CPFL Energy (CPL) 20-F 2017 FY Annual report (foreign)

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

FORM 20‑F

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

for the fiscal year ended December 31, 2017
Commission File Number 1‑32297

CPFL ENERGIA S.A.

(Exact name of registrant as specified in its charter)

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

Rodovia Engenheiro Miguel Noel Nascentes Burnier, 1,755, km 2,5
Parque São Quirino
Campinas
São Paulo ‑ 13088 140
(Address of principal executive offices)

Gustavo Estrella
+55 19 3756 8704 – gustavoestrella@cpfl.com.br
Federative Republic of Brazil
(Name, telephone, e‑mail and/or facsimile
number and address of company contact person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class:	Name of each exchange on which registered:
Common Shares, without par value* American Depositary Shares (as evidenced by American Depositary Receipts), each representing 2 Common Shares	New York Stock Exchange

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

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

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

As of December 31, 2017, there were 1,017,914,746 common shares, without par value, outstanding

 

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

Yes T   No £ 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934.

Yes £   No T 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes T   No £ 

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

Yes £   No £  N/A T 

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

Large Accelerated Filer T   Accelerated Filer £   Non‑accelerated Filer £ 

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.£

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP £   IFRS T   Other £ 

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

Item 17£   Item 18 £ 

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

Yes £   No T 

 

Table of Contents

		Page
Contents
FORWARD-LOOKING STATEMENTS		1
CERTAIN TERMS AND CONVENTIONS		1
PRESENTATION OF FINANCIAL AND OTHER INFORMATION		2
ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	2
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	2
ITEM 3.	KEY INFORMATION	2
ITEM 4.	INFORMATION ON THE COMPANY	17
ITEM 4A.	UNRESOLVED STAFF COMMENTS	64
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	64
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	101
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	111
ITEM 8.	FINANCIAL INFORMATION	111
ITEM 9.	THE OFFER AND LISTING	114
ITEM 10.	ADDITIONAL INFORMATION	116
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	133
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	134
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	135
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	135
ITEM 15.	CONTROLS AND PROCEDURES	135
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	136
ITEM 16B.	CODE OF ETHICS	136
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	137
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	137
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	137
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	138
ITEM 16G.	CORPORATE GOVERNANCE	138

 

ITEM 16H.	MINE SAFETY DISCLOSURE	139
ITEM 17.	FINANCIAL STATEMENTS	139
ITEM 18.	FINANCIAL STATEMENTS	139
ITEM 19.	EXHIBITS	139
GLOSSARY OF TERMS		141
SIGNATURES		145

 

FORWARD‑LOOKING STATEMENTS

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

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

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

· electricity shortages;

· changes in tariffs;

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

· potential disruption or interruption of our services;

· interest rate fluctuation, inflation and exchange rate variation;

· actions taken by our major shareholders;

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

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

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

· changes in consumer demand;

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

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

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

CERTAIN TERMS AND CONVENTIONS

A glossary of electricity industry terms is included in this annual report, beginning on page 141.

1

 

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 audited annual 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, 2017, 2016, 2015, 2014, and 2013.  Our financial data as of December 31, 2017 and 2016 and for each of the three years in the period ended December 31, 2017, 2016 and 2015 was derived from our audited annual 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 and 2013 and for each of the two years ended December 31, 2014 and 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.

2

 

STATEMENT OF OPERATIONS DATA

	For the year ended December 31,
	2017(3)	2017	2016	2015(4)	2014(4)	2013(4)
	US$	R$	R$	R$	R$	R$
	(in millions, except per share and per ADS data)
Net operating revenue	8,085	26,745	19,112	20,599	17,399	14,634
Cost of electric energy services:
Cost of electric energy	5,109	16,902	11,200	13,312	10,643	8,197
Operating cost	838	2,771	2,249	1,907	1,672	1,468
Services rendered to third parties	627	2,075	1,357	1,049	946	1,010
Gross operating income	1,511	4,998	4,306	4,331	4,138	3,960
Operating expenses:
Sales expenses	178	590	547	465	403	377
General and administrative expenses	286	947	849	863	774	929
Other operating expense	132	438	387	358	328	285
Income from electric energy service	914	3,022	2,523	2,645	2,633	2,370
Interest in associates and joint ventures	94	312	311	217	60	121
Financial income (expense):
Income	266	880	1,201	1,143	786	699
Expense	(716)	(2,368)	(2,654)	(2,551)	(1,969)	(1,671)
Net financial income (expenses)	(450)	(1,488)	(1,453)	(1,408)	(1,183)	(971)
Income before taxes	558	1,847	1,381	1,454	1,511	1,519
Social contribution	(51)	(169)	(151)	(160)	(169)	(157)
Income tax	(132)	(435)	(351)	(419)	(455)	(413)
Total taxes	(183)	(604)	(501)	(579)	(624)	(570)
Net income	376	1,243	(879)	875	886	949
Net income attributable to controlling shareholders	357	1,180	901	865	949	937
Net income (loss) attributable to non‑controlling shareholders	19	63	(22)	10	(63)	12
Earnings per share attributable to controlling shareholders(1):
Basic	0.35	1.16	0.89	0.85	0.93	0.92
Diluted	0.35	1.15	0.87	0.83	0.92	0.90
Net income per ADS:
Basic	0.70	2.32	1.77	1.70	1.86	1.84
Diluted	0.70	2.30	1.74	1.66	1.83	1.79
Dividends(2)	85	280	214	205	977	931
Weighted average of number of common shares (in millions)(1).	1,018	1,018	1,018	1,018	1,018	1,018
Dividends per share(1)(2)	0.08	0.28	0.21	0.20	0.96	0.91
Dividends per ADS (2)	0.17	0.55	0.42	0.40	1.92	1.83

(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. 

(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, 2017 of R$3.308to US$1.00.The average of the month-end commercial selling rates during the year 2017 was R$3.202to 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 January 1, 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.    The selected historical financial data for 2013 has not been restated to reflect the reclassification, and therefore is not fully comparable with the data for 2017, 2016, 2015 and 2014.

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BALANCE SHEET DATA

	For the year ended December 31,
	2017(2)	2017	2016	2015	2014(3)	2013
	US$	R$	R$	R$	R$	R$
	(in millions)
Current assets:
Cash and cash equivalents	982	3,250	6,165	5,683	4,357	4,206
Consumers, concessionaires and licensees	1,300	4,301	3,766	3,175	2,251	2,008
Derivatives	134	444	163	627	23	2
Sector financial assets	64	211	-	1,464	611	-
Other current assets	416	1,375	1,285	1,559	1,972	1,048
Total current assets	2,896	9,581	11,379	12,509	9,215	7,264
Noncurrent assets:
Accounts receivable	72	237	203	129	123	154
Derivatives	62	204	641	1,651	585	317
Sector financial assets	107	355	-	490	322	-
Financial asset of concession	1,979	6,546	5,363	3,597	2,835	2,787
Investments in joint-ventures	303	1,002	1,494	1,248	1,099	1,033
Property, plant and equipment	2,959	9,787	9,713	9,173	9,149	7,717
Intangible Assets	3,201	10,590	10,776	9,210	8,930	8,748
Other noncurrent assets	901	2,979	2,602	2,525	2,887	3,022
Total noncurrent assets	9,583	31,700	30,792	28,024	25,930	23,778
Total assets	12,479	41,282	42,171	40,532	35,144	31,043
Current liabilities:
Short‑term debt(1)	1,600	5,293	3,429	3,641	3,526	1,837
Sector financial liabilities	12	40	598	-	22	-
Other current liabilities	1,828	6,046	4,992	5,884	3,869	3,068
Total current liabilities	3,440	11,379	9,018	9,525	7,417	4,906
Noncurrent liabilities:
Long‑term debt(1)	4,497	14,876	18,733	18,093	15,637	15,187
Sector financial liabilities	2	8	317	-	-	-
Other long‑term liabilities	1,159	3,833	3,729	2,785	2,693	2,152
Noncurrent liabilities	5,658	18,717	22,780	20,877	18,330	17,339
Non-controlling interest	673	2,225	2,403	2,456	2,454	1,775
Net equity attributable to controlling shareholders	2,709	8,962	7,970	7,674	6,944	7,024
Total liabilities and shareholders’ equity	12,479	41,282	42,171	40,532	35,144	31,043

(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, 2017 of R$3.308to 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”).

4

 

OPERATING DATA

	For the year ended December 31,
	2017	2016	2015	2014	2013
Energy sold (in GWh):
Residential	19,122	16,473	16,164	16,501	15,426
Industrial	14,661	13,022	12,748	14,144	14,691
Commercial	10,220	9,720	9,259	9,437	8,837
Rural	3,762	2,474	2,152	2,326	2,081
Public administration	1,456	1,271	1,278	1,295	1,234
Public lighting	1,964	1,746	1,649	1,622	1,586
Public services	2,157	1,840	1,797	1,861	1,820
Own consumption	34	32	33	34	34
Total energy sold to Final Consumers	53,376	46,578	45,082	47,221	45,709
Electricity sales to wholesalers (in GWh)	27,557	21,459	17,971	14,988	14,975
Total consumers (in thousands)(1)	9,376	9,224	7,751	7,585	7,386
Installed Capacity (in MW)(2)	3,284	3,259	3,164	3,162	2,988
Assured Energy (in GWh)(3)	13,682	14,188	13,550	13,566	12,758
Energy generated (in GWh)(4)	10,137	12,568	14,310	13,658	11,427

(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) Refers solely to the total amount of energy (GWh) produced by conventional management companies and the equivalent participation percentage of renewable energy generation companies (51.60% in 2017, 51.60% in 2016, 51.61% in 2015 and 2014 and 58.84% in 2013).

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, 2017 of R$3.308 to US$1.00.  The translated amounts have been rounded.  These translations should not be considered as a representation that any such amounts have been, could have been or could be converted into U.S. dollars at that or at any other exchange rate, as of those dates or any other date.  In addition, the translations should not be construed as a representation that the amounts translated into U.S. dollars are in accordance with generally accepted accounting principles.  See “—Exchange Rates” below for more information regarding thereal/U.S. dollar exchange rate.

Exchange Rates

The Brazilian Central Bank allows thereal/U.S. dollar exchange rate to float freely, and it has intervened occasionally to control unstable movements in foreign exchange rates.  We cannot predict whether the Brazilian Central Bank or the Brazilian government will continue to let therealfloat freely or will intervene in the exchange rate market through a currency band system or otherwise.  Therealmay substantially depreciate or appreciate against the U.S. dollar.  For more information on these risks, see “Item 10.  Additional Information—Risk Factors—Risks Relating to Brazil”.

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

	Year‑end	Average for period(1)	Low	High
	(reaisper U.S. dollar)
Year ended:
December 31, 2013	2.343	2.174	1.953	2.446
December 31, 2014	2.656	2.360	2.197	2.740
December 31, 2015	3.905	3.339	2.575	4.195
December 31, 2016	3.259	3.483	3.119	4.156
December 31, 2017	3.308	3.202	3.051	3.381

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

5

 

	Month‑end	Average for period(1)	Low	High
	(reaisper U.S. dollar)
Month ended:
October 2017	3.277	3.191	3.132	3.280
November 2017	3.262	3.259	3.214	3.292
December 2017	3.308	3.292	3.232	3.333
January 2018	3.162	3.211	3.139	3.270
February 2018	3.245	3.232	3.173	3.282
March 2018	3.234	3.288	3.225	3.338
April 2018 (through April 18)	3.384	3.376	3.310	3.426

(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), although preliminary injunctions have been dismissed.  It is not possible to estimate when these proceedings will be finally decided. 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.

6

 

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, Law No. 13,360/16, Decree No. 9,158/17, Decree No. 9,187/17 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).  Previously, all revisions in methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.  However, in 2015, ANEEL changed this procedure to allow for the review of the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis.  Periodic tariff reviews will be held for CPFL Paulista and RGE Sul in April 2018 and for RGE in June 2018. 

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;

· injunctions related to construction activities;

· restrictions on the operation of existing facilities and equipment;

7

 

· requiring the concessionaire’s controlling shareholders to carry out further capital expenditures (not applicable to authorizations);

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

· termination of the concession or authorization.

In addition, the Brazilian government may terminate any of our concession agreements or authorizations by means of expropriation if it deems this to be in the public interest.

We are currently in compliance with all of the material terms of our concession agreements and authorizations and each of our power plants is supported by legal permissions granted by the competent authority. 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 previous distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista (now merged into CPFL Santa Cruz) 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, in particular Decree No. 7,805/12, Law No. 12,783/13 and Decree No. 8,461/15, so the concessions are now subject to the new targets and standards established by the Brazilian authorities. Such new targets and standards are included in the amendments to the concession agreements.  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.  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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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 post adjustments 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 ofvolume 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.  In addition, on January 9, 2018, a federal court nullified Ordinance No. 455/2012, on the basis that the MME has no authority to issue a regulation related to the commercialization of electrical energy. However, this decision will still have to be confirmed by the court of appeal due to the requirement for review of all cases involving the Brazilian government.  If this decision is overruled, 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 2017, according to data from the National Electrical System Operator (Operador Nacional do Sistema Elétrico), or ONS, approximately 69.9% (73.4% in 2016) of Brazil’s electricity supply came from Hydroelectric Power Plants. According to the ONS, this figure is expected to continue to decrease reaching 68.3% through 2021.

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 process to offset the deficit of hydroelectric energy, which was created in 2000 and is 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, but 2017 consisted principally of yellow and red tariff flags.  In November 2017, ANEEL held a public hearing in order to review the tariff flags methodology.  In accordance with the new methodology, red tariff flags were applied in November and December 2017. However, in February and March 2018, green tariff flags were applied under the new methodology.  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 for Calculation of Distribution Tariffs”.

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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 Braziliangovernment 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 the Assured Energy of our Generation Power Plants.

Decree No. 2,655 of July 2, 1998 established that the Assured Energy of generation power plants would be revised every five years.  In 2017, this principle of five-year revision was extended to biomass plants, which led to a reduction in the Assured Energy of CPFL Renováveis’ biomass plants by an average of approximately 25% in that year.  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 Hydroelectric Power Plants (other than 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 would remain in effect until December 2017.  The first revision of Assured Energy was implemented in January 2018 under MME Ordinance No. 178/2017 and led to a reduction in the Assured Energy of our Hydroelectric Power Plants by an average of approximately 2.4%. SHPPs, unlike other Hydroelectric Power Plants, have been subject to annual revisions of their Assured Energy since 2010 in accordance with MME No. 463/2009.  These annual revisions have not resulted in reductions in the Assured Energy levels of CPFL Geração’s SHPPs, but have resulted in reductions for CPFL Renováveis’ SHPPs (although in 2017, CPFL Renováveis, together with certain other renewable energy producers, obtained a court order reinstating the initial Assured Energy levels of their SHPPs pending final resolution of their appeal against the revision process). 

We cannot be certain how future revisions will affect the Assured Energy of each of our individual Power Plants, whether the renewable energy producers will succeed in their appeal against the revision process, or whether the overall effect of revisions will increase or decrease our Assured Energy.  When the Assured Energy of a Power Plant is decreased, our ability to supply electricity under that plant’s power purchase agreements is adversely affected, which can lead to a decrease in our revenues and increase our costs if our generation subsidiaries are required to purchase power elsewhere.  We expect revisions of Assured Energy under Decree 2,655/98 to continue to take place every five years for our Power Plants other than SHPPs.  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, including strikes;

·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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·construction and operational delays, or unanticipated cost overruns;

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

·unavailability of adequate funding.

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

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

Our activities are subject to comprehensive federal, state and municipal legislation, 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 or on the extent of damage caused, 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$455million in our Generation activities (R$393million in renewable sources and R$62 million in conventional sources), R$9,802 million in our Distribution activities and R$176 million in our commercialization and services activities during the period from 2018 through 2022. 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, we invested R$46 million in 2017 and R$51 million in 2016 related to the construction of transmission lines for CPFL Morro Agudo S.A., 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$2,139million in 2018 and approximately R$2,108 million in 2019.  Of total budgeted capital expenditures over this period, R$3,787 million are expected to be invested in our Distribution segment, R$323 million in our Renewable Generation segment and R$35 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$102 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”.

Our ability to complete the proposed capital expenditure program described above depends on a series of factors, including our ability to charge adequate tariffs for our services, our access to Brazilian and foreign securities markets and several operational and regulatory contingencies, among others. There is no certainty regarding whether we will have the financial resources available to conclude our proposed capital expenditure program.  Any inability to complete this program may have a material adverse effect on us, our operations and the development of our business.

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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 isattributed 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$2,093 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 S.A., or State Grid, 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 Power Participações S.A. is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.  In November 2017, State Grid launched a mandatory tender offer for our shares.  Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to approximately 94.75% of our total share capital.  State Grid has announced that it intends to (i) cancel our registration as a Class A publicly-held company with the CVM; (ii) delist our company from theNovo Mercado section of the B3; (iii) delist our ADSs from the New York Stock Exchange, or the NYSE, and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the U.S. Securities and Exchange Commission, or the SEC.

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’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, 2017, approximately 75.9% of our total indebtedness was denominated inreaisand indexed to Brazilian money‑market rates or inflation rates, or bore interest at floating rates.  The remaining 24.1% of our total indebtedness as of December 31, 2017 was denominated in foreign currency, substantially U.S. dollars, compared to approximately 25.0% as of December 31, 2016, 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 Brazilianreal appreciates against the U.S. dollar, our financing expenses decrease. 

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

As of December 31, 2017, we had total debt of R$20,168.6million.  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, or make non-controlling investments in companies in the sector.  If we do make investments in other electricity companies, this could increase our leverage or reduce our profitability.  Furthermore, we may not be able to integrate an 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 the risk of 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.

Our business is subject to cyberattacks and security and privacy breaches.

Our business involves the collection, storage, processing and transmission of customers’, suppliers and employees’ personal or sensitive data.  We also use key information technology systems for controlling energy and commercial, administrative and financial operations. An increasing number of organizations, including large businesses, financial institutions and government institutions, have disclosed breaches of their information technology and information security systems, some of which have involved sophisticated and highly targeted attacks, including on portions of their websites or infrastructure.

The techniques used to obtain unauthorized, improper or illegal access to our systems, our data or our customers’ data, to disable or degrade service, or to sabotage systems are constantly evolving, may be difficult to detect quickly, and often are not recognized until launched against a target.  Unauthorized parties may attempt to gain access to our systems or facilities through various means, including, among others, hacking into our systems or those of our customers, partners or vendors, or attempting to fraudulently induce our employees, customers, partners, vendors or other users of our systems into disclosing user names, passwords, payment card information or other sensitive information, which may in turn be used to access our information technology systems.  Certain efforts may be supported by significant financial and technological resources, making them even more sophisticated and difficult to detect. 

Although we have developed systems and processes that are designed to protect our data, the data of our customers, employees and suppliers, and to prevent data loss and other security breaches, and expect to continue to expend significant additional resources to bolster these protections, these security measures cannot provide absolute security.  Our information technology and infrastructure may be vulnerable to cyberattacks or security breaches, and third parties may be able to access our customers’, suppliers’ and employees’ personal or proprietary information that are stored on or accessible through those systems.  Our security measures may also be breached due to human error, malfeasance, system errors or vulnerabilities, or other irregularities.  Any actual or perceived breach of our security could interrupt our operations, result in our systems or services being unavailable, result in improper disclosure of data, materially harm our reputation and brand, result in significant legal and financial exposure, lead to loss of customer confidence in, or decreased use of, our products and services, and adversely affect our business and results of operations.  In addition, any breaches of network or data security at our customers or suppliers, including data center, could have similar negative effects.  Actual or perceived vulnerabilities or data breaches may lead to claims against us.

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We also expect to spend significant additional resources to protect against security or privacy breaches, and may be required to address problems caused by breaches.  Additionally, while we maintain insurance policies, we do not maintain insurance policies specifically for cyber-attacks and our current insurance policies may not be adequate to reimburse us for losses caused by security breaches, and we may not be able to collect fully, if at all, under these insurance policies. We cannot guarantee that the protections we have in place to protect our operating technology and information technology systems are sufficient to protect against cyberattacks and security and privacy breaches.

Risks Relating to Brazil

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

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

·interest rates;

·monetary policy;

·currency fluctuations;

·inflation;

·liquidity of domestic capital and lending markets;

·tax policies;

·changes in labor laws;

·regulatory environment of our sector;

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

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

Uncertainty over whether the Brazilian government will change policies or regulations affecting these or other factors may contribute to political and economic uncertainty in Brazil and to heightened volatility in Brazilian securities markets and securities issued abroad by Brazilian issuers.  Standard & Poor’s downgraded Brazil below investment grade on September 9, 2015 and further downgraded Brazil from BB to BB- on January 11, 2018, with stable outlook; 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 this position was confirmed on May 26, 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.

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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.  Certain of these companies are also facing investigations, and, in certain cases, being convicted by the competent authorities, such as 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. Certain of these companies have chosen to enter into leniency agreements with the competent authorities, when possible.  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, or, also, entering into plea bergains, 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 and the favoring of companies in contracts with the Brazilian government.

The potential outcome of these investigations, convictions, plea bargaining and leniency agreements 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, convictions, plea bargaining and agreements will lead to further political and economic instability or whether new allegations, convictions, plea bargaining or agreements against government officials, officers and/or companies will arise in the future.  In addition, we cannot predict the outcome of any such allegations, convictions, plea bargaining and agreements nor their effect on the Brazilian economy.

Developments in these proceedings and investigations could adversely affect our business, financial condition and results of operations. 

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

The Brazilian currency has experienced frequent and substantial variations in relation to the U.S. dollar and other foreign currencies over the last decade.  The exchange rate of therealagainst the U.S. dollar was R$3.905 on December 31, 2015; R$3.259 on December 31, 2016; and R$3.308on December 31, 2017.  On April 18, 2018, the exchange rate was R$3.384per 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 thereal also reduces the U.S. dollar value of distributions and dividends on the ADSs and the U.S. dollar equivalent of the market price of our common shares and, as a result, 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 2008 and March 2018, the base interest rate in Brazil, or SELIC, varied between 6.5% p.a.  and 14.0% p.a., reaching its lowest level (6.5%) in March 2018.  On April 18, 2018, the SELIC rate was 6.4% 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 beable 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.

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

The market value of securities of Brazilian issuers is affected by economic and market conditions in other countries, including the United States, the European Union and emerging market countries.  The global financial crisis that commenced in 2008 led to significant consequences, including stock and credit market volatility, unavailability of credit, higher interest rates, a general economic slowdown, volatile exchange rates and inflationary pressure.  Global recovery from this crisis has been slower than expected in recent years, with the largest emerging economies of China, Brazil and India posting weaker than expected results and the European Union is continuing to experience weak GDP growth, although the United States posted GDP growth of 2.3% in 2017.  Although economic conditions in other countries may differ significantly from economic conditions in Brazil, investor reactions to developments in those countries may have an adverse effect on the market value of securities of Brazilian issuers.  Crises in the United States, the European Union, China or emerging market countries may diminish investor interest in securities of Brazilian issuers, including ours.  This could adversely affect the trading price of the ADSs or our common shares, and could also make it more difficult for us to access the capital markets and finance our operations in the future on acceptable terms or at all.

Risks Relating to the ADSs and Our Common Shares

Our controlling shareholder may delist our ADSs from the NYSE, which could limit liquidity of the ADSs and adversely affect our business and access to future capital.

In November 2017, our controlling shareholder State Grid launched a mandatory tender offer for our shares.  Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to approximately 94.75% of our total share capital.  State Grid has announced that it intends to (i) cancel our registration as a Class A publicly-held company with the CVM; (ii) delist our company from theNovo Mercado section of the B3; (iii) delist our ADSs from the NYSE, and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the SEC.

Delisting from the NYSE could have an adverse effect on our business, including our ability to access future capital, and on the trading of the ADSs.  If a delisting of the ADSs were to occur, the ADSs may trade in the over-the-counter market such as on the OTC Bulletin Board or on the “pink sheets”.  The over-the-counter market is generally considered to be a less efficient market, and this could diminish investors’ interest in the ADSs as well as significantly impact the price and liquidity of the ADSs.  Any such delisting may also adversely affect the trading of the ADSs by ADS holders, or impede them from liquidating their holdings.  Delisting may also make it more difficult for us to issue additional securities or secure additional financing, particularly in the United States.  Furthermore, a deregistration would substantially reduce or effectively terminate the trading of our securities in the United States. 

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”.

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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 generallybe 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 52.5% of the aggregate market capitalization of the B3 S.A. – Brasil, Bolsa e Balcão, or the B3 (previously known as BM&FBOVESPA), as of December 31, 2017.  The top ten stocks in terms of trading volume accounted for 32.1%, 42.8% and 39.3% of all shares traded in 2017, 2016, and 2015, respectively.

ITEM 4.Information on the company

Overview

We are a corporation (sociedade por ações) incorporated and existing under the laws of Brazil with the legal name CPFL Energia S.A.  Our principal executive offices are located at Rodovia Engenheiro Miguel Noel Nascentes Burnier, km 2,5, Parque São Quirino, CEP 13088-900, Campinas, state of São Paulo, Brazil and our telephone number is +55 19  3756‑8704.  Our Investor Relations Department is located at the same address 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 45,386 GWh of electricity we distributed to approximately 9.4 million consumers in 2017.  In electricity generation, our Installed Capacity at December 31, 2017 was 3,284 MW.  Through our interest in CPFL Renováveis, we are also involved in the construction of one SHPP, as a result of which we expect to increase our Installed Capacity to 3,299 MW over the next three years as this is 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 2017, the total amount of electricity sold by our commercialization subsidiaries was64.6 GWh and 20,066 GWh to affiliated and unaffiliated parties, respectively.

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On September 2, 2016, our former shareholder Camargo Correa entered into an agreement to sell its 23.6% stake in our company to State Grid.  Following the announcement, other members of our controlling shareholders block also decided to sell their stakes to State Grid.  As a result, State Grid acquired approximately 54.6% of our voting capital.  State Grid Brazil Power Participações S.A. 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 on January 23, 2017.  In November 2017, State Grid launched a mandatory tender offer for our shares.  Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to approximately 94.75% of our total share capital.  State Grid has announced that it intends to (i) cancel our registration as a Class A publicly-held company with the CVM; (ii) delist our company from theNovo Mercado section of the B3; (iii) delist our ADSs from the NYSE, and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the SEC.

The following significant developments have occurred in our business since the beginning of 2015:

· In January 2015, we established CPFL 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 21^st 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 audited annual consolidated financial statements for 2015. 

· 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 (now merged into CPFL Santa Cruz) 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 audited annual 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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·	On June 2, 2017, CPFL Transmissão Morro Agudo S.A., or CPFL Morro Agudo, a subsidiary of CPFL Geração commenced operations. The concession contract has a duration of 30 years.
·	In June 2017, the Pedra Cheirosa wind complex commenced operations. Pedra Cheirosa, located in Itarema, in the state of Ceará, has Installed Capacity of 48.3 MW and a physical guarantee of 26.1 MW. Until December 2017, when the 2013 A-5 auction energy sale contract came into effect, the energy generated by Pedra Cheiorsa was supplied to the system and sold in the spot market.
·	On December 15, 2017, the management of RGE Sul and its parent company CPFL Jaguariúna Participações Ltda., CPFL Jaguarúna, approved the merger of CPFL Jaguariúna and RGE Sul. As a consequence of this merger, CPFL Jaguariúna was dissolved. This merger is expected to improve our governance structure and increase synergy with the other companies of the CPFL Energia group. As a result of this merger, the amount of capital stock of RGE Sul was increased by R$63.5 million. The amount of capital stock now held by shareholders CPFL Energia and CPFL Brasil totals R$1,431.6 million.
·	On November 21, 2017, through the Resolution for Authorization No. 6,723/2017, ANEEL approved our proposal to consolidate the concessions of our five distribution companies (CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari, together the Merged Companies), pursuant to Normative Resolution No. 716/2016.  Effective as of January 1, 2018, the Merged Companies were merged with and into a company named CPFL Santa Cruz (which company was previously named CPFL Jaguari). This transaction was approved by Extraordinary General Meetings held on December 31, 2017 at each of the Merged Companies.  This merger is expected to optimize our administrative and operational costs and produce large-scale savings and synergy in 2018.
	As a result of this merger transaction and the resulting transfer of the assets of the Merged Companies to CPFL Santa Cruz, the Merged Companies no longer exist and the capital stock of CPFL Santa Cruz (previously named CPFL Jaguari) was increased from R$20.6 million to R$170.4 million. Such shares are made up of 359,058,396 common shares, fully paid up, held by us as holder of the entire equity interest in CPFL Santa Cruz. For more information, see note 14.4.2 of our audited annual consolidated financial statements.
	According to Normative Resolution No. 716/2016, until the first tariff review of the Merged Companies in March 2021, ANEEL may institute a policy that reconciles the variations in the old tariffs for each of the Merged Companies and the new unified tariff for CPFL Santa Cruz over time. ANEEL decided to introduce the unified tariff during the March 2018 tariff adjustment.

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The following chart provides an overview of our corporate structure at March 31, 2018: 

 

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 Centrais Elétricas S.A., or Furnas.

(2)RGE Sul is held by CPFL Energia (76.3893%) and CPFL Brasil (23.4561% ).

Our core businesses are:

· Distribution.  In 2017, our five fully-consolidated distribution subsidiaries delivered 45,386 GWh of electricity to approximately 9.4 million consumers primarily in the states of São Paulo and Rio Grande do Sul.

· Conventional Generation.  At December 31, 2017, our conventional generation subsidiaries had Installed Capacity of 2,198 MW.  During 2017, we generated 6,642 GWh of electricity, and we had 9,952 GWh of Assured Energy at December 31, 2017, 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. In 2017, we began to report within this business the activities of our two transmission assets held through CPFL Geração, CPFL Piracicaba and CPFL Morro Agudo, both of which are operational.

· 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 commenceoperations in 2020, and expected to have Installed Capacity of approximately 29.9 MW.  CPFL Renováveis also has 45 wind farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, all of which are operational and have aggregate Installed Capacity of 1,309 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, 2017, our total consolidated Installed Capacity through our Renewable Generation segment (calculated on the basis of our 51.60% interest in CPFL Renováveis) was 1,085 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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· 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 2017, we sold 20,131GWh of electricity, of which 20,066GWh 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) CPFL Telecom and (ii) 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, 2017, our total consolidated Installed Capacity (calculated on the basis of our 51.60% interest in CPFL Renováveis) was 3,284 MW, of which 2,198MW was through conventional sources and 1,085 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.

Our total Installed Capacity at December 31, 2017 represents a 0.8% increase as compared to Installed Capacity of 3,259 MW at December 31, 2016 as a result of the Pedra Cheirosa wind complex beginning operations.  By the end of 2020, when we expect the Boa Vista SHPPs to become operational, we expect our total Installed Capacity to reach 3,299 MW.

Many of our generation facilities hold long‑term PPAs approved by ANEEL, which we believe will ensure us an attractive rate of return on our investment.  We also have a consolidated portfolio of 209 MW (calculated on the basis of our 51.60% interest in CPFL Renováveis’ total portfolio of 406 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. 

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Focus on further improving our operating efficiency.  The distribution of electricity in our distribution concession areas is our largest business segment, representing approximately 48.6% of our consolidated net income in 2017.  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, introducingautomated systems where possible.  We also understand the need to invest in digital assets, such as Smart Grid technology and in 2017 we deployed 1,355 automatic reclosers. These automatic reclosers are supported by our robust proprietary communication infrastructure, including digital radio communication systems, radio frequency mesh and a fiber optic network.

Expand and strengthen our commercialization.  Free Consumers make up a significant segment of the electricity market in Brazil, representing approximately 30% 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.

Strategy and management for sustainable development. We maintain a strategic focus on a low carbon business portfolio and climate change projects. We aim to strengthen our integrated business management through short- and medium-term economic-financial and socio-environmental key performance indicators and targets, as well as long-term strategic objectives aligned with the United Nations Sustainable Development Goals (SDGs) as well as other national and international commitments.

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

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

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Our Service Territory

   

Distribution

We are one of the largest electricity distributors in Brazil, based on the amount of electricity we delivered in 2017.  Our five distribution subsidiaries together supply electricity to a region covering 303,573 square kilometers, primarily in the states of São Paulo and Rio Grande do Sul.  Their concession areas include 679¹ municipalities and a population of approximately 22.8 million people.  Together, they provided electricity to approximately 9.4 million consumers as of December 31, 2017.  Our five subsidiaries distributed approximately 14.2% of the total electricity distributed in Brazil in 2017, based on data from the EPE.

Distribution Companies

We have five 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 10.2 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 4.4 million consumers at December 31, 2017.  In 2017, CPFL Paulista distributed 20,485 GWh of electricity, accounting for approximately 24.1% of the total electricity distributed in the state of São Paulo and 6.4% of the total electricity distributed in Brazil during the year.

· 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 4.2 million people.  Its concession area covers 27 municipalities, including the cities of Santos, Sorocaba and Jundiaí.  CPFL Piratininga had approximately 1.7 million consumers atDecember 31, 2017.  In 2017, CPFL Piratininga distributed 7,921GWh of electricity, accounting for approximately 9% of the total electricity distributed in the state of São Paulo and 2.5% 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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·	RGE.  Rio Grande Energia S.A., or RGE, supplies electricity to a concession area covering 86,152 square kilometers in the state of Rio Grande do Sul with a population of approximately 3.9million 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, 2017.  In 2017, RGE supplied 7,949 GWh of electricity, accounting for approximately 33.2% of the total electricity distributed in the state of Rio Grande do Sul and 2.5% 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 99,512 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, 2017.  In 2017, RGE Sul supplied 6,771 GWh of electricity.
·	CPFL Santa Cruz.  CPFL Santa Cruz supplies electricity to a concession area covering 20,684 square kilometers, which includes 39 municipalities in the northwest part of the state of São Paulo, three municipalities in the state of Paraná and three municipalities in the state of Minas Gerais. In 2017, CPFL Santa Cruz distributed 2,260 GWh of electricity to approximately 447,000 consumers, accounting for approximately 2% of the total electricity distributed in the state of São Paulo and 0.7% of the total electricity distributed in Brazil during the year.
	CPFL Santa Cruz is the surviving entity of the merger of our five previous distribution companies CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari.
	On December 9, 2015, the concessions held by the Merged Companies were extended to July 2045.  For further information on the extension of these concessions, see “—Our Concessions and Authorizations—Concessions”.

Distribution Network

Our five 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, 2017, our distribution networks consisted of 318,018 kilometers of distribution lines, including 457,741 distribution transformers, and 12,504 km of High Voltage distribution lines between 34.5 kV and 138 kV.  At that date, we had 547 transformer substations for transforming High Voltage into Medium Voltages for subsequent distribution, with total transforming capacity of 18,468 mega‑volt amperes.  Of the industrial and commercial consumers in our concession area, 387 had 69 kV, 88 kV or 138 kV high‑voltage electricity supplied through direct connections to our High Voltage distribution lines.

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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 Brazilianelectricity 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 five 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 approximately 441,000 inspections during 2017, which we believe led to a recognition of previously unbilled receivables estimated at approximately R$60.3 million.

Power Outages

The following table sets forth the frequency and duration of electricity outages per consumer for the years ended December 31, 2017 and 2016 for each of our distribution subsidiaries:

	Year ended December 31, 2017
	CPFL Paulista	CPFL Piratininga	RGE	RGESul	CPFL Santa Cruz(3)	CPFL Jaguari(3)	CPFL Mococa(3)	CPFL Leste Paulista(3)	CPFL Sul Paulista(3)
SAIFI1	4.94	4.45	7.74	7.62	3.69	5.64	6.04	6.19	6.77
SAIDI2	7.14	6.97	14.16	15.58	4.82	6.31	5.92	7.91	8.20

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

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

(3) Merged into CPFL Santa Cruz effective as of January 1, 2018. For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.

	Year ended December 31, 2016
	CPFL Paulista	CPFL Piratininga(4)	RGE	RGESul(3)	CPFL Santa Cruz(5)	CPFL Jaguari(5)	CPFL Mococa(5)	CPFL Leste Paulista(5)	CPFL Sul Paulista(5)
SAIFI1	5.00	3.97	7.56	9.41	4.09	6.13	6.63	5.73	11.76
SAIDI2	7.62	8.44	14.44	19.45	5.65	7.10	10.56	8.01	15.20

(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.  
(4) In our annual report for 2016, we published SAIFI of 3.80 and SAIDI of 6.97 for CPFL Piratininga, which statistics excluded the effect of a failure in transmission provided by CTEEP due to a storm.  A decision by ANEEL required us to include the effect of this outage in the statistics for CPFL Piratininga.

(5) Merged into CPFL Santa Cruz effective as of January 1, 2018. For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.

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 2016, 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. In addition, our SAIDI and SAIFI numbers have improved significantly from 2016 to 2017, evidencing the effectiveness of our maintenance and investments in these 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.  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.

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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 2017,according to data from ANEEL, the amount we reimbursed our consumers remained 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 12.6% 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 2017, we invested approximately R$1,882.5 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 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 2017, 9.0% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries (including our joint ventures).

In 2017, we purchased 11,779GWh of electricity from the Itaipu Power Plant, amounting to 15.1% 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$28.73/kW.  Our purchases represent approximately 19.6% (including RGE Sul) 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.

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

In 2017, we paid an average of R$199.58 per MWh for purchases of electricity from Itaipu, compared with R$192.99 during 2016 and R$279.65 during 2015.  These figures do not include the transmission fee.

We purchased 66,195 GWh of electricity in 2017 from generating companies other than Itaipu, representing 84.9% of the total electricity we purchased.  We paid an average of R$191.88 per MWh for purchases of electricity from generating companies other than Itaipu, compared with R$164.77 per MWh in 2016 and R$210.44 per MWh in 2015.  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,
	2017	2016	2015
	(in GWh)
Energy purchased for resale
Itaipu	11,779	10,497	10,261
Electric Energy Trading Chamber - CCEE	2,453	1,195	2,946
Proinfa Program	1,142	1,058	1,058
Energy purchased in the Regulated Market and through bilateral contracts	62,600	51,225	44,342
TOTAL	77,974	63,975	58,607

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

Beginning in 2013, all distribution companies in Brazil have been required to purchase electricity from generation companies whose concessions were renewed in accordance with Law 12,783/13.  The tariffs and volumes of electricity to be purchased by each distribution company, as well as the provisions of the applicable agreements between the generation and distribution companies, were set by ANEEL in the law.  Since distribution companies are required to contract in advance, through public bids, for 100% of their forecast electricity needs and are only authorized to pass through the cost of up to 105% of this electricity to consumers, any involuntary quota to be purchased from generation companies whose concessions were renewed under Law 12,783/13 that takes a distributor’s energy volume to more than 105% of its forecast would lead to additional costs for the distributor.  As a result, Normative Resolution No.  706 of March 29, 2016 provided that the costs resulting from involuntary purchase quotas can be passed on to consumers, and the energy volume can be offset from electricity auctions from existing power generation facilities in the following years.  See “Item 3.  Key Information—Risk Factors—Our operating results depend on prevailing hydrological conditions.  Poor hydrological conditions may affect our results of operations” and “Item 3.  Key Information—Risk Factors—We may not be able to fully pass through the costs of our electricity purchases and, to meet demand, we could be forced to purchase electricity in the spot market at prices substantially higher than under our long term purchase agreements”.

Transmission Tariffs.  In 2017, we paid a total of R$1,284 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 25 to our audited annual consolidated financial statements for a breakdown of our sales by category.

·Industrial consumers.  Sales to final industrial consumers accounted for 19.8% of revenues from electricity sales in our Distribution segment in 2017.

·Residential consumers.  Sales to final residential consumers accounted for 45.2% of our revenues from electricity sales in our Distribution segment in 2017.

·Commercial consumers.  Sales to final commercial consumers, which include service businesses, universities and hospitals, accounted for 21.3% of our revenues from electricity sales in our Distribution segment in 2017.

·Rural consumers.  Sales to final rural consumers accounted for 4.6% of our revenues from electricity sales in our Distribution segment in 2017.

·Other consumers.  Sales to other consumers, which include public and municipal services such as street lighting, accounted for 9.4% of our revenue of electricity sales in our Distribution segment in 2017.

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 andrelated regulations establish a cap on tariffs that provides for annual, periodic and extraordinary adjustments.  For a discussion of the regulatory regime applicable to our tariffs and their adjustment, see “—The Brazilian Power Industry”.

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Group A consumers receive electricity at 2.3 kV or higher.  Tariffs for Group A consumers are based on the voltage level at which electricity is supplied, and the time of day electricity is supplied.  The consumers may opt for a different tariff applicable in peak periods in order to optimize the use of the electric network.  Tariffs for Group A consumers consist of two components:  the TUSD and the tariff for energy consumption, or TE.  The TUSD, expressed inreaisper kW, is based on:  (i) the electricity demand contracted by the party connected to the system; (ii) certain regulatory charges; and (iii) technical and non‑technical losses of energy on the distribution system.  The TE, expressed inreaisper MWh, is based on the amount of electricity actually consumed.  These consumers may opt to purchase electricity in the Free Market under the New Industry Model Law.  See “—The New Industry Model Law”.

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

The following tables set forth our average retail prices for each consumer category for 2017 and 2016.  These prices include taxes (ICMS, PIS and COFINS) and were calculated based on our revenues and the volume of electricity sold in 2017 and 2016.

	Year ended December 31, 2017
	CPFL Paulista	CPFL Piratininga	RGE	RGE Sul	CPFL Santa Cruz(2)	CPFL Leste Paulista(2)	CPFL Sul Paulista(2)	CPFL Jaguari(2)	CPFL Mococa(2)
	(R$/MWh)
Residential	572.79	585.98	667.24	708.93	646.21	620.96	632.70	590.43	664.57
Industrial	554.80	493.84	500.10	583.76	566.56	518.58	452.88	461.75	565.57
Commercial	563.84	532.64	652.20	706.58	632.20	583.81	585.65	532.52	630.32
Rural	322.43	361.45	339.60	271.45	388.09	360.66	386.92	362.72	407.56
Other	425.13	383.42	264.44	607.72	340.23	442.23	425.43	410.70	449.41
Average	531.64	533.29	502.12	580.28	522.10	507.47	529.24	496.70	567.33

	Year ended December 31, 2016
	CPFL Paulista	CPFL Piratininga	RGE	RGE Sul(1)	CPFL Santa Cruz(2)	CPFL Leste Paulista(2)	CPFL Sul Paulista(2)	CPFL Jaguari(2)	CPFL Mococa(2)
	(R$/MWh)
Residential	591.80	679.76	665.32	742.37	665.54	599.01	616.72	580.38	650.89
Industrial	569.16	575.46	496.30	582.93	584.23	524.54	460.80	466.23	536.60
Commercial	571.80	609.34	654.51	734.76	650.17	567.98	577.97	531.61	617.03
Rural	322.86	419.32	332.16	275.02	404.93	352.51	379.15	353.03	382.57
Other	434.09	436.56	262.92	505.37	333.73	435.06	419.70	405.37	437.20
Average	546.79	612.09	501.75	590.87	537.89	499.18	521.06	490.20	549.57

(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) On November 21, 2017, through the Resolution for Authorization No. 6,723/2017, ANEEL approved our proposal to consolidate the concessions of our five distribution companies (CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari, together the Merged Companies), pursuant to Normative Resolution No. 716/2016.  Effective as of January 1, 2018, the Merged Companies were merged with and into a company named CPFL Santa Cruz (which company was previously named CPFL Jaguari). For more information, see “Item 4. Information on the Company—Overview” and note 14.4.2 of our audited annual consolidated financial statements.

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

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TUSD.  The TUSD tariffs, which are set by ANEEL, consist of the three tariffs described under “Item 4.  Information on the Company—System Tariffs—TUSD”.  In 2017, tariff revenues for the use of our network by Free Consumers amounted to R$2,137.6 million.  The average tariff for the use of our network was R$105.73/MWh and R$130.88/MWh in 2017 and 2016, respectively, including the TUSD we charge to other distributors connected to our Distribution Networks.

Billing Procedures

The procedure we use for billing and payment for electricity supplied to our consumers is determined by consumer and tariff categories.  Meter readings and invoicing take place on a monthly basis for Low Voltage consumers, with the exception of rural consumers, whose meters are read in intervals varying from one to two months, as authorized by relevant regulation, and consumers of our subsidiary RGE, whose meters are read in intervals varying from one to three months.  Bills are issued from meter readings or, if meter readings are not possible, from the average of monthly consumption.  Low voltage consumers are billed within a maximum of three business days after the meter reading, with payment required within a minimum of five business days after the invoice presentation date.  In case of nonpayment, we send the consumer a notice of nonpayment with the following month’s invoice and we allow the consumer up to 15 days to settle the amount owed to us.  If payment is not received within three business days after that 15‑day period, the consumer’s electricity supply may be suspended.  We may also take other measures, such as inclusion of the consumer in the list of debtors of credit reporting agencies, or extrajudicial or judicial collection through collection agencies.

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

According to the most recent data from ABRADEE, the percentage of customers in default for our three largest distribution subsidiaries compare favorably to the average for other major Brazilian electricity distributors.  For this purpose, consumers in default are consumers whose bills are over 90 days overdue.  Bills due and outstanding for over 360 days are classified as irrecoverable.

Customer Service

We strive to provide high‑quality customer service to our distribution consumers.  We provide customer service 24 hours a day, seven days a week.  The requests are received using a variety of platforms such as call centers, our website, SMS and our smartphone application.  In 2017, we responded to approximately 47.9million inquiries.  We also provide customer service through our branch offices, which handled approximately 5.6 million customer requests in 2017.  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 3,284 MW as of December 31, 2017.  Most of the electricity we produce comes from our Hydroelectric Power Plants.  We generated a total of 10,137GWh in 2017, 12,568 GWh in 2016 and 14,310 GWh in 2015.

If less than the total Assured Energy is being generated (i.e., if the 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 theMRE.  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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Conventional Generation

Hydroelectric Power Plants

At December 31, 2017, 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 Energia S.A. (formerly VBC), one of our 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. In 2016, due to the renegotiated GSF, the Serra da Mesa concession was extended to September 30, 2040, in accordance with ANEEL’s Authoritative Resolution No. 6,055/2016.

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, of which our share is 985 GWh/year.  We sell our participation in the Assured Energy of this Complex to affiliates in our group.  These facilities are operated by CERAN, under CPFL Geração’s supervision.

· Monte Claro.  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. 

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We are currently assessing alternative measures in order to raise our results. Discussions are currently underway with ANEEL and other entities in the transmission sector, regarding the conditions under which we will transfer the Monte Claro Substation to the basic network, which could eliminate maintenance costs and our responsability 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, 2017, 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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Small Hydroelectric Power Plants

At December 31, 2017, 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 (now all merged into CPFL Santa Cruz), 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.

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, 2017: 

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	Holding company	Partic.	Capacity (MW)		Assured Energy (GWh)		Placed in service	Concession expires
			Our share	TOTAL	Our share	TOTAL
Hydroelectric plants:
Serra da Mesa	CPFL Geração	51.54%	657.1	1,275.0	3,029.5	5,878.0	1998	2039(1)
Monte Claro	CPFL Geração	65%	84.5	130.0	335.9	516.8	2004	2036
Barra Grande	CPFL Geração	25.01%	172.5	690.0	833.7	3,334.1	2005	2036
Campos Novos	CPFL Geração	48.72%	428.8	880.0	1,612.9	3,310.4	2007	2035
Castro Alves	CPFL Geração	65%	84.5	130.0	364.4	560.6	2008	2036
14 de Julho	CPFL Geração	65%	65.0	100.0	284.7	438.0	2008	2036
Luis Eduardo Magalhães	CPFL Jaguari de Geração	6.93%	62.5	902.5	319.7	4,613.0	2001	2032
Foz do Chapecó	Chapecoense	51%	436.1	855.0	1,930.0	3,784.3	2010	2036
SUBTOTAL - Hydroelectric plants			1,991.0		8,710.8
Thermoelectric 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	2042
Termoparaíba	CPFL Geração	53.34%(4)	91.1	170.8	578.9	1,084.5	2011	2042
SUBTOTAL - Thermoelectric plants			182.2		1,157.4
Small Hydroelectric Plants
Cariobinha	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	2042
Pinheirinho	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	2042
Rio do Peixe II	CPFL Geração	100%	15.0	15.0	46.8	46.8	N/A	2042
Santa 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		84.0
TOTAL – 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.  In 2016, due to the renegotiated GSF, the Serra da Mesa concession was extended to September 30, 2040, in accordance with ANEEL’s Authoritative Resolution No. 6,055/2016. We have a contractual right to 51.54% of the Assured Energy of this facility, under a 30-year agreement. 

(2) Inactive power plant.  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, 2017, 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 sharesof 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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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. 

· 25 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 2), with 29.9 MW of Installed Capacity, which is under construction and scheduled to commence operations in 2020.

· 52 subsidiaries involved in the generation of electric energy from wind sources. 45 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 1,308.5 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 MW.  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 3 MW and 30 MW and a reservoir area of up to three square kilometers.  A typical Small Hydroelectric Power Plant operates under a “run-of-river” system and as a result, it may experience idleness when the available water flow is less than the turbine inflow capacity.  If flows are greater than the equipment’s capacity, water flows through a spillway.  Small Hydroelectric Power Plants are allowed to participate in the MRE, and in this case, the amount of energy sold by the power plant depends solely on its certificate of guarantee and not on its individual energy production. 

CPFL Renováveis operates 40 of our 50 (39 operational and one 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.

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The automation of the 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 production of organic inputs used for power generation. For this reason, the operational costs of biomass-fueled thermoelectric plants tend to be higher than the operational costs of Small Hydroelectric Power Plants.

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

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 inthe 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.

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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 12.76 GW as of December 2017 according to ANEEL, signaling a high growth potential in this segment.  Wind farms are also eligible for MDL and have the potential to generate carbon credits for sale. 

We currently have 45 wind farms under the authorization regime, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul.

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

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

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

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

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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.

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. 

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Pedra Cheirosa. The Pedra Cheirosa Complex, located in the state of Ceará, consists of the Pedra Cheirosa I and Pedra Cheirosa II Wind Farms, which have an aggregate Installed Capacity of 48.3 MW and aggregate Assured Energy of 26.1 MWavg. This wind farm commenced operations in June 2017.

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, 2017:

	Capacity (MW)		Assured Energy (GWh)		Placed in service	Facility upgraded	Concession expires
	Our share	TOTAL	Our share	TOTAL
Small Hydroelectric plants:
Alto Irani	10.8	21.0	55.9	108.3	2008		2032
Americana	15.5	30.0	26.6	51.5	1949	2002	2027
Andorinhas	0.3	0.5	1.9	3.7	1940		(2)
Arvoredo	6.7	13.0	33.4	64.6	2010		2032
Barra da Paciência	11.9	23.0	67.3	130.4	2011		2029
Buritis	0.4	0.8	1.6	3.1	1922		2027(1)
Capão Preto	2.2	4.3	9.8	19.0	1911	2008	2027
Chibarro	1.3	2.6	6.9	13.4	1912	2008	2027
Cocais Grande	5.2	10.0	20.8	40.4	2009		2029
Corrente Grande	7.2	14.0	38.6	74.7	2011		2030
Diamante	2.2	4.2	7.2	14.0	2005		2019
Dourados	5.6	10.8	25.7	49.8	1926	2002	2027
Eloy Chaves	9.7	18.8	49.8	96.4	1954	1993	2027
Esmeril	2.6	5.0	13.0	25.2	1912	2003	2027
Figueiropolis	10.0	19.4	57.0	110.4	2010		2034
Gavião Peixoto	2.5	4.8	16.4	31.8	1913	2007	2027
Guaporé	0.4	0.7	1.8	3.5	1950		(2)
Jaguari	6.1	11.8	20.3	39.4	1917	2002	2027
Lençóis	0.9	1.7	4.7	9.1	1917	1988	2027
Ludesa	15.5	30.0	95.8	185.7	2007		2032
Mata Velha	12.4	24.0	59.2	114.8	2016
Monjolinho	0.3	0.6	0.5	1.0	1893	2003	2027(2)
Ninho da Águia	5.2	10.0	29.4	56.9	2011		2029
Novo Horizonte	11.9	23.0	47.0	91.1	2011		2032
Paiol	10.3	20.0	47.3	91.7	2010		2032
Pinhal	3.5	6.8	16.7	32.4	1928	1993	2027
Pirapó	0.4	0.8	2.6	5.1	1952		(2)
Plano Alto.	8.3	16.0	41.8	81.0	2008		2032
Saltinho.	0.4	0.8	3.3	6.4	1950		(2)
Salto Góes.	10.3	20.0	50.2	97.2	2012		2040
Salto Grande	2.4	4.6	11.7	22.6	1912	2003	2027
Santa Luzia.	14.7	28.5	83.3	161.4	2007		2037
Santana	2.2	4.3	11.8	22.9	1951	2002	2027
São Gonçalo.	5.7	11.0	32.6	63.2	2010		2030
São Joaquim.	4.2	8.1	22.9	44.4	1911	2002	2027
Socorro	0.5	1.0	1.4	2.7	1909	1994	2027(1)

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	Capacity (MW)		Assured Energy (GWh)		Placed in service	Facility upgraded	Concession expires
	Our share	TOTAL	Our share	TOTAL
Três Saltos	0.3	0.6	1.9	3.8	1928		2027(1)
Varginha.	4.6	9.0	24.4	47.2	2010		2029
Várzea Alegre	3.9	7.5	22.1	42.7	2011		2029
SUBTOTAL - Small Hydroelectric Power Plants (our share) .	218	423	1,065	2,063
Thermoelectric biomass plants:
Baldin (CPFL Bioenergia)	23.2	45.0	31.9	61.8	2010		2039
Bio Alvorada	25.8	50.0	89.9	174.3	2013		2042
Bio Buriti	25.8	50.0	48.7	94.4	2011		2040
Bio Coopcana	25.8	50.0	81.4	157.7	2013		2042
Bio Ester	20.6	40.0	65.5	127.0	2010		2029
Bio Formosa	20.6	40.0	24.9	48.2	2011		2032
Bio Ipê	12.9	25.0	32.4	62.8	2012		2040
Bio Pedra	36.1	70.0	46.5	90.2	2012		2046
SUBTOTAL - Thermoelectric biomass plants (our share)	191	370	421	816
Wind farm plants
Atlântica I	15.5	30.0	59.2	114.8	2014		2046
Atlântica II	15.5	30.0	58.3	113.0	2014		2046
Atlântica IV	15.5	30.0	58.8	113.9	2014		2046
Atlântica V	15.5	30.0	61.9	120.0	2014		2046
Bons Ventos.	25.8	50.0	74.0	143.4	2010		2033
Campo dos Ventos I.	13.0	25.2	61.5	119.1	2016		2046
Campo dos Ventos II	15.5	30.0	67.8	131.4	2013		2046
Campo dos Ventos III	13.0	25.2	60.6	117.4	2016		2046
Campo dos Ventos V.	13.0	25.2	59.2	114.8	2016		2046
Canoa Quebrada.	29.4	57.0	108.8	210.9	2010		2032
Canoa Quebrada (Rosa dos Ventos) .	5.4	10.5	1.7	3.3	2014		2032
Costa Branca.	10.7	20.7	44.3	85.8	2014		2046
Enacel.	16.3	31.5	46.2	89.6	2010		2032
Eurus I	15.5	30.0	70.1	135.8	2014		2046
Eurus III.	15.5	30.0	72.8	141.0	2014		2046
Eurus VI.	4.1	8.0	14.3	27.7	2011		2045
Foz do Rio Choró	13.0	25.2	33.3	64.6	2009		2032
Icaraizinho.	28.2	54.6	99.8	193.4	2009		2032
Juremas.	8.3	16.1	34.4	66.6	2014		2046
Lagoa do Mato	1.7	3.2	0.7	1.4	2014		2032
Macacos	10.7	20.7	44.3	85.8	2014		2046
Morro dos Ventos I.	14.9	28.8	61.0	118.3	2014		2045
Morro dos Ventos III	14.9	28.8	62.8	121.8	2014		2045
Morro dos Ventos IV.	14.9	28.8	61.9	120.0	2014		2045
Morro dos Ventos VI.	14.9	28.8	59.2	114.8	2014		2045
Morro dos Ventos IX.	15.5	30.0	64.7	125.3	2014		2045
Morro dos Ventos II.	15.0	29.2	69.1	134.0	2015		2047
Paracuru	13.0	25.2	56.9	110.2	2008		2032
Pedra Cheirosa	24.9	48.3	124.3	240.9	2017		2049
Pedra Preta.	10.7	20.7	46.6	90.2	2014		2046
Praia Formosa.	54.2	105.0	130.3	252.6	2009		2032
Santa Clara I	15.5	30.0	62.0	120.1	2011		2045
Santa Clara II.	15.5	30.0	57.7	111.8	2011		2045
Santa Clara III.	15.5	30.0	56.6	109.6	2011		2045
Santa Clara IV.	15.5	30.0	55.6	107.8	2011		2045
Santa Clara V	15.5	30.0	56.1	108.7	2011		2045
Santa Clara VI.	15.5	30.0	55.6	107.7	2011		2045
São Domingos	13.0	25.2	(3)	(3)	2016		2032
Taiba	8.5	16.5	30.3	58.8	2008		2032
Ventos de São Benedito	15.2	29.4	(3)	(3)	2016		2032
Ventos de Santo Dimas.	15.2	29.4	(3)	(3)	2016		2032
Ventos de São Martinho	7.6	14.7	(3)	(3)	2016		2032
Ventos de Santa Mônica	15.2	29.4	(3)	(3)	2016		2032
Ventos de Santa Úrsula.	14.1	27.3	(3)	(3)	2016		2032
SUBTOTAL - Wind farms (our share)	675	1,309	2,243	4,346
Solar power plant
Tanquinho.	0.6	1.1	1.0	1.7	2012		-
SUBTOTAL – Solar power plant (our share).	1	1	1	2
TOTAL (our share only)	1,085	2,103	3,729	7,228

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 (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.

