CPFL Energy 20F 2019 Annual report

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, 2019
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 Jorge de Figueiredo Correa, No. 1,632, parte
CEP 13087-397 - Jardim Professora Tarcília, Campinas – SP
Federative Republic of Brazil
(Address of principal executive offices)

Yuehui Pan
+55 19 3756 6211 – panyuehui@cpfl.com.br
Federative Republic of Brazil
(Name, telephone, e-mail and/or facsimile
number and address of company contact person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:None

Securities registered or to be registered pursuant to Section 12(g) of the Act:Common Shares, without par value

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

As of December 31, 2019, there were 1,152,254,440 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☒ 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☒

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☒ No☐

Indicate by check mark whether the registrant has submitted electronically 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☐

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 definition of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer☒ 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. ☐

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

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

U.S. GAAP☐

International Financial Reporting Standards as issuedby the International Accounting Standards Board ☒

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☒

Table of Contents

Pag

FORWARD-LOOKING STATEMENTS		1
CERTAIN TERMS AND CONVENTIONS		2
PRESENTATION OF FINANCIAL AND OTHER INFORMATION		3
ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	3
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	3
ITEM 3.	KEY INFORMATION	3
ITEM 4.	INFORMATION ON THE COMPANY	28
ITEM 4A.	UNRESOLVED STAFF COMMENTS	82
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	82
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	125
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	137
ITEM 8.	FINANCIAL INFORMATION	138
ITEM 9.	THE OFFER AND LISTING	145
ITEM 10.	ADDITIONAL INFORMATION	147
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	166
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	167
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	167
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	167
ITEM 15.	CONTROLS AND PROCEDURES	167
ITEM 16.	[RESERVED]	168
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	168
ITEM 16B.	CODE OF ETHICS	168
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	168
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	169
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	169
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	169
ITEM 16G.	CORPORATE GOVERNANCE	169
ITEM 16H.	MINE SAFETY DISCLOSURE	171
ITEM 17.	FINANCIAL STATEMENTS	171
ITEM 18.	FINANCIAL STATEMENTS	171
ITEM 19.	EXHIBITS	171
GLOSSARY OF TERMS		172
SIGNATURES		178

-i-

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:

·	government interventions, resulting in changes to the economy, taxes, tariffs, regulatory environment or environmental regulation in Brazil;
·	changes in the general economic, political, demographic and business conditions in Brazil and particularly in the markets we serve, including, without limitation, inflation, interest rates, exchange rates, employment rate, population growth and consumer confidence;
·	our ability to identify, develop, plan and execute new projects;
·	changes in Brazilian electricity prices;
·	our ability to take advantage of all the expected benefits of the acquisitions we make;
·	our ability to acquire wind, hydroelectric or thermoelectric power generation equipment within the time and at prices that make the projects viable;
·	bidding processes for transmission lines;
·	lack of auctions where energy from alternative sources can be commercialized;
·	difficulties in completing our projects under development;
·	unforeseen delays, excess or cost increases in the implementation of our projects and other problems related to construction and development;

·	limitations in our access to adequate financing, or our inability to make investments in line with our business plan in accordance with our initial schedule;

·	increases in costs, including, without limitation, costs relating to: (a) operation and maintenance; (b) regulatory and environmental expenses; (c) contributions, fees and taxes; and (d) tariffs for the transportation of electric energy, in such a way as to affect our profit margins;


·	difficulties in accessing electric power transmission systems;
·	our ability to obtain, keep and renew applicable governmental authorizations and licenses, including environmental authorizations and licenses, that make projects feasible;

·	the availability of average winds in line with the measurements and expectations used for the decision to invest in wind projects;

·	unplanned environmental aspects that overburden projects and cause delays;
·	the impact of climate change, causing prolonged droughts and interference in speed and frequency of winds, among others;
·	factors or trends that may affect our business, market share, financial condition, liquidity or results of our operations;
·	our level of capitalization and indebtedness and our ability to contract new financing and execute our expansion plan;
·	judicial or administrative proceedings to which we are or become a party;
·	changes in applicable laws and regulations, as well as the enactment of new laws and regulations, including those relating to regulatory, corporate, environmental, tax and employment matters;
·	actions taken by our controlling shareholder
·	electricity shortages;
·	changes in tariffs;
·	our inability to generate electricity due to water shortages, transmission outages, operational or technical problems or physical damages to our facilities;

·	potential disruption or interruption of our services, including due to outbreaks of communicable diseases such as the coronavirus (COVID-19) and catastrophic events affecting our industry;

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


·	increased competition in the power industry markets in which we operate;
·	our inability to implement our capital expenditure plan, including our inability to arrange financing when required and on reasonable terms;

·	changes in consumer demand;
·	existing and future governmental regulations relating to the power industry; and
·	the risk factors discussed under “Item 3. Key Information—Risk Factors,” beginning on page 6.

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

CERTAIN TERMS AND CONVENTIONS

A glossary of electricity industry terms is included in this annual report, beginning on page 172.

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

Unless the context otherwise requires, all references herein to “we,” “us” or “our company” are references to CPFL Energia S.A., its consolidated subsidiaries and jointly controlled entities.

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

We maintain our books and records inreais. We prepared our audited annual consolidated financial statements included in this annual report in accordance with IFRS, as issued by the 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 the years ended December 31, 2019, 2018, 2017, 2016 and 2015. Our financial data as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019, 2018 and 2017 was derived from our audited annual consolidated financial statements, which appear elsewhere in this annual report and were prepared in accordance with IFRS, as issued by the IASB. You should read this selected financial data in conjunction with our audited annual consolidated financial statements and the related notes included in this annual report. Our financial data as of December 31, 2016 and 2015 and for each of the two years ended December 31, 2016 and 2015 was derived from our audited annual consolidated financial statements that are not included in this annual report.

The following standards became effective on January 1, 2019 and have impacted our financial information as of and for the year ended December 31, 2019:

- IFRS 16 – Leases

- IFRIC 23 – Uncertainty Over Tax Treatments

As permitted by these IFRS standards, we adopted these standards as of January 1, 2019, without restating comparative information presented in the audited consolidated financial statements as of and for the year ended December 31, 2019. Therefore, our financial information as of and for the year ended December 31, 2019 is not comparable with our financial information for previous periods. For further information about the adoption of these standards with respect to our financial statements as of and for the year ended December 31, 2019, see Note 3.17 of our audited annual consolidated financial statements. The financial information presented in this annual report should be read in conjunction with our consolidated financial statements.

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,
	2019⁽²⁾	2019	2018	2017	2016	2015
	US$	R$	R$	R$	R$	R$
	(in millions, except per share and per ADS data)
Net operating revenue	7,427	29,932	28,137	26,745	19,112	20,599
Cost of electric energy services:
Cost of electric energy	4,559	18,371	17,838	16,902	11,200	13,312
Cost of operation	718	2,894	2,734	2,771	2,249	1,907
Depreciation and amortization	317	1,278	1,238	1,144	938	870
Other cost of operation	401	1,616	1,496	1,627	132	198
Cost of services rendered to third parties	519	2,090	1,775	2,075	1,357	1,049
Gross profit	1,632	6,578	5,789	4,998	4,306	4,331
Operating expenses:
Selling expenses	174	700	608	590	547	464
Depreciation and amortization	1	5	4	5	4	22
Allowance for doubtful accounts	58	233	169	155	176	127
Other selling expenses	114	461	435	429	367	316
General and administrative expenses	255	1,027	987	947	849	863
Depreciation and amortization	27	109	65	94	95	85
Other general and administrative expenses	228	918	922	853	754	778
Other operating expenses	121	487	485	438	387	358
Depreciation and amortization	72	288	287	286	255	303
Other general and administrative expenses	49	199	199	152	132	55
Income from electric energy services	1,083	4,363	3,708	3,022	2,523	2,645
Equity interests in subsidiaries,associates and joint ventures	87	349	334	312	311	217
Financial income (costs):
Financial income	224	904	762	880	1,201	1,143
Financial expenses	(404)	(1,630)	(1,865)	(2,368)	(2,654)	(2,551)
Net financial income (costs)	(180)	(726)	(1,103)	(1,488)	(1,453)	(1,408)
Profit before taxes	989	3,986	2,940	1,847	1,381	1,454
Social contribution	(84)	(337)	(214)	(169)	(151)	(160)
Income tax	(224)	(901)	(560)	(435)	(351)	(419)
Total taxes	(307)	(1,238)	(774)	(604)	(501)	(579)
Profit for the year	682	2,748	2,166	1,243	879	875
Profit (loss) attributableto owners of the company	671	2,703	2,058	1,180	901	865
Profit (loss) attributableto noncontrolling interests	11	46	108	63	(22)	10
Earnings per share attributable to owners of the company:
Basic	0.62	2.48	2.02	1.16	0.89	0.85
Diluted	0.61	2.47	2.01	1.15	0.87	0.83
Profit for the year per ADS:
Basic	1.23	4.96	4.04	2.32	1.77	1.70
Diluted	1.23	4.94	4.02	2.30	1.74	1.66
Dividends⁽¹⁾	159	642	489	280	214	205
Weighted average of number of common shares (in millions)	286	1,152	1,018	1,018	1,018	1,018
Dividends per share⁽¹⁾	0.14	0.56	0.48	0.28	0.21	0.20
Dividends per ADS⁽¹⁾	0.28	1.11	0.96	0.55	0.42	0.40

______________________

(1)

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

(2)

Solely for convenience purposes, amounts in reais have been translated 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, 2019 of R$4.030 to US$1.00.

