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, 2016
Commission File Number 1‑32297

CPFL ENERGIA S.A.

(Exact name of registrant as specified in its charter)

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

 

Rua Gomes de Carvalho, 1510, 14 ^th floor ‑ Suite 142
CEP 04547‑005 Vila Olímpia ‑ São Paulo, São Paulo
Federative Republic of Brazil
+55 11 3841‑8507
(Address of principal executive offices)

Gustavo Estrella
+55 19 3756 8704 – gustavoestrella@cpfl.com.br
Rodovia Engenheiro Miguel Noel Nascentes Burnier, 1,755, km 2,5
Parque São Quirino
Campinas
São Paulo ‑ 13088 140
Federative Republic of Brazil
(Name, telephone, e‑mail and/or facsimile
number and address of company contact person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:

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

 

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

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

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

As of December 31, 2016, 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, a non-accelerated filer, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," and "emerging growth company" in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer  T	Accelerated Filer  £
Non‑accelerated Filer  £	Emerging Growth Company £

 

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, 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. ¨

        

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 

 

---

† 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.

 

 

 

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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	18
ITEM 4A	Unresolved Staff Comments	67
ITEM 5	Operating and Financial Review and Prospects	67
ITEM 6	Directors, Senior Management and Employees	108
ITEM 7	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	117
ITEM 8	Financial Information	118
ITEM 9	The Offer and Listing	121
ITEM 10	Additional Information	123
ITEM 11	Quantitative and Qualitative Disclosures About Market Risk	142
ITEM 12	Description of Securities Other than Equity Securities	143
ITEM 13	Defaults, Dividend Arrearages and Delinquencies	144
ITEM 14	Material Modifications to the Rights of Security Holders and Use of PROCEEDS	144
ITEM 15	Controls and Procedures	144
ITEM 16A	Audit Committee Financial Expert	146
ITEM 16B	Code of Ethics	146
ITEM 16C	Principal Accountant Fees and Services	146
ITEM 16D	Exemptions from the Listing Standards for Audit Committees	147
ITEM 16E	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	147
ITEM 16F	Change in Registrant’s Certifying Accountant	147
ITEM 16G	Corporate Governance	148

 

 

 

 

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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:

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

CERTAIN TERMS AND CONVENTIONS

A glossary of electricity industry terms is included in this annual report, beginning on page 151. 

 

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$” are to the Brazilian real , the official currency of Brazil.  All references to “U.S. dollars”, “dollar” or “US$” are to U.S. dollars, the official currency of the United States.

We maintain our books and records in reais .  We prepared our consolidated financial statements included in this annual report in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).  Certain figures included in this annual report have been rounded; accordingly, figures shown as totals in certain tables may not be an exact arithmetic aggregation of the figures that precede them.

ITEM 1.                         Identity of Directors, Senior Management and Advisers

Not applicable.

ITEM 2.                         Offer Statistics and Expected Timetable

Not applicable.

ITEM 3.                         Key Information

Selected Financial and Operating Data

The tables below contain a summary of our financial data as of and for years ended December 31, 2016, 2015, 2014, 2013, and 2012.  Our financial data as of December 31, 2016 and 2015 and for each of the three years in the period ended December 31, 2016 was derived from our consolidated financial statements, which appear elsewhere in this annual report and were prepared in accordance with IFRS, as issued by the IASB.  You should read this selected financial data in conjunction with our audited annual consolidated financial statements and the related notes included in this annual report.  Our financial data as of December 31, 2014, 2013 and 2012 and for each of the two years ended December 31, 2013 was derived from our audited annual consolidated financial statements that are not included in this annual report.

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

 

 

STATEMENT OF OPERATIONS DATA

	For the year ended December 31,
	2016 (3)	2016	2015 (4)	2014 (4)	2013 (4)	2012 (4)(5)
	US$	R$	R$	R$	R$	R$
	(in millions, except per share and per ADS data)
Net operating revenue	5,864	19,112	20,599	17,399	14,634	14,891
Cost of electric energy services :
Cost of electric energy	3,437	11,200	13,312	10,643	8,197	8,253
Operating cost	690	2,249	1,907	1,672	1,468	1,378
Services rendered to third parties	416	1,357	1,049	946	1,010	1,356
Gross operating income	1,321	4,306	4,331	4,138	3,960	3,904
Operating expenses :
Sales expenses	168	547	465	403	377	468
General and administrative expenses	261	849	863	774	929	724
Other operating expenses	119	387	358	328	285	377
Income from electric energy service	774	2,523	2,645	2,633	2,370	2,335
Interest in associates and joint ventures	96	311	217	60	121	121
Financial income (expense) :
Income	368	1,201	1,143	786	699	707
Expense	(814)	(2,654)	(2,551)	(1,969)	(1,671)	(1,285)
Net financial income (expenses)	(446)	(1,453)	(1,408)	(1,183)	(971)	(578)
Income before taxes	424	1,381	1,454	1,511	1,519	1,878
Social contribution	(46)	(151)	(160)	(169)	(157)	(178)
Income tax	(108)	(351)	(419)	(455)	(413)	(493)
Total taxes	(154)	(501)	(579)	(624)	(570)	(671)
Net income	270	(879)	875	886	949	1,207
Net income attributable to controlling shareholders	276	901	865	949	937	1,176
Net income (loss) attributable to non‑controlling shareholders	(7)	(22)	10	(63)	12	31
Earnings per share attributable to controlling shareholders (1) :
Basic	0.27	0.89	0.85	0.93	0.92	1.16
Diluted	0.27	0.87	0.83	0.92	0.90	1.14
Net income per ADS:
Basic	0.54	1.77	1.70	1.86	1.84	2.31
Diluted	0.53	1.74	1.66	1.83	1.79	2.28
Dividends (2)	66	214	205	977	931	1,096
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)	0.06	0.21	0.20	0.96	0.91	1.08
Dividends per ADS (2)	0.13	0.42	0.40	1.92	1.83	2.15

(1) Reflects the capital increases that took place on April 29, 2015, and April 29, 2016 through the issuance of 30,739,955 and 24,900,531 shares, respectively.  In accordance with IAS 33, when there is an increase in the number of shares without an increase in issued capital, the number of shares is adjusted retrospectively for all prior periods presented.  For more information, see notes 25.1 and 26 of our audited consolidated financial statements for the year ended December 31, 2016.

 

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(2) “Dividends” represent the total amount of dividends from net income for each period indicated, subject to approval of the shareholders at the general shareholders’ meeting to be held in the following year.

(3) Translated at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2016 of R$3.259 to US$1.00.  The Brazilian real revalued significantly against the U.S. dollar during 2016, however, from R$3.905 to US$1.00 as of December 31, 2015.  The average of the month-end commercial selling rates during the year 2016 was R$3.483 to US$1.00.  See “—Exchange Rates” below for more information regarding the real /U.S. dollar exchange rate.

(4) Data for 2014 and 2015 have been restated to reflect a change in presentation of the line item representing Changes in expected cash flows from Concession Financial Assets, which relates to our Distribution segment.  Since 2016 this line item has been included in Other operating revenues, within Net operating revenue, together with the other income related to the core activity of the asset.  This item was previously presented as part of Net financial expense.  We believe the new presentation more accurately reflects the business model of electricity distribution and provides a better representation of our operational and financial performance.  The reclassification does not affect total assets, equity, net income or cash flows.  For further information on this reclassification, see note 2.7 to our audited consolidated financial statements.  The selected historical financial data for 2013 and 2012 has not been restated to reflect the reclassification, and therefore is not fully comparable with the data for 2016, 2015 and 2014.

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

 

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BALANCE SHEET DATA

 

	For the year ended December 31,
	2016 (2)	2016	2015	2014 (3)	2013	2012 (4)
	US$	R$	R$	R$	R$	R$
	(in millions)
Current assets :
Cash and cash equivalents	1,892	6,165	5,683	4,357	4,206	2,435
Consumers, concessionaires and licensees	1,156	3,766	3,175	2,251	2,008	2,205
Derivatives	50	163	627	23	2	1
Sector financial assets	-	-	1,464	611	-	-
Other current assets	394	1,285	1,559	1,972	1,048	904
Total current assets	3,492	11,379	12,509	9,215	7,264	5,545
Noncurrent assets :
Accounts receivable	62	203	129	123	154	162
Derivatives	197	641	1,651	585	317	486
Sector financial assets	-	-	490	322	-	-
Financial asset of concession	1,646	5,363	3,597	2,835	2,787	2,343
Investments in joint-ventures	458	1,494	1,248	1,099	1,033	1,022
Property, plant and equipment	2,980	9,713	9,173	9,149	7,717	7,104
Intangible Assets	3,306	10,776	9,210	8,930	8,748	9,180
Other noncurrent assets	798	2,602	2,525	2,887	3,022	3,082
Total noncurrent assets	9,448	30,792	28,024	25,930	23,778	23,379
Total assets	12,939	42,171	40,532	35,144	31,043	28,294
Current liabilities :
Short‑term debt (1)	1,052	3,429	3,641	3,526	1,837	1,962
Sector financial liabilities	183	598	-	22	-	-
Other current liabilities	1,532	4,992	5,884	3,869	3,068	3,007
Total current liabilities	2,767	9,018	9,525	7,417	4,906	4,969
Noncurrent liabilities :
Long‑term debt (1)	5,748	18,733	18,093	15,637	15,187	13,511
Sector financial liabilities	97	317	-	-	-	-
Other long‑term liabilities	1,144	3,729	2,785	2,693	2,152	2,553
Noncurrent liabilities	6,990	22,780	20,877	18,330	17,339	16,064
Non-controlling interest	737	2,403	2,456	2,454	1,775	1,510
Net equity attributable to controlling shareholders	2,445	7,970	7,674	6,944	7,024	6,381
Total liabilities and shareholders’ equity	12,939	42,171	40,532	35,144	31,043	28,294

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

(2) Translated at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2016 of R$3.259 to US$1.00.