(3) Projects that have no Assured Energy figure as they do not operate in the regulated market.

Expansion of Installed Capacity

Consumption of electricity in Brazil in 2017 increased 0.8% in 2017, reaching 465,130 GWh , as was expected by the Energetic Studies Company (Empresa de Pesquisas Energéticas), or EPE.  To address this 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, which is expected to have an aggregate Installed Capacity of 29.9 MW (of which our consolidated share will be 15.4 MW).  We expect that the total generating capacity from this facility will become fully operational by the end of 2020.

The following table sets forth information regarding this renewable generation construction project: 

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)
Boa Vista II Small Hydro Power Plant (one company)	29.9	136	2017	2020	51.60	15.4	70

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Boa Vista 2 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 29.9 MW and aggregate Assured Energy of 136 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

· 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 Eficiência, 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.

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· 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 mainly in peak periods, which reduce our customers’ electricity costs.  Its natural gas co-generation activities include the simultaneous and sequential production of electricity and heat 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 Eficiência, 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 Eficiência also offers distributed photovoltaic generation services, through CPFL GD S.A., a source of generation that injects power into the local 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 electricity 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.

· 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 termsof 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.

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· 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.

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	Term
014/1997	CPFL Paulista	São Paulo	30 years from November 1997
09/2002	CPFL Piratininga	São Paulo	30 years from October 1998
012/1997	RGE Sul	Rio Grande do Sul	30 years from November 1997
013/1997	RGE	Rio Grande do Sul	30 years from November 1997
021/1999	CPFL Santa Cruz(1)	São Paulo and Paraná	30 years from July 2015
015/1999	CPFL Jaguari(1)	São Paulo	30 years from July 2015
017/1999	CPFL Mococa(1)	São Paulo and Minas Gerais	30 years from July 2015
018/1999	CPFL Leste Paulista(1)	São Paulo	30 years from July 2015
019/1999	CPFL Sul Paulista(1)	São Paulo	30 years from July 2015
003/2013	CPFL Transmissão	São Paulo	30 years from February 2013
006/2015	CPFL Morro Agudo	São Paulo	30 years from March 2015

(1) Merged into CPFL Santa Cruz effective as of January 1, 2018. For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.

Law No.  12,783 of 2013 provided that the type of existing distribution concession held by our five distribution subsidiaries that have now been merged into CPFL Santa Cruz 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.

On November 21, 2017, through the Resolution for Authorization No. 6,723/2017, ANEEL approved our proposal to consolidate the concessions of our five distribution companies (CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari, together the Merged Companies), pursuant to Normative Resolution No. 716/2016.  Effective as of January 1, 2018, the Merged Companies were merged with and into a company named CPFL Santa Cruz (which company was previously named CPFL Jaguari). This transaction was approved by Extraordinary General Meetings held on December 31, 2017 at each of the Merged Companies.  This merger is expected to optimize our administrative and operational costs and produce large-scale savings and synergy in 2018.

As a result of this merger transaction and the resulting transfer of the assets of the Merged Companies to CPFL Santa Cruz, the Merged Companies no longer exist and the capital stock of CPFL Santa Cruz (previously named CPFL Jaguari) was increased from R$20.6 million to R$170.4 million. Such shares are made up of 359,058,396 common shares,fully paid up, held by us as holder of the entire equity interest in CPFL Santa Cruz. For more information, see note 14.4.2 of our audited annual consolidated financial statements.

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According to Normative Resolution No. 716/2016, until the first tariff review of the Merged Companies in March 2021, ANEEL may institute a policy that reconciles the variations in the old tariffs for each of the Merged Companies and the new unified tariff for CPFL Santa Cruz over time. ANEEL decided to introduce the unified tariff during the March 2018 tariff adjustment. 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 period
Hydroelectric plants
	005/2004	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 ANEEL
	036/2001	Barra Grande	Barra Grande	Rio Grande do Sul	35 years from May 2001	At the discretion of ANEEL
	043/2000	ENERCAN	Campos Novos	Santa Catarina	35 years from May 2000	At the discretion of ANEEL
	005/1997	Investco	Luiz Eduardo Magalhães	Tocantins	35 years from December 1997	At the discretion of ANEEL
	128/2001	Foz do Chapecó	Foz do Chapecó	Santa Catarina and Rio Grande do Sul	35 years from November 2001	At the discretion of ANEEL
Thermoelectric plants
	015/1997	CPFL Geração	UTE Carioba	São Paulo	30 years from November 1997	30 years
Small Hydroelectric Plants
	015/1997	CPFL Geração	Cariobinha (Small Hydroelectric Power Plant)	São Paulo	30 years from November 1997	30 years
	(3)	CPFL Centrais Geradoras(4)	Lavrinha (Micro Hydroelectric Power Plant)	São Paulo	(3)	‑
	009/1999	CPFL 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)	‑

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Renewable generation

	Concession no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Small Hydroelectric Plants
	003/2011	CPFL Renováveis	Americana	São Paulo	up to November 2027	30 years
	Dispatch 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 years
	004/2011	CPFL Renováveis	Eloy Chaves	São Paulo	up to November 2027	30 years
	002/2011	CPFL Renováveis	Esmeril	São Paulo	up to November 2027	30 years
	002/2011	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 years
	002/2011	CPFL Renováveis	Lençóis	São Paulo	up to November 2027	(3)
	004/2011	CPFL Renováveis	Monjolinho	São Paulo	up to November 2027	(3)
	004/2011	CPFL Renováveis	Pinhal	São Paulo	up to November 2027	30 years
	Dispatch No.  1989	CPFL Renováveis	Pirapó	Rio Grande do Sul	(3)	(3)
	Dispatch No.  1988	CPFL Renováveis	Saltinho	Rio Grande do Sul	(3)	(3)
	003/2011	CPFL Renováveis	Salto Grande	São Paulo	up to November 2027	(3)
	002/2011	CPFL Renováveis	São Joaquim	São Paulo	up to November 2027	20 years
	004/2011	CPFL Renováveis	Socorro	São Paulo	up to November 2027	(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 September 30, 2040.  The renewal was approved by the MME in Ordinance No.  262 published on April 27, 2012 and the final extension of the renegotiated GSF was approved by ANEEL in Authoritative Resolution No.6,055 published on September 27, 2016.

(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”).

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Authorizations

Conventional generation

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

Renewable generation

	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Small Hydroelectric plants
	Resolution No.357	SPE Aiuruoca Energia S.A.	Aiuruoca(*)	Minas Gerais	30 years from December 23, 1999	30 years
	Resolution No.  587	SPE Alto Irani Energia S.A.	Alto Irani	Santa Catarina	30 years from October 30, 2002	30 years
	Resolution No.  606	SPE Arvoredo Energia S.A.	Arvoredo	Santa Catarina	30 years from November 7, 2002	30 years
	Resolution No.  348	SPE Barra da Paciência Energia S.A.	Barra da Paciência	Minas Gerais	30 years from December 20, 1999	30 years
	Resolution No.540	SPE Cachoeira Grande Energia S.A.	Cachoeira Grande(*)	Minas Gerais	30 years from October 15, 2003	30 years
	Resolution No.  349	SPE Cocais Grande Energia S.A.	Cocais Grande	Minas Gerais	30 years from December 23, 1999	30 years
	Resolution No.  17	SPE Corrente Grande Energia S.A.	Corrente Grande	Minas Gerais	30 years from January 17, 2000	30 years
	Resolution No.  198	Figueirópolis Energética S.A.	Figueirópolis	Mato Grosso	30 years from May 04, 2004	30 years
	Resolution No.  705	Ludesa Energética S.A.	Ludesa	Santa Catarina	30 years from december 17, 2002	30 years
	Resolution No.  262	Mata Velha Energética S.A.	Mata Velha	Minas Gerais	30 years from May 16, 2002	30 years
	Resolution No.  370	SPE Ninho da Águia Energia S.A.	Ninho da Águia	Minas Gerais	30 years from December 30, 1999	30 years
	Resolution No.  652	Novo Horizonte Energética S.A.	Novo Horizonte	Paraná	30 years from november 26, 2002	30 years
	Resolution No.  406	SPE Paiol Energia S.A.	Paiol	Minas Gerais	30 years from August 07, 2002	30 years
	Resolution No.  607	SPE Plano Alto Energia S.A.	Plano Alto	Santa Catarina	30 years from November 7, 2002	30 years
	Resolution No.  2510	SPE Salto Góes Energia S.A.	Salto Góes	Santa Catarina	30 years from August 19, 2010	30 years
	Resolution No.718	SPE Santa Cruz Energia S.A	Santa Cruz(*)	Minas Gerais	30 years from December 18, 2002	30 years
	Resolution No.  13	SPE São Gonçalo Energia S.A.	São Gonçalo	Minas Gerais	30 years from January 14, 2000	30 years
	Ordinance No.  352	SPE Santa Luzia Energética S.A.	Santa Luzia	Santa Catarina	35 years from December 21, 2007	30 years
	Resolution No.  355	SPE Varginha Energia S.A.	Varginha	Minas Gerais	30 years from December 23, 1999	30 years
	Resolution No.  367	SPE Várzea Alegre Energia S.A.	Várzea Alegre	Minas Gerais	30 years from December 30, 1999	30 years
	Ordinance No.  502	SPE Boa Vista II Energia S.A.	Boa Vista II	Minas Gerais	35 years from November 09, 2015	30 years
Thermoelectric biomass plants
	2106	CPFL Bioenergia	Baldin Thermoelectric Power Plant	São Paulo	30 years from September 24, 2009	At the discretion of the granting authority
	Resolution No.  3714	SPE Alvorada S.A.	Alvorada Thermoelectric Power Plant	Minas Gerais	30 years from October 29, 2012	At the discretion of the granting authority
	Resolution No.  2643	CPFL Bio Buriti S.A.	Buriti Thermoelectric Power Plant	São Paulo	30 years from December 16, 2010	At the discretion of the granting authority
	Resolution No.  3328	SPE Coopcana S.A.	Coopcana Thermoelectric Power Plant	Paraná	30 years from February 14, 2012	At the discretion of the granting authority
	Resolution No.117	Lacenas Participações Ltda.	Ester Thermoelectric Power Plant	São Paulo	30 years from May 21, 1999	At the discretion of the granting authority
	Resolution No.  259	CPFL Bio Formosa S.A.	Baía Formosa Thermoelectric Power Plant	Rio Grande do Norte	30 years from May 15, 2002	At the discretion of the granting authority
	Resolution No.  2375	CPFL Bio Ipê S.A.	Ipê Thermoelectric Power Plant	São Paulo	30 years from May 3, 2010	At the discretion of the granting authority
	Ordinance No.  129	CPFL Bio Pedra S.A.	Pedra Thermoelectric Power Plant	São Paulo	35 years from February 28, 2011	At the discretion of the granting authority

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Wind farm plants
	Ordinance No.  134	Atlântica I Parque Eólico S.A.	Atlântica I	Rio Grande do Sul	35 years from February 28, 2011	At the discretion of the granting authority
	Ordinance No.  148	Atlântica II Parque Eólico S.A.	Atlântica II	Rio Grande do Sul	35 years from March 04, 2011	At the discretion of the granting authority
	Ordinance No.  147	Atlântica IV Parque Eólico S.A.	Atlântica IV	Rio Grande do Sul	35 years from March 04, 2011	At the discretion of the granting authority
	Ordinance No.  168	Atlântica V Parque Eólico S.A.	Atlântica V	Rio Grande do Sul	35 years from March 22, 2011	At the discretion of the granting authority
	Resolution No.  093	Bons Ventos Geradora de Energia S.A.	Bons Ventos	Ceará	30 years from March 10, 2003	At the discretion of the granting authority
	Ordinance No.  257	Campo dos Ventos II Energias Renováveis S.A.	Campo dos Ventos II	Rio Grande do Norte	35 years from April 18, 2011	At the discretion of the granting authority
	Resolution No.3967	Campo dos Ventos I Energias Renováveis S.A.	Campo dos Ventos I	Rio Grande do Norte	30 years from March 26, 2013	At the discretion of the granting authority
	Resolution No.3968	Campo dos Ventos III Energias Renováveis S.A.	Campo dos Ventos III	Rio Grande do Norte	30 years from March 26, 2013	At the discretion of the granting authority
	Resolution No.3969	Campo dos Ventos V Energias Renováveis S.A.	Campo dos Ventos V	Rio Grande do Norte	30 years from March 26, 2013	At the discretion of the granting authority
	Resolution No.  680	Bons Ventos Geradora de Energia S.A.	Canoa Quebrada	Ceará	30 years from December 11, 2002	At the discretion of the granting authority
	Resolution No.  329	Rosa dos Ventos Geração e Comercialização de Energia S.A.	Canoa Quebrada	Ceará	30 years from June 19, 2002	At the discretion of the granting authority
	Ordinance No.  585	SPE Costa Branca Energia S.A.	Costa Branca	Rio Grande do Norte	35 years from October 14, 2011	At the discretion of the granting authority
	Resolution No.  625	Bons Ventos Geradora de Energia S.A.	Enacel	Ceará	30 years from November 13, 2002	At the discretion of the granting authority
	Ordinance No.  264	Desa Eurus I S.A.	Eurus I	Rio Grande do Norte	35 years from April 19, 2011	At the discretion of the granting authority
	Ordinance No.  266	Desa Eurus III S.A.	Eurus III	Rio Grande do Norte	35 years from April 27, 2011	At the discretion of the granting authority
	Ordinance No.  749	Eurus VI Energias Renováveis Ltda.	Eurus VI	Rio Grande do Norte	35 years from August 25, 2010	At the discretion of the granting authority
	Resolution No.  306	SIIF Cinco Geração e Comercialização de Energia S.A.	Foz de Choró	Ceará	30 years from June  05, 2002	At the discretion of the granting authority
	Resolution No.  454	Eólica Icaraizinho Geração e Comercialização de Energia S.A.	Icaraizinho	Ceará	30 years from August 28, 2002	At the discretion of the granting authority

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Ordinance No.  556	SPE Juremas Energia S.A.	Juremas	Rio Grande do Norte	35 years from September 29, 2011	At the discretion of the granting authority
Resolution No.  340	Rosa dos Ventos Geração e Comercialização de Energia S.A.	Lagoa do Mato	Ceará	30 years from June 26, 2002	At the discretion of the granting authority
Ordinance No.  557	Macacos Energia S.A.	Macacos	Rio Grande do Norte	35 years from September 29, 2011	At the discretion of the granting authority
Ordinance No.  664	Desa Morro dos Ventos I S.A.	Morro dos Ventos I	Rio Grande do Norte	35 years from July 27, 2010	At the discretion of the granting authority
Ordinance No.  373	Desa Morro dos Ventos II S.A.	Morro dos Ventos II	Rio Grande do Norte	35 years from June 12, 2012	At the discretion of the granting authority
Ordinance No.  685	Desa Morro dos Ventos III S.A.	Morro dos Ventos III	Rio Grande do Norte	35 years from August 04, 2010	At the discretion of the granting authority
Ordinance No.  686	Desa Morro dos Ventos IV S.A.	Morro dos Ventos IV	Rio Grande do Norte	35 years from August 04, 2010	At the discretion of the granting authority
Ordinance No.  663	Desa Morro dos Ventos VI S.A.	Morro dos Ventos VI	Rio Grande do Norte	35 years from July 27, 2010	At the discretion of the granting authority
Ordinance No.  665	Desa Morro dos Ventos IX S.A.	Morro dos Ventos IX	Rio Grande do Norte	35 years from July 27, 2010	At the discretion of the granting authority
Resolution No.  460	Eólica Paracuru Geração e Comercialização de Energia S.A.	Paracuru	Ceará	30 years from August 28, 2002	At the discretion of the granting authority
Ordinance No.  584	Pedra Preta Energia S.A.	Pedra Preta	Rio Grande do Norte	35 years from October 14, 2011	At the discretion of the granting authority
Resolution No.  307	Eólica Formosa Geração e Comercialização de Energia S.A.	Praia Formosa	Ceará	30 years from June  05, 2002	At the discretion of the granting authority
Ordinance No.  609	Santa Clara I Energia Renováveis Ltda.	Santa Clara I	Rio Grande do Norte	35 years from July 02, 2010	At the discretion of the granting authority
Ordinance No.  683	Santa Clara II Energia Renováveis Ltda.	Santa Clara II	Rio Grande do Norte	35 years from August 05, 2010	At the discretion of the granting authority
Ordinance No.  610	Santa Clara III Energia Renováveis Ltda.	Santa Clara III	Rio Grande do Norte	35 years from July 02, 2010	At the discretion of the granting authority
Ordinance No.  672	Santa Clara IV Energia Renováveis Ltda.	Santa Clara IV	Rio Grande do Norte	35 years from July 30, 2010	At the discretion of the granting authority
Ordinance No.  838	Santa Clara V Energia Renováveis Ltda.	Santa Clara V	Rio Grande do Norte	35 years from October 11, 2010	At the discretion of the granting authority
Ordinance No.  670	Santa Clara VI Energia Renováveis Ltda.	Santa Clara VI	Rio Grande do Norte	35 years from July 30, 2010	At the discretion of the granting authority
Resolution No.  4592	Santa Mônica Energias Renovaveis Ltda.	Santa Mônica	Rio Grande do Norte	30 years from April 01, 2014	At the discretion of the granting authority
Resolution No.  4591	Santa Ursula Energias Renovaveis Ltda.	Santa Úrsula	Rio Grande do Norte	30 years from March 31, 2014	At the discretion of the granting authority

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	Resolution No.  778	Bons Ventos Geradora de Energia S.A.	Taíba Albatroz	Ceará	30 years from December 24, 2002	At the discretion of the granting authority
	Resolution No.  4563	São Benedito Energias Renovaveis Ltda.	Ventos de São Benedito	Rio Grande do Norte	30 years from March 07, 2014	At the discretion of the granting authority
	Resolution No.  4562	Ventos de Santo Dimas Energias Renovaveis Ltda.	Ventos de Santo Dimas	Rio Grande do Norte	30 years from March 07, 2014	At the discretion of the granting authority
	Resolution No.  4572	Ventos de São Martinho Energias Renovaveis Ltda.	Ventos de São Martinho	Rio Grande do Norte	30 years from March 21, 2014	At the discretion of the granting authority
	Ordinance No.  387	Pedra Cheirosa I Energia S.A.	Pedra Cheirosa I	Ceará	35 years from August 04, 2014	At the discretion of the granting authority
	Ordinance No.  359	Pedra Cheirosa II Energia S.A.	Pedra Cheirosa II	Ceará	35 years from July 23, 2014	At the discretion of the granting authority
Solar power plants
	Of.ANEEL No.  961/2012	SPE CPFL Solar 1 Energia S.A.	Tanquinho	São Paulo	Undetermined(**)	Undetermined(**)

(*)   Project in planning phase.

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

Independent Power Producers 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.

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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, 2017 was R$9,787 million.  No single one of our properties produces more than 10.0% of our total revenues.  Our facilities are generally adequate for our present needs and suitable for their intended purposes.

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

Environmental

The Brazilian 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 laws and licensing procedures, which include the undertaking of environmental impact studies prior to constructing new facilities and implementing programs to reduce environmental impacts.  Once the respective environmental licenses are obtained, the company holding such 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 consider 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 ONS, as of December 31, 2017, the Installed Capacity of power generation in Brazil was 157,807 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 increased by 0.8% in 2017, reaching 465,130 GWh.  The MME and the EPE estimate that electricity consumption will grow by 3.7% per year, however, until 2026. 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 212.5GW by 2026, of which 118.6 GW (55.8%) is projected to be hydroelectric, 33.0 GW (15.5%) is projected to be thermoelectric and nuclear and 60.9 GW (28.7%) is projected to be from other renewable sources.

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Currently, approximately 29.7% of the Installed Capacity in Brazil is owned by Eletrobras, a joint capital and publicly traded company controlled by the Brazilian government.  We are among the largest private players within the electricity generation sector, with 2.1% of the market share.

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.

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.

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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.

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 concessionairemay 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.

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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”.

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 torender 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.

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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.

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.

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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 thatpurchase 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/real exchange rate.  Changes in the price of electricity generated by Itaipu are, however, subject to the Parcel A Cost recovery mechanism discussed below under “—Distribution Tariffs”. 

The Regulated Market

In the Regulated Market, distribution companies purchase their expected electricity requirements for their Captive Consumers from generators through public auctions.  The auctions are administered by ANEEL, either directly or indirectly through the CCEE.

Electricity purchases are made through two types of bilateral agreements:  (i) Energy Agreements (Contratos de Quantidade de Energia); and (ii) Capacity Agreements (Contratos de Disponibilidade de Energia).  Under an Energy Agreement, a generator commits to supply a certain amount of electricity and assumes the risk that its electricity supply could be adversely affected by hydrological conditions and low reservoir levels, among other conditions, which could interrupt the supply of electricity.  In such cases, the generator is required to purchase the electricity elsewhere in order to comply with its supply commitments.  Under a Capacity Agreement, a generator commits to make a certain amount of capacity available to the Regulated Market.  In such case, the generator’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.

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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”.

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.  Under Act No. 455/2012, PPAs had to be registered in advance with the CCEE on a monthly basis, but the electricity volume contracted could be adjusted on anex post basis after the consumption had taken place.  Under Act No. 455/2012, as of June 1, 2014, PPAs needed to be registered with the CCEE in advance on a weekly basis, and theex post volume adjustment was prohibited.  As a result, parties had to state their expected consumption volumeex ante, except when they had specifically indicated to the CCEE that the PPA in question referred to effective consumption volume.  However, the Brazilian Association of Electricity Traders (ABRACEEL) obtained an injunction against Act No.  455/2012, preventing the implementation of theex ante contract registration rule to energy traders.  The application of this Act in the CCEE was previously suspended for all agents (Generators, Traders and Consumer), since its applicability to specific groups of agents was unclear.  In addition, on January 9, 2018, a federal court declared Act No. 455/2012 null, stating that the MME has no competence to issue regulations related to the commercialization of electric energy. However, this decision will still have to be confirmed by the court of appeal due to the requirement for review of all cases involving the Brazilian government. The act only applied to the Free Market, not 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.

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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. 

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$505.18, according to ANEEL’s Resolution 2,364/2017.  Before such Resolution, the maximum value of PLD was R$533.82 (Resolution No. 2,190/2016) and R$422.56 (Resolution No. 2,002/2015).

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 disputeresolution; (iv) the trading rules in both Regulated and Free Markets; and (v) the accounting and clearing process for transactions in the spot market.

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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. 

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.

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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.

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 for 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.

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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.

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. For concessionaires whose contracts were extended in 2015 and that undergo tariff revisions after February 24, 2017, there will also be an annual update of the productivity (Pd) component.

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. However, for concessionaires whose contracts were extended in 2015, the inflation index used to restate Parcel B is the IPCA.

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.  Previously, all revisions in methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.  However, in 2015, ANEEL changed this procedure to allow for the review of the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis.  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 toconcession 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.”. 

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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.

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 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, but 2017 consisted principally of yellow and red tariff flags.  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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Regulatory Charges

EER

The Reserve Energy Charge (Encargo de Energia de Reserva), or EER, is a regulatory charge assessed on a monthly basis designed to raise funds for energy reserves contracted by CCEE.  These energy reserves are used to increase the safety of the energy supply in the Interconnected Power System.  The EER is collected on a monthly basis from Final Consumers of the Interconnected Power System registered with CCEE.

RGR Fund and UBP

In certain circumstances, electric energy companies are compensated for certain assets used in connection with a concession if the concession is revoked or is not renewed.  In 1957, the Brazilian government created a reserve fund designed to provide funds for such compensation, known as the “RGR Fund”.  Public service generation companies must make monthly contributions to the RGR Fund at an annual rate equal to 2.5% of the company’s annual investments in fixed assets related to the rendering of public services, not to exceed 3.0% of total operating revenues in any year.  Law No.  12,431 of 2011 extended the imposition of this fee until 2035.  However, Law No.  12,783/13 provides that, as of January 1, 2013, this charge is no longer levied on distribution companies, generation and transmission concessions which had the concession extended under that Law or new generation and transmission concessionaires.

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

CDE Account

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

ESS – System Service Charge

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

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

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Fee for the Use of Water – CFURH

The New Industry Model Law requires that holders of a concession and authorization to use water resources must pay a fee of 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.

                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.  In January 2016, our joint venture BAESA opted to renegotiate its ACR contracts. Therefore, the hydrologic riskswere transferred to the Centralizing Account of the Resources from the Tariff Flags (Conta Centralizadora dos Recursos de Bandeiras Tarifárias, or CCRBT). 

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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 audited annual 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 our previous distribution subsidiaries CPFL Santa Cruz, CPFL Leste Paulista, CPFL Jaguari, CPFL Sul Paulista and CPFL Mococa (now all merged into CPFL Santa Cruz), which had their periodic reviews in March 2016, average tariffs were also increased.  For further information on the merger, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.  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 April 2015, the Morro dos Ventos II Wind Farm commenced operations, with Installed Capacity of 29 MW.  Also in April 2015, at the A-5/21^st 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 audited annual 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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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. 

The wind farms at the Pedra Cheirosa wind complex (Pedra Cheirosa I and II), located in the municipality of Itarema, State of Ceará, started operations on June 27, 2017, almost a year earlier than expected. The installed capacity is of 48.3 MW and the assured energy is of 26.1 average-MW. Energy was sold through long-term contracts in the 2013 A-5 auction (at R$156.20/MWh for Pedra Cheirosa I and at R$156.82 for Pedra Cheirosa II, both in June 2017).

By the end of 2020, when we expect the Boa Vista SHPP to become operational, we expect our total Installed Capacity to reach 3,299 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 2017, sales to Captive Consumers represented 65.9% of the volume of electricity we delivered and 59.7% of our operating revenues, compared to 67.9% of the volume of electricity we delivered and 72.8% of our operating revenues in 2016.  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”.

Tariffs are determined separately for each of our five 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 of February 2016, every March for CPFL Santa Cruz (prior to February 2016, the tariff adjustments for CPFL Santa Cruz 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, 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 thetariffs 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”.

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· 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 or 2017.

Annual Adjustment — RTA

On November 21, 2017, through the Resolution for Authorization No. 6,723/2017, ANEEL approved our proposal to consolidate the concessions of our five distribution companies (CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari, together the Merged Companies), pursuant to Normative Resolution No. 716/2016.  Effective as of January 1, 2018, the Merged Companies were merged with and into a company named CPFL Santa Cruz (which company was previously named CPFL Jaguari). This transaction was approved by Extraordinary General Meetings held on December 31, 2017 at each of the Merged Companies.  For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.  According to Normative Resolution No. 716/2016, until the first tariff review of the Merged Companies in March 2021, ANEEL may institute a policy that reconciles the variations in the old tariffs for each of the Merged Companies and the new unified tariff for CPFL Santa Cruz over time. ANEEL decided to introduce the unified tariff during the March 2018 tariff adjustment.

Tariff increases apply differently to different consumer classes, with generally higher increases for consumers using higher voltages, to reduce the effects of historical cross‑subsidies in their favor that were mostly eliminated in 2007.  The following table sets forth the average percentage increase in our tariffs resulting from each annual adjustment from 2014 through the date of this annual report.  Rates of tariff increase should be evaluated in light of the Brazilian inflation rate.  See “—Background—Brazilian Economic Conditions”.

	CPFL Paulista	CPFL Piratininga	RGE	RGE Sul	CPFL Santa Cruz(7)	CPFL Mococa(7)	CPFL Leste Paulista(7)	CPFL Sul Paulista(7)	CPFL Jaguari(7)
2014
Economic 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)%
2015
Economic 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%
2016
Economic 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)
2017
Economic adjustment(1)	2.13%	6.33%	2.37%	2.95%	1.37%	3.45%	3.18%	0.97%	3.88%
Regulatory adjustment(2)	(2.93)%	1.37%	1.21%	(3.15)%	(2.65)%	(1.80)%	(2.41)%	0.66%	(1.83)%
Total adjustment	(0.80)%	7.69%	3.57%	(0.20)%	(1.28)%	1.65%	0.77%	1.63%	2.05%
2018
Economic adjustment(1)	8.67%	(3)	(3)	11.57%	4.41%	(7)	(7)	(7)	(7)
Regulatory adjustment(2)	4.01%	(3)	(3)	6.88%	1.30%	(7)	(7)	(7)	(7)
Total adjustment	12.68%	(3)	(3)	18.45%	5.71%	(7)	(7)	(7)	(7)

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

(2)   This portion of the adjustment reflects settlement of regulatory assets and liabilities we present in our regulatory financial information, primarily the CVA, and is not considered in the calculation of the following year’s adjustment.

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

(4)   Represents the effect of Periodic Revisions – RTP for CPFL 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 (now all merged into CPFL Santa Cruz) 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 (now all merged into CPFL Santa Cruz) to March every year.

(6)   Tariffs defined prior to the acquisition of RGE Sul.

(7)   Merged into CPFL Santa Cruz effective as of January 1, 2018. For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.

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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 2015, ANEEL now reviews the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis, whereas previously all methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.

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

	First cycle		Second cycle		Third cycle		Fourth cycle
	Adjustment 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	8.67
CPFL Piratininga	October 2003	10.14	October 2007	(12.77)	October 2011	(3.95)(1)(3)	October 2015	40.14
RGE	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	11.57
CPFL Santa Cruz(6)	February 2004	17.14	February 2008	(14.41)	February 2012	4.16(1)(2)	March 2016	11.59
CPFL Mococa(6)	February 2004	21.73	February 2008	(7.60)	February 2012	7.18(1)(2)	March 2016	11.90
CPFL Leste Paulista(6)	February 2004	20.10	February 2008	(2.18)	February 2012	(2.00)(1)(2)	March 2016	17.01
CPFL Sul Paulista(6)	February 2004	12.29	February 2008	(5.19)	February 2012	(4.48)(1)(2)	March 2016	16.89
CPFL Jaguari(6)	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 (now merged into CPFL Santa Cruz) 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 (now merged into CPFL Santa Cruz) 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.

(6)   Merged into CPFL Santa Cruz effective as of January 1, 2018. For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.

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Extraordinary Tariff Adjustment – RTE

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

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

	CPFL Paulista	CPFL Piratininga	RGE	RGE Sul	CPFL Santa Cruz(2)	CPFL Mococa(2)	CPFL Leste Paulista(2)	CPFL Sul Paulista(2)	CPFL Jaguari(2)
2013
Economic 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.
(2)   Merged into CPFL Santa Cruz effective as of January 1, 2018. For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.

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)(3)	CPFL Mococa(1)(3)	CPFL Leste Paulista(1)(3)	CPFL Sul Paulista(1)(3)	CPFL Jaguari(1)(3)
2015
Economic 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 (now all merged into 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.

(3)   Merged into CPFL Santa Cruz effective as of January 1, 2018. For more information, see “Item 4. Information on the Company—Overview” and Note 14.4.2 of our audited annual consolidated financial statements.

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 thatpurchase 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.

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Prices for Purchased Electricity

The prices of electricity purchased by our distribution companies under long‑term contracts executed in the Regulated Market are:  (i) approved by ANEEL in the case of agreements entered into before the New Industry Model Law; and (ii) determined in auctions for agreements entered into thereafter, while the prices of electricity purchased in the Free Market are agreed by bilateral negotiation based on prevailing market rates.  In 2017, we purchased 77,974 GWh, compared to 63,975 GWh in 2016. The increase of 21.9%, or 13,999 GWh, was due to (i) an increase of 22.2%, or 11,375 GWh, in the volume of energy purchased through auction in the regulated market and bilateral contracts, (ii) an increase of 59.6%, or 1,342 GWh, in costs of energy purchased in the spot market and (iii) an increase of 12.2%, or 1,282 GWh, in purchases from Itaipu, each of which were driven by our increased electricity sales. Prices under long‑term contracts are adjusted annually to reflect increases in certain generation costs and inflation.  Most of our contracts have adjustments linked to the annual adjustment in distribution tariffs, so that the increased costs are passed through to our consumers in increased tariffs.  Since an increasing proportion of our energy is purchased at public auctions, the success of our strategies in these auctions affects our margins and our exposure to price and market risk, as our ability to pass through costs of electricity purchases depends on the successful projection of our expected demand.

We also purchase a substantial amount of electricity from Itaipu under take‑or‑pay obligations at prices that are governed by regulations adopted under an international agreement.  Electric utilities operating under concessions in the Midwest, South and Southeast regions of Brazil are required by law to purchase a portion of Brazil’s share of Itaipu’s available capacity.  In 2017, we purchased 11,779 GWh of electricity from Itaipu (15.1% of the electricity we purchased in terms of volume), as compared to 10,497 GWh (16.4% of the electricity we purchased in terms of volume) in 2016.  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 for Calculation of Distribution Tariffs”.

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

This tariff-pricing mechanism may lead to timing differences between the budgeted costs (Parcel A and other financial components) included in the tariff at the beginning of the tariff period and those actually incurred while it is in effect.  This difference createsa contractual right to receive cash from consumers through subsequent tariffs, or to pay to (or receive from) the granting authority any remaining amounts at the expiration of the concession (see note 8 to our audited annual consolidated financial statements).  This leads to an adjustment to recognize the future increase (or decrease) in tariffs to take account of additional (or lower) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue recorded as Sector Financial Assets or Liabilities. 

On November 25, 2014, ANEEL approved an amendment to distribution concession contracts.  On December 10, 2014, the nine distribution subsidiaries we had at that time 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 29 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) CPFL Telecom and (ii) 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 78.8% of our net operating revenue in 2017 (compared with 78.7% in 2016), but its contribution to our net income was smaller at 48.7% of our net income for the year, as further explained in “Results of Operations—2017 compared to 2016—Net Income” below (by comparison, our Distribution segment accounted for 46.3% of our net income in 2016 and 71.5% in 2015). 

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, 2017, 2016 and 2015 are presented in the following table:

	Distribution	Conventional Generation	Renewable Generation	Commercialization	Services
2017
Net operating revenue	78.8%	4.5%	7.3%	12.8%	1.8%
Net income	48.6%	52.4%	1.6%	7.3%	4.4%
2016
Net operating revenue	78.7%	5.2%	8.8%	10.9%	2.1%
Net income	46.3%	57.4%	(16.0)%	12.8%	6.1%
2015
Net operating revenue	82.4%	4.8%	7.8%	8.7%	1.4%
Net income	71.5%	32.3%	(6.4)%	10.1%	5.9%

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, 2017, our Renewable Generation Sources segment provided 20.0% of our operating income, but due to the significant financing costsincurred to finance these projects, the segment’s contribution to net income was only 1.6%. As of December 31, 2017, 2.6% of the property, plant and equipment in our Renewable Generation Sources segment was under construction, compared to 2.4% as of December 31, 2016. In 2017, we began to report within this business the activities of our two transmission assets held through CPFL Geração, CPFL Piracicaba and CPFL Morro Agudo, both of which are operational.

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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 audited annual 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 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, 2017, 2016 and 2015:

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	Distribution	Conventional Generation Sources	Renewable Generation Sources	Commercialization	Services	Other (*)	Elimination	Total
2017
Net Revenue	21,068,435	741,842	1,489,932	3,402,804	40,611	1,281	-	26,744,905
(-) Inter-segment Revenues	8,182	448,421	469,152	11,297	444,935	-	(1,381,988)	-
Income from electric energy service	1,470,695	763,415	604,596	167,724	67,598	(52,193)	-	3,021,834
Financial income	597,133	102,713	137,746	19,117	10,693	12,912	-	880,314
Financial expense	(1,163,600)	(431,289)	(648,571)	(52,023)	(6,445)	(65,939)	-	(2,367,868)
Income before taxes	904,228	747,229	93,770	134,818	71,846	(105,220)	-	1,846,670
Income tax/social contribution	(299,510)	(95,688)	(74,125)	(44,527)	(16,994)	(72,784)	-	(603,629)
Net Income	604,717	651,541	19,645	90,290	54,852	(178,004)	-	1,243,042
2016
Net 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)	-	2,522,608
Financial income	781,365	182,574	132,653	31,513	10,742	61,655	-	1,200,503
Financial 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)	-	1,380,547
Income 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)	-	879,057
2015
Net 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)	-	2,645,434
Financial income	740,628	110,018	131,354	42,840	44,098	74,310	-	1,143,247
Financial 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)	-	1,454,454
Income 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)	-	875,277

(*)   Refers to recorded assets and transactions that are not related to any of our operating 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. 

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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 temperaturesand 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 for 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, 2017, 2016 and 2015:

	2017	2016	2015
Growth in GDP (inreais)(1)	1.0%	(3.5%)	(3.5%)
Unemployment rate ‑ % average(2)	12.7%	11.5%	8.5%
Credit to individuals (non‑earmarked resources) ‑ % GDP	13.0%	12.9%	13.4%
Growth in Retail Sales	2.0%	(6.3%)	(4.3%)
Growth (contraction) in Industrial Production	2.5%	(6.4%)	(8.3%)
Inflation (IGP‑M)(3)	(0.5%)	7.2%	10.5%
Inflation (IPCA)(4)	2.9%	6.3%	10.7%
Average exchange rate–US$1.00(5)	R$3.20	R$3.483	R$3.339
Year‑end exchange rate–US$1.00	R$3.31	R$3.259	R$3.905
Depreciation (appreciation) of therealvs.  U.S. dollar	1.5%	(16.5%)	47.0%

Sources: Focus Report, Instituto Brasileiro de Geografia e Estatística and 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 Brazilian Institute for Geography and Statistics (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 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 strong economic contraction with significant political crises and uncertainties, and poor economic indicators. However, in 2017, the Brazilian economy began to improve, showing recovery in principal areas of activity and financial indicators, with GDP growth of 1.0% (compared with negative growth of 3.5% in both 2016 and 2015), according to the Brazilian Central Bank.

                    Employment and income indicators, which are all key indicators of electrical energy consumption, also showed recovery in 2017 and helped to boost domestic activity. According to IBGE, in 2017 household consumption had increased 1.0% compared with negative growth of 3.2% and 4.3% in 2015 and 2016, respectively. 

                    Our industry also experienced positive results in 2017, showing annual growth of 2.5% in 2017, according to IBGE, and experiencing the highest rate of exports in the last five years, according to the Industry and Foreign Trade Ministry. This growth was a result of international demand, which benefited from a favorable exchange rate and the 3.5% growth in world GDP, according to the International Monetary Fund.

                    In 2017, the inflation rate (IPCA) reached the lowest level in 20 years (2.9% e.o.p.), which allowed for a more flexible monetary policy. As a result, the Brazilian Central Bank was able to sustain continued reductions in the Selic interest rate throughout the year, reaching 7.0% by year-end.

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                    However, despite the improvement in various macro factors in 2017, Brazil continues to experience successive downgrades of the country’s credit rating:  Standard & Poor’s (September 2015 and January 2018); Fitch Ratings (December 2015); Moody’s Investors Service (February 2016). These devaluations reflect continued adverse fiscal developments and continued 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, maintaining it at AA. As of the date of this report, our ratings from both agencies have been sustained.

Reclassification of information for 2015

                    Data for 2015 has 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 January 1, 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. 

Results of Operations—2017 compared to 2016

Net Operating Revenues   

Compared to the year ended December 31, 2016, our net operating revenues increased 39.9% (or R$7,633million) to R$26,745 million in the year ended December 31, 2017. Excluding the consolidation of RGE Sul effects, acquired in October 2016, net operating revenue increased to R$ 23,375 million, an increase of R $ 25.6% (R$ 4,768 million) when compared to 2016. 

This increase in operating revenue was primarily due to the combined effect of: (i) a positive variation of R$3,996 million in the Sector Financial Assets and Liabilities, as discussed in the section “Other Operating Revenue” below; (ii) an increase of R$1,699 million in energy sales in the spot market, as discussed in the section “Sales by Destination” below; (iii) an increase of R$1,430 million in electricity sales to final consumers, as discussed in the section “Sales by Destination” below; and (iv) an increase of R$869 million in other concessionaires and licensees, partially offset by an increase of R$1,637 million in deductions from operating revenues, discussed in the section “Deductions from operating revenues” 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, 2016, our gross operating revenues from sales to Final Consumers (which includes TUSD revenue from captive consumers) increased 7.5% (or R$1,788 million) in the year ended December 31, 2017, to R$25,787 million.  Our gross operating revenues primarily reflect sales to Captive Consumers in concession areas from our 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 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 occurs as well as the following year.  The adjustments for our largest subsidiaries occur in April (CPFL Paulista), June (RGE Sul and RGE) and October (CPFL Piratininga).

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In the year ended December 31, 2017, overall average energy prices decreased by 6.2%, mainly due to the negative tariff adjustment of 10.50% for CPFL Paulista, the negative tariff adjustment of 6.43% for RGE SUL, the positive tariffadjustment of 5.00% for RGE and the positive tariff adjustment of 17.28% for CPFL Piratininga.  As a result, although the red tariff rate was in effect for the majority of 2017, when compared to 2016, the effects of tariff adjustments (Annual Adjustment – RTA or Periodic Revision – RTP, since there is no Annual Adjustment in the year of Periodic Revisions) exceeded the other tariff effects. For more information, see note 25.2 to our audited annual consolidated financial statements. Overall average prices for Final Consumers in 2017 were lower for all consumer classes:

· Residential and commercial consumers.  With respect to Captive Consumers (which represent 95.3% of the total amount sold to this category in our consolidated statements), average prices decreased 5.3% for residential consumers and 3.6% for commercial consumers, due to the annual tariff adjustment described above.  With respect to Free Consumers, the average price for the commercial consumers decreased 25.7%.

· Industrial consumers.  Average prices decreased 5.6%, mainly due to the tariff adjustments described above.  With respect to Free Consumers, the average price for industrial consumers decreased 31.4%.  The decrease in the average price for the industrial consumers was due to the tariff applied to the contracts governing the use of our TUSD by Free Consumers, which resulted from the annual tariff adjustment.

The total volume of energy sold to Final Consumers in the year ended December 31, 2017 increased 14.6% compared to the year ended December 31, 2016.  This increase represents the effect of an increase of 86% (or 4,427 GW) in the volume of energy sold to Conventional Free Consumers (driven by increases of (i) 3,512 GW to industrial, (ii) 725 GW to commercial consumers and (iii) 190 GW to other consumers by our commercialization subsidiaries as a result of the migration of these consumers from captive to the free consumer category) and the inclusion of RGE Sul’s distribution operations in our consolidated results for the full year in 2017, which led to an increase of 5,563 GW (compared to RGE Sul’s 1,141 GW contribution during the last two months of 2016).

The volume sold to residential and commercial categories, which accounts for 66.6% for our sales to Final Consumers, increased by 16.1% (or 2,649 GW) and 5.2% (or 501 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 full year in 2017 (compared to inclusion in only the last two months of 2016), which led to an increase of 2,230 GW sold to residential consumers, compared to 426 GW in 2016; and (ii) an increase of 2.6% of the volume sold by our distribution subsidiaries (excluding RGE Sul) to the residential category; due to our residential consumers’ greater economic strength in 2017, driven by the GDP growth of 1.0% in 2017 compared to the GDP contraction of 3.5% in 2016.

· Commercial:  (i) an increase of 142 GW in the volume of energy sold to Captive Consumers in the commercial category; and (ii) an increase of 617 GW in the volume sold by our commercialization subsidiaries due to the migration of consumers from captive to the free consumer category.  This increase was partly offset by a reduction of 60.9% (or 258 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 who are allowed to purchase energy only from renewable sources.

The volume sold to industrial consumers, which represented 19.8% of our sales to Final Consumers in 2017 (compared with 22.0% in 2016), decreased by 2.2% in the year ended December 31, 2017 compared to the year ended December 31, 2016.  Volumes to Captive Consumers in this category decreased 6.6%, which represents the net effect of a decrease of 463 GW related to our distribution subsidiaries and the increase in migration of industrial consumers from the captive to the free market.  Regarding Free Consumers, volumes sold increased by 5.1% (or 725 GW), reflecting the same migration of consumers, as well as improvements in Brazilian economic conditions during 2017.

Sales to wholesalers

Compared to the year ended December 31, 2016, our gross operating revenues from sales to wholesalers in the year ended December 31, 2017 increased 74.2% (or R$2,594 million) to R$6,090 million (15.2% of gross operating revenues), due mainly to (i) an increase of 264.7% (or R$1,699 million) in sales of energy in the spot market (mainly driven by higher average prices), and (ii) an increase of 36.7% (or R$869 million) in sales of electricity to other concessionaires and licensees.  These increases reflect the combined effect of an increase of 28.4% in energy volumes sold and an increase of 35.7% in the average price of sales to wholesalers compared to 2016.  For more information on net operating revenues from our segments, see “—Sales by Segment”. 

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Other operating revenues

Compared to the year ended December 31, 2016, our other gross operating revenues (which excludes TUSD revenue from captive consumers) increased 157.4% (or R$5,021 million) to R$8,210 million in the year ended December 31, 2017 (20.5% of our gross operating revenues), mainly due to:

(i)	a positive variation of R$3,996 million in revenue from Sector Financial Assets and Liabilities, which posted revenue of R$1,901 million in 2017 compared with an expense of  R$2,095 million in 2016.  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 pay (or receive) cash to or 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 increase in this item in 2017 was driven mainly by (i) an increase of R$2,353 million related to electric energy cost, (ii) an increase of R$495 million related to the pass-through from Itaipu and (iii) an increase of R$610 million in contributions to the ESS and EER.  For further information, see note 8 to our audited annual consolidated financial statements;
(ii)	an increase of R$719 million in revenue from construction of concession infraestructure; and
(iii)	the increase of 12.1% (or R$153 million) in revenue related to the low income subsidy and discounts on tariffs reimbursed by funds from the CDE Account.

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 33.2% of our gross operating revenue in the year ended December 31, 2017 and 37.9% in the year ended December 31, 2016.  Compared to the year ended December 31, 2016, these deductions increased by 14.0% (or R$1,637 million) to R$13,309 million in 2017, mainly due to: (i) an increase of 27.9% (or R$736 million) in PIS and COFINS taxes, mainly due to the increase in our gross operating revenues (the calculation basis for these taxes); (ii) an increase of 10.55% (or R$521 million) in ICMS taxes; (iii) an increase of R$448 million in tariff flag revenues recognized, which are required to be paid into the Tariff Flag Resources Centralizing Account administered by the CCEE; and (iv) a decrease of R$175 million in contributions made to the CDE Account as a result of the new quotas defined by ANEEL in 2017.

Sales by segment

Distribution

Compared to the year ended December 31, 2016, net operating revenues from our Distribution segment increased 40.1% (or R$6,037 million) to R$21,077 million in the year ended December 31, 2017.  This increase primarily reflected the increase of R$7,519 million in gross operating revenue, due to the following fluctuations:

(i)	a positive variation of R$3,996 million in revenue from Sector Financial Assets and Liabilities, which represented a revenue of R$1,901 million in 2017 compared with an expense of R$2,095 million in 2016 (see “Other Operating Revenues” above);
(ii)	an increase of R$1,272 million in electricity sales to wholesalers, driven by significant increases in the energy prices we were able to obtain on the spot market;
(iii)	an increase of R$722 million in revenue from construction of concession infrastructure; and
(iv)	the increase of 12.1% (or R$153 million) in revenue related to the low income subsidy and discounts on tariffs reimbursed by funds from the CDE Account (see note 25.5 to our audited annual consolidated financial statements and “Other Operating Revenues” above).

The deductions from our Distribution segments operating revenues increased by 13% (or R$1,460 million) to R$12,692 million in 2017, mainly due to: (i) an increase of 38.4% (or R$1,085 million) in deductions related to PIS, COFINS and ICMS taxes, driven by the increase in our gross operating revenues (the basis for calculation for these taxes); (ii) anincrease of R$448 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; and (iii) a decrease of5.2% (or R$175 million) in contributions made to the CDE Account due to new quotas defined by ANEEL in 2017 (see note 25.4 to our audited annual consolidated financial statements). For more information, see “Deduction from operating revenues” above).

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Generation (conventional sources)

Net operating revenues from our Generation from Conventional Sources segment in the year ended December 31, 2017 amounted to R$1,190 million, an increase of 18.7% (or R$187 million) compared to R$1,003 million in the year ended December 31, 2016, due mainly to (i) an increase of R$72 million in other revenues and income; (ii) an increase of R$47 million of revenue from construction related to CPFL Morro Agudo; (iii) an increase of 6.6% (R$37 million) in revenue from sales to our distribution subsidiaries; (iv) the price-driven increase of 5.9% (R$32 million) in revenue from sales from our facility Serra da Mesa to Furnas; and (v) an increase of 181.9% (or R$11 million) in spot market energy. This increase was partially offset by an increase of 8.8% (R$8.2 million) in PIS and COFINS tax deductions from revenue due to the increase in gross operating revenues from the segment (the basis for calculation for these taxes).

Generation (renewable sources)

Net operating revenues from our Generation from Renewable Sources segment in the year ended December 31, 2017 amounted to R$1,959 million, an increase of 17.1% (or R$286 million) compared to R$1,673 million in the year ended December 31, 2016.  This increase was due mainly to:  (i) an increase of R$210 million in revenue from Other concessionaires and licensees, driven by new volumes; and (ii) an increase of R$148 million in revenue from energy sales on the spot market.  These increases were partially offset by a decrease of 60.9% (or R$58 million) in revenue from Free Consumers in the Commercial sector, driven principally from Special Free Consumers migrating from the captive market and an increase of 6.8% (or R$7 million) in PIS and COFINS tax deductions from revenue due to the increase in gross operating revenues from the segment (the basis for calculation for these taxes).

Commercialization

Net operating revenues from our Commercialization segment in the year ended December 31, 2017 amounted to R$3,414 million, an increase of 63.6% (or R$1,327 million) compared to R$2,087 million in the year ended December 31, 2016.  This increase was mainly due to:  (i) an increase of 102.5% (or R$782 million) in revenue from sales to Other concessionaires and licensees, driven by a 76.2% (or R$4,121 million) increase in volume; (ii) an increase of 600.8% (or R$347 million) in revenue from sales in the spot market, driven by a 130.6% (or R$582 million) increase in volume; (iii) an increase of 21.3% (or R$281 million) in revenue from Industrial Free Consumers, driven by an increase of 38.9% in volumes; and (iv) an increase of 81.5% (or R$116 million) in revenue from Commercial Free Consumers, driven by an increase of 101.3% in volumes.

These increases were partially offset by:  (i) an increase of 63.6% (or R$136 million) in PIS and COFINS tax deductions from operating revenues, mainly due to the increase in gross operating revenues for the segment (the basis for calculation for these taxes); (ii) a decrease of 99.1% (or R$57 million) in other revenues and income; and (iii) a decrease of 100% (or R$12 million) of Electricity sales to Furnas (Wholesalers).

Services

Net operating revenues from our Services segment in the year ended December 31, 2017 amounted to R$486 million, an increase of 21.3% (or R$86 million) compared to R$400 million in the year ended December 31, 2016.  This increase was mainly due to:  (i) an increase of R$75 million in revenues from construction and maintenance services; (ii) an increase of R$27 million in revenues from administrative, call center and IT outsourcing.  These increases were partially offset by:  (i) a decrease of 23.5% (R$25 million) in revenue from our self-generation energy efficiency business; 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 for 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 increased 58.6% (or R$5,768 million) in the year ended December 31, 2017, to R$15,617 million (65.8% of our total operating costs and operatingexpenses) compared with R$9,849 million for the year ended December 31, 2016 (representing 59.4% of our total operating costs and operating expenses), mainly due to an increase of 30.1% in average prices, reflecting:

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(i) an increase of 67.1% (or R$5,728 million) in the cost of energy purchased in the Regulated Market, reflecting an increase of 22.2% in the volume of energy purchased and a 36.7% increase in average purchase prices;

(ii) an increase of R$325 million in purchases of energy from Itaipu, reflecting an increase of 3.4% in the average price of energy purchased (inreais), itself caused by a 11.4% increase in the tariff (which is established on an annual basis by ANEEL in US$/kW), 8.3% depreciation in the average rate of thereal against the U.S. dollar during 2017 compared with 2016 and a 12.2% increase in the volume of energy purchased; and

(iii) an increase of 107.6% (or R$290 million) in cost of energy purchased in the spot market, driven mainly by an increase of 59.6% in volume purchased.