BALANCE SHEET DATA

	For the year ended December 31,
	2019⁽²⁾	2019	2018	2017	2016	2015
	US$	R$	R$	R$	R$	R$
	(in millions)
Current assets:
Cash and cash equivalents	481	1,937	1,891	3,250	6,165	5,683
Consumers, concessionaires and licensees	1,237	4,986	4,548	4,301	3,766	3,175
Securities	211	851	-	-	-	24
Derivatives	70	281	309	444	163	627
Sector financial assets	271	1,094	1,331	211	-	1,464
Other current assets	296	1,192	1,322	1,375	1,285	1,536
Total current assets	2,566	10,341	9,402	9,581	11,379	12,509
Noncurrent assets:
Consumers,concessionaires andlicensees	177	713	753	237	203	129
Sector financial assets	1	3	224	355	-	490
Derivatives	92	370	348	204	641	1,651
Concession financial assets	2,179	8,780	7,430	6,546	5,363	3,597
Investments	248	998	980	1,002	1,494	1,248
Property, plant and equipment	2,254	9,084	9,457	9,787	9,713	9,173
Contract assets	328	1,323	1,046	-	-	-
Intangible Assets	2,313	9,321	9,463	10,590	10,776	9,210
Other noncurrent assets	781	3,147	3,109	2,982	2,602	2,525
Total noncurrent assets	8,371	33,738	32,810	31,702	30,792	28,024
Total assets	10,937	44,078	42,212	41,283	42,171	40,532
Current liabilities:
Short-term debt⁽¹⁾	858	3,459	3,363	5,293	3,429	3,641
Sector financial liabilities	-	-	-	40	598	-
Other current liabilities	1,639	6,607	5,052	6,046	4,992	5,884
Total current liabilities	2,498	10,066	8,415	11,379	9,018	9,525
Noncurrent liabilities:
Long-term debt⁽¹⁾	3,834	15,451	17,013	14,876	18,733	18,126
Sector financial liabilities	25	103	47	8	317	-
Other long-term liabilities	1,284	5,176	4,204	3,834	3,729	2,751
Noncurrent liabilities	5,144	20,729	21,264	18,718	22,780	20,877
Non-controlling interest	72	289	2,270	2,225	2,403	2,456
Net equity attributable to controlling shareholders	3,224	12,994	10,263	8,962	7,970	7,674
Total liabilities and shareholders’ equity	10,937	44,078	42,212	41,283	42,171	40,532

______________________

(1)

Short-term debt and long-term debt include loans and financing, debentures, accrued interest on loans, financing and debentures and derivatives.

(2)

Solely for convenience purposes, amounts inreais have been translated 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, 2019 of R$4.030 to US$1.00. The average of the month-end commercial selling rates during the year 2019 was R$3.946 to US$1.00.

OPERATING DATA

	For the year ended December 31,
	2019	2018	2017	2016	2015
Energy sold (in GWh):
Residential	20,355	19,618	19,122	16,473	16,164
Industrial	13,198	13,834	14,661	13,022	12,748
Commercial	10,700	10,211	10,220	9,720	9,259
Rural	3,231	3,583	3,762	2,474	2,152
Public administration	1,468	1,459	1,456	1,271	1,278
Public lighting	2,039	2,003	1,964	1,746	1,649
Public services	2,348	2,348	2,157	1,840	1,797
Own consumption	36	34	34	32	33
Total energy sold to Final Consumers	53,375	53,091	53,376	46,578	45,082
Electricity sales to wholesalers (in GWh)	25,435	24,459	27,557	21,459	17,971
Total consumers (in thousands)⁽¹⁾	9,756	9,580	9,375	9,222	7,751
Installed Capacity (in MW)⁽³⁾	4,304	3,272	3,284	3,259	3,164
Assured Energy (in GWh)⁽²⁾⁽³⁾	17,223	13,420	13,682	14,188	13,550
Energy generated (in GWh)⁽³⁾	13,611	10,648	10,137	12,568	14,310

______________________

(1)

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

(2)

Refers to Assured Energy in GW available at the end-period, multiplied by the number of hours per year. Due to the cancellation of daylight savings time in 2019, there were 8,761 hours in 2019. See “Item 4. Information on the Company” for more information about commencement of operations of each power plant.

(3)

Refers solely to the total amount of energy (GWh) produced by conventional management companies and the equivalent participation percentage of renewable energy generation companies (99.94% in 2019, 51.56% in 2018, 51.60% in 2017 and 2016 and 51.61% in 2015).

Convenience Translations into U.S. Dollars

Solely for the investor’s convenience, we have translated certain amounts included in this annual report fromreaisinto U.S. dollars at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2019 of R$4.030 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.

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 ANEEL. ANEEL regulates and oversees various aspects of our business and establishes our tariffs. If we make additional and unexpected capital investments that are not considered prudent by ANEEL, ANEEL may not authorize the recovery of all costs, not allowing our tariffs to be adjusted accordingly, 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, financial results and our capacity to fulfill our contractual obligations may be adversely affected.

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

The Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as theLei do Novo Modelo do Setor Elétrico, or New Regulatory Framework. Challenges to the constitutionality of the New Regulatory Framework are still pending before the Brazilian Federal Supreme Court (Supremo Tribunal Federal). It is not possible to estimate when these proceedings will be finally decided. If all or part of the New Regulatory Framework 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 could have an adverse impact on the entire energy sector, including our business and results of operations.

If the regulatory framework under which we operate is revised in a way that results in us being required to conduct our business in a manner substantially different from our current operations, our operations, financial results and our capacity to fulfill our contractual obligations may be adversely affected.

We cannot ensure 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 terms and conditions of the renewal are otherwise acceptable to the Brazilian government. The Brazilian government has considerable discretion under the Concession Law, Law No. 9,074/95, Decree No. 7,805/12, Law No. 12,783/13, Decree No. 8,461/15, Law No. 13,360/16, Decree No. 9,158/17, Decree No. 9,187/17 and under concession contracts regarding renewal of concessions. Furthermore, we may 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 non-renewal of any of our concessions and authorizations, as well as the non-renewal of our energy supply contracts, could have a material adverse effect on our financial condition, results of operations and our capacity to fulfill our contractual obligations.

The tariffs that we charge for sales of electricity to Captive Consumers and the tariffs for using the distribution system that we charge to Special Free 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.

Our tariffs are determined under concession agreements with the Brazilian government, and in accordance with ANEEL’s regulations and decisions. Our tariff rates are established discretionarily by ANEEL pursuant to the provisions of the concession contract and the legislation in effect.

Our concession agreements and Brazilian law establish a mechanism that allows for three types of tariff adjustments: (i) annual adjustment (RTA), (ii) periodic revision (RTP), and (iii) extraordinary revision (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 every four or five years (according to the terms of each concession agreement). 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. Previously, all revisions in methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014. In 2015, ANEEL changed this procedure to allow for the review of the underlying methodologies applicable to the electricity sector from time to time on an item by item basis. Periodic tariff reviews were held for Companhia Piratininga de Força e Luz, or CPFL Piratininga, in October2019, resulting in average adjustment of -7.80%, for Companhia Paulista de Força e Luz, or CPFL Paulista, and RGE Sul, in April 2018 and for RGE in June 2018, resulting in average adjustments of 16.90% (CPFL Paulista), 22.47% (RGE Sul) and 20.58% (RGE).

We cannot predict whether ANEEL will establish tariffs or methodologies that are favorable to us. Additionally, we currently have ongoing judicial proceedings disputing the tariff review. A future unfavorable result in these proceedings may result in changes in the current tariffs, which may adversely impact our businesses and results of operations. See “Item 5. Operating and Financial Review and Prospects—Background—Periodic Revisions—RTP” for more information.

We are a holding company and a significant part of our cash flow comes from the distribution of profits of our subsidiaries. Certain financial agreements entered into by our subsidiaries impose restrictions on the distribution of dividends.

We are a publicly-held corporation with the main purpose of acting as a holding company, holding equity interests in other companies engaged in distribution, transmission, generation, commercialization activities as well as the provision of services, all in the energy segment.

A significant part of our cash flow comes from the distribution of dividends and interest attributable to shareholders’ equity by our subsidiaries. Events causing a reduction in the profits of such companies or suspensions in the payment of dividends may affect our financial condition. Our subsidiaries have financing agreements that prevent them from distributing dividends above the legal and statutory minimum dividends and, upon the occurrence of an event of default, from paying any dividends or interest attributable to shareholders’ equity. Our decision to distribute dividends will depend, among other factors, on our ability to generate profits, profitability, financial condition, investment plans, contractual limitations and restrictions imposed by applicable legislation and regulations.

Our distribution business may be required to reimburse consumers for up to ten years in the event of inaccurate billings.

The regulations applicable to inaccurate billings, in particular those regarding time barring periods, as established by Article 113, II, of ANEEL Normative Resolution No. 414, of September 9, 2010, were suspended by a preliminary injunction granted on December 18, 2018, and given effect by ANEEL on January 4, 2019. The original language of Article 113, II, limited the period during which distribution companies were required by ANEEL to reimburse consumers in the event of inaccurate billings to 36 months. The new time barring period to be applied by ANEEL is ten years. If the preliminary injunction remains in place, we will be required to reimburse customers in the event of inaccurate billings for a ten-year period, which could represent a significant cost and adversely affect our financial results.

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. We cannot ensure that we will obtain, keep or renew all installation and operating permits necessary to conduct our business.

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:

fines per breach of up to 2.0% of the net operating revenue generated by the concession or authorization in the 12 months prior to the infraction notice related to the breach, or (if the relevant concession or authorization is non-operational) up to 2.0% of the estimated value of the energy that would have been produced for the 12 months prior to the infraction notice related to the breach;

·	injunctions related to construction activities;
·	restrictions on the operation of existing facilities and equipment;
·	requiring the concessionaire’s controlling shareholders to carry out further capital expenditures (not applicable to authorizations);
·	temporary suspension from participating in new tenders, which may also be extended to controlling shareholders of the entity subject to the penalty;
·	intervention by ANEEL in the management of the concessionaire; and
·	termination of the concession or authorization.

In addition, the Brazilian government may terminate any of our concession agreements or authorizations by means of expropriation if it deems this to be in the public interest. We may also be a party in judicial lawsuits that may result in the future in restrictions in contracting with public authorities, which may adversely affect us financially and reputationally.

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, results of operations and our capacity to fulfill our contractual obligations.