(3) Data for 2014 have been restated due the completion of the accounting for the purchase price allocation related to acquisition of Dobrevê Energia S.A.  - (“DESA”), as stated in note 15.4.2 of our audited consolidated financial statements for the year ended December 31, 2015.

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

 

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OPERATING DATA

 

	For the year ended December 31,
	2016	2015	2014	2013	2012 (4)
Energy sold (in GWh):
Residential	16,473	16,164	16,501	15,426	14,567
Industrial	13,022	12,748	14,144	14,691	14,536
Commercial	9,720	9,259	9,437	8,837	8,714
Rural	2,474	2,152	2,326	2,081	2,093
Public administration	1,271	1,278	1,295	1,234	1,220
Public lighting	1,746	1,649	1,622	1,586	1,525
Public services	1,840	1,797	1,861	1,820	1,864
Own consumption	32	33	34	34	33
Total energy sold to Final Consumers	46,578	45,082	47,221	45,709	44,552
Electricity sales to wholesalers (in GWh)	21,459	17,971	14,988	14,975	14,429
Total consumers (in thousands) (1)	9,224	7,751	7,585	7,386	7,176
Installed Capacity (in MW) (2)	3,259	3,164	3,162	2,988	2,961
Assured Energy (in GWh) (3)	14,188	13,550	13,566	12,758	12,742
Energy generated (in GWh)	15,713	17,066	13,658	11,427	10,570

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

(2) Commencing in 2016 we ceased to account for installed capacity of the Carioba (36 MW) thermoelectric plant and SHPP Cariobinha (1.3 MW) , since these facilities are no longer active.

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

(4) 2012 volume information was restated for purposes of comparison of operational and financial information, due to the adoption of IFRS 11 – Joint Arrangements.

 

Convenience Translations into U.S. Dollars

Solely for the investor’s convenience, we have translated certain amounts included in this annual report from reais into U.S. dollars at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2016 of R$3.259 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 the real /U.S. dollar exchange rate.

Exchange Rates

The Brazilian Central Bank allows the real /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 the real float freely or will intervene in the exchange rate market through a currency band system or otherwise.  The real may 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 in reais per U.S. dollar (R$/US$), for the periods indicated.

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

 

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	Month‑end	Average for period (1)	Low	High
	( reais per U.S. dollar)
Month ended :
October 2016	3.181	3.186	3.119	3.236
November 2016	3.397	3.342	3.202	3.445
December 2016	3.259	3.352	3.259	3.465
January 2017	3.127	3.197	3.127	3.273
February 2017	3.099	3.104	3.051	3.148
March 2017	3.093	3.128	3.077	3.174
April 2017 (through April 10 )	3.141	3.120	3.092	3.141

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

 

Risk Factors

Risks Relating to Our Operations and the Brazilian Power Industry

We are subject to comprehensive regulation of our business, which fundamentally affects our financial performance.

Our business is subject to extensive regulation by various Brazilian regulatory authorities, particularly the National Electric Energy Agency ( Agência Nacional de Energia Elétrica ), or ANEEL.  ANEEL regulates and oversees various aspects of our business and establishes our tariffs.  If we are obligated by ANEEL to make additional and unexpected capital investments and are not allowed to adjust our tariffs accordingly, if ANEEL does not authorize the recovery of all costs or if ANEEL modifies the regulations related to tariff adjustments, we may be adversely affected.

In addition, both the implementation of our strategy for growth and our ordinary business may be adversely affected by governmental actions such as changes to current legislation, the termination of federal and state concession programs, creation of more rigid criteria for qualification in public energy auctions, or a delay in the revision and implementation of new annual tariffs.

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

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

The Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as the Lei do Novo Modelo do Setor Elétrico , or New Industry Model Law.  Challenges to the constitutionality of the New Industry Model Law are still pending before the Brazilian Federal Supreme Court ( Supremo Tribunal Federal ).  If all or part of the New Industry Model Law were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework.  The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including our business and results of operations.

 

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We are uncertain as to the renewal of our concessions and authorizations.

We carry out our generation, transmission and distribution activities pursuant to concession agreements entered into with the Brazilian government.  Our concessions range in duration from 20 to 35 years.  The Brazilian Federal constitution requires all concessions relating to public services to be awarded through public tender.  Under laws and regulations specific to the electric energy sector, the Brazilian government may renew existing concessions for an additional period of up to 20 or 30 years, depending on the nature of the concession, without public tender, provided that the concessionaire has met minimum performance, financial and other relevant standards, and provided that the proposal is otherwise acceptable to the Brazilian government.  The Brazilian government has considerable discretion under Law No.  8,987/95, or the Concession Law, Law No.  9,074/95, Decree No.  7,805/12, Law No.12,783/13, Decree No.  8,461/15 and under concession contracts regarding renewal of concessions.  Furthermore, we may also be subject to new regulations enacted by the Brazilian government that could retroactively affect the rules for renewal of our concessions and authorizations .

The tariffs that we charge for sales of electricity to Captive Consumers and the tariffs for using the distribution system that we charge to Free and Special Consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us.

ANEEL has substantial discretion to establish the tariff rates that our distribution companies charge our consumers.  Our tariffs are determined under concession agreements with the Brazilian government, and in accordance with ANEEL’s regulations and decisions.

Our concession agreements and Brazilian law establish a mechanism that allows for three types of tariff adjustments:  (i) annual adjustment ( reajuste tarifário anual ), or RTA, (ii) periodic revision ( revisão tarifária periódica ), or RTP, and (iii) extraordinary revision ( revisão tarifária extraordinária ), or RTE.  We are entitled to apply each year for the annual adjustment, which is designed to offset some effects of inflation on tariffs and pass through to consumers certain changes in our cost structure that are beyond our control, such as the cost of the electricity we purchase and certain regulatory charges, including charges for the use of transmission and distribution facilities.  ANEEL generally carries out the RTP periodic tariff revision every four or five years (according to the terms of each concession agreement).  The objective of this periodic revision is to share gains with consumers and incentivize concessionaires to increase efficiency levels.  As such, it aims to identify variations in our costs and set a reduction factor based on our operational efficiency that will be applied against the index of our ongoing annual tariff adjustments.  Extraordinary revisions of our tariffs may occur at any time, or may be requested by us.  Extraordinary revisions may have a negative effect on our results of operations or financial position, or may serve to offset unpredictable costs (such as taxes that significantly change our cost structure).  In addition, ANEEL currently reviews the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis, whereas previously all methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.

We cannot predict whether ANEEL will establish tariffs or methodologies that are favorable to us.  See “Item 5.  Operating and Financial Review and Prospects—Background—Periodic Revisions—RTP”.

We may not be able to comply with the terms of our concession agreements and authorizations, which could result in fines, other penalties and, depending on the gravity of the non‑compliance, in our concessions or authorizations being terminated.

ANEEL may impose penalties on us in the event that we fail to comply with any provision of our concession agreements or authorizations.  Depending on the gravity of the non‑compliance, these penalties could include the following: 

 

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

We are currently in compliance with all of the material terms of our concession agreements and authorizations.  However, we cannot assure you that we will not be penalized by ANEEL for breaching our concession agreements or authorizations or that our concessions or authorizations will not be terminated in the future.  The compensation to which we are entitled upon expiration or early termination of our concessions or authorizations may not be sufficient for us to realize the full value of certain assets.  In addition, if any of our concession agreements or authorizations is terminated for reasons attributable to us, the effective amount of compensation by the granting authorities could be materially reduced through the imposition of fines or other penalties.  Accordingly, the imposition of fines or penalties on us or the termination of any of our concessions or authorizations could have a material adverse effect on our financial condition and results of operations.

The distribution concessions held by our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista were originally granted in 1999 for a sixteen‑year term and have recently been extended to July 2045.  The extensions were granted under the new laws and regulations regarding distribution concessions, so the concessions are now subject to the new targets and standards established by the Brazilian authorities. There is as yet no precedent regarding how the authorities will act under these new laws and regulations, which include certain variables that are beyond our control and which may therefore impair our ability to fully achieve the relevant goals.  If we do not achieve the applicable goals, our distribution concessions and, therefore, our revenues could be adversely affected.  See “Item 4—Information on the Company— Concessions, Permissions and Authorizations —Concessions”.

In our Distribution business, we are required to forecast demand for electricity in the market.  If actual demand is different from our forecast, we could be forced to purchase or sell electricity in the spot market at prices that could lead to additional costs for us, which we may not be able to fully pass on to customers.

Under the New Industry Model Law, an electricity distributor must contract in advance, through public bids, for 100% of the required electricity that it has forecast for its distribution concession areas, and is authorized to pass through the cost of up to 105% of this electricity to consumers.  Over- or under-forecasting demand can have adverse consequences.  If we under-forecast demand and purchase in advance less electricity than we need, in a manner for which we are considered liable under the New Industry Model Law and applicable regulation, we may be required to enter the spot market to purchase the additional electricity at prices substantially higher than under our long term purchase agreements.  We may be prevented from passing through this additional cost in full to consumers; and we would also be subject to penalties under applicable regulation.  On the other hand, if we over-forecast demand and purchase in advance more electricity than we need (for example, if a significant portion of our Potential Free Consumers migrate and purchase electricity in the Free Market), we may be required to sell the excess at prices substantially lower than under our concessions and authorizations.  In either circumstance, if there are significant differences between our forecast electricity needs and actual demand, our results of operations may be adversely affected.  See “Item 4.  Information on the Company—The Brazilian Power Industry—The New Industry Model Law” and “Item 4.  Information on the Company—Distribution—Purchases of Electricity”.