 These increases were partly offset by an additional R$575 million in PIS and COFINS tax credits (representing an increase of 58.2% compared to 2016) related to purchases of energy, which represents a decrease in the cost of energy.

Electricity network usage charges.  Our charges for the use of our transmission and distribution system decreased 5.0% (or R$67 million) to R$1,284 million in the year ended December 31, 2017, mainly as a result of:  (i) a decrease of R$816 million of System Service Charges; and (ii) a decrease of R$107 million in EER.  These decreases were partially offset by (i) an increase of R$707 million in Basic Network Charges; (ii) an increase of R$107 million in transmission from Itaipu charges; and (ii) an increase of R$38 million in Connection Charges.    

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, 2016, our other costs and operating expenses increased 26.6% (or R$1,432 million) to R$6,822 million in the year ended December 31, 2017, mainly due to the following events: (i) an increase of 53.2% (or R$719 million) in expenses related to the construction of concession infrastructure; (ii) an increase of 25.9% (or R$283 million) in our personnel expenses, reflecting increased costs under our collective bargaining agreements; (iii) an increase of 19.9% (or R$207 million) in depreciation and amortization expenses; (iv) an increase of 11.7% (or R$76 million) in expenses related to outsourced services; (v) an increase of 31.6% (or R$60 million) in inventory consumption; (vi) an increase of R$49 million in expenses related to disposal of assets; and (vii) a decrease of 12.1% (or R$21 million) in allowance for doubtful accounts.

Income from Electric Energy Service

Compared to the year ended December 31, 2016, our income from electric energy service increased 19.8% (or R$499 million) to R$3,022 million in the year ended December 31, 2017, since our net operating revenue increased by more in absolute terms (R$7,633 million) than the increase in our cost of generating and distributing electric energy and other operating costs and expenses (R$7,134 million). 

Income from Electric Energy Service by Segment

Distribution

Compared to the year ended December 31, 2016, income from electric energy service from our Distribution segment increased R$217 million to R$1,471 million in the year ended December 31, 2017.  As discussed above, net operating revenues from the segment increased by R$6,037 million while costs and operational expenses related to the segment increased by R$5,819 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, 2016, electricity costs increased 45.1% (or R$4,399 million), to R$14,147 million in the year ended December 31, 2017. 

The cost of energy purchased for resale increased 52.6% (or R$4,473 million), reflecting: (i) an increase of 61.3% (or R$4,365 million) in the cost of energy purchased in the Regulated Market, reflecting an increase of 9.8% in the volumeof energy purchased and an increase of 46.9% in average purchase prices; (ii) an increase of R$325 million in purchases of energy from Itaipu, reflecting an increase of 3.4% in the average price of energy purchased (inreais), itself caused by a 11.4% increase in the tariff (which is established on an annual basis by ANEEL in US$/kW) and 8.3% depreciation in the average rate of thereal against the U.S. dollar during 2017 compared with 2016, offset by a 12.2% increase in the volume of energy purchased; and (iii) an increase of 109% (or R$236 million) in PROINFA costs.  This increase in the cost of energy purchased for resale was partially offset by an increase of 52.3% (or R$452 million) in PIS and COFINS tax credits related to purchases of energy.

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In addition, as mentioned above, charges for the use of the transmission and distribution system decreased 5.0% (or R$67 million) to R$1,284 million in the year ended December 31, 2017, mainly as a result of:  (i) a decrease of R$816 million of System Service Charges; and (ii) a decrease of R$107 million in Reserve Energy Charges.  These decreases in charges were partially offset by (i) an increase of R$707 million in Basic Network Charges; and (ii) an increase of R$29 million in Connection Charges.

Other costs and operating expenses.  Compared to the year ended December 31, 2016, our other costs and operating expenses for the Distribution segment increased 36.2% (or R$1,248 million), to R$4,695 million in the year ended December 31, 2017, mainly due to (i) an increase of 55.3% (or R$722 million) in expenses related to the construction of concession infrastructure; (ii) an increase of 29.7% (or R$195 million) in expenses related to outsourced services; (iii) an increase of 26.3% (or R$192 million) in our personnel expenses principally due to the acquisition of RGE Sul as well as salary increases under our collective bargaining agreement; and (iv) an increase of 15% (or R$84 million) in depreciation and amortization expenses.  These increases were partially offset by a decrease of 7.7% (or R$13 million) in allowance for doubtful accounts.Generation (conventional sources)

Compared to the year ended December 31, 2016, income from electric energy service from our Conventional Generation segment increased 13.7% (or R$91 million) to R$763 million for the year ended December 31, 2017.  This increase was mainly due to an increase of 18.7% (or R$187 million) in net operating revenue as discussed in the section “Sales by Segment” above, partly offset by an increase of 48.4% (or R$99 million) in costs and operational expenses.

The increase in costs and operational expenses was mainly due to (i) an increase of 62.4% (or R$46 million) in expenses related to the construction of concession infrastructure of CPFL Morro Agudo; (ii) an increase of 17.8% (or R$4 million) in expenses related to outsourced services; and (iii) an increase of R$49 million in the cost of electric energy driven by a 49.6% increase in volume and a 26.1% increase in average prices, which was the result of our strategy in 2017 to acquire energy in the short-term market in order to minimize the impacts of the GSF and PLD increases resulting from the lack of rainfall and the consequent reduction in hydropower generation and increase in thermal generation. This increase was partially offset by the recognition of R$7 million expense related to amortization of GSF costs.

Generation (renewable sources)

Compared to the year ended December 31, 2016, income from electric energy service from our Renewable Generation segment increased 37.4% (or R$165 million) to R$605 million for the year ended December 31, 2017.  This increase was mainly due to the increase of 17.1% (or R$286 million) in net operating revenue (as discussed in the section “Sales by Segment” above) partially offset by the increase of 9.9% (or R$122 million) in costs and operational expenses.

The increase in costs and operational expenses mainly reflects:  (i) an increase of 15.2% (or R$61 million) in depreciation and amortization expenses related to the entry into operation of Pedra Cheirosa; (ii) an increase of R$16 million in purchases of operating materials and equipment; (iii) R$15 million in expenses related to impairment of Bio Formosa and CPFL Solar Tanquinho projects; and (iv) an increase of 10.8% (or R$10 million) in charges for use of the transmission and distribution system. These increases in costs were partially offset by a decrease of 5.6% (or R$10 million) in expenses for outsourced services.

Commercialization

Compared to the year ended December 31, 2016, income from electric energy service from our Commercialization segment increased 5.6% (or R$9 million), to R$168 million in the year ended December 31, 2017. This increase was due to the net effect of the increase of 63.6% (or R$1,327 million) in net operating revenues of the segment, as discussed in the section “Sales by Segment” above, which exceeded the increase of 68.5% (or R$1,319 million) in costs and operational expenses.  The increase in costs and expenses was mainly due to an increase of 70.1% (or R$1,317 million) in the cost of energy purchased in the Regulated Market, driven by an increase of 62.2% in the volume of energy purchased partly offset by lower purchase prices.

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Services

Compared to the year ended December 31, 2016, income from electric energy service from our Services segment increased 3.4% (or R$2 million), to R$85 million in the year ended December 31, 2017. This increase was due to the net effect of the increase of 21.3% (or R$85 million) in net operating revenues as discussed in the section “Sales by Segment” above, which exceeded the increase of 24.0% (or R$83 million) in costs and operational expenses.

Net Income

Net Financial Expense

Compared with the year ended December 31, 2016, our net financial expense increased 2.3% (or R$34 million), from R$1,453 million in 2016 to R$1,488 in the year ended December 31, 2017, mainly due a decrease of R$286 million in our financial expenses, more than offset by a decrease of R$320 million in our financial income.

The reasons for the decrease in financial expenses are:  (i) a decrease of 24.4% (or R$171 million) in financial expenses from monetary and exchange adjustments, because of lower average interest rates; and (ii) a decrease of 8.0% (or R$144 million) in debt charges. These decreases in financial expenses were partially offset by (i) an increase of R$57 million in financial expenses from monetary adjustments of Sector Financial Liabilities; and (ii) a decrease of 25.8% (or R$18 million) in capitalized borrowing costs, which is accounted for as a decrease in financial expenses.

The decrease in financial income is mainly due to following reasons: (i) a decrease of 31.5% (or R$210 million) in income from financial investments, due to the reduction of the cash and cash equivalents balances; (ii) a decrease of 58.7% (or R$87 million) in income from monetary and exchange adjustments; (iii) a reduction of 100% (or R$33 million) in income from adjustment of Sector Financial Assets and Liabilities (see note 8 to our audited annual consolidated financial statements); and (iv) a decrease of R$13 million in adjustments of tax credits.  These decreases were partially offset by (i)  an increase of 7.9% (or R$19 million) in interest and fine payments; (ii) an increase of 16.1% (or R$11 million) in PIS and COFINS on other finance income; and (iii) an increase of 40.5% (or R$14 million) in income from adjustments of escrow deposits.

At December 31, 2017, we had R$15,310 million (compared with R$16,452 million at December 31, 2016) in debt denominated inreais, which accrued both interest and inflation adjustments based on a variety of Brazilian indices and money market rates.  The average CDI interbank rate during the year decreased to 9.93% in 2017, compared to 14% in 2016; and the average TJLP decreased to 7.1% in 2017, compared to 7.5% in 2016.  We also had the equivalent of R$4,858 million (compared with R$5,502 million at December 31, 2016) 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 increased to R$604 million in the year ended December 31, 2017 compared with R$501 million in the year ended December 31, 2016.  Our effective rate of 32.7% on pretax income in the year ended December 31, 2017 was lower than the official rate of 34%, principally due to the ability to recognize further prior year tax loss carryforwards.  Our unrecorded tax credits relate to losses generated for which there is no currently reasonable certainty that future taxable income will be sufficient to absorb such losses (see note 9.6 to our audited annual consolidated financial statements). 

Net Income

Compared to the year ended December 31, 2016, and due to the factors discussed above, net income increased 41.4% (or R$364 million), to R$1,243 million in the year ended December 31, 2017.

Net Income by Segment

In the year ended December 31, 2017, 48.6% of our net income derived from our Distribution segment, 52.4% from our Generation from Conventional Sources segment, 1.6% from our Generation from Renewable Sources segment, 7.3% from our Commercialization segment, 4.4% from our Services segment and negative 14.3% from Other. For the equivalent contributions from our segments in 2016 and 2015, see the table under “Background – Operating Segments” earlier in this Item 5.

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Distribution

Compared to the year ended December 31, 2016, net income from our Distribution segment increased 48.5%, (or R$198 million), to R$605 million in the year ended December 31, 2017, as a result of:  (i) an increase of 17.3% (or R$217 million) in income from electric energy service; offset by (ii) an increase of 2.9% (or R$16 million) in net financial expenses; and (iii) an increase of 1.3% (or R$4 million) in Income and Social Contribution Taxes expenses.

The increase in the segment’s net financial expenses was mainly due to:

· a decrease of 12.7% (or R$169 million) in financial expenses, mainly due to (i) a decrease of R$1,294 million in derivatives expenses; (ii) an increase of R$1,224 million in monetary and exchange rate variations; and (iii) a decrease of R$67 million in financial expenses from debt charges as a result of lower indebtedness;

· a decrease of R$184 million in financial income, mainly due to: (i) a decrease of 41.4% (or R$153 million) in income from financial investments; (ii) a decrease of 48.5% (or R$38 million) in monetary and exchange rate variations; and (iii) a decrease of 100% (or R$33 million) in income from the adjustment of Sector Financial Assets and Liabilities (see note 8 to our audited annual consolidated financial statements). These decreases were partly offset by:  (i) an increase of 10% (or R$24 million) in arrears of interest and fines; and (ii) an increase of 33% (or R$12 million) in income from interest of escrow deposits.

Generation (conventional sources)

Net income from our Generation from Conventional Sources segment increased by 29.0% (or R$147 million) to R$652 million during the year ended December 31, 2017 from R$505 million for the year ended December 31, 2016.  This increase is mainly due to: (i) the increase of 13.7% (or R$91 million) in income from electric energy service; and (ii) a decrease of 13.4% (or R$51 million) in net financial expenses.

The decrease in net financial expenses was due mainly to:  (i) a decrease of 72.3% (or R$49 million) in positive monetary and exchange variations, both classified in financial income; and (ii) a decrease of 24.2% (or R$25 million) in income from financial investments.  These decreases were partially offset by (i) a decrease of R$114 million in derivatives expenses; and (ii) a decrease of R$24 million in debt charges and negative monetary and exchange variations, driven by lower average interest rates.

Generation (renewable sources)

The net income from our Generation from Renewable Sources segment increased by 113.9% (or R$161 million) to R$20 million in the year ended December 31, 2017 compared to net loss of R$141 million in 2016, mainly due to the combined effect of:  (i) the increase of 37.4% (or R$165 million) in income from electric energy service, (ii) an increase of R$28 million in Income and Social Contribution Taxes expenses; and (iii) a decrease of 4.5% (or R$24 million) in net financial expenses .

The increase in net financial expenses was driven by a decrease of R$45 million in debt expenses and monetary and exchange rate variations, offset by an increase of R$25 million in capitalized borrowing costs, which is accounted for as a decrease in financial expenses.  

Commercialization

Compared to the year ended December 31, 2016, net income from our Commercialization segment decreased 19.6% (or R$22 million), to R$90 million in the year ended December 31, 2017, reflecting the combined effect of:  (i) a decrease of R$40 million in net financial income related to the impact for the entire year of debentures issued in late 2016 in connection with the acquisition of RGE Sul; (ii) an increase of 5.6% (or R$9 million) in the income from electric energy service; and (iii) a decrease of R$9 million in Income and Social Contribution Taxes expenses.

Services

Compared to the year ended December 31, 2016, net income from our Services segment increased 1.9% (or R$1 million), to R$55 million in the year ended December 31, 2017.  This relatively stable number reflects the combined effectof:  (i) an increase of 3.4% (or R$2 million) in the income from electric energy service and (ii) a slight decrease of R$1 million of net financial income.

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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 (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 the nine distribution subsidiaries we had at that time, 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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(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);

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 subsidiaries (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.

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 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

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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 the core activity of the asset.  This item was previously presented as part of Net financial expense.  Data for 2015 have been restated to reflect this reclassification.

Compared to the year ended December 31, 2015, our other gross operating revenues (which excludes 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 3.2 and 10 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 25.3 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 25.3 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.

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:

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(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 25.3 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 basis for calculation 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 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 for calculation for these taxes).

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 for calculation for these taxes).

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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 for 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 for 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:

(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 thereal against 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 offset by (i) an increase of R$52 million in Reserve Energy Charges; (ii) an increase of R$29 million in ConnectionCharges; 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). 

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Other costs and operating expenses

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

Compared to the year ended December 31, 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) a 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

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).

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Other costs and operating expenses.  Compared to the year ended December 31, 2015, our other costs and operating expenses for the Distribution segment increased16.1% (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 agreement negotiated in 2015 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.

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 (see note 27 to our audited annual consolidated financial statements); 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 in 2015; 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 thenet 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.

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Net Income

Net Financial Expense

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 audited annual consolidated 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.

Distribution

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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:  (i) 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 a 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 audited annual consolidated 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 12 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.

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.

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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 2016 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, 2017, our working capital was negative, reflecting an excess of current labilities over current assets of R$1,797 million, a decrease of R$4,158 million compared to a positive working capital balance of R$2,361 million at December 31, 2016, representing an excess of current assets over current liabilities. The main causes of this decrease in working capital were:

(i) a decrease of R$2,915 million in our cash and cash and equivalents, due to net cash generation of R$2,034 million in operating activities, offset by cash usage of R$2,440 million in financing activities and cash usage of R$2,509 million in investing activities;

(ii) an increase of R$1,870 million in our short‑term debt balance, which includes loans and financing, debentures and related accrued interest;

(iii) an increase of R$569 million in our Trade Payables balance;

(iv) an increase of R$216 million in our Regulatory Charges balance;

(v) an increase of R$154 million in our other current payables;

(vi) a decrease of R$427 million in net Sector Financial Assets and Liabilities balances, from a liability position of R$598 million in 2016 to an asset position of R$171 million in 2017;

(vii) an increase of R$65 million in dividends balance;

(viii) an increase of R$535 million in our Consumers Receivables balance;

(ix) an increase of R$277 million in derivative financial instruments, net;

(x) an increase of R$103 million in our Other Current Assets balance.

                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 audited annual consolidated financial statements.

Our net cash provided by operating activities was R$2,034 million in the year ended December 31, 2017, compared to R$4,634 million in the year ended December 31, 2016 (a decrease of R$2,600 million or 56.1%).  The decrease primarily reflects:

(i)	an increase of R$491 million in net income, adjusted for the reconciliation of net cash;
(ii)	net increase of R$4,244 million in operating assets (which represents a decrease in the cash provided by operating activities), primarily driven by Sector Financial Assets (R$2,919 million), accounts receivable from consumers (R$517 million) and escrow deposits (R$1,004 million), partly offset by a decrease of R$647 million in dividends and interest on capital received;

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(iii)	net increase of R$891 million in cash generation arising from increases in operating liabilities, primarily due to accounts payables (R$1,349 million) and regulatory charges (R$730 million), partly offset by a decrease of R$1,378 million in Sector Financial Liability; and
(iv)	a decrease of R$262 million in cash consumption in income tax and social contributions (R$538 million), offset by payments of interest (R$275 million).

Our net cash provided by operating activities was R$4,684 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$2,127 million or 83.1%).  The increase primarily reflects:

(i)	an increase of R$539 million in net income, adjusted for the reconciliation of net cash;
(ii)	net decrease of R$5,537 million in operating assets (which represents an increase in the cash provided by operating activities), primarily driven by Sector Financial Assets (R$3,353 million) and accounts receivable from consumers (R$849 million);
(iii)	a decrease of R$3,407 million in cash generation arising from increases in operating liabilities, primarily due to accounts payables (R$1,607 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 from financing activities recorded a consumption of cash of R$2,440 million in the year ended December 31, 2017 compared to generation of cash of R$337 million in the year ended December 31, 2016.  This increase of R$2,103 million was due to:

(i)	an increase of R$1,517 million related to payments of loans, financing, debentures and derivatives;
(ii)	an increase of R$105 million related to payment of dividends; and
(iii)	a decrease of R$376 million in fund-raising from borrowings and debentures.

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.

Indebtedness

The following table sets forth our current and noncurrent indebtedness (in millions) for the year ended December 31, 2017:

	2017
	Current	Noncurrent
Secured debt	927	4,676
Unsecured debt	4,424	10,142
Total	5,351	14,818

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Our total indebtedness decreased R$1,875 million, or 8.5%, from December 31, 2016 to December 31, 2017, as result of repayments of debt during the year in the aggregate amount of R$2,058 million; partly offset by an increase of R$177 million in new debentures issued and other debt incurred, mainly due to:

· Issuances of debentures in the amount of R$700 million by CPFL Paulista; R$380 million by RGE; R$530 million by CERAN; R$350 million by CPFL Renováveis; R$306 million by CPFL Piratininga and R$220 million by RGE Sul.

· Incurrence of new debt denominated in U.S. dollars, principally in the amount of R$400 million by CPFL Brasil; and R$169 million by RGE.  This debt was incurred in order to improve working capital, finance debt payments, refinance maturing debt and fulfill required investments.

In January 2018, we issued debentures totaling R$2,610 million through our subsidiaries CPFL Paulista (R$1,380 million), RGE Sul (R$ 300 million), RGE (R$ 220 million), CPFL Piratininga (R$ 215 million), CPFL Geração (R$ 190 million), CPFL Santa Cruz (R$ 190 million) and CPFL Brasil (R$ 115 million).

In 2018 and 2019, 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).

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, 2017 (including accrued interest) was R$20,169 million.  Approximately R$4,858 million of our total outstanding debt, or 24.1%, 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$5,351 million falls due in 2018.

Our major categories of indebtedness are as follows:

· BNDES.  At December 31, 2017, we had R$4,549 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 subsidiary CPFL Renováveis (R$3,543 million); (ii) financing of investment programs for our distribution subsidiaries, primarily CPFL Paulista, CPFL Piratininga, CPFL Santa Cruz, RGE Sul and RGE (R$944 million); and (iii) loans to our subsidiaries CPFL Serviços, CPFL Brasil, CPFL Eficiência, and CPFL Transmissão Piracicaba (R$62 million).

· Debentures.  At December 31, 2017, we had indebtedness of R$9,177 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 17 to our audited annual consolidated financial statements.

· Working capital.  At December 31, 2017, we had R$859million 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, 2017, we had R$757 million outstanding under a number of otherreal-denominated facilities.  Thesereal-denominated facilities relate to our renewable energy subsidiaries (R$682 million) and our distribution subsidiaries (R$75 million).  They are indexed based on the CDI or TJLP and bear interest at different rates.

· Other foreign currency-denominateddebt.  At December 31, 2017, we had the equivalent of R$4,858 million outstanding under other loans denominated in foreign currency, principally U.S. dollars (US$1,469 million).  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations. 

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For more details on our borrowings, debentures and derivatives please see notes 16, 17 and 33 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, 2017, with the exception of certain subsidiaries of CPFL Renováveis, as specified below:

· PCH Holding S.A. was not in compliance in this period with its debt coverage ratio, which requires cash generation of 1.2 times the debt service amount. PCH Holding S.A. obtained a formal waiver from the lender, BNDES, the non-declaration of early maturity of the debt;

· Turbina 16 Energia S.A. was not in compliance in this period with its debt coverage ratio, which requires cash generation of 1.3 times the debt service amount. Turbina 16Energia S.A. obtained a formal waiver from the lender, BNDES, the non-declaration of early maturity of the debt;

· SPE Bio Alvorada was not in compliance in this period with its debt coverage ratio, which requires cash generation of 1.2 times the debt service amount for the period, its net indebtedness to EBITDA ratio, and its own equity to own equity plus net indebtedness ratio. SPE Bio Alvorada obtained a formal waiver from the lender, BNDES, the non-declaration of early maturity of the debt;

· SPE Mata Velha S.A. was not in compliance in this period with its debt coverage ratio, which requires cash generation of 1.2 times the debt service amount for the period. SPE Mata Velha S.A. obtained a formal waiver from the lender, BNDES, the non-declaration of early maturity of the debt;

· Bio Coopcana S.A. was not in compliance in this period with its debt coverage ratio, which requires cash generation of 1.2 times the debt service amount for the period, its net indebtedness to EBITDA ratio, and its own equity to own equity plus net indebtedness ratio. Bio Coopcana obtained a formal waiver from the lender, BNDES, the non-declaration of early maturity of the debt.

Uses of funds

Our cash flow used for investing activities was R$2,509 million in the year ended December 31, 2017 compared with R$3,815 million in the year ended December 31, 2016.  This decrease of R$1,306 million (34.2%) primarily reflects:

(i)	a decrease of R$1,497 million related to the price paid in business combination net of cash acquired in 2016 (specifically, the acquisition of RGE Sul, after accounting for acquired cash) (see note 14.3 of our audited annual consolidated financial statements);
(ii)	a decrease of R$341 million in property, plant and equipment mainly due to investments in our renewable energy subsidiaries; and
(iii)	an increase of R$673 million in intangible assets primarily due to investments in our distribution activities.

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:

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(i)	net cash outflow (R$1,497 million) related to the acquisition of RGE Sul, after accounting for acquired cash (see note 14.3 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
(iii)	an increase of R$333 million in intangible assets primarily due to investments in our distribution activities.

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, 2017 we had outstanding debt maturing during the following 12 months in the total amount of R$5,351 million; and

· in 2017 (R$205 million in 2016).  See “Item 10.  Additional Information—Interest Attributable to Shareholders’ Equity” and the Unconsolidated Statement of Cash Flow in note 23,5 to our audited annual consolidated financial statements.in dividendsDividends on an annual basis.  We paid R$221 million

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 settle the debt due in advance or carry cash to improve our liquidity.  We continued to employ this strategy during 2017 in relation to debt due in 2018 and expect to continue to apply it in 2018 in relation to debt due in 2019. 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, 2017, 2016 and 2015:

	Year ended December 31,
	2017	2016	2015
	(in millions ofreais)
Distribution	1,883	1,201	868
Conventional Generation	9	8	7
Renewable Generation	621	979	494
Commercialization and other investments	58	51	59
Total	2,570	2,239	1,428

In addition to the capital expenditures shown above, we invested R$46 million in 2017 and R$51 million in 2016 related to the construction of CPFL Transmissão’s transmission lines, which, in accordance with the requirements of IFRIC 12, was recorded as a financial asset of concession in noncurrent assets.

We plan to make capital expenditures aggregating approximately R$2,139 million in 2018, R$2,108 million in 2019, R$2,217 million in 2020, R$2,117 million in 2021 and R$1,852 million in 2022.  Of total budgeted capital expenditures over this period, R$9,802million are expected to be invested in our Distribution segment, R$393 million in our Renewable Generation segment and R$62 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$175 million in our commercialization and services activities.  Part of these expenditures, particularly in generation projects, is already contractually committed.  See “—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments”.  Planned capital expenditures for development of our generation capacity, and the related financing arrangements, are discussed in more detail under “Item 4.  Information on the Company—Generation of Electricity”.

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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 Smart Grid Program – focused on smart metering for high and medium voltage consumers and on the excellence of workforce management by the use of smartphones and new software – has increased our operational efficiency.  We have already deployed 27,450 smart meters in the field, reaching the conclusion of the project implementation.  Currently, our five distribution companies are already operating under the new data dispatch system for emergency commercial services.  In 2017, we deployed the Distribution Automation project at the seven distribution companies that were located in São Paulo state during that time.In total, 81% of automatic circuit reclosers (ACR’s) in the distribution grid were included in the RF Mesh (Radio Frequency Mesh) network.

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, approved by shareholders in our Annual Shareholders’ Meeting, on April 29, 2016.

For the year ended December 31, 2016, our Board of Directors approved dividend distribution of R$214 million, equivalent to R$0.210194546per share, approved by shareholders in our Annual Shareholders’ Meeting, on April 28, 2017. 

For the year ended December 31, 2017, our Board of Directors approved dividend distribution of R$280 million, equivalent to R$0.275259517 per share, subject to the approval by shareholders in our Annual Shareholders’ Meeting, which is scheduled to take place on April 27, 2018.

	December 31, 2017
Profit for the year	1,179,750
Realization of comprehensive income	25,873
Prescribed dividends	3,768
Profit basis for allocation	1,209,391
Legal reserve	(58,988)
Statutory reserve - concession financial asset	(123,673)
Statutory reserve - working capital improvement	(746,541)
Mandatory dividend	(280,191)

See note 23.5 and 23.6 to our audited annual consolidated financial statements for additional information.

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2017 (including our noncurrent contractual obligations).   

	Payments due by period
	Total	Less than 1 year	1‑3 years	4‑5 years	After 5 years
	(in millions ofreais)
Contractual obligations as of December 31, 2017:
Suppliers	3,677	3,549	-	-	128
Debt obligations(1)	13,362	4,187	5,267	1,486	2,422
Public utilities(1)	258	20	42	47	149
Post-employment benefit (2)	1,557	131	303	313	811
Regulatory charges	582	582	-	-	-
Others	243	181	-	-	62
Total of Balance Sheet items(1)	19,679	8,650	5,612	1,846	3,572
Leasings and rentals	226	17	29	25	155
Electricity purchase agreements(3)	112,551	13,152	22,999	21,729	54,671
Distribution and transmission systems service charges(4)	32,970	2,614	5,759	5,699	17,998
Premium of Hydrological Risk renegotiation (GSF)(5)	364	27	13	47	276
Generation projects(6)	108	97	11	-	-
Supplies	1,591	102	238	245	1,006
Total of other commitments	147,810	16,009	29,049	28,646	74,106
Total of contractual obligations	167,489	24,659	34,661	30,492	77,678

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(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 2017 price.  See “—Background—Prices for Purchased Electricity” and note 34 to our audited annual consolidated financial statements.

(4)   Estimated expenses related to distribution and transmission system services charges through the end of the 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, 2017, 2016 and 2015 totaled R$176million, R$147 million and R$125 million, respectively.

Off‑Balance Sheet Arrangements

As of December 31, 2017, 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 2017 (in thousands ofreais)
Modality	Approval	Company	Debt	Released	Balance
BNDES / Investimento - FINEM XIX	In 2012	CPFL Renováveis	34,543	33,543	1,000(1)
BNDES / Investimento - FINEM XXI	In 2012	CPFL Renováveis	47,000	43,000	4,000(1)
BNDES / Investimento - FINAME I	In 2012	CPFL Renováveis	4,691	3,753	938
BNDES / Investiment - FINEM XVII	In 2012	CPFL Renováveis	555,127	553,070	2,057
BNDES / Investimento - FINEM XII	In 2013	CPFL Renováveis	391,245	357,146	34,099
BNDES / Investimento - FINEP III	In 2013	CPFL Renováveis	23,031	6,921	16,109
BNDES / Investimento - FINEM XIII	In 2013	CPFL Renováveis	383,748	379,948	3,800
BNDES / Investimento - FINEP II	In 2014	CPFL Renováveis	88,095	10,348	77,747
BNDES / Investimento – FINEM	In 2014	CPFL Telecom	95,333	34,918	60,415
BNDES / FINAME	In 2015	CPFL Serviços	6,011	5,144	867(1)
BNDES / Investimento - FINEM XXV	In 2015	CPFL Renováveis	84,338	82,799	1,539
BNDES / Investimento - FINEM XXVI	In 2015	CPFL Renováveis	764,109	636,400	127,709
BNDES / Investimento - FINEM XXVII	In 2015	CPFL Renováveis	69,491	69,327	164
BNDES / FINAME	In 2016	CPFL Serviços	12,277	11,886	391(1)
BNDES / FINAME	In 2017	CPFL Jaguari	6,556	-	6,556
BNDES / FINAME	In 2017	CPFL Serviços	11,286	-	11,286
BNDES / FINAME XXVII	In 2017	CPFL Renováveis	2,000	1,414	586

(1)   Outstanding balance was canceled.

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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 2.8% per year between 2009 and 2014, following a prior period of higher growth.  The years 2015 and 2016, however, were marked by strong economic contraction with significant political crises and uncertainties, and poor economic indicators.  These factors, combined with adjustments to government spending budgets, resulted in negative GDP growth of 3.5% in both 2016 and 2015, according to the Brazilian Central Bank.  However, in 2017, the Brazilian economy began to improve, showing recovery in principal areas of activity and financial indicators, with GDP growth of 1.0%, according to the Brazilian Central Bank. As a result, employment levels, household income and debt service costs – all of which are key drivers for energy consumption – began to improve in 2017.  For further information regarding this improvement, see “—Background—Brazilian Economic Conditions.”

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 2,103 MW (of which our share is 1,085 MW).

As of December 31, 2017, we had an Installed Capacity of 3,284 MW.  In 2020, we expect to reach an Installed Capacity of 3,299 MW, when the Boa Vista II SHPP will have begun operations.  We also have a 406 MW (of which our share is 209 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 toperiodically 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.  For the years 2015 and 2016, we have recognized a loss of R$39 million and R$48 million, respectively, in each case related to provisions for impairment of long-lived assets, and for the year 2017 we recognized R$20 million (see notes 13.1 and 14.2 to audited annual consolidated financial statements).

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Impairment of Financial Assets

A financial asset not measured at fair value through profit or loss is reassessed at each reporting date to determine whether there is objective evidence that it is impaired.  Impairment can occur after the initial recognition of the asset and have a negative effect on the estimated future cash flows.

The Company and its subsidiaries consider evidence of impairment of receivables and held‑to‑maturity investment securities for both specific asset and at a collective level for all significant securities.  Receivables and held‑to‑maturity investment securities that are not individually significant are collectively assessed for impairment by grouping together the securities with similar risk characteristics.

In assessing collective impairment the Company uses historical trends of the probability of default, timing of recoveries and the amount of loss incurred, adjusted for Management’s judgment as to whether the assumptions and current economic and credit conditions are such that the actual losses are likely to be higher or lower than suggested by historic trends.

An impairment loss of a financial asset is recognized as follows:

· Amortized cost:  as the difference between the carrying amount and the present value of the estimated future cash flows discounted at the asset’s original effective interest rate.  Losses are recognized in profit or loss and shown in an allowance account against receivables.  Interest on the impaired asset continues to be recognized through the unwinding of the discount.  When a subsequent event indicates that the amount of impairment loss has decreased, this reduction is reversed to credit through profit or loss.

· Available-for-sale:  as the difference between the acquisition cost, net of any principal repayment and amortization of the principal, and the current fair value, less any impairment loss previously recognized in profit or loss.  Losses are recognized in profit or loss.

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

Pension Liabilities

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

Deferred Tax Assets and Liabilities

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

We regularly review our deferred tax assets for recoverability.  If evidences are not enough to prove that it is more likely than not that we will not recover such deferred tax assets, then such asset is not registered in the balance sheet of thecompany.  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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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 B3 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 economic 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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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 five 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 office of director may be permanently vacated by resignation, dismissal, disability, loss of mandate, proven impediment, death or the occurrence of other situations referred to by law, in which case the alternate director, if one has been elected, shall take the place of the director until the election of his substitute, which shall take place at the first general shareholders’ meeting held after the vacancy occurred.

A director may resign by written communication to the chairman of the Board of Directors, which takes effect with regard to the Company, from the receipt of such communication, and with regard to third parties, from the filing of the resignation document with the Commercial Registry and its publication, to be effected by the resigning director.

                The Board of Directors shall decide, in a meeting to be held within fifteen days after notice of permanent vacancy has been given, on how the vacant board seat should be filled, which may involve retaining the alternate director in office until the election of a new director in a general shareholders’ meeting, or, otherwise by convening a shareholders’ meeting for the special purpose of electing a new director.

The Board of Directors shall meet at least 12 times a year and, whenever requested by the chairman in accordance with our bylaws and the Internal Rules of our Board of Directors.  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 must 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$11,913,000.00, 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. 

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Under Brazilian Corporate Law, combined with a decision by the CVM, non-controlling shareholders have the right to designate at least one member (and his/her respective alternate member) of our Board of Directors for election to the Board, provided that they hold at least 10.0% of the outstanding voting shares.  Non-controlling shareholders that own more than 5.0% of voting shares may request multiple voting (voto múltiplo), which confers upon each voting share a number of votes equal to the number of members of the Board of Directors and gives the shareholder the right to accumulate his or her votes in one sole candidate, or distribute them among several candidates.

Currently, our Board of Directors consists of seven members, of which two are independents (in accordance with the listing regulations of the New Market segment of the B3, or theNovo Mercado, and our bylaws).  Seven members of our current Board were elected at our annual general meeting of shareholders held on April 28, 2017.  Their terms are expected to expire at our next annual general meetings of shareholders, scheduled to take place on April 27, 2018.

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

Name	Age	Position
Yuhai Hu	54	Chairman
Daobiao Chen	49	Vice-chairman
Yang Qu	52	Member
Yumeng Zhao	44	Member
Andre Dorf	45	Member
Antonio Kandir	64	Independent Member
Marcelo Amaral Moraes	50	Independent Member

YuhaiHu - 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 and CEO of State Grid International Development Co., Ltd (or SGID, a wholly-owned subsidiary of SGCC and an indirect controlling shareholder of our company). Since 2017, he is also the Chairman of the Board of Directors of SGID.

Daobiao Chen – 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 President of the Economic Information Sector for Organization of Development and Global Cooperation of Energy Interconnection, and currently the Senior Vice President of State Grid International Development Co., Ltd.,an indirect controlling shareholder of our company.

YangQu – 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 2011, 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 GridBrazil Holding SA . Mr. Zhao was also elected Chief Executive Officer of State Grid Brazil Power Participações Ltda. (one of our shareholders) in 2016, and elected an officer of ESC Energia S.A. (one of our shareholders) in 2017.

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Yumeng Zhao– 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 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 Power Supply Company from 2004 to 2006.  He was also the manager of the Marketing Department of State Grid Anhui Electric Power Company in 2006, a deputy manager of Xuancheng Power Supply Company from 2006 to 2013, President of Chuzhou Electric Power Company from 2009 to 2013 and was general manager of Anqing Power Supply Company from 2013 to 2016.  From 2016 to 2017, he was the Assistant President of State Grid International Development Co., Ltd. On March 26, 2018, Mr. Zhao was also elected as an alternate member to our Human Resources Management Committee.

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), Chief 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 Cardsystem S.A., a technology services provider; (ii) Comiex Empreendimentos e Participações Ltda., an investment management company; (iii) GOL Linhas Aéreas Inteligentes, an aviation company; (iv) Vibra Agroindustrial S.A., a poultry company; and (v) AEGEA Saneamento e Participações S.A. a sanitation company.  and (v) Banco Ribeirão Preto, a financial institution.  Mr. Kandir also previously served on the boards of directors of the following companies: (i) Marisol S.A., a clothing company, from 2014 to 2017; (ii) Companhia Providência Indústria e Comércio, a nonwoven fabrics company; (iii) Amil Saúde, a healthcare insurance company;  and (iv) 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.

Marcelo Amaral Moraes – Mr. Moraes has been an independent director of CPFL Energia since 2017. He received a degree in economics from the Federal University of Rio de Janeiro (UFRJ) in 1990, completed an MBA from COPPEAD at UFRJ in November 1993, and received a post-graduate degree in Corporate Law and Arbitration from Fundação Getúlio Vargas in São Paulo in November 2003. He is currently the chairman of the fiscal council of Vale S.S. and has been a member of this fiscal council since 2004, where he also held the position of alternate member of the Board of Directors in 2003. Mr. Moraes also serves as the chairman of the fiscal council of Aceco TI S.A. He was also a member of the Board of Directors of Eternit SA. from 2016 to 2018. He also served as Executive Officer of Stratus Investimentos Ltda. 2006 to 2010, as an observing member of the Board of Directors of Infinity Bio-Energy S.A. from 2011 to 2012, and as Executive Officer of Capital Dynamics Investimentos Ltda. from 2012 to 2015. 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.

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 eight members that are appointed by our Board of Directors for a two‑year term, with the possibility of re‑election.  Our current board of executive officers has seven members as the position of Chief Business Development Officer is vacant.  Our executive officers were elected at the Board of Directors’ meetings held on May 8, 2017. 

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

Name	Age	Position
Andre Dorf	45	Chief Executive Officer
Yumeng Zhao	44	Deputy Chief Executive Officer
Gustavo Estrella	44	Chief Financial and Investor Relations Officer
Luis Henrique Ferreira Pinto	57	Chief Regulated Operations Officer
Karin Regina Luchesi	41	Chief Market Operations Officer
Wagner Luiz Schneider de Freitas	46	Chief Planning and Business Management Officer
(vacant)		Chief Planning and Business Development Officer
Gustavo Pinto Gachineiro	46	Chief Legal and Institutional Relations Officer

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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 was the CEO of CPFL Renováveis from 2013 to 2016 and has been the Chairman of the Board of Directors of CPFL Renováveis since 2016.  Since July 2016, Mr.  Dorf has been our Chief Executive Officer and since 2017, he has been a member of our Board of Directors.

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 Financial and Investor Relations Officer and Vice‑Chairman of the Board of Directors of CPFL Renováveis and a member of the Board of Directors of RGE, CPFL Paulista, CPFL Piratininga, CPFL Geração, Paulista Lajeado and Sul Geradora Participações S.A. Since 2013, he has been our Chief Financial and Investor Relations Officer.

Luis Henrique Ferreira Pinto– Mr. Ferreira Pinto graduated in Electrical and Electronic Engineering from the Engineering University of Barretos in 1985.  He obtained a graduate degree in 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 Business 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 2006.  He has also served as the Coordinator of the Technical Losses Group at the Brazilian Association of Electricity Distributors (ABRADEE) between 2005 and 2006, and was a professor of the Course on Technical Losses in the Energy Sector at the COGI Foundation between 2005 and 2006.  He has also served as the CEO of RGE between June 2011 and April 2013 and as the CEO of CPFL Paulista and CPFL Piratininga between 2013 and 2015.  Since 2015, he has been our Chief Regulated Operations Officer.

Karin Regina Luchesi – Ms. Luchesi graduated in Material Production Engineering from the Federal University of São Carlos in 2001 and obtained an Executive Master’s degree in Finance from Insper in 2010.  She began her career in the Electric Sector, at the Electric Power Trading Chamber - CCEE.  She has held several positions within our company since 2001, serving for seven years as Manager of the Department of Energy Purchase and Sale Contract Management.  In June 2011 she became Distribution Energy Sale Officer, while also acting as Energy Planning and Energy Management Officer from January to May 2014.  Since May, 2014, she has been the CEO of CPFL Generação, in addition to acting as an Officer at CPFL Transmissão, Paulista Lajeado and CPFL Jaguari de Geração and sitting on the Boards of Directors of CPFL Renováveis, CERAN, Chapecoense, Foz do Chapecó, ENERCAN, BAESA and EPASA.  Since 2015, she has been our Chief Market Operations Officer.

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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, a Master’s degree in Mechanical and Aeronautical Engineering, Industrial Management and Strategic Development from the Institute of Aeronautical Technology (ITA), in 2003, and an MBA with a specialization in Organizational Development and Leadership from the Positive University (Universidade Positivo) in 2017. 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. Since 2016, he has also served on the Board of Directors of Fundação Nacional de Qualidade. 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.

Yumeng Zhao– 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.

Gustavo Pinto Gachineiro – Mr. Gachineiro received a degree in law from the University of São Paulo (USP) in 1993 and an MBA from Fundação Getúlio Vargas in 2007.  He was elected Legal and Corporate Relations Vice President of CPFL Energia in 2017.  He previously held positions at Global Village Telecom (GVT), where he worked as Chief Legal Officer from 2003 to 2008, interim Vice President for Legal and HR from 2008 to 2012, and Vice President for Legal and Institutional Relations from 2012 to 2015. Following the acquisition of GVT by the Telefonica Group, he served as Legal and Corporate Relations Vice President at Telefônica Brasil S/A (Vivo) from 2015 to 2017.  Prior to his positions at GVT and Vivo, he served as Chief Legal Officer at Elucid (Grupo Rede) in 2003, Chief Legal Officer at AT&T Brazil from 1999 to 2003, and as Legal Manager at Stiefel Laboratories in 1999.  He also served as in-house counsel at Promon Eletrônica from 1997 to 1999 and at Bardella S/A Indústrias Mecânicas from 1995 to 1997. Mr. Gachineiro is also an alternate member of the Board of Directors of CPFL Renováveis. 

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 is composed of three 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 an aggregate of 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 (up to the third degree) of any member of our Management or Board of Directors.  Our fiscal council, elected at our shareholders’ meeting held on April 28, 2017 with a mandate lasting until our next shareholders’ meeting, set to take place on April 27, 2018, is composed of three members:  Yuehui Pan, Ran Zhang and Ricardo Florence dos Santos.

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).

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Advisory Committees

Our bylaws allow our Board of Directors to establish committees andad hoc commissions 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; (iv) managing the delegation of Sarbanes Oxley and Audit Committee activities to the Fiscal Council; and (v) forwarding to the Board of Directors proposals for improvements in business management processes, as needed.  The members of this committee are Yunwei Liu, Zhangyan Fu and Gustavo Henrique de Aguiar Sablewski.

Human Resources Management Committee.  Our Human Resources Management Committee is responsible for assisting the Board of Directors by:  (i) coordinating the CEO selection process; (ii) defining criteria for compensation of our Board of Directors, executive officers and Fiscal Council; (iii) aligning our strategy for directly- and indirectly-controlled companies as well as companies with shared control, including contracting instruments and short- and long-term incentive plans; and (iv) managing our organizational structure, sucession plan and related assessments.  The members of this committee are Daobiao Chen, Li Zhang and Rodrigo Agnew Ronzella.

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; (ii) evaluating energy purchase or sale agreements with related parties ensuring these transactions are conducted fairly and consistent with market practice; and (iii) issuing our list of related parties. The members of this committee are Hongwu Ding, Fu Li and Marcelo Amaral Moraes.

In addition to the advisory committees, our Board of Directors may createad hoc commissions, if deemed necessary.  The main responsibilities of anad hoc commission include evaluating and addressing specific matters that may arise.  In 2016, our Board of Directors set up twoad hoc commissions: the Strategy Commission and the Finance and Budget Commission. Thesead hoc commissions remained in place throughout 2017.

Compensation

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

Pursuant to Article 17 of our bylaws, the Board of Directors is responsible for establishing the individual monthly compensation due to the executive officers, with due observance to the aggregate amount approved by the shareholders.

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

The table below shows the aggregate compensation paid directly by CPFL Energia to the members of our Board of Directors and Fiscal Council and our executive officers for 2017:

	Compensation for the year ended December 31, 2017
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	7 members(1)	3 members(1)	7 members(1)
Fixed annual compensation:	(in thousands ofreais)
Salary	644	220	6,874	7,738
Direct or indirect benefits	-	-	271	271
Other	128	44	5,017	5,189
Variable compensation:
Bonus	-	-	11,374	11,374
Other	-	-	3,239	3,239
Post‑employment benefits	-	-	546	546
Total compensation	772	264	27,321	28,357

(1)Represents the weighted average number of members.

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 The table below sets forth the compensation paid by our subsidiaries to our management for 2017:

	Year ended December 31, 2017
	Board of Directors	Fiscal Council	Executive Officers
	Fixed	Fixed	Total (fixed and variable)
	(in thousands ofreais)
Subsidiaries(1)	-	-	9,228

(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 2018 (excluding any compensation to be paid by our subsidiaries to such individuals):

	Approved compensation for the year ending December 31, 2018(1)
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	7 members(2)	5 members(2)	9 members(2)
Fixed annual compensation:	(in thousands ofreais)
Salary	517	270	10,556	11,343
Direct or indirect benefits	-	-	616	616
Other	103	54	2,956	3,113
Variable compensation:
Bonus	-	-	10,794	10,794
Other	-	-	7,107	7,107
Post‑employment benefits	-	-	924	924
Total compensation	620	324	32,953	33,897

⁽¹⁾Represents the expected compensation for a twelve-month period (from May 2018 to April 2019), to be approved in the Annual Shareholders’ Meeting of CPFL Energia, which is scheduled to take place on April 27, 2018.

⁽²⁾Represents the weighted average number of members.

In addition, the 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$73.7 million for 2017, including R$7.6 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$1.5 million.

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

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

	Board of Directors	Fiscal Council	Executive Officers*
Fixed compensation:	100%	100%	43.5%
Benefits:	-	-	3.0%
Variable compensation:
Short‑term incentives	-	-	41.6%
Long‑term incentives	-	-	11.9%
Total	100%	100%	100%

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

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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 we aim 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.

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 2017, 183,416 phantom stocks were granted, considering the valuation of the CPFL Energia, divided by the number of shares available in the market.

In addition, in January 2017, we established a new long-term incentive plan, known as the “Incentivo.” TheIncentivo establishes certain targets for receiving bonus payments.  These targets and the related bonuses are connected to the Eligible Professional’s position. TheIncentivo also aims to incentivize and retain employees who provide the greatestvalue through their individual performance. The bonus payments under theIncentivo are subject to an adjustment factor based on the average performance of our company during the three year vesting period, which can reduce the Eligible Professional’s bonus by up to 50% or increase the Eligible Professional’s bonus by up to 200%. Under the adjustment factor, our average performance is measured by the EBITDA and net income targets established at the time of the Eligible Professional’sIncentivo.

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As of December 31, 2017, the total expense amount accrued by us related to the long-term incentive plan was R$16,272.8 million, of which R$10,315.6 million related to the ILP and the remainder of R$5,957.2 million related to theIncentivo plan was R$ 5,957.2 million.

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, 2017:         

	Pension Plans for Executive Officers
Name of pension plan	PGBL Bradesco	PGBL Brasil Prev
Number of Executive Officer members	4	2
Number of Executive Officer members eligible for retirement	4	2
Early retirement provisions	None	None
Inflation-adjusted value of pension plan contributions held at year-end, excluding contributions made directly by beneficiaries (in thousands ofreais)	633	274
Amount of pension plan contributions made during the year, excluding contributions made directly by beneficiaries (in thousands ofreais)*	280	109
Provisions 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, 2018 was 189. 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, 2017, we had 13,344 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,
	2017	2016	2015
Distribution	7,758	7,985	5,248
Conventional Generation	92	95	106
Renewable Generation	475	430	391
Commercialization	48	48	48
Services	3,431	3,102	2,554
Corporate staff	1,540	1,557	1,543
Total	13,344	13,217	9,890

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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 2017, we reserved R$96.8 million (R$80.5 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.

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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 March 31, 2018, reflecting the consummation of the acquisition of control of our company by State Grid.  Percentages in the following table are based on 1,017,914,746 outstanding common shares.

	Common Shares	(%)
State Grid Brazil Power Participações S.A. (1)	964,521,902	94.75
Executive officers and directors as a group	189	0.00
Total	964,522,091	94.75

(1) State Grid Brazil Power Participações S.A., or State Grid, is our controlling shareholder.  It holds 730,435,698 shares directly (or 71.75%) and 234,086,204 shares indirectly (or 23.00%) through its wholly-owned subsidiary ESC Energia S.A.  State Grid Brazil Power Participações S.A.  is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.

State Grid acquired control of our company on January 23,2017.  In November 2017, State Grid launched a mandatory tender offer for our shares.  Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to approximately 94.75% of our total share capital.  State Grid has announced that it intends to (i) cancel our registration as a Class A publicly-held company with the CVM; (ii) delist our company from theNovo Mercado section of the B3; (iii) delist our ADSs from the NYSE, and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the SEC.

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

Our related party transactions are described in note 30 to our audited annual consolidated financial statements.

ITEM 8.Financial Information

Consolidated Statements and Other Financial Information

See Item 18.  Financial Statements.

Legal Proceedings

CPFL Paulista and CPFL Piratininga are defendants in numerous proceedings commenced by industrial consumers alleging that certain tariff increases that occurred in the past were illegal.  The plaintiffs allege that electricity tariffs were among items subject to a price freeze under financial regulations that were in force at the time.  The total amount claimed under these proceedings was approximately R$155.2 million as of December 31, 2017.  This amount consists of R$33.8 million where we have classified the likelihood of loss as probable; R$86.8million where we have classified the likelihood of loss as possible; and R$34.8 million where we have classified the likelihood of loss as remote.  A significant number of these proceedings have been decided against us or our subsidiaries, as applicable. We have made accounting provisions of R$33.8 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 Piritininga to pay a debt owed by the pension fund.  In late 2016, the administrative court rejected CPFL Piratininga’s defense and issued an infraction notice.  CPFL Piratininga has appealed against the infraction notice, for which a judgment is pending. In January2018, CPFL Piratininga obtained an order at first instance for reconsideration of aspects of the administrative proceeding, although this order may be subject to appeal.  The amount claimed in these Fundação CESP proceedings totaled approximately R$223.8 million as of December 31, 2017.  We believe that the likelihood of loss is possible. 

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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 the court of R$360 million in 2007 and R$54 million in 2011 in order to prevent any attachment of assets by the tax authority and enable CPFL Paulista to appeal the claim.  By year-end 2015, these payments as adjusted for inflation amounted to R$746 million.  In January 2016, CPFL Paulista obtained court decisions that authorized CPFL Paulista to replace these escrow deposits with financial guarantees (letter of guarantee and performance bond), following which CPFL Paulista was able to withdraw the deposits in 2016.  In February 2017, following a decision on appeal, CPFL Paulista paid into court a new escrow deposit in the amount of R$206.8 million (adjusted to R$224.6 million as of December 31, 2017 to account for inflation), related to the interest accrued on the original escrow deposits. This tax claim has also resulted in other execution proceedings, which together total R$1.2 billion, which remain subject to decisions by 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 the court of second instance ruled in favor of CPFL Paulista, returning the lawsuit to the original court. The case is currently awaiting the start of an additional investigation by a court appointed expert. 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$1,902 million as of December 31, 2017 on the basis that the Brazilian environmental agency prevented them from felling their trees before the area was flooded as part of the construction of the hydroelectric facility, and therefore that the Serra da Mesa joint venture expropriated the timber.  The claim is awaiting trial at the court of first instance.  CPFL Geração has argued that the claim is groundless, and that any potential claim should be made solely against Furnas, as sole holder of the concession operated by the joint venture.  We therefore believe that the likelihood of loss is remote. 

CPFL Geração is subject to a tax claim in the amount of approximately R$351 million as of December 31, 2017 regarding an interpretation of the basis for 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 filed a petition to cancel an infraction notice in the amount of approximately R$538 million as of December 31, 2017 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 four separate  admistrative proceedings.  In 2016, RGE filed a claim to suspend all four of these administrative proceedings until the decision on the underlying tax claim is issued, as the result of this claim indirectly affects the other proceedings, despite the fact that they relate to different periods.  The likelihood of loss in these proceedings is possible and the potential losses amount to R$145 million as of December 2017. 

CPFL Santa Cruz (four proceedings), CPFL Geração (four proceedings) and RGE (two proceedings) are also subject to tax claims in the amounts of R$121 million, R$385 million and R$384 million, respectively, as of December 31, 2017, 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 in all of the proceedings is possible. 

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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.  Following a successful partial decision in favor of CPFL Paulista in 2017, the amount claimed totaled approximately R$334 million as of December 31, 2017.  In February 2018, the city of Ribeirão Preto withdrew one of its claims in the amount of R$164 million.

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 a transaction in which Sul Geradora Participações S.A. was prepaid for energy exports.  The Brazilian tax authority claims that Sul Geradora Participações S.A. used resources obtained through this transaction to acquire credits against companies in its own corporate group rather than to finance its exports.  Following rejection of our original defense against these allegations, we filed a voluntary appeal, which was allowed to proceed and was granted in full, revoking the penalty. However, the National Treasury then filed a special appeal, which reverted the previous decision, thus reinstating the infraction notice. We then filed an ordinary judicial action to revoke the infraction notice and we are currently awaiting trial.  During 2017, the Brazilian Federal Revenue Authority withdrew certain of its claims, following which the amount claimed totaled approximately R$92 million as of December 31, 2017.  We believe the likelihood of loss is possible. 