The distribution concessions held by our previous distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista (merged into CPFL Santa Cruz in 2018) were originally granted in 1999 for a 16-year term and have recently been extended to July 2045. The extensions were granted under the new laws and regulations regarding distribution concessions, in particular Decree No. 7,805/12, Law No. 12,783/13 and Decree No. 8,461/15, so the concessions are now subject to the new targets and standards established by the Brazilian authorities. Such new targets and standards are included in the amendments to the concession agreements. There is as yet no precedent regarding how the authorities will act under these new laws and regulations, which include certain variables that are beyond our control and which may therefore impair our ability to fully achieve the relevant goals. If we do not achieve the applicable goals, our distribution concessions and, therefore, our revenues and our capacity to fulfill our contractual obligations could be adversely affected. See “Item 4—Information on the Company—Our Concessions and Authorizations—Concessions” for more information.

The licenses, permits and authorizations required and applicable to our activities are issued by public bodies such as mayor offices and environmental agencies and must be kept valid. When necessary, such licenses, permits and authorizations must be renewed with the competent public authorities.

We cannot ensure that we will obtain or keep valid or timely renew all permits, authorizations and real estate and environmental licenses necessary for the development of our activities. The delay in or rejection to the issuance or renewal of such documents by licensing agencies, as well as any possible inability of ours to comply with the requirements set forth by such agencies during the licensing process, may adversely affect our results of operations. Failure to obtain, keep or renew these licenses or authorizations may result in the imposition of fines and the interdiction of our irregular establishments, with a total or partial interruption of our activities. In the event of closing or temporary interruption of any of our businesses, our businesses and results may be adversely affected.

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 Regulatory Framework, an electricity distributor must contract in advance, through public bids, for 100% of the required electricity that it has forecast for its Captive Consumers in its distribution concession areas, and is authorized to pass through the cost of up to 105% of this electricity purchase to consumers. Over- or under-forecasting demand can have adverse consequences. If we under-forecast the electricity demand and purchase in advance less electricity than we need, in a manner for which we are considered liable under the New Regulatory Framework and applicable regulation, we may be required to purchase the additional electricity in the spot market at volatile prices that can be 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 to purchasing electricity in the Free Marketor if events in Brazil or abroad which are not under our control, such as natural disasters or pandemics, create volatility in energy consumption), we may be required to sell the surplus energy at prices substantially lower than under our concessions. In either circumstance, if there are significant differences between our forecast electricity needs and actual demand, our results of operations may be adversely affected. Since August 2017, Decree No. 9,143/17 has allowed distribution companies to negotiate the energy surplus with Free Consumers and other agents of the Free Market (generators, traders and self-producers). See “Item 4. Information on the Company—The Brazilian Power Industry—The New Regulatory Framework—Restricted Activities of Distributors” and “Item 4. Information on the Company—Distribution—Purchases of Electricity” for more information.For more information about risks relating to natural disasters or pandemics, see “—An occurrence of a natural disaster, widespread health epidemic or pandemic or other outbreaks could significantly harm our business, financial condition and results of operations. Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in sporadic volatility in global markets. As a result, the Brazilian economy and outlook may be affected, and consequently, our business, financial condition and trading price of our common shares may be adversely affected.”

ANEEL is revising the regulation on net metering and distribution tariffs and such revisions could adversely affect our distribution business.

Established by ANEEL Normative Resolution No. 482, of April 17, 2012, net metering regulations enable Captive Consumers to generate power and to inject any surplus of energy into the distribution system, in exchange for energy credits that can be used to offset future consumption in the following 60 months. This resolution was amended in 2015 to enable shared generation of energy according to which a group of consumers can generate power in a remote location within the same distribution concession area and divide the energy credits between its constituents. ANEEL has conducted a public consultation and a public hearing and is currently conducting another public consultation to review ANEEL Normative Resolution No. 482, of April 17, 2012, in particular with regard to the distribution fees to be paid to distribution concessionaires over the netted amounts of energy. The revised regulation should come into effect in 2020. If ANEEL revises the regulation in a way that is unfavorable to us, our results of operations could be adversely affected.

Furthermore, Captive Consumers classified as Group B are currently subject to pay monomial distribution tariffs that include energy consumption and as well as the use of the distribution system. ANEEL is conducting public hearings to assess the regulatory impacts of a possible change in the tariffs structure of these consumers to a binomial structure, which would segregate the tariffs paid for the energy consumption and the tariffs paid for the use of the distribution system. If this binomial structure is implemented in a way that is unfavorable to us, our results of operations could be adversely affected.

Commercialization activity is subject to potential losses due to short-term variations in energy prices on the spot market. In addition, we may not be able to buy electricity in the amount we need to meet the requirements in our sales agreements, which may expose us to the spot market at prices substantially higher than under our long-term agreements.

In our energy commercialization activities, we may not be able to buy electricity in the amount we need to meet the requirements in our sales agreements, which may expose us to the spot market at prices substantially higher than the prices under our mid- and long-term agreements. In general, all agents of the Free Market are subject to potential differences between the volumes of energy generated or purchased (supply) and the volumes of energy sold or consumed (demand). These differences in volume are settled by the CCEE at the spot price, or the PLD. The PLD is calculated for each submarket and load level on a weekly basis and is based on the marginal cost of the operation, limited to minimum and maximum values determined by ANEEL. The maximum and minimum values of the PLD are reviewed and set each year by ANEEL. Variations in energy prices on the spot market may lead to potential losses in our commercialization activity. Factors that may affect the PLD include: (i) expected and identified load variations; (ii) variations in the reservoir levels of hydroelectric plants; (iii) decreases or increases of expected and verified affluence; (iv) anticipations or delays in the commencement of operations of new generation or transmission companies; and (v) variations in predicted and verified generation of small power plants. The occurrence of any of these factors may lead to a substantial variation in the PLD, which may result in increased costs or reduced revenues in the short-term energy commercialization, and may still adversely affect our cash flow. For more information about a series of recent developments in regulations with respect to registration with the CCEE of expected consumption volume by participants in the Free Market, see “Item 4. Information on the Company—The New Regulatory Framework—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 2019, according to data from the ONS, 70.5% (71.8% in 2018) of Brazil’s electricity supply came from Hydroelectric Power Plants.

Brazil is subject to unpredictable hydrological conditions, with non-cyclical deviations from the average rainfall index. 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, including those we operate, generate a volume of energy lower than the volume of energy assured under the MRE, these plants may be exposed to the PLD. In the context of the MRE, when the amount of energy generated is lower than the assured energy, the “Generation Scaling Factor,” or GSF, takes place, which results in exposure of the hydroelectric generator to the PLD in the spot market. From 2015 to 2018, there was a shortage of energy under the MRE, which resulted in higher disbursements from hydroelectric generation. We remain exposed to GSF risk and disburse PLD-based amounts to provide energy to our consumers in the Free Market.

In the distribution segment, there may be extraordinary costs in acquiring energy when the ONS dispatches Thermoelectric Power Plants out of the merit order, such as ESS, related to energy security. These additional costs may be passed on by distributors to consumers through periodic tariff readjustment or revision, in accordance with the applicable legislation. However, there will be a cash flow mismatch in the intervening period, since these costs must be covered immediately, while the tariffs are only readjusted annually. See “Item 4. Information on the Company—The Brazilian Power Industry—Regulatory Charges—ESS” for more information.

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 consumption to energy costs. Revenues collected under the tariff flag system are repaid to distribution companies on the basis of their relative energy cost for the period. Due to the poor hydrological conditions that were observed from 2013 through 2015, red tariff flags were applied throughout 2015 since introduction of the system in January 2015. In 2016, due to an improvement in hydrological conditions, green tariff flags were applied in most months of the year, but 2017 consisted principally of yellow and red tariff flags. In November 2017, ANEEL held a public hearing in order to review the tariff flags methodology. In accordance with the new methodology, red tariff flags were applied in November and December 2017. In 2018,green tariff flags were applied from January to April and again in December, yellow tariff flags were applied in May and November, and red tariff flags were applied from June to October. In April 2018, the methodology to calculate the additional rates due to the tariff flags was revised in order to consider the lack of hydropower generation (GSF factor). From June to October 2018, the tariff flag reached its highest level, collecting an additional R$50 per MWh consumed due to poor hydrological conditions and higher market prices.

In May 2019, through ANEEL Homologating Resolution No. 2,551, ANEEL revised the methodology used to calculate additional tariffs arising from tariff flag applications to consider the MRE’s total hydraulic generation forecast, as defined by the Monthly Operation Program (PMO), adjusted by the CCEE reduction factors and the average physical guarantee volume designed for the tariff flags and applied to the monthly average of the PLD for the tariff flag level, which is determined by the CCEE following price ranges triggers. The tariffs values valid from June 2019 to November 2019 were R$15 per MWh on yellow tariff flags, R$40 per MWh on the red tariff flags stage 1 and R$60 per MWh on the red tariff flags stage 2. In October 2019, ANEEL opened public consultation No. 27 to revise the tariff flag values, removing, as of November 2019, the rounding system that was applied to the values until then. As of November 2019, the current tariff flag values are: R$13.43 per MWh on yellow tariff flags, R$41.69 per MWh on the red tariff flags stage 1 and R$62.43 per MWh on the red tariff flags stage 2. In 2019, green tariff flags were applied from January to April and again in June, yellow tariff flags were applied in May, July, October and December, and red tariff flags level 1 were applied in August, September and November.

This mechanism may be insufficient to cover the thermoelectric energy supply costs and the exposure in the spot market due to poor hydrological conditions (GSF factor), and distributors still bear the risk of cash flow mismatches in the short term. See “Item 4. Information on the Company—Basis for Calculation of Distribution Tariffs” for more information.

If the hydrological conditions are not satisfactory or the tariff flags system is altered, our operations and financial results may be adversely affected, as well as our ability to fulfill our contractual obligations.

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.