 

On August 2, 2012, the Brazilian Ministry of Mines and Energy (MME) enacted Ordinance.  No.  455, which prohibited ex 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 of volume requirements under Ordinance No.  455/2012.  As a result, Ordinance No.  455/2012 has been suspended for all CCEE participants (Generators, Traders and Free Consumers), since it may not be applied selectively to a specific group.  If the injunction is lifted, and if our projected energy volume proves incorrect so that we purchase less or more electricity than we need in the Free Market, we would no longer be able to adjust for our exposure to the energy volume purchased.  See “Item 4.  Information on the Company—The New Industry Model Law—Recent Developments in the Free Market”.

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

We are dependent on the prevailing hydrological conditions in Brazil.  In 2016, according to data from the National Electrical System Operator (Operador Nacional do Sistema Elétrico), or ONS, approximately 76% of Brazil’s electricity supply came from Hydroelectric Power Plants.

Brazil is subject to unpredictable hydrological conditions, with non‑cyclical deviations from average rainfall.  When hydrological conditions are poor, the ONS may dispatch Thermoelectric Power Plants, including those that we operate, to top up hydroelectric generation and maintain security levels in reservoirs and the electricity supply level in cases when the Hydroelectric Power Plants in Brazil, including those we operate, are unable to generate sufficient energy to honor their Assured Energy requirement in the Energy Reallocation Mechanism ( Mecanismo de Realocação de Energia ), or MRE.  This deficit of hydroelectric energy, referred to as the Generation Scaling Factor, or GSF, therefore exposes operators of Hydroelectric Power Plants to spot price risk.  The GSF was activated in 2014, 2015 and 2016, requiring us to purchase energy, therefore leading to adverse results in our Generation segment.  Under Federal Law 13,203 of December 8, 2015, we have effectively capped our exposure to this risk for the life of our existing PPAs in our Generation segment, and have covered the cash outlay from January 2015 to July 2020 through the GSF payment we made in 2015 regarding the electricity required to serve our consumers in the Regulated Market.  We remain exposed to this spot price risk, however, with respect to the cost of electricity required to serve our consumers in the Free Market.  For further information, see “Item 4.  Information on the Company—The Brazilian Power Industry—Generation Scaling Factor.”

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

 

In January 2015, the electricity sector began to implement a mechanism of monthly “tariff flags” under which consumer invoices may be subject to tariff additions on a monthly basis when energy supply costs reach certain levels, enabling consumers to adapt their usage to current energy costs.  Revenues collected under the tariff flag system are repaid to distribution companies on the basis of their relative energy cost for the period.  Due to the poor hydrological conditions that were observed from 2013 through 2015, red tariff flags were applied throughout 2015 since introduction of the system in January 2015.  In 2016, due to an improvement in hydrological conditions, green tariff flags were applied in most months of the year.  Although this mechanism mitigates the cash flow mismatch in part, it may be insufficient to cover the thermoelectric energy supply costs, and Distributors still bear the risk of cash flow mismatches in the short term.  See “Item 4.  Information on the Company—The Brazilian Power Industry—Basis of Calculation of Distribution Tariffs”.

 

 

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The impact of an electricity shortage and related electricity rationing, as in 2001 and 2002, may have a material adverse effect on our business and results of operations.

Periods of severe or sustained below‑average rainfall resulting in an electricity shortage may adversely affect our financial condition and results of operations.  For example, during the low rainfall period of 2000 and 2001, the Brazilian government instituted the Rationing Program, a program to reduce electricity consumption that was in effect from June 1, 2001 to February 28, 2002.  The Rationing Program established limits for energy consumption for industrial, commercial and residential consumers, with reductions in consumption ranging from 15% to 25%.  If Brazil experiences another electricity shortage (a condition which might happen and we are not able to control or anticipate), the Brazilian government may implement similar or other policies in the future to address the shortage.  For example, electricity conservation programs, including mandatory reductions in electricity consumption, could be implemented if poor hydrological conditions cannot be offset in practice by other energy sources, such as Thermoelectric Power Plants, thereby resulting in a low supply of electricity to the Brazilian market.

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

Decree No.  2,655 of July 2, 1998 established that the Assured Energy of generation power plants would be revised every five years.  As part of these revisions, the Brazilian Ministry of Mines and Energy (MME) can revise a company’s Assured Energy, limited to a maximum change of 5% per revision or 10% over the entire period of the concession agreement.  According to Ordinance No.  515/2015 issued by the MME, the first revision of Assured Energy under this process was originally expected to be implemented for all Hydroelectric Power Plants (with the exception of SHPPs) in January 2017.  Since the application of the methodology of this new revision to each Power Plant is not yet available, however, the MME issued Ordinance No.  714/2016, pursuant to which the current Assured Energy for each Hydroelectric Power Plant will remain in effect until December 2017.  The first revision of Assured Energy is now expected to be implemented in January 2018.  We cannot be certain how the MME’s revisions will affect the Assured Energy of each of our individual Power Plants, and whether it will increase or decrease our overall Assured Energy.  If the Assured Energy of a Power Plant is decreased, our ability to supply electricity under that plant’s power purchase agreements would be adversely affected, which could lead to a decrease in our revenues and increase our costs if our generation subsidiaries are required to purchase power elsewhere.  We expect similar revisions of Assured Energy under Decree 2,655/98 to continue to take place every five years.  See “Item 4 — Principal Regulatory Authorities — Ministry of Mines and Energy - MME”.

Construction, expansion and operation of our electricity generation, transmission and distribution facilities and equipment involve significant risks that could lead to lost revenues or increased expenses.

The construction, expansion and operation of facilities and equipment for the generation, transmission and distribution of electricity involve many risks, including:

• the inability to obtain required governmental permits and approvals;  
   
• the unavailability of equipment;  
   
• supply interruptions;  
   
• work stoppages;  
   
• labor unrest;  
   
• social unrest;  
   
• weather and hydrological interferences;  
   
• unforeseen engineering, regulatory and/or environmental problems;
   
• increases in electricity losses, including technical and commercial losses;

 

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• 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, and any mitigating or aggravating circumstances applicable to the violator.  It is possible that enhanced environmental and health regulations will force us to allocate capital expenditures to compliance, and consequently, increase our level of investment or divert funds from existing planned investments, either of which could have a material adverse effect on our financial condition and results of operations.

If we are unable to complete our proposed capital expenditure program in a timely manner, the operation and development of our business may be adversely affected.

We plan to invest approximately R$1,011 million in our Generation activities (R$954 million in renewable sources and R$57 million in conventional sources), R$9,222 million in our Distribution activities, R$264 million in our commercialization and services activities and R$ 48 million in our transmission activities during the period from 2017 through 2021. At the date of this Annual Report, however, these planned capital expenditures have not yet been approved by our Board of Directors, and they therefore remain subject to change. Our ability to carry out this capital expenditure program depends on a variety of factors, including our ability to charge adequate tariffs for our services, our access to domestic and international capital markets and a variety of operating, regulatory and other contingencies.  We cannot be certain that we will have the financial resources to complete our proposed capital expenditure program, and failure to do so could have a material adverse effect on the operation and development of our business.

 

In addition to the capital expenditures shown above, we invested R$51 million in 2016 and R$37 million in 2015 related to the construction of our transmission lines (under our Transmission activities), which, in accordance with the requirements of IFRIC 12, was recorded as a financial asset of concession in noncurrent assets.

We plan to make capital expenditures aggregating approximately R$2,722 million in 2017 and approximately R$2,061 million in 2018, in each case subject to approval by our Board of Directors.  Of total budgeted capital expenditures over this period, R$3,772 million are expected to be invested in our Distribution segment, R$846 million in our Renewable Generation segment and R$28 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$135 million in our commercialization and services activities.  We have already contractually committed to part of these expenditures, particularly in generation projects.  See “—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments”.  Planned capital expenditures for development of our generation capacity, and the related financing arrangements, are discussed in more detail under “Item 4.  Information on the Company—Generation of Electricity”.

 

 

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We are strictly liable for any losses and damages resulting from inadequate provision of electricity services, and our contracted insurance policies may not fully cover such losses and damages.

Under Brazilian law, we are strictly liable for direct and indirect losses and damages resulting from the inadequate provision of electricity distribution services.  In addition, our distribution facilities may, together with our transmission and generation utilities, be held liable for losses and damages caused to others as a result of interruptions or disturbances arising from the generation, transmission or distribution systems, whenever these interruptions or disturbances are not attributed to an identifiable member of the ONS.  Until all responsible parties are identified, liability for any losses and damages is attributed as follows:  (i) 35.7% to distribution entities; (ii) 28.6% to transmission entities; and (iii) 35.7% to generation entities.  These percentages are based on the number of votes that each concessionaire has in general meetings of the ONS and, therefore, may change in the future.  We cannot assure you that our contracted insurance policies will fully cover damages resulting from inadequate rendering of electricity services, which may have an adverse effect on us.

We may not be able to create the expected benefits and return on investments from our renewable energy generation businesses. 

Through our subsidiary CPFL Renováveis we have made substantial capital investments (amounting to R$1,724 million for the last three fiscal years) in generation businesses other than hydroelectric power, principally wind and biomass generation.  These renewable generation businesses are dependent on certain factors that are not within our control and may significantly affect these businesses.

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

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

Our controlling shareholder’s interests could conflict with yours. 

On January 23, 2017, State Grid Brazil Power Participações Ltda., or State Grid Brazil, consummated the acquisition of common shares representing approximately 54.6% of our voting capital, pursuant to which it has the power to control us.  State Grid Brazil is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.  Our controlling shareholder may take actions that could be contrary to your interests, and our controlling shareholder will be able to prevent other shareholders, including you, from blocking these actions.  In particular, our controlling shareholder controls the outcome of decisions at shareholders’ meetings, and it can elect a majority of the members of our Board of Directors.  Our controlling shareholder can direct our actions in areas such as business strategy, financing, distributions, acquisitions and dispositions of assets or businesses.  Its decisions on these matters may be contrary to the expectations or preferences of our non-controlling shareholders, including holders of our ADSs.  For further information regarding State Grid Brazil’s acquisition and its announced intentions regarding shareholdings in our company, see “Item 4.  Information on the Company— Overview”.