CPFL Piratininga has commenced proceedings against the Brazilian Federal Revenue Authority 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. CPFL Piratininga then applied for a special and extraordinary appeal, both of which were denied in December 2017. As a result of these denials, the original decision is now final and enforceable, although we have not yet received official notice of this decision. We have deposited the full amount  into judicial escrow and will now begin the process to calculate the exact amount payable, which we believe amounts to R$152 million as of December 31, 2017. 

In December 2016, the Brazilian Federal Revenue Authority imposed an infraction notice and a fine on CPFL Geração charging IRPJ and CSLL taxes, alleging that CPFL Geração made capital gains and applied an incorrect tax basis on the incorporation of SMITA Empreendimentos e Participações S.A. into ERSA Energias Renováveis S.A., which resulted in the creation of CPFL Renováveis in 2011. CPFL Geração filed an objection motion in January 2017. The court overruled this objection and upheld the infraction notice. CPFL Geração then filed a voluntary appeal in September 2017, which is currently awaiting judgment. We believe the likelihood of a loss is possible and the amount involved is R$350 million as of December 31, 2017.

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$5.6 million and possible up to R$97.5 million in December 2017.

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 because the lawsuit remains in the initial stages and the extent of any losses will depend on an environmental report, which has not yet been performed.

RGE is a defendant in a Public Civil Action that challenged RGE’s practice of subcontracting maintenance services on electric energy networks.  On February 2, 2017 the court ruled that RGE must refrain from outsourcing activities related to its core business, but rejected the public prosecutor’s class action claim. We believe the likelihood of loss is possible, in the amount of R$200.9 million as of December 31, 2017.  In March 2018, the court issued a decision on appeals filed by both parties, although the proceedings remain subject to ongoing appeal.  A new Labor Reform law promulgated on November 11, 2017 now permits the outsourcing activities that gave rise to the initial claim. We still believe the likelihood of loss  is possible.

We establish balance sheet provisions relating to potential losses from litigation based on estimates of such losses.  For this purpose, we classify these losses as remote, possible or probable.  IFRS practices require us to establish provisions in connection with probable losses, and it is therefore our policy to establish provisions in connection with those claims only.  As of December 31, 2017, our provisions for contingencies were approximately R$961 million, reflecting our ongoing contingency monitoring and risk control.  Our Management believes that none of these proceedings, eitherindividually or in the aggregate, will have a material adverse effect on our financial condition.  See note 21 to our audited annual consolidated financial statements for more information on the status of our litigation.

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In addition to the above, an alternate member to our fiscal council, Reginaldo Ferreira Alexandre, is involved in a proceeding with the CVM involving members of the executive board, board of directors and supervisory board of Petróleo Brasileiro S.A., or Petrobras. This proceeding relates to irregularities and inconsistencies in the preparation of certain impairment tests reflected in Petrobras’ financial statements for 2010 through 2014. Petrobras established a supervisory board in 2013. In addition, Petrobras’ supervisory board issued an opinion against the approval of the 2014 financial statements, citing the possibility of these irregularities and inconsistencies. However, the CVM has stated that a similar negative opinion should have also been provided with respect to the 2013 financial statements. As such, with respect to the supervisory board, the proceeding only relates to the 2013 financial statements.

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 B3, 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, 2017, the ADSs represented 1.6% of our shares and 29.9% of our current global public float.

State Grid acquired control of our company on January 23,2017.  In November 2017, State Grid launched a mandatory tender offer for our shares.  Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to approximately 94.75% of our total share capital.  State Grid has announced that it intends to (i) cancel our registration as a Class A publicly-held company with the CVM; (ii) delist our company from theNovo Mercado section of the B3; (iii) delist our ADSs from the NYSE, and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the SEC.

Price Information

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

	Reaisper Common share		U.S. dollars per ADS
	High	Low	High	Low
2012	29.30	21.28	32.94	20.75
2013	23.57	18.39	22.78	15.49
2014	22.74	15.42	20.19	12.56
2015	21.20	14.17	14.40	6.95
2016	25.21	13.87	15.55	6.75
2017	27.62	17.98	17.58	10.65
2016
First Quarter	20.30	13.87	11.10	6.75
Second Quarter	20.81	18.15	12.86	10.06
Third Quarter	24.32	20.56	15.16	12.80
Fourth Quarter	25.21	23.60	15.55	13.70
2017
First Quarter	25.87	25.17	16.67	15.49
Second Quarter	26.51	25.72	16.84	15.32
Third Quarter	27.24	26.42	17.58	15.98
Fourth Quarter	27.62	17.98	17.58	10.65
2018
January	21.45	18.74	13.41	11.52
February	24.25	21.50	14.95	12.82
March	24.91	23.76	15.00	14.30
April (up to April 18)	24.68	24.27	14.80	14.17

(*)   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.

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Corporate Governance Practices

In 2000, the B3 (at that time known as 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 B3, 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 B3 to list our securities on theNovo Mercado. 

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

1.	Transparency/Disclosure – the desire to provide stakeholders with information that is of interest to rather than simply that required by law or regulation.
2.	Impartiality/Fairness – fair and equal treatment of all shareholders and other stakeholders, taking into consideration their rights, duties, needs, interests and expectations.
3.	Accountability – provision of information by our management in a clear, concise, understandable and timely manner, assuming the consequences of their acts and omissions in full, and performing their roles diligently and responsibly.
4.	Corporate responsibility/Compliance – complete focus on economic and financial viability of our company, the reduction of negative externalities impacting our businesses and operations and the increase in positive externalities, while taking into account the various types of capital (financial, manufactured, intellectual, human, social, environmental, reputational, etc.) in the short-, medium- and long-term.

We implemented this model in 2003 and redesigned it in 2017 in order to adjust our corporate governance structure to the current making‑business scenario and decision‑making process, as well as to consider our new corporate structure.  In December 2017, our Board of Directors approved the revision of our Corporate Governance Guidelines as related to their application to our controlled and affiliated companies.  In addition, in 2012, 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.

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 hoc commissions 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 B3, and it was approved during the second half of 2010 to provide for a further enhancement of the special corporate governance and disclosure rules.  The revised rules entered in force and effect on May 10, 2011, including those related to theNovo Mercado segment.  The main changes to the rules in the segment that we are listed include, among others:  (i) prohibition to include dispositions that restrict or create obligations to the shareholders which vote favorably to a suppression or amendment of dispositions of the bylaws; (ii) prohibition of the same individual to hold the positions of chairman of the board of directors and chief executive officer (or equivalent position as the main executive of the company); and (iii) obligation of the board of directors to issue a justified opinion on any tender offers for the acquisition of the shares representative of the corporate capital of the company.  On December 19, 2011, we amended our bylaws to incorporate these rules, among other changes.  In 2013 we amended our bylaws to include the creation of a “Reserve for Adjustment of the Concession Financial Assets”, with subsequent amendment to items “a” and “c” and addition of items “d” and “e” of paragraph 2, Article 27.  In 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.

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In 2017, an additional revision of the rules applicable to companies listed inNovo Mercado was discussed and approved.  The revised rules, which became effective on January 2, 2018, include, among others: (i) the board of directors must have at least two independent directors or 20% of the board of directors as independent, whichever is greater; (ii) required preparation and disclosure of: (a) compensation policy; (b) policy for the appointment of members of the board of directors, its advisory committees and the statutory executive officers; (c) risk management policy; (d) related party transactions policy; and (e) securities trading policy; (iii) material facts (fatos relevantes), information on benefits and communication of results in the form of press releases should be published simultaneously in Portuguese and English, except in the event of disclosure of a material fact as a result of information leakage or atypical movements in trading price; and (iv) required preparation and approval by the board of directors of a code of conduct.

On June 8, 2017, the CVM altered the rules applicable to publicly held companies. These revisions created an obligation for companies to annually inform the CVM of their corporate governance practices, as recomended by the Brazilian Corporate Governace Code – Publicy Held Companies (Código Brasileiro de Governança Corporativa – Companhias Abertas). The Brazilian Corporate Governace Code – Publicy Held Companies is divided in different principles, which are considered the essential values of corporate governance, and adopts a system of “comply or explain”. Therefore, companies have to evaluate their practices and principles based on the Brazilian Corporate Governace Code – Publicy Held Companies and disclose whether they comply with the recommendation or to explain the reasons why they did not adopt such principle.

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.

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.

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Under our bylaws, at least 25.0% of our adjusted net income, as calculated under Brazilian Accounting Principles and adjusted under Brazilian Corporate Law, for the preceding fiscal year must be distributed as a mandatory annual dividend.  Adjusted net income means the distributable amount after any deductions for statutory reserves and reserves for investment projects.

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

Brazilian Corporate Law permits the suspension of the mandatory distribution of dividends in any fiscal year in which the Management bodies report to the shareholders’ meeting that the distribution would be inadvisable in view of the company’s financial condition.  The suspension is subject to approval by the shareholders meeting and review by members of the fiscal council, if it has been installed.  The law does not establish the circumstances in which payment of the mandatory dividend would be “inadvisable” based on the company’s financial condition.  In the case of publicly‑held corporations, the board of directors must file a justification for such suspension with the CVM within five days of the relevant general meeting.  If the mandatory distribution is not paid, the unpaid amount must be attributed to a special reserve account.  If not absorbed by subsequent losses, those funds must be paid out as dividends as soon as the financial condition of the company permits.  Under Brazilian Corporate Law, the shareholders of a publicly‑held company may also, through a unanimous decision in a General Shareholders’ Meeting, decide to distribute dividends in an amount lower than the mandatory distribution or retain the net profit exclusively for purposes of fundraising by means of non-convertible debentures.

Payment of Dividends

We are required by Brazilian Corporate Law to hold an annual general shareholders’ meeting by no later than April 30 of each year, at which the shareholders have to decide, among other matters, on the payment of an annual dividend.  Additionally, interim dividends may be declared by our Board of Directors.  Any interim dividend paid may be set off against the amount of the mandatory dividend payable for the fiscal year in which the interim dividend was paid.

Pursuant to our charter, we are required to pay a mandatory annual dividend of at least 25.0% of our adjusted net income.  Any holder of record of shares at the time of a dividend declaration is entitled to receive dividends.  Dividends on shares held through a depositary are paid to the depositary for further distribution to the shareholders.  Under Brazilian Corporate Law, dividends are generally required to be paid to the holder of record on a dividend declaration date within 60 days following the date the dividend was declared, unless a shareholders’ resolution sets forth another date of payment, which, in either case, must occur prior to the end of the fiscal year in which such dividend was declared.  Pursuant to our bylaws, declared unclaimed dividends do not bear interest, are not monetarily adjusted and revert to us if unclaimed within three years after the date when we begin to pay such declared dividends. 

In general, shareholders who are not residents of Brazil must register their equity investment with the 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 depositaryregisters 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.

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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:

· 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 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 efficiencycampaigns and extraordinary tariff increases, our Board of Directors also approved the allocation of R$393 million to the statutory reserve – working capital improvement account.

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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 25.0% of our adjusted net income, in annual installments.  The amount of any of our distributions of dividends and/or interest attributed to shareholders’ equity will depend on a series of factors, such as our financial conditions, prospects, macroeconomic conditions, tariff adjustments, regulatory changes, growth strategies and other matters our Board of Directors and our shareholders may consider relevant.  In addition, covenants contained in our debt instruments may limit the amount of dividends and/or interest attributable to shareholders’ equity that we may make.  Within the context of our tax planning, we may in the future determine that it is to our benefit to distribute interest attributable to shareholders’ equity in lieu of dividends.

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

Shareholder Meetings

Actions to be taken at our shareholders’ meetings

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

A special shareholders’ meeting may be held concurrently with the annual shareholders’ meeting.  The following actions, among others provided under Brazilian Corporate Law and/or our bylaws, may only be taken at a special shareholders’ meeting:

· the cancellation of the 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;

· the delisting of our shares from the Novo Mercado of the B3;

· the appointment of a specialized firm to determine the economic value of the Company’s shares, in the event of a public offering as contemplated under Chapters VIII and IX of the Bylaws, based on a list of three selected firms provided by the Board of Directors;

· approval of our participation in a group of companies (grupo de sociedades, as defined in Brazilian Corporate Law);

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· 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);

· the plans for the granting of stock options to members of management and employees of the Company and companies directly or indirectly controlled by the Company, without the preemptive rights by the shareholders; and

· amendment of our bylaws.

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

· the right to participate in the distribution of profits;

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

· the right to inspect and monitor our management, in accordance with the Brazilian Corporation Law;

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

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

Quorum

As a general rule, Brazilian Corporate Law provides that a quorum for purposes of holding a shareholders’ meeting shall consist of shareholders representing at least 25.0% of a company’s issued and outstanding voting capital on the first call and, if that quorum is not reached, any percentage on the second call.  There are certain exceptions to the general rule, as in the case of a shareholders’ meeting with the purposes of (i) amending our bylaws, which shall only be held with the presence of shareholders representing at least two‑thirds of our issued and outstanding voting capital on the first call and any percentage on the second call; and (ii) appointing a financial institution responsible for our valuation, in the event of cancellation of our registration with the CVM as a publicly‑held company, which shall only be held with the presence of shareholders representing at least 20.0% of our issued and outstanding voting capital on the first call and any percentage on the second call.

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;

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

·apply for cancellation of any voluntary liquidation; and

·approve our dissolution.

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

Notice of our Shareholders’ Meetings

Notice of our shareholders’ meetings must be published at least three times in theDiário Oficial do Estado de São Paulo, the official newspaper of the state of São Paulo, and in the newspaperValor Econômico.  The first notice must be published no later than 15 days before the date of the meeting on the first call, and no later than eight days before the date of the meeting on the second call.  However, in certain circumstances, the CVM may require that the first notice be published 30 days in advance of the meeting.  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, as amended, or CVM Rule No.  481, requires that additional information is disclosed in the meeting call notice for certain matters.  For example, in the event of an election of directors, the meeting call notice shall disclose, among other information, the minimum percentage of equity interest required from a shareholder to request the adoption of multiple voting procedures, as well as the relevant ballot paper for casting votes remotely.

Documents and Information

The specific documents and information requested for the exercise of the voting rights of our shareholders shall be made available by electronic means at the CVM and the U.S. Securities and Exchange Commission websites, as well as at our investor relations website.  The following matters, without prejudice to others provided under Brazilian Corporate Law, require specific documents and information:

·matters with interest of related parties;

·ordinary Shareholders’ Meeting;

·election of members of the Board of Directors;

·compensation of the Management of the Company;

·amendment to the Company’s bylaws;

·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 the CVM in a certain category (category A).

Location of our Shareholders’ Meetings

In 2017, our shareholders’ meetings took place at our head offices in the city of São Paulo, state of São Paulo. Beginning in 2018, the meetings will take place in the company’s new headquarters, in the city of Campinas, state of São Paulo. Brazilian Corporate Law allows our shareholders to hold meetings outside our head offices in the event of forcemajeure, provided that the meetings are held in the City of Campinas and the relevant notice contains a clear indication of the place where the meeting will occur.

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Who May Call our Shareholders’ Meetings

Subject to the provisions of the Brazilian Corporate Law and our bylaws, our Board of Directors may ordinarily call ou shareholders’ meetings.  These meetings may also be called by:

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

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

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

Conditions of Admission

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

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

CVM Rule No.  481 also established the right of shareholders to request the inclusion of candidates and proposals in the ballot, to the extent that the terms provided for in CVM Rule No. 481 are observed.  The inclusion of proposals in the ballot must be requested up to 45 days before the annual general meeting. In relation to the inclusion of candidates in the annual general meeting or in the extraordinary general meeting, in both cases the request must be made up to 25 days before the date of such meeting.  If the inclusion of a candidate is requested properly, we must present a new version of the ballot at least 20 days before the date of the referred meeting, in order for the shareholders to decide whether they want to change their votes or not. If the shareholders do not provide new voting instructions, the previous one will be considered.  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.

Another obligation of CVM Rule No. 481 is the disclosure of the voting statement, containing the first five numbers of each shareholder CPF or CNPJ and their votes for each subject discussed in the general meeting, such disclosure must be made by the Company within seven business days after the meeting.

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

Voting Rights of ADS Holders

According to CVM Rule nº 559/2015, whenever the contracts related to the ADSs program allow, the ADS holders may instruct the depositary to vote the number of common shares that their ADSs represent, otherwise the depositary shall exercise the voting rights related to such shares in the best interest of the ADS holders.  The depositary will notify those holders of shareholders’ meetings and arrange to deliver our voting materials to them upon our request.  Those materials will describe the matters to be voted on and explain how the ADS holders may instruct the depositary how to vote.  For instructions to be valid, they must reach the depositary by a date set by the depositary.

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

Preemptive Rights

Our shareholders have a general preemptive right to subscribe for shares in any capital increase according to the proportion of their shareholdings.  Pursuant to Brazilian Corporate Law, our shareholders also have a general preemptive right to subscribe for any convertible debentures and subscription warrants that we may issue.  A period of at least 30 days following the publication of notice of the capital increase is allowed for the exercise of the preemptive right.  Pursuant to Brazilian Corporate Law, holders are permitted to transfer or dispose of their preemptive right for consideration.

Pursuant to Brazilian Corporate Law and our bylaws, our Board of Directors may decide to increase our share capital within the limit of the authorized capital.  Whenever such increase is made through a stock exchange, through a public offering or through an exchange of shares in a public which purpose is to acquire control of another company, the Board of Directors is entitled to exclude the preemptive rights or reduce the exercise period of such rights.

Withdrawal Rights

Brazilian Corporate Law grants our shareholders the right to withdraw from the Company in case they disagree with decisions taken in shareholder’s meetings concerning the following matters:  (i) the reduction of minimum mandatory dividends; (ii) the merger of the Company or consolidation with another company; (iii) the change of the corporate purpose of the Company; (iv) a spinoff of the Company (if such spin‑off changes the Company’s corporate purpose, reduces mandatory dividends or results in the company joining a group of entities); (v) the acquisition by us of the control of another company for a price that exceeds the limits established in paragraph two of Article 256 of Brazilian Corporate Law; (vi) a change in our corporate form; (vii) approval of our participation in a group of companies (as defined in Brazilian Corporate Law); (viii) if the company resulting from a merger, spin-off or consolidation with another company, which is a successor of a public-held company, does not register itself with the CVM as a publicly‑held company, within the deadlines provided under Brazilian Corporate Law; or (ix) stock swap merger of the Company with another company, so that the Company becomes a wholly-owned subsidiary of that company.  Even shareholders who did not vote or were not present at the relevant meeting may exercise this withdrawal right, 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.

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Material Contracts

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

Exchange Controls and Other Limitations Affecting Security Holders

There are no restrictions on ownership of our capital stock by individuals or legal entities domiciled outside Brazil.  However, the right to convert dividend payments and proceeds from the sale of common shares into foreign currency and to remit such amounts outside Brazil is subject to restrictions under foreign investment legislation which generally requires, among other things, that the relevant investment be registered with the 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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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 the 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 the 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.

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.

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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.

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 Brazlian 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.

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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.

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 determinethat 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%.

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Tax on foreign exchange transactions

Pursuant to Decree No.  6,306/07, the conversion into foreign currency or the conversion into Brazilian currency of the proceeds received or remitted by a Brazilian entity from a foreign investment in the Brazilian securities market, including those in connection with the investment by a non-Brazilian holder in the shares and ADSs may be subject to the Tax on Foreign Exchange Transactions, or IOF/Exchange.  Currently, the applicable rate for most foreign currency exchange transactions is 0.38%.  However, currency exchange transactions carried out for the inflow of funds in Brazil by a 4,373 Holder are subject to IOF/Exchange at (i) 0% rate in case of variable income transactions carried out on the Brazilian stock, futures and commodities exchanges, as well as in the acquisitions of shares of Brazilian publicly-held companies in public offerings or subscription of shares related to capital contributions, provided that the issuer company has registered its shares for trading in the stock exchange (ii) 0% for the outflow of resources from Brazil related to these type of investments, including payments of dividends and interest on shareholders’ equity and the repatriation of funds invested in the Brazilian market.  Furthermore, the IOF/Exchange is currently levied at a 0% rate on the withdrawal of ADSs into shares.  In any case, the Brazilian government is permitted to increase at any time the rate to a maximum of 25%, but only in relation to future transactions. 

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

Other Relevant Brazilian Taxes

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

U.S. Federal Income Tax Consequences

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

This discussion does not purport to be a comprehensive description of all of the U.S. federal income tax consequences that may be relevant to a particular holder (including tax considerations that arise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known 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);

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·tax‑exempt organizations;

·regulated investment companies;

·realestate investment trusts;

·grantor trusts;

·common trust funds;

·banks or other financial institutions;

·persons liable for the alternative minimum tax;

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

·insurance companies;

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

·U.S. expatriates; and

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

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

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

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 toreflect 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.

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

Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.  Subject to the below‑mentioned concerns by the U.S. Treasury Department regarding certain inconsistent actions taken by intermediaries and certain exceptions for short‑term and hedged positions, the U.S. dollar amount of dividends received by certain U.S. holders (including individuals) with respect to the ADSs will be subject to taxation at a maximum rate of 20.0% if the dividends represent “qualified dividend income”.  Dividends paid on the ADSs will be treated as qualified dividend income if (i) the ADSs are readily tradable on an established securities market in the United States and (ii) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a PFIC.  The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed.  However, no assurances can be given that the ADSs will be or will remain readily tradable.  See below for a discussion regarding our PFIC determination.

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

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.

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

Taxation of Sales, Exchanges or Other Taxable Dispositions

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

Upon the sale, exchange or other taxable disposition of common shares or ADSs, a U.S. holder will generally recognize gain or loss for U.S. federal income tax purposes in an amount equal to the difference between the amount realized in consideration for the disposition of the common shares or ADSs (including the gross amount of the proceeds before the deduction of any Brazilian tax) and the U.S. holder's adjusted tax basis in the common shares or ADSs.  The initial tax basis of common shares or ADSs held by a U.S. holder will be the U.S. dollar value of thereais-denominated purchase price determined on the date of purchase.  Such gain or loss generally will be treated as capital gain or loss and will be long-term capital gain or loss if the common shares or ADSs have been held for more than one year at the time of the sale, exchange or other taxable disposition.  Under current law, certain non-corporate U.S. holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains.  The deductibility of capital losses is subject to limitations under the Code.

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

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 annual consolidated financial statements, the nature of our business, and relevant market and shareholder data, we believe that we would not beclassified 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.

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

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

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-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 apayment 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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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, 2017, approximately 24.1% of our indebtedness was denominated in U.S. dollars.  Also at December 31, 2017, we had swap agreements that offset the exchange rate risk with respect to R$4,688 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 B3), after giving effect to the swaps, would be approximately R$21.8 million (R$9.9 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 33.c.1 to our audited annual consolidated financial statements.

Risk of Index Variation

We have indebtedness and financial assets that are denominated inreaisand that bear interest at variable rates or, in some cases, are fixed.  The interest or indexation rates include several different Brazilian money‑market rates and inflation rates.  At December 31, 2017, the amount of such liabilities, net of such assets and after giving effect to swaps, wasR$8,229.9 million.  Further information for other scenario, please see note 33.c.2 to our audited annual consolidated financial statements.

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A hypothetical, instantaneous and unfavorable change of 25% in rates applicable to floating rate financial assets and liabilities held at December 31, 2017, would result in a net additional cash outflow of approximately R$227.1 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 ADSs
Delivery of common shares deposited under our deposit agreement against surrender of ADSs	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) surrendered	Person surrendering ADSs for cancellation and withdrawal of deposited securities or person to whom deposited securities are delivered
Distribution of cash dividends or other cash distributions	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person to whom distribution is made
Distribution of ADSs pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADSs	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person to whom distribution is made
Distribution of securities other than ADSs or rights to purchase additional ADSs	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person to whom distribution is made
Depositary services	Not in excess of US$5.00 per 100 ADSs (or fraction thereof) held	Person holding ADSs on the applicable record date(s) established by the depositary

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

Additional Charges

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

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

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(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 2017 we received no reimbursements from the depositary for expenses incurred by us relating to the ADR program.

ITEM 13.Defaults, Dividend Arrearages and Delinquencies

None. 

ITEM 14.Material Modifications to the Rights of Security Holders and Use of PROCEEDS

None.

ITEM 15.Controls and Procedures

We have evaluated, with the participation of our chief executive officer and chief financial officer, the effectiveness of our disclosure controls and procedures (including those related to cybersecurity risks and incidents and their potential impacts) as of December 31, 2017. In addition, in January 2018, Bureau Veritas completed an audit of our information security management system under ISO/IEC 27001 and found it to be effective.  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 (including those related to cybersecurity risks and incidents and their potential impacts) were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to our Management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Our Management is responsible for establishing and maintaining adequate internal control over financial reporting.  Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  Our internal control over financial reporting includes those policies and procedures that:  (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositionsof our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our Management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, and that the degree of compliance with the policies or procedures may deteriorate. 

Our Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2017 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, 2017.

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, Yuehui Pan, 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 of our stakeholders.  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.  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 athttps://cpfl.riweb.com.br/show.aspx?idMateria=TJJ0DQFsfdvDqqPuQGlX+Q== (This URL is intended to be an inactive textual reference only.  It is not intended to be an active hyperlink to our website.  The information on our website,which might be accessible through a hyperlink resulting from this URL, is not and shall not be deemed to be, incorporated into this annual report). 

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ITEM 16C.Principal Accountant Fees and Services

Audit and Non‑Audit Fees

The following table sets forth the fees billed to us by our independent registered and public accounting firm during the years ended December 31, 2017 and 2016.  Our independent accounting firm was KPMG Auditores Independentes for the year ended December 31, 2017 and Deloitte Touche Tohmatsu Auditores Independentes for the year ended December 31, 2016.

	Year ended December 31,
	2017	2016
	(in thousands ofreais)
Audit fees	4,198	4,888
Audit‑related fees	1,212	1,583
Tax fees	1,296	440
Total	6,706	6,911

“Audit Fees” are the aggregated fees billed by KPMG Auditores Independentes and 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 2017 and 2016, respectively.

“Audit‑related fees” are fees charged by KPMG Auditores Independentes and 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, 2017 and 2016, respectively.

“Tax fees” in the above table are for services related to tax compliance charged by KPMG Auditores Independentes and Deloitte Touche Tohmatsu Auditores Independentes for the years ended December 31, 2017 and 2016, 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.

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ITEM 16F.Change in Registrant’s Certifying Accountant

As previously disclosed in our annual report on Form 20-F for the fiscal year ended December 31, 2016, 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 our Form 20-F for the fiscal year ended December 31, 2016 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 the review of our quarterly information for the first quarter of 2017.

ITEM 16G.Corporate Governance

The following chart summarizes the ways that our corporate governance practices differ from those followed by domestic companies under the listing standards under the New York Stock Exchange:

Section of the New York Stock Exchange Listed Company Manual	New York Stock Exchange Listing Standard	Ways that CPFL’s Corporate Governance Practices Differ from Those Followed by Domestic Companies Listed on the New York Stock Exchange
303A.01	A company listed on the New York Stock Exchange (a “listed company”) must have a majority of independent directors on its Board of Directors.  “Controlled companies” are not required to comply with this requirement.	CPFL is a controlled company, because more than a majority of its voting power is controlled by State Grid Brazil Power Participações S.A., 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 the B3 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, 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.
303A.08	Shareholders must be given the opportunity to vote on all equity‑compensation plans and material revisions thereto, with limited exemptions set forth in the NYSE rules.	Under Brazilian Corporate Law, shareholder pre‑approval is required for the adoption of any equity compensation plans.
303A.09	A listed company must adopt and disclose corporate governance guidelines that cover certain minimum specified subjects.	CPFL has formal corporate governance guidelines that address the matters specified in the NYSE rules.  CPFL’s corporate governance guidelines are available on http://www.cpfl.com.br/ir.
303A.10	A listed company must adopt and disclose a code of business conduct and ethics for directors, officers and employees, and promptly disclose any waivers of the code for directors or executive officers.	CPFL has a formal Code of Ethics that applies to its directors, officers, employees and controlling shareholders.  CPFL’s Code of Ethics has a scope that is similar, but not identical, to that required for a U.S. domestic company under the NYSE rules.  CPFL reports each year under Item 16B of our annual report on Form 20‑F any waivers of the code of ethics in favor of our chief executive officer, our chief financial officer, our principal accounting officer and persons performing similar functions.  We will disclose such amendment or waiver on our website.
303A.12	Each listed company CEO must certify to the NYSE each year that he or she is not aware of any violation by the company of NYSE corporate governance listing standards.	CPFL’s CEO provides to the NYSE a Foreign Private Issuer Annual Written Affirmation, and he will promptly notify the NYSE in writing after any executive officer of CPFL becomes aware of any material non‑compliance with any applicable provisions of the NYSE corporate governance rules.

138

 

ITEM 16H.Mine Safety Disclosure

Not applicable.

ITEM 17.Financial Statements

Not applicable.

ITEM 18.Financial Statements

See pages F‑1 through F-112, incorporated herein by reference.

ITEM 19.Exhibits

No.	Description
1.1	Amended and Restated Bylaws of CPFL Energia S.A.  (together with an English version).
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.

139

 

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.

140

 

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.

B3:  B3 S.A.-Brasil Bolsa e Balcão.Created in March 2017 by the merger of BM&FBOVESPA and CETIP, B3 is a new financial market infrastructure company that consolidates BM&FBOVESPA’s activities in listed products trading and post-trading and CETIP’s activities in registration and depositary services for over-the-counter securities and financing.

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.”

141

 

CPFL Santa Cruz: “CPFL Santa Cruz” refers to the surviving company of the merger of Companhia Luz e Força Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista and CPFL Mococa into CPFL Jaguari.(This surviving corporate entity was previously named Companhia Jaguari de Energia, or CPFL Jaguari.)

DistributionNetwork:  Electric network system that distributes energy to end consumers within a concession area.

Distributor:  An entity supplying electric energy to a group of consumers by means of a Distribution Network.

EnergyAgreement:  Agreement under which a generator commits to supply a certain amount of electricity and assumes the risk that its electricity supply could be adversely affected by hydrological conditions and low reservoir levels, which could interrupt the supply of electricity.  In such a case, the generator would be required to purchase electricity elsewhere in order to comply with its supply commitments.

EPE:  Energetic Studies Company (Empresa de Pesquisas Energéticas).

ESS:  System Service Charge (Encargo de Serviço do Sistema).

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

Free Market:  Market segment that permits a certain degree of competition.  The Free Market specifically contemplates purchase of electricity by non‑regulated entities such as Free Consumers and energy traders.

Gigawatt (GW):  One billion watts.

Gigawatthour(GWh):  One gigawatt of power supplied or demanded for one hour, or one billion watt hours.

HighVoltage:  A class of nominal system voltages equal to or greater than 2.3 kV and equal to or lower than 230 kV.

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

Installed Capacity:  The level of electricity which can be delivered from a particular generator on a full‑load continuous basis under specified conditions as designated by the manufacturer.

Interconnected Power System:  Systems or networks for the transmission of energy, connected together by means of one or more links (lines and/or transformers).

Independent Power Producer:  A legal entity or consortium holding a concession or authorization for power generation for sale for its own account to public utility concessionaires.

IGP-M:  Market General Price Index (Índice Geral de Preços – Mercado published 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.

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

142

 

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:  Periodic Tariff Revision (revisão tarifária periódica).

SAIDI: System Average Interruption Duration Index.

SAIFI:  System Average Interruption Frequency Index.

SDGs: 17 sustainable development goals established by the United Nations and 169 specific targets that apply to all countries and cover a broad range sustainability issues, including poverty, hunger, health, education, climate change, gender equality, water, sanitation, energy, environment and social justice. For more information, see //sustainabledevelopment.un.org/sdgs.

143

 

SHPP or Small Hydroelectric Power Plants:  Power projects with capacity from 3 MW to 30 MW.

Special Free Consumers: Individual or groups of consumers whose contracted energy demand is between 500 kV and 3 MW.  Special Free Consumers may only purchase energy from renewable sources:  (i) Small Hydroelectric Power Plants with capacity superior to 3,000 kW and equal or inferior to 30,000 kW, (ii) hydroelectric generators with capacity superior to 3,000 kW and equal or inferior to 50,000 kW, under the independent power production regime; (iii) generators with capacity limited to 3,000 kW, and (iv) alternative energy generators (solar, wind and biomass enterprises) with system capacity not greater than 50,000 kW.

Substation:  An assemblage of equipment which switches and/or changes or regulates the voltage of electricity in a transmission and distribution system.

TE:  Energy Tariff (Tarifa de Energia).

TFSEE:  Tax on the Supervision of Electrical Services (Taxa de Fiscalização de Serviços de Energia Elétrica).

TEO: Energy Optimization Tariff (Tarifa de Energia de Otimização)

Thermoelectric Power Plant:  A generator which uses combustible fuel, such as coal, oil, diesel natural gas or other hydrocarbon as the source of energy to drive the electric generator.

Transmission:  The bulk transfer of electricity from generating facilities to the distribution system at load center station by means of the transmission network (in lines with capacity between 69 kV and 525 kV).

Transmission Tariff:  Revenue charged by a transmission concessionaire based on the transmission network it owns and operates.  Transmission tariffs are subject to periodic revisions by ANEEL.

TSEE:  Social Tariff for Electricity (Tarifa Social de Energia Elétrica).

TUSD: Tariff for the Use of the Distribution System (Tarifa de Uso dos Sistemas Elétricos de Distribuição).

TUST:  Tariff for the Use of the Transmission System (Tarifa de Uso dos Sistemas Elétricos de Transmissão).

UBP:  Use of a Public Asset (Uso de Bem Público)

Volt:  The basic unit of electric force analogous to water pressure in pounds per square inch.

Watt:  The basic unit of electrical power.

144

 

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 23, 2018.

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

KPMG Auditores Independentes

Avenida Coronel Silva Telles, 977, 10º andar - Dahruj Tower

13020-431 - Campinas/SP - Brasil

Caixa Postal 737 - CEP 13012-970 - Campinas/SP - Brasil

Telefone +55 (19) 3198-6000, Fax +55 (19) 3198-6001

www.kpmg.com.br

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
CPFL Energia S.A.:

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated statement of financial position of CPFL Energia S.A. and subsidiaries (the Company) as of December 31, 2017, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and the related notes (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established inInternal Control – Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for the year then ended, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established inInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting under Item 15 of the Company’s Form 20-F. Our responsibility is to express an opinion on the Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as weconsidered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We have served as the Company’s auditor since 2017.

/s/ KPMG Auditores Independentes

Campinas, São Paulo - Brazil
April23, 2018

 

Deloitte Touche Tohmatsu Av. Dr. José Bonifácio Coutinho Nogueira, 150 -Salas 501, 502, 504 e 510 13091-611 - Campinas - SP Brasil   Tel.: + 55 (19) 3707-3000 Fax: +55 (19) 3707-3001 www.deloitte.com.br  

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

CPFL Energia S.A.

São Paulo – SP

We have audited the accompanying consolidated balance sheet ofCPFL Energia S.A.and subsidiaries (the “Company”) as of December 31, 2016, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for each of the two 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 the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2016, inaccordance with International Financial Reporting Standards - IFRS, issued by the International Accounting Standards Board - IASB.

Campinas, São Paulo, Brazil

April 17, 2017

/s/DELOITTE TOUCHE TOHMATSU

Auditores Independentes

Deloitte refers to one or more of Deloitte Touche Tohmatsu Limited, a UK private company limited by guarantee ("DTTL"), its network of member firms, and their related entities. DTTL and each of its member firms are legally separate and independent entities. DTTL (also referred to as "Deloitte Global") does not provide services to clients. Please see www.deloitte.com/about for a more detailed description of DTTL and its member firms.

Deloitte provides audit, consulting, financial advisory, risk management, tax and relates services to public and private clients spanning multiple industries. Deloitte serves four out of five Fortune Global 500® companies through a globally connected network of member firms in more than 150 countries bringing world-class capabilities, insights, and high-quality service to address clients’ most complex business challenges. To learn more about how Deloitte’s approximately 225,000 professionals make an impact that matters, please connect with us on Facebook, LinkedIn or Twitter.

©2018 Deloitte Touche Tohmatsu. All rights reserved.

 

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AT DECEMBER 31, 2017 AND 2016

(In thousands of Brazilian reais - R$)

ASSETS	Note	Dec 31, 2017	Dec 31, 2016
CURRENT ASSETS
Cash and cash equivalents	5	3,249,642	6,164,997
Consumers, concessionaires and licensees	6	4,301,283	3,765,893
Dividend and interest on capital	12	56,145	73,328
Income tax and social contribution recoverable	7	88,802	143,943
Taxes recoverable	7	306,244	259,905
Derivatives	33	444,029	163,241
Sector financial asset	8	210,834	-
Concession financial asset	10	23,736	10,700
Other assets	11	900,498	797,181
TOTAL CURRENT ASSETS		9,581,212	11,379,187
NONCURRENT ASSETS
Consumers, concessionaires and licensees	6	236,539	203,185
Associates, subsidiaries and parent company	30	8,612	47,631
Escrow Deposits	21	839,990	550,072
Income tax and social contribution recoverable	7	61,464	65,535
Taxes recoverable	7	171,980	132,751
Sector financial assets	8	355,003	-
Derivatives	33	203,901	641,357
Deferred tax assets	9	943,199	922,858
Concession financial asset	10	6,545,668	5,363,144
Investments at cost		116,654	116,654
Other receivables	11	840,192	766,253
Investments	12	1,001,550	1,493,753
Property, Plant and Equipment	13	9,787,125	9,712,998
Intangible assets	14	10,589,824	10,775,613
TOTAL NONCURRENT ASSETS		31,701,701	30,791,805
TOTAL ASSETS		41,282,912	42,170,992

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, 2017 AND 2016

(In thousands of Brazilian reais - R$)

LIABILITIES AND EQUITY	Note	Dec 31, 2017	Dec 31, 2016
CURRENT LIABILITIES
Trade payables	15	3,296,870	2,728,130
Borrowings	16	3,589,607	1,875,648
Debentures	17	1,703,073	1,547,275
Private pension plan	18	60,801	33,209
Regulatory charges	19	581,600	366,078
Income tax and social contribution payable	20	81,457	57,227
Taxes, fees and contributions	20	628,846	624,317
Dividend		297,744	232,851
Estimated payroll		116,080	131,707
Derivatives	33	10,230	6,055
Sector financial liability	8	40,111	597,515
Use of public asset		10,965	10,857
Other payables	22	961,306	807,623
TOTAL CURRENT LIABILITIES		11,378,688	9,018,492
NONCURRENT LIABILITIES
Trade payables	15	128,438	129,781
Borrowings	16	7,402,450	11,168,394
Debentures	17	7,473,454	7,452,672
Private pension plan	18	880,360	1,019,233
Taxes, fees and contributions	20	18,839	26,814
Deferred tax liabilities	9	1,249,591	1,324,134
Provision for tax, civil and labor risks	21	961,134	833,276
Derivatives	33	84,576	112,207
Sector financial liability	8	8,385	317,406
Use of public asset		83,766	86,624
Other payables	22	426,890	309,292
TOTAL NONCURRENT LIABILITIES		18,717,881	22,779,832
EQUITY	23
Issued capital		5,741,284	5,741,284
Capital reserves		468,014	468,014
Legal reserve		798,090	739,102
Statutory reserve - concession financial asset		826,600	702,928
Statutory reserve - working capital improvement		1,292,046	545,505
Additional dividend proposed		-	7,820
Accumulated comprehensive income		(164,506)	(234,633)
		8,961,528	7,970,021
Equity attributable to noncontrolling interests		2,224,816	2,402,648
TOTAL EQUITY		11,186,344	10,372,668
TOTAL LIABILITIES AND EQUITY		41,282,912	42,170,992

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, 2017, 2016 and 2015

(In thousands of Brazilian reais - R$, except for earnings per share)

	Note	2017	2016	2015
NET OPERATING REVENUE	25	26,744,905	19,112,089	20,599,212
COST OF ELECTRIC ENERGY SERVICES
Cost of electric energy	26	(16,901,518)	(11,200,242)	(13,311,747)
Cost of operation	27	(2,771,145)	(2,248,795)	(1,907,107)
Cost of services rendered to third parties	27	(2,074,611)	(1,357,032)	(1,049,101)
GROSS PROFIT		4,997,632	4,306,020	4,331,167
Operating expenses	27
Sales expenses		(590,232)	(547,251)	(464,583)
General and administrative expenses		(947,072)	(849,416)	(863,499)
Other Operating Expense		(438,494)	(386,746)	(357,653)
INCOME FROM ELECTRIC ENERGY SERVICES		3,021,834	2,522,608	2,645,433
Equity interests in associates and joint ventures	12	312,390	311,414	216,885
FINANCE INCOME (EXPENSES)	28
Finance income		880,314	1,200,503	1,143,247
Finance expenses		(2,367,868)	(2,653,977)	(2,551,110)
		(1,487,554)	(1,453,474)	(1,407,863)
PROFIT BEFORE TAXES		1,846,670	1,380,547	1,454,454
Social contribution	9	(168,728)	(150,859)	(160,162)
Income tax	9	(434,901)	(350,631)	(419,015)
		(603,629)	(501,490)	(579,177)
PROFIT FOR THE YEAR		1,243,042	879,057	875,277
Profit attributable to the owners of the Company		1,179,750	900,885	864,940
Profit (loss) attributable to noncontrolling interests		63,292	(21,828)	10,337
Earnings per share attributable to owners of the Company:
Basic	24	1.16	0.89	0.85
Diluted	24	1.15	0.87	0.83

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, 2017, 2016 and 2015

(In thousands of Brazilian reais - R$)

	2017	2016	2015
Profit for the year	1,243,042	879,057	875,277
Other comprehensive income
Items that will not be reclassified subsequently to profit and loss
- Actuarial gains (losses), net of tax effects	96,000	(394,175)	65,547
Total Comprehensive income for the year	1,339,042	484,882	940,825
Attributable to owners of the Company	1,275,750	506,709	930,488
Attributable to noncontrolling interests	63,292	(21,828)	10,337

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, 2017, 2016 and 2015

(In thousands of Brazilian reais - R$)

			Earning reserves				Accumulated comprehensive income				Noncontrolling interests
				Statutory reserves
				Concession	Working			Private			Accumulated	Other
	Issued	Capital	Legal	financial	capital		Deemed	pension	Retained		comprehensive	equity	Total
	capital	reserves	reserve	asset	improvement	Dividends	cost	plan	earnings	Total	income	component	equity
Balance at December 31, 2014	4,793,424	468,082	650,811	330,437	554,888	-	483,610	(337,718)	-	6,943,535	17,003	2,436,791	9,397,329
Total comprehensive income
Profit for the year	-	-	-	-	-	-	-	-	864,940	864,940	-	10,337	875,277
Other comprehensive income - actuarial gains	-	-	-	-	-	-	-	65,547	-	65,547	-	-	65,547
Internal changes of shareholders'equity
Realization of deemed cost of property, plant and equipment	-	-	-	-	-	-	(39,574)	-	39,574	-	(2,550)	2,550	-
Tax on realization of deemed cost	-	-	-	-	-	-	13,455	-	(13,455)	-	867	(867)	-
Recognition of legal reserve	-	-	43,247	-	-	-	-	-	(43,247)	-	-	-	-
Changes in statutory reserve in the year	-	-	-	255,013	392,972	-	-	-	(647,985)	-	-	-	-
Other changes in noncontrolling interests	-	-	-	-	-	-	-	-	-	-	-	(48)	(48)
Capital transactions with owners
Capital increase	554,888	-	-	-	(554,888)	-	-	-	-	-	-	-	-
Prescribed dividends	-	-	-	-	-	-	-	-	5,597	5,597	-	-	5,597
Additional dividend approved	-	-	-	-	-	-	-	-	(205,423)	(205,423)	-	(8,147)	(213,570)
Capital increase in subsidiaries with no change in control	-	-	-	-	-	-	-	-	-	-	-	7	7
Balance 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	10,130,140
Total comprehensive income
Profit for the year	-	-	-	-	-	-	-	-	900,885	900,885	-	(21,828)	879,057
Other comprehensive income - actuarial gains	-	-	-	-	-	-	-	(394,175)	-	(394,175)	-	-	(394,175)
Internal changes of shareholders'equity
Realization 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 owners
Capital increase	392,972	-	-	-	(392,972)	-	-	-	-	-	-	-	-
Prescribed dividends	-	-	-	-	-	-	-	-	3,144	3,144	-	-	3,144
Additional dividend proposed	-	-	-	-	-	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	467
Balance 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
Total comprehensive income
Profit for the year	-	-	-	-	-	-	-	-	1,179,750	1,179,750	-	63,292	1,243,042
Other comprehensive income - actuarial gains	-	-	-	-	-	-	-	96,000	-	96,000	-	-	96,000
Internal changes of shareholders'equity
Realization of deemed cost of property, plant and equipment	-	-	-	-	-	-	(39,202)	-	39,202	-	(2,634)	2,634	-
Tax on realization of deemed cost	-	-	-	-	-	-	13,329	-	(13,329)	-	896	(896)	-
Recognition of legal reserve	-	-	58,988	-	-	-	-	-	(58,988)	-	-	-	-
Changes in statutory reserve in the year	-	-	-	123,673	746,541	-	-	-	(870,213)	-	-	-	-
Other changes in noncontrolling interests	-	-	-	-	-	-	-	-	-	-	-	(113)	(113)
Capital transactions with owners
Capital increase (reduction)	-	-	-	-	-	-	-	-	-	-	-	(122,791)	(122,791)
Prescribed dividends	-	-	-	-	-	-	-	-	3,768	3,768	-	-	3,768
Interim dividends	-	-	-	-	-	-	-	-	-	-	-	(7,226)	(7,226)
Dividend proposal approved	-	-	-	-	-	(7,820)	-	-	(280,191)	(288,011)	-	(110,993)	(399,005)
Balance at December 31, 2017	5,741,284	468,014	798,090	826,600	1,292,046	-	405,840	(570,346)	-	8,961,528	11,833	2,212,983	11,186,344

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, 2017, 2016 and 2015

(In thousands of Brazilian reais – R$)

	2017	2016	2015
OPERATING CASH FLOW
Profit before taxes	1,846,670	1,380,547	1,454,454
ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIES
Depreciation and amortization	1,529,052	1,291,165	1,279,902
Provision for tax, civil and labor risks	176,609	228,292	258,539
Allowance for doubtful debts	155,097	176,349	126,879
Interest on debts, inflation adjustment and exchange rate changes	1,863,311	2,052,959	1,519,819
Pension plan expense	113,898	76,638	60,184
Equity interests in associates and joint ventures	(312,390)	(311,414)	(216,885)
Impairment	20,437	48,291	38,956
Loss on disposal of noncurrent assets	132,195	83,576	16,309
Deferred taxes (PIS and COFINS)	963	(8,579)	19,138
Others	(19,074)	(1,832)	(5,825)
	5,506,768	5,015,992	4,551,470
DECREASE (INCREASE) IN OPERATING ASSETS
Consumers, concessionaires and licensees	(722,406)	(205,828)	(1,055,143)
Dividends and interest on capital received	730,178	83,356	24,050
Taxes recoverable	68,184	128,453	(62,041)
Escrow deposits	(248,128)	756,171	22,827
Sectorial financial asset	(425,004)	2,494,223	(858,860)
Receivables - amounts from the Energy Development Account - CDE / CCEE	(29,354)	186,052	181,141
Concession financial assets (transmission companies)	(56,665)	(55,134)	(44,243)
Other operating assets	91,607	265,404	(82,278)
INCREASE (DECREASE) IN OPERATING LIABILITIES
Trade payables	565,945	(782,963)	787,063
Other taxes and social contributions	(261,194)	(63,986)	412,703
Other liabilities with private pension plan	(79,724)	(77,183)	(112,172)
Regulatory charges	215,522	(514,935)	808,223
Tax, civil and labor risks paid	(206,788)	(216,998)	(247,512)
Sectorial financial liability	(1,089,592)	288,144	(23,170)
Payables - amounts provided by the CDE	17,544	(70,907)	19,696
Other operating liabilities	141,759	(148,967)	107,930
CASH FLOWS PROVIDED BY OPERATIONS	4,218,652	7,080,894	4,429,684
Interest paid on debts and debentures	(1,846,453)	(1,570,985)	(1,595,649)
Income tax and social contribution paid	(338,175)	(875,883)	(276,061)
NET CASH FROM OPERATING ACTIVITIES	2,034,024	4,634,026	2,557,974
INVESTING ACTIVITIES
Price paid in business combination net of cash acquired	-	(1,496,675)	-
Capital increase in existing investees	91,599	-	-
Gain on sales of interest in joint ventures	-	-	10,454
Purchases of property, plant and equipment	(685,856)	(1,026,867)	(550,003)
Securities, pledges and restricted deposits	(93,933)	(125,517)	(147,914)
Purchases of intangible assets	(1,884,577)	(1,211,082)	(877,793)
Sale of noncurrent assets	26,807	-	10,586
Intragroup loans	36,639	44,922	29,776
NET CASH USED IN INVESTING ACTIVITIES	(2,509,321)	(3,815,219)	(1,524,894)
FINANCING ACTIVITIES
Capital increase by noncontrolling interests	(122,791)	467	7
Borrowings and debentures raised	3,398,084	3,774,355	4,532,167
Repayment of principal of borrowings and debentures	(5,273,261)	(4,016,693)	(4,037,685)
Repayment of derivatives	(102,641)	158,242	(135,309)
Dividends and interest on capital paid	(336,934)	(231,749)	(5,204)
Repayment for business combinations	(2,514)	(21,234)	(61,709)
NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES	(2,440,057)	(336,612)	292,267
NET INCREASE IN CASH AND CASH EQUIVALENTS	(2,915,354)	482,195	1,325,347
CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR	6,164,997	5,682,802	4,357,455
CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR	3,249,642	6,164,997	5,682,802

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

F - 6

 

CPFL ENERGIA S.A.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 and 2015

(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 Rodovia Eng^o Miguel Noel Nascentes Burnier, Km 2,5, Parque São Quirino - Campinas - SP - Brazil.

The Company has direct and indirect interests in the following subsidiaries and joint ventures (information on the concession area, member of consumers, energy production capacity and related data are not audited by the independent auditos):

Energy distribution	Company type	Equity interest	Location (state)	Number of municipalities	Approximate number of consumers (in thousands)	Concession period	End of the concession
Companhia Paulista de Força e Luz ("CPFL Paulista")	Publicly-held corporation	Direct 100%	Interior of São Paulo	234	4,389	30 years	November 2027
Companhia Piratininga de Força e Luz ("CPFL Piratininga")	Publicly-held corporation	Direct 100%	Interior of São Paulo	27	1,720	30 years	October 2028
Rio Grande Energia S.A. ("RGE")	Publicly-held corporation	Direct 100%	Interior of Rio Grande do Sul	255	1,485	30 years	November 2027
RGE Sul Distribuidora de Energia S.A. ("RGE Sul")	Publicly-held corporation	Indirect 100%	Interior of Rio Grande do Sul	118	1,336	30 years	November 2027
Companhia Jaguari de Energia ("CPFL Santa Cruz") (e)	Privately-held corporation	Direct 100%	Interior of São Paulo, Paraná and Minas Gerais	45	447	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 share
CPFL Geração de Energia S.A. ("CPFL Geração")	Publicly-held corporation	Direct 100%	São Paulo and Goiás	3 Hydropower plants (a)	1,295	678
CERAN - Companhia Energética Rio das Antas ("CERAN")	Privately-held corporation	Indirect 65%	Rio Grande do Sul	3 Hydropower plants	360	234
Foz do Chapecó Energia S.A. ("Foz do Chapecó")	Privately-held corporation	Indirect 51% (d)	Santa Catarina and Rio Grande do Sul	1 Hydropower plant	855	436
Campos Novos Energia S.A. ("ENERCAN")	Privately-held corporation	Indirect 48.72%	Santa Catarina	1 Hydropower plant	880	429
BAESA - Energética Barra Grande S.A. ("BAESA")	Privately-held corporation	Indirect 25.01%	Santa Catarina and Rio Grande do Sul	1 Hydropower plant	690	173
Centrais Elétricas da Paraíba S.A. ("EPASA")	Privately-held corporation	Indirect 53.34%	Paraíba	2 Thermal plants	342	182
Paulista Lajeado Energia S.A. ("Paulista Lajeado")	Privately-held corporation	Indirect 59.93% (b)	Tocantins	1 Hydropower plant	903	63
CPFL Energias Renováveis S.A. ("CPFL Renováveis")	Publicly-held corporation	Indirect 51.60%	(c)	(c)	(c)	(c)
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

 

Energy commercialization	Company type	Core activity	Equity interest
CPFL 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 interest
CPFL 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 Eficiência")	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 interest
CPFL Jaguari de Geração de Energia Ltda ("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)   CPFL Geração has 51.54% of assured energy and power of the Serra da Mesa hydropower plant, whose concession is controlled by Furnas. The small hydropower plant Cariobinha and the thermoelectric plant Carioba are inactive while they await he position of the Ministry of Mines and Energy on the early termination of their concession and are not included in the table.

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

F - 8

 

c)     CPFL Renováveis has operations in the states of São Paulo, Minas Gerais, Mato Grosso, Santa Catarina, Ceará, Rio Grande do Norte, Paraná and Rio Grande do Sul and its main activities are: (i) holding investments in companies of the renewable energy segment; (ii) identification, development, and exploration of generation potentials; and (iii) sale of electric energy. At December 31, 2017, CPFL Renováveis had a portfolio of 112 projects with installed capacity of 2,508.4 MW (2,102.6 MW in operation), as follows: 

·       Hydropower generation: 46 SHP’s (543.2 MW) with39SHPs (small hydroelectric power plants) in operation (423MW) and 7 SHPs under development (120.2 MW);

·       Wind power generation: 57 projects (1,594.1 MW) with 45projects in operation (1,308.5MW) and 12projects under construction/development (285.6 MW);

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

·       Solar power generation:1solar plant in operation (1.1MW).

d)    The joint venture Chapecoense has as its direct subsidiary Foz do Chapecó and fully consolidates its financial statements.

e)    As described in note 14.4.2, on December 31, 2017, approval was given for the merger of the subsidiaries Companhia Luz e Força Santa Cruz, Companhia Leste Paulista de Energia, Companhia Jaguari de Energia, Companhia Sul Paulista de Energia and Companhia Luz e Força de Mococa into Companhia Jaguari de Energia, which adopted the trade name “CPFL Santa Cruz”.

Negative net working capital (calculated by the excess of current liabilities over current assets)

As at December 31, 2017, the Company had net working capital (calculated by the excess of current liabilities over current assets) of R$ 1,797,477. In January 2018, the subsidiaries issued debentures in the amount of R$ 2,610,000 (note 36). The Company has history of profitable operations and ready access to financial resources therefore the financial statements have been prepared using the going concern basis.

F - 9

 

( 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 Group.

The consolidated financial statements were approved by Management and authorized for issue onApril 23, 2018.