The operational capacity of the Hydroelectric Power Plants in Brazil is strongly dependent on reservoir levels and, therefore, on rain. Periods of severe or sustained below-average rainfall resulting in an electricity shortage may adversely affect our financial condition and results of operations. Hydrological conditions may be challenging both during the wet season, from December to April, and the dry season, from May to November. 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%. The Rationing Program may result in the decrease of demand for electric energy in Brazil, reducing gross operational profits. 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.

In the event of a shortage of electricity, with a lower supply of electricity in the Brazilian market, our operations, financial results and our capacity to fulfill our contractual obligations may be adversely affected.

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

Decree No. 2,655 of July 2, 1998 established that the Assured Energy of generation power plants would be revised every five years. As part of these revisions, the MME can revise a company’s Assured Energy, limited to a maximum change of 5% per revision or 10% over the entire period of the concession agreement. According to Ordinance No. 515/2015 issued by the MME, the first revision of Assured Energy under this process was originally expected to be implemented for Hydroelectric Power Plants (other than SHPPs) in January 2017. Since the application of the methodology of this new revision to each power plant is not yet available; however, the MMEissued Ordinance No. 714/2016, pursuant to which the current Assured Energy for each Hydroelectric Power Plant would remain in effect until December 2017. The first revision of Assured Energy was implemented in January 2018 under MME Ordinance No. 178/2017 and led to a reduction in the Assured Energy of our Hydroelectric Power Plants by an average of 2.4%. SHPPs, unlike other Hydroelectric Power Plants, have been subject to annual revisions of their Assured Energy since 2010 in accordance with MME Ordinance No. 463/2009. These annual revisions have not resulted in reductions in the Assured Energy levels of CPFL Geração’s SHPPs, but have resulted in reductions for CPFL Renováveis’ SHPPs, which is subject to judicial discussion. Beginning in 2017, Decree No. 564/2014 extended such revision to biomass plants, which led to a decrease in the Assured Energy of CPFL Renováveis’ biomass plants by an average of 1.1% in 2019 and an increase by an average of 4.3% in 2018.

We cannot be certain of how and when future revisions will affect the Assured Energy of each of our individual power plants, whether the renewable energy producers will succeed in their appeal against the revision process, or whether the overall effect of revisions will increase or decrease our Assured Energy. When the Assured Energy of a power plant is decreased, our ability to supply electricity under that plant’s PPAs is adversely affected, which can lead to a decrease in our revenues and increase our costs if our generation subsidiaries are required to purchase power elsewhere. We expect revisions of Assured Energy under Decree No. 2,655/98 to continue to take place every five years for our power plants other than SHPPs. See “Item 4—Principal Regulatory Authorities—Ministry of Mines and Energy – MME” for more information.

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 or renew required governmental permits and approvals;
·	the unavailability of equipment;
·	supply interruptions;
·	work stoppages;
·	labor unrest, including strikes;
·	social unrest;
·	weather and hydrological interferences;
·	unforeseen engineering, regulatory and/or environmental problems;
·	increases in electricity losses, including technical and commercial losses;
·	construction and operational delays, or unanticipated cost overruns;

·	the inability to win electricity auctions held 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, results of operations and our capacity to fulfill our contractual obligations.

Dams are part of the Brazilian energy sector’s critical and essential infrastructure. Failures in dams under our responsibility can have serious impacts on affected communities, our results and our reputation.

Dams are important infrastructure for our business, representing most of our power generation capacity. However, dams have an intrinsic risk of rupture, either by factors internal or external to their structure (such as the rupture of an upstream dam). The gravity and nature of the risk are not entirely predictable. Thus, we are subject to the risk of a dam failure that could have much greater repercussions than the loss of hydroelectric generation capacity. Failure of a dam can result in economic, social, regulatory, environmental and potential loss of human lives in existing downstream communities. This could result in a significant adverse effect on our image, business, results of operations and financial condition.

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, obtaining and maintaining licenses, as well as regulation and oversight by Brazilian governmental agencies responsible for implementing environmental and health laws and policies. Such measures may include, among others, criminal and administrative penalties, such as the imposition of fines and the revocation of licenses. These agencies may take action against us if we do not comply with applicable regulations, or fail to obtain or maintain our respective licenses. The penalties depend on the intensity of the offense or the extent of the damage caused, as well as on any aggravating or mitigating circumstances applicable to the violator. It is possible that an increase in the strictness of environmental and health regulations will force us to increase or direct our investments to comply with such regulation and, consequently, to divert resources from planned investments, which may adversely affect our financial situation and result of our operations.

Companies in the electricity sector are subject to strict environmental legislation at the federal, state and local levels regarding vegetation suppression, solid waste management, interventions in specially protected areas, and the operation of potentially polluting activities, among others. Such companies require licenses and authorizations from governmental agencies for the installation of their businesses and the operation of their activities.

In the event of violation or non-compliance with such laws, regulations, licenses and authorizations, companies may be subject to administrative sanctions, such as fines, prohibition of activities, cancellation of licenses and revocation of authorizations, or criminal sanctions (including their management), without prejudice to the obligation to repair the environmental damage caused in the civil sector. The Public Prosecutor’s Office may initiate a civil investigation or immediately initiate public civil action seeking compensation for possible damage to the environment and affected third parties.

Federal legislation imposes strict liability on all those who directly or indirectly cause environmental degradation and, therefore, the duty to repair or indemnify for damages caused to the environment and to affected third parties, regardless of intent or fault. Federal legislation also provides for piercing the corporate veil of the polluting company, subjecting management and shareholders to personal responsibility, to enable compensation for damages caused to environmental quality. As a result, we may be required to bear the cost of environmental repair. Payment of substantial environmental indemnities or material expenses incurred to fund environmental recovery may prevent, or cause us to delay or redirect investment plans to other areas, which may adversely affect our business, reputation, operations and image.

Governmental agencies or other authorities may also edit new, stricter rules or seek more restrictive interpretations of existing laws and regulations, which may require companies in the electric power sector, including us, to spend additional resources on environmental suitability, including obtaining environmental licenses for installations and equipment that did not previously require these environmental licenses.

If environmental and health regulations become more stringent in the future, our operations and financial results may be adversely affected, as well as our ability to meet our contractual obligations.

Changes in Brazilian tax legislation, tax incentives and benefits, or different interpretations of tax legislation or case law may negatively affect our results of operations.

Changes in Brazilian tax laws, interpretations of tax authorities, administrative or judicial jurisprudence and tax rules in Brazil may result in an increase in the tax burden on our financial results, which may significantly reduce our operating profits and cash flows. Our distribution subsidiaries and commercialization subsidiary, CPFL Brasil, are parties to judicial proceedings that address the exclusion of ICMS from the tax assessment basis of PIS and COFINS paid by such entities. If we are successful in such proceedings, we expect to obtain a tax credit of part of the amounts of PIS and COFINS overpaid, while the remaining amounts may have to be returned to consumers. If the administrative or judicial authorities have a different understanding than ours as to the use of the tax credit, we may have to return the total amount of the overpayments to consumers, which will not give rise to the benefits we expect. In addition, our results of operations and our financial condition may be negatively affected if certain tax incentives are not maintained or renewed. We may fail to collect applicable taxes and fees or to comply with tax laws, which may result in additional tax assessments and penalties.

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 R$1,158 million in our generation activities (R$1,085 million in renewable sources and R$73 million in conventional sources), R$11,587 million in our distribution activities, R$233 million in our commercialization and services activities and R$564 million in our transmission activities during the period from 2020 through 2024. Our ability to carry out this capital expenditure program depends on a variety of factors, including our ability to charge adequate tariffs for our services, our access to domestic and international capital markets and a variety of operating, regulatory and other contingencies. We cannot be certain that we will have the financial resources to complete our proposed capital expenditure program, and failure to do so could have a material adverse effect on the operation and development of our business.

We plan to make capital expenditures aggregating R$3,069 million in 2020, R$2,924 million in 2021, R$2,906 million in 2022, R$2,334 million in 2023 and R$2,306 million in 2024. We have already contractually committed to part of these expenditures, particularly in generation projects. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments” for more information. Planned capital expenditures for development of our generation capacity, and the related financing arrangements, are discussed in more detail under “Item 4. Information on the Company—Generation of Electricity.” Our ability to complete the proposed capital expenditure program described above depends on a series of factors, including our ability to charge adequate tariffs for our services, our access to Brazilian and foreign securities markets and several operational and regulatory contingencies, among others. There is no certainty regarding whether we will have the financial resources available to conclude our proposed capital expenditure program. Any inability to complete this program may have a material adverse effect on us, our operations, the development of our business and our capacity to fulfill our contractual obligations.

We are liable for any losses and damages resulting from not providing or inadequately providing 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. We may have to pay for damages resulting from not rendering or inadequately rendering electricity services, which may have an adverse effect on us and our capacity to fulfill our contractual obligations.

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$972 million for the last three fiscal years) in generation businesses other than hydroelectric power, principallywind generation. Some of these business lines depend on favorable regulatory incentives to support continued investing and there is significant uncertainty as to the extent to which these favorable regulatory incentives will be available in the future. 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 or in the Free Market. 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 expected benchmarks.

Production levels of wind projects depend on adequate wind, resulting in volatility in production levels and profitability. For example, estimates of natural resources for our wind projects are based on historical experience, when available, and on wind resources studies conducted by an independent certifier, and do not necessarily reflect actual wind power production in a given year.

As a result, these types of renewable energy projects face considerable risks in relation to our core business, including the risk that favorable regulatory regimes will expire or be adversely modified. Additionally, at the development or acquisition stage, due to the incipient nature of these industries or limited experience with relevant technologies, our ability to predict actual performance results may be impaired and projects may not perform as expected. 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 or be subject to the penalties set forth in the agreements, which would increase our costs and lead to losses in this segment. These projects are capital intensive and generally require third-party financing, which can be difficult to obtain at attractive rates. As a result, capital constraints may reduce our ability to develop such projects or develop them based on an efficient capital structure. See “Item 4. Information on the Company—The Brazilian Power Industry—The New Regulatory Framework” for more information.