We are exposed to increases in prevailing market interest rates as well as foreign exchange rate risk.

As of December 31, 2016, approximately 75% of our total indebtedness was denominated in reais and indexed to Brazilian money‑market rates or inflation rates, or bore interest at floating rates.  The remaining 25% of our total indebtedness as of December 31, 2016 was denominated in foreign currency, substantially U.S. dollars, compared to approximately 32.0% as of December 31, 2015, although this foreign currency denominated debt is substantially subject to currency swaps that convert these obligations into reais .  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 Brazilian real appreciates against the U.S. dollar, as was the case in 2016, 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, 2016, we had total debt of R$22,044 million.  Our indebtedness increases the possibility that we may be unable to generate cash sufficient to pay when due the principal, interest or other amounts due in respect of our indebtedness.  In addition, we may incur additional debt from time to time to finance acquisitions, investments, joint ventures or for other purposes, subject to the restrictions applicable under our existing indebtedness, such as when we acquired RGE Sul in October 2016.  If we incur additional debt, the risks associated with our leverage would increase. 

We may acquire other companies in the electricity business, as we have in the past, and these acquisitions could increase our leverage or adversely affect our consolidated performance.

We regularly analyze opportunities to acquire other companies engaged in activities along the entire electricity generation, transmission and distribution chain, such as when we acquired RGE Sul in October 2016.  If we do acquire other electricity companies, this could increase our leverage or reduce our profitability.  Furthermore, we may not be able to integrate the acquired company’s activities and achieve the economies of scale and expected efficiency gains that often drive such acquisitions.  Any such failure could harm our financial condition and results of operations.

The level of default by our consumers could adversely affect our business, operational results, and/or financial situation.

The level of default by our consumers may be affected by economic factors such as income levels, unemployment, interest rates, inflation and the price of energy.  The current macroeconomic situation in Brazil, combined with the increase in energy prices in recent years, could lead to an increase in default by our consumers.  Although we have implemented a number of measures to improve payment collection, we cannot assure you that these measures will be sufficient or effective in maintaining our consumer default at current levels.  If the level of default increases, our business, operational results and financial situation could be adversely affected.

Risks Relating to Brazil

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

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

• interest rates;
   
• monetary policy;
   
• currency fluctuations;
   
• inflation;
   
• liquidity of domestic capital and lending markets;

 

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Uncertainty over whether the Brazilian government will change policies or regulations affecting these or other factors may contribute to political and economic uncertainty in Brazil and to heightened volatility in Brazilian securities markets and securities issued abroad by Brazilian issuers.  Standard & Poor’s downgraded Brazil below investment grade on September 9, 2015 (BB+) and again on February 17, 2016 (BB-); Fitch Ratings lowered its rating for Brazil from BBB- to BB+ on December 16, 2015 and later to BB with negative outlook on May 5, 2016; and Moody’s Investors Service downgraded Brazil to Ba2 with negative outlook on February 24, 2016 and has reaffirmed such rating on March 15, 2017. These downgrades reflected poor economic conditions, continued adverse fiscal developments and increased political uncertainty in Brazil.

We cannot assure you that the Brazilian government will continue with its current economic policies, or that these and other developments in Brazil’s economy and government policies will not, directly or indirectly, adversely affect our business and results of operations. 

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

Current political conditions in Brazil may affect the confidence of investors and the public in general as well as the development of the economy.  Following the impeachment of former President Dilma Rousseff on August 31, 2016, uncertainty remains with regard to matters such as the presidential administration’s future policies and appointments to influential governmental positions and ongoing investigations into allegations of corruption in state-controlled enterprises, which may affect the confidence of investors and the general public.  It may also have an adverse impact on the Brazilian economy, our business, financial condition, results of operations and the market price of our common shares and ADSs.

Currently, Brazilian markets are experiencing heightened volatility due to the uncertainties derived from changes in the political scenario and from the ongoing Lava Jato investigation, being conducted by the Office of the Brazilian Federal Prosecutor, and its impact on the Brazilian economy and political environment. Members of the Brazilian federal government and of the legislative branch, as well as senior officers of large state-owned companies, have faced allegations and, in certain cases, convictions related to crimes of political corruption, involving alleged bribes by means of kickbacks on contracts granted by the government to several infrastructure, oil and gas and construction companies.  The profits of these kickbacks allegedly financed the political campaigns of political parties of the government that were unaccounted for or not publicly disclosed, in addition to alleged personal enrichment of the recipients of the bribes. Certain of these companies are also facing investigations by the Brazilian Securities Commission (Comissão de Valores Mobiliários), or CVM, the U.S. Securities and Exchange Commission, or the SEC and the United States Department of Justice, or the DOJ.

The potential outcome of these investigations is still uncertain, but they have already an adverse impact on the image and reputation of the implicated companies, political parties and on the general market perception of the Brazilian economy and political scenario.  We cannot predict whether such allegations and convictions will lead to further political and economic instability or whether new allegations or convictions against government officials will arise in the future.  In addition, we cannot predict the outcome of any such allegations and convictions nor their effect on the Brazilian economy.

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

 

 

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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 the real against the U.S. dollar was R$2.656 on December 31, 2014; R$3.905 on December 31, 2015; and R$3.259 on December 31, 2016.  On April 10, 2017, the exchange rate was R$3.141 per US$1.00.  The real may continue to fluctuate significantly against the U.S. dollar in the future.

Depreciation of the real increases 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 the real against 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 the real against 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 the real relative 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 the real could materially and adversely affect the growth of the Brazilian economy and our business, financial condition and results of operations.

Depreciation of the real  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 real interest rates in the world.  Between 2007 and 2016, the base interest rate in Brazil, or SELIC, varied between 7.25% p.a.  and 13.75% p.a., reaching its lowest level (7.25%) at the end of 2012.  On April 10, 2017, the SELIC rate was 12.25 % p.a.  Inflation has had and may in the future have significant effects on the Brazilian economy and our business.  Relatively lenient interest rate policies by the government and Brazilian Central Bank may trigger increases in inflation, and, consequently, volatility in growth and the need for sudden and significant interest rate increases, which could negatively affect our business.  In addition, if Brazil again experiences high inflation, we may not be able to adjust the rates we charge our consumers to offset the effects of inflation on our cost structure.  Conversely, tight monetary policies with high interest rates may restrict Brazil’s growth and the availability of credit.

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

The market value of securities of Brazilian issuers is affected by economic and market conditions in other countries, including the United States, the European Union and emerging market countries.  The global financial crisis that commenced in 2008 led to significant consequences, including stock and credit market volatility, unavailability of credit, higher interest rates, a general economic slowdown, volatile exchange rates and inflationary pressure.  Global recovery from this crisis has been slower than expected in recent years, with the largest emerging economies of China, Brazil and India posting weaker than expected results and the European Union is continuing to experience weak GDP growth, although the United States posted GDP growth of 1.6% in 2016.  Although economic conditions in other countries may differ significantly from economic conditions in Brazil, investor reactions to developments in those countries may have an adverse effect on the market value of securities of Brazilian issuers.  Crises in the United States, the European Union, China or emerging market countries may diminish investor interest in securities of Brazilian issuers, including ours.  This could adversely affect the trading price of the ADSs or our common shares, and could also make it more difficult for us to access the capital markets and finance our operations in the future on acceptable terms or at all.

 

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Risks Relating to the ADSs and Our Common Shares

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

Holders of our ADSs do not have the same voting rights as holders of our common shares.  Holders of our ADSs are entitled to the contractual rights set forth for their benefit under the deposit agreements.  ADS holders exercise voting rights by providing instructions to the depositary, as opposed to voting at shareholders’ meetings or by proxy.  In practice, the ability of a holder of ADSs to instruct the depositary as to voting will depend on the timing and procedures for providing instructions to the depositary, either directly or through the holder’s custodian and clearing system.  For further information, see “Item 10.Additional Information—Voting Rights of ADS Holders”.

If you surrender your ADSs and withdraw common shares, you risk losing the ability to remit foreign currency abroad and certain Brazilian tax advantages.

As an ADS holder, you benefit from the electronic registration made by the custodian with the Brazilian Central Bank’s Information System, or the SISBACEN, for our common shares underlying the ADSs in Brazil, which permits the custodian to remit abroad proceeds related to dividends and other distributions with respect to the common shares.  If you surrender your ADSs and withdraw common shares, you will need to update your registration with the SISBACEN and enter into simultaneous foreign exchange transactions (without the effective remittance of funds) in order to re-enable the remittance abroad of proceeds related to the disposition of or distributions relating to the common shares.  Before entering into these foreign exchange transactions and updating the SISBACEN registration, you will not be able to remit abroad any proceeds relating to the common shares.  If you do not qualify under the foreign investment regulations you will generally be subject to less favorable tax treatment upon the sale of our common shares.  For further information, see “Item 10.  Additional Information— Allocation of Net Income and Distribution of Dividends-Payment of Dividends”.

For the registration with the SISBACEN referred to above, as well as for entering into simultaneous foreign exchange transactions, you may incur expenses or suffer delays in the application process, which could delay your ability to receive dividends or distributions relating to our common shares or the return of your capital in a timely manner.  The depositary’s electronic registration with SISBACEN may also be adversely affected by future legislative changes.

Holders of ADSs may be unable to exercise preemptive rights with respect to our common shares.

We may not be able to offer our common shares to U.S. holders of ADSs pursuant to preemptive rights granted to holders of our common shares in connection with any future issuance of our common shares unless a registration statement under the Securities Act is effective with respect to such common shares and preemptive rights, or an exemption from the registration requirements of the Securities Act is available.  We are not obligated to file a registration statement relating to preemptive rights with respect to our common shares, and we cannot assure you that we will file any such registration statement.  If such a registration statement is not filed and an exemption from registration does not exist, Citibank N.A., as depositary, will attempt to sell the preemptive rights, and you will be entitled to receive the proceeds of such sale.  However, these preemptive rights will expire if the depositary does not sell them, and U.S. holders of ADSs will not realize any value from the granting of such preemptive rights.

