI

   

   60,085

   

   70,240

   

   Fixed rate 2.5% (a)

   

   96 monthly installments from December 2014

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   39,442

   

   43,522

   

   Fixed rate 6% (b)

   

   96 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   65,261

   

   59,348

   

   SELIC + 2.62% to 2.66% (h)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINEM VII

   

   81,394

   

   76,728

   

   TJLP + 2.12% to 2.66% (d)

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and receivablesFINAME

   

   6,033

   

   8,045

   

   Fixed rate 4.5%

   

   96 monthly installments from January 2012

   

   CPFL Energia guaranteeFINAME

   

   168

   

   227

   

   Fixed rate 10.0%

   

   90 monthly installments from May 2012

   

   Liens on assetsFINAME

   

   579

   

   715

   

   Fixed rate 10.0%

   

   66 monthly installments from October 2015

   

   Liens on assetsCPFLSanta CruzFINEM

   

   9,094

   

   10,306

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   3,381

   

   3,663

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   6,062

   

   7,382

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL Leste PaulistaFINEM

   

   3,397

   

   3,850

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   1,239

   

   1,343

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   2,224

   

   2,709

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL Sul PaulistaFINEM

   

   2,412

   

   2,734

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   1,731

   

   1,876

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   3,122

   

   3,803

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL JaguariSantander - Bank credit note

   

   1,464

   

   1,710

   

   TJLP + 3.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeSantander - Bank credit note

   

   572

   

   808

   

   UMBNDES + 2.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeFINEM

   

   2,422

   

   2,745

   

   Fixed rate 6%

   

   111 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   1,287

   

   1,394

   

   SELIC + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeFINEM

   

   2,321

   

   2,826

   

   TJLP + 2.19%

   

   72 monthly installments from April 2015

   

   CPFL Energia guaranteeCPFL MococaSantander - Bank credit note

   

   1,883

   

   2,200

   

   TJLP + 3.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeSantander - Bank credit note

   

   736

   

   1,039

   

   UMBNDES + 2.1%

   

   96 monthly installments from June 2014

   

   CPFL Energia guaranteeSantander - Bank credit note

   

   1,413

   

   1,932

   

   UMBNDES +1.99%

   

   96 monthly installments from October 2015

   

   CPFL Energia guaranteeSantander - Bank credit note

   

   4,081

   

   4,619

   

   TJLP + 2.99% (f)

   

   96 monthly installments from October 2015

   

   CPFL Energia guaranteeRGE SULFINEP I

   

   7,757

   

   -

   

   Fixed rate 5%

   

   81 monthly installments from September 2013

   

   Bank guaranteeFINEP II

   

   7,562

   

   -

   

   TJLP

   

   73 monthly installments from May 2016

   

   Bank guarantee
   F - 43


---



CPFL ServiçosFINAME

   

   1,297

   

   1,509

   

   Fixed rate 2.5% to 5.5%

   

   96 monthly installments from August 2014

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   313

   

   357

   

   Fixed rate 6%

   

   72 monthly installments from April 2016

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   668

   

   864

   

   Fixed rate 7.7% to 10%

   

   90 monthly installments from November 2012

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   11,292

   

   13,049

   

   Fixed rate 2.5% to 5.5%

   

   114 monthly installments from February 2013

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   47

   

   60

   

   TJLP + 4.2%

   

   90 monthly installments from November 2012

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   2,249

   

   2,659

   

   Fixed rate 6%

   

   90 monthly installments from October 2014

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   101

   

   108

   

   Fixed rate 6%

   

   96 monthly installments from July 2016

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   5,768

   

   6,496

   

   Fixed rate 6%

   

   114 monthly installments from June 2015

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   762

   

   1,002

   

   TJLP + 2.2% to 3.2% (c)

   

   56 monthly installments from July 2015

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   3,870

   

   4,006

   

   Fixed rate 9.5% to 10% (c)

   

   66 monthly installments from October 2015

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   1,589

   

   -

   

   Fixed rate 6% to 10% (e)

   

   66 monthly installments from April 2016

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   5,832

   

   -

   

   TJLP + 3.50% (e)

   

   48 monthly installments from July 2017

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   2,511

   

   -

   

   SELIC + 3.86% to 3.90% (k)

   

   48 monthly installments from July 2017

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   1,147

   

   -

   

   SELIC + 3.74% (d)

   

   36 monthly installments from November 2018

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   495

   

   -

   

   TJLP + 3.40% (h)

   

   36 monthly installments from November 2018

   

   CPFL Energia guarantee and liens on equipmentCERANBNDES

   

   266,484

   

   312,150

   

   TJLP + 3.69% to 5%

   

   168 monthly installments from December 2005

   

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

   

   48,409

   

   68,993

   

   UMBNDES + 5% (1)

   

   168 monthly installments from February 2006

   

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

   

   16,871

   

   19,466

   

   Fixed rate 3.0%

   

   96 monthly installments from July 2015

   

   CPFL Energia guaranteeCPFL TelecomFINAME

   

   7,448

   

   7,610

   

   Fixed rate 6.0% (b)

   

   60 monthly installments from December 2016

   

   CPFL Energia guaranteeFINEM

   

   7,849

   

   7,018

   

   SELIC + 3.12% (h)

   

   60 monthly installments from December 2016

   

   CPFL Energia guaranteeFINEM

   

   21,342

   

   21,544

   

   TJLP + 2.12% to 3.12% (c)

   

   60 monthly installments from December 2016

   

   CPFL Energia guaranteeFINEM

   

   470

   

   -

   

   TJLP (l)

   

   60 monthly installments from December 2016

   

   CPFL Energia guaranteeCPFL RenováveisFINEM I

   

   262,224

   

   290,445

   

   TJLP + 1.95%

   

   168 monthly installments from October 2009

   

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

   

   22,210

   

   25,308

   

   TJLP + 1.90%.

   

   144 monthly installments from June 2011

   

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

   

   495,912

   

   528,528

   

   TJLP + 1.72%

   

   192 monthly installments from May 2013

   

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

   

   80,362

   

   90,678

   

   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

   

   74,737

   

   79,457

   

   TJLP + 2.05%

   

   192 monthly installments from October 2013

   

   Pledge of CPFL Renováveis shares, assignment of receivablesFINEM VII

   

   138,474

   

   156,737

   

   TJLP + 1.92 %

   

   156 monthly installments from October 2010

   

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

   

   25,195

   

   32,289

   

   TJLP + 2.15%

   

   120 monthly installments from May 2010

   

   Pledge of shares, liens on machinery and equipment, real estate mortgages and guarantee letterFINEM X

   

   230

   

   528

   

   TJLP

   

   84 monthly installments from October 2010

   

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

   

   105,670

   

   115,676

   

   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

   

   317,289

   

   335,894

   

   TJLP + 2.18%

   

   192 monthly installments from July 2014

   

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

   

   318,257

   

   296,891

   

   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

   

   TJLP + 3.50%

   

   120 monthly installments from June 2007

   

   Pledge of shares and of credit rights, liens on machines and equipment to be acquired with the resources of the operationFINEM XV

   

   27,305

   

   31,227

   

   TJLP + 3.44%

   

   139 monthly installments from September 2011

   

   Pledge of shares, assignment of credit rights, pledge of grantor rights and reserve accountFINEM XVI

   

   6,418

   

   8,500

   

   Fixed rate 5.50%

   

   101 monthly installments from September 2011

   

   Pledge of shares, assignment of credit rights, pledge of grantor rights and reserve accountFINEM XVII

   

   460,426

   

   490,786

   

   TJLP + 2.18%

   

   192 monthly installments from January 2013

   

   Pledge of shares, assignment of credit rights, liens on machinery and equipment, assignment of receivables, reserve accountFINEM XVIII

   

   13,763

   

   18,481

   

   Fixed rate 4.5%

   

   102 monthly installments from June 2011

   

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

   

   29,559

   

   31,381

   

   TJLP + 2.02%

   

   192 monthly installments from January 2014

   

   Pledge of shares and assignment of receivablesFINEM XX

   

   44,650

   

   52,091

   

   Fixed rate 2.5%

   

   108 monthly installments from January 2014

   

   Pledge of shares and assignment of receivablesFINEM XXI

   

   40,281

   

   42,765

   

   TJLP + 2.02%

   

   192 monthly installments from January 2014

   

   Pledge of shares and assignment of receivablesFINEM XXII

   

   39,281

   

   45,828

   

   Fixed rate 2.5%

   

   108 monthly installments from January 2014

   

   Pledge of shares and assignment of receivablesFINEM XXIII

   

   1,729

   

   2,305

   

   Fixed rate 4.5%

   

   102 monthly installments from June 2011

   

   Pledge of shares and assignment of receivablesFINEM XXIV

   

   109,580

   

   136,528

   

   Fixed rate 5.5%

   

   108 monthly installments from January 2012

   

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

   

   87,492

   

   79,010

   

   TJLP + 2.18%

   

   192 monthly installments from July 2016

   

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

   

   525,011

   

   270,768

   

   TJLP + 2.75%

   

   192 monthly installments from July 2017

   

   Penhor de ações e de máquinas e equipamentos, cessão fiduciária dos direitos creditórios, conta reserva.Pledge of shares and machines and equipment, assignment of credit rights, reserve accountFINEM XXVII

   

   70,532

   

   -

   

   TJLP + 2,02%

   

   162 monthly installments from November 2016

   

   Pledge of shares of the intervening parties, assignment of credit rights, pledge of incidental rights authorized by ANEEL and SPE Reserve AccountFINAME IV

   

   2,857

   

   3,327

   

   Fixed rate 2.5%

   

   96 monthly installments from February 2015

   

   Liens and CPFL Renováveis guaranteeFINEP I

   

   1,397

   

   1,890

   

   Fixed rate 3.5%

   

   61 monthly installments from October 2014

   

   Bank guaranteeFINEP II

   

   10,445

   

   10,383

   

   TJLP - 1.0%

   

   85 monthly installments from June 2017

   

   Bank guaranteeFINEP III

   

   5,232

   

   6,374

   

   TJLP + 2.0%

   

   73 monthly installments from July 2015

   

   Bank guaranteeBNB I

   

   100,323

   

   108,835

   

   Fixed rate 9.5% to 10%

   

   168 monthly installments from January 2009

   

   Liens, pledge of shares and SIIF Energy guaranteeBNB II

   

   158,364

   

   165,324

   

   Fixed rate 10% (J)

   

   222 monthly installments from May 2010

   

   CPFL Energia guaranteeBNB III

   

   29,020

   

   30,837

   

   Fixed rate 9.5%

   

   228 monthly installments from July 2009

   

   Guarantee, liens on assets, assignment of credit rightsNIB

   

   67,872

   

   72,739

   

   IGPM + 8.63%

   

   50 quarterly installments from June 2011

   

   No guaranteeBanco do Brasil

   

   -

   

   31,014

   

   Fixed rate 10.0%

   

   132 monthly installments from June 2010

   

   Pledge of shares, pledge of the intervening parties and credit rights, assignment of revenues, bank guarantee, insurance and reserve accountCPFL BrasilFINEP

   

   -

   

   1,864

   

   Fixed rate 5%

   

   81 monthly installments from August 2011

   

   ReceivablesPurchase of assetsCPFL ESCOFINAME

   

   2,923

   

   3,544

   

   Fixed rate 4.5% to 8.7%

   

   96 monthly installments from March 2012

   

   CPFL Energia guaranteeFINAME

   

   99

   

   117

   

   Fixed rate 6%

   

   72 monthly installments from October 2016

   

   CPFL Energia guaranteeFINAME

   

   234

   

   261

   

   TJLP + 2.70%

   

   48 monthly installments from August 2016

   

   CPFL Energia guaranteeFINAME

   

   219

   

   216

   

   SELIC + 2.70%

   

   48 monthly installments from August 2016

   

   CPFL Energia guaranteeFINAME

   

   121

   

   -

   

   Fixed rate 9.5%

   

   48 monthly installments from October 2016

   

   CPFL Energia guaranteeFINAME

   

   678

   

   -

   

   Fixed rate 9.5% (e)

   

   48 monthly installments from February 2017

   

   CPFL Energia guarantee and liens on equipmentFINAME

   

   753

   

   -

   

   TJLP + 3.50% (e)

   

   48 monthly installments from August 2017

   

   CPFL Energia guarantee and liens on equipment
   F - 44


---



Financial institutionsCPFL EnergiaSantander - Working capital

   

   -

   

   331,343

   

   86.40% of CDI

   

   1 installment in January 2016

   

   No guaranteeCPFL PaulistaBanco do Brasil - Working capital

   

   380,403

   

   331,549

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeCPFL PiratiningaBanco do Brasil - Working capital

   

   66,951

   

   58,353

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeCPFL Santa CruzBanco do Brasil - Working capital

   

   50,213

   

   43,764

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   6,925

   

   7,637

   

   CDI + 0.27% (f)

   

   12 semiannual installments from June 2015

   

   CPFL Energia guaranteeCPFL Leste PaulistaBanco IBM - Working capital

   

   5,405

   

   6,587

   

   100.0% of CDI

   

   14 semiannual installments from December 2012

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   20,955

   

   23,790

   

   CDI + 0.1%

   

   12 semiannual installments from October 2014

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   15,658

   

   17,268

   

   CDI + 0.27%

   

   12 semiannual installments from March 2015

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   6,993

   

   8,052

   

   CDI + 1.33% (f)

   

   12 semiannual installments from January 2016

   

   CPFL Energia guaranteeCPFL Sul PaulistaBanco do Brasil - Working capital

   

   31,954

   

   27,850

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   7,888

   

   8,914

   

   CDI + 0.27% to 1.33 (f)

   

   12 semiannual installments from June 2015

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   6,784

   

   -

   

   CDI + 1.27% (g)

   

   Semiannual installments from February 2017

   

   CPFL Energia guaranteeCPFL JaguariBanco do Brasil - Working capital

   

   4,413

   

   3,846

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   10,726

   

   13,266

   

   100.0% of CDI

   

   14 semiannual installments from December 2012

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   11,297

   

   12,825

   

   CDI + 0.1%

   

   12 semiannual installments from October 2014

   

   CPFL Energia guaranteeCPFL MococaBanco do Brasil - Working capital

   

   28,911

   

   25,198

   

   104.90% of CDI (f)

   

   2 annual installments from July 2017

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   3,481

   

   4,305

   

   100.0% of CDI

   

   14 semiannual installments from December 2012

   

   CPFL Energia guaranteeBanco IBM - Working capital

   

   13,296

   

   14,663

   

   CDI + 0.27%

   

   12 semiannual installments from March 2015

   

   CPFL Energia guaranteeCPFL ServiçosBanco IBM - Working capital

   

   3,473

   

   5,111

   

   CDI + 0.10%

   

   11 semiannual installments from June 2013

   

   CPFL Energia guaranteeCPFL GeraçãoBanco do Brasil - Working capital

   

   641,316

   

   642,124

   

   109.5% of CDI

   

   1 installment in March 2019

   

   CPFL Energia guaranteeCPFL RenováveisHSBC

   

   250,363

   

   290,679

   

   CDI + 0.5% (i)

   

   8 annual installment from June 2013

   

   Pledge of sharesSafra

   

   208,547

   

   -

   

   105% of CDI

   

   14 installments from August 2016

   

   Redeemable preferred shares structureBanco BBM - Bank credit note

   

   44,171

   

   -

   

   CDI + 3.40%

   

   1 installment in March 2018

   

   No guaranteeBanco ABC - Bank credit note

   

   44,217

   

   -

   

   CDI + 3.80%

   

   1 installment in December 2017

   

   No guaranteeBanco ABC - Promissory notes

   

   105,883

   

   -

   

   CDI + 3.80%

   

   Semiannual installments from February 2017

   

   No guaranteeCPFL TelecomBanco IBM - Working capital

   

   31,449

   

   35,689

   

   CDI + 0.18%

   

   12 semiannual installments from August 2014

   

   CPFL Energia guaranteeCPFL Transmissão Morro AgudoSantander

   

   5,031

   

   -

   

   CDI + 1.60% (k)

   

   1 installment in March 2017

   

   CPFL Energia guaranteeOthersEletrobrásCPFL Paulista

   

   2,960

   

   3,931

   

   RGR + 6% to 6.5%

   

   monthly installments from August 2006

   

   Receivables and promissory notesCPFL Piratininga

   

   -

   

   88

   

   RGR + 6%

   

   monthly installments from August 2006

   

   Receivables and promissory notesRGE

   

   5,851

   

   7,658

   

   RGR + 6%

   

   monthly installments from August 2006

   

   Receivables and promissory notesCPFL Santa Cruz

   

   508

   

   1,029

   

   RGR + 6%

   

   monthly installments from January 2007

   

   Receivables and promissory notesCPFL Leste Paulista

   

   338

   

   532

   

   RGR + 6%

   

   monthly installments from February 2008

   

   Receivables and promissory notesCPFL Sul Paulista

   

   303

   

   544

   

   RGR + 6%

   

   monthly installments from August 2007

   

   Receivables and promissory notesCPFL Jaguari

   

   9

   

   24

   

   RGR + 6%

   

   monthly installments from June 2007

   

   Receivables and promissory notesCPFL Mococa

   

   122

   

   170

   

   RGR + 6%

   

   monthly installments from January 2008

   

   Receivables and promissory notesRGE SUL

   

   25,946

   

   -

   

   Fixed rate 5%

   

   120 monthly installments from June 2012

   

   Bank guaranteeOthers

   

   66,141

   

   131,751Subtotal local currency

   

   7,579,974

   

   7,744,225Foreign 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 (***)

   

   327,503

   

   397,324

   

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

   

   1 installment in october 2018

   

   CPFL Energia guarantee and promissory notesBank of America Merrill Lynch

   

   146,703

   

   175,750

   

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

   

   1 installment in September 2018

   

   CPFL Energia guarantee and promissory notesBank of Tokyo-Mitsubishi

   

   163,279

   

   195,524

   

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

   

   1 installment in February 2020

   

   CPFL Energia guarantee and promissory notesBank of Tokyo-Mitsubishi

   

   163,106

   

   195,380

   

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

   

   4 semiannual installments from September 2017

   

   CPFL Energia guarantee and promissory notesBNP Paribas

   

   68,663

   

   85,991

   

   Euro + 1.6350% (3)

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   -

   

   195,502

   

   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

   

   282,808

   

   338,504

   

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

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   130,522

   

   156,381

   

   US$ + 2.28% to 2.32% (3)

   

   1 installment in December 2017

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   115,382

   

   138,255

   

   US$ + 2.36% to 2.39% (3)

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   82,544

   

   98,891

   

   US$ + 2.74% (3)

   

   1 installment in January 2019

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   49,311

   

   59,080

   

   US$ + 2.2% (3)

   

   1 installment in February 2018

   

   CPFL Energia guarantee and promissory notesBank of America Merrill Lynch

   

   490,334

   

   587,094

   

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

   

   1 installment in February 2018

   

   CPFL Energia guarantee and promissory notesMizuho Bank

   

   244,484

   

   292,895

   

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

   

   3 semiannual installments from March 2018

   

   CPFL Energia guarantee and promissory notesMorgan Stanley

   

   -

   

   196,502

   

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

   

   1 installment in September 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   -

   

   95,502

   

   US$ + 3.3125% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesSyndicated transaction (**) - Bank of America Merrill Lynch, Citibank, HSBC and EDC-Export Development Canada

   

   218,104

   

   -

   

   US$ + Libor 3 months + 2.7% (4)

   

   5 semiannual installments from May 2019

   

   CPFL Energia guarantee and promissory notes
    F - 45


---



CPFL 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

   

   188,822

   

   236,474

   

   Euro + 1.6350% (3)

   

   1 installment in January 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   204,486

   

   244,778

   

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

   

   2 annual installments from January 2019

   

   CPFL Energia guarantee and promissory notesCitibank

   

   163,225

   

   195,502

   

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

   

   1 installment in March 2019

   

   CPFL Energia guarantee and promissory notesSantander

   

   -

   

   177,268

   

   US$ + 2.58% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   -

   

   124,737

   

   US$ + 3.3125% (3)

   

   1 installment in July 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   54,235

   

   64,980

   

   US$ + 2.08% (3)

   

   1 installment in August 2017

   

   CPFL Energia guarantee and promissory notesSumitomo

   

   163,712

   

   195,938

   

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

   

   1 installment in April 2018

   

   CPFL Energia guarantee and promissory notesSyndicated transaction (**) - Bank of America Merrill Lynch, Citibank, HSBC and EDC-Export Development Canada

   218,104

   

   -

   

   US$ + Libor 3 months + 2.7% (4)

   

   5 semiannual installments from May 2019

   

   CPFL Energia guarantee and promissory notesRGEBank of Tokyo-Mitsubishi

   

   58,852

   

   70,439

   

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

   

   1 installment in April 2018

   

   CPFL Energia guarantee and promissory notesBank of Tokyo-Mitsubishi

   

   267,740

   

   320,602

   

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

   

   1 installment in May 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   -

   

   58,683

   

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

   

   2 annual installments from May 2018

   

   CPFL Energia guarantee and promissory notesCitibank

   

   -

   

   274,426

   

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

   

   1 installment in April 2017

   

   CPFL Energia guarantee and promissory notesHSBC

   

   44,496

   

   53,260

   

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

   

   1 installment in October 2017

   

   CPFL Energia guarantee and promissory notesJ.P. Morgan

   

   199,826

   

   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 notesSyndicated transaction (**) - Bank of America Merrill Lynch, Citibank, HSBC and EDC-Export Development Canada

   218,104

   

   -

   

   US$ + Libor 3 months + 2.7% (4)

   

   5 semiannual installments from May 2019

   

   CPFL Energia guarantee and promissory notesCPFL Santa CruzSantander

   

   -

   

   34,679

   

   US$ + 2.544% (3)

   

   1 installment in June 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   16,556

   

   -

   

   US$ + 3.37% (4) (g)

   

   1 installment in July 2019

   

   CPFL Energia guarantee and promissory notesCPFL Sul PaulistaSantander

   

   -

   

   38,147

   

   US$ + 2.544% (3)

   

   1 installment in June 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   16,556

   

   -

   

   US$ + 3.37% (4) (g)

   

   1 installment in July 2019

   

   CPFL Energia guarantee and promissory notesCPFL Leste PaulistaScotiabank

   