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 inputs used) is presented in note 33 – Financial Instruments.

2.3 Use of estimates and judgments

The preparation of consolidated financial statements requires the Group’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 Group’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 (Allowance for doubtful accounts: key assumptions regarding recoverable amounts);

·Note 8 – Sector financial asset and liability (there would be certain new sector related financial components not included in the  previous methodology);

·Note 9 – Deferred tax assets and liabilities (recognition of assets: availability of future taxable profit against which the tax losses can be utilized);

·Note 10 – Concession financial asset (assumptions for fair value measurement, based on significant unobservable inputs);

·Note 11 – Other receivables (allowance for doubtful accounts, key assumptions regarding recoverable amounts);

·Note 13 – Property, plant and equipment (application of definite useful lives and key assumptions regarding recoverable amounts);

·Note 14 – Intangible assets (key assumptions regarding recoverable amounts);

·Note 18 – Private pension plan (key actuarial assumptions used in the measurement of defined benefit obligations);

·Note 21 – Provision for tax, civil and labor risks and escrow deposits (recognition and measurement: key assumptions on the probability and magnitude of outflow of resources);

·Note 25 – Net operating revenue (assumptions for measurement of unbilled supply and Distribution System Usage Tariff - TUSD ); and

F - 10

 

·Note 33 – Financial instruments (assumptions for fair value measurement, based on significant unobservable inputs).

2.4 Functional currency and presentation currency

The Group’s functional currency is the Brazilian Real, and the financial statements are presented in thousands of reais. Figures are rounded only after sum-up of the amounts. Consequently, when summed up, the amounts stated in thousands of reais may not tally with the rounded totals.

2.5 Segment information

An operating segment is a component of the Company (i) that engages in operating activities from which it earns revenues and incurs expenses, (ii) whose operating results are regularly reviewed by Management to make decisions about resources to be allocated and assess the segment's performance, and (iii) for which individual financial information is available.

The Group´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 29.

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, 2017 and 2016, the noncontrolling interests recognized in the financial statements refer to the interests held by third parties in subsidiaries CERAN, Paulista Lajeado and CPFL Renováveis.

( 3 ) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

3.1Cash and cash equivalents

In the statements of cash flows, cash and cash equivalents include negative balances of overdraft accounts that are immediately payable and are an integral part of the Group’s cash management.

Cash and cash equivalents comprise the balances of cash and financial investments with original maturities of three months or less from the contract date, which are subject to an insignificant risk of change in value and are used by the Company in the management of short-term obligations.

3.2 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 criteria are met, the infrastructure of distribution concessionaires is segregated at the time ofconstruction in accordance with the IFRS requirements, so that the following are recognized in the financial statements (i) an intangible asset corresponding to the right to operate the concession and collect from the users of public utilities, and (ii) a financial asset corresponding to the unconditional contractual right to receive cash (indemnity) by transferring control of the assets at the end of the concession.

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The concession financial asset of distribution companies 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 Brazilian Electricity Regulatory Agency (Agência Nacional de Energia Elétrica - ANEEL), and takes into consideration changes in the estimated cash flow, mainly based on factors such as new replacement price, and adjustment for Extended Comprehensive Consumer Price Index (“IPCA”) for the distribution subsidiaries. The financial asset of distribution companies 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 4 and 25).

The financial asset of the transmission companies is classified as loans and receivables, initially measured at its fair value and subsequently at amortized cost using the effective interest method.

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

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

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

3.3 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 Group holds 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 Group manages 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 Group has 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

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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 Group has 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 33.

- 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.

3.4 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.

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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, adding the portion of noncontrolling interests 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.

A bargain purchase is recognized as a gain in the statement of profit or loss in the year of the business acquisition.

Intangible assets corresponding to the right to operate concessions may have three origins, as follows:

i.Acquisitions through business combinations: the portion arising from business combinations that corresponds to the right to operate the concession is stated as an intangible asset and,amortized over the remaining period of the concessions, on a straight-line basis;

ii.Investments in infrastructure: 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 3.2.

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 Company capitalizes interests on the Use of Public Assets intangible from the signing date to the date of commencement of the operations, when the whole intagible starts to be 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 Group 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.

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

- Non-financial assets

Non-financial assets that have indefinite useful lives, such as goodwill, are tested annually for impairment to assess whether the asset's carrying amount does not exceed its recoverable amount. Other assets subject to amortization are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may be impaired.

An impairment loss is recognized if the carrying amount of an asset exceeds its estimated recoverable amount, which is the greater of (i) its fair value less costs to sell and (ii) its value in use.

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 triggering events that would lead to 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 (more likely than not) 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. The unwinding of the discount is recognized as finance cost.

3.8 Employee benefits

Certain subsidiaries have post-employment benefits and pension plans, recognized 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.

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As established in the Company's bylaws and in accordance with current corporate law, the Board of Directors is responsible for declaring an interim dividend and interest on capital determined in a half-yearly statement of income. An interim dividend and interest on capital declared at the base date of June 30 is only recognized as a liability in the Company's financial statement after the date of the Board of Directors' decision.

Interest on capital is treated in the same way as dividends and is also stated in changes in equity. The withholding income tax on interest on capital is always recognized as a charge to equity with a balancing item in liabilities upon the proposal for its payment, even if not yet approved, since it meets the criterion of obligation at the time of Management’s proposal.

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 credits relating to the tax benefits created by the corporate restructuring, 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.

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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.

3.13 Government grants – CDE (Energy Development Account)

Government grants are only recognized when it is reasonably certain that these amounts will be received by the Group. 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 (note 25) have the main purpose of offsetting discounts granted in order to provide immediate financial support to the distribution companies.

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 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 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.

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The excess of the consideration transferred, added to the portion of noncontrolling interests, over the fair value of the identifiable assets (including the concession intangible asset) and net liabilities assumed at the acquisition date are recognized as goodwill. In the event that the fair value of the identifiable assets 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

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.

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 12.2.

(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, 2017:

a)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 of recognition of deferred tax assets for unrealized losses on debt instruments and the method to assess whether taxable profits will be available against which the entity can utilize a deductible temporary difference, to address the diversity in practice.

The application of the amendments to IAS 12 did not have material impacts on the Company’s consolidated financial statements for the year ended December 31, 2017.

b)Amendments to IAS 7 – Statement of Cash Flows

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.

The application of the amendments to IAS 7 resulted in changes in the disclosure of the movement of financial assets and liabilities the cash flows of which are classified as financing activity. The changes of these amendments to IAS 7 generated additional disclosure reflected in notes 17 – Borrowings, 18 – Debentures and 33 – Financial Instruments.

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c)Annual Improvements to IFRS / 2014 – 2016 Cycle

Annually, the IASB discusses and decides on the proposed improvements to IFRS, as they are raised during the year. On December 8, 2016, the amendments relating to the 2014-2016 Cycle were issued, one of which is effective for annual periods beginning on or after January 1, 2017.

Amendments to IFRS 12 – Disclosure of interests in other entities: clarifies the scope of the standard regarding the interest of entities in other entities that are classified as held for sale or discontinued operations in accordance with IFRS 5.

Considering that the Company does not have interest in other entities that are classified as held for sale or discontinued operations, these amendments did not have effects on the disclosures and amounts recognized in the consolidated financial statements for the year ended December 31, 2017.

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 annual periods beginning on January 1, 2017. Consequently, the Company has not early 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.

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; (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.

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 default 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 opinion is that, these assets will be classified as measured at fair value through profit or loss according to the new standard, the effects of the subsequent remeasurement of this asset would be recognized in profit or loss for the year. Thus, there will not be material impacts on the Company’s consolidated financial statements.

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The transmission subsidiaries have assets classified as “loans and receivables”, in accordance with the current requirements of IAS 39. These assets have two components: the right to receive the “Allowed Annual Revenue - RAP” to be received over the concession period and the indemnity at the end of the concession. These instruments are designated as loans and receivables because they are non-derivative financial assets, with fixed or determinable payments that are not quoted in an active market. Management’s opinion is that the asset arising from the receipt of RAP will be classified and measured at amortized cost with the new standard, not causing impacts on the Company’s consolidated financial statements. Regarding the indemnity receivable at the end of the concession, this will correspond to the portion of assets not depreciated over the concession at their new replacement value. Considering that the calculation of the amount to be received will not change during the concession, Management analyzes the possibility of measuring and classifying this portion of the financial asset as at fair value through profit or loss. Currently, Management’s opinion is that the effects of this possible change would be immaterial.

Moreover, as the Group 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 in the calculation of impairment of financial assets, the Company estimates that the impact on the equity for January 1^st 2018 will be a decrease in line item “Consumers, concessionaires and licensees” between R$ 70,000 and R$ 80,000.

Considering that the Group holds certain financial liabilities designated at fair value through profit or loss, Management believes that there will be no impacts on its consolidated financial statements since the changes in credit risk currently recognized directly in profit or loss will be recognized in other comprehensive income. For the year ended December 31, 2017, the changes in credit risk recognized in profit or loss represented an expense of R$ 92,138.

b) IFRS 15 - Revenue from contracts with customers

IFRS 15 provides a straightforward model for accounting for contracts with customers and 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.

IFRS 15 is effective for annual periods beginning on or after January 1, 2018. Contracts that begin and end in the same period of comparative presentation, as well as contracts that are completed at the beginning of the oldest period presented will not be restated. The Company analyzed the 5-step approach to the various types of the Group’ revenue and has not identified any material impact of the adoption of this standard on its consolidated financial statements. Therefore, after the appropriate analyses, the conclusion is that the current revenue recognition is in accordance with IFRS 15.

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.

IFRS 16 is effective for annual periods beginning or on after January 1, 2019. The Company is assessing the standard and its adoption and preliminarily believes that the main impact will be the recording of lease of properties (under the lessee’s view), but no material impacts from the adoption of this standard are expected.

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d)IFRIC 22 – Foreign currency transactions and advance consideration

Issued on December 8, 2016, IFRIC 22 addresses the exchange rate to be used in transactions that involve the consideration paid or received in advance in foreign currency transactions, IFRIC will be effective for annual periods beginning on or after January 1, 2018.

The Group’s foreign currency transactions are currently restricted to debt instruments with international financial institutions, measured at fair value, and to the purchase of electricity from Itaipu. As assets and liabilities measured at fair value are outside the scope of IFRIC and there are no advance payments on operations with Itaipu, Management believes that IFRIC 22 will not have material impacts on its consolidated financial statements.

e)Annual Improvements to IFRS / 2014 – 2016 Cycle

Annually, the IASB discusses and decides on the proposed improvements to IFRS, as they are raised during the year. On December 8, 2016, new amendments were issued relating to the 2014-2016 cycle, effective as of January 1, 2018.

Amendments to IFRS 1 – First-time adoption of IFRS: excludes from the standard some exceptions existing for application in the transition period of entities that are first-time adopters of IFRS.  

As the Company is not a first-time adopter of IFRS, Management believes that the application of these amendments will not have effect on the disclosures and amounts recognized in its consolidated financial statements.

( 4 ) DETERMINATION OF FAIR VALUES

A number of the Group’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and / or disclosure purposes based on the following methods. When applicable, further information on the assumptions used in determining fair values is disclosed in the notes specific to that asset or liability.

The Group 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 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 cash 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 “B3”) andAssociação Brasileira das Entidades dos Mercados Financeiro e de Capitais (“ANBIMA”) (note 33) and also includes the debtor's credit rating. The assumptions for fair value calculation are described in note 33.

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 updated value at subsequent dates, in accordance with the tariff review process.

F - 21

 

( 5 ) CASH AND CASH EQUIVALENTS

	Dec 31, 2017	Dec 31, 2016
Bank balances	365,031	170,884
Short-term financial investments	2,884,611	5,994,112
Overnight investment (a)	178,444	95,034
Bank certificates of deposit (b)	785,074	2,357,187
Repurchase agreements secured on debentures (b)	3,268	58,616
Investment funds (c)	1,917,826	3,483,274
Total	3,249,642	6,164,997

(a)   Current account balances, which earn daily interest by investment in repurchase agreements secured on Bank Certificate Deposit (CDB) 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, short-term due, low credit risk and interest equivalent, on average, to 101.87% of the CDI.

(c)   Exclusive Fund investments, with daily liquidity and interest equivalent, on average, of 100% of the CDI, subject to floating rates tied to the CDI linked to their investments in federal government bonds, CDBs, financial bills and secured debentures of major financial institutions, with low credit risk and short-term due.

( 6 ) CONSUMERS, CONCESSIONAIRES AND LICENSEES

The balance derives mainly from the supply of electric energy. The following table shows the breakdown at December 31, 2017 and 2016:

	Amounts coming due	Past due		Total
		until 90 days	> 90 days	Dec 31, 2017	Dec 31, 2016
Current
Consumer classes
Residential	602,525	457,273	53,805	1,113,604	932,380
Industrial	322,250	77,148	84,232	483,630	386,826
Commercial	254,605	86,290	41,574	382,470	317,111
Rural	74,136	18,409	6,117	98,663	97,444
Public administration	69,333	15,638	3,939	88,910	94,348
Public lighting	58,475	6,573	2,485	67,533	73,142
Public utilities	87,159	8,972	4,713	100,843	97,503
Billed	1,468,483	670,303	196,865	2,335,653	1,998,754
Unbilled	1,008,486	-	-	1,008,486	1,095,188
Financing of consumers' debts	169,171	20,784	39,885	229,840	170,982
CCEE transactions	182,128	229,887	1,052	413,067	289,761
Concessionaires and licensees	508,046	423	7,950	516,419	390,333
Others	36,011	-	-	36,011	39,974
	3,372,325	921,397	245,752	4,539,476	3,984,991
Allowance for doubtful accounts				(238,193)	(219,098)
Total				4,301,283	3,765,893
Noncurrent
Financing of consumers' debts	217,944	-	-	217,944	198,875
Free Energy	5,976	-	-	5,976	5,436
CCEE transactions	41,301	-	-	41,301	41,301
	265,221	-	-	265,221	245,612
Allowance for doubtful accounts				(28,683)	(42,427)
Total				236,539	203,185

F - 22

 

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) tax 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:

	Consumers, concessionaires and licensees	Other receivables (note 11)	Total
As 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	44,405
Write-off of accrued receivables	89,770	1,930	91,700
As 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	82,998
Write-off of accrued receivables	144,289	3,000	147,289
As of December 31, 2016	(261,525)	(27,992)	(289,517)
Allowance - reversal (recognition)	(263,668)	(1,439)	(265,107)
Recovery of revenue	110,008	-	110,008
Write-off of accrued receivables	148,309	52	148,361
As of December 31, 2017	(266,876)	(29,379)	(296,255)
Current	(238,193)	(29,379)	(267,572)
Noncurrent	(28,683)	-	(28,683)

F - 23

 

The allowance for doubtful debts is set up based on the history and probability of default and, specifically for distributors, according to the following criteria:

Class	Past due over:
Residential	90 days
Commercial	180 days
Other classes	360 days
Sundry bills	180 days
Debts in installments	90 days. In the event of default in one of the installments, the whole  receivable from the customer is subject to impairment.

F - 24

 

( 7 )TAXES RECOVERABLE

	Dec 31, 2017	Dec 31, 2016
Current
Prepayments of social contribution - CSLL	7,257	14,141
Prepayments of income tax - IRPJ	21,887	35,534
Income tax and social contribution to be offset	59,658	94,268
Income tax and social contribution recoverable	88,802	143,943
Withholding income tax - IRRF on interest on capital	43,841	3,642
Withholding income tax - IRRF	103,277	115,189
State VAT - ICMS to be offset	104,843	82,090
Social Integration Program - PIS	8,447	9,062
Contribution for Social Security Funding - COFINS	37,699	39,984
National Social Security Institute - INSS	7,597	6,374
Others	541	3,564
Other taxes recoverable	306,244	259,905
Total current	395,046	403,848
Noncurrent
Social contribution to be offset - CSLL	58,856	55,498
Income tax to be offset - IRPJ	2,608	10,037
Income tax and social contribution recoverable	61,464	65,535
State VAT - ICMS to be offset	159,624	122,415
Social Integration Program - PIS	1,024	800
Contribution for Social Security Funding - COFINS	4,719	3,687
Others	6,613	5,849
Other taxes recoverable	171,980	132,751
Total noncurrent	233,444	198,286

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.

( 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, 2016			Operating revenue		Finance income /expense	Receipt	As of December 31, 2017
	Deferred	Approved	Total	Constitution	Realization	Monetary adjustment	Tariff flag (note 27.5)	Deferred	Approved	Total
Parcel "A"	(762,573)	190,369	(572,203)	1,187,928	536,269	(76,726)	(386,242)	924,943	(235,916)	689,026
CVA (*)
CDE (**)	(342,161)	(70,301)	(412,462)	(405,409)	356,715	(38,267)	-	(235,901)	(263,520)	(499,422)
Electric energy cost	(506,490)	(239,777)	(746,267)	2,018,754	751,840	(31,144)	(385,704)	1,625,759	(18,280)	1,607,479
ESS and EER (***)	(406,568)	(124,411)	(530,979)	(1,003,482)	450,638	(57,165)	(151)	(974,091)	(167,048)	(1,141,139)
Proinfa	3,492	31,414	34,906	(28,048)	(18,829)	(6,600)	-	(610)	(17,961)	(18,572)
Basic network charges	27,527	9,660	37,187	1,448	(35,035)	(376)	-	(20,163)	23,387	3,224
Pass-through from Itaipu	147,012	442,911	589,923	1,022,892	(570,453)	43,016	-	959,518	125,860	1,085,378
Transmission from Itaipu	7,646	7,281	14,927	13,992	(13,705)	394	-	7,802	7,806	15,608
Neutrality of industry charges	142,091	164,375	306,466	89,103	(258,685)	7,767	-	32,566	112,084	144,651
Overcontracting	164,878	(30,782)	134,096	(521,321)	(126,217)	5,648	(387)	(469,937)	(38,244)	(508,181)
Other financial components	(182,958)	(159,759)	(342,717)	(72,877)	249,516	(5,607)	-	(193,496)	21,812	(171,685)
Refunds related to judicial injuctions	(76,615)	(132,410)	(209,025)	(10,038)	190,291	805	-	-	(27,968)	(27,968)
Others	(106,343)	(27,349)	(133,692)	(62,839)	59,226	(6,412)	-	(193,496)	49,780	(143,717)
Total	(945,530)	30,612	(914,918)	1,115,051	785,786	(82,333)	(386,242)	731,447	(214,104)	517,341
Current assets			-							210,834
Noncurrent assets			-							355,003
Current liabilities			(597,515)							(40,111)
Noncurrent liabilities			(317,406)							(8,385)

F - 25

 

	As of December 31, 2015			Operating revenue		Finance income/cost	Receipt		As of December 31, 2016
	Deferred	Approved	Total	Constitution	Through billing	Monetary adjustment	Tariff flag (note 27.5)	Business Combination	Deferred	Approved	Total
Parcel "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	34,906
Basic network charges	28,185	68,289	96,474	19,517	(84,894)	(1,449)	-	7,539	27,527	9,660	37,187
Pass-through from Itaipu	1,281,279	39,416	1,320,695	(116,276)	(921,201)	197,581	-	109,124	147,012	442,911	589,923
Transmission from Itaipu	11,372	4,097	15,469	8,102	(13,754)	2,163	-	2,948	7,646	7,281	14,927
Neutrality of industry charges	187,765	2,508	190,273	198,274	(171,420)	15,730	-	73,609	142,091	164,375	306,466
Overcontracting	67,127	77,578	144,705	(48,195)	73,600	(31,037)	(439)	(4,537)	164,878	(30,782)	134,096
Other 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)

(*) Deferred tariff costs and gains variations from Parcel “A” items

(**) Energy Development Account – CDE

(***) System Service Charge (ESS) and Reserve Energy Charge (EER)

a) CVA

Refers to the variations of the Parcel “A” account, in accordance with note 3.14. These amounts are adjusted 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 based on SELIC rate and are compensated in the subsequent tariff processes.

d) Other financial components

F - 26

 

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, Companhia Luz e Força Santa Cruz, Companhia Leste Paulista, Companhia Jaguari de Energia, Companhia Sul Paulista de Energia, Companhia Luz e Força de Mococa (grouped in 2017 under the trade name “CPFL Santa Cruz” as mentioned in note 14.4.2); (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 taxaassets and liabilities

	Dec 31, 2017	Dec 31, 2016
Social contribution credit (debit)
Tax losses carryforwards	103,903	123,389
Tax benefit of merged goodwill	105,065	86,377
Temporarily nondeductible differences	(305,677)	(332,750)
Subtotal	(96,708)	(122,984)
Income tax credit (debit)
Tax losses carryforwards	303,543	358,683
Tax benefit of merged goodwill	342,262	295,987
Temporarily nondeductible differences	(844,948)	(923,383)
Subtotal	(199,141)	(268,713)
PIS and COFINS credit (debit)
Temporarily nondeductible differences	(10,543)	(9,580)
Total	(306,392)	(401,276)
Total tax credit	943,199	922,858
Total tax debit	(1,249,591)	(1,324,134)

9.2 - Tax benefit of merged intangible

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 14.

	December 31, 2017		December 31, 2016
	Social contribution	Income tax	Social contribution	Income tax
CPFL Paulista	45,872	127,421	50,497	140,270
CPFL Piratininga	11,215	38,491	12,251	42,044
RGE	21,513	88,843	23,629	97,584
RGE Sul	26,466	73,515	-	-
CPFL Geração	-	13,992	-	16,090
Total	105,065	342,262	86,377	295,987

F - 27

 

9.3 - Accumulated balances of temporarily nondeductible/nontaxable differences

	December 31, 2017			December 31, 2016
	Social contribution	Income tax	PIS/COFINS	Social contribution	Income tax	PIS/COFINS
Temporarily nondeductible differences
Provision for tax, civil and labor risks	53,687	149,130	-	45,065	125,182	-
Private pension fund	2,331	6,476	-	1,711	4,753	-
Allowance for doubtful debts	27,354	75,985	-	26,543	73,729	-
Accrued energy from the Free Market	8,382	23,284	-	7,718	21,440	-
Research and development and energy efficiency programs	21,851	60,697	-	17,474	48,538	-
Personnel-related provisions	4,111	11,420	-	3,422	9,506	-
Depreciation rate difference	5,535	15,374	-	6,200	17,223	-
Derivatives	(48,848)	(135,690)	-	(54,368)	(151,023)	-
Recognition of concession - adjustment of intangible asset (IFRS)	(7,291)	(20,253)	-	(8,355)	(23,208)	-
Recognition of concession - adjustment of financial asset (IFRS)	(117,527)	(324,387)	(7,881)	(104,080)	(287,990)	(6,157)
Actuarial losses  (IFRS)	25,716	71,432	-	25,390	70,527	-
Financial instruments (IFRS)	(5,291)	(14,694)	-	(10,022)	(27,838)	-
Accelerated depreciation	(104)	(288)	-	(73)	(204)	-
Others	(15,699)	(41,527)	(2,662)	4,491	12,281	(3,423)
Temporarily nondeductible differences - accumulated comprehensive income:
Property, plant and equipment  - adjustment of deemed cost (IFRS)	(51,961)	(144,336)	-	(55,223)	(153,398)	-
Actuarial losses (IFRS/CPC)	36,607	101,687	-	49,698	138,051	-
Temporarily nondeductible differences - Business combination - CPFL Renováveis
Deferred taxes - asset:
Provision for tax, civil and labor risks	13,188	36,635	-	-	-	-
Fair value of property, plant and equipment (negative value added of assets)	21,294	59,150	-	22,771	63,252	-
Deferred taxes - liability:
Fair value of property, plant and equipment (value added of assets)	(25,811)	(71,699)	-	(27,472)	(76,310)	-
Value added derived from determination of deemed cost	(62,354)	(173,207)	-	(78,443)	(217,897)	-
Intangible asset - exploration right/authorization in indirect subsidiaries acquired	(184,703)	(513,064)	-	(183,443)	(509,563)	-
Other temporary differences	(6,145)	(17,071)	-	(21,754)	(60,435)	-
Total	(305,677)	(844,947)	(10,543)	(332,750)	(923,383)	(9,580)

F - 28

 

9.4 - Reconciliation of the income tax and social contribution amounts recognized in the statements of income for the years ended December 31, 2017, 2016 and 2015:

	2017		2016		2015
	Social contribution	Income tax	Social contribution	Income tax	Social contribution	Income tax
Profit before taxes	1,846,670	1,846,670	1,380,547	1,380,547	1,454,454	1,454,454
Reconciliation to reflect effective rate:
Equity interest in associates and joint ventures	(312,390)	(312,390)	(311,414)	(311,414)	(216,885)	(216,885)
Amortization of intangible asset acquired	48,649	62,756	48,649	62,756	84,484	108,797
Effect of presumed profit regime	(352,101)	(430,296)	(175,110)	(234,827)	(186,546)	(244,541)
Adjustment of revenue from excess demand and excess reactive power	134,778	134,778	119,272	119,272	117,374	117,374
Tax incentive - operating profit	-	(71,340)	-	(112,232)	-	(85,760)
Other permanent additions (exclusions), net	74,015	82,631	6,420	(24,063)	42,310	59,450
Tax base	1,439,621	1,312,809	1,068,364	880,040	1,295,193	1,192,890
Statutory rate	9%	25%	9%	25%	9%	25%
Tax credit (debit)	(129,566)	(328,202)	(96,153)	(220,010)	(116,567)	(298,223)
Recognized (unrecognized) tax credit, net	(39,162)	(106,699)	(54,706)	(130,621)	(43,595)	(120,792)
Total	(168,728)	(434,901)	(150,859)	(350,631)	(160,162)	(419,015)
Current	(153,543)	(387,076)	(244,015)	(623,183)	(10,916)	(1,944)
Deferred	(15,185)	(47,825)	93,156	272,552	(149,246)	(417,071)

Amortization of intangible asset acquired–Refers to the nondeductible portion of amortization of intangible assets derived from the acquisition of investees (note 14).

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.

The deferred income tax and social contribution expense recorded in the statement of profit or loss in the amount of R$ 63,010 refers to (i) income tax and social contribution losses (R$ 74,626); (ii) tax benefit of the merged intangible (R$ 35,018) and (iii) temporary differences (revenue of R$ 46,634).

9.5 Income tax and social contribution amounts recognized in equity

The deferred income tax and social contribution recognized directly in equity (other comprehensive income) in 2017, 2016 and 2015 were as follows:

	2017		2016		2015
	Social Contribution	Income tax	Social Contribution	Income tax	Social Contribution	Income tax
Actuarial losses (gains)	(166,857)	(166,857)	527,436	527,436	(84,635)	(84,635)
Limits on the asset ceiling	21,399	21,399	(8,738)	(8,738)	7,984	7,984
Basis of calculation	(145,458)	(145,458)	518,698	518,698	(76,651)	(76,651)
Statutory rate	9%	25%	9%	25%	9%	25%
Calculated taxes	13,092	36,365	(46,683)	(129,675)	6,899	19,163
Limitation on recognition (reversal) of tax credits	-	-	13,720	38,112	(3,959)	(10,998)
Taxes recognized in other comprehensive income	13,092	36,365	(32,962)	(91,562)	2,940	8,165

F - 29

 

9.6 Unrecognized deferred tax assets

As of December 31, 2017, the parent company has tax credits on tax loss carryforwards that were not recognized amounting to R$ 86,977 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, 2017, the main subsidiaries that have such income tax and social contribution credits are CPFL Renováveis (R$ 952,402), RGE Sul (R$248,705), Sul Geradora (R$ 72,645), CPFL Telecom (R$ 33,321) and CPFL Jaguari Geração (R$ 2,486). These tax losses can be carried forward indefinitely.

( 10 )CONCESSION FINANCIAL ASSET

	Distribution	Transmission	Total
As of December 31, 2014	3,296,837	77,779	3,374,616
Current	540,094	-	540,094
Noncurrent	2,756,744	77,779	2,834,522
Additions	330,062	37,469	367,531
Transfers to intangible assets - extended concessions	(537,198)	-	(537,198)
Adjustment of expected cash flow	414,800	-	414,800
Adjustment - financial asset measured at amortized cost	-	11,400	11,400
Cash inputs - RAP	-	(3,257)	(3,257)
Disposals	(20,788)	-	(20,788)
As of December 31, 2015	3,483,713	123,391	3,607,104
Current	-	9,630	9,630
Noncurrent	3,483,713	113,761	3,597,474
Additions	655,456	50,580	706,036
Adjustment of expected cash flow	203,452	-	203,452
Adjustment - financial asset measured at amortized cost	-	16,088	16,088
Cash inputs - RAP	-	(9,727)	(9,727)
Disposals	(25,392)	-	(25,392)
Business combination	876,281	-	876,281
As of December 31, 2016	5,193,511	180,333	5,373,844
Current	-	10,700	10,700
Noncurrent	5,193,511	169,633	5,363,144
Additions	972,254	46,261	1,018,515
Adjustment of expected cash flow	212,294	-	212,294
Adjustment - financial asset measured at amortized cost	-	27,807	27,807
Cash inputs - RAP	-	(15,677)	(15,677)
Disposals	(35,039)	-	(35,039)
Business combination	(12,338)	-	(12,338)
As of December 31, 2017	6,330,681	238,723	6,569,404
Current	-	23,736	23,736
Noncurrent	6,330,681	214,987	6,545,668

F - 30

 

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. Moreover, the difference to adjust the balance to the expected cash flow receipts (new replacement value - “VNR” - note 4) is recognized as a balancing item to the operating income account (note 25) in the statement of profit or loss for the year.

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$ 27,807 is recognized against other operating income (R$16,088 in 2016 and R$11,400 in 2015).

The balances disclosed in the "Business Combinations" line refer to the complementary amounts related to the acquisition of RGE Sul, which final recognition occurred on September 30, 2017, according to note 14.3.

F - 31

 

( 11 )OTHER ASSETS

	Current		Noncurrent
	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Advances - Fundação CESP	7,851	7,533	6,797	-
Advances to suppliers	31,981	15,787	-	-
Pledges, funds and restricted deposits	159,291	106,925	621,489	533,719
Orders in progress	167,197	203,344	5,062	-
Services rendered to third parties	8,530	9,385	-	-
Energy pre-purchase agreements	-	-	26,260	27,302
Collection agreements	661	1,273	-	-
Prepaid expenses	80,599	65,668	20,042	20,942
GSF Insurance Premium	19,629	12,722	17,359	28,935
Receivables - CDE	242,906	213,552	-	-
Advances to employees	19,658	15,940	-	-
Arrendamentos	15,684	19,281	45,290	50,541
Others	175,889	153,764	97,893	104,815
(-) Allowance for doubtful debts (note 6)	(29,379)	(27,992)	-	-
Total	900,498	797,181	840,192	766,253

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 (“PEE”) and Research and Development (“P&D”) programs. Upon the closing of the respective projects, the balances are amortized against the respective liability recognized in Other Payables (note 22).

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 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 – CDE: refer to: (i) low income subsidies totaling R$ 15,930 (R$17,239 at December 31, 2016). (ii) other tariff discounts granted to consumers amounting to R$ 224,936 (R$164,396 as of December 31, 2016) and (iii) tariff discounts – judicial injunctions totaling R$ 2,039 (R$ 31,917 as of December 31, 2016).

In 2017 the subsidiaries matched the receivables relating to CDE to the payables relating to theEnergy Development Account (CDE)(note 22) amounting to R$ 238,510, of which (i) R$ 95,978 based on a judicial injunction obtained in May 2015, and (ii) R$ 142,532 authorized by Order No. 1,576/2016.

( 12 )INVESTMENTS

	Dec 31, 2017	Dec 31, 2016
Permanent equity interests - equity method
By equity method	990,910	1,482,533
Fair value of assets, net	10,640	11,219
Total	1,001,550	1,493,753

F - 32

 

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, 2017	Dec 31, 2016	2017	2016	2015
Baesa	187,654	175,914	11,849	9,853	2,508
Enercan	176,998	562,701	85,808	117,112	74,677
Chapecoense	385,870	537,170	120,651	117,451	77,487
EPASA	240,388	206,749	94,663	67,577	63,348
Fair value adjustments of assets, net	10,640	11,219	(579)	(579)	(1,136)
	1,001,550	1,493,753	312,390	311,414	216,885

12.1 - Dividends and Interest on capital

At December 31, 2017 and 2016, the Company has the following amounts receivable from the joint ventures below, relating to dividends and interest on capital:

	Dividend		Interest on own capital		Total
Investments	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Investco	-	-	2,118	2,926	2,118	2,926
Baesa	108	89	-	-	108	89
Enercan	21,184	40,983	-	-	21,184	40,983
Chapecoense	32,734	29,329	-	-	32,734	29,329
Total	54,026	70,402	2,118	2,926	56,145	73,328

12.2 – Joint Ventures

Summarized financial information on joint ventures at December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015 is as follows:

	December 31, 2017					December 31, 2016
Joint venture	Enercan	Baesa	Chapecoense	Epasa	Joint venture	Enercan	Baesa	Chapecoense	Epasa
Current assets	182,843	124,361	329,721	319,222	Current assets	405,874	54,703	577,296	257,082
Cash and cash equivalents	48,695	17,873	116,425	74,741	Cash and cash equivalents	288,956	18,946	280,083	85,709
Noncurrent assets	1,101,291	1,030,904	2,745,989	531,527	Noncurrent assets	1,174,869	1,117,120	2,892,371	562,462
Current liabilities	291,010	121,369	426,695	157,343	Current liabilities	196,760	116,192	391,402	172,401
Borrowings and debentures	140,090	63,154	138,788	34,299	Borrowings and debentures	87,560	87,032	137,753	35,555
Other financial liabilities	4,085	17,113	67,897	993	Other financial liabilities	7,848	24,119	78,372	62,762
Noncurrent liabilities	629,850	283,456	1,892,407	242,765	Noncurrent liabilities	229,085	352,142	2,024,989	259,559
Borrowings and debentures	510,874	-	1,172,181	186,373	Borrowings and debentures	153,020	63,196	1,292,239	218,891
Other financial liabilities	25,115	265,250	716,986	-	Other financial liabilities	26,254	276,600	730,494	28,686
Equity	363,273	750,440	756,608	450,641	Equity	1,154,897	703,489	1,053,275	387,584
Net operating revenue	580,430	412,329	829,525	789,402	Net operating revenue	564,966	239,730	789,732	548,145
Operational costs and expenses	(273,339)	(265,955)	(186,638)	(518,352)	Operational costs and expenses	(137,159)	(76,985)	(140,212)	(328,093)
Depreciation and amortization	(52,773)	(50,621)	(126,811)	(35,640)	Depreciation and amortization	(53,888)	(51,429)	(126,770)	(35,075)
Interest income	32,849	4,906	24,639	6,102	Interest income	31,602	9,115	35,113	10,329
Interest expense	(31,135)	(27,986)	(183,237)	(26,197)	Interest expense	(36,275)	(23,961)	(125,192)	(23,128)
Income tax expense	(88,229)	(25,442)	(123,307)	(39,892)	Income tax expense	(121,223)	(20,401)	(106,683)	(28,011)
Profit (loss) for the year	176,113	47,385	236,570	177,458	Profit (loss) for the year	240,363	39,405	212,294	126,665
Equity Interests and voting capital	48.72%	25.01%	51.00%	53.34%	Equity Interests and voting capital	48.72%	25.01%	51.00%	53.34%

F - 33

 

	December 31, 2015
Joint venture	Enercan	Baesa	Chapecoense	Epasa
Net operating revenue	523,055	427,561	729,511	949,246
Operational 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	11,275
Interest 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	118,734
Equity 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%

At the Extraordinary General Meeting held on August 2, 2017, the shareholders of the joint venture ENERCAN approved a capital reduction by R$ 188,000 (R$ 91,599 proportional to the Company’s indirect interest), with capital decreasing to R$ 200,787 (R$ 388,787 as at December 31, 2016).

At the Extraordinary General Meeting held on October 25, 2017, the shareholders of subsidiary CERAN approved a capital reduction by R$ 350,875, with fully subscribed and paid-in capital decreasing to R$ 120,000.

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 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 thea BNDES.

12.3 – 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 - 34

 

( 13 )PROPERTY, PLANT AND EQUIPMENT

	Land	Reservoirs, dams and  water mains	Buildings, construction and improvements	Machinery and equipment	Vehicles	Furniture and fittings	In progress	Total
At December 31, 2014	182,316	1,185,614	1,517,475	5,832,005	32,328	11,660	388,088	9,149,486
Historical cost	197,393	1,637,812	1,976,212	7,521,804	43,081	22,462	388,088	11,786,852
Accumulated depreciation	(15,077)	(452,199)	(458,737)	(1,689,799)	(10,753)	(10,802)	-	(2,637,366)
Additions	-	-	168	512	-	-	583,538	584,216
Disposals	(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	471
Depreciation	(6,257)	(68,562)	(50,716)	(370,076)	(6,343)	(1,926)	-	(503,881)
Write-off of depreciation	-	139	204	3,572	379	186	-	4,480
Reclassification - depreciation	-	(68,775)	68,711	151	-	(88)	-	-
Transfers from/to other assets - depreciation	-	-	-	35	-	-	-	35
Impairment 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	9,173,217
Historical cost	198,141	1,965,641	1,516,228	7,878,838	52,947	22,323	674,166	12,308,285
Accumulated depreciation	(21,334)	(589,395)	(440,246)	(2,054,749)	(16,717)	(12,627)	-	(3,135,068)
Additions	-	171	-	236	-	-	1,084,612	1,085,019
Disposals	-	-	(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)	8,536
Transfers 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	-	5,484
Reclassification - depreciation	(1,211)	(967)	(5,374)	(1,002)	7	11	-	(8,536)
Transfers from/to other assets - depreciation	-	3	(46)	1,374	150	91	-	1,572
Impairment losses	-	-	-	-	-	-	(5,221)	(5,221)
Business combination	-	-	-	2,140	27,175	-	1,049	30,364
At December 31, 2016	176,145	1,394,162	1,153,220	6,655,391	76,217	7,562	250,302	9,712,998
Historical cost	206,330	2,060,191	1,652,934	9,066,408	106,920	21,507	250,302	13,364,592
Accumulated depreciation	(30,185)	(666,028)	(499,714)	(2,411,017)	(30,704)	(13,945)	-	(3,651,594)
Additions	-	-	-	772	2,978	-	753,137	756,887
Disposals	(22)	(132)	(140)	(32,336)	(2,248)	(635)	(8,332)	(43,845)
Transfers	2,950	400	154,737	574,944	20,434	1,484	(754,948)	-
Transfers from/to other assets - cost	(1,893)	6,393	(154,880)	98,579	(126)	(330)	11,033	(41,224)
Depreciation	(8,004)	(79,276)	(59,736)	(431,393)	(18,055)	(1,332)	-	(597,795)
Write-off of depreciation	2	124	120	9,529	1,379	387	-	11,540
Transfers from/to other assets - depreciation	(683)	(2,413)	1,930	9,690	(8)	108	-	8,624
Business Combination	-	-	-	-	(4,800)	-	-	(4,800)
Impairment losses	-	-	(474)	(14,787)	-	-	-	(15,261)
At December 31, 2017	168,494	1,319,257	1,094,777	6,870,389	75,771	7,245	251,192	9,787,125
Historical cost	207,365	2,066,850	1,652,178	9,693,512	122,540	22,026	251,192	14,015,662
Accumulated depreciation	(38,870)	(747,593)	(557,400)	(2,823,123)	(46,769)	(14,782)	-	(4,228,537)
Average depreciation rate 2017	3.86%	3.93%	3.69%	4.53%	13.09%	8.31%
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%

F - 35

 

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$ 197,305 (R$182,181 at December 31, 2016).

In accordance with IAS 23, the interest on borrowings taken by subsidiaries to finance the works is capitalized during the construction phase. During 2017, R$29,817 (R$ 54,733 in 2016 and R$ 34,212 in 2015) was capitalized in the financial statements at a rate of 8.80% p.a. (11.70% p.a. in 2016 and 11.16% p.a. in 2015).

In the financial statements, depreciation expenses are recognized in the statement of profit or loss in line item “depreciation and amortization” (note 27).

At December 31, 2017, the total amount of property, plant and equipment pledged as collateral for borrowings, as mentioned in note 16, is approximately R$ 3,903,380, mainly relating to the subsidiary CPFL Renováveis (R$ 3,841,016).

The balances disclosed in the "Business Combinations" line refer to the complementary amounts related to the acquisition of RGE Sul, which final recognition occurred on September 30, 2017, according to note 14.3.

13.1 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.

In 2016, a provision of R$ 5,221 was recognized in subsidiary CPFL Telecom for the impairment of cash-generating units, for 2017 the recognition of an additional provision was not necessary. In 2017, due to the changes in the Brazilian political, economic and energy scenario, the subsidiary CPFL Renováveis recognized a loss of R$ 15,261 relating to property, plant and equipment of the Bio Baia Formosa and Solar Tanquinho projects. This loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 27).

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 29). Additionally, during 2017 and 2016 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).

F - 36

 

( 14 )INTANGIBLE ASSETS

		Concession right
	Goodwill	Acquired in business combinations	Distribution infrastructure - operational	Distribution infrastructure - in progress	Public utilities	Other intangible assets	Total
As of December 31, 2014	6,115	4,658,210	3,734,606	414,574	30,162	86,503	8,930,171
Historical cost	6,152	7,441,935	9,526,355	414,574	35,840	195,577	17,620,433
Accumulated Amortization	(37)	(2,783,725)	(5,791,748)	-	(5,678)	(109,074)	(8,690,262)
Additions	-	-	-	879,851	-	9,298	889,149
Amortization	-	(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	-	-	537,198
Disposal 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	9,210,338
Historical cost	6,152	7,441,902	10,348,857	499,627	35,840	192,626	18,525,004
Accumulated Amortization	(37)	(3,086,356)	(6,099,675)	-	(7,097)	(121,500)	(9,314,665)
Additions	-	-	-	1,213,924	-	10,507	1,224,431
Amortization	-	(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	-	-	1,870,268
Impairment 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	10,775,613
Historical cost	6,152	7,602,941	11,987,109	666,008	35,840	183,138	20,481,188
Accumulated Amortization	(37)	(3,136,425)	(6,436,607)	-	(8,516)	(123,990)	(9,705,575)
Additions	-	-	-	1,898,434	-	9,344	1,907,778
Amortization	-	(286,215)	(639,292)	-	(1,419)	(9,390)	(936,318)
Transfer - intangible assets	-	-	814,643	(814,643)	-	-	-
Transfer - financial asset	-	-	131	(972,385)	-	-	(972,254)
Disposal and transfer - other assets	-	(16,244)	(91,214)	48,061	-	1,723	(57,674)
Corporate restructuring - note 14.4.1	-	(26,766)	(73,215)	-	-	-	(99,981)
Impairment losses	-	(5,129)	-	-	-	(47)	(5,176)
Business combination	-	(15,057)	(7,108)	-	-	-	(22,165)
As of December 31, 2017	6,115	4,117,105	5,554,447	825,476	25,904	60,777	10,589,824
Historical cost	6,152	7,558,645	11,442,528	825,476	35,840	174,407	20,043,048
Accumulated Amortization	(37)	(3,441,540)	(5,888,080)	-	(9,936)	(113,630)	(9,453,223)

F - 37

 

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 27).

In accordance with IAS 23, the interest on borrowings taken by subsidiaries is capitalized for qualifying intangible assets. In the financial statements, in 2017 R$20,726  was capitalized (R$ 13,349 in 2016 and R$ 11,358 in 2015) at a rate of 8.17% p.a. (7.74% p.a. in 2016 and 7.53% p.a. in 2015).

The balances disclosed in the "Business Combinations" line refer to the complementary amounts related to the acquisition of RGE Sul, which final recognition occurred on September 30, 2017, according to note 14.3.

14.1Intangible 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:

	Dec 31, 2017			Dec 31, 2016	Annual amortization rate
	Historical cost	Accumulated amortization	Net value	Net value	2017	2016	2015
Intangible asset - acquired in business combinations
Intangible asset acquired, not merged
Parent company
CPFL Paulista	304,861	(207,003)	97,858	107,843	3.28%	3.28%	4.78%
CPFL Piratininga	39,065	(25,040)	14,025	15,319	3.31%	3.31%	4.50%
RGE	3,150	(1,827)	1,323	1,457	4.25%	4.24%	5.51%
CPFL Geração	54,555	(35,488)	19,067	20,912	3.38%	3.38%	5.04%
CPFL Jaguari Geração	7,896	(3,852)	4,044	4,314	3.42%	3.41%	6.36%
	409,527	(273,210)	136,317	149,845
Subsidiaries
CPFL Renováveis	3,717,093	(898,762)	2,818,331	2,995,028	4.75%	5.39%	4.35%
RGE Sul (CPFL Jaguariúna)	-	-	-	99,524	-	9.09%	-
RGE	618	(189)	429	473	7.12%	9.41%	9.41%
	3,717,711	(898,951)	2,818,760	3,095,025
Subtotal	4,127,238	(1,172,161)	2,955,077	3,244,869
Intangible asset acquired and merged
Subsidiaries
RGE	1,120,266	(885,969)	234,297	257,924	2.11%	2.11%	1.79%
RGE Sul	312,741	(33,188)	279,553	307,982	9.09%	9.09%	-
CPFL Geração	426,450	(323,463)	102,987	112,953	2.34%	2.34%	3.80%
Subtotal	1,859,457	(1,242,620)	616,837	678,859
Intangible asset acquired and merged – Reassessed
Parent company
CPFL Paulista	1,074,026	(754,666)	319,360	351,565	3.00%	3.00%	4.34%
CPFL Piratininga	115,762	(74,202)	41,560	45,395	3.31%	3.31%	4.50%
RGE	310,128	(184,343)	125,785	138,469	4.09%	4.09%	5.32%
CPFL Jaguari Geração	15,275	(8,377)	6,898	7,358	3.01%	3.01%	5.61%
Subtotal	1,515,191	(1,021,588)	493,603	542,787
Subsidiaries
RGE Sul	56,759	(5,171)	51,588	-	9.09%	-	-
Total	7,558,645	(3,441,540)	4,117,105	4,466,516

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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

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 intangible 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 Group started to adopt prospectively, for all cases, the straight-line method of amortization over the remaining concession period.

F - 39

 

14.2Impairment 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.

In 2016, a provision of R$ 2,637 was recognized in subsidiary CPFL Telecom for the impairment of cash-generating units, in the statement of profit or loss in line item “Other operating expenses” (note 27). In 2017, the subsidiary CPFL Renováveis recognized a loss of R$ 5,176 (R$ 40,433 in 2016), relating to intangible assets acquired in the business combination of the Pedra Cheirosa I and Bio Formosa projects.

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 29). Additionally, during 2017 and 2016 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.

14.3Business 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 Participações 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.

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.

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 Avenida São Borja, 2.801 – Bairro Fazenda São BorjaSão Leopoldo, State of Rio Grande do Sul.

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.

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.

F - 40

 

Additional information to the acquisition (acquisition of RGE Sul)

a)Consideration

Consideration transferred	RGE Sul October 31, 2016
Consideration directly transferred to prior shareholders	1,698,455
Reimbursements due to adjustments according 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. Consequently, as the entire amount paid was allocated to identified assets and liabilities, no residual value was allocated as goodwill on this transaction.

The allocation of the amount paid for assets and liabilities acquired was made with amounts provisionally calculated for the financial statements as at December 31, 2016, based on analyses conducted by Management itself at the time such financial statements were prepared. The final fair values presented were pending confirmation until the completion of the economic and financial appraisal report prepared by independent appraiser, completed on October 30, 2017.

As a consequence, during the measurement period, certain reclassifications were made to the amounts provisionally recorded in the financial statements as at December 31, 2016, relating to the (i) decrease in the fair value of the concession infrastructure’s intangible asset; (ii) completion of the fair value allocation and review of estimates based on acquirer management assumptions on the provision for tax, civil and labor risks; (iii) increase in the amount of trade receivables; (iv) decrease in the concession’s financial asset; (v) decrease in the intangible asset relating to the operation right, as a consequence of the revision of the assumptions used to determine the value of tangible and intangible assets; and (vi) recording of deferred income tax and social contribution balances on certain adjustments. These reclassifications are within the measurement period, pursuant to IFRS 3, and were considered immaterial for purposes of retrospectively adjust the provisional amounts recognized at the acquisition data.

The allocation of the price paid at the fair value of the assets and liabilities acquired is as follows:

	October 31, 2016	October 31, 2016
	Consolidated	Consolidated
	(provisional)	final
Current assets
Cash and cash equivalents	95,164	95,164
Consumers, concessionaries and licensees	580,945	580,945
Other current assets	89,548	89,548
Noncurrent assets
Consumers, concessionaries and licensees	54,111	79,501
Deferred tax assets	204,176	310,741
Concession financial asset	876,281	863,943
Intangible assets - Distribution infrastructure	1,456,472	1,444,401
Intangible acquired in this business combination	413,796	398,739
Other noncurrent assets	147,784	155,508
Current liabilities
Trade payables	(479,031)	(479,031)
Debentures and borrowings	(24,672)	(24,672)
Taxes, fees and contributions	(65,198)	(65,198)
Sector financial asset	(29,246)	(29,246)
Regulatory charges	(60,787)	(60,787)
Other current liabilities	(114,552)	(114,552)
Noncurrent liabilities
Debentures and borrowings	(1,131,949)	(1,131,949)
Sector financial asset	(64,935)	(64,939)
Provision for tax, civil and labor risks	(223,383)	(323,595)
Other noncurrent liabilities	(132,686)	(132,682)
Net assets acquired	1,591,839	1,591,839

F - 41

 

Goodwill arising on acquisition
Consideration paid, net	1,591,839	1,591,839
(-) Fair value of assets acquired and liabilities assumed	1,591,839	1,591,839
Goodwill	-	-

The fair values presented above were finalized are in accordance with the economic and financial appraisal report prepared by the independent expert.

The fair values of the concession financial asset and distribution infrastructure intangible assets was determined based on the expert appraisal, considering the same assumptions adopted when preparing the report for Periodic Tariff Review purposes.

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.

The final fair value of the indemnification asset is R$ 41,974, 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 provision recognized.

F - 42

 

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.

e) Contingent liabilities recognized

We present below the final contingent liabilities recognized in the amount of R$ 150,065:

	RGE Sul
	October 31, 2016
Labor lawsuits (i)	11,429
Civil lawsuits (i)	83,575
Regulatory lawsuits (i)	5,850
Environmental lawsuits (ii)	41,974
Tax lawsuits (i)	7,236
	150,065
Provisions recognized in the subsidiary	173,530
Provisions for tax, civil and labor risks	323,595

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 gross contractual amount of the receivables is R$ 703,672 and, based on independent expert, which has been confirmed by management´s assessment, R$43,226 are not expected to be received and represent, therefore, the portion that is expected to represent an impairment. Therefore, the fair value of the receivables acquired is R$ 660,446.

g) Net cash outflow on the acquisition

Consideration paid, net	1,591,839
(-) Cash and cash equivalents balance acquired	(95,164)
Cash paid in the acquisition, net	1,496,675

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h) Additional financial information

i.Net Operating Revenue and loss of the subsidiary acquired included in the consolidated financial statements in 2017:

Considering that the acquisition date was October 31, 2016, the consolidated financial statement as at December 31, 2017 comprises fully the revenue and the result of RGE Sul for the period.The Company’s consolidated financial statements for the year ended December 31, 2016 the operations of RGE Sul for the last two months of the year were consolidated by the Company:

	2016
	Net Operating Revenue	Losses
RGE Sul (November 1 to December 31, 2016)	522,677	(27,687)

ii.Combined financial information on the Net Operating Revenue and Profit for 2016, if the acquisition had occurred on January 1, 2016.

	Net operating revenue	Net profit (loss)
	January to December, 2016	January to December, 2016
CPFL Energia Consolidated	19,112,089	879,057
Results for the period when the entity was not consolidated by CPFL (*)	2,365,090	(403,839)
	21,477,179	475,218

 (*) Results for the period when the entity was not consolidated (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. The pro forma adjustments to profit for the period consider: (i) addition of the subsidiary’s result for the period in which it was not consolidated by the Company; (ii) inclusion of the amortization of the intangible asset acquired on the business combination and the amortization and disposal of the fair value of the distribution infrastructure’s intangible asset, had the acquisition occurred on January 1, 2016.

14.4Corporate restructurings

14.4.1Merger of CPFL Jaguariúna

At the Extraordinary General Meeting “EGM” held on December 15, 2017, approval was given for the merger of CPFL Jaguariúna into RGE Sul. Accordingly, the merged company was wound up and RGE Sul became the successor to its assets, rights and obligations.

At the time of the merger, the concepts of CVM Instructions No. 319/99 and  No. 349/01 were applied, which resulted in the recognition on the consolidated financial statements of an intangible asset rectifying account, generating a tax credit of R$ 99,981(note 9). To reassess its investments on the individual financial information of each entity with interests on RGE Sul, the CPFL Energia and CPFL Brasil recognized, proportionally to its investments in RGE Sul, (i) a reassessed concession intangible asset of R$ 148,487 and R$ 45,594 respectively, totaling R$194,081, corresponding to the fair value adjustment (value added) of the intangible assets relating to the distribution infrastructure and the right to operate the concession; and (ii) a net adjustment corresponding to the surplus value and decrease in  value in the amounts of R$ 66,607 and R$ 20,452, respectively, corresponding  to the fair value of the provision for tax, civil and labor risks, decrease in value of consumers, and surplus value of indemnification asset.Both amounts are non-deductible for tax purposes for the Company and for CPFL Brasil.

F - 44

 

14.4.2Grouping of subsidiaries Companhia Luz e Força Santa Cruz, Companhia Leste Paulista de Energia, Companhia Jaguari de Energia, Companhia Sul Paulista de Energia and Companhia Luz and Força de Mococa

On November 21, 2017, ANEEL through Resolution No. 6,723/2017 authorized the grouping of the power distribution companies Companhia Luz e Força Santa Cruz, Companhia Leste Paulista de Energia,  Companhia Sul Paulista de Energia, Companhia Luz e Força de Mococa and Companhia Jaguari de Energia, pursuant to Normative Resolution No. 716/2016 of May 3, 2016. Effective as of January 1, 2018, the operations of these subsidiaries are controlled only by Companhia Jaguari de Energia, which adopted the trade name “CPFL Santa Cruz”. This operation was approved by the EGM held on December 31, 2017 at the grouped companies. This grouping caused no effect in the consolidated financial statements".

( 15 )TRADE PAYABLES

	Dec 31, 2017	Dec 31, 2016
Current
System service charges	413	59,935
Energy purchased	2,248,748	1,868,950
Electricity network usage charges	252,170	121,884
Materials and services	650,538	545,468
Energy from the Free Market	145,002	131,893
Total	3,296,870	2,728,130
Noncurrent
Energy purchased	128,438	129,148
Materials and services	-	633
Total	128,438	129,781

The amounts of energy purchased recorded in noncurrent refer to the transaction made by the 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 22).