The relative volatility and illiquidity of the Brazilian securities markets may substantially limit your ability to sell the common shares underlying the ADSs at the price and time you desire.

Investing in securities that trade in emerging markets, such as Brazil, often involves greater risk than investing in securities of issuers in the United States, and such investments are generally considered to be more speculative in nature.  The Brazilian securities market is substantially smaller, less liquid, more concentrated and can be more volatile than major securities markets in the United States.  Accordingly, although you are entitled to withdraw the common shares underlying the ADSs from the depositary at any time, your ability to sell the common shares underlying the ADSs at a price and time at which you wish to do so may be substantially limited.  There is also significantly greater concentration in the Brazilian securities market than in major securities markets in the United States.  The ten largest companies in terms of market capitalization represented 54.9% of the aggregate market capitalization of the BM&FBOVESPA S.A.  ‑ Bolsa de Valores, Mercadorias & Futuros , or BM&FBOVESPA, as of December 31, 2016.  The top ten stocks in terms of trading volume accounted for 42.8%, 39.3% and 46.3% of all shares traded on the BM&FBOVESPA in 2016, 2015, and 2014, respectively.

 

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ITEM 4.                         Information on the company

Overview

We are a corporation ( sociedade por ações ) incorporated and existing under the laws of Brazil with the legal name CPFL Energia S.A.  Our principal executive offices are located at Rua Gomes de Carvalho, 1,510, 14 ^th  floor – Suite 142, Vila Olímpia, CEP 04547‑005, São Paulo, state of São Paulo, Brazil and our telephone number is +55 11 3841‑8507.  Our Investor Relations Department is located at Rodovia Engenheiro Miguel Noel Nascentes Burnier, Km 2.5, nº 1,755, Parque São Quirino, CEP 13088-900, Campinas, state of São Paulo, Brazil, and its telephone number is +55 19 3756‑6083. 

We are a holding company that, through our subsidiaries, distributes, generates, transmits and commercializes electricity in Brazil as well as provides energy-related services.  We were incorporated in 1998 as a joint venture among VBC Energia S.A., or VBC, 521 Participações S.A.  and Bonaire to combine their interests in companies operating in the Brazilian power sector.

We are one of the largest electricity distributors in Brazil, based on the 39,611 GWh of electricity we distributed to approximately 9.2 million consumers in 2016.  In electricity generation, our Installed Capacity at December 31, 2016 was 3,259 MW.  Through our subsidiary CPFL Renováveis, we are also involved in the building of one SHPP and two wind farms, as a result of which we expect to increase our Installed Capacity to 3,297 MW over the next five years as they are completed.

We also engage in power commercialization, buying and selling electricity to power producers, Free Consumers and power trading companies.  We also provide agency services to Free Consumers before the CCEE and other agents as well as electricity‑related services to our affiliates and unaffiliated parties.  In 2016, the total amount of electricity sold by our commercialization subsidiaries was 90 GWh and 12,291 GWh to affiliated and unaffiliated parties, respectively.

On September 2, 2016, our shareholder Camargo Correa entered into an agreement to sell its 23.6% stake in our company to State Grid Brazil Participações Ltda., or State Grid Brazil.  Following the announcement, other members of our controlling shareholders block also decided to sell their stakes to State Grid Brazil.  As a result, State Grid Brazil acquired approximately 54.6% of our voting capital.  State Grid Brazil is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.  The acquisition was approved by the Administrative Council for Economic Defense (Conselho Administrativo de Defesa Econômica – CADE), the Brazilian antitrust regulator, in September 2016 and by ANEEL in December 2016.  The acquisition was completed and control of our company was transferred to State Grid Brazil on January 23, 2017.  On February 16, 2017, State Grid Brazil announced that it intends to carry out a public tender offer to purchase all of the common shares of our company, at a price of  R$ 25.51 (US$ 8.28) per common share, in order to (i) cancel our registration as a Class A publicly-held company with the Brazilian Securities Commission (Comissão de Valores Mobiliários), or CVM; (ii) delist our company from the Novo Mercado section of the São Paulo Stock Exchange; (iii) delist our ADSs from the New York Stock Exchange and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the U.S. Securities and Exchange Commission. As per Significant Event Notice disclosed by both companies to the market on February 23, 2017, State Grid Brazil filled with CVM in February 22, 2017 requiring authorization for a Public Tender Offer for acquisition of CPFL Energia’s shares. Such request is currently under analysis by CVM.

The following significant developments have occurred in our business since the beginning of 2014:

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

 

 

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The following chart provides an overview of our corporate structure at March 31, 2017: 

   

Notes:

(1) 51.54% stake of the availability of power and energy of Serra da Mesa HPP, regarding the Power Purchase Agreement between CPFL Geração and Furnas.

(2) CPFL Energia holds RGE Sul through CPFL Jaguariúna.

 

Our core businesses are:

 

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In addition to our five operating segments above, we consolidate a number of activities known as “Other”.  The activities consolidated under Other consist of (i) two transmission assets held through CPFL Geração, of which one (CPFL Piracicaba) is operational and the other (CPFL Morro Agudo) is under construction, (ii) CPFL Telecom and (iii) our holding company expenses other than the amortization of intangible assets related to our concessions, which is allocated to our operational segments.

Our Strategy

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

Complete the development of our existing renewable generation projects, expand our generation portfolio by developing new conventional and renewable energy generation projects and maintain our position as market leader in renewable energy sources.  At December 31, 2016, our total consolidated Installed Capacity (calculated on the proportional basis of our 51.60% interest in CPFL Renováveis) was 3,259 MW, of which 2,199 MW was generated through conventional sources and 1,060 MW through renewable sources.  Through CPFL Renováveis, in August 2011 we became the largest renewable energy generation group in Brazil in terms of Installed Capacity and capacity under construction, according to ANEEL.  Today, we continue to be the largest energy renewable generation group in terms of Installed Capacity in operation in Brazil and in South America, according to ANEEL and Bloomberg New Energy Outlook.

 

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

Many of our generation facilities hold long‑term PPAs approved by ANEEL, which we believe will ensure us an attractive rate of return on our investment.  We also have a consolidated portfolio of 1,099 MW (calculated on the proportional basis of our 51.60% interest in CPFL Renováveis’ total portfolio of 2,129 MW) of renewable generation projects to be developed by CPFL Renováveis in the coming years.  When electricity consumption in Brazil returns to growth, we believe that there will continue to be new opportunities for us to explore investments in additional conventional and renewable generation projects. 

Focus on further improving our operating efficiency .  The distribution of electricity in our distribution concession areas is our largest business segment, representing approximately 46.3% of our consolidated net income in 2016.  We continue to focus on improving the quality of our service and maintaining efficient operating costs by exploiting synergies and technologies.  We also make an effort to standardize and update our operations regularly, introducing automated systems where possible.  In recent years, in order to achieve a new level of operational efficiency, we commenced roll out of the Tauron Program, which consists of two main projects:  Smart Metering for Commercial and Industrial consumers (High Voltage and Medium Voltage customers) and Mobile Workforce Management.  This program is already delivering benefits, with 26,783 smart meters deployed in the field and our nine distribution companies operating with a data dispatch system for emergency services, replacing the previous voice-based system.

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

Position ourselves to take advantage of consolidation in our industry by using our experience in successfully integrating and restructuring other operations .  We believe that further stabilization of the regulatory environment in the Brazilian power industry in future may lead to substantial consolidation in the generation, transmission and, particularly, the distribution sectors.  Given our financial strength and managerial expertise, we believe that we are well‑positioned to take advantage of this consolidation.  If promising assets are available on attractive terms, we may make acquisitions that complement our existing operations and afford us and our consumers further opportunities to take advantage of economies of scale.

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

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

 

 

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Our Service Territory

 

Distribution

We are one of the largest electricity distributors in Brazil, based on the amount of electricity we delivered in 2016.  Our nine distribution subsidiaries together supply electricity to a region covering 302,001 square kilometers, primarily in the states of São Paulo and Rio Grande do Sul.  Their concession areas include 679 ¹  municipalities and a population of approximately 23 million people.  Together, they provided electricity to approximately 9.2 million consumers as of December 31, 2016.  Our nine subsidiaries distributed approximately 12.3% of the total electricity distributed in Brazil in 2016, based on data from the EPE.

Distribution Companies

We have nine distribution subsidiaries:

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On December 9, 2015, the concessions held by CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista were extended to July 2045.  For further information on the extension of these concessions, see “ — Our Concessions and Authorizations — Concessions.”

Distribution Network

Our nine distribution subsidiaries operate distribution lines with voltage levels ranging from 11.9 kV to 138 kV.  These lines distribute electricity from the connection point with the Basic Network to our power substations, in each of our concession areas.  All consumers that connect to these distribution lines, including Free Consumers and other concessionaires, are required to pay a tariff for using the system ( Tarifa de Uso do Sistema de Distribuição ), or TUSD.

Each of our subsidiaries has a distribution network consisting of a widespread network of predominantly overhead lines and substations having successively lower voltage ranges.  Consumers are classified in different voltage levels based on their consumption of, and demand for, electricity.  Large industrial and commercial consumers receive electricity at High Voltage ranges (up to 138 kV) while smaller industrial, commercial and residential consumers receive electricity at lower voltage ranges (2.3 kV and below).

At December 31, 2016, our distribution networks consisted of 315,538 kilometers of distribution lines, including 450,247 distribution transformers.  Our nine distribution subsidiaries had 12,181 kilometers of High Voltage distribution lines between 34.5 kV and 138 kV.  At that date, we had 523 transformer substations for transforming High Voltage into Medium Voltages for subsequent distribution, with total transforming capacity of 17,316 mega‑volt amperes.  Of the industrial and commercial consumers in our concession area, 377 had 69 kV, 88 kV or 138 kV high‑voltage electricity supplied through direct connections to our High Voltage distribution lines.