   16,556

   

   -

   

   US$ + 3.37% (4) (g)

   

   1 installment in July 2019

   

   CPFL Energia guarantee and promissory notesCPFL JaguariSantander

   

   -

   

   53,752

   

   US$ + 2.544% (3)

   

   1 installment in June 2016

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   16,556

   

   -

   

   US$ + 3.37% (4) (g)

   

   1 installment in July 2019

   

   CPFL Energia guarantee and promissory notesCPFL GeraçãoHSBC

   

   326,159

   

   390,757

   

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

   

   1 installment in March 2017

   

   CPFL Energia guarantee and promissory notesChina Construction Bank - Bank credit note

   97,946

   

   -

   

   US$+Libor 3 months + 1.60% + 1.4% fee (4)

   1 installment in June 2019

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   117,550

   

   -

   

   US$ + 3.37% (4) (g)

   

   1 installment in July 2019

   

   CPFL Energia guarantee and promissory notesCitibank

   

   391,380

   

   -

   

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

   

   3 annual installments from September 2018

   

   CPFL Energia guarantee and promissory notesChina Construction Bank - Bank credit note

   32,624

   

   -

   

   US$ + 3.37% (4) (g)

   

   1 installment in September 2019

   

   CPFL Energia guarantee and promissory notesScotiabank

   

   163,125

   

   -

   

   US$ + 3.13% (f)

   

   1 installment in December 2019

   

   CPFL Energia guaranteeCPFL ServiçosJ.P. Morgan

   

   -

   

   14,760

   

   US$ + 1.75% (3)

   

   1 installment in October 2016

   

   CPFL Energia guarantee and promissory notesPaulista LajeadoBanco Itaú

   

   35,771

   

   42,862

   

   US$ + 3.196% (4)

   

   1 installment in March 2018

   

   CPFL Energia guarantee and promissory notesCPFL BrasilScotiabank

   

   44,501

   

   53,317

   

   US$ + 2.779% (3)

   

   1 installment in August 2018

   

   CPFL Energia guarantee and promissory notesMark to market

   

   (37,415)

   

   (312,249)Subtotal foreign currency

   

   5,502,211

   

   6,940,180Borrowing costs (*)

   

   (38,143)

   

   (21,618)**Total - Consolidated**

   

   13,044,041

   

   14,662,787
  (*) In accordance with IAS 39, this refers to the fundraising costs attributable to issuance of the respective debts.
 (**) Syndicated transaction – borrowings in foreign currency, having as counterpart a group of financial institutions.  The subsidiaries hold swaps converting the operating cost of currency variation to interest rate variation in reais, corresponding to: (1) 143.85% of CDI                                (3) 99% to 109% of CDI (2) 95.20% of CDI                                  (4) 109.1% to 119% of CDI  Effective rate: (a) 30% to 40% of CDI                           (e) 80.1% to 90% of CDI         (i) CDI + 0.73% (b) 40.1% to 50% of CDI                        (f) 100.1% to 110% of CDI      (J) Fixed rate 10.57% (c) 60.1% to 70% of CDI                        (g) 110.1% to 120% of CDI     (k) 130.01% to 140% of CDI (d) 70.1% to 80% of CDI                        (h) 120.1% to 130% of CDI     (l) 50.1% to 60% of CDI  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, 2016, the total balance of the borrowings measured at fair value was R$5,502,211 (R$ 6,940,180 as of December 31, 2015). Changes in the fair values of these borrowings are recognized in the finance income/cost of the the Company and its subsidiaries. Accumulated gains of R$ 37,415 (R$ 312,249 at December 31, 2015) on marking the borrowings to market, added to gains of R$24,504 (losses of R$ 184,518 at December 31, 2015) 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$ 61,919 (R$ 127,731 at December 31, 2015). The maturities of the principal of borrowings recorded in non current liabilities are scheduled as follows:   F - 46


---



2018

   

   4,034,9722019

   

   2,784,4862020

   

   1,356,4672021

   

   688,6452022

   

   489,4412023 to 2027

   

   1,230,2022028 to 2032

   

   458,8992033 to 2037

   

   16,225Subtotal

   

   11,059,336Mark to market

   

   (35,651)Total

   

   11,023,685
  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

   

   2016

   

   2015

   

   Dec 31, 2016

   

   Dec 31, 2015IGP-M

   

   7.17

   

   10.54

   

   0.53

   

   0.50UMBND

   

   (16.30)

   

   47.00

   

   0.38

   

   0.49TJLP

   

   7.50

   

   6.21

   

   31.48

   

   27.67CDI

   

   13.63

   

   13.18

   

   56.31

   

   61.60Others

   

   

   

   

   

   11.31

   

   9.74100.00

   

   100.00
    F - 47


---



Main borrowings in the year:  R$ thousandCompany

   

   Bank / credit issue

   

   Total approved

   

   Released in 2016

   

   Released net of fundraising costs

   

   Interest

   

   UtilizationLocal currencyInvestmentCPFL Paulista

   

   FINEM VII

   

   427,716

   

   27,075

   

   26,421

   

   Quarterly

   

   Subsidiary's investment planCPFL Piratininga

   

   FINEM VI

   

   194,862

   

   7,866

   

   7,586

   

   Quarterly

   

   Subsidiary's investment planRGE

   

   FINEM VII

   

   266,790

   

   21,125

   

   20,740

   

   Quarterly

   

   Subsidiary's investment planCPFL Serviços

   

   FINAME (a)

   

   12,277

   

   11,886

   

   11,886

   

   Quarterly

   

   Subsidiary's investment planCPFL Esco

   

   FINAME (a)

   

   1,543

   

   1,525

   

   1,525

   

   Quarterly

   

   Subsidiary's investment planCPFL Renováveis

   

   FINEM XIII

   

   379,948

   

   38,873

   

   38,873

   

   Monthly

   

   Subsidiary's investment planCPFL Renováveis

   

   FINEM XXVII

   

   69,103

   

   67,628

   

   67,628

   

   Monthly

   

   Subsidiary's investment planCPFL Renováveis

   

   FINEM XXVI

   

   764,109

   

   219,028

   

   218,370

   

   Monthly

   

   Subsidiary's investment planCPFL Renováveis

   

   FINEM XXV

   

   84,338

   

   6,676

   

   6,676

   

   Monthly

   

   Subsidiary's investment planFinancial institutionsCPFL Sul Paulista

   

   Banco IBM - Bank credit notes (a)

   

   6,459

   

   6,459

   

   6,459

   

   Semiannually

   

   Working capital improvementCPFL Transmissão Morro Agudo

   

   Santander / Bank credit notes (a)

   

   5,000

   

   5,000

   

   5,000

   

   With the principal

   

   Working capital improvementCPFL Renováveis: Alto Irani

   

   Banco Safra / Redeemable preferred shares of the subsidiary Alto Irani (a)

   

   75,000

   

   75,000

   

   73,416

   

   Semiannually

   

   Subsidiary's investment planCPFL Renováveis: Plano Alto

   

   Banco Safra / Redeemable preferred shares of the subsidiary Plano Alto (a)

   

   55,000

   

   55,000

   

   53,838

   

   Semiannually

   

   Subsidiary's investment planCPFL Renováveis - Parent company

   

   Banco BBM - Bank credit notes (a)

   

   44,000

   

   44,000

   

   44,000

   

   With the principal

   

   Working capital improvementCPFL Renováveis - Parent company

   

   Banco ABC - Bank credit notes (a)

   

   44,000

   

   44,000

   

   44,000

   

   With the principal

   

   Subsidiary's investment planCPFL Renováveis - Parent company

   

   Banco ABC - Promissory notes (a)

   

   100,000

   

   100,000

   

   99,294

   

   Semiannually

   

   Working capital improvementCPFL Renováveis: Figueirópolis

   

   Banco Safra / Redeemable preferred shares of the subsidiary Figueirópolis (a)

   

   70,000

   

   70,000

   

   68,521

   

   Semiannually

   

   Subsidiary's investment plan2,600,145

   

   801,141

   

   794,233Foreign currencyFinancial institutionsCPFL Paulista

   

   Syndicalized transaction: Bank of America Merrill Lynch, Citibank, HSBC and EDC / Law 4.131

   

   236,127

   

   236,127

   

   232,458

   

   Quarterly

   

   Working capital improvementCPFL Piratininga

   

   Syndicalized transaction: Bank of America Merrill Lynch, Citibank, HSBC and EDC / Law 4.131

   

   236,127

   

   236,127

   

   232,461

   

   Quarterly

   

   Working capital improvementRGE

   

   Syndicalized transaction: Bank of America Merrill Lynch, Citibank, HSBC and EDC / Law 4.131

   

   236,127

   

   236,127

   

   232,461

   

   Quarterly

   

   Working capital improvementCPFL Santa Cruz

   

   Scotiabank / Law 4.131

   

   16,484

   

   16,484

   

   16,484

   

   Semiannually

   

   Working capital improvementCPFL Leste Paulista

   

   Scotiabank / Law 4.131

   

   16,484

   

   16,484

   

   16,484

   

   Semiannually

   

   Working capital improvementCPFL Sul Paulista

   

   Scotiabank / Law 4.131

   

   16,484

   

   16,484

   

   16,484

   

   Semiannually

   

   Working capital improvementCPFL Jaguari

   

   Scotiabank / Law 4.131

   

   16,484

   

   16,484

   

   16,484

   

   Semiannually

   

   Working capital improvementCPFL Geração

   

   Scotiabank / Law 4.131

   

   117,036

   

   117,036

   

   117,036

   

   Semiannually

   

   Working capital improvementCPFL Geração

   

   Scotiabank / Law 4.131

   

   174,525

   

   174,525

   

   174,525

   

   Semiannually

   

   Working capital improvementCPFL Geração

   

   Citibank / Law 4.131

   

   397,320

   

   397,320

   

   397,320

   

   Quarterly

   

   Working capital improvementCPFL Geração

   

   CCB China / Law 4.131 (a)

   

   137,071

   

   137,071

   

   137,071

   

   Quarterly

   

   Working capital improvement1,600,269

   

   1,600,269

   

   1,589,2694,200,414

   

   2,401,411

   

   2,383,502
  (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 Maintaining, by the indirect subsidiary, the borrowings from theBNDES raised by the indirect subsidiary CERANestablish: ·Maintaining the debt service coverage ratio at 1.3 during the amortization period;   F - 48


---



·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. As of December 31, 2016 the indirect subsidiaries SPE Ninho da Águia Energia S.A., SPE Paiol Energia S.A. and SPE Várzea Alegre Energia S.A (subsidiaries of CPFL Renováveis) had not complied with the debt coverage ratio (ICSD), which requires cash generation of 1.2 times the debt service amount for the period. The total amount of the debts, R$ 87,376, was classified in current liabilities. Early maturity of the debt due to non-compliance with the debt coverage ratio agreed was not declared at December 31, 2016 and on March 7, 2017, the subsidiaries obtained a waiver from BNDES to determine the debt coverage ratio for the second semester of  2016. Failure to comply with the covenant also did not result in early maturity of other debts with specific cross-default conditions. 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. 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. FINEM XI and FINEM XXIV   F - 49


---



·Maintaining a Net Bank Debt/EBITDA ratio of 3.75 or less, determined in the Company's annual consolidated financial statements. FINEM XII ·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 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 annual 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. 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 2016, the Company obtained from BNDES approval for non-compliance  with the Net Debt/EBITDA ratio without the acceleration of the debt maturity for the year ended December 31, 2016.  FINEM XXVII ·Maintenance of Debt Service Coverage Ratio of 1.2 or more; ·Maintenance of an Equity / Asset ratio of 39.5% or more 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.   F - 50


---



Foreign currency borrowings - Bank of America Merrill Lynch, J.P. Morgan, Citibank, Scotiabank, Bank of Tokyo-Mitsubishi, Santander, Sumitomo, Mizuho, HSBC, BNP Paribasand Syndicated transaction(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. For purposes of determining covenants, the definition of EBITDA for the Company takes into consideration mainly the consolidation of direct and indirect 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 were subject to acceleration of their maturities in the event of any changes in the Company’s shareholding structure, except if at least one of the following shareholders, Camargo Corrêa and Previ, remained directly or indirectly in the Company’s control block. In view of the change of the Company’s shareholding control in January 2017, the Company negotiated previously with the creditors of the Company and its direct and indirect subsidiaries the non-acceleration of the maturities of such borrowings, which started including State Grid International Development Limited or any entity directly or indirectly controlled by State Grid Corporation of China as exception for non-acceleration of their maturities. 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 financial and non financial covenants and clauses are adequately complied with, except as mentioned previously in relation to the indirectly-controlled entity CPFL Renováveis, at December 31, 2016.  F - 51


---



( 18 )DEBENTURES AND INTERESTS ON DEBENTURES
   December 31, 2016

   

   December 31, 2015Issue

   

   Current and noncurrent interest

   

   Current

   

   Noncurrent

   

   Total

   

   Current and noncurrent interest

   

   Current

   

   Noncurrent

   

   TotalParent company5th Issue

   Single series

   

   18,069

   

   -

   

   620,000

   

   638,069

   

   -

   

   -

   

   -

   

   -CPFL Paulista6th Issue

   Single series

   

   47,079

   

   198,000

   

   462,000

   

   707,079

   

   47,292

   

   -

   

   660,000

   

   707,2927th Issue

   Single series

   

   28,913

   

   -

   

   505,000

   

   533,913

   

   29,546

   

   -

   

   505,000

   

   534,546CPFL Piratininga6th Issue

   Single series

   

   7,846

   

   33,000

   

   77,000

   

   117,846

   

   7,882

   

   -

   

   110,000

   

   117,8827th Issue

   Single series

   

   13,455

   

   -

   

   235,000

   

   248,455

   

   13,749

   

   -

   

   235,000

   

   248,749RGE6th Issue

   Single series

   

   35,666

   

   150,000

   

   350,000

   

   535,666

   

   35,828

   

   -

   

   500,000

   

   535,8287th Issue

   Single series

   

   9,733

   

   -

   

   170,000

   

   179,733

   

   9,946

   

   -

   

   170,000

   

   179,946RGE Sul4th Issue

   Single series

   

   32,058

   

   -

   

   1,100,000

   

   1,132,058

   

   -

   

   -

   

   -

   

   -CPFL Santa Cruz1st Issue

   Single series

   

   550

   

   32,500

   

   32,500

   

   65,550

   

   568

   

   -

   

   65,000

   

   65,568CPFL Brasil2nd Issue

   Single series

   

   -

   

   -

   

   -

   

   -

   

   2,794

   

   -

   

   228,000

   

   230,7943rd Issue

   Single series

   

   11,657

   

   -

   

   400,000

   

   411,657

   

   -

   

   -

   

   -

   

   -CPFL Geração5th Issue

   Single series

   

   12,969

   

   546,000

   

   546,000

   

   1,104,969

   

   13,382

   

   -

   

   1,092,000

   

   1,105,3826th Issue

   Single series

   

   23,228

   

   -

   

   460,000

   

   483,228

   

   23,531

   

   -

   

   460,000

   

   483,5317th Issue

   Single series

   

   16,379

   

   -

   

   635,000

   

   651,379

   

   16,770

   

   -

   

   635,000

   

   651,7708th Issue

   Single series

   

   3,369

   

   -

   

   85,520

   

   88,889

   

   3,153

   

   -

   

   80,024

   

   83,1779th Issue

   Single series

   

   524

   

   -

   

   50,278

   

   50,802CPFL Renováveis1st Issue - SIIF (*)

   1st to 12th series

   

   762

   

   41,938

   

   461,314

   

   504,014

   

   788

   

   38,965

   

   467,577

   

   507,3291st Issue - PCH Holding 2

   Single series

   

   644

   

   8,700

   

   132,091

   

   141,435

   

   616

   

   8,701

   

   140,792

   

   150,1091st Issue - CPFL Renováveis

   Single series

   

   6,160

   

   43,000

   

   322,500

   

   371,660

   

   6,579

   

   43,000

   

   365,500

   

   415,0792nd Issue - CPFL Renováveis

   Single series

   

   11,486

   

   30,000

   

   270,000

   

   311,486

   

   11,894

   

   -

   

   300,000

   

   311,8943rd Issue - CPFL Renováveis

   Single series

   

   4,444

   

   -

   

   296,000

   

   300,444

   

   4,589

   

   -

   

   296,000

   

   300,5894th Issue - CPFL Renováveis

   1st series

   

   7,925

   

   -

   

   200,000

   

   207,925

   

   -

   

   -

   

   -

   

   -1st Issue - DESA

   Single series

   

   425

   

   17,500

   

   -

   

   17,925

   

   862

   

   17,500

   

   17,500

   

   35,8622nd Issue - DESA

   Single series

   

   29,153

   

   -

   

   65,000

   

   94,153

   

   16,487

   

   -

   

   65,000

   

   81,4871st Issue - Turbina 16

   Single series

   

   -

   

   -

   

   -

   

   -

   

   1,810

   

   277,200

   

   -

   

   279,0101st Issue - Campos dos Ventos V

   Single series

   

   -

   

   -

   

   -

   

   -

   

   374

   

   42,000

   

   -

   

   42,3741st Issue - Santa Úrsula

   Single series

   

   -

   

   -

   

   -

   

   -

   

   275

   

   30,800

   

   -

   

   31,0751st Issue - Pedra Cheirosa I

   Single series

   

   6,675

   

   52,200

   

   -

   

   58,875

   

   -

   

   -

   

   -

   

   -1st Issue - Pedra Cheirosa II

   Single series

   

   6,114

   

   47,800

   

   -

   

   53,914

   

   -

   

   -

   

   -

   

   -1st Issue - Boa Vista II

   Single series

   

   6,395

   

   50,000

   

   -

   

   56,395

   

   -

   

   -

   

   -

   

   -80,183

   

   291,138

   

   1,746,905

   

   2,118,226

   

   44,274

   

   458,165

   

   1,652,369

   

   2,154,808Borrowing costs (**)

   

   

   (7,346)

   

   (8,545)

   

   (51,684)

   

   (67,575)

   

   -

   

   -

   

   (28,842)

   

   (28,842)334,333

   

   1,242,095

   

   7,423,519

   

   8,999,946

   

   248,714

   

   458,165

   

   6,363,552

   

   7,070,430(*) 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.
  F - 52


---



Issue

   

   Quantity issued

   

   Annual Remuneration

   

   Annualeffective rate

   

   Amortization conditions

   

   CollateralParent company5th Issue

   Single series

   

   62,000

   

   114.5% of CDI

   

   120.65% of CDI

   

   2 annual installments from October 2019

   

   No guaranteeCPFL 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 Piratininga6th 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 guaranteeRGE Sul4th Issue

   Single series

   

   110,000

   

   114.50% of CDI

   

   120.65% of CDI

   

   2 annual installments from October 2019

   

   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 guarantee3rd Issue

   Single series

   

   40,000

   

   114.5% of CDI

   

   124.04%% of CDI

   

   2 annual installments from October 2019

   

   CPFL Energia guaranteeCPFL Geração5th 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 guarantee9th Issue

   Single series

   

   50,000

   

   IPCA+ 5.48%

   

   101.74% of CDI

   

   1 installment in October 2021

   

   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 - CPFL 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 - CPFL Renováveis

   Single series

   

   300,000

   

   114.0% of CDI

   

   115.43% of CDI

   

   5 annual instalments from June 2017

   

   Unsecured3rd Issue - CPFL Renováveis

   Single series

   

   29,600

   

   117.25% of CDI

   

   120.64% of CDI

   

   1 installment in May 2020

   

   Unsecured4th Issue - CPFL Renováveis

   1st series

   

   20,000

   

   126% CDI

   

   134.22% CDI

   

   3 annual installments from September 2019

   

   CPFL Renováveis guarantee1st Issue - DESA

   Single series

   

   20

   

   CDI + 1.75%

   

   CDI + 1.75%

   

   3 semiannual installments from May de 2016

   

   Unsecured2nd Issue - DESA

   Single series

   

   65

   

   CDI + 1.34%

   

   CDI + 1.34%

   

   3 semiannual installments from April de 2018

   

   Unsecured1st Issue - Turbina 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 guarantee1st Issue - Pedra Cheirosa I

   Single series

   

   5,220

   

   CDI + 2.85%

   

   CDI + 2.85%

   

   1 installment in September 2017

   

   CPFL Renováveis guarantee1st Issue - Pedra Cheirosa II

   Single series

   

   4,780

   

   CDI + 2.85%

   

   CDI + 2.85%

   

   1 installment in September 2017

   

   CPFL Renováveis guarantee1st Issue - Boa Vista II

   Single series

   

   5,000

   

   CDI + 2.85%

   

   CDI + 2.85%

   

   1 installment in September 2017

   

   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:
  2018

   

   1,655,2272019

   

   3,000,7262020

   

   1,771,0962021

   

   595,3402022

   

   129,9202023 to 2027

   

   230,0952028 to 2032

   

   41,113Total

   

   7,423,519
 F - 53


---



Main debentures issuances during the year  Company

   

   Issue

   

   Quantity issued

   

   Released in 2016

   

   Released net of issuance costs

   

   Interest

   

   UtilizationCPFL Energia - Parent company

   

   5th Issue

   

   62,000

   

   620,000

   

   609,060

   

   Semiannual

   

   Indirect acquisition of RGE Sul sharesCPFL Brasil

   

   3rd Issue

   

   40,000

   

   400,000

   

   389,077

   

   Semiannual

   

   Indirect acquisition of RGE Sul sharesCPFL Geração

   

   9th Issue

   

   50,000

   

   50,000

   

   48,843

   

   Annual

   

   Subsidiary's investment planCPFL Renováveis: Pedra Cheirosa I (a)

   

   1st issue

   

   5,200

   

   52,200

   

   51,602

   

   With the principal

   

   Subsidiary's investment planCPFL Renováveis: Pedra Cheirosa II (a)

   

   1st issue

   

   4,780

   

   47,800

   

   47,251

   

   With the principal

   

   Subsidiary's investment planCPFL Renováveis: Boa Vista II (a)

   

   1st issue

   

   5,000

   

   50,000

   

   49,426

   

   With the principal

   

   Subsidiary's investment planCPFL Renováveis - parent company

   

   4th Issue

   

   20,000

   

   200,000

   

   195,589

   