Our controlling shareholder’s interests could conflict with yours.

On January 23, 2017, State Grid Brazil Power Participações S.A., or State Grid, consummated the acquisition of common shares representing 54.6% of our voting capital, pursuant to which it has gained control over us. State Grid Brazil Power Participações S.A. is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China. In November 2017, State Grid launched a mandatory tender offer for our shares. Following the closing of this tender offer on December 5, 2017, State Grid directly and indirectly through ESC Energia S.A. (a wholly-owned subsidiary of State Grid) held 964,521,902 of our common shares, equivalent to 94.75% of our total share capital. On May 30, 2019, we announced the launch of our follow-on primary equity offering, or the Follow-on Offering, which closed on June 14, 2019. Following the closing of the Follow-on Offering, State Grid’s direct and indirect equity interest in our capital stock decreased to 83.71%.

On December 18, 2019, our board of directors approved our intention to (i) terminate our Second Amended and Restated Deposit Agreement, or the Deposit Agreement, with Citibank, N.A. regarding our ADSs, (ii) delist our ADSs from the New York Stock Exchange, or the NYSE, and (iii) terminate our registration with the U.S. Securities and Exchange Commission, or the SEC. Following the termination of our Deposit Agreement, on January 28, 2020, the NYSE suspended trading in our ADSs and filed a Form 25 with the SEC to permanently remove our ADSs from listing. This removal became effective on February 10, 2020. Once we meet the criteria for terminating our reporting obligations under the Exchange Act of 1934, as amended, or the Exchange Act, we intend to file a Form 15F with the SEC to deregister and terminate our reporting obligations under the Exchange Act. Immediately upon filing Form 15F, our legal obligation to file reports under the Exchange Act will be suspended, and deregistration is expected to become effective 90 days later.

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 common shares. See “Item 4. Information on the Company—Overview” for more information regarding State Grid’s acquisition and our announced intention regarding our ADSs.

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

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. Itaipu rates rise or fall pursuant to the variation of the U.S. dollar/realexchange rate. Furthermore, changes in the price of electricity generated by Itaipu are subject to the Parcel A Cost recovery mechanism pursuant to which our tariffs are adjusted annually in order to contemplate the losses or gains from these purchases from Itaipu. Our cash flows may be adversely affected by volatile exchange rates due to the mismatch between the date on which we purchase electricity from Itaipu and the date on which our tariffs are adjusted through the Parcel A Cost recovery mechanism. For more information on the Parcel A Cost recovery mechanism, see “Item 4. Information on the Company—Basis for Calculation of Distribution Tariffs.”

Natural disasters, the outbreak of a widespread health epidemic or pandemic, or other events, such as wars, acts of terrorism, political events and environmental accidents may cause sporadic volatility in global markets and result in volatile exchange rates. See “—An occurrence of a natural disaster, widespread health epidemic or pandemic or other outbreaks could significantly harm our business, financial condition and results of operations. Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in sporadic volatility in global markets. As a result, the Brazilian economy and outlook may be affected, and consequently, our business, financial condition and trading price of our common shares may be adversely affected.”

Our level of indebtedness and debt service obligations, as well as the restrictive covenants in our financial contracts, could adversely affect our ability to operate our business and make payments on our debt.

As of December 31, 2019, we had total debt of R$18,910 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.

Some of our financing agreements contain restrictive covenants that impose operational restrictions and other restrictions on our business. In particular, some of these covenants prevent us from incurring additional debt or making restricted payments, including the distribution of dividends, should we not comply with certain financial ratios and financial tests. These indexes and financial tests are based on the achievement of certain adjusted EBITDA levels (calculated according to the criteria contained in the debt instruments), interest expenses, total indebtedness and net profit. These indexes and financial tests are maintenance tests, which means that we must comply with them continuously every year to not breach our debt obligations. Our ability to comply with these indexes and financial tests may be affected by events beyond our control and we cannot assure that we will comply with these indexes and financial tests. Failure to comply with any of these covenants may result in an event of default under these agreements and others.

Our level of indebtedness and the restrictive covenants in our debt instruments may entail significant risks, including the following:

·	increase our vulnerability to negative economic, financial and sectorial conditions in general; and
·	the need to dedicate a substantial part of our cash flows from debt service operations, thus reducing the availability of our cash flows to finance capital expenditures.

Our operational cash flow generation may not be sufficient to pay the principal, interest and other amounts owed in relation to current and future debt. In this case, we may not be able to borrow, sell assets or otherwise raise funds on acceptable terms or even do so to refinance our debt as soon as it is due or becomes due. If we incur additional debt, the risks related to our debt may increase, including the risk of default upon maturity of our debt.

In the event that we are in default under any of our financing agreements, the maturity of the debt underlying these agreements (including principal, interest and any fines) may be accelerated, which may trigger provisions for cross-default or cross-acceleration under our other financing agreements and, in view of our significant level of indebtedness, materially and adversely affect our financial condition. In the past, we have been unable to comply with certain of our debt covenants and we have requested and obtained waivers from compliance with certain debt coverage ratio covenants. We may, in the future, be unable to comply with such or other applicable debt covenants and be forced to seek additional waivers. We cannot guarantee that we will be successful in meeting our covenants, and if we are unable to meet our covenants, in obtaining or renewing any waivers.

Hiring costs may vary according to market demand due to a restricted number of suppliers.

Our maintenance needs and construction demands of new projects are met by a limited number of suppliers. We are vulnerable to market supply and demand, especially at times when there are large investments in the energy sector, which may cause us to pay high prices for these services and materials used in these projects.

The inability or unwillingness of such third parties to provide us these services at the quality level set forth in the contract, as well as to supply the necessary materials to perform these services, may: (i) cause non-compliance with our regulatory obligations; (ii) jeopardize the preservation of our power plants and transmission and Distribution Networks; or (iii) temporarily reduce the electric power generation availability or capacity of our power stations and our transmission and Distribution Networks. As a result, we may have lower sales revenues and a possible short-term market exposure, which may have an adverse effect on our results and image. Termination of these materials supply agreements and construction or operation and maintenance services, or our inability to renew them or to negotiate new agreements with other equally qualified service providers, in a timely manner and at similar prices, may have an adverse effect on our results.

We rely on third parties to supply equipment used in our facilities, as well as to conduct part of our operations, and the failure of one or more suppliers may adversely affect our activities, financial condition and results of operations.

We rely on third parties to provide the equipment used in our facilities and engineering services and, as a result, we are subject to price increases and failures by such suppliers and service providers, such as delivery delays or delivery of damaged equipment. Such issues may adversely affect our activities and have an adverse effect on our results. Furthermore, various sources of supply-chain risk, including strikes or shutdowns, loss of or damage to our equipment or their components while they are in transit or storage, natural disasters or the occurrence of a contagious disease or illness, such as the coronavirus, or COVID-19, outbreak that the World Health Organization designated as a pandemic in March 2020, could limit the supply of the equipment used in our facilities.

In addition, due to the technical specifications of our equipment and construction projects, there are few suppliers and service providers available. If a supplier discontinues the production or the sale of any equipment necessary to our activities or interrupts the provision of engineering services, we may not be able to acquire such equipment or service from other suppliers under the same price and conditions. As a result, the provision oftransmission and generation services by us may be significantly impaired, which may adversely impact our financial condition and results of operations.

Since we outsource part of our operations, in the event that one or more service providers discontinue its activities or interrupts the rendering of services, our operations may be adversely affected, which may have an adverse effect on our results and financial condition.

In particular, we may experience a shortage in some of the key equipment used in our activities due to disruptions caused by the current COVID-19 pandemic, particularly in China where some of this equipment is manufactured. Any continued operating complications caused by the COVID-19 pandemic, including any prolonged period of travel, work place closures, commercial and other similar restrictions may result in further shortages or service interruptions. Any shortages or interruptions may adversely affect the continuous development of our activities, which may have a material adverse effect on our results of operations and financial position.

Furthermore, in the event that one or more service providers do not comply with any of their labor or social security obligations, we may be jointly and severally or subsidiarily liable for such obligations. This may adversely affect our operating results, as well as negatively impact our reputation in the event of any future fine or indemnity payment.

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

We regularly analyze opportunities to acquire other companies engaged in activities along the entire electricity generation, transmission and distribution chain, such as when we acquired RGE Sul in October 2016, or make non-controlling investments in companies in the sector. Such acquisitions involve risks and challenges relating to achieving the conditions that were used to project the future profitability of the business, including integrating operations, systems, employees, equipment and clients of the acquired companies, as well as generating the expected return on investments and exposure to liabilities of such companies. As a result, integrating our businesses with the business of the acquired companies and capturing its synergies may also require more resources and time than initially expected.

Such acquisitions may also require approval by CADE, ANEEL, and existing and future financial creditors. The decisions of any of these entities may be prejudicial to our businesses and may even result in the cancellation or nullification of the transaction.

If we do make investments in other electricity companies, this could increase our leverage or reduce our profitability. Furthermore, we may not be able to integrate an acquired company’s activities and achieve the economies of scale and expected efficiency gains that often drive such acquisitions. Any such failure could harm our financial condition and results of operations.

Our transmission business may be obligated to perform certain work for a price established by ANEEL, which may be based on unrealistic costs and at a lower weighted average cost of capital than the one we accepted in the auctions in which we have participated.

The applicable laws and regulations, as well as the concession agreements of our transmission business, set forth that we are obligated to perform maintenance and enhancements on the existing transmission facilities when mandated by ANEEL. The price for such projects is unilaterally established by ANEEL based on prices included in a theoretical cost database and on a regulatory weighted average cost of capital, which may be lower than the one we accepted in the auctions in which we have participated. We may perform work for which returns on investment may differ from our expectations.