F - 45

 

( 16 )DEBTS AND BORROWINGS

	December 31, 2016						Borrowings raised	Repayments of principal	Interests, restatements and mark to market	Exchange rate variations	Interests paid	December 31, 2017
	Current		Noncurrent									Current		Noncurrent
	Interests	Principal	Interests		Principal	Total						Interests	Principal	Principal	Total
Measured at cost
Local currency
Investment	17,827	842,015	-		4,606,227	5,466,069	169,650	(1,151,289)	440,526	-	(379,542)	15,564	647,250	3,882,601	4,545,415
Rental assets	38	1,034	-		3,955	5,028	-	(1,038)	377	-	(373)	13	1,180	2,800	3,993
Financial Institutions	89,387	255,355	144,709		1,517,251	2,006,702	185,752	(515,824)	207,812	-	(343,163)	79,015	472,928	989,335	1,541,278
Others	50	59,756	-		42,370	102,176	27,209	(58,490)	5,638	-	(1,793)	32	46,125	28,584	74,741
Total at cost	107,303	1,158,159	144,709		6,169,803	7,579,974	382,611	(1,726,640)	654,353	-	(724,871)	94,624	1,167,484	4,903,320	6,165,427
Measured at fair value
Foreign currency
Financial Institutions	22,062	595,101	-		4,922,463	5,539,626	569,260	(1,315,172)	138,568	124,311	(139,596)	21,034	2,322,261	2,573,703	4,916,997
Mark to market	-	(1,764)	-		(35,651)	(37,415)	-	-	(21,137)	-	-	-	(11,375)	(47,177)	(58,552)
Total at fair value	22,062	593,337	-		4,886,812	5,502,211	569,260	(1,315,172)	117,431	124,311	(139,596)	21,034	2,310,885	2,526,526	4,858,445
Borrowing costs	-	(5,213)	-		(32,930)	(38,143)	(6,415)	-	12,742	-	-	-	(4,420)	(27,396)	(31,816)
Total	129,364	1,746,284	144,709	��	11,023,685	13,044,041	945,456	(3,041,812)	784,526	124,311	(864,467)	115,658	3,473,949	7,402,450	10,992,057

F - 46

 

Measured at amortized cost	Dec 31, 2017	Dec 31, 2016		Annual interest	Amortization	Collateral
Local currency
Investment
CPFL Paulista
FINEM V	2,883	37,078		TJLP + 2.12% to 3.3% (c)	72 monthly installments from February 2012	SGBP and CPFL Energia guarantee and receivables
FINEM V	1,892	3,638		Fixed rate 8% (c)	90 monthly installments from August 2011	SGBP and CPFL Energia guarantee and receivables
FINEM V	23,283	30,835		Fixed rate 5.5% (b)	96 monthly installments from February 2013	SGBP and CPFL Energia guarantee and receivables
FINEM VI	101,068	149,984		TJLP + 2.06% to 3.08% (e) (f)	72 monthly installments from January 2014	SGBP and CPFL Energia guarantee and receivables
FINEM VI	7,401	8,907		Fixed rate 2.5% (a)	114 monthly installments from June 2013	SGBP and CPFL Energia guarantee and receivables
FINEM VI	135,787	163,404		Fixed rate 2.5% (a)	96 monthly installments from December 2014	SGBP and CPFL Energia guarantee and receivables
FINEM VII	29,612	57,798		Fixed rate 6% (b)	96 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINEM VII	32,687	73,435		SELIC + 2.62% to 2.66% (h)	72 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINEM VII	54,259	132,622		TJLP + 2.12% to 2.66% (c) (d)	72 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINAME	16,904	25,356		Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
CPFL Piratininga
FINEM IV	1,553	19,970		TJLP + 2.12% to 3.3% (c)	72 monthly installments from February 2012	SGBP and CPFL Energia guarantee and receivables
FINEM IV	610	1,173		Fixed rate 8% (c)	90 monthly installments from August 2011	SGBP and CPFL Energia guarantee and receivables
FINEM IV	12,108	16,035		Fixed rate 5.5% (b)	96 monthly installments from February 2013	SGBP and CPFL Energia guarantee and receivables
FINEM V	29,540	43,836		TJLP + 2.06% to 3.08% (e) (f)	72 monthly installments from January 2014	SGBP and CPFL Energia guarantee and receivables
FINEM V	1,944	2,339		Fixed rate 2.5% (a)	114 monthly installments from June 2013	SGBP and CPFL Energia guarantee and receivables
FINEM V	33,791	40,664		Fixed rate 2.5% (a)	96 monthly installments from December 2014	SGBP and CPFL Energia guarantee and receivables
FINEM VI	37,052	41,620		SELIC + 2.62% to 2.66% (h)	72 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINEM VI	53,823	65,778		TJLP + 2.12% to 2.66% (c) (d)	72 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINEM VI	24,308	28,198		Fixed rate 6% (b)	96 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINAME	8,016	12,023		Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
RGE SUL
FINEP	4,481	7,757		TJLP	73 monthly installments from May 2016	Bank guarantee
FINEP	5,487	7,562		Fixed rate 5%	81 monthly installments from September 2013	Bank guarantee
RGE
FINEM V	1,745	22,444		TJLP + 2.12% to 3.3% (c)	72 monthly installments from February 2012	SGBP and CPFL Energia guarantee and receivables
FINEM V	8,932	11,828		Fixed rate 5.5% (b)	96 monthly installments from February 2013	SGBP and CPFL Energia guarantee and receivables
FINEM VI	53,994	80,126		TJLP + 2.06% to 3.08% (e) (f)	72 monthly installments from January 2014	SGBP and CPFL Energia guarantee and receivables
FINEM VI	783	942		Fixed rate 2.5% (a)	114 monthly installments from June 2013	SGBP and CPFL Energia guarantee and receivables
FINEM VI	49,930	60,085		Fixed rate 2.5% (a)	96 monthly installments from December 2014	SGBP and CPFL Energia guarantee and receivables
FINEM VII	34,001	39,442		Fixed rate 6% (b)	96 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINEM VII	58,097	65,261		SELIC + 2.62% to 2.66% (h)	72 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINEM VII	66,601	81,394		TJLP + 2.12% to 2.66% (d)	72 monthly installments from April 2016	SGBP and CPFL Energia guarantee and receivables
FINAME	4,022	6,033		Fixed rate 4.5%	96 monthly installments from January 2012	CPFL Energia guarantee
FINAME	109	168		Fixed rate 10.0%	90 monthly installments from May 2012	Liens on assets
FINAME	443	579		Fixed rate 10.0%	66 monthly installments from October 2015	Liens on assets
Companhia Luz e Força Santa Cruz
FINEM	-	9,094		Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	-	3,381		SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	-	6,062		TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
CPFL Leste Paulista
FINEM	-	3,397		Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	-	1,239		SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	-	2,224		TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
CPFL Sul Paulista			��
FINEM	-	2,412		Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	-	1,731		SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	-	3,122		TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
Companhia Jaguari de Energia (CPFL Santa Cruz)
Santander - Bank credit note	3,514	-		TJLP + 2.99% (f)	96 monthly installments from October 2015	CPFL Energia guarantee
Santander - Bank credit note	1,215	-		UMBNDES +1.99%	96 monthly installments from October 2015	CPFL Energia guarantee
Santander - Bank credit note	2,759	1,464		TJLP + 3.1%	96 monthly installments from June 2014	CPFL Energia guarantee
Santander - Bank credit note	1,077	572		UMBNDES + 2.1%	96 monthly installments from June 2014	CPFL Energia guarantee
FINEM	15,016	2,422		Fixed rate 6%	111 monthly installments from April 2015	CPFL Energia guarantee
FINEM	6,424	1,287		SELIC + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	12	-		Selic + 3.63%	36 monthly installments from December 2018	CPFL Energia guarantee
FINEM	10,612	2,321		TJLP + 2.19%	72 monthly installments from April 2015	CPFL Energia guarantee
FINEM	6,204	-		TJLP + 3.29%	36 monthly installments from December 2018	CPFL Energia guarantee
FINEM	206	-		TJLP + 3.39%	96 monthly installments from May 2019	CPFL Energia guarantee

F - 47

 

CPFL Mococa
Santander - Bank credit note	-	1,883	TJLP + 3.1%	96 monthly installments from June 2014	CPFL Energia guarantee
Santander - Bank credit note	-	736	UMBNDES + 2.1%	96 monthly installments from June 2014	CPFL Energia guarantee
Santander - Bank credit note	-	1,413	UMBNDES +1.99%	96 monthly installments from October 2015	CPFL Energia guarantee
Santander - Bank credit note	-	4,081	TJLP + 2.99% (f)	96 monthly installments from October 2015	CPFL Energia guarantee
CPFL Serviços
FINAME	1,086	1,297	Fixed rate 2.5% to 5.5%	96 monthly installments from August 2014	CPFL Energia guarantee and liens on equipment
FINAME	253	313	Fixed rate 6%	72 monthly installments from April 2016	CPFL Energia guarantee and liens on equipment
FINAME	472	668	Fixed rate 7.7% to 10%	90 monthly installments from December 2012	CPFL Energia guarantee and liens on equipment
FINAME	9,534	11,292	Fixed rate 2.5% to 5.5%	114 monthly installments from February 2013	CPFL Energia guarantee and liens on equipment
FINAME	33	47	TJLP + 4.2%	90 monthly installments from November 2012	CPFL Energia guarantee and liens on equipment
FINAME	1,839	2,249	Fixed rate 6%	90 monthly installments from October 2014	CPFL Energia guarantee and liens on equipment
FINAME	88	101	Fixed rate 6%	96 monthly installments from July 2016	CPFL Energia guarantee and liens on equipment
FINAME	5,039	5,768	Fixed rate 6%	114 monthly installments from June 2015	CPFL Energia guarantee and liens on equipment
FINAME	514	762	TJLP + 2.2% to 3.2% (c)	56 monthly installments from July 2015	CPFL Energia guarantee and liens on equipment
FINAME	3,060	3,870	Fixed rate 9.5% to 10% (c)	66 monthly installments from October 2015	CPFL Energia guarantee and liens on equipment
FINAME	1,276	1,589	Fixed rate 6% to 10% (e)	66 monthly installments from August 2016	CPFL Energia guarantee and liens on equipment
FINAME	5,216	5,832	TJLP + 3.50% (e)	48 monthly installments from June 2017	CPFL Energia guarantee and liens on equipment
FINAME	1,201	2,511	SELIC + 3.90%	48 monthly installments from June 2017	CPFL Energia guarantee and liens on equipment
FINAME	1,251	-	SELIC + 3.86%	48 monthly installments from August 2017	CPFL Energia guarantee and liens on equipment
FINAME	1,262	1,147	TJLP + 3.40%	36 monthly installments from August 2017	CPFL Energia guarantee and liens on equipment
FINAME	588	495	SELIC + 3.74%	36 monthly installments from August 2017	CPFL Energia guarantee and liens on equipment
FINAME	2,613	-	SELIC + 3.58% to 3.72%	36 monthly installments from January 2019	CPFL Energia guarantee and liens on equipment
FINAME	8,905	-	TJLP + 3.25% to 3.38%	36 monthly installments from January 2019	CPFL Energia guarantee and liens on equipment
CPFL Telecom
FINAME	-	7,448	Fixed rate 6.0% (b)	60 monthly installments from December 2016	CPFL Energia guarantee
FINEM	-	7,849	SELIC + 3.12% (h)	60 monthly installments from December 2016	CPFL Energia guarantee
FINEM	-	21,342	TJLP + 2.12% to 3.12% (c)	60 monthly installments from December 2016	CPFL Energia guarantee
FINEM	-	470	TJLP	60 monthly installments from December 2016	CPFL Energia guarantee
CPFL Transmissão Piracicaba
FINAME	14,275	16,871	Fixed rate 3.0%	96 monthly installments from July 2015	CPFL Energia guarantee
CERAN
BNDES	-	266,484	TJLP + 3.69% to 5%	208 monthly installments from December 2005	Pledge of shares; assignment of credit, concession rights and revenues
BNDES	-	48,409	UMBNDES + 5% (1)	208 monthly installments from February 2006	Pledge of shares; assignment of credit, concession rights and revenues
CPFL Renováveis
FINEM I	232,310	262,224	TJLP + 1.95%	168 monthly installments from October 2009	Pledge of the subdidiary's and PCH Holding's shares; assignment of credit and concession rights ; and liens on equipment
FINEM II	18,951	22,210	TJLP + 1.90%	144 monthly installments from June 2011	CPFL Energia and CPFL Bioenergia guarantees, liens on assets and assignment of credit rights
FINEM III	460,623	495,912	TJLP + 1.72%	192  monthly installments from May 2013	SGBP and CPFL Energia guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit rights
FINEM V	69,485	80,362	TJLP + 2.8% to 3.4%	143 monthly installments from December 2011	CPFL Renováveis guarantee; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM VI	69,619	74,737	TJLP + 2.05%	192 monthly installments from October 2013	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; and assignment of credit and concession rights
FINEM VII	119,234	138,474	TJLP + 1.92 %	156 monthly installments from October 2010	Pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM IX	17,827	25,195	TJLP + 2.15%	120 monthly installments from May 2010	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; liens on assets; assignment of credit and concession rights and real estate mortgage
FINEM X	-	230	TJLP	84 monthly installments from October 2010	Pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM XI	95,016	105,670	TJLP + 1.87% to 1.9%	168 monthly installments from January 2012	CPFL Energia guarantee; liens on assets; and assignment of credit rights
FINEM XII	297,835	317,289	TJLP and TJLP + 2.18%	192 monthly installments from July 2014	SGBP, CPFL Energia, CPFL Renováveis and Eólica Holding guarantees; pledge of the subsidiary's and Eólica Holding's shares; liens on assets; assignment of credit and concession rights
FINEM XIII	298,439	318,257	TJLP + 2.02% to 2.18%	192 monthly installments from November 2014	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of the subsidiary's shares; liens on assets; assignment of credit and concession rights
FINEM XV	23,185	27,305	TJLP + 3.44%	139 monthly installments from  September 2011	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of the subsidiary's shares; and assignment of credit and concession rights
FINEM XVI	4,335	6,418	Fixed rate 5.50%	101 monthly installments from  September 2011	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of the subsidiary's shares; and assignment of credit and concession rights
FINEM XVII	428,205	460,426	TJLP and TJLP + 2.18%	192 monthly installments from  January 2013	Bank guarantee; pledge of the subsidiary's and DESA Eólica's shares; liens on assets; and assignment of credit and concession rights
FINEM XVIII	9,044	13,763	Fixed rate 4.5%	102 monthly installments from June 2011	CPFL Energia and Bioenergia guarantees; liens on assets; and assignment of credit rights
FINEM XIX	27,579	29,559	TJLP + 2.02%	192 monthly installments from January 2014	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM XX	37,208	44,650	Fixed rate 2.5%	108 monthly installments from January 2014	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM XXI	37,583	40,281	TJLP + 2.02%	192 monthly installments from January 2014	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM XXII	32,734	39,281	Fixed rate 2.5%	108 monthly installments from January 2014	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM XXIII	1,153	1,729	Fixed rate 4.5%	102 monthly installments from June 2011	Pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM XXIV	82,632	109,580	Fixed rate 5.5%	108 monthly installments from January 2012	SGBP and CPFL Energia guarantees; liens on assets; and assignment of credit rights
FINEM XXV	83,136	87,492	TJLP + 2.18%	192 monthly installments from July 2016	SGBP and CPFL Energia guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINEM XXVI	681,912	525,011	TJLP + 2.75%	192 monthly installments from July 2017	SGBP and CPFL Energia guarantees; pledge of subsidiary's and T-16's shares; liens on assets; and assignment of credit and concession rights
FINEM XXVII	67,584	70,532	TJLP + 2,02%	162 monthly installments from November 2016	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; and assignment of credit and concession rights
FINEM XXVIII	1,415	-	TJLP	144 monthly installments from January 2018	SGBP, CPFL Energia and CPFL Renováveis guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
FINAME I	2,387	2,857	Fixed rate 2.5%	96 monthly installments from February 2015	CPFL Renováveis guarantee; and liens on assets
FINEP I	904	1,397	Fixed rate 3.5%	61 monthly installments from October 2014	Bank guarantee
FINEP II	9,516	10,445	TJLP - 1.0%	85 monthly installments from June 2017	Bank guarantee
FINEP III	4,091	5,232	TJLP + 2.0%	73 monthly installments from July 2015	Bank guarantee
BNB I	92,926	100,323	Fixed rate 9.5% to 10% and compliance bonus of 15%	168 monthly installments from January 2009	SIIF Énergies do Brasil guarantee; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
BNB II	151,428	158,364	Fixed rate 10% and compliance bonus of 15% to 25%	222 monthly installments from May 2010	BVP S.A. and bank guarantees; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
BNB III	27,138	29,020	Fixed rate 9.5% and compliance bonus of 25%	228 monthly installments from July 2009	CPFL Renováveis guarantee; pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights
NIB	57,291	67,872	IGPM + 8.63%	50 quarterly installments from June 2011	Pledge of subsidiary's shares; liens on assets; and assignment of credit and concession rights

F - 48

 

Purchase of assets
CPFL Eficiência
FINAME	2,281	2,923	Fixed rate 4.5% to 8.7%	96 monthly installments from March 2012	CPFL Energia guarantee
FINAME	81	99	Fixed rate 6%	72 monthly installments from October 2016	CPFL Energia guarantee
FINAME	171	234	TJLP + 2.70%	48 monthly installments from August 2016	CPFL Energia guarantee
FINAME	174	219	SELIC + 2.70%	48 monthly installments from August 2016	CPFL Energia guarantee
FINAME	100	121	Fixed rate 9.5%	36 monthly installments from September 2017	CPFL Energia guarantee
FINAME	515	678	Fixed rate 9.5%	48 monthly installments from February 2017	CPFL Energia guarantee and liens on equipment
FINAME	672	753	TJLP + 3.50%	48 monthly installments from August 2017	CPFL Energia guarantee and liens on equipment
Financial institutions
CPFL Paulista
Banco do Brasil - Working capital	-	380,403	104.90% of CDI (f)	2 annual installments from July 2017	CPFL Energia guarantee
CPFL Piratininga
Banco do Brasil - Working capital	-	66,951	104.90% of CDI (f)	2 annual installments from July 2017	CPFL Energia guarantee
Companhia Luz e Força Santa Cruz
Banco do Brasil - Working capital	-	50,213	104.90% of CDI (f)	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	-	6,925	CDI + 0.27% (f)	12 semiannual installments from June 2015	CPFL Energia guarantee
CPFL Leste Paulista
Banco IBM - Working capital	-	5,405	100.0% of CDI	14 semiannual installments from December 2012	CPFL Energia guarantee
Banco IBM - Working capital	-	20,955	CDI + 0.1%	12 semiannual installments from October 2014	CPFL Energia guarantee
Banco IBM - Working capital	-	15,658	CDI + 0.27%	12 semiannual installments from March 2015	CPFL Energia guarantee
Banco IBM - Working capital	-	6,993	CDI + 1.33% (f)	8 semiannual installments from January 2016	CPFL Energia guarantee
CPFL Sul Paulista
Banco do Brasil - Working capital	-	31,954	104.90% of CDI (f)	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	-	7,888	CDI + 0.27% to 1.33 (f)	12 semiannual installments from June 2015	CPFL Energia guarantee
Banco IBM - Working capital	-	6,784	CDI + 1.27%	8 semiannual installments from February 2017	CPFL Energia guarantee
Companhia Jaguari de Energia (CPFL Santa Cruz)
Banco do Brasil - Working capital	95,682	4,413	104.90% of CDI (f)	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	35,895	-	CDI + 0.27% (f)	12 semiannual installments from June 2015	CPFL Energia guarantee
Banco IBM - Working capital	5,180	-	CDI + 1.33% (f)	8 semiannual installments from January 2016	CPFL Energia guarantee
Banco IBM - Working capital	5,652	-	CDI + 1.27%	8 semiannual installments from February 2017	CPFL Energia guarantee
Banco IBM - Working capital	13,111	10,726	100.0% of CDI	14 semiannual installments from December 2012	CPFL Energia guarantee
Banco IBM - Working capital	25,443	11,297	CDI + 0.1%	12 semiannual installments from October 2014	CPFL Energia guarantee
CPFL Mococa
Banco do Brasil - Working capital	-	28,911	104.90% of CDI (f)	2 annual installments from July 2017	CPFL Energia guarantee
Banco IBM - Working capital	-	3,481	100.0% of CDI	14 semiannual installments from December 2012	CPFL Energia guarantee
Banco IBM - Working capital	-	13,296	CDI + 0.27%	12 semiannual installments from March 2015	CPFL Energia guarantee
CPFL Serviços
Banco IBM - Working capital	1,279	3,473	CDI + 0.10%	11 semiannual installments from June 2013	CPFL Energia guarantee
Promissory notes	46,941	-	104.0% of CDI	1 installment in June 2018	CPFL Energia guarantee
CPFL Geração
Banco do Brasil - Working capital	630,309	641,316	109.5% of CDI	1 installment in March 2019	CPFL Energia guarantee
CPFL Telecom
Banco IBM - Working capital	-	31,449	CDI + 0.18%	12 semiannual installments from August 2014	CPFL Energia guarantee
CPFL Transmissão Morro Agudo
Santander	-	5,031	CDI + 1.60%	1 installment in March 2017	CPFL Energia guarantee
CPFL Renováveis
Bradesco	204,934	250,363	CDI + 0.5%	8 annual installment from June 2013	No collateral
Safra	194,006	208,547	105% of CDI	14 installments from August 2016	No collateral
Banco BBM - Bank credit note	44,095	44,171	CDI + 3.40%	1 installment in March 2018	No collateral
Banco BBM - Bank credit note	26,198	-	CDI + 1.90%	Bullet	CPFL Renováveis guarantee
Banco ABC - Bank credit note	-	44,217	CDI + 3.80%	1 installment in December 2017	No collateral
Deustche Bank - Bank credit note	46,966	-	CDI + 1.45%	Bullet	CPFL Renováveis promissory note
Banco ABC - Promissory notes	102,006	105,883	CDI + 3.80%	4 semiannual installments from February 2017	No collateral
Banco BBM - Promissory notes	63,582	-	CDI + 1.39%	1 installment in June 2018	CPFL Renováveis guarantee
Others
Eletrobrás
CPFL Paulista	2,410	2,960	RGR + 6% to 6.5%	120 monthly installments from January 2013	Receivables and promissory notes
RGE	3,988	5,851	RGR + 6%	120 monthly installments from May 2008	Receivables and promissory notes
RGE SUL	18,970	25,946	RGR + 6%	120 monthly installments from December 2008	Bank guarantee; assignment of credit rights; and promissory notes
CPFL Santa Cruz	-	508	RGR + 6%	120 monthly installments from January 2007	Receivables and promissory notes
CPFL Leste Paulista	-	338	RGR + 6%	120 monthly installments from February 2008	Receivables and promissory notes
CPFL Sul Paulista	-	303	RGR + 6%	120 monthly installments from August 2007	Receivables and promissory notes
CPFL Jaguari	-	9	RGR + 6%	120 monthly installments from June 2007	Receivables and promissory notes
CPFL Mococa	-	122	RGR + 6%	120 monthly installments from January 2008	Receivables and promissory notes
Others	49,372	66,141
Subtotal local currency	6,165,427	7,579,974
Foreign currency
Measured at fair value
Financial institutions
CPFL Paulista
Bank of America Merrill Lynch	332,766	327,503	US$+Libor 3 months+1.35% (3)	1 installment in october 2018	CPFL Energia guarantee and promissory notes
Bank of America Merrill Lynch	148,930	146,703	US$+Libor 3 months+1.70% (4)	1 installment in September 2018	CPFL Energia guarantee and promissory notes
Bank of Tokyo-Mitsubishi	165,826	163,279	US$ + Libor 3 months + 0.88% (3) (g)	1 installment in February 2020	CPFL Energia guarantee and promissory notes
Bank of Tokyo-Mitsubishi	124,211	163,106	US$+Libor 3 months+0.80% (3) (f)	4 semiannual installments from September 2017	CPFL Energia guarantee and promissory notes
BNP Paribas	-	68,663	Euro + 1.6350% (2)	1 installment in January 2018	CPFL Energia guarantee and promissory notes
HSBC	-	282,808	US$ + Libor 3 months + 1.30% (2)	1 installment in January 2018	CPFL Energia guarantee and promissory notes
J.P. Morgan	-	130,522	US$ + 2.28% to 2.32% (3)	1 installment in December 2017	CPFL Energia guarantee and promissory notes
J.P. Morgan	-	115,382	US$ + 2.36% to 2.39% (3)	1 installment in January 2018	CPFL Energia guarantee and promissory notes
J.P. Morgan	83,783	82,544	US$ + 2.74% (3)	1 installment in January 2019	CPFL Energia guarantee and promissory notes
J.P. Morgan	-	49,311	US$ + 2.2% (3)	1 installment in February 2018	CPFL Energia guarantee and promissory notes
Bank of America Merrill Lynch	498,061	490,334	US$ + Libor 3 months + 1.40% (3)	1 installment in February 2018	CPFL Energia guarantee and promissory notes
Mizuho Bank	248,189	244,484	US$+Libor 3 months+1.55% (3) (f)	3 semiannual installments from March 2018	CPFL Energia guarantee and promissory notes
Syndicated transaction  (**) - Bank of America Merrill Lynch, Citibank, HSBC and EDC-Export Development Canada	221,475	218,104	US$ + Libor 3 months + 2.7% (4)	5 semiannual installments from May 2019	CPFL Energia guarantee and promissory notes
CPFL Piratininga
BNP Paribas	218,814	188,822	Euro + 1.6350% (3)	1 installment in January 2018	CPFL Energia guarantee and promissory notes
Citibank	207,743	204,486	US$ + Libor 3 months + 1.41% (3)	2 annual installments from January 2019	CPFL Energia guarantee and promissory notes
Citibank	165,740	163,225	US$ + Libor 3 months + 1.35% (4)	1 installment in March 2019	CPFL Energia guarantee and promissory notes
Scotiabank	-	54,235	US$ + 2.08% (3)	1 installment in August 2017	CPFL Energia guarantee and promissory notes
Sumitomo	166,346	163,712	US$ + Libor 3 months + 1.35% (3) (f)	1 installment in April 2018	CPFL Energia guarantee and promissory notes
Syndicated transaction  (**) - Bank of America Merrill Lynch, Citibank, HSBC and EDC-Export Development Canada	221,475	218,104	US$ + Libor 3 months + 2.7% (4)	5 semiannual installments from May 2019	CPFL Energia guarantee and promissory notes
RGE
Bank of Tokyo-Mitsubishi	59,793	58,852	US$ + Libor 3 months + 0.82%(3)	1 installment in April 2018	CPFL Energia guarantee and promissory notes
Bank of Tokyo-Mitsubishi	271,893	267,740	US$ + Libor 3 months + 0.83%(3)	1 installment in May 2018	CPFL Energia guarantee and promissory notes
Syndicated transaction  (**) - Bank of America Merrill Lynch, Citibank, HSBC and EDC-Export Development Canada	221,475	218,104	US$ + Libor 3 months + 2.7% (4)	5 semiannual installments from May 2019	CPFL Energia guarantee and promissory notes
Bank of Tokyo-Mitsubishi	172,592	-	US$ + 1.9275%	1 installment in October 2018	CPFL Energia guarantee and promissory notes
HSBC	-	44,496	US$ + Libor 3 months + 1.30% (2)	1 installment in October 2017	CPFL Energia guarantee and promissory notes
J.P. Morgan	-	199,826	US$ + 2.78% (3)	1 installment in February 2018	CPFL Energia guarantee and promissory notes

F - 49

 

Companhia Luz e Força Santa Cruz
Scotiabank	-	16,556	US$ + 3.37% (4)	1 installment in July 2019	CPFL Energia guarantee and promissory notes
CPFL Sul Paulista
Scotiabank	-	16,556	US$ + 3.37% (4)	1 installment in July 2019	CPFL Energia guarantee and promissory notes
CPFL Leste Paulista
Scotiabank	-	16,556	US$ + 3.37% (4)	1 installment in July 2019	CPFL Energia guarantee and promissory notes
Companhia Jaguari de Energia (CPFL Santa Cruz)
Scotiabank	67,219	16,556	US$ + 3.37% (4)	1 installment in July 2019	CPFL Energia guarantee and promissory notes
CPFL Geração
HSBC	-	326,159	US$+Libor 3 months + 1.30% (2)	1 installment in  March 2017	CPFL Energia guarantee and promissory notes
China Construction Bank - Bank credit note	99,443	97,946	US$+Libor 3 months + 1.60% + 1.4% fee (4)	1 installment in June 2019	CPFL Energia guarantee and promissory notes
Scotiabank	119,314	117,550	US$ + 3.3703% (4)	1 installment in July 2019	CPFL Energia guarantee and promissory notes
Citibank	397,328	391,380	US$+Libor 3 months + 1.41% (3)	3 annual installments from September 2018	CPFL Energia guarantee and promissory notes
China Construction Bank - Bank credit note	33,120	32,624	US$ + Libor 3 months + 1.20% + 1.1% fee (3)	1 installment in September 2019	CPFL Energia guarantee and promissory notes
Scotiabank	165,572	163,125	US$ + 3.1259%	1 installment in December 2019	CPFL Energia guarantee
Paulista Lajeado
Banco Itaú	36,311	35,771	US$ + 3.196% (4)	1 installment in March 2018	CPFL Energia guarantee and promissory notes
CPFL Brasil
Scotiabank	45,161	44,501	US$ + 2.779% (3)	1 installment in August 2018	CPFL Energia guarantee and promissory notes
Scotiabank	11,731	-	US$ + 2.6201% (3)	1 installment in September 2020	CPFL Energia guarantee and promissory notes
Scotiabank	253,626	-	US$ + 2.2997% (3)	1 installment in September 2020	CPFL Energia guarantee and promissory notes
Scotiabank	159,060	-	US$ + 2.3073%	1 installment in October 2020	CPFL Energia guarantee and promissory notes
Mark to market	(58,552)	(37,415)
Total in foreign currency - fair value	4,858,445	5,502,211
Borrowing costs (*)	(31,816)	(38,143)
Total - Consolidated	10,992,057	13,044,041

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
(b) 40.1% to 50% of CDI	(f) 100.1% to 110% of CDI
(c) 60.1% to 70% of CDI	(g) 110.1% to 120% of CDI
(d) 70.1% to 80% of CDI	(h) 120.1% to 130% of CDI

(*) In accordance with IAS 39, this refers to the fundraising costs attributable to issuance of the respective debts, measured at cost.

(**) Syndicated transaction – borrowings in foreign currency, having as counterpart a group of financial institutions.

In conformity with IAS 32 and 39, the Group 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 reduce the accounting mismatch. At December 31, 2017, the total balance of the borrowings measured at fair value was R$4,858,445 (R$5,502,211 as of December 31, 2016).

Changes in the fair values of these borrowings are recognized in the finance income/cost of the the Group. Accumulated gains of R$ 58,552 (R$ 37,415 at December 31, 2016) on marking the borrowings to market,compensated by losses of R$51,145 (gains of R$24,504 at December 31, 2016) of marking to market the derivative financial instruments contracted as a hedge against foreign exchange variations (note 33), resulted in a total net gain of R$ 7,407 (R$ 61,919 at December 31, 2016).

F - 50

 

The maturities of the principal of borrowings recorded in non current liabilities are scheduled as follows:

2019	2,737,432
2020	1,744,143
2021	649,487
2022	453,085
2023	371,895
2024 to 2028	1,155,315
2029 to 2033	338,270
Subtotal	7,449,627
Mark to market	(47,177)
Total	7,402,450

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 debt
Index	2017	2016	Dec 31, 2017	Dec 31, 2016
IGP-M	(0.52)	7.17	0.52	0.53
TJLP	7.00	7.50	31.38	31.48
CDI	6.89	13.63	59.49	56.31
Others			8.60	11.68
			100.00	100.00

Main borrowings in the year:

Company	Bank / credit issue	Total approved	Released in 2017	Released net of fundraising costs	Interest	Loan purpose
Local currency
Companhia Luz e Força Santa Cruz, CPFL Leste Paulista, Companhia Jaguari de Energia (CPFL Santa Cruz), CPFL Sul Paulista and CPFL Mococa	FINAME (a)	6,556	6,556	6,556	Quarterly	Subsidiary's investment plan
CPFL Serviços	FINAME (a)	11,286	11,286	11,286	Quarterly	Purchase of machinery and equipment
CPFL Serviços	Promissory Notes	45,000	45,000	45,000	Bullet	Working capital
CPFL Renováveis	FINEM XXVI	764,109	146,730	142,811	Monthly	Subsidiary's investment plan
CPFL Renováveis	FINEM XXVII	87,184	1,699	1,699	Monthly	Subsidiary's investment plan
CPFL Renováveis	FINEM XXVIII	206,000	1,414	1,414	Monthly	Subsidiary's investment plan
CPFL Renováveis	BBM / Promissory Notes (a)	62,000	62,000	61,833	Due with principal	Working capital
CPFL Renováveis	Bank credit note (a)	11,000	11,000	10,794	Due with principal	Working capital
CPFL Renováveis	Bank credit note (a)	14,000	14,000	13,737	Due with principal	Working capital
CPFL Renováveis	Bank credit note (a)	1,000	1,000	981	Due with principal	Working capital
CPFL Renováveis	Bank credit note (a)	44,000	44,000	44,000	Due with principal	Working capital
CPFL Renováveis	Bank credit note (a)	2,752	2,752	2,700	Due with principal	Working capital
		1,254,887	347,437	342,811
Foreign currency
CPFL Brasil	Law 4.131 - Scotiabank	400,000	400,000	400,000	Semiannual	Working capital
RGE	Law 4.131 - Bank of Tokyo - Mitsubishi	169,260	169,260	169,260	Quarterly	Working capital
		569,260	569,260	569,260
		1,824,147	916,697	912,071

(a) the agreement has no restrictive covenants

F - 51

 

Pre-payment

CPFL Paulista – In 2017, R$ 1,093,611 were settled in advance relating to borrowings from banks J.P.Morgan, Banco do Brasil, Banco Safra, HSBC and BNP Paribas, with original maturities from December 2017 to July 2018.

CPFL Piratininga –In 2017, R$ 68,952 were settled in advance relating to borrowings from Banco do Brasil with original maturities from July 2017 to July 2018.

RGE – In 2017, R$ 200,672 were settled in advance relating to borrowings from bank J.P.Morgan, with original maturities in February 2018.

RESTRICTIVE COVENANTS

(i)BNDES:

Borrowings from the BNDES restrict the subsidiaries CPFL Paulista, CPFL Piratininga, RGE 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.

For debts to BNDES related to FINEM of these subsidiaries, in 2017 their agreements were amended with the inclusion of new financial covenants, in addition to those previously mentioned, which must be calculated annually in the consolidated financial statements of their parent companies:

(i) Maintenance, by CPFL Energia, of the following ratios:

·Net Debt to EBITDA ratio – maximum of 3.75;

·Equity / (Equity + Net Bank Debts) ratio greater than 0.28.

 (iii) Maintenance, by State Grid Brazil Power (SGBP), of the following ratios:

·Equity to Total Assets ratio greater than 0.30 (disregarding the effects of IFRIC 12).

CPFL Renováveis (calculated in indirect subsidiary CPFL Renováveis and its subsidiaries, except when mentioned in each specific item):

F - 52

 

FINEM I

·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 debt coverage ratio (ICSD) had not been complied regarding the second half of 2016, and the total amount of the debts, R$ 87,376, was classified in current liabilities, with no declaration of early maturity of the debt due. After December 31, 2016, the Companies obtained a waiver from BNDES to determine the debt coverage ratio for the second semester of 2016, due this the amount was transfer to noncurrent liabilities in January 2017. Failure to comply with the covenant also did not result in early maturity of other debts with specific cross-default conditions.

In December 2017, the subsidiary obtained from BNDES the non-declaration of early maturity of the debt for non-compliance with the DSCR in the consolidated financial statements of PCH Holding.

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.

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

FINEM V

·Maintaining the debt service coverage ratio at 1.2;

·Maintaining the own capitalization ratio at 30% or more.

FINEM VI

·Maintenance of DSCR equal to or greater than 1.2 times.

·Maintenance of Company Capitalization Ratio equal to or greater than 25%.

·Maintenance of Equity/(Equity + Net Bank Debts) ratio greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Net Bank Debt to EBITDA ratio less than or equal to 3.75 calculated in the Company’s annual consolidated financial statements.

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

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.

F - 53

 

·Maintenance of Equity/(Equity + Net Bank Debts) greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Net Bank Debt to EBITDA ratio less than or equal to 3.75 calculated in the Company’s annual consolidated financial statements.

·Maintenance of Equity/Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

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.

·If the DSCR is calculated at an amount equal to or greater than 1.3, the beneficiaries will be waived from the obligation to maintain the DSCR of the beneficiaries.

·Maintenance of Equity/(Equity + Net Bank Debts) greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Net Bank Debt to EBITDA ratio less than or equal to 3.75 calculated in the Company’s annual consolidated financial statements.

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

In December 2017, the subsidiary obtained from BNDES the non-declaration of early maturity of the debt in the event of non-compliance with the DSCR in the consolidated financial statements of Turbina 16.

FINEM XI, FINEM XXIV, FINEM XV and FINEM XVI

·Maintaining a Net Bank Debt/EBITDA ratio of 3.75 or less, determined in the Company's annual consolidated financial statements.

·Maintenance of Equity/(Equity + Net Bank Debts) ratio greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

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.

·Maintenance of Equity/(Equity + Net Bank Debts) greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

FINEM XVII

·Maintaining the annual debt service coverage ratio at 1.2;

F - 54

 

·Maintaining the annual consolidated debt service coverage ratio at 1.3 or more, determined in the consolidated financial statements of Desa Eólicas.

·If the DSCR is calculated at an amount equal to or greater than 1.3, the beneficiaries will be waived from the obligation to maintain the DSCR.

FINEM XIX and FINEM XX

·Maintenance of Debt Service Coverage Ratio of 1.2;

·Maintenance of Net Debt/EBITDA ratio of 4.6 in 2016 and 3.75 in 2017 and thereafter, determined in the consolidated financial statements of CPFL Renováveis;

·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;

·Maintenance of Equity/(Equity + Net Bank Debts) ratio greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Net Bank Debt to EBITDA ratio less than or equal to 3.75 calculated in the Company’s annual consolidated financial statements.

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

In December 2016, the subsidiary obtained a waiver from BNDES for non-compliance with the Net Debt to EBITDA ratio without declaration of early maturity of the debt for the year ended December 31, 2016.

In December 2017, the subsidiary obtained from BNDES the non-declaration of the early maturity in the event of non-compliance with the DSCR in the consolidated financial statements of Bio Alvorada and authorization for non-compliance with the Net Debt to EBITDA ratio and Equity/(Equity + Net Debt) ratio.

FINEM XXI e FINEM XXII

·Maintenance of DSCR greater than or equal to 1.2.

·Maintenance of Net Debt to EBITDA ratio less than or equal to 4.6 in 2016 and 3.75 from 2017 on, calculated in the consolidated financial statements of CPFL Renováveis;

·Maintenance of Equity / (Equity + Net Debts) ratio greater than or equal to 0.41 from 2013 to 2016 and 0.45 from 2017 on, calculated in the consolidated financial statements of CPFL Renováveis;

·Maintenance of Equity/(Equity + Net Bank Debts) ratio greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Net Bank Debt to EBITDA ratio less than or equal to 3.75 calculated in the Company’s annual consolidated financial statements.

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

In December 2017, the Company obtained a waiver from BNDES for non-compliance with the Net Debt to EBITDA ratio without declaration of early maturity of the debt for the years ended December 31, 2016 and 2017.

FINEM XXVII

·Maintenance of Debt Service Coverage Ratio of 1.2 or more;

·Maintenance of an Equity / Asset ratio of 39.5% or more.

·Maintenance of Equity/(Equity + Net Bank Debts) ratio greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Net Bank Debt to EBITDA ratio less than or equal to 3.75 calculated in the Company’s annual consolidated financial statements.

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

F - 55

 

In December 2017, the subsidiary obtained from BNDES the non-declaration of early maturity of the debt in the event of non-compliance with the DSCR in the consolidated financial statements of Mata Velha.

FINEM XXVIII

·Maintenance of DSCR greater than or equal to 1.2.

·Maintenance of Net Debt to EBITDA ratio less than or equal to 4.6 in 2016 and 3.75 from 2017 on, calculated in the consolidated financial statements of CPFL Renováveis;

·Maintenance of Equity / (Equity + Net Debts) ratio greater than or equal to 0.41 from 2013 to 2016 and 0.45 from 2017 on, calculated in the consolidated financial statements of CPFL Renováveis;

·Maintenance of Equity/(Equity + Net Bank Debts) ratio greater than 0.28 calculated in the Company’s annual consolidated financial statements;

·Maintenance of Net Bank Debt to EBITDA ratio less than or equal to 3.75 calculated in the Company’s annual consolidated financial statements.

·Maintenance of Equity to Total Assets ratio greater than 0.3 calculated annually based on the consolidated financial statements of State Grid Brazil Power.

In December 2017, the subsidiary obtained from BNDES the non-declaration of the early maturity of the debt in the event of non-compliance with the DSCR in the consolidated financial statements of Bio Coopcana and Bio Alvorada and authorization for non-compliance with the Net Debt  to EBITDA ratio and Equity/(Equity + Net Debt) ratio.

Bradesco

·Maintenance of Net Debt to EBITDA ratio less than 3.50 calculated semiannually based on the semiannual financial statements, consolidating the results of T-15 Energia S.A. with those of the SPEs, in the case of PCH Participações S.A. there is consolidation proportional to T-15’s interest in PCH Participações.

NIB

·Maintaining the half-yearly debt service coverage ratio at 1.3;

·Maintaining an indebtedness ratio of 70% or less;

·Maintaining a financing Coverage Ratio of 1.7 or more.

ii) 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 proportional 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 in the context of net indebtedness).

Various borrowings of the direct and indirect subsidiaries were subject to early maturity in the event of 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 Group’s creditors that they would not declare the early maturity of such borrowings, so which started including State Grid International Development Limited or any entity directly or indirectly controlled by State Grid Corporation of China as exception for not declaring the early maturity of the debt.

Furthermore, failure to comply with the obligations or restrictions mentioned may result in default in relation to other contractual obligations (cross default), depending on each borrowing agreement.

The Group’s management monitors these ratios on a systematic and continuous basis to ensure that the conditions are complied with. In the opinion of the Group’s management, all covenants and financial and non-financial clauses are properly complied, except as mentioned previously in relation to the indirectly-controlled entity CPFL Renováveis, at December 31, 2017.

F - 56

 

( 17 )DEBENTURES

	December 31, 2016	Debentures issued	Repayments of principal	Interests and monetary adjustment	Exchange rates	December 31, 2017
Debentures	9,067,520	2,486,000	(2,231,451)	913,313	(981,986)	9,253,396
Borrowing costs	(67,575)	(33,371)	-	24,076	-	(76,870)
Total	8,999,945	2,452,629	(2,231,451)	937,389	(981,986)	9,176,526

		December 31, 2017				December 31, 2016
	Issue	Current and noncurrent interest	Current	Noncurrent	Total	Current and noncurrent interest	Current	Noncurrent	Total
CPFL Paulista
6th Issue	Single series	-	-	-	-	47,079	198,000	462,000	707,079
7th Issue	Single series	17,134	126,250	378,750	522,134	28,913	-	505,000	533,913
8th Issue	1st series	1,669	-	215,310	216,980	-	-	-	-
8th Issue	2nd series	2,925	-	358,224	361,149	-	-	-	-
8th Issue	3rd series	1,161	-	131,397	132,558	-	-	-	-
		22,890	126,250	1,083,681	1,232,821	75,992	198,000	967,000	1,240,992
CPFL Piratininga
6th Issue	Single series	1,950	-	44,000	45,950	7,846	33,000	77,000	117,846
7th Issue	Single series	7,973	58,750	176,250	242,973	13,455	-	235,000	248,455
8th Issue	2nd series	7,669	-	246,000	253,669	-	-	-	-
8th Issue	1st series	1,174	-	61,125	62,299	-	-	-	-
		18,766	58,750	527,375	604,891	21,301	33,000	312,000	366,301
RGE
6th Issue	Single series	8,864	-	200,000	208,864	35,666	150,000	350,000	535,666
7th Issue	Single series	5,768	42,500	127,500	175,768	9,733	-	170,000	179,733
8th Issue	2nd series	7,812	-	250,000	257,812	-	-	-	-
8th Issue	1st series	2,573	-	132,573	135,146	-	-	-	-
		25,017	42,500	710,073	777,590	45,399	150,000	520,000	715,399
Companhia Luz e Força Santa Cruz
1st Issue	Single series	-	-	-	-	550	32,500	32,500	65,550
Companhia Jaguari de Energia (CPFL Santa Cruz)
1st Issue	Single series	135	32,500	-	32,635	-	-	-	-
RGE Sul
4th Issue	Single series	16,662	-	1,100,000	1,116,662	32,058	-	1,100,000	1,132,058
6th Issue	Single series	312	-	220,000	220,312	-	-	-	-
		16,974	-	1,320,000	1,336,974	32,058	-	1,100,000	1,132,058
CPFL Brasil
3rd Issue	Single series	6,059	-	400,000	406,059	11,657	-	400,000	411,657
CPFL Geração
5th Issue	Single series	3,366	546,000	-	549,366	12,969	546,000	546,000	1,104,969
6th Issue	Single series	13,671	153,318	306,682	473,671	23,228	-	460,000	483,228
7th Issue	Single series	8,978	-	635,000	643,978	16,379	-	635,000	651,379
8th Issue	Single series	3,401	-	87,905	91,306	3,369	-	85,520	88,889
9th Issue	Single series	550	-	51,672	52,221	524	-	50,278	50,802
		29,966	699,318	1,081,259	1,810,543	56,470	546,000	1,776,798	2,379,268
CPFL Energia
5th Issue	Single series	2,817	-	186,000	188,817	18,069	-	620,000	638,069
CPFL Renováveis
1st Issue - SIIF (*)	1st to 12th series	762	44,968	449,678	495,408	762	41,938	461,314	504,014
1st Issue - PCH Holding 2	Single series	260	8,701	123,391	132,352	644	8,700	132,091	141,435
1st Issue - Dobrevê	Single series	-	-	-	-	425	17,500	-	17,925
2nd Issue - Dobrevê	Single series	39,857	43,329	21,671	104,857	29,153	-	65,000	94,153
1st Issue - Pedra Cheirosa I	Single series	1,617	64,653	-	66,270	6,675	52,200	-	58,875
1st Issue - Pedra Cheirosa II	Single series	1,481	59,203	-	60,684	6,114	47,800	-	53,914
1st Issue - Boa Vista II	Single series	-	-	-	-	6,395	50,000	-	56,395
1st Issue - CPFL Renováveis	Single series	2,970	64,500	258,000	325,470	6,160	43,000	322,500	371,660
2nd Issue - CPFL Renováveis	Single series	5,531	60,000	210,000	275,531	11,486	30,000	270,000	311,486
3rd Issue - CPFL Renováveis	Single series	2,169	98,657	197,343	298,169	4,444	-	296,000	300,444
4th Issue - CPFL Renováveis	1st series	4,534	-	200,000	204,534	7,925	-	200,000	207,925
5th Issue - CPFL Renováveis	Single series	9,716	12,000	88,000	109,716	-	-	-	-
7th Issue - CPFL Renováveis	Single series	6,244	-	253,529	259,773	-	-	-	-
		75,141	456,011	1,801,612	2,332,764	80,183	291,138	1,746,905	2,118,226
CERAN
1st Issue	1st series	181	106,000	212,000	318,181	-	-	-	-
1st Issue	2nd series	121	-	212,000	212,121	-	-	-	-
		302	106,000	424,000	530,302	-	-	-	-
Borrowing costs (**)		(7,580)	(8,745)	(60,546)	(76,870)	(7,346)	(8,545)	(51,684)	(67,575)
		190,489	1,512,584	7,473,454	9,176,526	334,333	1,242,092	7,423,518	8,999,945

F-57

 

	Issue	Quantity issued		Annual Remuneration	Annual effective rate	Amortization conditions	Collateral
CPFL Paulista
6th Issue	Single series	660		CDI + 0.8%	CDI  + 0.87%	3 annual installments from July 2017	CPFL Energia guarantee
7th Issue	Single series	50,500		CDI + 0.83% (3)	CDI  + 0.89%	4 annual installments from February 2018	CPFL Energia guarantee
8th Issue	1st series	213,804		IPCA + 4.42%	IPCA + 4.42%	1 installment in September 2022	CPFL Energia guarantee
8th Issue	2nd series	355,718		IPCA + 4.66%	IPCA + 4.66%	2 annual installments from September 2023	CPFL Energia guarantee
8th Issue	3rd series	130,478		IPCA + 5.05%	IPCA + 5.05%	3 annual installments from September 2025	CPFL Energia guarantee
CPFL Piratininga
6th Issue	Single series	110		CDI + 0.8%	CDI + 0.91%	3 annual installments from July 2017	CPFL Energia guarantee
7th Issue	Single series	23,500		CDI + 0.83% (2)	CDI + 0.89%	4 annual installments from February 2018	CPFL Energia guarantee
8th Issue	2nd series	246,000		109.5% of CDI	109.5% CDI	2 annual installments from February 2021	CPFL Energia guarantee
8th Issue	1st series	60,000		IPCA + 5.2901%	IPCA + 5.2901%	2 annual installments from February 2023	CPFL Energia guarantee
RGE
6th Issue	Single series	500		CDI + 0.8%	CDI + 0.88%	3 annual installments from July 2017	CPFL Energia guarantee
7th Issue	Single series	17,000		CDI + 0.83% (3)	CDI + 0.88%	4 annual installments from February 2018	CPFL Energia guarantee
8th Issue	2nd series	250,000		111.25% of CDI	111.25% CDI	2 annual installments from February 2021	CPFL Energia guarantee
8th Issue	1st series	130,000		IPCA + 5.3473%	IPCA + 5.3473%	2 annual installments from February 2023	CPFL Energia guarantee
Companhia Luz e Força Santa Cruz
1st Issue	Single series	650		CDI + 1.4%	CDI + 1.52%	2 annual instalments from June 2017	CPFL Energia guarantee
Companhia Jaguari de Energia (CPFL Santa Cruz)
1st Issue	Single series	650		CDI + 1.4%	CDI + 1.52%	2 annual instalments from June 2017	CPFL Energia guarantee
RGE Sul
4th Issue	Single series	110,000		114.5% of CDI	120.65% of CDI	2 annual installments from October 2019	CPFL Energia guarantee
6th Issue	Single series	520,000		CDI + 0.48%	CDI + 0.48%	1 installment in December 2020	CPFL Energia guarantee
CPFL Brasil
3rd Issue	Single series	40,000		114.5% of CDI	120.04% of CDI	2 annual installments from October 2019	CPFL Energia guarantee
CPFL Geração
5th Issue	Single series	10,920		CDI + 1.4%	CDI + 1.48%	2 annual instalments from June 2017	CPFL Energia guarantee
6th Issue	Single series	46,000		CDI + 0.75% (1)	CDI + 0.75%	3 annual instalments from August 2018	CPFL Energia guarantee
7th Issue	Single series	63,500		CDI + 1.06%	CDI + 1.11%	1 installment in April 2019	CPFL Energia guarantee
8th Issue	Single series	1		IPCA + 5.86% (1)	103.33% CDI	1 installment in April 2019	CPFL Energia guarantee
9th Issue	Single series	50,000		IPCA+ 5.4764%	101.74% of CDI	1 installment in October 2021	CPFL Energia guarantee
CPFL Energia
5th Issue	Single series	62,500		114.5% of CDI	120.65% of CDI	2 annual installments from October 2019	No guarantee
CPFL Renováveis
1st Issue - SIIF	1st to 12th series	432,299,666		TJLP + 1%	TJLP + 1% + 0.6%	39 semiannual installments from 2009	Liens
1st Issue - PCH Holding 2	Single series	1,581		CDI + 1.6%	CDI + 1.8%	9 annual installments from June 2015	CPFL Renováveis guarantee
1st Issue - Dobrevê	Single series	20		CDI + 1.75%	CDI + 1.75%	3 semiannual installments from May 2016	Unsecured
2nd Issue - Dobrevê	Single series	65		CDI + 1.34%	CDI + 1.34%	3 semiannual installments from April 2018	Unsecured
1st Issue - Pedra Cheirosa I	Single series	5,220		CDI + 2.85%	CDI + 2.85%	1 installment in March 2018	CPFL Renováveis guarantee
1st Issue - Pedra Cheirosa II	Single series	4,780		CDI + 2.85%	CDI + 2.85%	1 installment in March 2018	CPFL Renováveis guarantee
1st Issue - Boa Vista II	Single series	5,000		CDI + 2.85%	CDI + 2.85%	1 installment in September 2017	CPFL Renováveis guarantee
1st Issue - CPFL Renováveis	Single series	43,000		CDI + 1.7%	CDI + 2.6%	9 annual installments from May 2015	Assignment of dividends of BVP and PCH Holding
2nd Issue - CPFL Renováveis	Single series	300,000		114.0% of CDI	129.39% CDI	5 annual instalments from June 2017	Unsecured
3rd Issue - CPFL Renováveis	Single series	29,600		117.25% of CDI	120.64% CDI	3 semiannual installments from April 2018	Unsecured
4th Issue - CPFL Renováveis	1st series	20,000		126% CDI	134.22% CDI	3 annual installments from September 2019	CPFL Energia guarantee
5th Issue - CPFL Renováveis	Single series	100,000,000		129.5% of CDI	144.46% CDI	Semiannual installments from June 2018	Assignment of 60% of quotas and credit rights of PPA contracts of Ludesa, and Dobrevê guarantee
7th Issue - CPFL Renováveis	Single series	250,000		IPCA + 5.62%	IPCA + 6.14%	Bullet	CPFL Energia guarantee
CERAN
1st Issue	1st series	318,000		107.75% of CDI	109.82% CDI	3 annual installments from December 2018	No guarantee
1st Issue	2nd series	212,000		107.75% of CDI	109.82% CDI	2 annual installments from December 2021	No guarantee
The Company and its subsidiaries hold swaps that convert the prefixed component of interest on the operation to interest rate variation in reais, corresponding to:
(1) 100.15% to 106.9% of CDI	(2) 107% to 107.9% of CDI		(3) 108% to 108.1% of CDI
(*) These debentures can be converted into shares and, therefore, are considered in the calculation of the dilutive effect for earnings per share (note 24)
(**) In accordance with IAS 39, this refers to borrowings costs attributable to issuance of the respective debt instruments.