   Semiannual

   

   Debt profile and working capital improvement1,420,000

   

   1,390,847
 (a) the agreement has no restrictive covenants.  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 Energia, CPFL Paulista, CPFL Piratininga, RGE, RGE Sul, CPFL Geração, 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, 2016 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 December 2015, through the General Meeting of Debentureholders held on December 21, 2015. ii.Debt Operational Service Coverage ratio related to the calculation of June 2016, through the General Meeting of Debentureholders held on June 30, 2016.  - 2nd and 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. - 4th issue of CPFL Renováveis ·Maintaining net indebtedness divided by EBITDA - maximum of 5.4 in 2016, 4.6 in 2017, 4.0 from 2018. F - 54


---



- 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/dividend 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.  Various debentures of the direct and indirect subsidiaries were subject to acceleration of their maturities in the event of any changes in the Company’s shareholding structure, except if at least one of the following shareholders, Camargo Corrêa and Previ, remained directly or indirectly in the Company’s control block. In view of the change of the Company’s shareholding control in January 2017, the Company negotiated previously with the creditors of the Company and its direct and indirect subsidiaries the non-acceleration of the maturities of such borrowings, which started including State Grid International Development Limited or any entity directly or indirectly controlled by State Grid Corporation of China as exception for non-acceleration of their maturities. 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 financial and non financial covenants and clauses are adequately complied with at December 31, 2016.  ( 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  
 F - 55


---



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. 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 Fundação CEEE. 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. - RGE Sul Supplementary pension plans for its employees, former employees and related beneficiaries, managed by CEEE. The Single Plan is of the “defined benefit” type and is closed to new participants since February 2011. The Company’s contribution equates the contribution of the benefitted employees, in the proportion of one for one, including regarding the Fundação’s administrative costing plan. Currently the Itauprev plan is in effect, structured in the modality of defined contribution. - 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.   
 F - 56


---



19.2 – Changes in the defined benefit plans   December 31, 2016CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalPresent value of actuarial obligations

   

   4,524,008

   

   1,202,596

   

   108,486

   

   352,879

   

   480,081

   

   6,668,050Fair value of plan's assets

   

   (3,723,563)

   

   (1,062,638)

   

   (89,533)

   

   (347,906)

   

   (405,251)

   

   (5,628,892)Net actuarial liability recognized in the statement of financial position

   

   800,445

   

   139,958

   

   18,953

   

   4,972

   

   74,830

   

   1,039,158December 31, 2015CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalPresent 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

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalPresent 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)Net actuarial liability recognized in the statement of financial position

   

   505,140

   

   73,383

   

   3,261

   

   6,264

   

   -

   

   588,048
   The changes in the present value of the actuarial obligations and the fair value of the plan’s assets are as follows:
  CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalPresent 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

   

   -

   

   5,124,182Business combination

   

   -

   

   -

   

   -

   

   -

   

   474,710

   

   474,710Gross current service cost

   

   828

   

   3,242

   

   76

   

   59

   

   365

   

   4,570Interest on actuarial obligations

   

   467,872

   

   121,158

   

   11,184

   

   35,211

   

   8,469

   

   643,894Participants' contributions transferred during the year

   

   59

   

   2,020

   

   -

   

   319

   

   165

   

   2,563Actuarial loss: effect of changes in demographic assumptions

   

   -

   

   -

   

   -

   

   3,602

   

   -

   

   3,602Actuarial loss: effect of changes in financial assumptions

   

   619,803

   

   193,652

   

   14,909

   

   57,793

   

   3,613

   

   889,770Benefits paid during the year

   

   (357,813)

   

   (78,805)

   

   (8,292)

   

   (23,090)

   

   (7,241)

   

   (475,241)Present value of actuarial obligations at December 31, 2016

   

   4,524,008

   

   1,202,596

   

   108,486

   

   352,879

   

   480,081

   

   6,668,050
   F - 57


---



CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalFair 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)Business combination

   

   -

   

   -

   

   -

   

   -

   

   (415,621)

   

   (415,621)Expected return during the year

   

   (404,183)

   

   (115,607)

   

   (9,582)

   

   (35,632)

   

   (7,470)

   

   (572,474)Participants' contributions transferred during the year

   

   (59)

   

   (2,020)

   

   -

   

   (319)

   

   (165)

   

   (2,563)Sponsors' contributions

   

   (48,263)

   

   (13,405)

   

   (843)

   

   (9,441)

   

   (1,437)

   

   (73,389)Actuarial loss (gain)

   

   (273,282)

   

   (59,390)

   

   (7,068)

   

   (38,403)

   

   12,201

   

   (365,942)Benefits paid during the year

   

   357,813

   

   78,805

   

   8,292

   

   23,090

   

   7,241

   

   475,241Fair value of actuarial assets at December 31, 2016

   

   (3,723,563)

   

   (1,062,638)

   

   (89,533)

   

   (347,906)

   

   (405,251)

   

   (5,628,892)
   F - 58


---



19.3 Changes in the recognized assets and liabilities The changes in net liability are as follows:  CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalNet actuarial liability at December 31, 2013

   

   364,085

   

   44,895

   

   -

   

   3,046

   

   -

   

   412,026Expenses (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

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalNet 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 demographic assumptions

   

   (226)

   

   (614)

   

   (12)

   

   (6)

   

   -

   

   (858)Actuarial loss: effect of changes in financial 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
 CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   Total liabilitiesNet actuarial liability at December 31, 2015

   

   437,670

   

   10,308

   

   10,277

   

   -

   

   -

   

   458,255Business combination

   

   -

   

   -

   

   -

   

   -

   

   59,089

   

   59,089Expenses (income) recognized in the statement of profit or loss

   

   64,514

   

   8,791

   

   1,677

   

   158

   

   1,364

   

   76,505Sponsors' contributions transferred during the year

   

   (48,263)

   

   (13,405)

   

   (843)

   

   (9,442)

   

   (1,437)

   

   (73,388)Actuarial loss: effect of changes in demographic assumptions

   

   -

   

   -

   

   -

   

   3,602

   

   -

   

   3,602Actuarial loss: effect of changes in financial assumptions

   

   346,523

   

   134,263

   

   7,843

   

   19,392

   

   15,813

   

   523,834Effect of asset ceiling

   

   -

   

   -

   

   -

   

   (8,738)

   

   -

   

   (8,738)Net actuarial liability at December 31, 2016

   

   800,445

   

   139,958

   

   18,954

   

   4,972

   

   74,830

   

   1,039,158Other contributions

   

   12,914

   

   133

   

   8

   

   228

   

   -

   

   13,284Total liability

   

   813,359

   

   140,091

   

   18,962

   

   5,200

   

   74,830

   

   1,052,442Current

   

   

   

   

   

   

   

   

   

   

   

   33,209Noncurrent

   

   

   

   

   

   

   

   

   

   

   

   1,019,233
  19.4Expected contributions and benefits The expected contributions to the plans for 2017 are shown below:  2017CPFL Paulista

   75,920CPFL Piratininga

   21,375CPFL Geração

   1,606RGE

   9,914RGE Sul

   9,053Total

   117,868
   The subsidiaries CPFL Paulista, CPFL Piratininga and CPFL Geração 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.    F - 59


---



The expected benefits to be paid by the plan administrators in the next 10 years are shown below:  2017

   

   2018

   

   2019

   

   2020

   

   2021 to 2026

   

   TotalCPFL Paulista

   374,441

   

   390,441

   

   407,979

   

   424,542

   

   2,869,228

   

   4,466,631CPFL Piratininga

   83,797

   

   88,712

   

   94,257

   

   99,111

   

   713,424

   

   1,079,301CPFL Geração

   8,941

   

   9,408

   

   9,745

   

   10,173

   

   68,181

   

   106,448RGE

   25,229

   

   27,041

   

   28,632

   

   30,051

   

   212,032

   

   322,985RGE Sul

   33,377

   

   35,368

   

   37,554

   

   39,607

   

   285,256

   

   431,162Total

   525,785

   

   550,970

   

   578,167

   

   603,484

   

   4,148,121

   

   6,406,527
  At December 31, 2016, the average duration of the defined benefit obligation was 9.1 years for CPFL Paulista, 10.7 years for CPFL Piratininga, 9.3 years for CPFL Geração, 10.2 years for RGE and 10.6 years for RGE Sul.  19.5 Recognition of private pension plan income and expense The external actuary’s estimate of the expenses (income) to be recognized in 2017 and the expense (income) recognized in 2016, 2015 and 2014 is as follows:  2017 EstimatedCPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   TotalService cost

   

   707

   

   3,153

   

   73

   

   270

   

   2,153

   

   6,356Interest on actuarial obligations

   

   476,613

   

   127,561

   

   11,431

   

   37,395

   

   50,927

   

   703,927Expected return on plan assets

   

   (392,819)

   

   (113,470)

   

   (9,437)

   

   (37,412)

   

   (43,258)

   

   (596,396)Total expense (income)

   

   84,501

   

   17,244

   

   2,067

   

   253

   

   9,822

   

   113,887
 2016 ActualCPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul*

   

   TotalService cost

   

   828

   

   3,242

   

   76

   

   59

   

   365

   

   4,570Interest on actuarial obligations

   

   467,872

   

   121,158

   

   11,184

   

   35,211

   

   8,469

   

   643,894Expected return on plan assets

   

   (404,184)

   

   (115,608)

   

   (9,582)

   

   (35,632)

   

   (7,470)

   

   (572,476)Effect of asset ceiling

   

   -

   

   -

   

   -

   

   520

   

   -

   

   520Total expense (income)

   

   64,514

   

   8,791

   

   1,677

   

   158

   

   1,364

   

   76,505 (*) The expenses and income presented for RGE Sul are related to November and December 2016.




2015 ActualCPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   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)

   

   -

   

   60,184


2014 ActualCPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

   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)

   

   -

   

   48,165




F - 60



---



The main assumptions taken into consideration in the actuarial calculation at the end of the reporting period were as follows:  CPFL Paulista, CPFL Geração and CPFL Piratininga

   

   RGE

   

   RGE SulDec. 31, 2016

   

   Dec. 31, 2015

   

   Dec. 31, 2014

   

   Dec. 31, 2016

   

   Dec. 31, 2015

   

   Dec. 31, 2014

   

   Dec. 31, 2016Nominal discount rate for actuarial liabilities:

   

   10.99% p.a.

   

   12.67% p.a.

   

   11.46% p.a.

   

   10.99% p.a.

   

   12.67% p.a.

   

   11.46% p.a.

   

   10.99% p.a.Nominal Return Rate on Assets:

   

   10.99% p.a.

   

   12.67% p.a.

   

   11.46% p.a.

   

   10.99% p.a.

   

   12.67% p.a.

   

   11.46% p.a.

   

   10.99% p.a.Estimated Rate of nominal salary increase:

   

   7% p.a.

   

   6.79% p.a.

   

   8.15% p.a.

   

   8.15% p.a.

   

   6.79% p.a.

   

   8.15% p.a.

   

   7.29% p.a.Estimated Rate of nominal benefits increase:

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.Estimated long-term inflation rate (basis for determining the nominal rates above)

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.

   

   5% p.a.General biometric mortality table:

   

   AT-2000 (-10)

   

   AT-2000 (-10)

   

   AT-2000 (-10)

   

   BR-EMS sb v.2015

   

   AT-2000 (-10)

   

   AT-2000 (-10)

   

   AT-2000Biometric table for the onset of disability:

   

   Low Light

   

   Low Light

   

   Low Light

   

   Medium Light

   

   Low Light

   

   Low Light

   

   Medium LightExpected turnover rate:

   

   ExpR_2012*

   

   ExpR_2012*

   

   ExpR_2012**

   

   Null

   

   ExpR_2012*

   

   ExpR_2012**

   

   NullLikelihood 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

   

   100% one year after 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

   

   100% one year after when a beneficiary of the plan first becomes eligible(*) FUNCESP experience, with aggravation of 40%(**) FUNCESP experience
   19.6 Plan assets The following tables show the allocation (by asset segment) of the assets of the CPFL ́s Group pension plans, at December 31, 2016 and 2015 managed by Fundação CESP and Fundação CEEE. The tables also show the distribution of the guarantee resources established as target for 2017, obtained in light of the macroeconomic scenario in December 2016. Assets managed by the plans are as follows:  Assets managed by Fundação CESP

   

   Assets managed by Fundação CEEECPFL Paulista and CPFL Geração

   

   CPFL Piratininga

   

   RGE

   

   RGE Sul2016

   

   2015

   

   2016

   

   2015

   

   2016

   

   2015

   

   2016Fixed rate

   

   79%

   

   80%

   

   83%

   

   84%

   

   76%

   

   73%

   

   74%Federal governament bonds

   

   60%

   

   57%

   

   56%

   

   54%

   

   61%

   

   56%

   

   60%Corporate bonds (financial institutions)

   

   6%

   

   5%

   

   10%

   

   10%

   

   8%

   

   4%

   

   8%Corporate bonds (non financial institutions)

   1%

   

   1%

   

   1%

   

   1%

   

   4%

   

   5%

   

   4%Multimarket funds

   

   1%

   

   16%

   

   1%

   

   19%

   

   3%

   

   8%

   

   3%Other fixed income investments

   

   12%

   

   1%

   

   15%

   

   -

   

   -

   

   -

   

   -Variable income

   

   14%

   

   13%

   

   12%

   

   12%

   

   15%

   

   14%

   

   16%CPFL Energia's shares

   

   8%

   

   5%

   

   6%

   

   4%

   

   -

   

   -

   

   -Investiment funds - shares

   

   6%

   

   8%

   

   7%

   

   8%

   

   15%

   

   14%

   

   16%Structured investments

   

   1%

   

   -

   

   1%

   

   -

   

   8%

   

   11%

   

   8%Equity funds

   

   -

   

   -

   

   -

   

   -

   

   7%

   

   10%

   

   7%Real estate funds

   

   -

   

   -

   

   -

   

   -

   

   1%

   

   1%

   

   1%Multimarket fund

   

   1%

   

   -

   

   1%

   

   -

   

   -

   

   -

   

   -Total quoted in an active market

   

   94%

   

   93%

   

   97%

   

   96%

   

   99%

   

   98%

   

   98%Real estate

   

   3%

   

   4%

   

   2%

   

   2%

   

   1%

   

   1%

   

   1%Transactions with participants

   

   1%

   

   2%

   

   2%

   

   2%

   

   1%

   

   1%

   

   2%Other investments

   

   1%

   

   1%

   

   -

   

   -

   

   -

   

   -

   

   -Escrow deposits and others

   

   1%

   

   1%

   

   -

   

   -

   

   -

   

   -

   

   -Total not quoted in an active market

   

   6%

   

   7%

   

   3%

   

   4%

   

   1%

   

   2%

   

   2%
    F - 61


---



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$417,058 (R$ 245,380 at December 31, 2015).  Target for 2017Fundação CESP

   

   Fundação CEEECPFL Paulista and CPFL Geração

   

   CPFL Piratininga

   

   RGE

   

   RGE SulFixed income investments

   77.1%

   

   80.4%

   

   80.0%

   

   78.0%Variable income investments

   14.4%

   

   12.2%

   

   15.0%

   

   16.0%Real estate

   3.4%

   

   1.6%

   

   1.0%

   

   1.0%Transactions with participants

   1.5%

   

   1.8%

   

   1.0%

   

   2.0%Structured investments

   2.3%

   

   2.3%

   

   3.0%

   

   3.0%Investments abroad

   1.3%

   

   1.7%

   

   0.0%

   

   0.0%Total

   100.0%

   

   100.0%

   

   100.0%

   

   100.0%
 The allocation target for 2017 was based on the recommendations for allocation of assets made at the end of 2016 by Fundação CESP and Fundação CEEE, in their Investment Policy. This target may change at any time during 2017, 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. Fundação CESP and Fundação CEEE conduct studies of Asset Liability Management at least once a year, for a horizon longer than ten years. The ALM study also represents an important tool for the liquidity risk management of the pension plans since it considers the payment flow of benefits versus the assets considered liquid. 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

   

   RGE Sul

   

   TotalDefined benefit plan obligation

   

   

   4,524,008

   

   1,202,596

   

   108,486

   

   352,879

   

   480,081

   

   6,668,050Increase (Decrease)

   

   CPFL Paulista

   

   CPFL Piratininga

   

   CPFL Geração

   

   RGE

   

   RGE Sul

   

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

   

   

   -0.25 p.p.

   

   104,645

   

   32,642

   

   2,565

   

   9,082

   

   12,933

   

   161,867+0.25 p.p.

   

   (100,503)

   

   (31,174)

   

   (2,460)

   

   (8,694)

   

   (12,346)

   

   (155,177)General biometric mortality table**

   

   

   +1 year

   

   (92,886)

   

   (19,346)

   

   (2,132)

   

   (5,666)

   

   (8,549)

   

   (128,578)-1 year

   

   90,954

   

   18,750

   

   2,091

   

   5,484

   

   8,299

   

   125,577
 * The assumption considered in the actuarial report for the nominal discount rate was 10.99% p.a. for all subsidiaries shown in the table above. The projected rates are increased or decreased by 0.25 p.p. to 10.74% p.a. and 11.24% p.a.. ** The assumption considered in the actuarial report for the mortality table was AT-2000 (-10) for CPFL Paulista, CPFL Piratininga and CPFL Geração; BREMS sb v.2015 for RGE and AT-2000 for RGE Sul. The projections were performed with 1 year of aggravation or softening on the respective mortality tables. F - 62


---



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. 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 CEEE 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 CEEE 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
  Dec 31, 2016

   

   Dec 31, 2015Fee for the use of water resources

   

   1,385

   

   2,482Global reversal reserve - RGR

   

   17,469

   

   17,446ANEEL inspection fee - TFSEE

   

   2,044

   

   1,764Energy development account - CDE

   

   309,117

   

   526,196Tariff flags and others

   

   36,064

   

   304,129Total

   

   366,078

   

   852,017
 Energy development account – CDE: refer to the (i) annual CDE quota for the year 2016 in the amount of R$ 164,681 (R$ 401,347 as at December 31, 2015); (ii) quota intended for the reimbursement of the CDE injection for the period from January 2013 to January 2014 in the amount of R$ 44,622 (R$ 45,618 in December 31, 2015); and (iii) quota intended for the reimbursement of the injection into the Regulated Contracting Environment (ACR account) for the period from February to December 2014, in the amount of R$ 99,814 (R$ 79,231 in December 31, 2015). The subsidiaries conducted matching of accounts between the amount of CDE payable and the Accounts Receivable – Eletrobras (note 12) in 2016, in the amount of R$ 869,717. Tariff flags and others: refer basically to the amount to be passed on to the Centralizing Account for Tariff Flag Resources (“CCRBT”).  F - 63


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( 21 )TAXES, FEES AND CONTRIBUTIONS
  Dec 31, 2016

   

   Dec 31, 2015CurrentICMS (State VAT)

   

   416,096

   

   384,151PIS (tax on revenue)

   

   28,759

   

   33,199COFINS (tax on revenue)

   

   126,939

   

   159,317IRPJ (corporate income tax)

   

   42,793

   

   30,751CSLL (social contribution on net income)

   

   14,434

   

   12,498Other

   

   52,522

   

   33,427Total

   

   681,544

   

   653,342NoncurrentPIS / COFINS - installment

   

   26,814

   

   -
  ( 22 )PROVISION FOR TAX, CIVIL AND LABOR RISKS AND ESCROW DEPOSITS
  December 31, 2016

   

   December 31, 2015Provision for tax, civil and labor risks

   

   EscrowDeposits

   

   Provision for tax, civil and labor risks

   

   EscrowDepositsLaborVarious

   222,001

   

   110,147

   

   171,989

   

   78,345CivilVarious

   236,915

   

   114,214

   

   194,530

   

   112,909TaxFINSOCIAL

   32,372

   

   90,951

   

   29,917

   

   84,092Income Tax

   142,790

   

   150,439

   

   138,524

   

   886,271Others

   113,227

   

   84,091

   

   15,920

   

   63,600288,389

   

   325,481

   

   184,362

   

   1,033,964Others

   85,971

   

   229

   

   18,654

   

   2,310Total

   833,276

   

   550,072

   

   569,534

   

   1,227,527
 The changes in the provision for tax, civil, labor and other risks are shown below:  Dec 31, 2015

   

   Additions

   

   Reversals

   

   Payments

   

   Monetary Restatements

   

   Business combination

   

   Dec 31, 2016Labor

   171,989

   

   114,403

   

   (56,710)

   

   (104,254)

   

   20,416

   

   76,156

   

   222,001Civil

   194,530

   

   105,424

   

   (51,246)

   

   (105,870)

   

   30,080

   

   63,998

   

   236,915Tax

   184,362

   

   81,776

   

   (13,006)

   

   (1,122)

   

   20,457

   

   15,922

   

   288,389Others

   18,654

   

   12,362

   

   (8,880)

   

   (5,757)

   

   2,286

   

   67,307

   

   85,971Total

   569,534

   

   313,965

   

   (129,843)

   

   (217,003)

   

   73,239

   

   223,383

   

   833,276
  The additions in provisions for tax risks, made in 2016, refer basically to discussions by certain subsidiaries about the levy of PIS and COFINS on finance income.
 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).  F - 64


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b)Civil Bodily injury –refer mainlyto claims for indemnities relating to accidents in the Company's 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$139,957 (R$ 129,907 at December 31, 2015) 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. The line item of “others” refers mainly to lawsuits involving regulatory matters. Possible losses 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. 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, 2016 and 2015, were as follows:  Dec. 31, 2016

   

   Dec. 31, 2015

   

   Main reasons for claimsLabor

   668,005

   

   659,636

   

   Work accidents, risk premium for dangerousness at workplace and overtimeCivil

   1,004,279

   

   697,242

   

   Personal injury, environmental impacts and overfed tariffsTax

   4,611,077

   

   3,600,368

   

   ICMS, FINSOCIAL, PIS and COFINS, and Income taxRegulatory

   93,827

   

   71,514

   

   Technical, commercial and economic-financial supervisionsTotal

   6,377,188

   