System Performance

Electricity Losses

We experience two types of electricity losses:  technical losses and commercial losses.  Technical losses are those that occur in the ordinary course of our distribution of electricity.  Commercial losses are those that result from illegal connections, fraud or billing errors and similar matters.  Electricity loss rates of our three historical largest distribution subsidiaries (CPFL Paulista, CPFL Piratininga and RGE) compare favorably to the average for other major Brazilian electricity distributors according to the most recent information available from the Brazilian Association of Electric Energy Distributors ( Associação Brasileira de Distribuidores de Energia Elétrica ), or ABRADEE, an industry association.  According to the same information, RGE Sul’s loss rates also compare favorably to the national average, although to a lesser degree than our three historical largest subsidiaries.

We are also actively engaged in efforts to reduce commercial losses from illegal connections, fraud or billing errors.  To achieve this, in each of our nine subsidiaries, we have deployed trained technical teams to conduct inspections, enhanced monitoring for irregular consumption, increased replacements for obsolete measuring equipment and developed a computer program to discover and analyze irregular invoicing.  We conducted 341,899 inspections during 2016, which we believe led to a recovery of receivables estimated at more than R$47 million.

Power Outages

The following table sets forth the frequency and duration of electricity outages per consumer for the years ended December 31, 2016 and 2015 for each of our distribution subsidiaries:

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

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

(3) Acquired by us on October 31, 2016.  RGE Sul was not a subsidiary of our company for the first 10 months of 2016.

 

 

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

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

(3) Acquired by us on October 31, 2016.  RGE Sul was not a subsidiary of our company in 2015.

We seek to improve the quality and reliability of our power supply, as measured by the frequency and duration of our power outages.  According to data from ABRADEE for 2015, the most recent data available, our frequency and duration of interruptions per consumer in the past few years compare favorably to the averages for other Brazilian distribution companies.

Based on data published by ANEEL, the duration and frequency of outages at CPFL Paulista and CPFL Piratininga are among the lowest in Brazil compared to companies of similar size.  The duration of outages at RGE are comparatively higher than those at CPFL Paulista and CPFL Piratininga, but they remain in line with the average rate for power companies in Southern Brazil, mainly as a result of the lack of redundancies in its distribution system, the use of medium voltage lines and a lower level of automation in the network.  RGE Sul’s duration and frequency of outages remain below the national average, however.  Following our acquisition of RGE Sul on October 31, 2016, we are currently in discussions with the regulator regarding planned investments designed to improve RGE Sul’s performance indicators, taking into account its current indicators and the characteristics of its concession area.

ANEEL establishes performance indicators per consumer to be complied with by power companies.  If these indicators are not reached, we are obliged to reimburse our consumers, and our revenues are negatively affected.  In 2015, according to data from ANEEL, the amount we reimbursed our consumers was lower than the average amount reimbursed by power companies of similar size.

Our distribution subsidiaries have construction and maintenance technology that allows for repairs of the electricity network without interruption in electricity service, thereby allowing us to have low rates of scheduled interruption, which amounts to up to approximately 8.6% of total interruptions.  Unscheduled interruptions due to accidents or natural causes, including lightning storms, fire and wind represented the remainder of our total interruptions.  In 2016, we invested approximately R$1,201 million in our Distribution segment, primarily in: (i) expansion, maintenance, improvement, automation, modernization and reinforcement of the electrical system in order to meet market growth; (ii) operational infrastructure; (iii) customer service; and (iv) research and development programs, among other things.  We expect to invest an additional R$1,895 million for such purposes throughout 2017.

We strive to improve response times for our repair services.  The quality indicators for the provision of energy by CPFL Paulista and CPFL Piratininga have maintained levels of excellence while complying with regulatory standards.  This was also mainly the result of our efficient operational logistics, including the strategic positioning of our teams and the technology and automation of our network and operation centers, together with a preventive maintenance and conservation plan.

Purchases of Electricity

Most of the electricity we sell is purchased from unrelated parties, rather than generated by our facilities.  In 2016, 10.3% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries (including our joint ventures).

In 2016, we purchased 10,497 GWh of electricity from the Itaipu Power Plant, amounting to 16.4% of the total electricity we purchased.  Itaipu is located on the border of Brazil and Paraguay and is subject to a bilateral treaty between the two countries pursuant to which Brazil has committed to purchasing specified amounts of electricity.  This treaty will expire in 2023.  Electric utilities operating under concessions in the midwest, south and southeast regions of Brazil are required by law to purchase a portion of the electricity that Brazil is obligated to purchase from Itaipu.  The amounts that these companies must purchase are governed by take-or-pay contracts with tariffs established in US$/kW.  ANEEL determines annually the amount of electricity to be sold by Itaipu.  We pay for energy purchased from Itaipu in accordance with the ratio between the volume established by ANEEL and our statutorily established share, regardless of whether Itaipu generates such amount of electricity, at a price of US$25.78/kW.  Our purchases represent approximately 16.9% of Itaipu’s total supply to Brazil, disregarding the two-month period purchases of electricity by our distribution subsidiary RGE Sul, which control was acquired on October 31, 2016.  This share was fixed by law according to the amount of electricity sold in 1991.  The rates at which companies are required to purchase Itaipu’s electricity are established pursuant to the bilateral treaty and fixed to cover Itaipu’s operating expenses, payments of principal and interest on its U.S. dollar-denominated debts and the cost of transmitting the power to their concession areas.

 

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

In 2016, we paid an average of R$192.99 per MWh for purchases of electricity from Itaipu, compared with R$279.65 during 2015 and R$132.82 during 2014.  These figures do not include the transmission fee.

We purchased 53,478 GWh of electricity in 2016 from generating companies other than Itaipu, representing 83.6% of the total electricity we purchased.  We paid an average of R$ 164.77 per MWh for purchases of electricity from generating companies other than Itaipu, compared with R$210.44 per MWh in 2015 and R$201.79 per MWh in 2014.  For more information on the Regulated Market and the Free Market, see “—The New Industry Model Law— The Regulated Market” and “—The New Industry Model Law— The Free Market”.

The following table shows amounts purchased from our suppliers in the Regulated Market and in the Free Market, for the periods indicated.

	Year Ended December 31,
	2016	2015	2014
	(in GWh)
Energy purchased for resale
Itaipu	10,497	10,261	10,417
Electric Energy Trading Chamber - CCEE	1,195	2,946	5,074
Proinfa Program	1,058	1,058	1,043
Energy purchased in the Regulated Market and through bilateral contracts	51,225	44,342	42,345
TOTAL	63,975	58,607	58,879

 

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

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

 

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Transmission Tariffs .  In 2016, we paid a total of R$1,351 million in tariffs for the use of the transmission network, including Basic Network tariffs, connection tariffs and transmission of high‑voltage electricity from Itaipu at rates set by ANEEL.

Consumers and Tariffs

Consumers

We classify our consumers into five principal categories.  See note 27 to our audited annual consolidated financial statements for a breakdown of our sales by category.

Retail Distribution Tariffs .  We classify our consumers into two different groups, Group A consumers and Group B consumers, based on the voltage level at which electricity is supplied to them.  Each consumer is placed in a certain tariff level defined by law and based on its respective classification.  Some discounts are available depending on the consumer classification, tariff level or environment for trading (Free Consumers and generators).  Group B consumers pay higher tariffs.  Tariffs in Group B vary by type of consumer (residential, rural, other categories and public lighting).  Consumers in Group A pay lower tariffs, decreasing from A4 to Al, because they are supplied electricity at higher voltages, which requires lower use of the energy distribution system.  The tariffs we charge for sales of electricity to Final Consumers are determined pursuant to our concession agreements and regulations ratified by ANEEL.  These concession agreements and related regulations establish a cap on tariffs that provides for annual, periodic and extraordinary adjustments.  For a discussion of the regulatory regime applicable to our tariffs and their adjustment, see “—The Brazilian Power Industry”.

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

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

 

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

	Year ended December 31, 2016
	CPFL Paulista	CPFL Piratininga	RGE	RGE Sul (1)	CPFL Santa Cruz	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari	CPFL Mococa
		(R$/MWh)
Residential	591.80	679.76	665.32	742.37	665.54	599.01	616.72	580.38	650.89
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
Total	546.79	612.09	501.75	590.87	537.89	499.18	521.06	490.20	549.57

 

	Year ended December 31, 2015
	CPFL Paulista	CPFL Piratininga	RGE	RGE Sul (2)	CPFL Santa Cruz	CPFL Leste Paulista	CPFL Sul Paulista	CPFL Jaguari	CPFL Mococa
		(R$/MWh)
Residential	589.00	612.81	671.50	–	639.32	574.85	584.19	543.00	652.28
Industrial	561.40	550.31	533.24	–	609.89	509.75	483.70	460.79	517.43
Commercial	557.18	569.18	655.85	–	645.61	547.01	557.46	511.06	591.04
Rural	330.76	391.27	361.01	–	408.32	354.60	367.52	337.81	389.43
Other	437.75	418.14	276.94	–	354.28	422.77	422.89	396.75	442.72
Total	543.50	565.51	518.22	–	544.61	486.10	510.87	474.80	545.21

 

(1)      Average retail prices of RGE Sul reflect the two-month period (November and December 2016) following our acquisition of RGE Sul on October 31, 2016.

(2)      Average retail prices of RGE Sul are not presented, since RGE Sul was not a subsidiary of our company in 2015. 