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The maturities of the debentures recognized in noncurrent liabilities are scheduled as follows:

2019	2,549,412
2020	1,907,240
2021	1,061,702
2022	975,082
2023	423,730
2024 to 2028	556,288
Total	7,473,454

Main debentures issuances during the year

			R$ thousand
Company	Issue	Quantity issued	Released in 2017	Released net of issuance costs	Interest	Utilization
CPFL Piratininga	8th Issue	306,000	306,000	303,437	Semiannual	Subsidiary's investment plan, debt profile and working capital improvement
RGE	8th Issue	380,000	380,000	376,605	Semiannual	Subsidiary's investment plan, debt profile and working capital improvement
CPFL Paulista	8th Issue	700,000	700,000	685,463	Semiannual	Subsidiary's investment plan, debt profile and working capital improvement
RGE Sul	6th Issue	520,000	220,000	219,887	Semiannual	Subsidiary's investment plan, debt profile and working capital improvement
CPFL Renováveis - parent company (a)	5th Issue	100,000,000	100,000	97,072	Semiannual	Subsidiary's investment plan
CPFL Renováveis - parent company (a)	7th Issue	250,000	250,000	243,472	Semiannual	Subsidiary's investment plan
CERAN	1st Issue	530,000	530,000	527,708	Semiannual	Transfer of resources to shareholders
			2,486,000	2,453,644

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Pre-payment

6th issue - CPFL Paulista, CPFL Piratininga and RGE – At 2017, R$ 1,060,538 were paid of the 6th issue of debentures of the subsidiaries CPFL Paulista (R$ 681,279), CPFL Piratininga (R$ 67,610) and RGE (R$ 311,649), whose due date were July 2017 to July 2019.

5th issue of debentures - CPFL Energia – At 2017, R$ 460,194 of the Company’s 5th issue of debentures, with original maturities in October 2019 and 2020, were settled.

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. Moreover, these agreements contain restrictive non-financial covenants, which are complied with as per the last  measurement period.

CPFL Energia, CPFL Paulista, CPFL Piratininga, RGE, RGE Sul, CPFL Geração, CPFL Brasil, Companhia Jaguari de Energia (“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, 2017 contain clauses that require the subsidiary CPFL Renováveis to maintain the following financial ratios:

- 1^st 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 5.4 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.

As at December 31, 2017, the subsidiary obtained approval from debenture holders for not comply with the following ratios:

(i)Operating DSCR relating to the June 2017 calculation, through the General Meeting of Debenture Holders held on June 28, 2017;

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(ii)Operating DSCR relating to the December 2017 calculation, through the General Meeting of Debenture Holders held on June 28, 2017;

- 2^nd and 3^rd 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.

- 4^th issue of CPFL Renováveis

·Maintaining net indebtedness divided by EBITDA - maximum of 5.4 in 2016, 4.6 in 2017, 4.0 from 2018.

7ª Emissão – CPFL Renováveis

·Maintaining net indebtedness divided by EBITDA - maximum of 3.75

·Net indebtedness divided by EBITDA - maximum of 2.25

- 1^st issue of the indirect subsidiary PCH Holding 2

·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 5.4 in 2016, 4.6 in 2017, 4.0 in 2018 and 2019 and 3.75 from 2020.

- 2^nd issue of Dobrevê Energia S/A (DESA)

·Maintaining a net debt/dividend ratio less than or equal to 4.0 in 2016, 3.5 in 2017 and 3.5 in 2018.

CERAN

·Net Debt to EBITDA ratio less than or equal to 3.0, calculated semiannually.

Various borrowings of the direct and indirect subsidiaries and joint ventures were subject to early maturity in the event of 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 Group’s creditors that they would not declare the early maturity of such debentures, which started including State Grid International Development Limited or any entity directly or indirectly controlled by State Grid Corporation of China as exception for not declaring the early maturity of the debt.

Failure to comply with the restrictions mentioned may result in default in relation to other contractual obligations (cross default), depending on each agreement.

The Group’s management monitors these ratios on a systematic and continuous basis to ensure that the conditions are complied with. In the opinion of the Group’s management, all covenants and clauses are properly complied at December 31, 2017.

( 18 )PRIVATE PENSION PLAN

The subsidiaries sponsor supplementary retirement and pension plans for their employees. The main characteristics of these plans are as follows:

18.1 – Characteristics

CPFL Paulista

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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:

i.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.

ii.Mixed model, as from November 1, 1997, which covers:

·benefits for risk (disability and death), under a defined benefit plan, in which the subsidiary assumes responsibility for Plan’s actuarial deficit, and

·scheduled retirement, under a variable contribution plan, consisting of a benefit plan, which is a defined contribution plan up to the granting of the income, and does not generate any actuarial liability for the subsidiary CPFL Paulista. The benefit plan only becomes a defined benefit plan, consequently generating actuarial responsibility for the subsidiary, after the granting of a lifetime income, convertible or not into a pension.

Additionally, the subsidiary’s Managers may opt for a Free Benefit Generator Plan – “PGBL” (defined contribution), operated by either Banco do Brasil or Bradesco.

CPFL Piratininga

As a result of the spin-off of Bandeirante Energia S.A. (subsidiary’s predecessor), the subsidiary CPFL Piratininga assumed the responsibility for the actuarial liabilities of that company’s employees retired and terminated until the date of spin-off, as well as for the obligations relating to the active employees transferred to CPFL Piratininga.

On April 2, 1998, the Secretariat of Pension Plans – “SPC” approved the restructuring of the retirement plan previously maintained by Bandeirante, creating a "Proportional Supplementary Defined Benefit Plan – BSPS”, and a "Mixed Benefit Plan", with the following characteristics:

i.         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.

ii.        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.

iii.      Variable Contribution Plan – implemented together with the Defined Benefit plan effective after March 31, 1998. This is a defined contribution 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, contribution 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. Adefinedcontribution private pension plan was set up in January 2006 with Bradesco Vida e Previdência for employees hired from 1997.

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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.

Companhia Jaguari de Energia (“CPFL Santa Cruz”)

Until December 31, 2017, the subsidiaries Companhia Leste Paulista de Energia, Companhia Jaguari de Energia, Companhia Sul Paulista de Energia and Companhia Luz e Força de Mococa  had a private pension plan named CMSPREV, managed by IHPREV Fundo de Pensão, and subsidiary Companhia Luz e Força Santa Cruz had a benefits plan managed by BB Previdência - Fundo de Pensão from Banco do Brasil, both majority structured as a defined contribution plan.

After December 31, 2017, with the grouping event mentioned in note 14.4.2, the company’s official plan is the CMSPREV, managed by IHPREV Fundo de Pensão. The same plan was maintained for employees that had the benefits plan managed by BB Previdência - Fundo de Pensão from Banco do Brasil.

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.

18.2 – Changes in the defined benefit plans

	December 31, 2017
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Present value of actuarial obligations	4,615,061	1,247,462	110,801	365,924	524,293	6,863,541
Fair value of plan's assets	(3,925,061)	(1,105,738)	(94,378)	(387,322)	(446,670)	(5,959,170)
Present value of net obligations (fair value of assets)	690,000	141,724	16,424	(21,399)	77,623	904,369
Effect of asset ceiling	-	-	-	21,399	-	21,399
Net actuarial liability recognized in the statement of financial position	690,000	141,724	16,424	-	77,623	925,768

	December 31, 2016
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Present value of actuarial obligations	4,524,008	1,202,596	108,486	352,879	480,081	6,668,050
Fair 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	1,039,158

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	December 31, 2015
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Present value of actuarial obligations	3,793,259	961,329	90,609	278,985	-	5,124,182
Fair 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)	-	450,038
Effect of asset ceiling	-	-	-	8,217	-	8,217
Net actuarial liability recognized in the statement of financial position	437,670	10,308	10,277	-	-	458,255

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	Total
Present value of actuarial obligations at December 31, 2014	3,820,563	986,972	88,621	279,283	-	5,175,439
Gross current service cost	1,183	3,733	160	(131)	-	4,945
Interest on actuarial obligations	425,465	110,425	9,944	31,490	-	577,324
Participants' contributions transferred during the year	12	1,842	-	611	-	2,465
Actuarial loss: effect of changes in demographic assumptions	(226)	(614)	(12)	(6)	-	(858)
Actuarial loss: effect of changes in financial assumptions	(98,399)	(70,590)	(400)	(11,884)	-	(181,273)
Benefits paid during the year	(355,339)	(70,439)	(7,704)	(20,378)	-	(453,860)
Present value of actuarial obligations at December 31, 2015	3,793,259	961,329	90,609	278,985	-	5,124,182
Business combination	-	-	-	-	474,710	474,710
Gross current service cost	828	3,242	76	59	365	4,570
Interest on actuarial obligations	467,872	121,158	11,184	35,211	8,469	643,894
Participants' contributions transferred during the year	59	2,020	-	319	165	2,563
Actuarial loss: effect of changes in demographic assumptions	-	-	-	3,602	-	3,602
Actuarial loss: effect of changes in financial assumptions	619,803	193,652	14,909	57,793	3,613	889,770
Benefits 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
Gross current service cost	707	3,153	73	270	2,153	6,356
Interest on actuarial obligations	476,613	127,561	11,431	37,395	50,927	703,927
Participants' contributions transferred during the year	37	2,044	-	302	990	3,373
Actuarial loss: effect of changes in demographic assumptions	225	328	14	326	16,490	17,383
Actuarial loss: effect of changes in financial assumptions	(6,993)	(3,586)	(372)	(45)	8,153	(2,843)
Benefits paid during the year	(379,536)	(84,634)	(8,831)	(25,203)	(34,501)	(532,705)
Present value of actuarial obligations at December 31, 2017	4,615,061	1,247,462	110,801	365,924	524,293	6,863,541

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	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Fair 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): return on assets	61,144	22,320	8,702	5,329	-	97,495
Benefits paid during the year	355,339	70,439	7,704	20,378	-	453,860
Fair 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): return on assets	(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	475,241
Fair value of actuarial assets at December 31, 2016	(3,723,563)	(1,062,638)	(89,533)	(347,906)	(405,251)	(5,628,892)
Expected return during the year	(392,819)	(113,470)	(9,437)	(37,412)	(43,258)	(596,396)
Participants' contributions transferred during the year	(37)	(2,044)	-	(302)	(990)	(3,373)
Sponsors' contributions	(50,308)	(17,296)	(753)	(7,296)	(6,169)	(81,822)
Actuarial loss (gain): return on assets	(137,870)	5,076	(3,486)	(19,610)	(25,503)	(181,393)
Benefits paid during the year	379,536	84,634	8,831	25,203	34,501	532,705
Fair value of actuarial assets at December 31, 2017	(3,925,061)	(1,105,738)	(94,378)	(387,322)	(446,670)	(5,959,170)

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18.3 Changes in the recognized assets and liabilities

The changes in net liability are as follows:

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total liabilities
Net actuarial liability at December 31, 2016	800,445	139,958	18,954	4,972	74,830	1,039,158
Expenses (income) recognized in the statement of profit or loss	84,501	17,244	2,067	253	9,822	113,887
Sponsors' contributions transferred during the year	(50,308)	(17,296)	(753)	(7,296)	(6,169)	(81,822)
Actuarial loss (gain): effect of changes in demographic assumptions	225	328	14	326	16,490	17,383
Actuarial loss (gain): effect of changes in financial assumptions	(6,993)	(3,586)	(372)	(45)	8,153	(2,843)
Actuarial loss (gain): return on assets	(137,870)	5,076	(3,486)	(19,610)	(25,503)	(181,393)
Effect of asset ceiling	-	-	-	21,399	-	21,399
Net actuarial liability at December 31, 2017	690,000	141,724	16,424	-	77,623	925,768
Other contributions	14,436	637	158	160	-	15,391
Total liability	704,436	142,361	16,582	160	77,623	941,160

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Net actuarial liability at December 31, 2015	437,670	10,308	10,277	-	-	458,255
Business combination	-	-	-	-	59,089	59,089
Expenses (income) recognized in the statement of profit or loss	64,514	8,791	1,677	158	1,364	76,505
Sponsors' contributions transferred during the year	(48,263)	(13,405)	(843)	(9,442)	(1,437)	(73,388)
Actuarial loss (gain): effect of changes in demographic assumptions	-	-	-	3,602	-	3,602
Actuarial loss (gain): effect of changes in financial assumptions	619,805	193,653	14,911	57,795	3,613	889,773
Actuarial loss (gain): return on assets	(273,282)	(59,390)	(7,068)	(38,403)	12,200	(365,939)
Effect of asset ceiling	-	-	-	(8,738)	-	(8,738)
Net actuarial liability at December 31, 2016	800,445	139,958	18,954	4,972	74,830	1,039,158
Other contributions	12,914	133	8	228	-	13,284
Total liability	813,359	140,091	18,962	5,200	74,830	1,052,442

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Net actuarial liability at December 31, 2014	505,140	73,383	3,261	6,264	-	588,048
Expenses (income) recognized in the statement of profit or loss	51,121	8,745	413	(95)	-	60,184
Sponsors' contributions transferred during the year	(81,111)	(22,936)	(1,687)	(7,593)	-	(113,327)
Actuarial loss (gain): effect of changes in demographic assumptions	(226)	(614)	(12)	(6)	-	(858)
Actuarial loss (gain): effect of changes in financial assumptions	(98,399)	(70,590)	(400)	(11,884)	-	(181,273)
Actuarial loss (gain): return on assets	61,144	22,320	8,702	5,329	-	97,495
Effect of asset ceiling	-	-	-	7,984	-	7,984
Net actuarial liability at December 31, 2015	437,670	10,308	10,277	-	-	458,255
Other contributions	16,149	526	63	127	-	16,865
Total liability	453,819	10,834	10,340	127	-	475,120

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18.4Expected contributions and benefits

The expected contributions to the plans for 2018 are shown below:

	2018
CPFL Paulista	86,703
CPFL Piratininga	28,792
CPFL Geração	1,826
RGE	7,495
RGE Sul	6,370
Total	131,186

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

	2018	2019	2020	2021	2022 to 2027	Total
CPFL Paulista	374,545	387,635	399,573	410,879	2,663,707	4,236,339
CPFL Piratininga	84,231	88,618	92,230	96,650	667,185	1,028,914
CPFL Geração	9,010	9,252	9,572	9,829	63,274	100,937
RGE	26,223	27,396	28,545	29,487	200,079	311,730
RGE Sul	34,547	36,367	38,047	39,680	274,712	423,353
Total	528,556	549,268	567,967	586,525	3,868,957	6,101,273

At December 31, 2017, the average duration of the defined benefit obligation was 9.2 years for CPFL Paulista, 10.8 years for CPFL Piratininga, 9.4 years for CPFL Geração, 10.1 years for RGE and 11.0 years for RGE Sul.

18.5 Recognition of private pension plan income and expense

The external actuarial estimate of the expenses (income) to be recognized in 2018 and the expense (income) recognized in 2017, 2016 and 2015 is as follows:

	2018 Estimated
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Service cost	835	4,365	78	175	2,790	8,243
Interest on actuarial obligations	421,083	114,628	10,109	33,552	48,218	627,590
Expected return on plan assets	(359,588)	(102,621)	(8,634)	(35,950)	(41,166)	(547,959)
Effect of asset ceiling	-	-	-	2,035	-	2,035
Total expense (income)	62,330	16,372	1,553	(188)	9,842	89,909

	2017 Actual
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Service cost	707	3,153	73	270	2,153	6,356
Interest on actuarial obligations	476,613	127,561	11,431	37,395	50,927	703,927
Expected 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 Actual
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul*	Total
Service cost	828	3,242	76	59	365	4,570
Interest on actuarial obligations	467,872	121,158	11,184	35,211	8,469	643,894
Expected return on plan assets	(404,184)	(115,608)	(9,582)	(35,632)	(7,470)	(572,476)
Effect of asset ceiling	-	-	-	520	-	520
Total 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 Actual
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Service cost	1,183	3,733	160	(131)	-	4,945
Interest on actuarial obligations	425,465	110,425	9,944	31,490	-	577,324
Expected return on plan assets	(375,527)	(105,413)	(9,691)	(31,686)	-	(522,317)
Effect of asset ceiling	-	-	-	232	-	232
Total expense (income)	51,121	8,745	413	(95)	-	60,184

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 Sul
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016
Nominal discount rate for actuarial liabilities:	9,51% p.a.	10,99% p.a.	12,67% p.a.	9,51% p.a.	10,99% p.a.	12,67% p.a.	9,51% p.a.	10,99% p.a.
Nominal Return Rate on Assets:	9,51% p.a.	10,99% p.a.	12,67% p.a.	9,51% p.a.	10,99% p.a.	12,67% p.a.	9,51% p.a.	10,99% p.a.
Estimated Rate of nominal salary increase:	6,08% p.a. **	7% p.a.	6,79% p.a.	6,13% p.a.	8,15% p.a.	6,79% p.a.	6,1% p.a.	7,29% p.a.
Estimated Rate of nominal benefits increase:	4% p.a.	5% p.a.	5% p.a.	4% p.a.	5% p.a.	5% p.a.	4% p.a.	5% p.a.
Estimated long-term inflation rate (basis for determining the nominal rates above)	4% p.a.	5% p.a.	5% p.a.	4% p.a.	5% p.a.	5% p.a.	4% p.a.	5% p.a.
General biometric mortality table:	AT-2000 (-10)	AT-2000 (-10)	AT-2000 (-10)	BR-EMS sb v.2015	BR-EMS sb v.2015	AT-2000 (-10)	BR-EMS sb v.2015	AT-2000
Biometric table for the onset of disability:	Low Light	Low Light	Low Light	Medium Light	Medium Light	Low Light	Medium Light	Medium Light
Expected turnover rate:	ExpR_2012	ExpR_2012*	ExpR_2012*	Null	Null	ExpR_2012*	Null	Null
Likelihood of reaching retirement age:	100% when a beneficiary of the plan first becomes eligible	100% when a beneficiary of the plan first becomes eligible	100% when a beneficiary of the plan first becomes eligible	100% one year after when a beneficiary of the plan first becomes eligible	100% one year after when a beneficiary of the plan first becomes eligible	100% one year after when a beneficiary of the plan first becomes eligible	100% one year after 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%
(**) Estimated rate of nominal salary increase for CPFL Piratininga was 6.39%

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18.6 Plan assets

The following tables show the allocation (by asset segment) of the assets of the CPFL´s Group pension plans, at December 31, 2017 and 2016 managed by Fundação CESP and Fundação CEEE. The tables also show the distribution of the guarantee resources established as target for 2018, obtained in light of the macroeconomic scenario in December 2017.

Assets managed by the plans are as follows:

	Assets managed by Fundação CESP				Assets managed by Fundação CEEE
	CPFL Paulista and CPFL Geração		CPFL Piratininga		RGE		RGE Sul
	2017	2016	2017	2016	2017	2016	2017	2016
Fixed rate	77%	79%	80%	83%	79%	76%	78%	74%
Federal governament bonds	53%	60%	49%	56%	64%	61%	65%	60%
Corporate bonds (financial institutions)	4%	6%	7%	10%	9%	8%	8%	8%
Corporate bonds (non financial institutions)	1%	1%	1%	1%	3%	4%	3%	4%
Multimarket funds	2%	1%	2%	1%	2%	3%	1%	3%
Other fixed income investments	17%	12%	22%	15%	-	-	-	-
Variable income	15%	14%	14%	12%	18%	15%	18%	16%
CPFL Energia's shares	-	8%	-	6%	-	-	-	-
Investiment funds - shares	15%	6%	14%	7%	18%	15%	18%	16%
Structured investments	3%	1%	3%	1%	1%	8%	1%	8%
Equity funds	-	-	-	-	1%	7%	1%	7%
Real estate funds	-	-	-	-	1%	1%	1%	1%
Multimarket fund	3%	1%	3%	1%	-	-	-	-
Total quoted in an active market	94%	94%	97%	97%	98%	98%	97%	98%
Real estate	3%	3%	2%	2%	1%	1%	1%	1%
Transactions with participants	1%	1%	2%	2%	2%	1%	2%	2%
Other investments	1%	1%	-	-	-	-	-	-
Escrow deposits and others	1%	1%	-	-	-	-	-	-
Total not quoted in an active market	6%	6%	3%	3%	2%	2%	3%	2%

The plan assets do not hold 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 was R$417,058  at December 31, 2016.

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	Target for 2018
	Fundação CESP (*)		Fundação CEEE (*)
	CPFL Paulista and CPFL Geração	CPFL Piratininga	RGE	RGE Sul
Fixed income investments	72.80%	75.41%	80.50%	80.00%
Variable income investments	18.67%	17.11%	16.00%	16.00%
Real estate	3.18%	1.46%	0.50%	0.50%
Transactions with participants	1.32%	1.61%	1.50%	2.00%
Structured investments	2.56%	2.70%	1.50%	1.50%
Investments abroad	1.47%	1.71%	0.00%	0.00%
Total	100.00%	100.00%	100.00%	100.00%

(*) Information not audited by the independent auditors

The allocation target for 2018 was based on the recommendations for allocation of assets made at the end of 2017 by Fundação CESP and Fundação CEEE, in their Investment Policy. This target may change at any time during 2018, 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.

18.7 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 lower (higher) and if life expectancy were to decrease (increase) in one year:

	Increase (Decrease)	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul	Total
Nominal discount (p.a.)*	-0,25 p.p.	107,820	34,637	2,652	9,433	14,800	169,342
	+0,25 p.p.	(103,527)	(33,051)	(2,542)	(9,027)	(14,103)	(162,250)
General biometric mortality table**	+1 year	(101,296)	(21,786)	(2,334)	(6,452)	(9,244)	(141,112)
	-1 year	99,533	21,195	2,296	6,273	8,990	138,287
* The assumption considered in the actuarial report for the nominal discount rate was 9.51% p.a. for all companies. The projected rates are increased or decreased
by 0.25 p.p. to 9.26% p.a. and 9.76% 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; and
BREMS sb v.2015 for RGE and RGE Sul. The projections were performed with 1 year of aggravation or softening on the respective mortality tables.

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18.8 Investment riskof the private pension plan assets

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 social security 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.

( 19 )REGULATORY CHARGES

	Dec 31, 2017	Dec 31, 2016
Fee for the use of water resources	1,256	1,385
Global reversal reserve - RGR	17,545	17,469
ANEEL inspection fee - TFSEE	2,061	2,044
Energy development account - CDE	262,213	309,117
Tariff flags and others	298,525	36,064
Total	581,600	366,078

Energy development account – CDE: refer to the (i) annual CDE quota for the year 2017 in the amount of R$138,135 (R$ 164,681 as at December 31, 2016); (ii) quota intended for the reimbursement of the CDE injection for the period from January 2013 to January 2014 in the amount of R$47,429 (R$ 44,622 in December 31, 2016); 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$76,649 (R$99,814 in December 31, 2016). The subsidiaries conducted matching of accounts between the amount of CDE payable and the Accounts Receivable – CDE (note 11) in 2017, in the amount of R$ 238,510.

Tariff flags and others: refer basically to the amount to be passed on to the Centralizing Account for Tariff Flag Resources (“CCRBT”), the related amount receivable was recognized through the issuance of electricity bills (note 25.4).

( 20 )TAXES, FEES AND CONTRIBUTIONS

	Dec 31, 2017	Dec 31, 2016
Current
IRPJ (corporate income tax)	59,026	42,793
CSLL (social contribution on net income)	22,430	14,434
Income tax and social contribution	81,457	57,227
ICMS (State VAT)	403,492	416,096
PIS (tax on revenue)	32,486	28,759
COFINS (tax on revenue)	141,757	126,939
Others	51,111	52,522
Other taxes	628,846	624,316
Total current	710,303	681,544
Noncurrent
PIS (tax on revenue)	18,839	26,814

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( 21 )PROVISION FOR TAX, CIVIL AND LABOR RISKS AND ESCROW DEPOSITS

	December 31, 2017		December 31, 2016
	Provision for tax, civil and labor risks	Escrow Deposits	Provision for tax, civil and labor risks	Escrow Deposits
Labor	224,258	122,194	222,001	110,147
Civil	291,388	97,100	236,915	114,214
Tax
FINSOCIAL	33,473	95,903	32,372	90,951
Income Tax	150,020	382,884	142,790	150,439
Others	163,798	140,289	113,227	84,091
	347,291	619,077	288,389	325,481
Others	98,196	1,620	85,971	229
Total	961,134	839,990	833,276	550,072

The changes in the provision for tax, civil, labor and other risks are shown below:

	Dec 31, 2016	Additions	Reversals	Payments	Monetary Restatements	Business combination	Dec 31, 2017
Labor	222,001	98,267	(39,052)	(78,056)	26,915	(5,817)	224,258
Civil	236,915	108,147	(38,074)	(115,162)	18,298	81,264	291,388
Tax	288,389	34,005	(7,188)	(1,055)	20,351	12,791	347,291
Others	85,971	9,883	(2,508)	(12,514)	5,391	11,974	98,196
Total	833,276	250,302	(86,822)	(206,788)	70,954	100,212	961,134

The provision for tax, civil, labor and other 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 Group.

The principal pending issues relating to litigation, lawsuits and tax assessments are summarized below:

a)Labor:The main labor lawsuits relate to claims filed by former employees or labor unions for payment of salary adjustments (overtime, salary parity, severance payments and other claims).

b)Civil

Bodily injury –refer mainlyto claims for indemnities relating to accidents in the Company's electrical grids, damage to consumers, vehicle accidents, etc.

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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$147,100 (R$139,957 at December 31, 2016) 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 Group is party to other lawsuits in which Management, supported by its external legal counselors, believes that the chances of a successful outcome are possible, i.e., is not more likely than not that will have disbursement for these cases, 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, 2017 and 2016, were as follows:

	Dec 31, 2017	Dec 31, 2016	Main reasons for claims
Labor	686,538	668,005	Work accidents, risk premium for dangerousness at workplace and overtime
Civil	1,178,671	1,004,279	Personal injury, environmental impacts and overfed tariffs
Tax	5,100,151	4,611,077	ICMS, FINSOCIAL, PIS, COFINS, Social Contributions and Income tax
Regulatory	140,695	93,827	Technical, commercial and economic-financial supervisions
Total	7,106,055	6,377,188

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$ 1,224,660. In January 2016, the Company obtained court decisions that authorized the replacement of the escrow deposits regarding this claim 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 both cases, with suspensive effect, which awaits judgment by the Federal Regional Court. Concurrently, in February 2017, there was a decision for the refund of the amount related to interest incurred on one of the deposits withdrawn. Therefore, the subsidiary made an escrow deposit of R$ 206,874.

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 SMITAEmpreendimentos 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.

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As regards to labor contingencies, the Group 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 final 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 Group 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. Furthermore, in accordance with Law 13,467/17, of November 11, 2017, TR is the index for inflation adjustment used by the Labor Court since the date the law became effective.

Based on the opinion of their external legal advisers, Management of the Group and its subsidiaries consider that the registered amounts represent best estimate.

( 22 )OTHER PAYABLES

	Current		Noncurrent
	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Consumers and concessionaires	93,068	73,864	44,473	44,711
Energy efficiency program - PEE	186,621	257,622	110,931	58,798
Research & Development - P&D	103,308	75,655	68,780	55,272
EPE/FNDCT/PROCEL	15,612	12,928	-	-
Reversion fund	-	-	17,750	17,750
Advances	300,214	163,054	22,255	8,029
Tariff discounts - CDE	25,040	8,891	-	-
Provision for socio environmental costs and asset retirement	16,360	13,703	107,814	61,828
Payroll	20,747	16,951	-	-
Profit sharing	80,518	56,215	16,273	11,400
Collections agreement	72,483	69,793	-	-
Guarantees	-	-	5,959	44,140
Business combination	6,927	9,492	-	-
Others	40,408	49,454	32,654	7,364
Total	961,306	807,623	426,889	309,292

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 15).

Research and Development and Energy Efficiency Programs:the subsidiaries recognized liabilities relating to amounts already billed in tariffs (1% of Net Operating Revenue), but not yet invested in the Research and Development and Energy Efficiency Programs. These amounts are subject to adjustment for inflation at the SELIC rate, through the date of their realization.

Advances: refer mainly to advances from customers in relation to advance billing by the subsidiary CPFL Renováveis, before the energy or service has actually been provided or delivered.

Provision for socio environmental costs and asset retirement: refers mainly to provisions recognized by the subsidiary CPFL Renováveis in relation to socio environmental licenses as a result of events that have alreadyoccurred 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.

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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 Group 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 the Group’s Executives, approved by the Board of Directors, which consists in an incentive in financial resources based on salary multiples and that are driven by the company’s results and average performance in the three fiscal years after each concession.

( 23 )EQUITY

The shareholders’ interest in the Company’s equity at December 31, 2017 and 2016 is shown below:

	Number of shares
	December 31, 2017		December 31, 2016
Shareholders	Common shares	Interest %	Common shares	Interest %
State Grid Brazil Power Participações S.A.	730,435,698	71.76%	-	0.00%
ESC Energia S.A.	234,086,204	23.00%	234,086,204	23.00%
Camargo Correa S.A.	27,435	0.00%	5,897,311	0.58%
Caixa de Previdência dos Funcionários do Banco do Brasil - Previ	-	0.00%	299,787,559	29.45%
Fundação CESP	-	0.00%	51,048,952	5.02%
Fundação Sistel de Seguridade Social	-	0.00%	37,070,292	3.64%
Energia São Paulo FIA	-	0.00%	35,145,643	3.45%
Fundação Petrobras de Seguridade Social - Petros	-	0.00%	28,056,260	2.76%
Bonaire Participações S.A.	-	0.00%	1,249,386	0.12%
Fundação Sabesp de Seguridade Social - Sabesprev	-	0.00%	696,561	0.07%
BNDES Participações S.A.	-	0.00%	68,592,097	6.74%
Antares Holdings Ltda.	-	0.00%	16,967,165	1.67%
Brumado Holdings Ltda.	-	0.00%	36,497,075	3.59%
Executive Officers	189	0.00%	34,250	0.00%
Other shareholders	53,365,220	5.24%	202,785,991	19.92%
Total	1,017,914,746	100.00%	1,017,914,746	100.00%

23.1Changes in shareholding structure and Public Offering of Shares

On January 23, 2017, the Company received a correspondence from State Grid Brazil Power Participações S.A.. (“State Grid Brazil”) informing that on that date the Share Purchase Agreement between State Grid Brazil, Camargo Corrêa 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.

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. With the transaction, State Grid Brazil became the only controlling shareholder of the Company, and the Shareholders’ Agreement dated March 22, 2002 signed among the former shareholders was terminated.

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At the Company’s extraordinary general meeting held on March 27, 2017, the following resolutions were made (i) the selection of Credit Suisse (Brasil) S.A. to determine the Company’s economic value; (ii) the cancelation of the Company’s listing with the CVM as category “A”, and its conversion into category “B”; and (iii) withdrawal of the Company from the Listing Segment ofNovo Mercado.

State Grid Brazil informed, through Significant Events:

(i)on February 16, 2017, that it would conduct a public offering for acquisition of all the common shares held by the remaining shareholders of the Company (“Public Offering for Acquisition of Shares through Sale of Control”) and, on July 7, 2017, that it had decided to proceed only with the Public Offering for Acquisition of Shares through sale of control of the Company and through indirect sale of control of CPFL Renováveis;

(i)on October 30 and 31, 2017, that CVM had formally approved all relevant documents and the proceeding with the Public Offering for Acquisition of Shares through Sale of Control and, as a result of the approval, State Grid Brazil published on October 31, 2017 the Public Offering Notice with the related terms and conditions.

In a Significant Event Notice and Communication to the Market on November 30 and December 5, 2017, respectively, the Company informed that it had successfully conducted the public offering auction on the trading system of B3 S.A.– Brasil, Bolsa, Balcão (“Auction”). As a result of the auction, State Grid Brazil acquired 408,357,085 common shares of the Company, representing 88.44% of the total shares object of the Public Offering and 40.12% of the Company’s capital. The common shares were acquired for the price of R$ 27.69, totaling R$ 11,307,408. State Grid Brazil started holding, jointly with ESC Energia S.A., 964,521,902 common shares of the Company, increasing its joint interest from 54.64% to 94.75% of the Company’s total capital.

23.2Capital 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.

23.3Earnings reserves

Comprised of:

i.Legal reserve, amounting to R$ 798,090;

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$826,601 (R$ 702,928 at December 31, 2016).

23.4Accumulated 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$ 405,840;

ii.    Private pension plan: The debt balance of R$ 570,346 (net of taxes) refers to the effects of the actuarial gains and losses recognized directly in other comprehensive income, in accordance with IAS 19.

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23.5Dividends

At the Board of Directors’ Meeting held on January 5, 2017, approval was given for the declaration of interim dividend for 2016 in the amount of R$ 7,820.

Furthermore, in 2017 the Company proposed R$ 280,191 of minimum mandatory dividend, as set forth by Law 6,404/76, and for each share the amount of R$ 0.275259517 was attributed.

In 2017, the Company paid R$ 220,966 relating basically to the dividend for 2016.

23.6Allocation 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:

	2017
Profit for the year - Parent company	1,179,750
Realization of comprehensive income	25,873
Prescribed dividends	3,768
Profit base for allocation	1,209,391
Legal reserve	(58,988)
Statutory reserve - concession financial asset	(123,673)
Statutory reserve - working capital reinforcement	(746,541)
Mandatory dividend	(280,191)
Proposed addicional dividend	-

For this year, considering the current macro scenario with the incipient economic recovery and, also considering the uncertainties regarding the hydrology, the Company’s management is proposing the allocation of R$746,541 to the statutory reserve - working capital reinforcement.

23.7        Noncontrolling interests and joint ventures

The disclosure of interests in subsidiaries, in accordance with IFRS 12, is as follows:

23.7.1         Changes in noncontrolling interests

	CERAN	CPFL Renováveis	Paulista Lajeado	Total
As of December 31, 2014	214,454	2,171,911	67,427	2,453,794
Equity interests and voting capital	35.00%	48.39%	40.07%
Equity attributable to noncontrolling interests	25,990	(20,611)	4,958	10,337
Dividends	(6,173)	(2,818)	843	(8,147)
Other movements	-	7	(48)	(41)
As of December 31, 2015	234,271	2,148,490	73,182	2,455,942
Equity 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	2,402,648
Equity interests and voting capital	35.00%	48.40%	40.07%
Equity attributable to noncontrolling interests	37,949	13,720	11,623	63,292
Dividends	(92,832)	(16,619)	(8,769)	(118,220)
Capital increase (reduction)	(122,806)	15	-	(122,791)
Other movements	-	-	(113)	(113)
As of December 31, 2017	86,031	2,058,079	80,707	2,224,816
Equity interests and voting capital	35.00%	48.40%	40.07%

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23.7.2         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, 2017 and 2016, and for the years ended December 31, 2017, 2016 and 2015 are as follows:

	December 31, 2017
	CERAN	CPFL Renováveis	Paulista Lajeado
Current assets	110,566	1,623,645	48,037
Cash and cash equivalents	37,043	950,215	24,086
Noncurrent assets	848,445	11,232,357	120,677
Current liabilities	198,624	1,957,000	42,525
Borrowings and debentures	105,844	1,259,105	36,453
Other financial liabilities	12,360	7,258	264
Noncurrent liabilities	514,583	6,760,025	258
Borrowings and debentures	422,166	5,251,704	-
Other financial liabilities	83,766	-	-
Equity	245,804	4,138,977	125,931
Attributable to owners of the Company	245,804	4,032,448	125,931
Attributable to noncontrolling interests	-	106,529	-
	2017
Net operating revenue	321,743	1,959,084	38,278
Operational costs and expenses	(103,671)	(737,472)	(10,566)
Depreciation and amortization	(45,212)	(617,017)	(4)
Interest income	30,489	126,041	2,089
Interest expense	(40,202)	(648,571)	(4,050)
Income tax expense	(54,099)	(74,125)	(2,911)
Profit (loss) for the year	108,427	19,645	29,006
Attributable to owners of the Company	108,427	11,484	29,006
Attributable to noncontrolling interests	-	8,162	-

	December 31, 2016
	CERAN	CPFL Renováveis	Paulista Lajeado
Current assets	288,538	1,398,797	39,429
Cash and cash equivalents	238,241	908,982	24,688
Noncurrent assets	927,948	11,066,086	122,991
Current liabilities	121,646	1,313,466	9,586
Borrowings and debentures	60,162	889,981	324
Other financial liabilities	20,800	85,523	1,056
Noncurrent liabilities	341,356	6,713,610	36,404
Borrowings and debentures	254,732	5,517,890	36,167
Other financial liabilities	86,624	633	-
Equity	753,484	4,437,807	116,431
Attributable to owners of the Company	753,484	4,324,589	116,431
Attributable to noncontrolling interests	-	113,218	-
	2016
Net operating revenue	301,179	1,646,589	30,820
Operational costs and expenses	(67,242)	(653,459)	(27,404)
Depreciation and amortization	(48,082)	(553,169)	(3)
Interest income	28,232	112,389	2,728
Interest 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)	12,134
Attributable to owners of the Company	110,345	(151,900)	12,134
Attributable to noncontrolling interests	-	8,195	-

F-78

 

	2015
	CERAN	CPFL Renováveis	Paulista Lajeado
Net operating revenue	281,374	1,499,356	31,225
Operational costs and expenses	(71,033)	(498,005)	(22,400)
Depreciation and amortization	(45,986)	(540,578)	(7)
Interest income	17,532	115,639	2,243
Interest 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)	12,374
Attributable to owners of the Company	74,256	(54,447)	12,374
Attributable to noncontrolling interests	-	5,730	-

( 24 )EARNINGS PER SHARE

Earnings per share – basic and diluted

The calculation of the basic and diluted earnings per share at December 31, 2017, 2016 and 2015 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:

	2017	2016		2015
Numerator
Profit attributable to controlling shareholders	1,179,750	900,885		864,940
Denominator
Weighted average number of shares held by shareholders	1,017,914,746	1,017,914,746	(*)	1,017,914,746
Earnings per share - basic	1.16	0.89		0.85
Numerator
Profit attributable to controlling shareholders	1,179,750	900,885		864,940
Dilutive effect of convertible debentures of subsidiary CPFL Renováveis (**)	(11,966)	(16,153)		(19,811)
Profit attributable to controlling shareholders	1,167,784	884,731		845,129
Denominator
Weighted average number of shares held by shareholders	1,017,914,746	1,017,914,746	(*)	1,017,914,746
Earnings per share - diluted	1.15	0.87		0.83
(*) Considers the events occurred on April 29, 2016, related to the capital increase through the issuance of 24,900,531 shares (note 25). 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.
(**) Proportional to the percentage of the Company's interest in the subsidiary in the respective years.

F-79

 

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.

F-80

 

( 25 )NET OPERATING REVENUE

	Number of Consumers			In GWh			R$ thousand
Revenue from Eletric Energy Operations	2017 (*)	2016 (*)	2015 (*)	2017 (*)	2016 (*)	2015 (*)	2017	2016	2015
Consumer class
Residential	8,330,237	8,174,700	6,906,580	19,122	16,473	16,164	11,663,084	10,367,415	9,833,419
Industrial	59,825	61,112	55,586	14,661	13,022	12,748	5,095,840	5,281,978	5,526,967
Commercial	545,095	551,171	473,333	10,220	9,720	9,259	5,498,867	5,431,926	5,266,432
Rural	359,106	355,586	245,238	3,762	2,474	2,152	1,173,569	816,684	750,209
Public administration	60,639	61,208	51,359	1,456	1,271	1,278	787,967	690,389	702,152
Public lighting	11,230	11,073	10,362	1,964	1,746	1,649	654,950	580,229	545,597
Public services	9,790	9,649	8,402	2,157	1,840	1,797	978,286	901,662	879,288
(-) Adjustment of revenues from excess demand and excess reactive power	-	-	-	-	-	-	(65,991)	(72,129)	(79,362)
Billed	9,375,922	9,224,499	7,750,860	53,342	46,546	45,049	25,786,572	23,998,155	23,424,701
Own comsuption	-	-	-	34	32	33	-	-	-
Unbilled (net)	-	-	-	-	-	-	(89,575)	50,441	202,729
(-) Transfer or revenue related to the network availability for Captive Consumers	-	-	-	-	-	-	(9,273,840)	(9,055,188)	(8,118,085)
Electricity sales to final consumers	9,375,922	9,224,499	7,750,860	53,376	46,578	45,082	16,423,157	14,993,408	15,509,345
Furnas Centrais Elétricas S.A.				3,026	3,034	3,026	565,592	533,855	485,846
Other concessionaires and licensees				16,337	12,252	10,656	3,240,571	2,371,091	2,223,339
(-) Transfer or revenue related to the network availability for Captive Consumers				-	-	-	(56,528)	(50,598)	(46,982)
Spot market energy				8,194	6,173	4,289	2,340,463	641,744	875,002
Electricity sales to wholesalers				27,557	21,459	17,971	6,090,098	3,496,092	3,537,205
Revenue due to Network Usage Charge - TUSD - Captive Consumers							9,330,368	9,105,786	8,165,066
Revenue due to Network Usage Charge - TUSD - Free Consumers							2,137,566	2,057,327	1,898,138
(-) Adjustment of revenues from excess demand and excess reactive power							(21,861)	(17,908)	(16,884)
Revenue from construction of concession infrastructure							2,073,423	1,354,023	1,046,669
Sector financial asset and liability (Note 8)							1,900,837	(2,094,695)	2,506,524
Concession financial asset - Adjustment of expected cash flow (note 11)							204,443	186,148	393,343
Energy development account - CDE - Low-income, tariff discounts - judicial injunctions and other tariff discounts							1,419,128	1,266,027	895,538
Other revenues and income							496,340	438,377	367,356
Other operating revenues							17,540,244	12,295,084	15,255,750
Total gross operating revenue							40,053,498	30,784,584	34,002,212
Deductions from operating revenue
ICMS							(5,455,718)	(4,935,068)	(4,686,039)
PIS							(603,050)	(471,836)	(529,322)
COFINS							(2,777,626)	(2,172,777)	(2,438,208)
ISS							(15,929)	(10,568)	(8,204)
Global reversal reserve - RGR							(2,952)	(4,230)	(2,529)
Energy development account - CDE							(3,185,693)	(3,360,613)	(3,970,013)
Research and development and energy efficiency programs							(191,997)	(138,583)	(158,516)
PROINFA							(166,743)	(121,800)	(90,910)
Tariff flags and others							(878,460)	(430,077)	(1,796,226)
IPI							(102)	(195)	(100)
FUST and FUNTEL							(19)	(38)	(24)
Others							(30,304)	(26,709)	(22,997)
							(13,308,593)	(11,672,495)	(13,703,089)
Net operating revenue							26,744,905	19,112,089	20,599,212

F-81

 

25.1Adjustment 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 subsidiary Companhia Jaguari de Energia (“CPFL Santa Cruz”), due to the 4^th cycle of periodic tariff review, and November 2017 for CPFL Paulista and RGE Sul, 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 5^th 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.These amounts are accrued as sector financial liability, under special obligations which are being amortized, presented net in concession intangible asset, in compliance with IAS 37.

25.2 Extraordinary 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, Companhia Jaguari de Energia (“CPFL Santa Cruz”), CPFL Mococa and Companhia Luz e Força 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 B
CPFL 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%
Companhia Luz e Força Santa Cruz	10.04%	10.53%	9.78%
CPFL Leste Paulista	19.54%	24.74%	17.55%
Companhia Jaguari de Energia (CPFL Santa Cruz)	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

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25.3Periodic tariff review (“RTP”) and Annual tariff adjustment (“RTA”)

		2017		2016		2015
Subsidiary	Month	RTA	Effect perceived by consumers (a)	RTA / RTP	Effect perceived by consumers (a)	RTA / RTP	Effect perceived by consumers (a)
CPFL Paulista	April	-0.80%	-10.50%	9.89%	7.55%	41.45%	4.67%
CPFL Piratininga	October	7.69%	17.28%	-12.54%	-24.21%	56.29%	21.11%
RGE	June	3.57%	5.00%	-1.48%	-7.51%	33.48%	-3.76%
RGE Sul	April	-0.20%	-6.43%	3.94%	-0.34%	52.45%	5.46%
Companhia Luz e Força Santa Cruz	March	-1.23%	-8.42%	22.51%	7.15%	34.68%	27.96%
CPFL Leste Paulista	March	0.77%	-4.15%	21.04%	13.32%	20.80%	24.89%
Companhia Jaguari de Energia (CPFL Santa Cruz)	March	2.05%	-2.56%	29.46%	13.25%	38.46%	45.70%
CPFL Sul Paulista	March	1.63%	-10.73%	24.35%	12.82%	24.88%	28.38%
CPFL Mococa	March	1.65%	-3.28%	16.57%	9.02%	23.34%	29.28%

(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).

As mentioned in note 14.4.2, at December 31, 2017, the EGM approved the grouping of subsidiaries Companhia Luz e Força Santa Cruz, Companhia Leste Paulista de Energia, Companhia Jaguari de Energia, Companhia Sul Paulista de Energia e Companhia Luz and Força de Mococa In accordance with Normative Resolution 716, of May 3, 2016, until the first tariff review of the grouped concessionaire, which will take place in March 2021, ANEEL may apply the procedure that divides over time the variation in the tariffs of the former concessions and the unified tariff.This will occur in the tariff adjustment of March 2018.

25.4Energy Development Account (CDE) – Low-income, tariff discounts – judicial injunctions, 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$1,419,128 (R$1,038,621 was recognized in 2016 and R$ 895,538 in 2015), of which R$96,882 for the low-income subsidy (R$ 93,879 in 2016 and R$66,313 in 2015) and R$1,226,777 for other tariff discounts (R$944,742 in 2016 and R$ 829,225 in 2015), against other receivables in line item “Other Receivables – Eletrobrás” (note 11) and “Other Payables – Tariff discounts – CDE” (note 22).

25.5Tariff 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$ 1.00, R$ 3.00 and R$ 5.00 (before tax effects), respectively, for each 100 KWh consumed, readjusted by due to a decision issued by the Collegiate Board regarding Public Hearing No. 61/2017, as of November 1, 2017.

In 2017, ANEEL approved the Tariff Flags billed from December 2016 to October 2017. The amount billed in this period was R$ 610,584 (R$ 430,065 in 2016), recognized in line item “Tariff flags and others”.From this amount,R$ 386,242 were used to offset part of the sector financial asset and liability (note8) and R$ 224,395 were transferred to the centralizing account for tariff flag resources (“CCRBT”).  The amount of R$298,507, relating to the tariff flag billed in November and December 2017 and not approved, is recognized in regulatory charges (note 19).

25.6Energy Development Account – CDE

F-83

 

By means of Ratification Resolution No. 2,202 of February 7^nd 2017, superseded by Ratification Resolution No 2,204 of March 07, 2017, 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, 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, whose amount were updated by REH No. 2,231, of April 25, 2017 with payment and transfer to the CDE for the tariff period of each distribution company.

25.7Adjustment for refunding the Reserve Energy Charge ("EER") of Angra III

ANEEL approved through REH No. 2,214 of March 28, 2017 the republication of the energy tariff – TE and Distribution System Usage Tariff - TUSD for the distribution subsidiaries, with the purpose of refunding the amount forecast for the Reserve Energy Charge (EER) of the energy generation company UTN Almirante Alvaro Alberto - Unit III (Angra III).

The tariffs resulting from this decision were effective in April 2017, however, as the reading period of each consuming unit does not coincide with the calendar month, this reduction occurred in the revenue amounts of April and May 2017, with its impact diluted between the two periods.

The average effect perceived by the consumers was: -15.28% at CPFL Paulista, -6.8% at CPFL Piratininga, -10.89% at RGE, -13.76% at RGE Sul, -13.76% at Companhia Luz e Força Santa Cruz, -14.81% at Companhia Leste Paulista de Energia, -14.71% at Companhia Luz e Força de Mococa, -14.29% at Companhia Sul Paulista de Energia (as mentioned in note 14.4.2, in 2017 the subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Leste Paulista, CPFL Sul Paulista and CPFL Mococa were grouped, and they adopted the name CPFL Santa Cruz), and -16.49% at Companhia Jaguari de Energia (“CPFL Santa Cruz”).

The estimated impact of this adjustment is an average reduction of -12.85% in revenues of distribution subsidiaries in April 2017.

F-84

 

( 26 )COST OF ELECTRIC ENERGY

	In GWh			R$ thousand
	2017 (*)	2016 (*)	2015 (*)	2017	2016	2015
Electricity purchased for resale
Itaipu Binacional	11,779	10,497	10,261	2,350,858	2,025,780	2,869,481
Spot market / PROINFA	3,595	2,253	4,004	560,153	269,792	981,009
Energy purchased through auction in  the regulated market and bilateral contracts	62,600	51,225	44,342	14,269,265	8,541,677	9,192,868
PIS and COFINS credit	-	-	-	(1,562,779)	(987,997)	(1,196,579)
Subtotal	77,974	63,975	58,607	15,617,498	9,849,252	11,846,779
Electricity network usage charge
Basic network charges				1,541,629	834,341	847,342
Transmission from Itaipu				159,896	53,248	51,236
Connection charges				122,536	84,927	56,312
Charges for use of the distribution system				39,451	38,699	40,332
System service charges - ESS, net of transfers from CONER				(452,978)	362,735	555,851
Reserve energy charges - EER				(303)	106,925	54,762
PIS and COFINS credit				(126,213)	(129,883)	(140,868)
Subtotal				1,284,020	1,350,990	1,464,967
Total				16,901,518	11,200,242	13,311,747
(*) Information not audited by the independent auditors

( 27 )OPERATING COSTS AND EXPENSES

	2017
	Cost of operation	Cost of services rendered to third parties	Operating Expenses			Total
			Selling	General and administrative	Others
Personnel	882,150	2	170,859	324,147	-	1,377,158
Private pension plans	113,887	-	-	-	-	113,887
Materials	222,650	1,061	2,444	23,818	-	249,973
Third party services	251,549	1,856	186,525	287,201	-	727,151
Depreciation and amortization	1,143,795	-	5,403	93,639	-	1,242,837
Cost of infrastructure construction	-	2,071,698	-	-	-	2,071,698
Others	157,113	(7)	225,000	218,247	438,494	1,038,847
Collection fees	11,710	-	68,757	-	-	80,467
Allowance for doubtful accounts	-	-	155,097	-	-	155,097
Leases and rentals	52,734	-	(148)	19,740	-	72,326
Publicity and advertising	202	-	1	17,412	-	17,615
Legal, judicial and indemnities	-	-	-	188,355	-	188,355
Donations, contributions and subsidies	88	-	2	3,924	-	4,014
Gain (loss) on disposal, retirement and other noncurrent assets	-	-	-	-	132,195	132,195
Amortization of concession intangible asset	-	-	-	-	286,215	286,215
Amortization of premium paid - GSF	9,594	-	-	-	-	9,594
Financial compensation for use of water resources	8,656	-	-	-	-	8,656
Impairment	-	-	-	-	20,437	20,437
Others	74,130	(7)	1,291	(11,184)	(353)	63,877
Total	2,771,145	2,074,611	590,232	947,072	438,494	6,821,554

F-85

 

	2016
	Cost of operation	Cost of services rendered to third parties	Operating Expenses			Total
			Selling	General and administrative	Others
Personnel	686,434	1	134,864	272,618	-	1,093,918
Private pension plans	76,505	-	-	-	-	76,505
Materials	164,168	1,412	8,191	16,175	-	189,946
Third party services	271,623	3,416	146,957	229,199	-	651,195
Depreciation and amortization	937,506	-	3,602	94,949	-	1,036,056
Cost of infrastructure construction	-	1,352,214	-	-	-	1,352,214
Others	112,560	(11)	253,638	236,476	386,746	989,408
Collection fees	-	-	65,562	-	-	65,562
Allowance for doubtful accounts	-	-	176,349	-	-	176,349
Leases and rentals	42,163	-	113	17,109	-	59,385
Publicity and advertising	150	-	29	11,659	-	11,838
Legal, judicial and indemnities	-	-	-	181,888	-	181,888
Donations, contributions and subsidies	54	-	9	2,425	-	2,488
Gain (loss) on disposal, retirement and other noncurrent assets	-	-	-	-	83,575	83,575
Amortization of concession intangible asset	-	-	-	-	255,110	255,110
Amortization of premium paid - GSF	9,594	-	-	-	-	9,594
Financial compensation for use of water resources	12,233	-	-	-	-	12,233
Impairment	-	-	-	-	48,291	48,291
Others	48,367	(11)	11,575	23,395	(231)	83,095
Total	2,248,795	1,357,032	547,251	849,416	386,746	5,389,240

	2015
	Cost of operation	Cost of services rendered to third parties	Operating Expenses			Total
			Selling	General and administrative	Others
Personnel	596,021	28	123,812	219,348	-	939,209
Private pension plans	60,184	-	-	-	-	60,184
Materials	123,853	1,008	5,249	9,825	-	139,935
Third party services	187,080	2,777	128,022	241,115	-	558,994
Depreciation and amortization	870,427	-	21,826	84,985	-	977,238
Cost of infrastructure construction	-	1,045,301	-	-	-	1,045,301
Others	69,633	(12)	185,673	308,226	357,653	921,173
Collection fees	-	-	56,990	-	-	56,990
Allowance for doubtful accounts	-	-	126,879	-	-	126,879
Leases and rentals	31,687	-	(4)	16,874	-	48,558
Publicity and advertising	339	-	34	9,565	-	9,938
Legal, judicial and indemnities	10	-	-	263,453	-	263,463
Donations, contributions and subsidies	-	-	16	3,418	-	3,434
Gain (loss) on disposal, retirement and other noncurrent assets	-	-	-	-	16,309	16,309
Amortization of concession intangible asset	-	-	-	-	302,665	302,665
Financial compensation for use of water resources	13,768	-	-	-	-	13,768
Impairment	-	-	-	-	38,956	38,956
Others	23,829	(12)	1,759	14,916	(277)	40,214
Total	1,907,197	1,049,101	464,583	863,499	357,653	4,642,033

F-86

 

( 28 )FINANCE INCOME (COSTS)

	2017	2016	2015
Finance Income
Income from financial investments	457,255	667,429	472,745
Late payment interest and fines	265,455	246,045	215,923
Adjustment for inflation of tax credits	19,623	32,371	57,580
Adjustment for inflation of escrow deposits	49,502	35,228	84,683
Adjustment for inflation and exchange rate changes	60,999	147,849	121,609
Discount on purchase of ICMS credit	16,386	16,198	13,027
Adjustments to the sector financial asset (note 8)	-	32,747	162,786
PIS and COFINS on other finance income	(48,322)	(63,223)	(52,849)
PIS and COFINS on interest on capital	(27,798)	(2,324)	(6,941)
Other	87,214	88,182	74,685
Total	880,314	1,200,503	1,143,247
Finance expenses
Interest on debts	(1,661,060)	(1,811,263)	(1,725,252)
Adjustment for inflation and exchange rate changes	(540,053)	(703,128)	(686,575)
(-) Capitalized interest	50,543	68,082	45,568
Adjustments to the sector financial liability (note 8)	(82,333)	(25,079)	(1,573)
Use of public asset	(8,048)	(14,950)	(16,028)
Others	(126,917)	(167,638)	(167,250)
Total	(2,367,868)	(2,653,977)	(2,551,110)
Finance expenses, net	(1,487,554)	(1,453,474)	(1,407,863)

Interests were capitalized at an average rate of 8.54% p.a. (10.9% p.a. in 2016 and 10.25% p.a. in 2015) 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$235,852 (losses of R$ 1,399,988 in 2016 and gains of R$ 1,514,439 in 2015) on derivative instruments (note 33).