   5,028,760
  Tax –there is a discussion relating to the deductibility for income tax expense recognized in 1997 relating to the commitment assumed in regard to the pension plan of employees of subsidiary CPFL Paulista with Fundação CESP in the estimated amount of R$ 1,130,820, since it was subject to renegotiation and novation of debt in  that year. The subsidiary, based on an inquiry to the Brazilian Federal Revenue Service (RFB), obtained a favorable response included in Note MF/SRF/COSIT/GAB No. 157 of April 9, 1998 and took the tax deductibility of the expense, consequently generating tax loss in that year. Despite the favorable response of the RFB, the subsidiary received tax infringement notices from the tax authorities and, in two tax lawsuits arising from these infringements, made escrow deposits. In January 2016, the Company obtained court decisions that authorized the replacement of the escrow deposits (R$ 745,903 as at December 31, 2015) with financial guarantees (letter of guarantee and performance bond), for which the withdrawals on behalf of the subsidiary 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 awaits judgment by the Federal Regional Court. Based on the updated position of the lawyers that conduct this case, Management’s opinion is that the risk of loss is possible. In August 2016, the subsidiary CPFL Renováveis received a tax legal proceeding notice in the amount of R$ 285,537 relating to the collection of Withholding Income Tax - IRRF on remuneration of capital gain incurred by parties resident and/or domiciled abroad, arising from the transaction of sale of Jantus SL, in December 2011, which the Company’s management, supported by the opinion of its outside legal counselors, classified  the likelihood of a favorable outcome as possible. The subsidiary CPFL Geração, in December 2016, received two (2) tax legal proceeding notices that, summed up, total R$ 316,372 relating to the collection of Corporate Income Tax - IRPJ and Social Contribution on Profit – CSLL relating to calendar year 2011, calculated on the alleged capital gain identified on the acquisition of ERSA Energias Renováveis S.A. and recording of differences from the fair value remeasurement of SMITA


Empreendimentos e Participações S.A., company acquired in a downstream merger, which the Company’s management, supported by its outside legal counselors, classified the likelihood of a favorable outcome as possible.   F - 65


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As regards to 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,which has been acknowledged by the TST (Superior Labor Court) in recent decisions. 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. 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

   

   Dec 31, 2016

   

   Dec 31, 2015

   

   Number of remaining installments

   

   Interest rateCERAN

   

   97,481

   

   92,581

   

   231

   

   IGP-M + 9.6% p.a.Current

   

   10,857

   

   9,457Noncurrent

   

   86,624

   

   83,124
 ( 24 )OTHER PAYABLES
  Current

   

   NoncurrentDec 31, 2016

   

   Dec 31, 2015

   

   Dec 31, 2016

   

   Dec 31, 2015Consumers and concessionaires

   73,864

   

   53,959

   

   44,711

   

   -Energy efficiency program - PEE

   257,622

   

   295,745

   

   58,798

   

   35,597Research & Development - P&D

   75,655

   

   84,943

   

   55,272

   

   36,426EPE/FNDCT/PROCEL (*)

   12,928

   

   6,181

   

   -

   

   -Reversion fund

   -

   

   -

   

   17,750

   

   17,750Advances

   163,054

   

   141,228

   

   8,029

   

   10,041Tariff discounts - CDE

   8,891

   

   54,749

   

   -

   

   -Provision for socio environmental costs and asset retirement

   13,703

   

   -

   

   61,828

   

   53,378Payroll

   16,951

   

   13,136

   

   -

   

   -Profit sharing

   56,215

   

   49,227

   

   11,400

   

   5,099Collections agreement

   69,793

   

   130,282

   

   -

   

   -Guarantees

   -

   

   -

   

   44,140

   

   28,531Business combination

   9,492

   

   29,935

   

   -

   

   -Others

   49,454

   

   45,587

   

   7,364

   

   4,326Total

   807,623

   

   904,971

   

   309,292

   

   191,148 (*) EPE - Energy research company; FNDCT - National scientific and technological development fund; and PROCEL - National Program for Electric Energy Savings
  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. The noncurrent asset refers to the sale made by the indirect subsidiary RGE Sul in the period from September 1, 2000 to December 31, 2002 (note 16). 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.   F - 66


---



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. Tariff discounts – CDE:refers to the difference between the tariff discount granted to consumers and the amounts received via the CDE. 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%.  ( 25 )EQUITY
 The shareholders’ interest in the Company’s equity at December 31, 2016 and 2015 is shown below (see note 38.1 Subsequent event – acquisition of the Company):  Number of sharesDecember 31, 2016

   

   December 31, 2015Shareholders

   Common shares

   

   Interest %

   

   Common shares

   

   Interest %BB Carteira Livre I FIA

   -

   

   -

   

   262,698,037

   

   26.45%Caixa de Previdência dos Funcionários do Banco do Brasil - Previ

   299,787,559

   

   29.45%

   

   29,756,032

   

   3.00%Camargo Correa S.A.

   5,897,311

   

   0.58%

   

   26,764

   

   0.00%ESC Energia S.A.

   234,086,204

   

   23.00%

   

   234,086,204

   

   23.57%Bonaire Participações S.A.

   1,249,386

   

   0.12%

   

   1,238,334

   

   0.12%Energia São Paulo FIA

   35,145,643

   

   3.45%

   

   146,463,379

   

   14.75%Fundação Petrobras de Seguridade Social - Petros

   28,056,260

   

   2.76%

   

   1,816,119

   

   0.18%Fundação Sistel de Seguridade Social

   37,070,292

   

   3.64%

   

   -

   

   0.00%Fundação Sabesp de Seguridade Social - Sabesprev

   696,561

   

   0.07%

   

   -

   

   0.00%Fundação CESP

   51,048,952

   

   5.02%

   

   -

   

   0.00%BNDES Participações S.A.

   68,592,097

   

   6.74%

   

   66,914,177

   

   6.74%Antares Holdings Ltda.

   16,967,165

   

   1.67%

   

   16,552,110

   

   1.67%Brumado Holdings Ltda.

   36,497,075

   

   3.59%

   

   35,604,273

   

   3.59%Executive Officers

   34,250

   

   0.00%

   

   105,672

   

   0.01%Other shareholders

   202,785,991

   

   19.92%

   

   197,753,114

   

   19.91%Total

   1,017,914,746

   

   100.00%

   

   993,014,215

   

   100.00%
  The Company’s capital is R$ 5,741,284, comprising 1,017,914,746 common shares, fully subscribed and paid in. The shares do not have nominal value and there are no treasury shares. Capital can be increased by issuing up to 500,000,000 new common shares.   F - 67


---



25.1Approval of capital increase and bonus in shares to be paid to shareholders – AGM/EGM On April 8, 2016, the Company disclosed to its shareholders and the market in general, through a Significant Event Notice, that its controlling shareholders had signed a term separating the shareholders agreement relating to the shares that would be delivered to them due to the share bonus process. At the Extraordinary General Meeting of April 29, 2016, 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$ 392,972, through the issuance of 24,900,531 common shares, which were distributed to shareholders as share bonus, pursuant to Article 169 of Law No. 6,404/76. 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 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, amounting to R$ 180,297 in 2014, and (iv) other movements with no change of control amounting to R$87. In accordance with IFRS 10, these effects were recognized as transactions between shareholders, directly in Equity. 25.3Earnings reserves Comprised of: i.Legal reserve, amounting to R$ 739,102; 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 write-off of the concession financial asset arising from disposal or corporate restructuring or 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 No. 6,404/76, until their financial realization. This statutory reserve amounts to R$ 702,928 at December 31, 2016 (R$ 585,450 at December 31, 2015). 25.4Accumulated other comprehensive income The accumulated other 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$ 431,713; ii.Private pension plan: The debt balance of R$ 666,346 refers to the effects of the actuarial gains and losses recognized directly in other comprehensive income, in accordance with IAS 19. 25.5Dividends The Annual and Extraordinary General Meeting held on April 29, 2016 approved the allocation of  the profit for 2015, with the proposal of a minimum mandatory dividend of R$ 205,423. Furthermore, in 2016 the Company proposed R$ 213,960 of minimum mandatory dividend, as set forth by Law 6,404/76, and R$ 7,820 of additional dividend, and for each share the amount of R$ 0.217876793 was attributed. In 2016, the Company paid R$ 204,717 relating basically to the minimum mandatory dividend for 2015.  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:  
 F - 68


---



2016Profit for the year - Parent company

   900,885Realization of comprehensive income

   25,778Prescribed dividends

   3,144Profit base for allocation

   929,807Legal reserve

   (45,044)Statutory reserve - concession financial asset

   (117,478)Statutory reserve - working capital improvement

   (545,505)Mandatory dividend

   (213,960)Additional dividend

   (7,820)
  In 2016, considering the current adverse economic scenario and the uncertainties regarding market projections for distribution companies, Company Management is proposing allocating R$ 545,505 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 – Changes in noncontrolling interests  CERAN

   

   CPFL Renováveis

   

   Paulista Lajeado

   

   TotalAs of 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)

   

   (62,734)Business combination

   

   -

   

   759,686

   

   -

   

   759,686Dividends

   

   (15,022)

   

   (7,417)

   

   (7,099)

   

   (29,538)Other movements

   

   -

   

   11,560

   

   (1)

   

   11,559As of 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)As of December 31, 2015

   

   234,271

   

   2,148,490

   

   73,182

   

   2,455,942Equity interests and voting capital

   

   35.00%

   

   48.39%

   

   40.07%Equity attributable to noncontrolling interests

   

   38,621

   

   (65,311)

   

   4,862

   

   (21,828)Dividends

   

   (9,172)

   

   (22,751)

   

   1,096

   

   (30,827)Other movements

   

   -

   

   535

   

   (1,176)

   

   (641)As of December 31, 2016

   

   263,719

   

   2,060,963

   

   77,966

   

   2,402,648Equity interests and voting capital

   

   35.00%

   

   48.40%

   

   40.07%
 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, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014 are as follows:  F - 69


---



December 31, 2016CERAN

   

   CPFL Renováveis

   

   Paulista LajeadoCurrent assets

   

   288,538

   

   1,398,797

   

   39,429Cash and cash equivalents

   

   238,241

   

   908,982

   

   24,688Noncurrent assets

   

   927,948

   

   11,066,086

   

   122,991Current liabilities

   

   121,646

   

   1,313,466

   

   9,586Borrowings and debentures

   

   60,162

   

   889,981

   

   324Other financial liabilities

   

   20,800

   

   85,523

   

   1,056Noncurrent liabilities

   

   341,356

   

   6,713,610

   

   36,404Borrowings and debentures

   

   254,732

   

   5,517,890

   

   36,167Other financial liabilities

   

   86,624

   

   633

   

   -Equity

   

   753,484

   

   4,437,807

   

   116,431Attributable to owners of the Company

   

   753,484

   

   4,324,589

   

   116,431Attributable to noncontrolling interests

   

   -

   

   113,218

   

   -Net operating revenue

   

   301,179

   

   1,646,589

   

   30,820Operational costs and expenses

   

   (67,242)

   

   (653,459)

   

   (27,404)Depreciation and amortization

   

   (48,082)

   

   (553,169)

   

   (3)Interest income

   

   28,232

   

   112,389

   

   2,728Interest expense

   

   (36,485)

   

   (591,626)

   

   (1,383)Income tax expense

   

   (55,596)

   

   (46,311)

   

   (1,137)Profit (loss) for the year

   

   110,345

   

   (143,706)

   

   12,134Attributable to owners of the Company

   

   110,345

   

   (151,900)

   

   12,134Attributable to noncontrolling interests

   

   -

   

   8,195

   

   -Equity Interests and voting capital

   

   35.00%

   

   48.40%

   

   40.07%
  F - 70


---



December 31, 2015CERAN

   

   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

   

   16,515Borrowings and debentures

   

   62,279

   

   854,042

   

   392Other financial liabilities

   

   39,068

   

   75,716

   

   6,497Noncurrent liabilities

   

   401,988

   

   6,425,440

   

   40,908Borrowings and debentures

   

   318,864

   

   5,167,017

   

   40,908Other financial liabilities

   

   83,124

   

   633

   

   -Equity

   

   669,346

   

   4,303,797

   

   108,639Attributable to owners of the Company

   

   669,346

   

   4,176,063

   

   108,639Attributable to noncontrolling interests

   

   -

   

   127,734

   

   -Net operating revenue

   

   281,374

   

   1,499,356

   

   31,225Operational costs and expenses

   

   (71,033)

   

   (498,005)

   

   (22,400)Depreciation 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%
  2014CERAN

   

   CPFL Renováveis

   

   Paulista LajeadoNet operating revenue

   

   327,066

   

   1,247,627

   

   42,771Operational costs and expenses

   

   (174,134)

   

   (584,080)

   

   (53,183)Depreciation 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 interests in CPFL Renováveis were 41.16% up to February 2014, 41.17% from March to September 2014 and 48.39% from October 1, 2014
  ( 26 )EARNINGS PER SHARE
 Earnings per share – basic and diluted The calculation of the basic and diluted earnings per share at December 31, 2016, 2015 and 2014 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:   F - 71


---



2016

   

   2015

   

   2014NumeratorProfit attributable to controlling shareholders

   900,885

   

   864,940

   

   949,177DenominatorWeighted average number of shares held by shareholders (**)

   1,017,914,746

   

   1,017,914,746

   

   1,017,914,746Earnings per share - basic

   0.89

   

   0.85

   

   0.93NumeratorProfit attributable to controlling shareholders

   900,885

   

   864,940

   

   949,177Dilutive effect of convertible debentures of subsidiary CPFL Renováveis (*)

   (16,153)

   

   (19,811)

   

   (17,265)Profit attributable to controlling shareholders

   884,731

   

   845,129

   

   931,912DenominatorWeighted average number of shares held by shareholders (**)

   1,017,914,746

   

   1,017,914,746

   

   1,017,914,746Earnings per share - diluted

   0.87

   

   0.83

   

   0.92
 (*) Proportional to the percentage of the Company's interest in the subsidiary in the respective years. (**) Considers the event occurred on April 29, 2016, related to the capital increase through the issuance of 24,900,531 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 2016, 2015 and 2014. For this reason, these effects were not included in the calculation for each year.  F - 72


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

   

   In GWh (*)

   

   R$ thousandRevenue from Electric Energy Operations

   

   2016

   

   2015

   

   2014

   

   2016

   

   2015

   

   2014

   

   2016

   

   2015Restated (**)

   

   2014Restated (**)Consumer classResidential

   

   8,174,700

   

   6,906,580

   

   6,732,715

   

   16,473

   

   16,164

   

   16,501

   

   10,367,415

   

   9,833,419

   

   6,533,590Industrial

   

   61,112

   

   55,586

   

   56,920

   

   13,022

   

   12,748

   

   14,144

   

   5,281,978

   

   5,526,967

   

   3,871,868Commercial

   

   551,171

   

   473,333

   

   483,204

   

   9,720

   

   9,259

   

   9,437

   

   5,431,926

   

   5,266,432

   

   3,471,225Rural

   

   355,586

   

   245,238

   

   243,275

   

   2,474

   

   2,152

   

   2,326

   

   816,684

   

   750,209

   

   496,790Public administration

   

   61,208

   

   51,359

   

   50,538

   

   1,271

   

   1,278

   

   1,295

   

   690,389

   

   674,530

   

   476,557Public lighting

   

   11,073

   

   10,362

   

   9,917

   

   1,746

   

   1,649

   

   1,622

   

   580,229

   

   573,219

   

   315,072Public services

   

   9,649

   

   8,402

   

   8,155

   

   1,840

   

   1,797

   

   1,861

   

   901,662

   

   879,288

   

   566,719(-) Adjustment of revenues from excess demand and excess reactive power

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (72,129)

   

   (79,362)

   

   (84,017)Billed

   

   9,224,499

   

   7,750,860

   

   7,584,724

   

   46,546

   

   45,049

   

   47,187

   

   23,998,155

   

   23,424,701

   

   15,647,804Own comsuption

   

   -

   

   -

   

   -

   

   32

   

   33

   

   34

   

   -

   

   -

   

   -Unbilled (net)

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   50,444

   

   202,726

   

   63,142Other consumer charges / Emergency charges - ECE/EAEE

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (3)

   

   3

   

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

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (9,055,188)

   

   (8,118,085)

   

   (5,464,570)Electricity sales to final consumers

   

   9,224,499

   

   7,750,860

   

   7,584,724

   

   46,578

   

   45,082

   

   47,221

   

   14,993,408

   

   15,509,345

   

   10,246,379Furnas Centrais Elétricas S.A.

   

   

   

   

   

   

   

   3,034

   

   3,026

   

   3,026

   

   533,855

   

   485,846

   

   477,775Other concessionaires and licensees

   

   

   

   

   

   

   

   12,252

   

   10,656

   

   9,628

   

   2,371,091

   

   2,223,339

   

   1,690,711(-) Reclassification to Network Usage Charge - TUSD - Captive Consumers

   

   

   

   

   -

   

   -

   

   -

   

   (50,598)

   

   (46,982)

   

   -Spot market energy

   

   

   

   

   

   

   

   6,173

   

   4,289

   

   2,334

   

   641,744

   

   875,002

   

   976,377Electricity sales to wholesalers

   

   

   

   

   

   

   

   21,459

   

   17,971

   

   14,988

   

   3,496,092

   

   3,537,205

   

   3,144,864Revenue due to Network Usage Charge - TUSD - Captive Consumers

   

   

   

   

   

   

   

   

   

   

   

   9,105,786

   

   8,165,066

   

   5,464,570Revenue due to Network Usage Charge - TUSD - Free Consumers

   

   

   

   

   

   

   

   

   

   

   

   2,057,327

   

   1,898,138

   

   990,815(-) Adjustment of revenues from excess demand and excess reactive power

   

   

   

   

   

   

   

   

   

   (17,908)

   

   (16,884)

   

   (18,045)Revenue from construction of concession infrastructure

   

   

   

   

   

   

   

   

   

   

   

   

   1,354,023

   

   1,046,669

   

   944,997Sector financial asset and liability (Note 8)

   

   

   

   

   

   

   

   

   

   

   

   

   

   (2,094,695)

   

   2,506,524

   

   910,720Concession financial asset - Adjustment of expected cash flow (note 11)

   

   

   

   

   

   

   

   

   

   

   

   186,148

   

   393,343

   

   93,254Energy development account - CDE - Low-income, tariff discounts - judicial injunctions and other tariff discounts

   

   

   

   

   

   

   1,266,027

   

   895,538

   

   771,018Other revenues and income

   

   

   

   

   

   

   

   

   

   

   

   

   

   438,377

   

   367,356

   

   341,061Other operating revenues

   

   

   

   

   

   

   

   

   

   

   

   

   

   12,295,084

   

   15,255,750

   

   9,498,390Total gross operating revenue

   

   

   

   

   

   

   

   

   

   

   

   

   

   30,784,584

   

   34,302,301

   

   22,889,633Deductions from operating revenueICMS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (4,935,068)

   

   (4,686,039)

   

   (3,106,928)PIS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (471,836)

   

   (529,322)

   

   (335,937)COFINS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (2,172,777)

   

   (2,438,208)

   

   (1,547,783)ISS

   

   

   

   

   

   

   

   

   

   

   

   

   

   (10,568)

   

   (8,204)

   

   (7,583)Global reversal reserve - RGR

   

   

   

   

   

   

   

   

   

   

   

   

   

   (4,230)

   

   (2,529)

   

   (2,362)Energy development account - CDE

   

   

   

   

   

   

   

   

   

   

   

   

   

   (3,360,613)

   

   (3,970,013)

   

   (271,577)Research and development and energy efficiency programs

   

   

   

   

   

   

   

   

   

   

   

   (138,583)

   

   (158,516)

   

   (117,683)PROINFA

   

   

   

   

   

   

   

   

   

   

   

   

   

   (121,800)

   

   (90,910)

   

   (100,569)Tariff flags and others

   

   

   

   

   

   

   

   

   

   

   

   

   

   (430,077)

   

   (1,796,226)

   

   (2)IPI

   

   

   

   

   

   

   

   

   

   

   

   

   

   (195)

   

   (100)

   

   (10)FUST and FUNTEL

   

   

   

   

   

   

   

   

   

   

   

   

   

   (38)

   

   (24)

   

   (2)Others

   

   

   

   

   

   

   

   

   

   

   

   

   

   (26,709)

   

   (22,997)

   

   -(11,672,495)

   

   (13,703,089)

   

   (5,490,436)Net operating revenue

   

   

   

   

   

   

   

   

   

   

   

   

   

   19,112,089

   

   20,599,212

   

   17,399,196(*) Information not audited by the independent auditors(**) Includes the effects of note 2.7
 27.1Adjustment of revenues from excess demand and excess reactive power The tariff regulation procedure (“Proret”), in submodule 2.7 Other Revenues approved by ANEEL Normative Resolution No. 463 of November 22, 2011, determined that revenues from distribution subsidiaries 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. Beginining May 2015 for subsidiary CPFL Piratininga and September 2015 for subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista due to the 4th cycle of periodic tariff review, this special obligation started being amortized and the new values from excess demand and excess reactive power started being recognized in sector financial assets and liabilities and will only be amortized when the 5th cycle of periodic tariff review is approved. 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 judicial 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 judicial injunction relief originally granted in favor of ABRADEE was suspended. The distribution subsidiaries are awaiting the court’s decision on the final treatment of these revenues. At December 31, 2016, these amounts are accrued under Special Obligations, in compliance with IAS 37, presented net in concession intangible asset.  F - 73


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27.2Extraordinary Tariff Review (“RTE”) – 2015 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, 2015, 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 were 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%

   

   43.36%

   

   33.04%RGE Sul

   

   

   

   39.45%

   

   43.76%

   

   36.23%CPFL Santa Cruz

   

   

   

   10.04%

   

   10.53%

   

   9.78%CPFL Leste Paulista

   

   

   

   19.54%

   

   24.74%

   

   17.55%CPFL Jaguari

   

   

   

   23.01%

   

   25.01%

   

   18.79%CPFL Sul Paulista

   

   

   

   21.95%

   

   37.67%

   

   13.86%CPFL Mococa

   

   

   

   16.59%

   

   23.84%

   

   13.97%(*) Information not audited by the independent auditors
 27.3Periodic tariff review (“RTP”) and Annual tariff adjustment (“RTA”)  2016

   

   2015

   

   2014Subsidiary

   

   Month

   

   RTA / RTP

   

   Effect perceived by consumers (a)