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 and the recent COVID-19 pandemic, which has led to a prolonged period of workplace closures, commercial shutdowns and other similar restrictions, could lead to an increase in the risk of default by our consumers. ANEEL has also recently introduced measures restricting our ability to suspend service following consumer defaults for a specified period. For more information about the COVID-19 pandemic, see “—An occurrence of a natural disaster, widespread health epidemic or pandemic or other outbreaks could significantly harm our business, financial condition and results of operations. Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in sporadic volatility in global markets. As a result, the Brazilian economy and outlook may be affected, and consequently, our business, financial condition and trading price of our common shares may be adversely affected.”We cannot assure you that the measures to improve payment collection that we implemented will be sufficient or effective in maintaining our consumer default at current levels. If the level of default increases, our business, operational results, financial situation and capacity to fulfill our contractual obligations could be adversely affected.

Our business is subject to cyber-attacks and security and privacy breaches.

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

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

Our information technology and infrastructure may be vulnerable to cyber-attacks or security breaches, and third parties may be able to access our customers’, suppliers’ and employees’ personal or proprietary information that are stored on or accessible through those systems. Our security measures may also be breached due to human error, malfeasance, system errors or vulnerabilities, or other irregularities. Any actual or perceived breach of our security could interrupt our operations, result in our systems or services being unavailable, result in improper disclosure of data, materially harm our reputation and brand, result in significant legal and financial exposure, lead to loss of customer confidence in, or decreased use of, our products and services, and adversely affect our business and results of operations. In addition, any breaches of network or data security at our customers or suppliers, including data center, could have similar negative effects. Actual or perceived vulnerabilities or data breaches may lead to claims against us.

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

Data breaches in our database, which contains the personal data of our clients, suppliers and employees, as well as the Brazilian General Data Protection Act, or GDPA, which will come into force in August 2020, and other developments in the personal data protection and privacy legal framework could have an adverse effect on our business, financial condition or results of operations.

We maintain a database of information about our customers, which mainly includes data collected when clients sign up for our services and through our mobile applications. If we experience a breach in our security procedures, the integrity of our database may be affected. Doubts or misgivings about the security and protection of our customers’ data stored in our systems or otherwise processed by us can affect our reputation and, therefore, negatively impact our results. Unauthorized access of the personal data of our clients or any public perception that we unduly disclose the personal information of our clients may subject us to legal or administrative proceedings, resulting in damages, fines and harm to our reputation, especially after the GDPA (as defined and described below) comes into force.

Currently, the processing of personal data in Brazil is regulated by a series of rules, such as the Federal Constitution, the Consumer Protection Code and the Brazilian Civil Rights Framework for the Internet. Efforts to protect personal data inserted into and/or made available in our systems may not ensure that these protections are adequate and comply with the rules established by the current legislation. Failure to comply with certain provisions of applicable law, especially as regards to (i) providing clear information on the data processing operations performed by us, (ii) respect for the original purpose of the data collection; (iii) legal deadlines for the storage and exclusion of user personal data, and (iv) the adoption of legally required security standards for the preservation and inviolability of the personal data processed, can give rise to penalties, such as fines and even temporary suspension or prohibition of our personal data processing activities.

There can be no guarantee that we will have sufficient financial resources to comply with any new regulations or successfully compete in relation to data protection practices, in the context of a shifting regulatory environment.

In 2018, Law No. 13,709/2018, the GDPA, was published, as amended by Law No. 13,853/2019, and will come into force in August 2020. The GDPA has a wide range of applications and applies to individuals and private and public entities, regardless of the country where they are located or where the data is hosted, as long as (i) the data processing takes place in Brazil; (ii) the data processing is aimed at offering services or goods or to process data of individuals located in Brazil; or (iii) the data collection takes place in Brazil. The GDPA will apply regardless of industry or business dealing with personal data and is not limited to data processing activities through digital media and/or in the internet.

The GDPA brings deep changes in the regulation of personal data processing in Brazil, with a set of rules to be observed in activities such as collection, processing, storage, use, transfer, sharing, and erasure of information related to identified or identifiable individuals in Brazil, including that of our clients, suppliers and employees. The GDPA establishes, among others, principles, requirements and obligations applicable to data controllers or processors, a set of rights of personal data subjects, the legal basis applicable to the protection of personal data, requirements for obtaining consent of data subjects, obligations and requirements relating to security incidents, and obligations related to cross-borders data transfers, obligations to appoint a data protection officer, corporate governance practices, civil liability regime and penalties for non-compliance with its provisions. Law No. 13,853/2019 authorized the creation of the National Data Protection Authority, which will have authority and responsibility similar to that of the European data protection authorities. The National Data Protection Authority is currently not operational and no commissioners have been appointed to it. The National Data Protection Authority will be responsible for (i) conducting investigations, during which it will have the authority to issue rules and proceedings, decide on the GDPA interpretation and request information from controllers and processors; (ii) enforcing the law, in case of non-compliance, through administrative proceedings; and (iii) providing education, by disseminating information and knowledge about the GDPA and security measures, promoting service and product standards that support data control and developing studies about national and international practices for personal data protection and privacy, among other measures.

We may have difficulty adapting to the new legislation. In the event of non-compliance with the GDPA, we may be subject to penalties which include the publication of the infraction, elimination of personal data to which the violation relates, and an administrative fine.

The GDPA and similar laws and regulations that may be passed or issued by the National Data Protection Authority in the future may be interpreted and applied differently over time and from jurisdiction to jurisdiction, and it is possible they will be interpreted and applied in ways that will materially and adversely affect our business. Any failure, real or perceived, by us to comply with the law in force relating to personal data protection or with any regulatory requirements or orders or other local, state, federal, or international personal data protection-related laws and regulations could materially and adversely affect our business.

We may be substantially affected by violations of our Code of Ethical Conduct, the Anti-Corruption Law and similar laws.

Non-compliance by our officers, managers, employees or representatives, as well as by our subsidiaries, controlling companies or affiliates, jointly and severally, of our Code of Ethical Conduct and of applicable anti-corruption legislation may expose us to penalties set forth therein. Accordingly, our compliance guidelines may not be sufficient to prevent or detect inappropriate practices, fraud or breaches of law by any officer, manager, employee, representative, subsidiary, controlling company, affiliate or by any third party acting on behalf of or for the benefit of such parties or their interests. We may, in the future, discover cases in which there have been failures to comply with applicable laws, regulations or internal controls, which may result in fines or other penalties and adversely affect our reputation, financial condition and strategic objectives.

Law No. 12,846 of August 1, 2013, or the Anti-Corruption Law, introduced the concept of strict liability for legal entities involved in acts harmful to public administration, subjecting the offender to civil and administrative penalties, similar to the United States Foreign Corrupt Practices Act. Any failure to comply with anti-corruption laws, misconduct investigations or enforcement procedures against us may lead to fines, the loss of operating permits and reputational damage, as well as to other penalties, and may adversely affect us. We cannot ensure that our compliance guidelines are sufficient to prevent or detect all inappropriate practices, frauds or violations of the Anti-Corruption Law and similar laws by any of our officers, managers, employees or representatives.

Our internal controls may be insufficient to prevent or detect all violations of applicable law or of our internal policies.

Our internal controls may not be sufficient to prevent or detect all improper conduct, incidents of fraud or breaches of applicable law by our employees and members of our management. If our employees or other persons affiliated with us engage in fraudulent, corrupt or unfair practices or violate applicable laws and regulations or our internal policies, we may be held liable for any such violations, which may result in penalties, fines or sanctions that can substantially and adversely affect our businesses and our image.

Any future liquidation proceeding of the company or its subsidiaries may be conducted on a consolidated basis.

The Brazilian judiciary or our creditors and/or those of companies in our economic group may determine that any future liquidation proceeding of a company in an economic group be conducted as if the group were a single company (substantial consolidation theory). Should this happen, our shareholders may be adversely affected by the loss of value of the company in the event of allocation of our equity to pay the creditors of other companies in our economic group.

Unfavorable decisions in judicial or administrative proceedings or arbitrations may adversely affect our reputation, business, financial condition and operational results.

We and our managers are or may become defendants in judicial and administrative proceedings and arbitrations of a civil, criminal, tax, labor, regulatory and environmental nature, which we cannot guarantee will have favorable outcomes to us and our managers. The provisions we are required to make for these proceedings may be insufficient to cover the total cost involved. In addition, we and our management may be subject to contingenciesfor other reasons that require us to disburse significant amounts that affect the regular conduct of our business or result in the suspension or disqualification of our managers for the exercise of their positions. Unfavorable decisions for us or our managers may adversely affect our reputation, business, financial condition and operational results.

An occurrence of a natural disaster, widespread health epidemic or pandemic or other outbreaks could significantly harm our business, financial condition and results of operations. Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in sporadic volatility in global markets. As a result, the Brazilian economy and outlook may be affected, and consequently, our business, financial condition and trading price of our common shares may be adversely affected.

Natural disasters, such as fires or floods, the outbreak of a widespread health epidemic or pandemic, such as the COVID-19 pandemic, or other events, such as wars, acts of terrorism, political events, environmental accidents, power shortages or communication interruptions could significantly harm our business. The occurrence of a disaster or similar event may materially disrupt our business and operations. These events may also cause us to close our operating facilities temporarily, which would severely disrupt our operations and seriously harm our business, financial condition and results of operations. In addition, our net sales could be significantly reduced to the extent that a natural disaster, health epidemic or pandemic or other major event harms the economy of Brazil or any other jurisdictions where we may operate. Our operations could also be severely disrupted if our consumers, service providers or other participants were affected by natural disasters, health epidemics or pandemics or other major events.

Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in volatility in global markets, potentially affecting the Brazilian economy and outlook. In December 2019, a novel strain of coronavirus was reported to have surfaced in Wuhan, China and cases of infected patients have been reported in other jurisdictions, including reported cases in Brazil in, among other locations, the state of São Paulo, where we have our headquarters. On March 11, 2020, the World Health Organization designated COVID-19 as a pandemic. The spread of this virus has caused certain business, market and travel disruption globally and particularly in infected regions.