( 29 )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.

F-87

 

The information segregated by segment is presented below, in accordance with the criteria established by Executive Officers:

	Distribution	Generation (conventional source)	Generation (renewable source)	Commercialization	Services	Total	Others (*)	Elimination	Total
2017
Net operating revenue	21,068,435	741,842	1,489,932	3,402,804	40,611	26,743,623	1,281	-	26,744,905
(-) Intersegment revenues	8,182	448,421	469,152	11,297	444,935	1,381,988	-	(1,381,988)	-
Cost of electric energy	(14,146,703)	(147,379)	(348,029)	(3,196,028)	-	(17,838,139)	-	936,621	(16,901,518)
Operating costs and expenses	(4,695,480)	(156,340)	(389,443)	(47,296)	(398,188)	(5,686,747)	(51,121)	445,366	(5,292,502)
Depreciation and amortization	(763,739)	(123,129)	(617,017)	(3,054)	(19,760)	(1,526,699)	(2,353)	-	(1,529,052)
Income from electric energy service	1,470,695	763,415	604,596	167,724	67,598	3,074,028	(52,193)	-	3,021,834
Equity	-	312,390	-	-	-	312,390	-	-	312,390
Finance income	597,133	102,713	137,746	19,117	10,693	867,402	12,912	-	880,314
Finance expenses	(1,163,600)	(431,289)	(648,571)	(52,023)	(6,445)	(2,301,928)	(65,939)	-	(2,367,868)
Profit (loss) before taxes	904,228	747,229	93,770	134,818	71,846	1,951,891	(105,220)	-	1,846,670
Income tax and social contribution	(299,510)	(95,688)	(74,125)	(44,527)	(16,994)	(530,844)	(72,784)	-	(603,629)
Attributable to controlling shareholders	604,717	651,541	19,645	90,290	54,852	1,421,045	(178,004)	-	1,243,042
Attributable to controlling shareholders	604,717	601,969	3,382	90,290	54,852	1,355,211	(178,004)	-	1,177,206
Attributable to noncontrolling interests	-	49,572	16,263	-	-	65,835	-	-	65,836
Total assets (**)	22,278,452	4,287,337	12,815,017	931,546	374,435	40,686,787	596,125	-	41,282,912
Purchases of PP&E and intangible assets	1,882,502	8,973	621,046	2,927	54,149	2,569,598	835	-	2,570,433

2016
Net operating revenue	15,017,166	593,775	1,334,571	2,024,350	81,595	19,051,456	60,633	-	19,112,089
(-) Intersegment revenues	22,526	409,338	338,357	62,757	318,770	1,151,748	8,661	(1,160,410)	-
Cost of electric energy	(9,747,720)	(98,521)	(272,125)	(1,876,952)	-	(11,995,318)	-	795,075	(11,200,242)
Operating costs and expenses	(3,447,081)	(106,364)	(407,673)	(47,548)	(322,131)	(4,330,797)	(132,611)	365,334	(4,098,074)
Depreciation and amortization	(591,334)	(126,596)	(553,169)	(3,779)	(12,870)	(1,287,748)	(3,417)	-	(1,291,166)
Income from electric energy service	1,253,557	671,631	439,961	158,829	65,363	2,589,342	(66,734)	-	2,522,608
Equity	-	311,414	-	-	-	311,414	-	-	311,414
Finance income	781,365	182,574	132,653	31,513	10,742	1,138,848	61,655	-	1,200,503
Finance costs	(1,331,973)	(562,196)	(667,344)	(24,761)	(5,272)	(2,591,546)	(62,432)	-	(2,653,978)
Profit (loss) before taxes	702,950	603,424	(94,730)	165,581	70,832	1,448,057	(67,510)	-	1,380,547
Income tax and social contribution	(295,748)	(98,530)	(46,311)	(53,225)	(17,019)	(510,833)	9,343	-	(501,490)
Profit (loss) for the year	407,202	504,894	(141,041)	112,357	53,813	937,225	(58,167)	-	879,057
Attributable to controlling shareholders	407,202	461,411	(75,731)	112,357	53,813	959,052	(58,167)	-	900,885
Attributable to noncontrolling interests	-	43,483	(65,311)	-	-	(21,828)	-	-	(21,828)
Total assets (**)	22,887,781	5,310,924	12,459,791	466,021	345,372	41,469,889	701,103	-	42,170,992
Purchases of PP&E and intangible assets	1,200,621	7,564	978,896	3,713	42,954	2,233,748	4,199	-	2,237,949

F-88

 

2015
Net operating revenue	16,945,222	572,553	1,262,297	1,716,348	55,547	20,551,967	47,246	-	20,599,212
(-) Intersegment revenues	22,318	411,038	335,979	82,544	239,088	1,090,966	3,136	(1,094,101)	-
Cost of electric energy	(11,934,217)	(223,495)	(260,091)	(1,629,793)	-	(14,047,596)	-	735,849	(13,311,747)
Operating costs and expenses	(2,889,495)	(85,388)	(336,834)	(39,632)	(251,385)	(3,602,734)	(117,649)	358,257	(3,362,126)
Depreciation and amortization	(587,059)	(131,969)	(540,578)	(4,534)	(12,633)	(1,276,773)	(3,128)	-	(1,279,903)
Income from electric energy service	1,556,770	542,738	460,772	124,933	30,617	2,715,830	(70,396)	-	2,645,434
Equity	-	216,885	-	-	-	216,885	-	-	216,885
Finance income	740,628	110,018	131,354	42,840	44,098	1,068,938	74,310	-	1,143,247
Finance costs	(1,256,801)	(549,286)	(599,303)	(38,386)	(4,858)	(2,448,634)	(102,477)	-	(2,551,110)
Profit (loss) before taxes	1,040,597	320,354	(7,176)	129,386	69,857	1,553,017	(98,563)	-	1,454,454
Income tax and social contribution	(414,633)	(37,570)	(49,222)	(41,282)	(18,232)	(560,939)	(18,239)	-	(579,177)
Profit (loss) for the year	625,965	282,783	(56,398)	88,104	51,625	992,079	(116,802)	-	875,277
Attributable to controlling shareholders	625,965	251,831	(35,781)	88,104	51,625	981,744	(116,802)	-	864,942
Attributable to noncontrolling interests	-	30,954	(20,617)	(0)	-	10,337	-	-	10,337
Total assets (**)	22,138,086	4,575,230	11,868,943	714,781	317,845	39,614,885	917,586	-	40,532,471
Purchases of PP&E and intangible assets	868,495	6,910	493,584	2,432	39,176	1,410,597	17,199	-	1,427,796

(*) 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

As the Brazilian economic conditions have deteriorated even further during 2017, the following was recorded   R$20,437 of CPFL Renováveis (renewable generation segment) impairment losses (R$40,433 in 2016) and CPFL Telecom – “segment others”, an additional impairment of R$7,858 in 2016. This loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 27).

The investment balance in joint ventures, accounted for under the equity method and classified in the generation (conventional source) segment, is R$1,022,696 (R$ 1,493,753 in 2016).

( 30 )RELATED PARTY TRANSACTIONS

The Company’s controlling shareholders were, as of December 31, 2017, as follows:

·State Grid Brazil Power Participações S.A

F-89

 

Indirect subsidiary of State Grid Corporation of China, a Chinese state-owned company primarily engaged in developing and operating businesses in the electric energy sector.

·ESC Energia S.A.

Subsidiary of State Grid Brazil Power Participações S.A.

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)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.

b)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.

c)Advances –refer to advances for investments in research and development.

d)Intragroup loans –refer mainly to 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.

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 and CPFL Piratininga renegotiated with the subsidiary Ceran the extension of the original maturities of the energy purchase bills, previously from 15 November 2017 and 15 December 2017, to January 2018.

The total compensation of key management personnel in 2017was R$ 73,670 (R$ 58,132 in 2016 and R$ 43,208 in 2015). This amount comprises R$64,516 (R$49,989 in 2016 and R$ 44,061 in 2015) in respect of short-term benefits, R$1,516 (R$1,212 in 2016 and R$ 1,087 in 2015) of post-employment benefits and a provision of R$7,638 (R$ 6,930 in 2016 and reversal of provision of R$ 1,940 in 2015) for other long-term benefits, and refers to the amount recognized on an accrual basis.

Transactions with entities under common control basically refer to transmission system charge paid by the Company’s subsidiaries to the direct or indirect subsidiaries of State Grid Corporation of China.

Transactions between related parties involving controlling shareholders, entities under common control or with significant influence and joint ventures are as follows:

	ASSETS		LIABILITIES		INCOME			EXPENSES
	December 31, 2017	December 31, 2016	December 31, 2017	December 31, 2016	2017	2016	2015	2017	2016	2015
Advances
BAESA – Energética Barra Grande S.A.	-	-	691	726	-	-	-	-	-	-
Foz do Chapecó Energia S.A.	-	-	979	1,025	-	-	-	-	-	-
ENERCAN - Campos Novos Energia S.A.	-	-	1,212	1,269	-	-	-	-	-	-
EPASA - Centrais Elétricas da Paraiba	-	-	440	462	-	-	-	-	-	-
Energy purchases and sales, and charges
Entities under common control (Subsidiaries of State Grid Corporation of China)*	-	-	13,330	-	-	-	-	91,302	-	-
BAESA – Energética Barra Grande S.A.	-	-	13,169	5,642	-	-	6,080	80,362	60,765	111,541
Foz do Chapecó Energia S.A.	-	-	37,415	35,018	-	215	4,996	381,193	358,272	330,675
ENERCAN - Campos Novos Energia S.A.	823	387	51,381	50,526	8,763	3,684	23,283	281,530	269,480	244,102
EPASA - Centrais Elétricas da Paraiba	-	-	19,458	12,418	-	-	15,243	137,376	91,010	168,187
Intangible assets, property, plant and equipment, materials and services rendered
BAESA – Energética Barra Grande S.A.	153	56	-	-	1,582	521	1,354	-	-	-
Foz do Chapecó Energia S.A.	2	104	-	-	1,726	1,424	1,483	-	-	-
ENERCAN - Campos Novos Energia S.A.	152	74	-	-	1,665	1,826	1,354	-	-	-
EPASA - Centrais Elétricas da Paraíba S.A.	416	1,599	-	-	(469)	488	720	-	-	-
Intragroup loans
EPASA - Centrais Elétricas da Paraíba S.A.	-	38,078	-	-	327	4,379	14,123	-	-	-
Noncontrolling shareholders - CPFL Renováveis	8,612	9,067	-	-	(253)	1,039	1,475	-	-	-
Dividend and interest on own capital
BAESA – Energética Barra Grande S.A.	108	89	-	-	-	-	-	-	-	-
Chapecoense Geração S.A.	32,734	29,329	-	-	-	-	-	-	-	-
ENERCAN - Campos Novos Energia S.A.	21,184	40,983	-	-	-	-	-	-	-	-
Others
Instituto CPFL	-	-	-	-	-	-	-	3,613	-	-

F-90

 

The comparative information below refers to the period in which  the controlling shareholders were those prior to the change of control described in note 23.

	ASSETS	LIABILITIES	INCOME		EXPENSES
	Dec. 31, 2016	Dec. 31, 2016	2016	2015	2016	2015
Bank balances and short-term investments
Banco Bradesco S.A.(***)	-	-	-	351,086	-	312
Banco do Brasil S.A.	48,985	-	4,113	28,466	5	4
Borrowings (**), debentures (**) and derivatives (**)
Banco Bradesco S.A.(***)	-	-	-	-	-	85,505
Banco do Brasil S.A.	-	4,257,562	800	-	463,949	459,889
Banco BNP Paribas Brasil S.A	5,126	-	-	-	67,196	8,978
Other financial transactions
Banco Bradesco S.A.(***)	-	-	-	166	-	4,174
Banco do Brasil S.A.	-	962	234	80	6,408	5,941
Energy purchases and sales, and charges
AES Tiete S.A. (****)	-	-	2	-	14,498	-
Afluente Transmissão de Energia Elétrica S.A.	-	53	-	-	1,212	1,426
Aliança Geração de Energia S.A	-	1,183	4	1	49,944	34,063
Alpargatas S.A. (****)		-	2,954	-	-	-
Arizona 1 Energia Renovável S.A	-	-	-	-	967	883
Baguari I Geração de Energia Elétrica S.A.	-	6	-	-	294	268
BRF Brasil Foods	-	-	20,190	-	-	-
Caetite 2 Energia Renovável S.A.	-	-	-	-	889	810
Caetité 3 Energia Renovável S.A.	-	-	-	-	896	817
Calango 1 Energia Renovável S.A.	-	-	-	-	1,073	977
Calango 2 Energia Renovável S.A.	-	-	-	-	916	834
Calango 3 Energia Renovável S.A.	-	-	-	-	1,072	977
Calango 4 Energia Renovável S.A.	-	-	-	-	995	907
Calango 5 Energia Renovável S.A.	-	-	-	-	1,054	963
Companhia de Eletricidade do Estado da Bahia – COELBA	743	121	19,296	14,491	121	46
Companhia Energética de Pernambuco - CELPE	692	20	9,829	7,062	250	206
Companhia Energética do Rio Grande do Norte - COSERN	267	-	3,128	2,580	-	-
Companhia Hidrelétrica Teles Pires S.A.	-	1,416	57	17	53,710	29,915
ELEB Equipamentos Ltda	-	-	-	4,036	-	-
Embraer	-	-	6,938	26,615	-	-
Energética Águas da Pedra S.A.	-	112	6	2	4,716	4,260
Estaleiro Atlântico Sul S.A.	-	-	7,978	19,026	-	-
Goiás Sul Geração de Enegia S.A.	-	-	-	-	181	166
InterCement Brasil S.A	-	-	2	1	-	-
Itapebi Geração de Energia S.A	-	-	3	1	-	-
Mel 2 Energia Renovável S.A.	-	-	-	-	718	632
NC ENERGIA S.A.	451	2	28,298	5,336	6	-
Norte Energia S.A.	1	4,585	17	1	61,240	-
Rio PCH I S.A.	-	209	-	-	8,865	8,004
Samarco 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
Serra do Facão Energia S.A. - SEFAC	-	557	-	-	23,153	20,916
Termopernambuco S.A.	-	-	5	3	-	-
ThyssenKrupp Companhia Siderúrgica do Atlântico	-	-	25,268	37,238	7,683	6,965
Tupy	-	-	-	-	27,127	-
Vale Energia S.A.	8,680	-	102,069	92,353	216	695
Intangible assets, property, plant and equipment, materials and services rendered
Alpargatas S.A. (***)	168	-	2,310	-	-	-
Afluente Transmissão de Energia Elétrica S.A.	-	-	-	-	5	-
Banco Bradesco S.A.(***)	-	-	-	-	-	19
Banco do Brasil S A	-	-	-	-	6	170
Brasil veículos Companhia de Seguros	-	-	2	-	-	-
BRF Brasil Foods	-	-	1,250	-	-	-
Companhia de Saneamento Básico do Estado de São Paulo - SABESP	4	42	170	1,034	94	31
Companhia Brasileira de Soluções e Serviços CBSS - Alelo (***)	-	-	-	-	-	576
Companhia de Eletricidade do Estado da Bahia – COELBA	-	-	-	-	-	50
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	-	-	-
Ferrovia Centro-Atlântica S.A.	-	-	-	-	24	22
HM 02 Empreendimento Imobiliário SPE Ltda.	-	-	45	-	-	-
HM Engenharia e Construções S.A.	-	-	-	272	-	-
Indústrias Romi S.A.	4	-	51	68	-	-
InterCement Brasil S.A	-	-	43	26	-	-
Oi Móvel S.A (***)	-	-	-	-	302	-
Logum Logística S.A.	26	-	730	55	-	-
LUPATECH	-	-	-	-	-	2
Mapfre Seguros Gerais S.A. (***)	-	-	-	4	-	1
NC Energia S.A.	-	-	17	-	-	-
Renovias Concessionária S.A.	-	-	-	-	17	-
Rodovias Integradas do Oeste S.A.	-		-	-	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	2	-	32	44
Ultrafértil S.A	-		14	868	-	-
Vale Energia S.A.	-		331	-	-	-
Vale S.A.	-	-	-	-	11	-
Vale Fertilizantes S.A	-		-	45	-	-
(**) The balances include the mark to market adjustments
(***) Related party until December 2015
(****) Related party from January 2016

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( 31 )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. Expenses related to coverages are as follows:

Description	Type of cover	Dec. 31, 2017	Dec. 31, 2016 (*)	31/12/2015 (*)
Concession financial asset / Intangible assets	Fire, lightening, explosion, machinery breakdown, electrical damage and engineering risk	7,440,359	9,679,825	8,634,344
Transport	National transport	302,364	416,358	319,834
Stored materials	Fire, lightning, explosion and robbery	229,496	232,849	171,585
Automobiles	Comprehensive cover	16,779	13,235	6,544
Civil liability	Electric energy distributors	263,000	200,000	118,000
Personnel	Group life and personal accidents	694,341	234,357	202,989
Others	Operational risks and others	158,340	281,914	323,200
Total		9,104,679	11,058,537	9,776,496
(*) Information 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.

( 32 )RISK MANAGEMENT

The business of the Group 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

At CPFL Group, the risk management is conducted through a structure that involves the Board of Directors and Supervisory Board, Advisory Committees, Executive Board, Internal Audit and Corporate Risks Management and business areas. This management is regulated by the Corporate RiskManagement Policy, which describes the risk management model as well as the attributions of each agent.

F-92

 

The Board of Directors of CPFL Energia is responsible for deciding on the risk limit methodologies recommended by the Executive Board, and for being aware of the exposures and mitigation plans presented in the event these limits are exceeded. This forum is also responsible for being aware of and monitoring any important weaknesses in controls and/or processes, as well as relevant regulatory compliance failures, following up on the plans proposed by the Executive Board to correct them.

The Advisory Committee(s) of the Board of Directors, in its role(s) of technical body(ies), is responsible for becoming aware of (i) the risk monitoring models, (ii) the exposures to risks, and (iii) the control levels (including their effectiveness), supporting the Board of Directors in the performance of its statutory role related to risk management.

The Supervisory Board of CPFL Energia is responsible for, among other things, certifying that Management has means to identify the risks on the preparation and disclosure of the financial statements to which the CPFL Group is exposed as well as for monitoring the effectiveness of the control environment.

The Executive Board of CPFL Energia is responsible for conducting businesses within the risk limits defined, and should take the required measures to avoid that the exposure to risks exceeds such limits and report any excess of the limit to the Board of Directors of CPFL Energia, presenting mitigation actions.

The Internal Audit and Corporate Risks Management is responsible for coordinating the risk management process at CPFL Group, developing and keeping up-to-date Corporate Risk Management methodologies that involve the identification, measurement, monitoring and reporting of risks to which the CPFL Group is exposed.

The business areas have the primary responsibility for the management of the risks inherent to its processes, and should conduct them within the exposure limits defined and implementing mitigation plans for the main exposures.

The main market risk factors that affect the businesses are as follows:

Foreign exchange risk: This risk derives from the possibility of the Group incurring losses and cash constraints due to fluctuations in exchange rates, increasing the balances of liabilities denominated in foreign currency or decreasing the portion of revenue arising from annual adjustment of part of the tariff based on the fluctuation of the dollar, in power sale agreements of the joint venture ENERCAN. The exposure related to funding in foreign currency is hedged by swap transactions. The exposure related to ENERCAN revenue, proportional to the interest held by the Company, is hedged by financial instruments such as the zero cost collar described in note 33.b.1. The quantification of these risks is presented in note 33. In addition, the subsidiaries are exposed in their operating activities to fluctuations in exchange rates on purchase of electricity from Itaipu. The compensation mechanism - CVA protects the distribution subsidiaries against any economic losses.

Interest rate risk and inflation indexes: This risk arises due to the possibility of the Group incurring losses due to fluctuations in interest rates and in inflation indexes, which would increase the finance costs related to borrowings and debentures. The quantification of this risk is presented in note 33.

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.

F-93

 

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, marked against the market price of electricity.

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”) allowed the energy generation through 2017, with no supply risk, 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.

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

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 placeas regards the transactions and balances of financial instruments, for the purpose of monitoring the risks and current rates in relation to market conditions.

F-94

 

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.

( 33 )FINANCIAL INSTRUMENTS

The main financial instruments, at fair value and/or the carrying amount is significantly different of the respective fair value, classified in accordance with the Group’s accounting practices, are:

					December 31, 2017
	Note	Category	Measurement	Level (*)	Carrying amount	Fair value
Asset
Cash and cash equivalent	5	(a)	(2)	Level 1	2,289,302	2,289,302
Cash and cash equivalent	5	(a)	(2)	Level 2	960,340	960,340
Derivatives	33	(a)	(2)	Level 2	595,872	595,872
Derivatives - zero-cost collar	33	(a)	(2)	Level 3	52,058	52,058
Concession financial asset - distribution	10	(b)	(2)	Level 3	6,330,681	6,330,681
					10,228,253	10,228,253
Liability
Borrowings - principal and interest	16	(c)	(1)	Level 2 (***)	6,142,583	5,912,175
Borrowings - principal and interest (**)	16	(a)	(2)	Level 2	4,849,474	4,849,474
Debentures - Principal and interest	17	(c)	(1)	Level 2 (***)	9,176,527	7,581,432
Derivatives	33	(a)	(2)	Level 2	94,806	94,806
					20,263,390	18,437,887
(*) Refers to the hierarchy for determination of fair value
(**) As a result of the initial designation of this financial liability, the consolidated financial statements reported a gain of R$ 21,137 in 2017 (a loss of R$ 274,834 in 2016)
(***) Only for disclosure purposes, in accordance with IFRS 7
Key
Category:		Measurement:
(a) - Measured at fair value through profit or loss		(1) - Measured at amortized cost
(b) - Available for sale		(2) - Measured at fair value
(c) - Other finance liabilities

The financial instruments for which the carrying amounts approximate the fair values at the end of the reporting period, 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 – CDE, (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.

F-95

 

·         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 2017 there were no transfers between hierarchical levels of fair value.

a) Valuation of financial instruments

As mentioned in note 4, the fair value of a security corresponds to its maturity value (redemption value) adjusted to present value by the discount factor (relating to the maturity date of the security) obtained from the market interest curve, in Brazilian reais.

IFRS 7 requires the classification in a three-level hierarchy for fair value measurement of financial instruments, based on observable and unobservable inputs related to the valuation of a financial instrument at the measurement date.

IFRS 7 also defines observable inputs as market data obtained from independent sources and unobservable inputs that reflect market assumptions.

The three levels of the fair value hierarchy are:

· Level 1: quoted prices in an active market for identical instruments;

· 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$204,443 (R$ 186,148 in 2016 and R$ 393,343 in 2015), and the main assumptions are described in note 10 and 25.

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 33 b.1.

The Company recognizes in “Investments at cost” in the financial statements the 5.94% interest held by the indirect subsidiary Paulista Lajeado Energia S.A. in the total capital of Investco S.A. (“Investco”), in the form of 28,154,140 common shares and 18,593,070 preferred shares not quoted in stock  markets. The main objective of its operations is to generate electric energy for commercialization by the shareholders holding the concession. The Company recognizes the investment at cost.

b) Derivatives

The Group has the policy of using derivatives to reduce their risks of fluctuations in exchange and interest rates, without any speculative purposes. The Group has 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 Group 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 16). Other debts with terms different from the derivatives contracted as a hedge continue to be recognized at amortized cost. Furthermore, the Group did not adopt hedge accounting for derivativeinstruments.

F-96

 

At December 31, 2017, the Group had the following swap transactions, all traded on the over-the-counter market:

	Fair values (carrying amounts)
Company / strategy / counterparts	Assets	Liabilities	Fair value, net	Values at cost, net	Gain (loss) on marking to market	Currecy / index	Maturity range	Notional
Derivatives to hedge debts designated at fair value
Exchange rate hedge
CPFL Paulista
Bank of Tokyo-Mitsubishi	34,627	-	34,627	35,864	(1,237)	dollar	March 2019	117,400
Bank of America Merrill Lynch	42,466	-	42,466	42,830	(363)	dollar	September 2018	106,020
Bank of America Merrill Lynch	48,135	-	48,135	48,802	(667)	dollar	March 2019	116,600
J.P.Morgan	24,067	-	24,067	24,401	(334)	dollar	March 2019	58,300
J.P.Morgan	13,808	-	13,808	13,659	149	dollar	January 2019	67,613
Bank of Tokyo-Mitsubishi	14,124	-	14,124	22,015	(7,891)	dollar	February 2020	142,735
Bank of America Merrill Lynch	89,684	-	89,684	89,289	395	dollar	February 2018	405,300
Bank of America Merrill Lynch	-	(5,236)	(5,236)	(1,653)	(3,583)	dollar	October 2018	329,500
Bradesco	-	(5,163)	(5,163)	(4,068)	(1,095)	dollar	May 2021	59,032
Bank of America Merrill Lynch	-	(4,805)	(4,805)	(4,055)	(750)	dollar	May 2021	59,032
Citibank	-	(4,971)	(4,971)	(4,062)	(910)	dollar	May 2021	59,032
Citibank	-	(4,948)	(4,948)	(4,080)	(868)	dollar	May 2021	59,032
	266,911	(25,124)	241,787	258,941	(17,154)
CPFL Piratininga
Citibank	45,457	-	45,457	47,966	(2,509)	dollar	March 2019	117,250
Bradesco	27,046	-	27,046	27,257	(211)	dollar	April 2018	55,138
J.P.Morgan	27,050	-	27,050	27,259	(209)	dollar	April 2018	55,138
Citibank	30,880	-	30,880	35,979	(5,099)	dollar	January 2020	169,838
BNP Paribas	37,212	-	37,212	36,649	563	euro	January 2018	175,714
Bradesco	-	(5,163)	(5,163)	(4,068)	(1,095)	dollar	May 2021	59,032
Bank of America Merrill Lynch	-	(4,805)	(4,805)	(4,055)	(750)	dollar	May 2021	59,032
Citibank	-	(4,971)	(4,971)	(4,062)	(910)	dollar	May 2021	59,032
Bank of America Merrill Lynch	-	(2,339)	(2,339)	(2,035)	(304)	dollar	May 2021	29,516
Citibank	-	(2,474)	(2,474)	(2,040)	(434)	dollar	May 2021	29,516
	167,645	(19,753)	147,891	158,850	(10,959)
RGE
Bank of Tokyo-Mitsubishi	22,785	-	22,785	23,054	(270)	dollar	April 2018	36,270
Bank of Tokyo-Mitsubishi	101,289	-	101,289	102,467	(1,178)	dollar	May 2018	168,346
Bank of Tokyo-Mitsubishi	374	-	374	1,313	(939)	dollar	October 2018	169,260
Bradesco	-	(5,163)	(5,163)	(4,068)	(1,095)	dollar	May 2021	59,032
Bank of America Merrill Lynch	-	(4,805)	(4,805)	(4,055)	(750)	dollar	May 2021	59,032
Citibank	-	(4,971)	(4,971)	(4,062)	(910)	dollar	May 2021	59,032
Bank of America Merrill Lynch	-	(4,678)	(4,678)	(4,070)	(609)	dollar	May 2021	59,032
	124,448	(19,619)	104,829	110,579	(5,750)
Companhia Jaguari de Energia (CPFL Santa Cruz)
Scotiabank	-	(1,167)	(1,167)	(1,327)	160	dollar	July 2019	65,936
CPFL Paulista Lajeado
Itaú	598	-	598	557	41	dollar	March 2018	35,000
CPFL Brasil
Scotiabank	-	(1,537)	(1,537)	(1,608)	71	dollar	August 2018	45,360
Scotiabank	6,243	-	6,243	10,610	(4,367)	dollar	September 2020	249,989
Scotiabank	3,964	-	3,964	6,674	(2,709)	dollar	October 2020	150,011
	10,208	(1,537)	8,671	15,676	(7,005)
CPFL Geração
Scotiabank	-	(2,070)	(2,070)	(2,355)	286	dollar	July 2019	117,036
Votorantim	-	(5,339)	(5,339)	(5,316)	(23)	dollar	June 2019	104,454
Bradesco	-	(103)	(103)	433	(536)	dollar	September 2019	32,636
Citibank	-	(10,985)	(10,985)	(613)	(10,372)	dollar	September 2020	397,320
Scotiabank	-	(9,110)	(9,110)	(9,278)	167	dollar	December 2019	174,525
	-	(27,607)	(27,607)	(17,129)	(10,478)
Subtotal	569,809	(94,806)	475,004	526,148	(51,145)
Derivatives to hedge debts  not designated at fair value
Price index hedge
CPFL Geração
Santander	10,263	-	10,263	8,344	1,919	IPCA	April 2019	35,235
J.P.Morgan	10,263	-	10,263	8,344	1,919	IPCA	April 2019	35,235
	20,525	-	20,525	16,688	3,837
Interest rate hedge (1)
CPFL Paulista
J.P.Morgan	1,112	-	1,112	255	857	CDI	February 2021	300,000
Votorantim	380	-	380	87	293	CDI	February 2021	100,000
Santander	401	-	401	92	309	CDI	February 2021	105,000
	1,893	-	1,893	434	1,459
CPFL Piratininga
Votorantim	536	-	536	122	414	CDI	February 2021	135,000
Santander	402	-	402	91	310	CDI	February 2021	100,000
	938	-	938	213	724
RGE
Votorantim	620	-	620	143	477	CDI	February 2021	170,000
CPFL Geração
Votorantim	2,088	-	2,088	403	1,685	CDI	August 2020	460,000
Subtotal	26,063	-	26,063	17,881	8,182
Other derivatives (2)
CPFL Geração
Itaú	18,126	-	18,126	-	18,126	dollar	September 2020	19,975
Votorantim	14,948	-	14,948	-	14,948	dollar	September 2020	19,975
Santander	18,984	-	18,984	-	18,984	dollar	September 2020	25,248
Subtotal	52,058	-	52,058	-	52,058
Total	647,930	(94,806)	553,124	544,029	9,095
Current	444,029	(10,230)
Noncurrent	203,901	(84,576)
For further details on terms and information on debts and debentures, see notes 16 and 17
(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
(3)The values at cost are the derivative amount without the respective mark to market, while the notional refers to the contracted accrual.

F-97

 

	December 31, 2016	Interests and monetary restatements	Repayments of principal	December 31, 2017
Derivatives
to hedge debts designated at fair value	602,476	(189,466)	113,138	526,148
to hedge debts not designated at fair value	7,181	(1,175)	11,875	17,881
Others (zero-cost collar)	-	22,372	(22,372)	-
Mark-to-market (*)	76,679	(67,584)	-	9,095
	686,336	(235,853)	102,641	553,124

F-98

 

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 16).

The Group 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 2017, 2016 and 2015, 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	2017	2016	2015
CPFL Energia	Exchange variation	-	(76,202)	71,492
CPFL Energia	Mark to Market	-	2,319	(2,319)
CPFL Paulista	Interest rate variation	304	(1,423)	(2,250)
CPFL Paulista	Exchange variation	(89,612)	(802,479)	843,224
CPFL Paulista	Mark to Market	(25,410)	118,663	(98,738)
CPFL Piratininga	Interest rate variation	175	(661)	(609)
CPFL Piratininga	Exchange variation	(19,799)	(358,412)	300,652
CPFL Piratininga	Mark to Market	(18,999)	48,193	(32,431)
RGE	Interest rate variation	115	(835)	(1,321)
RGE	Exchange variation	(27,237)	(252,321)	291,612
RGE	Mark to Market	(10,679)	48,915	(29,946)
CPFL Geração	Interest rate variation	852	3,161	2,600
CPFL Geração	Exchange variation	(41,793)	(145,933)	122,294
CPFL Geração	Mark to Market	(6,033)	66,425	(7,896)
CPFL Santa Cruz	Exchange variation	(947)	(6,986)	9,899
CPFL Santa Cruz	Mark to Market	120	148	(80)
CPFL Leste Paulista	Exchange variation	(947)	(1,076)	4,596
CPFL Leste Paulista	Mark to Market	120	(80)	(76)
CPFL Sul Paulista	Exchange variation	(947)	(7,577)	12,404
CPFL Sul Paulista	Mark to Market	120	170	(83)
CPFL Jaguari	Exchange variation	(947)	(10,236)	16,616
CPFL Jaguari	Mark to Market	120	273	(63)
CPFL Mococa	Exchange variation	-	-	2,022
CPFL Mococa	Mark to Market	-	-	(33)
Paulista Lajeado	Exchange variation	(2,052)	(11,046)	4,626
Paulista Lajeado	Mark to Market	66	1,649	(1,675)
CPFL Telecom	Exchange variation	-	-	3,204
CPFL Telecom	Mark to Market	-	-	6
CPFL Brasil	Exchange variation	14,567	(13,857)	5,367
CPFL Brasil	Mark to Market	(7,009)	2,383	(2,378)
CPFL Serviços	Exchange variation	-	(3,420)	3,810
CPFL Serviços	Mark to Market	-	254	(87)
		(235,852)	(1,399,988)	1,514,439

F-99

 

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 scenario in 2015 was 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, 2017, the total amount contracted was US$ 65,197, 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:

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 19.65%.
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$ 477, resulting in a net asset of R$ 51,581.

The following table reconciles the opening and closing balances of the call and put options for the year ended December 31, 2017, as required by IFRS 13:

	Assets	Liabilities	Net
As of December 31, 2015	8,820	(2,440)	6,380
Measurement at fair value	65,546	2,440	67,986
Net cash received from settlement of flows	(16,651)	-	(16,651)
As of December 31, 2016	57,715	-	57,715
Measurement at fair value	16,715	-	16,715
Net cash received from settlement of flows	(22,372)	-	(22,372)
As of December 31, 2017	52,058	-	52,058

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.

F-100

c) Sensitivity Analysis

In compliance with IFRS 7, the Group 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 Group. 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 Group 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, 2017 is maintained, the simulation of the effects by type of financial instrument for three different scenarios would be:

				Decrease (increase)
Instruments	Exposure R$ thousand (a)		Risk	Currency depreciation (b)	Currency appreciation / depreciation of 25% (c)	Currency appreciation / depreciation of 50% (c)
Financial liability instruments	(4,641,924)			(209,785)	1,003,142	2,216,070
Derivatives - Plain Vanilla Swap	4,687,768			211,857	(1,013,050)	(2,237,956)
	45,844		drop in the dollar	2,072	(9,908)	(21,886)
Financial liability instruments	(218,814)			(14,978)	43,470	101,918
Derivatives - Plain Vanilla Swap	219,694			15,038	(43,645)	(102,328)
	880		drop in the euro	60	(175)	(410)
Total	46,724			2,132	(10,083)	(22,296)
				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	65,197	(d)	dollar apprec.	(56,138)	(80,491)	(104,844)

(a) The exchange rates considered as of December 31, 2017 were R$ 3.31 per US$ 1.00 and R$ 3.97 per € 1.00.

(b)  As per the exchange curves obtained from information made available by B3 S.A., with the exchange rate being considered at R$ 3.46 and R$ 4.24, and exchange depreciation at 4.52% and 6.85%, for the US$ and €, respectively.

(c) As required by CVM Instruction 475/2008, the percentage increases in the ratios applied refer to the information made available by the B3 S.A..

(d) Owing to the characteristics of this derivative (zero-cost collar), the notional amount is presented in US$.

Except for the zero cost collar, 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, 2017 is maintained, and (ii) the respective accumulated annual indexes for 2017 remain stable (CDI 6.89% p.a.; IGP-M -0.52% p.a.; TJLP 7.00% p.a.; IPCA 2.76% p.a. and SELIC 9.70% p.a.), the effects on the Company’s 2017 financial statements would be a net finance cost of R$ 764,150 (CDI R$ 669,661, TJLP R$276,141 and income of SELIC R$ 36,609, IGPM R$298 and IPCA R$ 141,152). 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:

F-101

 

			Decrease (increase)
Instruments	Exposure R$ thousand (a)	Risk	Scenario I (a)	Raise/drop of index by 25% (b)	Raise/drop of index by 50% (b)
Financial asset instruments	3,770,045		(3,016)	61,169	125,354
Financial liability instruments	(8,988,008)		7,190	(145,830)	(298,851)
Derivatives -Plain Vanilla Swap	(4,501,345)		3,601	(73,034)	(149,670)
	(9,719,308)	CDI apprec.	7,775	(157,695)	(323,167)
Financial liability instruments	(57,291)	IGP-M apprec.	(2,286)	(2,783)	(3,280)
Financial liability instruments	(3,944,876)	TJLP apprec.	9,862	(56,708)	(123,277)
Financial liability instruments	(1,311,432)		(14,557)	(1,869)	10,819
Derivatives -Plain Vanilla Swap	94,949		1,054	135	(783)
Concession financial asset	6,330,681		70,271	9,021	(52,228)
	5,114,198	drop in the IPCA	56,768	7,287	(42,192)
Sector financial asset and liability	517,341		(14,692)	(23,565)	(32,437)
Financial liability instruments	(139,926)		3,974	6,374	8,773
	377,415	drop in the SELIC	(10,718)	(17,191)	(23,664)
Total	(8,229,862)		61,401	(227,090)	(515,580)

(a) The CDI, IGP-M, TJLP, IPCA and SELIC indexes considered of 6.81%, 3.47%, 6.75%, 3.87% and 6.86%, respectively, were obtained from information available in the market.

(b) 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, 2017, taking into account principal and future interest, and is based on the undiscounted cash flow, considering the earliest date on which the Group have to settle their respective obligations.

December 31, 2017	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	Total
Trade payables	15		3,524,624	16,307	7,418	-	-	128,438	3,676,787
Borrowings - principal and interest	16	7.95% p.a.	336,255	947,051	2,904,702	5,267,176	1,485,520	2,421,543	13,362,247
Derivatives	33		39	523	14,160	32,258	59,801	-	106,781
Debentures - principal and interest	17	7.83% p.a.	35,930	544,995	1,541,223	5,378,610	1,938,783	1,350,776	10,790,317
Regulatory charges	19		581,600	-	-	-	-	-	581,600
Use of public asset		9.24% p.a.	1,645	3,305	14,979	42,579	46,788	149,061	258,357
Others	22		106,515	56,186	18,212	-	-	62,223	243,136
Consumers and concessionaires			60,298	25,844	6,926	-	-	44,473	137,541
EPE / FNDCT / PROCEL			849	3,226	11,286	-	-	-	15,361
Collections agreement			45,368	27,116	-	-	-	-	72,484
Reversal fund			-	-	-	-	-	17,750	17,750
Total			4,586,608	1,568,367	4,500,694	10,720,623	3,530,892	4,112,041	29,019,225

F-102

 

e)Credit risk

Cash, cash equivalents and derivatives are held with banks and financial institutions with rating AA-. 

The credit risk on operations of Consumers, Concessionaires and Licensees is derived from the exposure to financial losses resulting from non-compliance with financial obligations by the counterparties. Monthly, the risk is monitored and classified according to the current exposure, considering the limit approved by Management.

( 34 )COMMITTMENTS

The Group’s commitments at December 31, 2017 are as follows:

Commitments at December 31, 2017	Duration	Less than 1 year	1-3 years	4-5 years	More than 5 years	Total
Operational leasings	Up to 15 years	16,579	29,440	25,053	155,169	226,241
Energy purchase agreements (except Itaipu)	Up to 28 years	10,870,752	18,433,971	17,250,704	41,537,486	88,092,913
Energy purchase from Itaipu	Up to 28 years	2,281,157	4,564,825	4,478,641	13,133,756	24,458,379
Energy system service charges	Up to 32 years	2,613,587	5,758,898	6,599,478	17,997,838	32,969,801
GSF renegotiation	Up to 30 years	26,997	13,267	47,284	276,207	363,755
Power plant constrution projects	Up to 3 years	97,176	11,319	-	-	108,495
Trade payables	Up to 17 years	102,441	237,673	244,851	1,005,781	1,590,746
Total		16,008,689	29,049,391	28,646,012	74,106,237	147,810,330

The power plant construction projects include commitments made by the renewal energy subsidiaries for construction.

F-103

 

( 35 )NON-CASH TRANSACTION

	Dec 31, 2017	Dec 31, 2016	Dec 31, 2015
Transactions resulting from business combinations
Borrowings and debentures	-	(1,156,621)	-
Concession financial asset	(12,338)	876,281	-
Intangible assets	(22,165)	1,870,268	-
Property, plant and equipment	(4,800)	-	-
Other net assets acquired	-	1,911	-
	(39,303)	1,591,839	-
Cash and cash equivalents acquired in the business combination	-	(95,164)	-
Consideration paid in the acquisition, net	(39,303)	1,496,675	-
Other transactions
Capital increase through earnings reserve	-	392,272	554,888
Escrow deposits to property, plant and equipment	4	3,418	-
Interest capitalized in property, plant and equipment	29,817	54,733	34,212
Interest capitalized in concession financial asset - distribution infrastructure	20,726	13,349	11,358
Reversal of contingencies against intangible assets	-	7,591	-
Repayment of intercompany loans with noncontrolling shareholders' dividends	259	-	-
Provision for socio environmental costscapitalized in property, plant and equipment	41,213	-	-
Transfers between property, plant and equipment and other assets	32,600	14,592	2,928

The balances disclosed in the "Transactions resulting from business combination" lines refer to the complementary amounts related to the acquisition of RGE Sul, which was provisionally recorded at December 31, 2016, according to note 14.3.

( 36 )RELEVANT  FACT  AND EVENTS AFTER THE REPORTING PERIOD

36.1Issue of debentures

In January 2018, subsidiaries issued simple non-convertible debentures with the following conditions and details:

Subsidiary	Issue	Quantity issued	R$ thousand	Maturity	Interest	Utilization
CPFL Paulista	9th issue – single series	1,380,000	1,380,000	January 2021	Semiannual	Working capital improvement
CPFL Piratininga	9th issue – single series	215,000	215,000	January 2021	Semiannual	Working capital improvement
RGE	9th issue – single series	220,000	220,000	January 2021	Semiannual	Working capital improvement
CPFL Santa Cruz	2nd issue – single series	190,000	190,000	January 2021	Semiannual	Working capital improvement
CPFL Geração	10th issue – single series	190,000	190,000	December 2018	Semiannual	Working capital improvement
CPFL Brasil	4th issue – single series	115,000	115,000	January 2019	Semiannual	Working capital improvement
RGE Sul	6th issue – single series	520,000 (*)	300,000	December 2020	Semiannual	Working capital improvement
			2,610,000

F-104

 36.2RGE and RGE Sul concession grouping

In March 2018, we requested ANEEL an application of requesting the grouping of the concessions of distributors RGE Sul and RGE in a single concession agreement, being RGE Sul the incorporating company and RGE the incorporated company. The implementation of the grouping of the concessions shall depend on ANEEL’s authorization, as well as on the deliberation and approval by the competent bodies of RGE Sul and RGE.

F-105

 

( 37 )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, 2017 and December 31, 2016 and for the years ended on December 31, 2017, 2016 and 2015 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, 2017	December 31, 2016
Cash and cash equivalents	6,581	64,973
Dividends and interest on capital	204,807	642,978
Other receivables	63,993	83,065
Total current assets	275,382	791,016
Deferred tax assets	145,779	171,073
Investments	8,557,673	7,866,100
Other receivables	484,814	80,775
Total noncurrent assets	9,188,266	8,117,948
Total assets	9,463,648	8,908,964
LIABILITIES	December 31, 2017	December 31, 2016
Debentures	1,938	15,334
Dividends and interest on capital	281,919	218,630
Other payables	19,955	21,791
Total current liabilities	303,812	255,755
Debentures	184,388	612,251
Provision for tax, civil and labor risks	600	1,008
Allowance for equity investment losses	-	19,302
Other payables	13,320	50,628
Total noncurrent liabilities	198,308	683,188
Equity	8,961,528	7,970,021
Total liabilities and equity	9,463,648	8,908,964

F-106

 

UNCONSOLIDATED STATEMENTS OF PROFIT OR LOSS FOR THE YEAR

	2017	2016	2015
Net operating revenue	1	1,713	1,157
General and administrative expenses	(42,771)	��     (50,860)	(29,911)
Income from electric energy service	(42,770)	(49,147)	(28,754)
Equity interests in subsidiaries, associates and joint ventures	1,349,766	922,362	926,951
Finance income (expenses)	(56,471)	17,183	(22,948)
Profit before taxes	1,250,525	890,398	875,250
Social contribution and income tax	(70,775)	10,487	(10,309)
Profit for the year	1,179,750	900,885	864,940
	2017	2016	2015
Profit for the year	1,179,750	900,885	864,940
Items that will not be reclassified subsequently to profit and loss
Equity in comprehensive income of subsidiaries	96,000	(394,175)	65,547
Total comprehensive income for the year	1,275,750	506,709	930,488

UNCONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEAR

	2017	2016	2015
OPERATING CASH FLOW
Profit before taxes	1,250,525	890,398	875,250
ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIES
Depreciation and amortization	217	193	170
Provision for tax, civil and labor risks	61	425	1,497
Interest on debts, inflation adjustment and exchange rate changes	61,520	42,395	94,588
Equity interests in subsidiaries, associates and joint ventures	(1,349,766)	(922,362)	(926,951)
	(37,443)	11,049	44,553
DECREASE (INCREASE) IN OPERATING ASSETS AND LIABILITIES
Dividends and interest on capital received	1,172,336	1,606,073	627,014
Taxes recoverable	65,182	3,261	(12,350)
Other operating assets and liabilities	(19,043)	8,459	(2,526)
CASH FLOWS PROVIDED BY OPERATIONS	1,181,032	1,628,842	656,691
Interest paid on debts and debentures	(71,844)	(45,470)	(36,858)
Income tax and social contribution paid	(47,438)	(27,117)	(2,172)
NET CASH FROM OPERATING ACTIVITIES	1,061,750	1,556,255	617,661
INVESTING ACTIVITIES
Capital increase in investees	(9,400)	-	(490,010)
Advance for future capital increases	(383,340)	(1,384,520)	(52,680)
Other investing activities	(72,435)	(42,178)	10,298
NET CASH USED IN INVESTING ACTIVITIES	(465,175)	(1,426,698)	(532,392)
FINANCING ACTIVITIES
Borrowings and debentures raised	-	609,060	829,997
Repayment of principal of borrowings and debentures	(434,000)	(888,408)	(1,290,000)
Repayment of derivatives	-	(4,711)	-
Dividends and interest on capital paid	(220,966)	(204,717)	(850)
NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES	(654,966)	(488,776)	(460,853)
NET INCREASE IN CASH AND CASH EQUIVALENTS	(58,390)	(359,219)	(375,584)
CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR	64,973	424,192	799,775
CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR	6,581	64,973	424,192

F-107

 

Following is the information relating to CPFL Energia's unconsolidated condensed financial statements presented above:

a.Cash and cash equivalents:

	December 31, 2017	December 31, 2016
Bank balances	508	426
Investment funds	6,073	64,548
Total	6,581	64,973

Amounts invested in an Investment funds, involving investments subject to floating rates tied to the CDI in federal government bonds, CDBs, secured debentures of major financial institutions, with daily liquidity, low credit risk and interest equivalent, on average, to 101% of CDI.

b.Dividends and interest on equity:

	Dividend		Interest on own capital		Total
Subsidiary	December 31, 2017	December 31, 2016	December 31, 2017	December 31, 2016	December 31, 2017	December 31, 2016
CPFL Paulista	49,798	-			49,798	-
CPFL Piratininga	-	72,080	-	-	-	72,080
CPFL Sul Paulista (*)	-	8,641	-	1,986	-	10,627
Companhia Jaguari de Energia (CPFL Santa Cruz)	24,918	6,115	13,960	-	38,878	6,115
RGE	50,319	24,672	-	-	50,319	24,672
CPFL Geração	-	396,086	-	-	-	396,086
CPFL Centrais Geradoras	17	-	-		17	-
CPFL Jaguari Geração	-	1,664	-	-	-	1,664
CPFL Brasil	20,748	86,020	2,361	1,650	23,109	87,671
CPFL Planalto	888	-	-	-	888	-
CPFL Atende	1,003	1,953	620	554	1,623	2,507
Nect	4,348	5,600	-	-	4,348	5,600
CPFL Eficiência Energética	12,195	9,565	17,404	16,325	29,599	25,891
AUTHI	6,228	10,064	-	-	6,228	10,064
	170,461	622,459	34,344	20,516	204,807	642,978

(*) At December 31, 2017 the companies were group in Companhia Jaguari de Energia (note 14.4.2).

c.Other receivables:

	Current		Noncurrent
	December 31, 2017	December 31, 2016	December 31, 2017	December 31, 2016
Income tax and social contribution recoverable	17,051	53,246	-	-
Other taxes recoverable	46,699	29,590	-	-
Associates and subsidiaries	-	-	127,147	52,582
Escrow deposits	-	-	665	710
Advance for future capital increase	-	-	350,000	-
Loans and financing guarantees of subsidiaries	-	-	5,761	26,261
Others	243	229	1,241	1,223
Total	63,993	83,064	484,814	80,775

F-108

 

d.Deferred tax assets

	December 31, 2017	December 31, 2016
Social contribution credit (debit)
Tax losses carryforwards	38,216	42,841
Temporarily nondeductible differences	(408)	1,125
Subtotal	37,808	43,966
Income tax credit (debit)
Tax losses carryforwards	109,103	123,980
Temporarily nondeductible differences	(1,132)	3,126
Subtotal	107,971	127,106
Total	145,779	171,073

e.Investment:

The financial information of subsidiaries and joint ventures are accounted for using the equity method of accounting.

	Number of shares (thousand)	December 31, 2017	December 31, 2016	2017	2016	2015
Investment		Equity  interest		Share of profit (loss) of investees
CPFL Paulista	880,653	1,370,403	1,063,400	280,354	255,329	298,203
CPFL Piratininga	53,096,770	461,059	355,755	152,080	68,114	211,637
CPFL Santa Cruz	-	-	140,520	23,447	23,797	12,424
CPFL Leste Paulista	-	-	52,853	9,589	10,731	13,556
CPFL Sul Paulista	-	-	58,895	10,545	8,455	16,201
CPFL Jaguari	359,058	340,463	30,255	11,720	7,988	4,852
CPFL Mococa	-	-	33,824	6,999	9,198	6,679
RGE	1,019,790	1,680,334	1,614,320	117,700	102,647	145,804
RGE Sul	527,266	1,228,317	-	57,305	-	-
CPFL Geração	205,492,020	2,354,115	2,158,384	594,026	401,148	240,520
CPFL Jaguari Geração (*)	40,108	50,970	45,099	15,709	6,655	6,670
CPFL Brasil	3,000	96,093	109,054	94,455	104,235	81,929
CPFL Planalto (*)	630	3,293	2,101	3,550	2,476	1,830
CPFL Serviços	1,577,706	105,105	97,968	(12,863)	(8,175)	(17,952)
CPFL Atende (*)	13,991	19,338	17,150	7,128	5,833	7,776
Nect (*)	2,059	15,515	10,295	17,392	13,424	18,155
CPFL Total (*)	9,005	20,624	27,570	20,865	12,817	5,836
CPFL Jaguariúna (*)	-	-	1,256,161	(8,360)	(35,498)	(167)
CPFL Telecom	86,420	2,018	(19,302)	(14,021)	(33,333)	(60,718)
CPFL Centrais Geradoras (*)	16,128	16,177	15,459	735	(958)	4,740
CPFL Eficiência Energética	48,164	55,252	61,543	(2,582)	5,926	35,194
Authi (*)	10	18,694	16,810	24,912	24,264	2,537
Subtotal - By subsidiary's equity	��	7,837,770	7,148,112	1,410,685	985,074	1,035,703
Amortization of fair value adjustments of assets		-	-	(60,918)	(62,713)	(108,754)
Total		7,837,770	7,148,112	1,349,766	922,362	926,950
Investment		7,804,429	5,811,894
Advances for future capital increases		33,340	1,355,520
Allowance for equity investment losses		-	(19,302)
(*) number of quotas

F-110

 

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 2017 the Company recognized the amount of R$ 358,891 by way of dividends and interest on capital for the year 2016. The subsidiaries also declared in 2017: (i) interim dividends and interest on capital of R$ 277,612, related to interim profit of 2017; and (ii) R$ 280,191 as minimum mandatory dividend receivable related to 2017.

From the balance of dividends and interest on capital receivable as at December 31, 2016, R$ 12,164 was rectified during 2017.

Of the amounts recorded as receivables, the amount of R$1,172,336 was paid to the Company by the subsidiaries in 2017.

The dividends received are comprised as follows:

	2017	2016	2015
CPFL Paulista	2,228	948,624	425,400
CPFL Piratininga	112,638	267,647	-
CPFL Santa Cruz	8,427	40,009	-
CPFL Leste Paulista	4,449	9,242	-
CPFL Jaguari	-	1,291	806
CPFL Mococa	-	7,991	-
RGE	24,672	172,432	113,012
CPFL Geração	779,533	110,532	-
CPFL Brasil	166,695	1,601	52,599
CPFL Jaguari Geração	11,061	4,288	998
CPFL Planalto	1,471	2,835	1,002
CPFL Serviços	-	-	7,683
CPFL Atende	5,666	3,382	7,899
CPFL Total	17,810	10,767	4,734
Nect	13,424	18,155	10,780
CPFL Centrais Geradoras	-	4,740	1,720
CPFL Eficiência Energética	-	-	380
Authi	24,264	2,537	-
TOTAL	1,172,336	1,606,073	627,014

F-111

 

There are restrictions of transfer of funds from the concessionaires CPFL Paulista, CPFL Piratininga, CPFL Santa Cruz, 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 16, 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 12.2.

f.Interest on debentures:

		December 31, 2017			December 31, 2016
		Current and noncurrent interest	Noncurrent principal	Total	Current and noncurrent interest	Noncurrent principal	Total
5th Issue	Single series	2,817	186,000	188,817	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 and profit sharing of the Executive Officers.

************

F-112