   RTA / RTP

   

   Effect perceived by consumers (a)

   RTA / RTP

   

   Effect perceived by consumers (a)CPFL Paulista

   

   April

   

   9.89%

   

   7.55%

   

   41.45%

   

   4.67% (b)

   

   17.18%

   

   17.23%CPFL Piratininga

   

   October

   

   -12.54%

   

   -24.21%

   

   56.29%

   

   21.11% (b)

   

   19.73%

   

   22.43%RGE

   

   June

   

   -1.48%

   

   -7.51%

   

   33.48%

   

   -3.76% (b)

   

   21.82%

   

   22.77%RGE Sul

   

   April

   

   3.94%

   

   -0.34%

   

   52.45%

   

   5.46%

   

   -

   

   -CPFL Santa Cruz

   

   March (c)

   

   22.51%

   

   7.15%

   

   34.68%

   

   27.96%

   

   14.86%

   

   26.00%CPFL Leste Paulista

   

   March (c)

   

   21.04%

   

   13.32%

   

   20.80%

   

   24.89%

   

   -7.67%

   

   -5.32%CPFL Jaguari

   

   March (c)

   

   29.46%

   

   13.25%

   

   38.46%

   

   45.70%

   

   -3.73%

   

   3.70%CPFL Sul Paulista

   

   March (c)

   

   24.35%

   

   12.82%

   

   24.88%

   

   28.38%

   

   -5.51%

   

   0.43%CPFL Mococa

   

   March (c)

   

   16.57%

   

   9.02%

   

   23.34%

   

   29.28%

   

   -2.07%

   

   -9.53%
 (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)In February2016, ANEEL changed the date of adjustment and periodic review of subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari from February to March.  27.4Energy Development Account (CDE) – Low-income, tariff discounts – judicial injunctions, and other tariff discounts 27.4.1 Energy 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$ 1,038,621 was recognized in 2016 (R$ 895,538 in 2015 and R$ 771,018 in 2014), of which R$93,879 for the low-income subsidy (R$ 66,313 in 2015 and R$ 78,028 in 2014) and R$944,742 for other tariff


discounts (R$ 829,225 in 2015 and R$ 692,990 in 2014), against other receivables in line item “Other Receivables – Eletrobrás” (note 12) and “Other Payables – Tariff discounts – CDE” (note 24).   F - 74


---



27.4.2 Tariff discounts – judicial injunctions The Brazilian Association of Large Industrial Consumers of Electricity (“ABRACE”) obtained a judicial injunction in July 2015, which exempted its associates from paying specific items of the CDE (Energy Development Account) charge. The obligation of paying the CDE quota was not changed and the distributors borne this revenue deficit. In the tariff process subsequent to the decision on the judicial injunction, ANEEL granted a financial component in the tariff for recovery of this revenue. However, the decision of the ANEEL board was superseded by Order No. 1.576/2016, which revoked Decree No. 2.792/2015, and distributors were required to deduct the total effects of the judicial injunctions from the payment of the monthly CDE quotas. Thus, it was established that this cost will be the liability of Eletrobrás. In view of the new procedure defined in Order No. 1.576/2016 it was necessary: (i)to record a revenue in line item CDE – low-income subsidy, other tariff discounts and other tariff discounts – judicial injunctions against the line item receivables -  Eletrobrás (note 12) in the amount of R$ 227,406; (ii)record sector financial liability (note 8) against revenue from sector financial asset and liability in the amount of R$ 209,250, which will be refunded to consumers in the next tariff process.  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$ 1.50, R$ 3.00 and R$ 4.50 (before tax effects), respectively, for each 100 KWh consumed, readjusted by means of Ratification Resolution (“REH”) 2.016/2016 as from February 1st 2016, until January 31, 2017. In 2016, the distribution subsidiaries billed their consumers the amount of R$ 430,065 (R$ 1,796,226 in 2015) in terms of tariff flags, recorded in line item "Tariff flags and others”. In 2016, ANEEL approved the Tariff Flags billed from November 2015 to November 2016. The amount billed in this period was R$ 706,178, of this amount R$ 687,673 were used to offset part of the sector financial asset and liability (note 8) and R$ 18,911 were passed on to theAccount Centralizing Tariff Flag Resources.  27.6Energy Development Account – CDE By means of Ratification Resolution No. 2,018 of February 2nd 2016, superseded by Ratification Resolution No 2,077 of June 07, 2016 and 1,857 of February 27, 2015, the ANEEL established the definitive annual quotas of the CDE. These quotas comprise: (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. 2,004 of December 15, 2015, the ANEEL established another quota intended for amortization of the ACR account, with payment and transfer to the CDE for the tariff period of each distribution company.  F - 75


---



( 28 )COST OF ELECTRIC ENERGY
  In GWh (*)

   

   R$ thousand2016

   

   2015

   

   2014

   

   2016

   

   2015

   

   2014Electricity purchased for resaleItaipu Binacional

   

   10,497

   

   10,261

   

   10,417

   

   2,025,780

   

   2,869,481

   

   1,383,604Spot market / PROINFA

   

   2,253

   

   4,004

   

   6,117

   

   269,791

   

   981,009

   

   3,282,591Energy purchased through auction in the regulated market and bilateral contracts

   

   51,225

   

   44,342

   

   42,345

   

   8,541,677

   

   9,192,868

   

   8,837,459Energy development account - CDE/CCEE

   

   -

   

   -

   

   -

   

   -

   

   -

   

   (2,340,912)PIS and COFINS credit

   

   -

   

   -

   

   -

   

   (987,997)

   

   (1,196,579)

   

   (1,005,106)Subtotal

   

   63,975

   

   58,607

   

   58,879

   

   9,849,252

   

   11,846,779

   

   10,157,635Electricity network usage chargeBasic network charges

   

   

   

   

   

   

   

   834,341

   

   847,342

   

   727,341Transmission from Itaipu

   

   

   

   

   

   

   

   53,248

   

   51,236

   

   37,896Connection charges

   

   

   

   

   

   

   

   84,927

   

   56,312

   

   44,834Charges for use of the distribution system

   

   

   

   

   

   

   

   38,699

   

   40,332

   

   33,147System service charges - ESS

   

   

   

   

   

   

   

   362,735

   

   555,851

   

   (326,248)Reserve energy charges - EER

   

   

   

   

   

   

   

   106,925

   

   54,762

   

   10,898Energy development account - CDE

   

   

   

   

   

   

   

   -

   

   -

   

   (1)PIS and COFINS credit

   

   

   

   

   

   

   

   (129,883)

   

   (140,868)

   

   (42,372)Subtotal

   

   

   

   

   

   

   

   1,350,990

   

   1,464,967

   

   485,495Total

   

   

   

   

   

   

   

   11,200,242

   

   13,311,747

   

   10,643,130(*) Information not audited by the independent auditors
  28.1Amounts 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: 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. 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). There were no resources provided by the CDE recognized in the year ended December 31, 2016 and 2015. The table below shows the summary of the amounts from CDE per distributor controlled by the Company, recognized in the year ended December 31, 2014:   F - 76


---



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

   

   2,340,912
 ( 29 )OPERATING COSTS AND EXPENSES
  2016Cost of operation

   

   Cost of services rendered to third parties

   

   Expenses

   

   TotalSelling

   

   General and administrative

   OthersPersonnel

   686,434

   

   1

   

   134,864

   

   272,618

   

   -

   

   1,093,918Private pension plans

   76,505

   

   -

   

   -

   

   -

   

   -

   

   76,505Materials

   164,168

   

   1,412

   

   8,191

   

   16,175

   

   -

   

   189,946Third party services

   271,623

   

   3,416

   

   146,957

   

   229,199

   

   -

   

   651,195Depreciation and amortization

   937,506

   

   -

   

   3,602

   

   94,949

   

   -

   

   1,036,056Cost of infrastructure construction

   -

   

   1,352,214

   

   -

   

   -

   

   -

   

   1,352,214Others

   112,560

   

   (11)

   

   253,638

   

   236,476

   

   386,746

   

   989,408Collection fees

   -

   

   -

   

   65,562

   

   -

   

   -

   

   65,562Allowance for doubtful accounts

   -

   

   -

   

   176,349

   

   -

   

   -

   

   176,349Leases and rentals

   42,163

   

   -

   

   113

   

   17,109

   

   -

   

   59,385Publicity and advertising

   150

   

   -

   

   29

   

   11,659

   

   -

   

   11,838Legal, judicial and indemnities

   -

   

   -

   

   -

   

   181,888

   

   -

   

   181,888Donations, contributions and subsidies

   54

   

   -

   

   9

   

   2,425

   

   -

   

   2,488Gain (loss) on disposal, retirement and other noncurrent assets

   -

   

   -

   

   -

   

   -

   

   83,575

   

   83,575Amortization of concession intangible asset

   -

   

   -

   

   -

   

   -

   

   255,110

   

   255,110Amortization of premium paid - GSF

   9,594

   

   -

   

   -

   

   -

   

   -

   

   9,594Financial compensation for use of water resources

   12,233

   

   -

   

   -

   

   -

   

   -

   

   12,233Impairment

   -

   

   -

   

   -

   

   -

   

   48,291

   

   48,291Others

   48,367

   

   (11)

   

   11,575

   

   23,395

   

   (231)

   

   83,095Total

   2,248,795

   

   1,357,032

   

   547,251

   

   849,416

   

   386,746

   

   5,389,240
 2015Cost of operation

   

   Cost of services rendered to third parties

   

   Expenses

   

   TotalSelling

   

   General and administrative

   

   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 accounts

   -

   

   -

   

   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
    F - 77


---



2014Cost of operation

   

   Cost of services rendered to third parties

   

   Expenses

   

   TotalSelling

   

   General and administrative

   

   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 accounts

   -

   

   -

   

   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
  F - 78


---



( 30 )FINANCE INCOME (COSTS)
   2016

   

   2015Restated (*)

   

   2014Restated (*)Finance IncomeIncome from financial investments

   667,429

   

   472,745

   

   430,714Late payment interest and fines

   246,045

   

   215,923

   

   146,992Adjustment for inflation of tax credits

   32,371

   

   57,580

   

   25,309Adjustment for inflation of escrow deposits

   35,228

   

   84,683

   

   74,500Adjustment for inflation and exchange rate changes

   147,849

   

   121,609

   

   49,144Discount on purchase of ICMS credit

   16,198

   

   13,027

   

   17,382Adjustments to the sector financial asset (note 8)

   32,747

   

   162,786

   

   -PIS and COFINS on other finance income

   (63,223)

   

   (52,849)

   

   -PIS and COFINS on interest on capital

   (2,324)

   

   (6,941)

   

   (12,809)Other

   88,182

   

   74,685

   

   54,563Total

   1,200,503

   

   1,143,247

   

   785,794Finance costsInterest on debts

   (1,811,263)

   

   (1,725,252)

   

   (1,542,593)Adjustment for inflation and exchange rate changes

   (703,128)

   

   (686,575)

   

   (247,591)(-) Capitalized interest

   68,082

   

   45,568

   

   12,269Adjustments to the sector financial liability (note 8)

   (25,079)

   

   (1,573)

   

   -Use of public asset

   (14,950)

   

   (16,028)

   

   (10,649)Others

   (167,638)

   

   (167,250)

   

   (179,937)Total

   (2,653,977)

   

   (2,551,110)

   

   (1,968,503)Finance costs, net

   (1,453,474)

   

   (1,407,863)

   

   (1,182,708)
  (*)Includes the effects of note 2.7.
 Interests were capitalized at an average rate of 10.9% p.a. (10.25% p.a. in 2015 and 8.12% p.a. in 2014) on qualifying assets, in accordance with IAS 23. In line items Adjustment for inflation and exchange rate changes, the amounts include the effects of losses of R$ 1,399,988 in 2016 (gain of R$ 1,514,439 in 2015 and R$ 159,653 in 2014) 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 Executive Officers: F - 79


---



Distribution

   

   Generation(conventional source)

   

   Generation(renewable source)

   

   Commercialization

   

   Services

   

   Others (*)

   

   Elimination

   

   Total2016Net operating revenue

   15,017,166

   

   593,775

   

   1,334,571

   

   2,024,350

   

   81,595

   

   60,633

   

   

   

   19,112,089(-) Intersegment revenues

   22,526

   

   409,338

   

   338,357

   

   62,757

   

   318,770

   

   8,661

   

   (1,160,410)

   

   -Cost of electric energy

   (9,382,165)

   

   (91,588)

   

   (211,777)

   

   (1,514,712)

   

   -

   

   -

   

   

   

   (11,200,242)Operating costs and expenses

   (3,153,327)

   

   (100,606)

   

   (374,391)

   

   (38,440)

   

   (308,232)

   

   (123,077)

   

   

   

   (4,098,073)(-) Intersegment costs and expenses

   (659,308)

   

   (12,691)

   

   (93,630)

   

   (371,347)

   

   (13,900)

   

   (9,534)

   

   1,160,410

   

   -Depreciation and amortization

   (591,334)

   

   (126,596)

   

   (553,169)

   

   (3,779)

   

   (12,870)

   

   (3,417)

   

   

   

   (1,291,166)Income from electric energy service

   1,253,557

   

   671,631

   

   439,961

   

   158,829

   

   65,363

   

   (66,734)

   

   

   

   2,522,608Equity

   -

   

   311,414

   

   -

   

   -

   

   -

   

   -

   

   

   

   311,414Finance income

   781,365

   

   182,574

   

   132,653

   

   31,513

   

   10,742

   

   61,655

   

   

   

   1,200,503Finance costs

   (1,331,973)

   

   (562,196)

   

   (667,344)

   

   (24,761)

   

   (5,272)

   

   (62,432)

   

   

   

   (2,653,978)Profit (loss) before taxes

   702,950

   

   603,424

   

   (94,730)

   

   165,581

   

   70,832

   

   (67,510)

   

   

   

   1,380,547Income tax and social contribution

   (295,748)

   

   (98,530)

   

   (46,311)

   

   (53,225)

   

   (17,019)

   

   9,343

   

   

   

   (501,490)Profit (loss) for the year

   407,202

   

   504,894

   

   (141,041)

   

   112,357

   

   53,813

   

   (58,167)

   

   

   

   879,057Total assets (**)

   22,887,781

   

   5,310,924

   

   12,459,791

   

   466,021

   

   345,372

   

   701,103

   

   

   

   42,170,992Purchases of PP&E and intangible assets

   1,200,621

   

   7,564

   

   978,896

   

   3,713

   

   42,954

   

   4,199

   

   

   

   2,237,9492015 Restated (***)Net operating revenue

   16,945,222

   

   572,553

   

   1,262,297

   

   1,716,348

   

   55,547

   

   47,246

   

   

   

   20,599,212(-) Intersegment revenues

   22,318

   

   411,038

   

   335,979

   

   82,544

   

   239,088

   

   3,136

   

   (1,094,101)

   

   -Cost of electric energy

   (11,604,347)

   

   (147,120)

   

   (249,809)

   

   (1,310,470)

   

   -

   

   -

   

   

   

   (13,311,747)Operating costs and expenses

   (2,668,411)

   

   (80,811)

   

   (226,522)

   

   (34,460)

   

   (241,247)

   

   (110,674)

   

   

   

   (3,362,130)(-) Intersegment costs and expenses

   (550,953)

   

   (80,954)

   

   (120,593)

   

   (324,495)

   

   (10,137)

   

   (6,975)

   

   1,094,101

   

   -Depreciation and amortization

   (587,059)

   

   (131,969)

   

   (540,578)

   

   (4,534)

   

   (12,633)

   

   (3,128)

   

   

   

   (1,279,903)Income from electric energy service

   1,556,770

   

   542,738

   

   460,772

   

   124,933

   

   30,617

   

   (70,396)

   

   

   

   2,645,434Equity

   -

   

   216,885

   

   -

   

   -

   

   -

   

   -

   

   

   

   216,885Finance income

   740,628

   

   110,018

   

   131,354

   

   42,840

   

   44,098

   

   74,310

   

   

   

   1,143,247Finance costs

   (1,256,801)

   

   (549,286)

   

   (599,303)

   

   (38,386)

   

   (4,858)

   

   (102,477)

   

   

   

   (2,551,110)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

   625,965

   

   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

   

   

   

   1,427,7962014 Restated (***)Net operating revenue

   13,752,040

   

   722,623

   

   982,613

   

   1,790,822

   

   151,037

   

   61

   

   

   

   17,399,196(-) Intersegment revenues

   19,668

   

   467,761

   

   397,630

   

   387,788

   

   193,483

   

   -

   

   (1,466,329)

   

   -Cost of electric energy

   (8,544,349)

   

   (284,387)

   

   (301,366)

   

   (1,513,196)

   

   -

   

   -

   

   

   

   (10,643,297)Operating costs and expenses

   (2,332,587)

   

   (86,100)

   

   (227,191)

   

   (32,634)

   

   (282,250)

   

   (1,847)

   

   

   

   (2,962,608)(-) Intersegment costs and expenses

   (621,246)

   

   (201,236)

   

   (188,139)

   

   (423,202)

   

   (8,437)

   

   (24,069)

   

   1,466,329

   

   -Depreciation and amortization

   (577,753)

   

   (136,447)

   

   (432,267)

   

   (4,471)

   

   (8,760)

   

   (265)

   

   

   

   (1,159,964)Income from electric energy service

   1,695,773

   

   482,214

   

   231,280

   

   205,108

   

   45,072

   

   (26,119)

   

   

   

   2,633,327Equity

   -

   

   59,767

   

   -

   

   -

   

   -

   

   -

   

   

   

   59,767Finance income

   448,276

   

   84,884

   

   98,991

   

   29,543

   

   6,380

   

   117,720

   

   

   

   785,793Finance costs

   (838,386)

   

   (482,671)

   

   (464,713)

   

   (29,104)

   

   (10,221)

   

   (143,407)

   

   

   

   (1,968,501)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

   

   

   

   1,061,868
 (*) 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 (***) Includes the effects of note 2.7  As the Brazilian economic conditions have deteriorated even further during 2016, the following was recorded (i) CPFL Telecom – “segment others”, an additional impairment of R$7,858 and (ii) R$40,433 of CPFL Renováveis (renewable generation segment) impairment losses (in 2015, R$ 33,119 in subsidiary CPFL Telecom  and R$ 5,837 in subsidiary CPFL Total “segment services”). This loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 29).  The investment balance in joint ventures, accounted for under the equity method and classified in the generation (conventional source) segment, is R$ 1,493,753 (R$ 1,247,631 in 2015).  F - 80


---



( 32 )RELATED PARTY TRANSACTIONS
 The Company’s controlling shareholders were, as of December 31, 2016, as follows: ·ESC Energia S.A. Company controlled by the Camargo Corrêa group, with operations in diversified segments, such as construction, cement, textiles, aluminum and highway concessions, among others. ·Caixa de Previdência dos Funcionários do Banco do Brasil - PREVI Pension entity the participants of which are the employees of Banco do Brasil and employees of the company itself. ·Fundação CESP Pension entity that manages pension plans for employees of the electricity sector companies of the State of São Paulo ·Fundação SISTEL de Seguridade Social Pension entity that manages pension plans for employees of the telecommunications sector companies. ·Fundação Petrobras de Seguridade Social - PETROS Pension entity that manages pension plans for employees of companies mostly from the oil and chemical industries. ·Fundação SABESP de Seguridade Social - SABESPREV Pension entity that manages pension plans for employees of SABESP. 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.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 Grant 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 noncontrolling 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).   F - 81


---



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 Enercan and Baesa and with the subsidiary Ceran the extension of the original maturities of the energy purchase bills, previously from August to November 2016, to January 2017 and July 2017. The total compensation of key management personnel in 2016was R$ 58,132 (R$ 43,208 in 2015 and R$ 44,214 in 2014). This amount comprises R$49,989 (R$ 44,061 in 2015 and R$ 39,928 in 2014) in respect of short-term benefits, R$1,212 (R$ 1,087 in 2015 and R$ 1,043 in 2014) of post-employment benefits and a provision of R$ 6,930 (reversal of provision of R$ 1,940 in 2015 and provision of R$ 3,243 in 2014) 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:  
 F - 82


---



ASSETS

   

   LIABILITIES

   

   INCOME

   

   EXPENSESDec 31, 2016

   

   Dec 31, 2015

   

   Dec 31, 2016

   

   Dec 31, 2015

   

   2016

   

   2015

   

   2014

   

   2016

   

   2015

   

   2014Bank balances and short-term investmentsBanco Bradesco S.A.(**)

   -

   

   4,097,770

   

   -

   

   1

   

   -

   

   351,086

   

   -

   

   -

   

   312

   

   -Banco do Brasil S.A.

   48,985

   

   126,036

   

   -

   

   -

   

   4,113

   

   28,466

   

   12,126

   

   5

   

   4

   

   2Borrowings (*), debentures (*) and derivatives (*)Banco Bradesco S.A.(**)

   -

   

   -

   

   -

   

   667,335

   

   -

   

   -

   

   -

   

   -

   

   85,505

   

   -Banco do Brasil S.A.

   -

   

   -

   

   4,257,562

   

   3,727,087

   

   800

   

   -

   

   -

   

   463,949

   

   459,889

   

   485,400Banco BNP Paribas Brasil S.A

   5,126

   

   58,478

   

   -

   

   322,465

   

   -

   

   -

   

   -

   

   67,196

   

   8,978

   

   -Other financial transactionsBanco Bradesco S.A.(**)

   -

   

   1,344

   

   -

   

   1,259

   

   -

   

   166

   

   -

   

   -

   

   4,174

   

   -Banco do Brasil S.A.

   -

   

   -

   

   962

   

   879

   

   234

   

   80

   

   -

   

   6,408

   

   5,941

   

   6,304AdvancesBAESA – Energética Barra Grande S.A.

   -

   

   -

   

   726

   

   790

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Foz do Chapecó Energia S.A.

   -

   

   -

   

   1,025

   

   1,120

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -ENERCAN - Campos Novos Energia S.A.

   -

   

   -

   

   1,269

   

   1,377

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -EPASA - Centrais Elétricas da Paraiba

   -

   

   -

   

   462

   

   503

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Energy purchases and sales, and chargesAES Tiete S.A. (***)

   -

   

   -

   

   -

   

   -

   

   2

   

   -

   

   -

   

   14,498

   

   -

   

   -Afluente Transmissão de Energia Elétrica S.A.