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

TUSD .  The TUSD tariffs, which are set by ANEEL, consist of the three tariffs described under “Item 4.  Information on the Company — System Tariffs — TUSD”.  In 2016, tariff revenues for the use of our network by Free Consumers amounted to R$2,057 million.  The average tariff for the use of our network was R$130.88/MWh and R$119.92/MWh in 2016 and 2015, respectively, including the TUSD we charge to other distributors connected to our Distribution Networks.

Billing Procedures

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

 

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

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

Customer Service

We strive to provide high‑quality customer service to our distribution consumers.  We provide customer service 24 hours a day, 7 days a week.  The requests are received using a variety of platforms such as call centers, our website, SMS and our smartphone application.  In 2016, we responded to approximately 46.4 million inquiries.  We also provide customer service through our branch offices, which handled approximately 7.6 million customer requests in 2016.  The growth in electronic requests has allowed us to reduce our customer service costs and provide customer service through our call center to a larger number of customers without access to the Internet.  Following receipt of a customer service request, we dispatch our technicians to make any necessary repairs.

Generation of Electricity

We are actively expanding our generating capacity.  In accordance with Brazilian regulations, revenues from generation are based mainly on the Assured Energy of each facility, rather than its Installed Capacity or actual output.  Assured Energy is a fixed output of electricity established by the Brazilian government in the relevant concession agreement.  For certain companies, actual output is determined periodically by the ONS in view of demand and hydrological conditions.  Provided that a generation facility has sold its electricity and participates in the MRE, it will receive at least the revenue amount that corresponds to its Assured Energy, even if it does not actually generate all the energy.  For more information, see “—The Brazilian Power Industry—Generation Scaling Factor”.  Conversely, if a generation facility’s output exceeds its Assured Energy, its incremental revenue is equal only to the costs associated with generating the additional energy.

Most of our Hydroelectric Power Plants are members of the MRE, a system by which hydroelectric generation facilities share the hydrological risks of the Interconnected Power System.  Our total Installed Capacity in our Conventional Generation and Renewable Generation segments was 3,259 MW as of December 31, 2016.  Most of the electricity we produce comes from our Hydroelectric Power Plants.  We generated a total of 15,713 GWh in 2016, 17,066 GWh in 2015 and 13,658 GWh in 2014, in each case after accounting for the decrease in our participation in CPFL Renováveis as a result of its initial public offering in 2013 and the agreement with Arrow in 2014 (see “– Overview”).

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

 

 

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Conventional Generation

Hydroelectric Power Plants

At December 31, 2016, our subsidiary CPFL Geração owned a 51.54% interest in the Assured Energy from the Serra da Mesa Power Plant.  Through its generation subsidiaries CERAN, BAESA, ENERCAN and Chapecoense, CPFL Geração also owned interests in the Monte Claro, Barra Grande, Campos Novos, Castro Alves, 14 de Julho and Foz do Chapecó Power Plants, which have been operational since December 2004, November 2005, February 2007, March 2008, December 2008 and October 2010, respectively.  Through CPFL Jaguari Geração, we owned a 6.93% interest in the Assured Energy from the Luis Eduardo Magalhães Power Plant. 

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

Serra da Mesa .  Our largest Hydroelectric Facility in operation is the Serra da Mesa facility, which we acquired in 2001 from ESC (formerly VBC), one of our former controlling shareholders.  Furnas began construction of the Serra da Mesa facility in 1985.  In 1994, construction was suspended due to a lack of resources, which led to a public bidding procedure in order to resume construction.  Serra da Mesa currently consists of three Hydroelectric Facilities located on the Tocantins River in the state of Goiás.  The Serra da Mesa facility began operations in 1998 and has a total Installed Capacity of 1,275 MW.  The concession for the Serra da Mesa facility is owned by Furnas, which is also the operator, and we own part of the facility.  Under Furnas’ agreement with us, which has a 30‑year term commencing in 1998, we have the right to 51.54% of the Assured Energy of the Serra da Mesa facility until 2028 even if, during the term of the concession, there is an expropriation or forfeiture of the concession or the term of the concession expires.  We sell all of such electricity to Furnas under an electricity purchase contract that was renewed in March 2014 at a price that is adjusted annually based on the IGP‑M.  This contract expires in 2028.  Our share of the Installed Capacity and Assured Energy of the Serra da Mesa facility is 657 MW and 3,030 GWh/year, respectively.  On May 30, 2014, the concession held by Furnas was formally extended to November 12, 2039.

CERAN Hydroelectric Complex .  We own a 65.0% interest in CERAN, a subsidiary that was granted a 35‑year concession in March 2001 to construct, finance and operate the CERAN hydroelectric complex.  The other shareholders are CEEE (with 30.0%) and Desenvix (with 5.0%).  The CERAN hydroelectric complex consists of three Hydroelectric Power Plants:  Monte Claro, Castro Alves and 14 de Julho.  The CERAN Hydroelectric Complex is located on the Antas River approximately 120 km north of Porto Alegre, near the city of Bento Gonçalves, in the state of Rio Grande do Sul.  The entire CERAN Hydroelectric Complex has an Installed Capacity of 360 MW and estimated Assured Energy of 1,515.5 GWh per year.  We sell our participation in the Assured Energy of this Complex to affiliates in our group.  These facilities are operated by CERAN, under CPFL Geração’s supervision.

Following a refurbishment of the CERAN Hydroelectric complex in 2013, we installed equipment on the Monte Claro Hydroelectric Power Plant in order to improve the free flow of water and increase the plant’s availability.  Following monitoring, however, this equipment did not operate satisfactorily and the project was cancelled.  We are currently assessing alternative measures in order to raise the electricity generated by the CERAN complex.

 

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In addition, discussions with ANEEL and other entities in the transmission sector are ongoing regarding the conditions under which we will transfer the Monte Claro Substation to the Basic Network, which would eliminate maintenance costs and our responsibility for operation of the Substation. 

Barra Grande .  This facility became fully operational in May 2006 with a total Installed Capacity of 690 MW and total Assured Energy of 3,334.1 GWh per year.  CPFL Geração owns a 25.01% interest in this plant.  The other shareholders of the joint venture are Alcoa (42.18%), CBA ( Companhia Brasileira de Alumínio ) (15.0%), DME ( Departamento Municipal de Eletricidade de Poços de Caldas ) (8.82%), and Camargo Corrêa Cimentos S.A .  (9.0%).  We sell our participation in the Assured Energy of this facility to affiliates in our group. 

Campos Novos .  We own a 48.72% interest in ENERCAN, a joint venture formed by a consortium of private and public sector companies that was granted a 35‑year concession in May 2000 to construct, finance and operate the Campos Novos Hydroelectric Facility.  The plant was constructed on the Canoas River in the state of Santa Catarina, and became fully operational in May 2007 with a total Installed Capacity of 880 MW and Assured Energy of 3,310.4 GWh per year, of which our interest is 1,612.9 GWh per year.  The other shareholders of ENERCAN are CBA (33.14%), Votorantim Metais Níqueis S.A.  (11.63%) and CEEE (6.51%).  The plant is operated by ENERCAN under CPFL Geração’s supervision.  We sell our participation in the Assured Energy of this joint venture to affiliates in our group. 

Foz do Chapecó .  We own a 51.0% interest in Chapecoense, a joint venture formed by a consortium of private and public sector companies that was granted a 35‑year concession in November 2001 to construct, finance and operate the Foz do Chapecó Hydroelectric Power Plant.  The remaining 49.0% interest in the joint venture is divided among Furnas, which holds a 40.0% interest, and CEEE, which holds a 9.0% interest.  The Foz do Chapecó Hydroelectric Power Plant is located on the Uruguay River, on the border between the states of Santa Catarina and Rio Grande do Sul.  The Foz do Chapecó Power Plant became fully operational in March 2011 with 855 MW of total Installed Capacity and Assured Energy of 3,784.3 GWh per year.  We sell 40.0% of our share in the Assured Energy of this project to affiliates in our group and 60.0% through Agreements on Energy Commercialization in the Regulated Market ( Contratos de Comercialização de Energia no Ambiente Regulado ), or CCEARs.  In January 2013, at the request of ANEEL, we began the process of transferring the Foz do Chapecó Substation and exclusive transmission lines to the Basic Network, thereby eliminating maintenance costs and responsibility for operation of these assets, and reducing the transmission line energy loss factor (regulatory loss).  The transfer process was completed in October 2016.

Luis Eduardo Magalhães .  We own a 6.93% interest in the Assured Energy from the Luis Eduardo Magalhães Power Plant, also known as UHE Lajeado.  The plant is located on the Tocantins River in the state of Tocantins and became fully operational in November 2002 with a total Installed Capacity of 902.5 MW and Assured Energy of 4,613 GWh per year.  The plant was built by Investco S.A., a consortium comprised of Lajeado Energia, EDP ( Energias de Portugal ), CEB ( Companhia Energética de Brasília ) and Paulista Lajeado (which we acquired in 2007). 

Thermoelectric Power Plants

We operate three Thermoelectric Power Plants.  Termonordeste, which commenced operations in December 2010, and Termoparaíba, which commenced operations in January 2011 under ANEEL authorizations, are powered by fuel oil from the EPASA complex, with total Installed Capacity of 341.5 MW and total Assured Energy of 2,169.9 GWh per year.  On December 31, 2016, we owned an aggregate 53.34% interest in Termonordeste and Termoparaíba.  The Termonordeste and Termoparaíba Thermoelectric Power Plants are located in the city of João Pessoa, in the state of Paraíba.  The electricity from these power plants was sold in CCEARs, and part of this energy was purchased by our own distributors. 

The remaining facility, Carioba, has an Installed Capacity of 36 MW; however, it has been officially deactivated since October 19, 2011, as provided for in Order No.  4,101 of 2011.  We have applied to terminate the Carioba concession since ANEEL reduced the subsidy associated with the Fuel Usage Quota Account ( Conta de Consumo de Combustível ), or the CCC Account.  ANEEL has recommended that the MME terminate Carioba’s concession.  The MME is currently analyzing the request.  Commencing 2016 we have ceased to include Carioba in our installed capacity since the facility is inactive.