Increases in the number of infected patients in Brazil have adversely affected the Brazilian economy and the financial markets. Further increases in the number of infected patients in Brazil may cause these disruptions to be more severe and more acutely affect the Brazilian economy and the financial markets, consequently having an adverse effect on our financial condition, results of operations and the trading price of our common shares. For example, Brazilian residents, including our employees, that are suspected of having contracted a communicable disease such as COVID-19 are subjected to quarantines. On a business level, this may adversely affect our revenues and income from operations. For further information on the impact to our business, see "We rely on third parties to supply equipment used in our facilities, as well as to conduct part of our operations, and the failure of one or more suppliers may adversely affect our activities, financial condition and results of operations." Any such further outbreak could more generally restrict economic activities in affected regions in Brazil, resulting in reduced business volume, temporary closures of our or other companies’ facilities or otherwise disrupt our business operations.

While any disruption caused is currently expected to be temporary, there is uncertainty around the duration of these disruptions, the possibility of any government intervention or other measures, or the possibility of other economic effects on the stock market, foreign exchange rates and otherwise. Furthermore, the COVID-19 pandemic has already disrupted consumption and trade patterns, supply chains and production processes at a global scale. The extent to which the consequences of the COVID-19 pandemic impacts our results, including the results of our consumers, will depend on future developments that are highly uncertain and cannot be predicted, such as any new information which may emerge concerning the severity of the coronavirus, the potential spread to other regions and the actions to contain the coronavirus or treat its impact, among others.

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 common shares.

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

·	interest rates;
·	monetary policy;
·	currency fluctuations;
·	inflation;
·	liquidity of domestic capital and lending markets;
·	tax policies;
·	changes in labor laws;
·	regulatory environment of our sector;
·	exchange rates and exchange controls and restrictions on remittances abroad, such as those that were briefly imposed in 1989 and early 1990; and
·	other political, social and economic developments in or affecting Brazil.

Uncertainty over whether the Brazilian government will change policies or regulations affecting these or other factors may contribute to political and economic uncertainty in Brazil and to heightened volatility in Brazilian securities markets and securities issued abroad by Brazilian issuers. Standard & Poor’s downgraded Brazil below investment grade on September 9, 2015 and further downgraded Brazil from BB to BB- on January 11, 2018, with stable outlook, it reconfirmed its position on August 9, 2018 and on December 11, 2019, with positive outlook, and reconfirmed its position on April 6, 2020, with stable outlook; Fitch Ratings lowered its rating for Brazil from BBB- to BB+ on December 16, 2015, to BB on May 5, 2016 and later to BB- on February 23, 2018, with stable outlook, and reconfirmed its position on May 21, 2019 and on November 14, 2019; and Moody’s Investors Service downgraded Brazil to Ba2 on February 24, 2016, with stable outlook, and reconfirmed its position on April 9, 2018. 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.

The recent economic instability in Brazil has contributed to a decline in market confidence in the Brazilian economy, as well as to a deteriorating political environment. Despite the slow economic recovery and the still high fiscal vulnerability, several Brazilian macroeconomic fundamentals improved during 2018–19. The main highlight was the deceleration of inflation and the achievement of historically low interest rates.

In addition to the economic instability, the recent political instability in Brazil has also contributed to a decline in market confidence in the Brazilian economy. Various ongoing investigations into allegations of money laundering and corruption being conducted by the Office of the Brazilian Federal Prosecutor, including the largest such investigation, known as “Operação Lava Jato,” have negatively impacted the Brazilian economy and political environment.

Under “Operação Lava Jato” members of the Brazilian federal government and of the legislative branch, as well as senior officers of large state-owned and private companies, have faced allegations and, in certain cases, convictions, or, also, entering into plea bargains, related to crimes of political corruption, involving alleged bribes by means of kickbacks on contracts granted by the government to several infrastructure, oil and gas and construction companies. The profits of these kickbacks allegedly financed the political campaigns of political parties of the government that were unaccounted for or not publicly disclosed, in addition to alleged personal enrichment of the recipients of the bribes and the favoring of companies in contracts with the Brazilian government. Furthermore, certain of these companies have or are also facing investigations, and, in certain cases, being convicted by the competent authorities, such as the CVM, the SEC and the United States Department of Justice. Certain of these companies have chosen to enter into leniency agreements with the competent authorities, when possible. The potential outcome of these investigations, convictions, plea bargaining and leniency agreements is still uncertain, but they have already had 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 environment. We cannot predict whether such investigations will lead to further political and economic instability or whether new allegations against government officials, officers and/or companies will arise in the future. In addition, we cannot predict the outcome of any such investigations or allegations nor their effect on the Brazilian economy.

In August 2016, the Brazilian Senate approved the removal of Dilma Rousseff, Brazil’s then-President, from office, following a legal and administrative impeachment process for infringing budgetary laws. Michel Temer, the former Vice-President, who assumed the presidency of Brazil following Rousseff’s impeachment, is also under investigation for corruption allegations. He was first arrested on March 2019, having been convicted of the crimes of cartel involvement, active and passive corruption, money laundering and public auction fraud. He was released and arrested again four days later, in May 2019, and then released once again six days later. He continues to be under several investigation on corruption allegations. In addition, another former president, Luiz Inacio Lula da Silva, began serving a 12-year prison sentence for corruption and money laundering in April 2018 but was released from prison in November 2019 following a Federal Supreme Court ruling. Mr. da Silva still faces pending charges and could return to prison if found guilty once all appeals are exhausted. A strong opposition figure, Mr. da Silva’s release from prison could further deepen political tensions in Brazil.

On October 28, 2018, Jair Bolsonaro was elected the President of Brazil and took office on January 1, 2019. We cannot predict with certainty how Bolsonaro’s victory may affect Brazil’s overall stability, growth prospects, economic health and politics.

There is no guarantee that Bolsonaro will succeed in executing his campaign promises or approving certain favorable reforms, particularly when confronting a fractured congress. Additionally, during the presidential campaign, his Economic Minister, Paulo Guedes, proposed the repeal of the income tax exemption on the payment of dividends, which was recently reinforced together with reference to the extinction of interest attributable to shareholders’ equity. If such measures were to become law, there would be an increase in our tax expenses, which could impact our ability to pay and receive dividends or interest attributable to shareholders’ equity. Any future tax reform can also significantly influence our business if proposed and implemented. Moreover, Bolsonaro was generally a polarizing figure during his campaign for presidency, particularly in relation to certain social views, and we cannot predict the ways in which a divided electorate may continue to impact his presidency and ability to implement policies and reforms, all of which could have a negative impact on us and the price of our common shares.

In November 2019, the Brazilian government approved a pension reform after almost nine months of negotiations. The negotiations and delay in the approval of the pension reform exposed the political crisis between the Executive branch and Congress. In addition, the Brazilian federal government is expected to propose the general terms of a fiscal reform to stimulate the Brazilian economy and reduce the forecasted budget deficit for 2020 and subsequent years, but it is uncertain whether the federal government will be able to gather the required support in the Brazilian congress to pass any proposed reforms. If the Brazilian federal government fails to reduce public expenses and the expected reforms are not approved, Brazil will continue to run a budget deficit for 2020 and the subsequent years. We cannot predict the effects of this budget deficit on the Brazilian economy, nor which policies the Brazilian federal government may adopt or change or the effect that any such policies might have. Any such new policies or changes to current policies may have a material adverse effect on us or the price of our common shares. Furthermore, uncertainty over whether the current Brazilian government will implement changes in policy or regulation in the future may contribute to economic uncertainty in Brazil and to heightened volatility for securities issued abroad by Brazilian companies.

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 2010 and March 2020, the base interest rate in Brazil, or SELIC, varied between 14.25% p.a. and 3.75% p.a.

According to the IPCA index, the inflation rate was 4.3%, 3.8% and 2.9% in 2019, 2018 and 2017, respectively. On March, 2020, the accumulated inflation over the immediately preceding 12-month period was 3.30%. Brazil may experience high levels of inflation in the future and inflationary pressures may lead to the Brazilian government intervening in the economy and introducing policies that could adversely affect us, our business and the price of our common shares. In the past, the Brazilian government’s interventions included the maintenance of a restrictive monetary policy with high interest rates that restricted credit availability and reduced economic growth, causing volatility in interest rates. The SELIC rate oscillated from 13.75% as of December 31, 2016 to 4.5% as of December 31, 2019, as established by the CMN. More lenient Brazilian government and Brazilian Central Bank policies and interest rate decreases have triggered and may continue to trigger increases in inflation, and, consequently, growth volatility and the need for sudden and significant interest rate increases, which could negatively affect us and increase our indebtedness.

In the event that Brazil experiences high inflation in the future, we may not be able to adjust the prices we charge our clients to offset the potential impacts of inflation on our expenses, including salaries. This would lead to decreased profit for the year, adversely affecting us. Inflationary pressures may also adversely affect our ability to access foreign financial markets.

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

The Brazilian currency has experienced frequent and substantial variations in relation to the U.S. dollar and other foreign currencies over the last decade. The exchange rate of therealagainst the U.S. dollar was R$3.307 on December 31, 2017; R$3.874 on December 31, 2018; and R$4.030 on December 31, 2019. On April 22, 2020, the exchange rate was R$5.384 per US$1.00. Therealmay continue to fluctuate significantly against the U.S. dollar in the future.

Depreciation of therealincreases the cost of servicing our foreign currency denominated debt and the cost of purchasing electricity from the Itaipu power plant, a Hydroelectric Power Plant that is one of our major suppliers and that adjusts electricity prices based in part on its U.S. dollar costs. Depreciation of therealagainst the U.S. dollar could create inflationary pressures in Brazil and cause increases in interest rates, which could negatively affect the growth of the Brazilian economy as a whole and harm our financial condition and results of operations, curtail access to foreign financial markets and may prompt government intervention, including recessionary governmental policies. Depreciation of therealagainst the U.S. dollar can also lead to decreased consumer spending, deflationary pressures and reduced growth in the economy as a whole. On the other hand, appreciation of therealrelative to the U.S. dollar and other foreign currencies could lead to a deterioration of the Brazilian foreign exchange current account, as well as dampen export-driven growth. Depending on the circumstances, either depreciation or appreciation of therealcould materially and adversely affect the growth of the Brazilian economy and our business, financial condition and results of operations and our capacity to fulfill our contractual obligations.