   -

   

   -

   

   53

   

   27

   

   -

   

   -

   

   -

   

   1,212

   

   1,426

   

   1,342Aliança Geração de Energia S.A

   -

   

   -

   

   1,183

   

   1,364

   

   4

   

   1

   

   -

   

   49,944

   

   34,063

   

   -Alpargatas S.A. (***)

   -

   

   -

   

   -

   

   -

   

   2,954

   

   -

   

   -

   

   -

   

   -

   

   -Arizona 1 Energia Renovável S.A

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   967

   

   883

   

   826Baguari I Geração de Energia Elétrica S.A.

   -

   

   -

   

   6

   

   6

   

   -

   

   -

   

   -

   

   294

   

   268

   

   252Braskem S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   694

   

   -

   

   -

   

   -BRF Brasil Foods

   -

   

   -

   

   -

   

   -

   

   20,190

   

   -

   

   -

   

   -

   

   -

   

   -Caetite 2 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   889

   

   810

   

   757Caetité 3 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   896

   

   817

   

   765Calango 1 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,073

   

   977

   

   914Calango 2 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   916

   

   834

   

   782Calango 3 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,072

   

   977

   

   914Calango 4 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   995

   

   907

   

   848Calango 5 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,054

   

   963

   

   901Companhia Brasileira de Soluções e Serviços CBSS - Alelo (**)

   

   

   -

   

   -

   

   374

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Companhia de Eletricidade do Estado da Bahia – COELBA

   743

   

   655

   

   121

   

   -

   

   19,296

   

   14,491

   

   12,606

   

   121

   

   46

   

   -Companhia Energética de Pernambuco - CELPE

   692

   

   587

   

   20

   

   -

   

   9,829

   

   7,062

   

   6,304

   

   250

   

   206

   

   -Companhia Energética do Rio Grande do Norte - COSERN

   267

   

   227

   

   -

   

   -

   

   3,128

   

   2,580

   

   2,404

   

   -

   

   -

   

   1,063Eldorado Brasil Celulose S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   1,050

   

   -

   

   -

   

   -Companhia Hidrelétrica Teles Pires S.A.

   -

   

   -

   

   1,416

   

   1,548

   

   57

   

   17

   

   -

   

   53,710

   

   29,915

   

   -ELEB Equipamentos Ltda

   -

   

   -

   

   -

   

   -

   

   -

   

   4,036

   

   -

   

   -

   

   -

   

   -Embraer

   -

   

   -

   

   -

   

   -

   

   6,938

   

   26,615

   

   -

   

   -

   

   -

   

   -Energética Águas da Pedra S.A.

   -

   

   -

   

   112

   

   130

   

   6

   

   2

   

   -

   

   4,716

   

   4,260

   

   3,959Estaleiro Atlântico Sul S.A.

   -

   

   -

   

   -

   

   -

   

   7,978

   

   19,026

   

   7,584

   

   -

   

   -

   

   -Goiás Sul Geração de Enegia S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   181

   

   166

   

   155InterCement Brasil S.A

   -

   

   -

   

   -

   

   -

   

   2

   

   1

   

   -

   

   -

   

   -

   

   -Itapebi Geração de Energia S.A

   -

   

   -

   

   -

   

   -

   

   3

   

   1

   

   -

   

   -

   

   -

   

   -Mel 2 Energia Renovável S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   718

   

   632

   

   617NC ENERGIA S.A.

   451

   

   -

   

   2

   

   -

   

   28,298

   

   5,336

   

   1,837

   

   6

   

   -

   

   -Norte Energia S.A.

   1

   

   1

   

   4,585

   

   -

   

   17

   

   1

   

   -

   

   61,240

   

   -

   

   -Rio PCH I S.A.

   -

   

   -

   

   209

   

   242

   

   -

   

   -

   

   -

   

   8,865

   

   8,004

   

   7,441Samarco Mineração S.A.

   -

   

   -

   

   -

   

   -

   

   2

   

   1

   

   -

   

   -

   

   -

   

   -Santista Jeanswear S/A

   -

   

   -

   

   -

   

   -

   

   13,600

   

   4,491

   

   -

   

   -

   

   -

   

   -Santista Work Solution S/A

   -

   

   -

   

   -

   

   -

   

   2,224

   

   -

   

   -

   

   -

   

   -

   

   -SE Narandiba S.A.

   -

   

   -

   

   2

   

   -

   

   -

   

   -

   

   -

   

   152

   

   166

   

   142Serra do Facão Energia S.A. - SEFAC

   -

   

   -

   

   557

   

   576

   

   -

   

   -

   

   -

   

   23,153

   

   20,916

   

   19,837Tavex Brasil S.A

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   8,087

   

   -

   

   -

   

   -Termopernambuco S.A.

   -

   

   -

   

   -

   

   -

   

   5

   

   3

   

   -

   

   -

   

   -

   

   -ThyssenKrupp Companhia Siderúrgica do Atlântico

   -

   

   -

   

   -

   

   -

   

   25,268

   

   37,238

   

   557

   

   7,683

   

   6,965

   

   7,056Tupy

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   27,127

   

   -

   

   -Vale Energia S.A.

   8,680

   

   7,843

   

   -

   

   -

   

   102,069

   

   92,353

   

   87,077

   

   216

   

   695

   

   -Vale S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   7,483BAESA – Energética Barra Grande S.A.

   -

   

   -

   

   5,642

   

   88,441

   

   -

   

   6,080

   

   -

   

   60,765

   

   111,541

   

   104,491Foz do Chapecó Energia S.A.

   -

   

   -

   

   35,018

   

   142,596

   

   215

   

   4,996

   

   16,841

   

   358,272

   

   330,675

   

   318,140ENERCAN - Campos Novos Energia S.A.

   387

   

   667

   

   50,526

   

   140,496

   

   3,684

   

   23,283

   

   6,702

   

   269,480

   

   244,102

   

   226,595EPASA - Centrais Elétricas da Paraiba

   -

   

   -

   

   12,418

   

   19,807

   

   -

   

   15,243

   

   24,363

   

   91,010

   

   168,187

   

   214,978Intangible assets, property, plant and equipment, materials and services renderedAlpargatas S.A. (***)

   168

   

   -

   

   -

   

   -

   

   2,310

   

   -

   

   -

   

   -

   

   -

   

   -Afluente Transmissão de Energia Elétrica S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   5

   

   -

   

   -Banco Bradesco S.A.(**)

   -

   

   -

   

   -

   

   2

   

   -

   

   -

   

   -

   

   -

   

   19

   

   -Banco do Brasil S A

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   6

   

   170

   

   163BRASKEM Qpar S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   15

   

   -

   

   -

   

   -Brasil veículos Companhia de Seguros

   -

   

   -

   

   -

   

   -

   

   2

   

   -

   

   -

   

   -

   

   -

   

   -BRF Brasil Foods

   -

   

   -

   

   -

   

   -

   

   1,250

   

   -

   

   -

   

   -

   

   -

   

   -CCDI 29 Empreendimento Imobiliário Ltda

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   31,500

   

   -

   

   -

   

   -Companhia de Saneamento Básico do Estado de São Paulo - SABESP

   4

   

   65

   

   42

   

   42

   

   170

   

   1,034

   

   50

   

   94

   

   31

   

   4Companhia 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 Auto Raposo Tavares S.A. - CART

   -

   

   -

   

   -

   

   

   

   

   

   -

   

   -

   

   15

   

   -

   

   -Concessionária de Rodovias do Oeste de São Paulo – ViaOeste S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   6

   

   -

   

   -Concessionária do Sistema Anhanguera - Bandeirante S.A.

   86

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   10

   

   9

   

   -Estaleiro Atlântico Sul S.A.

   -

   

   -

   

   -

   

   -

   

   9

   

   -

   

   12

   

   -

   

   -

   

   -Ferrovia Centro-Atlântica S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   24

   

   22

   

   -HM 14 Empreendimento Imobiliário SPE Ltda

   -

   

   14

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -HM 02 Empreendimento Imobiliário SPE Ltda.

   -

   

   -

   

   -

   

   -

   

   45

   

   -

   

   -

   

   -

   

   -

   

   -HM Engenharia e Construções S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   272

   

   24

   

   -

   

   -

   

   -Indústrias Romi S.A.

   4

   

   -

   

   -

   

   -

   

   51

   

   68

   

   45

   

   -

   

   -

   

   -InterCement Brasil S.A

   -

   

   -

   

   -

   

   -

   

   43

   

   26

   

   60

   

   -

   

   -

   

   -Oi Móvel S.A (***)

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   302

   

   -

   

   -Logum Logística S.A.

   26

   

   -

   

   -

   

   -

   

   730

   

   55

   

   -

   

   -

   

   -

   

   -LUPATECH

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   2

   

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

   -

   

   -

   

   -

   

   -

   

   -

   

   4

   

   -

   

   -

   

   1

   

   -MRS Logística S.A

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   119

   

   -

   

   -

   

   -NC Energia S.A.

   -

   

   -

   

   -

   

   -

   

   17

   

   -

   

   -

   

   -

   

   -

   

   -Randon

   

   

   -

   

   

   

   -

   

   

   

   -

   

   -

   

   

   

   -

   

   76Renovias Concessionária S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   17

   

   -

   

   -Rodovias Integradas do Oeste S.A.

   -

   

   -

   

   

   

   12

   

   -

   

   -

   

   -

   

   3

   

   -

   

   -SAMM - Sociedade de Atividades em Multimídia Ltda.

   -

   

   -

   

   -

   

   -

   

   1,410

   

   1,463

   

   -

   

   

   

   

   

   -Santista Jeanswear S/A

   -

   

   -

   

   

   

   -

   

   1

   

   21

   

   -

   

   -

   

   -

   

   -Tim Celular S.A. (***)

   6

   

   -

   

   89

   

   -

   

   2,008

   

   -

   

   -

   

   12

   

   -

   

   -TOTVS S.A.

   

   

   -

   

   2

   

   3

   

   2

   

   -

   

   -

   

   32

   

   44

   

   70Ultrafértil S.A

   -

   

   -

   

   

   

   -

   

   14

   

   868

   

   226

   

   -

   

   -

   

   -Vale Energia S.A.

   -

   

   -

   

   

   

   -

   

   331

   

   -

   

   -

   

   -

   

   -

   

   -Vale S.A.

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   11

   

   -

   

   -Vale Fertilizantes S.A

   -

   

   39

   

   

   

   -

   

   -

   

   45

   

   36

   

   -

   

   -

   

   -BAESA – Energética Barra Grande S.A.

   56

   

   -

   

   

   

   -

   

   521

   

   1,354

   

   1,465

   

   -

   

   -

   

   -Foz do Chapecó Energia S.A.

   104

   

   -

   

   

   

   -

   

   1,424

   

   1,483

   

   1,491

   

   -

   

   -

   

   -ENERCAN - Campos Novos Energia S.A.

   74

   

   -

   

   -

   

   -

   

   1,826

   

   1,354

   

   1,465

   

   -

   

   -

   

   -EPASA - Centrais Elétricas da Paraíba S.A.

   1,599

   

   1,104

   

   

   

   -

   

   488

   

   720

   

   715

   

   -

   

   -

   

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

   38,078

   

   76,586

   

   -

   

   -

   

   4,379

   

   14,123

   

   10,629

   

   -

   

   -

   

   -Noncontrolling shareholders - CPFL Renováveis

   9,067

   

   7,680

   

   -

   

   -

   

   1,039

   

   1,475

   

   864

   

   -

   

   -

   

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

   89

   

   20

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -Chapecoense Geração S.A.

   29,329

   

   28,417

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -ENERCAN - Campos Novos Energia S.A.

   40,983

   

   30,905

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -EPASA - Centrais Elétricas da Paraiba

   -

   

   29,933

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -

   

   -(*) The balances include the mark to market adjustments(**) Related party until December 2015(***) Related party from January 2016
    F - 83


---



( 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 coverage

   

   Dec. 31, 2016Concession financial asset / Intangible assets

   

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

   

   9,679,825Transport

   

   National transport

   

   416,358Stored materials

   

   Fire, lightning, explosion and robbery

   

   232,849Automobiles

   

   Comprehensive cover

   

   13,235Civil liability

   

   Electric energy distributors and others

   

   200,000Personnel

   

   Group life and personal accidents

   

   234,357Others

   

   Operational risks and others

   

   281,914Total

   

   

   

   11,058,537Information not audited by independent auditors
  For the civil liability insurance of the officers, the insured amount is shared among the companies of the CPFL Energia Group. The premium is paid individually by each company involved, and the gross revenue is the base for the apportionment criterion.  ( 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 Compliance 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, Risks and Sustainability Committee to provide guidance for the Internal Audit, Risks 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 - 84


---



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, and there is also a penalty for insufficiency of contractual guarantee. These situations may be mitigated if the distributors are able to justify the involuntary exposures or 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 water rationing programs, as in 2001. The storage conditions of the National Interconnected System (“SIN”) improved during 2016, despite the low storage levels in the Northeast sub-system. The improvement in SIN storage conditions, associated with the reduced demand verified during the year and the availability of thermoelectric power generation, significantly reduce 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 No. 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   F - 85


---



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.  ( 35 )FINANCIAL INSTRUMENTS
 The main financial instruments, classified in accordance with the group’s accounting practices, are:  December 31, 2016

   

   December 31, 2015Note

   

   Category

   

   Measurement

   

   Level (*)

   

   Carrying amount

   

   Fair value

   

   Carrying amount

   

   Fair valueAssetCash and cash equivalent

   5

   

   (a)

   

   (2)

   

   Level 1

   

   5,267,966

   

   5,267,966

   

   4,353,488

   

   4,353,488Cash and cash equivalent

   5

   

   (a)

   

   (2)

   

   Level 2

   

   897,031

   

   897,031

   

   1,329,314

   

   1,329,314Securities

   

   

   (a)

   

   (2)

   

   Level 1

   

   511

   

   511

   

   23,633

   

   23,633Derivatives

   35

   

   (a)

   

   (2)

   

   Level 2

   

   746,883

   

   746,883

   

   2,269,932

   

   2,269,933Derivatives - zero-cost collar

   35

   

   (a)

   

   (2)

   

   Level 3

   

   57,715

   

   57,715

   

   8,820

   

   8,820Concession financial asset - distribution

   11

   

   (b)

   

   (2)

   

   Level 3

   

   5,193,511

   

   5,193,511

   

   3,483,713

   

   3,483,71312,163,617

   

   12,163,617

   

   11,468,901

   

   11,468,901LiabilityBorrowings - principal and interest

   17

   

   (c)

   

   (1)

   

   Level 2 (***)

   

   7,554,059

   

   6,615,837

   

   7,725,978

   

   6,499,746Borrowings - principal and interest

   17 (**)

   

   (a)

   

   (2)

   

   Level 2

   

   5,489,982

   

   5,489,982

   

   6,936,808

   

   6,936,808Debentures - Principal and interest

   18

   

   (c)

   

   (1)

   

   Level 2 (***)

   

   8,999,947

   

   8,857,941

   

   7,070,430

   

   6,105,830Derivatives

   35

   

   (a)

   

   (2)

   

   Level 2

   

   118,262

   

   118,262

   

   31,745

   

   31,745Derivatives - Zero-cost collar

   35

   

   (a)

   

   (2)

   

   Level 3

   

   -

   

   -

   

   2,440

   

   2,44022,162,250

   

   21,082,022

   

   21,767,402

   

   19,576,570(*) 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 loss of R$ 274,834 in 2016 (a gain of R$ 256,251 in 2015)(***) Only for disclosure purposes, in accordance with IFRS 7
  The financial instruments for which the carrying amounts approximate the fair values at the end of the reporting period, as they are either short term in nature, bear post fixed interest rates or are of a high credit rating are:
 ·Financial assets: (i) consumers, concessionaires and licensees, (ii) leases, (iii) associates, subsidiaries and parent company, (iv) receivables – Eletrobrás, (v) concession financial asset - transmission, (vi) pledges, funds and restricted deposits, (vii) services rendered to third parties, (viii) Collection agreements, and (ix) sector financial asset. ·Financial liabilities: (i) trade payables, (ii) regulatory charges, (iii) use of public asset, (iv) consumers and concessionaires payable, (v) FNDCT/EPE/PROCEL, (vi) collection agreement, (vii) reversal fund, (viii) payables for business combination, (ix) tariff discount CDE, and (x) sector financial liability. In addition, in 2016 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.   F - 86


---



The three levels of the fair value hierarchy are: · Level 1: quoted prices in an active market for identical instruments; · 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$ 186,148 (R$ 393,343 in 2015 and R$93,254 in 2014), and the main assumptions are described in note 11 and 27. 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, 2016, the Company and its subsidiaries had the following derivative transactions, all traded on the over-the-counter market:    F - 87


---



Fair values (carrying amounts)Company / strategy / counterparts

   

   Assets

   

   Liabilities

   

   Fair value, net

   

   Values atcost, net

   

   Gain (loss) on marking to market

   

   Currecy / index

   

   Maturity range

   

   NotionalDerivatives to hedge debts designated at fair valueExchange rate hedgeCPFL PaulistaBank of Tokyo-Mitsubishi

   

   44,536

   

   -

   

   44,536

   

   44,845

   

   (309)

   

   dollar

   

   March 2019

   

   117,400Bank of America Merrill Lynch

   

   41,815

   

   -

   

   41,815

   

   40,514

   

   1,300

   

   dollar

   

   September 2018

   

   106,020Bank of America Merrill Lynch

   

   47,538

   

   -

   

   47,538

   

   46,268

   

   1,270

   

   dollar

   

   March 2019

   

   116,600J.P.Morgan

   

   23,768

   

   -

   

   23,768

   

   23,134

   

   634

   

   dollar

   

   March 2019

   

   58,300J.P.Morgan

   

   13,231

   

   -

   

   13,231

   

   13,311

   

   (80)

   

   dollar

   

   December 2017

   

   51,470J.P.Morgan

   

   11,785

   

   -

   

   11,785

   

   11,885

   

   (100)

   

   dollar

   

   December 2017

   

   53,100J.P.Morgan

   

   4,053

   

   -

   

   4,053

   

   4,065

   

   (12)

   

   dollar

   

   January 2018

   

   27,121Bradesco

   

   10,045

   

   -

   

   10,045

   

   9,698

   

   347

   

   dollar

   

   January 2018

   

   54,214Bradesco

   

   41,072

   

   -

   

   41,072

   

   39,589

   

   1,483

   

   dollar

   

   January 2018

   

   173,459J.P.Morgan

   

   10,354

   

   -

   

   10,354

   

   10,191

   

   164

   

   dollar

   

   January 2018

   

   67,938J.P.Morgan

   

   10,532

   

   -

   

   10,532

   

   10,515

   

   16

   

   dollar

   

   January 2019

   

   67,613BNP Paribas

   

   1,367

   

   -

   

   1,367

   

   672

   

   695

   

   euro

   

   January 2018

   

   63,896Bank of Tokyo-Mitsubishi

   

   14,735

   

   -

   

   14,735

   

   18,298

   

   (3,563)

   

   dollar

   

   February 2020

   

   142,735J.P.Morgan

   

   5,961

   

   -

   

   5,961

   

   6,080

   

   (119)

   

   dollar

   

   February 2018

   

   41,100Bank of America Merrill Lynch

   

   81,111

   

   -

   

   81,111

   

   77,971

   

   3,140

   

   dollar

   

   February 2018

   

   405,300Bank of America Merrill Lynch

   

   -

   

   (11,672)

   

   (11,672)

   

   (11,726)

   

   54

   

   dollar

   

   October 2018

   

   329,500Bradesco

   

   -

   

   (4,379)

   

   (4,379)

   

   (5,418)

   

   1,039

   

   dollar

   

   May 2021

   

   59,032Bank of America Merrill Lynch

   

   -

   

   (3,771)

   

   (3,771)

   

   (5,390)

   

   1,619

   

   dollar

   

   May 2021

   

   59,032Citibank

   

   -

   

   (7,846)

   

   (7,846)

   

   (10,793)

   

   2,947

   

   dollar

   

   May 2021

   

   118,063361,903

   

   (27,668)

   

   334,235

   

   323,711

   

   10,524CPFL PiratiningaCitibank

   

   44,955

   

   -

   

   44,955

   

   44,779

   

   176

   

   dollar

   

   March 2019

   

   117,250Bradesco

   

   25,700

   

   -

   

   25,700

   

   25,194

   

   506

   

   dollar

   

   April 2018

   

   55,138J.P.Morgan

   

   25,717

   

   -

   

   25,717

   

   25,197

   

   521

   

   dollar

   

   April 2018

   

   55,138Citibank

   

   30,808

   

   -

   

   30,808

   

   30,780

   

   28

   

   dollar

   

   January 2020

   

   169,838BNP Paribas

   

   3,759

   

   -

   

   3,759

   

   1,849

   

   1,911

   

   euro

   

   January 2018

   

   175,714Scotiabank

   

   -

   

   (4,257)

   

   (4,257)

   

   (4,211)

   

   (46)

   

   dollar

   

   August 2017

   

   55,440Bradesco

   

   -

   

   (4,379)

   

   (4,379)

   

   (5,418)

   

   1,039

   

   dollar

   

   May 2021

   

   59,032Bank of America Merrill Lynch

   

   -

   

   (5,438)

   

   (5,438)

   

   (8,074)

   

   2,636

   

   dollar

   

   May 2021

   

   88,548Citibank

   

   -

   

   (5,950)

   

   (5,950)

   

   (8,098)

   

   2,148

   

   dollar

   

   May 2021

   

   88,548130,940

   

   (20,024)

   

   110,916

   

   101,997

   

   8,919CPFL GeraçãoBradesco

   

   92,771

   

   -

   

   92,771

   

   92,569

   

   201

   

   dollar

   

   March 2017

   

   232,520Votorantim

   

   -

   

   (4,525)

   

   (4,525)

   

   (7,212)

   

   2,687

   

   dollar

   

   June 2019

   

   104,454Scotiabank

   

   -

   

   (8,208)

   

   (8,208)

   

   (7,643)

   

   (566)

   

   dollar

   

   July 2019

   

   117,036Bradesco

   

   79

   

   -

   

   79

   

   (158)

   