 

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Small Hydroelectric Power Plants

At December 31, 2016, 10 of our 50 Small Hydroelectric Power Plants were under the management of two of our conventional generation subsidiaries, CPFL Geração and CPFL Centrais Geradoras.  These 10 Small Hydroelectric Power Plants reported their results within the Conventional Generation segment.  They consist of two groups of facilities:

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.

 

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The following table sets forth certain information relating to our principal conventional generation facilities in operation and the Small Hydroelectric Power Plants that reported their results within the Conventional Generation segment as of December 31, 2016: 

	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.  We have a contractual right to 51.54% of the Assured Energy of this facility, under a 30‑year agreement. 

(2) Inactive power plants.  On July 8, 2016, ANEEL published Order n° 1.776/2016, which recommended that MME terminate the Cariobinha UHE, without reversal of assets. 

(3) Hydroelectric projects with an Installed Capacity equal to or less than 5,000 kW that are registered with the regulatory authority and the administrator of power concessions but do not require concession or authorization processes for operating.

(4) After a capital increase on January 31, 2014, the holdings of certain shareholders of the joint venture EPASA were diluted.  As per the actual Shareholders Agreement, these shareholders were entitled to repurchase shares in order to reconstitute their holdings.  This right was exercised during February 2015, and as from March 1, 2015, CPFL Geração holds 53.34% of EPASA.

 

Renewable Generation

At December 31, 2016, through our subsidiary CPFL Geração, we owned a 51.60% interest in CPFL Renováveis, a company resulting from an association with another Brazilian renewable energy producer, Energias Renováveis S.A., or ERSA, which holds our subsidiaries engaged in the generation of electricity from renewable sources.  Through CPFL Renováveis, in August 2011, we became the largest renewable energy generation group in Brazil in terms of Installed Capacity and capacity under construction, according to ANEEL.  We have fully consolidated CPFL Renováveis in our financial statements since August 1, 2011.  CPFL Renováveis carried out its initial public offering in July 2013, resulting in a decrease in our shareholding from 63% to 58.84%.  On October 1, 2014, CPFL Renováveis acquired 100% of the shares of DESA through an issuance of shares of CPFL Renováveis, resulting in a decrease in our shareholding of CPFL Renováveis from 58.84% to 51.61%. 

 

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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. 

Existing Installed Capacity

The following describes our existing and operational renewable generation plants:

Small Hydroelectric Power Plants

Small Hydroelectric Power Plants are plants with generation capacity between 5 MW and 30 MW and a reservoir area of up to three square kilometers.  A typical Small Hydroelectric Power Plant operates under a “run-of-river” system and as a result, it may experience idleness when the available water flow is less than the turbine inflow capacity.  If flows are greater than the equipment’s capacity, water flows through a spillway.  Small Hydroelectric Power Plants are allowed to participate in the MRE, and in this case, the amount of energy sold by the power plant depends solely on its certificate of guarantee and not on its individual energy production. 

 

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CPFL Renováveis operates 40 of our 50 (39 operational and 1 under construction) Small Hydroelectric Power Plants primarily under the concession and registration regime, all located in the state of São Paulo, Minas Gerais, Mato Grosso, Paraná, Santa Catarina and Rio Grande do Sul.

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

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

Biomass Thermoelectric Power Plants

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

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

 

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CPFL Bio Ipê .  In March 2010, CPFL Bio Ipê, which was formed to develop electric energy generation projects using sugarcane bagasse, executed a partnership agreement with Grupo Pedra Agroindustrial to develop new biomass generation projects.  The CPFL Bio Ipê plant, located in Nova Independência, in the state of São Paulo, began its operations in May 2012.  The total Installed Capacity of this plant is 25 MW.  This project has an associated PPA of 71.5 GWh in force until 2030 and the energy has been entirely sold to CPFL Brasil.

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

CPFL Bio Ester .  In October 2012, CPFL Renováveis completed the acquisition of the electrical energy and steam co‑generation assets of SPE Lacenas Participações Ltda., which controls the Ester Thermoelectric Power Plant, located in the municipality of Cosmópolis, in the state of São Paulo.  The assets have total Installed Capacity of 40 MW.  Around 7 MW average of co‑generation energy from the Ester Thermoelectric Power Plant was commercialized in the 2007 alternative energy sources auction, for a period of 15 years.  The remaining 3.2 MW, on average, of energy was sold on the free market for 21 years.

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

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

Solar Power Plant

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

Wind Farms

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

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

Certain regions of Brazil are more favorable in terms of wind speed, with higher average speeds and lower volatility as measured by speed variation, allowing for more predictability in the volume of wind energy to be produced.  Wind farms operate complementary to hydroelectric plants, since wind speed is usually higher in drought periods and it is, therefore, possible to preserve water from reservoirs in scarce rain periods.  The complementary operation of wind farms and Small Hydroelectric Power Plants should allow us to “stock up” on electric power in the Small Hydroelectric Power Plants’ reservoirs during periods of high wind power generation.  Estimates of Abeeólica (Brazilian Wind Power Association) indicate a wind energy potential of 500 GW in Brazil, a volume that greatly exceeds the country’s current total Installed Capacity of 10.6 GW as of December 2016 according to ANEEL, signaling a high growth potential in this segment.  Wind farms are also eligible for MDL and have the potential to generate carbon credits for sale. 

 

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We currently have 43 wind farms under the authorization regime, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul.

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

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

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

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

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

Bons Ventos:  Bons Ventos Wind Farm, in the state of Ceará, has an Installed Capacity of 50 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The acquisition of Bons Ventos Wind Farm was concluded in June 2012. 

Canoa Quebrada:  Canoa Quebrada Wind Farm, in the state of Ceará, has an Installed Capacity of 57 MW and an associated agreement with Eletrobras under the Proinfa Program to sell all of the energy generated for a period of 20 years.  The acquisition of Canoa Quebrada Wind Farm was concluded in June 2012.

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

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

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

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

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

 

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Macacos Complex:  The Macacos Complex consists of the Pedra Preta, Costa Branca, Juremas and Macacos Wind Farms.  The Complex has an aggregate Installed Capacity of 78.2 MW and aggregate Assured Energy of 37.5 MWavg.  The Macacos Complex sold its energy through the 2010 Alternative Sources Auction. 

Morro dos Ventos Complex :  The Morro dos Ventos Complex consists of the Morro dos Ventos I, Morro dos Ventos III, Morro dos Ventos IV, Morro dos Ventos VI and Morro dos Ventos IX Wind Farms.  The Complex has an aggregate Installed Capacity of 144 MW and aggregate Assured Energy of 68.5 MWavg.  The Morro dos Ventos Complex sold its energy through the 2009 Reserve Energy Auction. 

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

Morro dos Ventos II:  Morro dos Ventos II wind farm, in the state of Rio Grande do Norte, has an Installed Capacity of 29.1 MW and aggregate Assured Energy of 15.3 MWavg.  This wind farm commenced operations in April 2015.

São Benedito and Campo dos Ventos Complexes.  The São Benedito Complex consists of the Ventos de São Benedito, Ventos de Santo Dimas, Santa Mônica, São Domingos, Ventos do São Martinho and Santa Úrsula wind farms.  The São Domingos and Ventos de São Martinho Wind Farms, previously part of the Campo dos Ventos Complex, were allocated to the São Benedito Complex in order to increase synergies.  The Campo dos Ventos Complex consists of Campo dos Ventos I, III and V Wind Farms.  Together, they have an Installed Capacity of 231 MW and aggregate Assured Energy of 1,059.1 GWh/year.  This project has a PPA in force until 2034 for the São Benedito Complex and 2033 for the Campo dos Ventos Complex. 

The following table sets forth certain information relating to our principal renewable facilities, held by CPFL Renováveis (51.60% our share) in operation as of December 31, 2016:

	Capacity (MW)		Assured Energy (GWh)		Placed in service	Facility upgraded	Concession expires
	Our share	TOTAL	Our share	TOTAL
Small Hydroelectric plants:
Alto Irani	10.8	21.0	61.9	120.0	2008		2032
Americana	15.5	30.0	26.6	51.5	1949	2002	2027
Andorinhas	0.3	0.5	1.9	3.7	1940		(2)
Arvoredo	6.7	13.0	35.1	68.1	2010		2032
Barra da Paciência	11.9	23.0	67.3	130.4	2011		2029
Buritis	0.4	0.8	1.6	3.1	1922		2027(1)
Capão Preto	2.2	4.3	10.3	20.0	1911	2008	2027
Chibarro	1.3	2.6	7.3	14.1	1912	2008	2027
Cocais Grande	5.2	10.0	22.0	42.6	2009		2029
Corrente Grande	7.2	14.0	38.6	74.7	2011		2030
Diamante	2.2	4.2	7.2	14.0	2005		2019
Dourados	5.6	10.8	31.6	61.2	1926	2002	2027
Eloy Chaves	9.7	18.8	52.4	101.5	1954	1993	2027
Esmeril	2.6	5.0	13.0	25.2	1912	2003	2027
Figueiropolis	10.0	19.4	56.5	109.5	2010		2034
Gavião Peixoto	2.5	4.8	17.3	33.5	1913	2007	2027
Guaporé	0.4	0.7	2.5	4.9	1950		(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 H orizonte	11.9	23.0	47.0	91.1	2011		2032
Paiol	10.3	20.0	49.8	96.5	2010		2032
Pinhal	3.5	6.8	16.7	32.4	1928	1993	2027
Pirapó	0.4	0.8	2.6	5.1	1952		(2)
Plano Alto	8.3	16.0	44.1	85.5	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	34.4	66.6	2010		2030
São Joaquim	4.2	8.1	22.9	44.4	1911	2002	2027
Socorro	0.5	1.0	1.4	2.7	1909	1994	2027(1)
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