   237

   

   dollar

   

   September 2019

   

   32,636Citibank

   

   -

   

   (8,824)

   

   (8,824)

   

   (7,646)

   

   (1,177)

   

   dollar

   

   September 2020

   

   397,320Scotiabank

   

   -

   

   (14,117)

   

   (14,117)

   

   (12,248)

   

   (1,870)

   

   dollar

   

   December 2019

   

   174,52592,849

   

   (35,674)

   

   57,175

   

   57,663

   

   (488)RGEBank of Tokyo-Mitsubishi

   

   21,496

   

   -

   

   21,496

   

   21,657

   

   (162)

   

   dollar

   

   April 2018

   

   36,270Bank of Tokyo-Mitsubishi

   

   96,357

   

   -

   

   96,357

   

   96,985

   

   (628)

   

   dollar

   

   May 2018

   

   168,346Bradesco

   

   11,207

   

   -

   

   11,207

   

   10,968

   

   239

   

   dollar

   

   October 2017

   

   32,715J.P.Morgan

   

   19,839

   

   -

   

   19,839

   

   19,441

   

   398

   

   dollar

   

   February 2018

   

   171,949Bradesco

   

   -

   

   (4,379)

   

   (4,379)

   

   (5,418)

   

   1,039

   

   dollar

   

   May 2021

   

   59,032Bank of America Merrill Lynch

   

   -

   

   (7,106)

   

   (7,106)

   

   (10,759)

   

   3,653

   

   dollar

   

   May 2021

   

   118,063Citibank

   

   -

   

   (4,053)

   

   (4,053)

   

   (5,403)

   

   1,350

   

   dollar

   

   May 2021

   

   59,032148,898

   

   (15,539)

   

   133,360

   

   127,471

   

   5,888CPFL JaguariScotiabank

   

   -

   

   (1,156)

   

   (1,156)

   

   (1,076)

   

   (80)

   

   dollar

   

   July 2019

   

   16,484CPFL Sul PaulistaScotiabank

   

   -

   

   (1,156)

   

   (1,156)

   

   (1,076)

   

   (80)

   

   dollar

   

   July 2019

   

   16,484CPFL Leste PaulistaScotiabank

   

   -

   

   (1,156)

   

   (1,156)

   

   (1,076)

   

   (80)

   

   dollar

   

   July 2019

   

   16,484CPFL Santa CruzScotiabank

   

   -

   

   (1,156)

   

   (1,156)

   

   (1,076)

   

   (80)

   

   dollar

   

   July 2019

   

   16,484CPFL Paulista LajeadoItaú

   

   -

   

   (678)

   

   (678)

   

   (653)

   

   (25)

   

   dollar

   

   March 2018

   

   35,000CPFL BrasilItaú

   

   -

   

   (3,403)

   

   (3,403)

   

   (3,407)

   

   5

   

   dollar

   

   August 2018

   

   45,360Subtotal (a)

   

   734,590

   

   (107,610)

   

   626,980

   

   602,476

   

   24,504Derivatives to hedge debts not designated at fair valueExchange rate hedgeCPFL GeraçãoJ.P.Morgan

   

   -

   

   (6,807)

   

   (6,807)

   

   (2,045)

   

   (4,762)

   

   dollar

   

   December 2018

   

   47,645Price index hedgeCPFL GeraçãoSantander

   

   6,077

   

   -

   

   6,077

   

   5,922

   

   155

   

   IPCA

   

   April 2019

   

   35,235J.P.Morgan

   

   6,077

   

   -

   

   6,077

   

   5,922

   

   155

   

   IPCA

   

   April 2019

   

   35,23512,155

   

   -

   

   12,155

   

   11,845

   

   310Interest rate hedge (1)CPFL PaulistaBank of America Merrill Lynch

   

   -

   

   (1,242)

   

   (1,242)

   

   (810)

   

   (432)

   

   CDI

   

   July 2019

   

   660,000J.P.Morgan

   

   -

   

   (530)

   

   (530)

   

   (286)

   

   (244)

   

   CDI

   

   February 2021

   

   300,000Votorantim

   

   -

   

   (158)

   

   (158)

   

   (92)

   

   (66)

   

   CDI

   

   February 2021

   

   100,000Santander

   

   -

   

   (163)

   

   (163)

   

   (96)

   

   (67)

   

   CDI

   

   February 2021

   

   105,000-

   

   (2,093)

   

   (2,093)

   

   (1,284)

   

   (809)CPFL PiratiningaJ.P.Morgan

   

   -

   

   (207)

   

   (207)

   

   (135)

   

   (72)

   

   CDI

   

   July 2019

   

   110,000Votorantim

   

   -

   

   (168)

   

   (168)

   

   (116)

   

   (52)

   

   CDI

   

   February 2021

   

   135,000Santander

   

   -

   

   (115)

   

   (115)

   

   (84)

   

   (31)

   

   CDI

   

   February 2021

   

   100,000-

   

   (490)

   

   (490)

   

   (335)

   

   (155)RGEBradesco

   

   -

   

   (941)

   

   (941)

   

   (614)

   

   (328)

   

   CDI

   

   July 2019

   

   500,000Votorantim

   

   -

   

   (321)

   

   (321)

   

   (166)

   

   (155)

   

   CDI

   

   February 2021

   

   170,000-

   

   (1,262)

   

   (1,262)

   

   (779)

   

   (483)CPFL GeraçãoVotorantim

   

   138

   

   -

   

   138

   

   (221)

   

   359

   

   CDI

   

   August 2020

   

   460,000Subtotal (b)

   

   12,293

   

   (10,652)

   

   1,641

   

   7,181

   

   (5,540)Other derivatives (2)CPFL GeraçãoItaú

   

   20,028

   

   -

   

   20,028

   

   -

   

   20,028

   

   dollar

   

   September 2020

   

   26,627Votorantim

   

   16,688

   

   -

   

   16,688

   

   -

   

   16,688

   

   dollar

   

   September 2020

   

   26,627Santander

   

   20,999

   

   -

   

   20,999

   

   -

   

   20,999

   

   dollar

   

   September 2020

   

   33,060Subtotal (c)

   

   57,715

   

   -

   

   57,715

   

   -

   

   57,715Total (a+b+c)

   

   804,598

   

   (118,262)

   

   686,336

   

   609,657

   

   76,679Current

   

   163,241

   

   (6,055)Noncurrent

   

   641,357

   

   (112,207)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 applied the fair value hedge to some of its financial instruments and as a result debts were marked to market (note 17).
   F - 88


---



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 2016, 2015 and 2014, 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: Gain (Loss)Company

   

   Hedged risk / transaction

   

   2016

   

   2015

   

   2014CPFL Energia

   

   Exchange variation

   

   (76,202)

   

   71,492

   

   -CPFL Energia

   

   Mark to Market

   

   2,319

   

   (2,319)

   

   -CPFL Paulista

   

   Interest rate variation

   

   (1,423)

   

   (2,250)

   

   1CPFL Paulista

   

   Exchange variation

   

   (802,479)

   

   843,224

   

   96,017CPFL Paulista

   

   Mark to Market

   

   118,663

   

   (98,738)

   

   (21,297)CPFL Piratininga

   

   Interest rate variation

   

   (661)

   

   (609)

   

   51CPFL Piratininga

   

   Exchange variation

   

   (358,412)

   

   300,652

   

   35,808CPFL Piratininga

   

   Mark to Market

   

   48,193

   

   (32,431)

   

   (6,124)RGE

   

   Interest rate variation

   

   (835)

   

   (1,321)

   

   (28)RGE

   

   Exchange variation

   

   (252,321)

   

   291,612

   

   37,585RGE

   

   Mark to Market

   

   48,915

   

   (29,946)

   

   (7,170)CPFL Geração

   

   Interest rate variation

   

   3,161

   

   2,600

   

   303CPFL Geração

   

   Exchange variation

   

   (145,933)

   

   122,294

   

   21,650CPFL Geração

   

   Mark to Market

   

   66,425

   

   (7,896)

   

   (6,221)CPFL Santa Cruz

   

   Exchange variation

   

   (6,986)

   

   9,899

   

   2,604CPFL Santa Cruz

   

   Mark to Market

   

   148

   

   (80)

   

   (115)CPFL Leste Paulista

   

   Exchange variation

   

   (1,076)

   

   4,596

   

   1,453CPFL Leste Paulista

   

   Mark to Market

   

   (80)

   

   (76)

   

   (117)CPFL Sul Paulista

   

   Exchange variation

   

   (7,577)

   

   12,404

   

   2,333CPFL Sul Paulista

   

   Mark to Market

   

   170

   

   (83)

   

   (163)CPFL Jaguari

   

   Exchange variation

   

   (10,236)

   

   16,616

   

   2,146CPFL Jaguari

   

   Mark to Market

   

   273

   

   (63)

   

   (160)CPFL Mococa

   

   Exchange variation

   

   -

   

   2,022

   

   427CPFL Mococa

   

   Mark to Market

   

   -

   

   (33)

   

   (70)Paulista Lajeado

   

   Exchange variation

   

   (11,046)

   

   4,626

   

   -Paulista Lajeado

   

   Mark to Market

   

   1,649

   

   (1,675)

   

   -CPFL Telecom

   

   Exchange variation

   

   -

   

   3,204

   

   81CPFL Telecom

   

   Mark to Market

   

   -

   

   6

   

   (6)CPFL Brasil

   

   Exchange variation

   

   (13,857)

   

   5,367

   

   -CPFL Brasil

   

   Mark to Market

   

   2,383

   

   (2,378)

   

   -CPFL Serviços

   

   Exchange variation

   

   (3,420)

   

   3,810

   

   830CPFL Serviços

   

   Mark to Market

   

   254

   

   (87)

   

   (167)(1,399,988)

   

   1,514,439

   

   159,653
  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, 2016, the total amount contracted was US$ 86,313, considering the options already settled up to date. 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:   F - 89


---



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 20.9%.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 increase by R$ 864, resulting in a net asset of R$ 58,579.
  The following table reconciles the opening and closing balances of the call and put options for the year ended December 31, 2016, as required by IFRS 13:  Assets

   

   Liabilities

   

   NetAs of December 31, 2014

   

   

   

   -

   

   -

   

   -Measurement at fair value

   

   

   

   10,342

   

   (2,440)

   

   7,902Net cash received from settlement of flows

   

   (1,522)

   

   -

   

   (1,522)As of December 31, 2015

   

   

   

   8,820

   

   (2,440)

   

   6,380Measurement at fair value

   

   

   

   65,546

   

   2,440

   

   67,986Net cash received from settlement of flows

   

   (16,651)

   

   -

   

   (16,651)As of December 31, 2016

   

   

   

   57,715

   

   -

   

   57,715
 The fair value measurement of these financial instruments was recognized as finance income in the statement of profit or loss for the year, and no effects were recognized in other comprehensive income.  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, TJLP and SELIC), as shown below: c.1) Exchange ratevariation Considering the level of net exchange rate exposure at December 31, 2016 is maintained, the simulation of the effects by type of financial instrument for three different scenarios would be:   
 F - 90


---



Decrease (increase)Instruments

   

   Exposure R$ thousand (a)

   

   Risk

   

   Currency depreciation (b)

   

   Currency appreciation / depreciation of 25%

   

   Currency appreciation / depreciation of 50%Financial liability instruments

   

   (5,295,856)

   

   

   

   (462,134)

   

   977,364

   

   2,416,861Derivatives - Plain Vanilla Swap

   

   5,430,208

   

   

   

   473,858

   

   (1,002,158)

   

   (2,478,175)134,352

   

   drop in the dollar

   

   11,724

   

   (24,794)

   

   (61,314)Financial liability instruments

   

   (257,485)

   

   

   

   (30,664)

   

   41,374

   

   113,411Derivatives - Plain Vanilla Swap

   

   261,385

   

   

   

   31,128

   

   (42,000)

   

   (115,129)3,900

   

   drop in the euro

   

   464

   

   (626)

   

   (1,718)Total

   

   138,252

   

   

   

   12,188

   

   (25,420)

   

   (63,032)Decrease (increase)Instruments

   

   Exposure US$ thousand

   

   Risk

   

   Currency depreciation (b)

   

   Currency appreciation / depreciation of 25%(c)

   

   Currency appreciation / depreciation of 50%(c)Derivatives - Zero-cost collar

   

   86,314

   (d)

   rise of the dollar

   

   (68,386)

   

   (99,565)

   

   (130,743)(a) The exchange rates considered as of December 31, 2016 were R$ 3.26 per US$ 1.00 and R$ 3.41 per € 1.00.(b) As per the exchange curves obtained from information made available by the BM&FBOVESPA, with the exchange rate being considered at R$ 3.54 and R$ 3.81, and exchange depreciation at 8.73% and 11.91%, for the US$ and €, respectively.(c) The percentage increases in the ratios applied refer to the information made available by the BM&FBOVESPA.(d) Owing to the characteristics of this derivative (zero-cost collar), the notional amount is presented in US$.
  Based on the net exchange exposure in US$ and euro being an asset, the risk is a drop in the dollar and euro and, therefore, the local exchange rate is appreciated by 25% and 50% in relation to the probable exchange rate.
  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, 2016 is maintained, and (ii) the respective accumulated annual indexes for 2016 remain stable (CDI 13.63% p.a.; IGP-M 7.17% p.a.; TJLP 7.50% p.a.; IPCA 6.29% p.a. and SELIC 14.08% p.a.), the effects on the Company’s 2016 financial statements would be a net finance cost of R$ 1,377,463 (CDI R$ 1,200,603, IGP-M R$ 4,886, TJLP R$ 341,942 and SELIC R$ 156,936 and an income of IPCA R$ 326,804). 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)Instruments

   

   Exposure R$ thousand

   

   Risk

   

   Scenario I (a)

   

   Raise/drop ofindex by 25%**

   

   Raise/drop ofindex by 50%**Financial asset instruments

   

   6,773,850

   

   

   

   (151,057)

   

   41,998

   

   235,053Financial liability instruments

   

   (10,430,518)

   

   

   

   232,601

   

   (64,669)

   

   (361,939)Derivatives -Plain Vanilla Swap

   

   (5,151,860)

   

   

   

   114,886

   

   (31,942)

   

   (178,770)(8,808,528)

   

   CDI apprec.

   

   196,430

   

   (54,613)

   

   (305,656)Financial liability instruments

   

   (67,872)

   

   

   

   1,663

   

   862

   

   61(67,872)

   

   IGP-M apprec.

   

   1,663

   

   862

   

   61Financial liability instruments

   

   (4,559,227)

   

   

   

   -

   

   (85,486)

   

   (170,971)(4,559,227)

   

   TJLP apprec.

   

   -

   

   (85,486)

   

   (170,971)Financial liability instruments

   

   (139,692)

   

   

   

   2,053

   

   3,737

   

   5,420Derivatives -Plain Vanilla Swap

   

   88,889

   

   

   

   (1,307)

   

   (2,378)

   

   (3,449)Concession financial asset

   

   5,247,689

   

   

   

   (77,141)

   

   (140,376)

   

   (203,610)5,196,886

   

   drop in the IPCA

   

   (76,395)

   

   (139,017)

   

   (201,639)Financial liability instruments

   

   (199,681)

   

   

   

   5,052

   

   (714)

   

   (6,480)Sector financial asset and liability

   

   (914,921)

   

   

   

   23,148

   

   (3,271)

   

   (29,689)(1,114,602)

   

   SELIC apprec.

   

   28,200

   

   (3,985)

   

   (36,169)Total

   

   (9,353,343)

   

   

   

   149,898

   

   (282,239)

   

   (714,374)* The CDI, IGP-M, TJLP, IPCA and SELIC indexes considered of 11.4%, 4.72%, 7.5%, 4.82% and 11.55%, respectively, were obtained from information available in the market.** In compliance with CVM Instruction 475/08, the percentage of raise/drop of 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, 2016, taking into account principal and interest, and is based on the undiscounted cash flow, considering the earliest date on which the Company and its subsidiaries have to settle their respective obligations.   F - 91


---









December 31, 2016

   

   Note

   

   Weighted average interest rates

   

   Less than 1 month

   

   1-3 months

   

   3 months to 1 year

   

   1-3 years

   

   4-5 years

   

   More than 5 years

   

   TotalTrade payables

   

   16

   

   

   

   2,641,544

   

   81,808

   

   4,778

   

   129,781

   

   -

   

   -

   

   2,857,911Borrowings - principal and interest

   

   17

   

   12.04% p.a.

   

   125,661

   

   682,898

   

   2,039,166

   

   8,537,020

   

   2,590,956

   

   2,887,932

   

   16,863,633Derivatives

   

   35

   

   

   

   286

   

   815

   

   16,826

   

   55,179

   

   97,752

   

   -

   

   170,858Debentures - principal and interest

   

   18

   

   14.22% p.a.

   

   93,758

   

   269,536

   

   2,044,542

   

   6,761,502

   

   2,127,274

   

   438,843

   

   11,735,455Regulatory charges

   

   20

   

   

   

   366,078

   

   -

   

   -

   

   -

   

   -

   

   -

   

   366,078Use of public asset

   

   23

   

   13.77% p.a.

   

   1,987

   

   4,149

   

   19,522

   

   44,487

   

   62,102

   

   234,601

   

   366,848Others

   

   24

   

   

   

   46,625

   

   91,395

   

   18,565

   

   44,711

   

   -

   

   17,750

   

   219,045Consumers and concessionaires

   

   

   

   

   

   11,432

   

   52,940

   

   9,492

   

   44,711

   

   -

   

   -

   

   118,575EPE / FNDCT / PROCEL (*)

   

   

   

   

   

   1,457

   

   2,397

   

   9,073

   

   -

   

   -

   

   -

   

   12,927Collections agreement

   

   

   

   

   

   33,736

   

   36,057

   

   -

   

   -

   

   -

   

   -

   

   69,793Reversal fund

   

   

   

   

   

   -

   

   -

   

   -

   

   -

   

   -

   

   17,750

   

   17,750Total

   

   

   

   

   

   3,275,940

   

   1,130,600

   

   4,143,399

   

   15,572,679

   

   4,878,084

   

   3,579,127

   

   32,579,828 (*) EPE - Energy research company; FNDCT - National scientific and technological development fund; and PROCEL - National Program for Electric Energy Savings.




( 36 )COMMITTMENTS


The Company’s commitments as regards long-term energy purchase agreements and plant construction projects at December 31, 2016, as follows:



Commitments at December 31, 2016

   

   Duration

   

   Less than 1 year

   

   1-3 years

   

   4-5 years

   

   More than 5 years

   

   TotalEnergy purchase agreements (except Itaipu)

   

   Up to 29 years

   

   9,433,125

   

   17,967,834

   

   16,493,436

   

   59,486,713

   

   103,381,108Energy purchase from Itaipu

   

   Up to 29 years

   

   2,589,135

   

   5,419,669

   

   5,985,978

   

   24,175,651

   

   38,170,433Energy system service charges

   

   Up to 34 years

   

   2,031,659

   

   6,916,109

   

   8,573,355

   

   29,439,307

   

   46,960,430GSF renegotiation

   

   Up to 26 years

   

   17,882

   

   -

   

   35,899

   

   266,279

   

   320,059Power plant constrution projects

   

   Up to 3 years

   

   1,560,470

   

   8,676

   

   -

   

   -

   

   1,569,146Trade payables

   

   Up to 17 years

   

   1,819,714

   

   1,253,650

   

   314,992

   

   496,760

   

   3,885,116Total

   

   

   

   17,451,985

   

   31,565,937

   

   31,403,661

   

   113,864,710

   

   194,286,292




The power plant construction projects include commitments made basically to construction related to the subsidiaries of the renewable energy segment.



( 37 )NON-CASH TRANSACTION




Dec 31, 2016

   

   Dec 31, 2015

   

   Dec 31, 2014Transactions resulting from business combinationsBorrowings and debentures

   

   (1,156,621)

   

   -

   

   (1,009,877)Concession financial asset

   

   876,281

   

   -

   

   -Intangible assets - distribution infrastructure acquired

   

   1,456,472

   

   -

   

   -Property, plant and equipment acquired

   

   -

   

   -

   

   1,616,999Intangible assets acquired

   

   413,796

   

   -

   

   626,399Other net assets acquired

   

   1,911

   

   -

   

   (328,928)1,591,839

   

   -

   

   904,593Cash and cash equivalents acquired

   

   (95,164)

   

   -

   

   (70,930)Consideration paid in the acquisition, net

   

   1,496,675

   

   -

   

   (833,663)Other transactionsCapital increase through earnings reserve

   

   392,272

   

   554,888

   

   -Interest capitalized in property, plant and equipment

   

   54,733

   

   34,212

   

   4,225Interest capitalized in concession financial asset - distribution infrastructure

   

   13,349

   

   11,358

   

   8,044Escrow deposits to property, plant and equipment

   

   3,418

   

   -

   

   -Reversal of contingencies against intangible assets

   

   7,591

   

   -

   

   -Transfers between property, plant and equipment and other assets

   

   14,592

   

   2,928

   

   16,430Provision for socio environmental costscapitalized in property, plant and equipment

   

   -

   

   -

   

   9,193Realization of noncontrolling interests`capital reserve against receivables

   

   -

   

   -

   

   2,189Transfers from concession financial asset and intangible asset to property, plant and equipment as a result of the spin-off of generation activity in distribution companies

   

   -

   

   -

   

   5,828




F - 92



---



( 38 )RELEVANT FACT AND EVENTS AFTER THE REPORTING PERIOD
  38.1 Acquisition of ownership interest in the Company by State Grid International Development Limited In a Significant Event Notice disclosed to the market on July 1, 2016, the Company disclosed that it received from its controlling shareholder Camargo Corrêa S.A. (“CCSA”) a communication on the proposal received from State Grid International Development Limited for the acquisition of the entire ownership interest relating to the Company’s control block. On September 2, 2016, the Company received from CCSA a correspondence confirming the signing of the acquisition contract. On November 23, 2016, the Company disclosed a Significant Event Notice informing that ANEEL approved, on that date, the request for approval of the transfer of shares of CPFL Energia held by the shareholders that are part of its control block (“Controlling Shareholders”) to State Grid Brazil Power Participações Ltda. (“State Grid”), Brazilian subsidiary of State Grid International Development Limited. This authorization was the last condition precedent for the closing of the transaction and the consummation of the transfer of shares of CPFL Energia held by the Controlling Shareholders to State Grid. On January 23, 2017, the Company disclosed a Significant Event Notice informing that it received, on that date, a correspondence from State Grid Brazil Power Participações Ltda. (“State Grid Brazil”) informing that on that date the Share Purchase Agreement dated September 2, 2016 between State Grid Brazil, Camargo Correa S.A., Caixa de Previdência dos Funcionários do Banco do Brasil – PREVI, Fundação CESP, Fundação Sistel de Seguridade Social, Fundação Petrobras de Seguridade Social – PETROS, Fundação SABESP de Seguridade Social — SABESPREV, and certain other parties, had been signed, therefore the transaction has been closed.   This Significant Event Notice also disclosed the conditions for the transaction regarding (i) closing and shares acquired, (ii) price per share of CPFL Energia; (iii) price per share of CPFL Renováveis; (iv) OPAs for sale of control; (v) OPA price for sale of control; (vi) Possibility of cancelation of registration of CPFL Energia and/or CPFL Renováveis; (vii) termination of control of shareholders, and other material information. After finalizing the transaction, State Grid Brazil became the parent company of CPFL Energia with 54.64% (556,164.817 shares, direct or indirect) of the Company’s voting and total capital. The total price paid for the direct and indirect acquisition of shares was R$ 25.51 per share, totaling approximately R$ 14.19 billion.  With the transaction, State Grid Brazil Power Participações Ltda. became the only controlling shareholder of the Company, and the Shareholders’ Agreement dated March 22, 2002 signed among the former shareholders was terminated. The members of the Board of Directors and Fiscal Council (except the director elected as independent member) resigned on the same date. The election of the alternate members for the vacant positions of the Board of Directors and the Fiscal Council occurred at the Extraordinary General Meeting held on February 16, 2017, according to the call notice and Management’s Proposal . As the closing occurred on January 23, 2017, after all conditions precedent were met, this transaction did not generate impacts on the Company’s ownership structure as at December 31, 2016.  F - 93


---



38.2 Approval for fundraising 38.2.1 Approval for issue of debentures of CPFL Piratininga and RGE The Board of Directors of the subsidiaries authorized, on January 25, 2017, the 8th issue of simple non-convertible debentures. The debentures were issued on February 15, 2017.  Subsidiary

   

   Issue

   

   Quantity issued

   Amount

   

   Maturity

   

   Interest

   

   UtilizationCPFL Piratininga

   

   8th issue -

   1st series

   60,000

   

   60,000

   

   Feb. 2024

   

   Semiannual

   

   Implementation and development of investment projects in substations and transmission linesCPFL Piratininga

   

   8th issue -

   2nd series

   246,000

   

   246,000

   

   Feb. 2022

   

   Semiannual

   

   Working capital improvement and extension of the debt profileRGE

   

   8th issue -

   1st series

   130,000

   

   130,000

   

   Feb. 2024

   

   Semiannual

   

   Implementation and development of investment projects in substations and transmission linesRGE

   

   8th issue -

   2nd series

   250,000

   

   250,000

   

   Feb. 2022

   

   Semiannual

   

   Working capital improvement and extension of the debt profile686,000
  38.2.2Approval for fundraising in foreign currency (Law 4,131) – CPFL Geração, CPFL Paulista, RGE and RGE Sul On February 1, 2017, the Board of Directors approved the raising of borrowings for the following subsidiaries: - CPFL Paulista: up to R$2,225,000; - CPFL Geração: up to R$679,000; - RGE Sul: up to R$390,000; and - RGE: up to R$ 308,000. These approvals will occur through borrowings based on Law 4,131/62 and/or roll over of the current debts in foreign currency with swap for CDI, as well as the assignment of swap in guarantee, Rural Credit, Bank Credit Note, Promissory Notes with take out of long-term debts, Issue of Debentures, Assumption of Debts, other working capital transactions.  38.3 Interim dividend for the 1st half of 2016 According to the Notice to the Shareholders of January 5, 2017, at a meeting held on the same date the Company’s Board of Directors approved the proposal for “Interim Dividend”, relating to the first half of 2016, which will be attributed to the mandatory minimum dividend for 2016, in the amount of R$ 221,780, equivalent to R$ 0.217876793 per share. The dividend proposed was paid on January 20, 2017, to the shareholders holding Company shares on January 12, 2017, and the shares will now be traded “ex-dividend” on the Bolsa de Valores, Mercadorias e Futuros – BM&FBOVESPA S.A. (“BM&FBovespa”) and on the New York Stock Exchange (“NYSE”) from January 13, 2017.  38.4Share Acquisition Public Offer As per the significant event notice on February 16, 2017, State Grid Brazil Power Participações will conduct a public offer for acquisition of all the common shares held by the remaining shareholders of CPFL Energia (“Acquisition Public Offer”), pursuant to the prevailing legislation and CPFL’s Bylaws. State Grid Brazil has also the intention of, together with the Acquisition Public Offer, conduct a unified public offer for acquisition of Company common shares aimed to: (i) cancel its listing as publicly-traded company with the CVM under the category “A” and its conversion to category “B” (“Offer for Conversion of Listing”); and (ii) withdraw the Company from the Special Listing Segment of BM&FBOVESPA namedNovo Mercado(“Offer for Withdrawal fromNovo Mercado”), in conformity with the relevant legislation. State Grid Brazil also intends to perform the following: (i) the deposit agreement relating to the American depositary of the Company’s shares to


be terminated, (ii) the Company to withdraw from the NYSE, and (iii) the Company’s listing as publicly-traded company in the United States to be canceled.  
 F - 94


---



CPFL Energia also informs that, due to the intention expressed by State Grid Brazil, the Company’s shareholders  decided in an Extraordinary General Meeting on March 27, 2017, on the (i) selection of the specialized institution Credit Suisse (Brasil) S.A. for determining the Company’s economic value based on a triple list to be submitted by the Board of Directors, as provided for in theNovo MercadoRegulation and the Company’s Bylaws; (ii) cancelation of the Company’s listing with CVM as issuer of securities registered under the category “A”, and their conversion into category “B”; and (iii) Company’s withdrawal from theNovo Mercadolisting segment of BM&FBOVESPA S.A.– Bolsa de Valores, Mercadorias e Futuros.  As per Significant Event Notice disclosed by both companies to the market on February 23, 2017, State Grid Brazil filled with the CVM on February 22, 2017 a request of authorization for a Public Tender Offer for acquisition of CPFL Energia’s shares. Such request is currently under analysis by CVM.  38.5 Annual Tariff Revisions — CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari, CPFL Mococa and CPFL Paulista The table below shows the impact of this revision of our subsidiaries mentioned above, published on March 21, 2017 for CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa, and on April 04, 2017 for CPFL Paulista.  Resolution

   Economic adjustment

   Regulatory adjustment

   TOTALCPFL Jaguari

   2,213

   3.88%

   -1.83%

   2.05%CPFL Sul Paulista

   2,209

   0.98%

   0.66%

   1.64%CPFL Mococa

   2,212

   3.45%

   -1.80%

   1.65%CPFL Santa Cruz

   2,211

   1.37%

   -2.65%

   -1.28%CPFL Leste Paulista

   2,210

   3.18%

   -2.42%

   0.76%CPFL Paulista

   2,217

   2.13%

   -2.93%

   -0.80%
  F - 95


---



( 39 )CONDENSED UNCONSOLIDATED FINANCIAL INFORMATION
 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, 2016 and December 31, 2015 and for the years ended on December 31, 2016, 2015 and 2014 presented herein was 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, 2016

   

   December 31, 2015Cash and cash equivalents

   64,973

   

   424,192Dividends and interest on capital

   642,978

   

   1,227,590Derivatives

   -

   

   70,153Other receivables

   83,065

   

   73,827Total current assets

   791,016

   

   1,795,763Deferred tax assets

   171,073

   

   140,389Investments

   7,866,100

   

   6,940,036Other receivables

   80,775

   

   72,282Total noncurrent assets

   8,117,948

   

   7,152,706Total assets

   8,908,964

   

   8,948,469
   LIABILITIES

   

   December 31, 2016

   

   December 31, 2015Interest on debts

   

   -

   

   38,057Interest on debentures

   

   15,334

   

   -Borrowings

   

   -

   

   935,196Dividends and interest on capital

   

   218,630

   

   212,531Derivatives

   

   -

   

   981Other payables

   

   21,791

   

   19,945Total current liabilities

   

   255,755

   

   1,206,708Debentures

   

   612,251

   

   -Provision for tax, civil and labor risks

   

   1,008

   

   1,635Allowance for equity investment losses

   

   19,302

   

   33,969Other payables

   

   50,628

   

   31,961Total noncurrent liabilities

   

   683,188

   

   67,565Equity

   

   7,970,021

   

   7,674,196Total liabilities and equity

   

   8,908,964

   

   8,948,469
        F - 96


---



UNCONSOLIDATED STATEMENTS OF PROFIT OR LOSS FOR THE YEAR   2016

   

   2015

   

   2014Net operating revenue

   

   1,713

   

   1,157

   

   61General and administrative expenses

   

   (50,860)

   

   (29,911)

   

   (26,175)Income from electric energy service

   

   (49,147)

   

   (28,754)

   

   (26,114)Equity interests in subsidiaries, associates and joint ventures

   

   922,362

   

   926,951

   

   1,011,185Finance income (costs)

   

   17,183

   

   (22,948)

   

   (25,464)Profit before taxes

   

   890,398

   

   875,250

   

   959,607Social contribution and income tax

   

   10,487

   

   (10,309)

   

   (10,430)Profit for the year

   

   900,885

   

   864,940

   

   949,1772016

   

   2015

   

   2014Profit for the year

   

   900,885

   

   864,940

   

   949,177Items that will not be reclassified subsequently to profit and lossEquity in comprehensive income of subsidiaries

   

   (394,175)

   

   65,547

   

   (225,720)Total comprehensive income for the year

   

   506,709

   

   930,488

   

   723,457
      F - 97


---



UNCONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEAR   2016

   

   2015

   

   2014OPERATING CASH FLOWProfit before taxes

   

   890,398

   

   875,250

   

   959,607ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIESDepreciation and amortization

   

   193

   

   170

   

   173Provision for tax, civil and labor risks

   

   425

   

   1,497

   

   640Interest on debts, inflation adjustment and exchange rate changes

   

   42,395

   

   94,588

   

   142,278Equity interests in subsidiaries, associates and joint ventures

   

   (922,362)

   

   (926,951)

   

   (1,011,185)11,049

   

   44,553

   

   91,513DECREASE (INCREASE) IN OPERATING ASSETS AND LIABILITIESDividends and interest on capital received

   

   1,606,073

   

   627,014

   

   1,248,982Taxes recoverable

   

   3,261

   

   (12,350)

   

   1,564Other operating assets and liabilities

   

   8,459

   

   (2,526)

   

   3,905CASH FLOWS PROVIDED BY OPERATIONS

   

   1,628,842

   

   656,691

   

   1,345,964Interest paid on debts and debentures

   

   (45,470)

   

   (36,858)

   

   (138,599)Income tax and social contribution paid

   

   (27,117)

   

   (2,172)

   

   (21,463)NET CASH FROM OPERATING ACTIVITIES

   

   1,556,255

   

   617,661

   

   1,185,902INVESTING ACTIVITIESCapital increase in investees

   

   -

   

   (490,010)

   

   (360,000)Advance for future capital increases

   

   (1,384,520)

   

   (52,680)

   

   (27,153)Other investing activities

   

   (42,178)

   

   10,298

   

   (2,835)NET CASH USED IN INVESTING ACTIVITIES

   

   (1,426,698)

   

   (532,392)

   

   (389,988)FINANCING ACTIVITIESBorrowings and debentures raised

   

   609,060

   

   829,997

   

   -Repayment of principal of borrowings and debentures

   

   (888,408)

   

   (1,290,000)

   

   -Repayment of derivatives

   

   (4,711)

   

   -

   

   -Dividends and interest on capital paid

   

   (204,717)

   

   (850)

   

   (986,811)NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES

   

   (488,776)

   

   (460,853)

   

   (986,811)NET INCREASE IN CASH AND CASH EQUIVALENTS

   

   (359,219)

   

   (375,584)

   

   (190,897)CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR

   

   424,192

   

   799,775

   

   990,672CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR

   

   64,973

   

   424,192

   

   799,775
  Following is the information relating to CPFL Energia's unconsolidated condensed financial statements presented above:
 a.Cash and cash equivalents:  December 31, 2016

   

   December 31, 2015Bank balances

   426

   

   311Investment funds

   64,548

   

   423,881Total

   64,973

   

   424,192
 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.    F - 98


---



b.Dividends and interest on equity:  Dividend

   Interest on capital

   TotalSubsidiary

   December 31, 2016

   

   December 31, 2015

   

   December 31, 2016

   

   December 31, 2015

   

   December 31, 2016

   

   December 31, 2015CPFL Paulista

   -

   

   612,585

   

   -

   

   52,383

   

   -

   

   664,968CPFL Piratininga

   72,080

   

   172,239

   

   -

   

   27,084

   

   72,080

   

   199,323CPFL Santa Cruz

   -

   

   19,527

   

   -

   

   7,517

   

   -

   

   27,044CPFL Leste Paulista

   -

   

   3,220

   

   -

   

   2,102

   

   -

   

   5,321CPFL Sul Paulista

   8,641

   

   3,848

   

   1,986

   

   1,986

   

   10,627

   

   5,834CPFL Jaguari

   6,115

   

   1,152

   

   -

   

   -

   

   6,115

   

   1,152CPFL Mococa

   -

   

   2,499

   

   -

   

   1,234

   

   -

   

   3,734RGE

   24,672

   

   67,815

   

   -

   

   64,073

   

   24,672

   

   131,887CPFL Geração

   396,086

   

   103,532

   

   -

   

   -

   

   396,086

   

   103,532CPFL Centrais Geradoras

   -

   

   1,185

   

   -

   

   -

   

   -

   

   1,185CPFL Jaguari Geração

   1,664

   

   1,667

   

   -

   

   -

   

   1,664

   

   1,667CPFL Brasil

   86,020

   

   41,176

   

   1,650

   

   1,601

   

   87,671

   

   42,777CPFL Planalto

   -

   

   458

   

   -

   

   -

   

   -

   

   458CPFL Serviços

   -

   

   12,026

   

   -

   

   -

   

   -

   

   12,026CPFL Atende

   1,953

   

   -

   

   554

   

   -

   

   2,507

   

   -Nect

   5,600

   

   4,539

   

   -

   

   -

   

   5,600

   

   4,539CPFL Total

   -

   

   5,589

   

   -

   

   -

   

   -

   

   5,589CPFL ESCO

   9,565

   

   9,565

   

   16,325

   

   6,354

   

   25,891

   

   15,920AUTHI

   10,064

   

   634

   

   -

   

   -

   

   10,064

   

   634622,462

   

   1,063,256

   

   20,516

   

   164,334

   

   642,978

   

   1,227,590
 c.Other receivables:  Current

   

   NoncurrentDecember 31, 2016

   

   December 31, 2015

   

   December 31, 2016

   

   December 31, 2015Taxes recoverable

   82,836

   

   72,885

   

   -

   

   -Associates and subsidiaries

   -

   

   -

   

   52,582

   

   2,814Escrow deposits

   -

   

   -

   

   710

   

   630Advance for future capital increase

   -

   

   -

   

   -

   

   52,680Loans and financing guarantees of subsidiaries

   -

   

   -

   

   26,261

   

   14,919Others

   229

   

   942

   

   1,223

   

   1,239Total

   83,064

   

   73,827

   

   80,775

   

   72,282
 d.Deferred tax assets  December 31, 2016

   

   December 31, 2015Social contribution credit (debit)Tax losses carryforwards

   42,841

   

   46,602Temporarily nondeductible differences

   1,125

   

   (5,918)Subtotal

   43,966

   

   40,684Income tax credit (debit)Tax losses carryforwards

   123,980

   

   116,438Temporarily nondeductible differences

   3,126

   

   (16,733)Subtotal

   127,106

   

   99,705Total

   171,073

   

   140,389
 e.Investment: The financial information of subsidiaries and joint ventures are accounted for using the equity method of accounting.   F - 99


---



Number of shares (thousand)

   

   December 31, 2016

   

   December 31, 2015

   

   2016

   

   2015

   

   2014Investment

   

   

   Equity interest

   

   Share of profit (loss) of investeesCPFL Paulista

   

   880,653

   

   1,063,400

   

   1,352,393

   

   255,329

   

   298,203

   

   502,719CPFL Piratininga

   

   53,096,770

   

   355,755

   

   537,670

   

   68,114

   

   211,637

   

   187,715CPFL Santa Cruz

   

   371,772

   

   140,520

   

   131,149

   

   23,797

   

   12,424

   

   49,052CPFL Leste Paulista

   

   892,772

   

   52,853

   

   46,301

   

   10,731

   

   13,556

   

   7,173CPFL Sul Paulista

   

   454,958

   

   58,895

   

   55,233

   

   8,455

   

   16,201

   

   11,351CPFL Jaguari

   

   209,294

   

   30,255

   

   28,521

   

   7,988

   

   4,852

   

   2,027CPFL Mococa

   

   117,199

   

   33,824

   

   29,205

   

   9,198

   

   6,679

   

   10,248RGE

   

   1,019,790

   

   1,614,320

   

   1,580,807

   

   102,647

   

   145,804

   

   177,672CPFL Geração

   

   205,492,020

   

   2,158,384

   

   2,169,922

   

   401,148

   

   240,520

   

   16,499CPFL Jaguari Geração (*)

   

   40,108

   

   45,099

   

   42,729

   

   6,655

   

   6,670

   

   (4,657)CPFL Brasil

   

   2,999

   

   109,054

   

   51,779

   

   104,235

   

   81,929

   

   136,876CPFL Planalto (*)

   

   630

   

   2,101

   

   2,003

   

   2,476

   

   1,830

   

   2,238CPFL Serviços

   

   1,509,882

   

   97,968

   

   7,117

   

   (8,175)

   

   (17,952)

   

   5,719CPFL Atende (*)

   

   13,991

   

   17,150

   

   17,373

   

   5,833

   

   7,776

   

   6,849Nect (*)

   

   2,059

   

   10,295

   

   16,087

   

   13,424

   

   18,155

   

   10,812CPFL Total (*)

   

   19,005

   

   27,570

   

   19,930

   

   12,817

   

   5,836

   

   10,327CPFL Jaguariuna (*)

   

   3,156

   

   1,256,161

   

   2,496

   

   (35,498)

   

   (167)

   

   1CPFL Telecom

   

   55,420

   

   (19,302)

   

   (33,969)

   

   (33,333)

   

   (60,718)

   

   (8,339)CPFL Centrais Geradoras (*)

   

   16,128

   

   15,459

   

   19,972

   

   (958)

   

   4,740

   

   4,720CPFL ESCO

   

   48,164

   

   61,543

   

   66,038

   

   5,926

   

   35,194

   

   1,602AUTHI (*)

   

   2,610

   

   16,810

   

   1,913

   

   24,264

   

   2,537

   

   -Subtotal - By subsidiary's equity

   

   

   

   7,148,112

   

   6,144,668

   

   985,074

   

   1,035,703

   

   1,130,604Amortization of fair value adjustments of assets

   

   

   

   -

   

   -

   

   (62,713)

   

   (108,754)

   

   (119,419)Total

   

   

   

   7,148,112

   

   6,144,668

   

   922,362

   

   926,950

   

   1,011,185Investment

   

   

   

   5,811,894

   

   6,178,637Advances for future capital increases

   

   

   

   1,355,520

   

   -Allowance for equity investment losses

   

   

   

   (19,302)

   

   (33,969)(*) number of quotas
  As at December 31, 2016, the balances of advance for future capital increase comprised advances to the following subsidiaries: (i) R$ 1,299,520 to CPFL Jaguariúna, (ii) R$ 56,000 to CPFL Serviços; and (iii) R$ 29,000 to CPFL Telecom (allowance for equity investment losses).
  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 (AGM/EGM), in the first half of 2016 the Company recognized the amount of R$ 278,520 by way of dividends and interest on capital for the year 2015. The subsidiaries also declared in 2016: (i) interim dividends and interest on capital of R$ 590,196, related to interim income of 2016; and (ii) R$ 164,771 as minimum mandatory dividend receivable related to 2016. Of the amounts recorded as receivables, the amount of R$1,606,073 was paid to the Company by the subsidiaries in 2016. The dividends received are comprised as follows:   F - 100


---



2016

   

   2015

   

   2014CPFL Paulista

   

   948,624

   

   425,400

   

   424,751CPFL Piratininga

   

   267,647

   

   -

   

   246,693CPFL Santa Cruz

   

   40,009

   

   -

   

   26,007CPFL Leste Paulista

   

   9,242

   

   -

   

   39,587CPFL Sul Paulista

   

   -

   

   -

   

   39,883CPFL Jaguari

   

   1,291

   

   806

   

   10,752CPFL Mococa

   

   7,991

   

   -

   

   32,881RGE

   

   172,432

   

   113,012

   

   -CPFL Geração

   

   110,532

   

   -

   

   278,653CPFL Brasil

   

   1,601

   

   52,599

   

   106,464CPFL Jaguari Geração

   

   4,288

   

   998

   

   9,683CPFL Planalto

   

   2,835

   

   1,002

   

   5,591CPFL Serviços

   

   -

   

   7,683

   

   -CPFL Atende

   

   3,382

   

   7,899

   

   5,006CPFL Total

   

   10,767

   

   4,734

   

   7,999Nect

   

   18,155

   

   10,780

   

   11,256CPFL Centrais Geradoras

   

   4,740

   

   1,720

   

   3,776CPFL ESCO

   

   -

   

   380

   

   -Authi

   

   2,537

   

   -

   

   -TOTAL

   

   1,606,073

   

   627,014

   

   1,248,982
 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:   December 31, 2016

   

   December 31, 2015Interest

   

   Current

   

   Noncurrent

   

   Total

   

   Interest

   

   Current

   

   Noncurrent

   

   Total5th Issue

   Single series

   

   18,069

   

   -

   

   620,000

   

   638,069

   

   -

   

   -

   

   -

   

   -
 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. ************




F - 101