Depreciation of therealalso reduces the U.S. dollar value of distributions and dividends on our common shares and the U.S. dollar equivalent of the market price of our common shares.

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 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 continuing to experience weak GDP growth.

On March 11, 2020, the World Health Organization designated COVID-19 as a pandemic. The spread of this virus has caused certain business, market and travel disruption globally and particularly in infected regions. While any disruption caused is currently expected to be temporary, there is uncertainty around the duration of these disruptions, the possibility of any government intervention or other measures, or the possibility of other economic effects on the stock market, foreign exchange rates and otherwise. For more information on risks relating to COVID-19, see “—An occurrence of a natural disaster, widespread health epidemic or pandemic or other outbreaks could significantly harm our business, financial condition and results of operations. Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in sporadic volatility in global markets. As a result, the Brazilian economy and outlook may be affected, and consequently, our business, financial condition and trading price of our common shares may be adversely affected.”

Although economic conditions in other countries may differ significantly from economic conditions in Brazil, investor reactions to developments in those countries, including the spread of the COVID-19 pandemic and its economic effects in other 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 our common shares, and could also make it more difficult for us to access the capital markets and finance our operations in the future on acceptable terms or at all.

Risks Relating to Our Common Shares

The relative volatility and illiquidity of the Brazilian securities markets may substantially limit your ability to sell our common shares 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. The Brazilian securities market is substantially smaller, less liquid, more concentrated and can be more volatile than major securities markets in the United States. Your ability to sell the common shares at a price and time at which you wish to do so is limited. There is also significantly greater concentration in the Brazilian securities market than in major securities markets in the United States. The ten largest companies in terms of market capitalization represented 46.9% of the aggregate market capitalization of the B3 (previously known as BM&FBOVESPA) as of December 31, 2019. The top ten stocks in terms of trading volume accounted for 33.9%, 40.8% and 32.1% of all shares traded in 2019, 2018, and 2017, respectively.

Holders of our common shares may be unable to enforce judgments against our directors or officers.

Most of our directors and officers named in this annual report reside in Brazil. Substantially all of our assets, as well as the assets of these persons, are located in Brazil. As a result, it may not be possible for holders of our common shares to effect service of process upon us or our directors and officers within the United States or other jurisdictions outside Brazil, attach their assets or enforce against us or our directors and officers judgments obtained in the United States or other jurisdictions outside of Brazil. Because judgments of U.S. courts for civil liabilities based upon the U.S. federal securities laws may only be enforced in Brazil if certain requirements are met, holders of our common shares may face greater difficulties in protecting their interest in actions against us or our directors and officers than would shareholders of a corporation incorporated in a state or other jurisdiction of the United States.

Judgments of Brazilian courts with respect to our common shares will be payable only in reais.

If proceedings are brought in Brazilian courts seeking to enforce our obligations in respect of our common shares, we will not be required to discharge any such obligations in a currency other thanreais. Under Brazilian exchange control limitations, an obligation in Brazil to pay amounts denominated in a currency other thanreais may only be satisfied in Brazilian currency at the exchange rate, as determined by the Brazilian Central Bank, in effect on the date the judgment is obtained, and any such amounts are then adjusted to reflect exchange rate variations through the effective payment date. The then prevailing exchange rate may not afford non-Brazilian investors with full compensation for any claim arising out of, or related to, our obligations under our shares.

Changes in Brazilian tax laws may have an adverse impact on the taxes applicable to a disposition of our common shares.

Law No. 10,833, dated as of December 29, 2003, provides that the disposition of assets located in Brazil by a non-resident to either a resident or a non-resident of Brazil is subject to taxation in Brazil, regardless of whether the disposition occurs outside or within Brazil. This provision results in the imposition of income tax on the gains arising from a disposition of our common shares by a non-resident of Brazil to either a resident or a non-resident of Brazil. Any gain or loss recognized by a U.S. holder on the disposition of common shares generally will be treated as U.S. source gain or loss for U.S. foreign tax credit purposes. Thus, a U.S. holder may not be able to benefit from a foreign tax credit for Brazilian income tax imposed on the disposition of common shares, unless the U.S. holder can apply the credit against U.S. federal income tax payable on other income from foreign sources in the appropriate income category. See “Item 10. Additional Information—U.S. Federal Income Tax Consequences—Taxation of Sales, Exchanges or Other Taxable Dispositions” for more information.

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 and commercial name CPFL Energia S.A. Our principal executive office is located at Rua Jorge de FigueiredoCorrea, No. 1,632, parte, CEP 13087-397, Jardim Professora Tarcília, Campinas, state of São Paulo, Brazil and our telephone number is +55 19 3756-6211. Our Investor Relations Department is located at the same address and its telephone number is +55 19 3756-8458.

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 68,055 GWh of electricity we distributed to 9.8 million consumers in 2019. In electricity generation, our Installed Capacity at December 31, 2019 was 4,304 MW. Through our interest in CPFL Renováveis, we are also involved in the construction of one SHPP and four wind farms, as a result of which we expect to increase our Installed Capacity by 109.7 MW over the next four years as these projects 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 2019, the total amount of electricity sold by our commercialization subsidiaries was 89 GWh and 19,097 GWh to affiliated and unaffiliated parties, respectively. We are presently also developing our electricity transmission business, having successfully won three of ANEEL’s 2018 greenfield transmission auctions that will require an investment of R$924 million (as estimated by ANEEL) and will require us to build approximately 407 km in transmission lines to add 2,343 MVA in our portfolio.

On September 2, 2016, our former shareholder Camargo Correa S.A. entered into an agreement to sell its 23.6% ownership interest in our company to State Grid. Following the announcement, other members of our then controlling shareholders’ block also decided to sell their ownership interest to State Grid. As a result, State Grid acquired 54.64% of our voting capital. State Grid Brazil Power Participações S.A. is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China. The acquisition was approved by CADE, the Brazilian antitrust regulator, in September 2016 and by ANEEL in December 2016. The acquisition was completed and, as a result, our control was transferred to State Grid on January 23, 2017. In November 2017, State Grid launched a mandatory tender offer for our shares. Following the closing of this tender offer on December 5, 2017, State Grid directly and indirectly through ESC Energia S.A. (a wholly-owned subsidiary of State Grid) held 964,521,902 of our common shares, equivalent to 94.75% of our total share capital.

In November 2018, State Grid also acquired 48.39% of the total share capital of CPFL Renováveis through a separate mandatory tender offer process. State Grid’s total share capital of CPFL Renováveis was diluted to 46.76% as a result of State Grid’s decision not to exercise its preemptive rights in the CPFL Renováveis capital increase that was approved by CPFL Renováveis’ board of directors on June 4, 2019 and to capitalize the Future Capital Increase Advance (Adiantamento para Futuro Aumento de Capital—AFAC) that CPFL Geração had held in CPFL Renováveis since 2016. This capital increase raised CPFL Geração’s total share capital of CPFL Renováveis to 53.18%.

On May 21, 2019, our board of directors authorized the beginning of CPFL Renováveis’ integration into our administrative structure. Our integration plan for CPFL Renováveis involves (i) the implementation of plans to restructure and improve the operations of CPFL Renováveis, with the aim of creating synergies between CPFL Renováveis and our current business, and (ii) conducting studies and analysis of a corporate reorganization that could involve a total or partial consolidation of CPFL Geração and CPFL Renováveis, which is still subject to further review by and ultimately the approval of our management. On July 1, 2019, following the authorization from our board of directors, our board of executive officers approved the integration of CPFL Renováveis’ administrative structure into our organizational model to optimize operations and gain efficiency. This potential consolidation would only occur following a final decision with respect to the B3’s requirement to reestablish CPFL Renováveis’ free float.

On May 30, 2019, we announced the launch of the Follow-on Offering, which closed on June 14, 2019. Pursuant to the Follow-on Offering, we offered 116,817,126 of our common shares in a global offering consisting of(i) a public offering of common shares with restricted selling efforts in Brazil, and (ii) a concurrent international offering of common shares, including in the form of ADSs, in the United States and elsewhere outside of Brazil. Also pursuant to the Follow-on Offering, we sold 17,522,568 additional common shares under an over-allotment option that closed on June 28, 2019. As a result of the Follow-on Offering, we received net proceeds of approximately R$3,164.3 million before expenses, after deducting underwriting commissions. We received net proceeds of approximately R$474.7 million before expenses, after deducting underwriting commissions, as a result of the over-allotment option. Following the closing of the Follow-on Offering, State Grid’s direct and indirect equity interest in our capital stock decreased to 83.71%.

On September 30, 2019, we, together with State Grid, announced the closing of the purchase and sale of the shares issued by CPFL Renováveis and the transfer by State Grid to us of all the shares of CPFL Renováveis directly held by State Grid at a purchase price of R$16.85 per share, as determined by the independent members of our board of directors on May 29, 2019 on the basis of an appraisal report prepared by financial advisory firm UBS. The total purchase price paid by us to State Grid was R$4.1 billion. We expect such transaction to enable potential synergies between us and our subsidiaries. On December 19, 2019, our board of directors and the board of executive officers of CPFL Geração approved CPFL Geração’s tender offer to acquire the remaining outstanding common shares of CPFL Renováveis to allow for the conversion of CPFL Renováveis’ registration as a category “A” publicly-held company into a category “B” publicly-held company and/or its delisting from theNovo Mercado. This tender offer is subject to CVM registration and to authorization by the B3. The offered price per share is R$16.85, as adjusted by the SELIC from the date of the mandatory tender offer carried out by State Grid in November 2018.

On December 18, 2019, our board of directors approved our intention to (i) terminate our Deposit Agreement regarding our ADSs, (ii) delist our ADSs from the NYSE, and (iii) terminate our registration with the U.S. Securities and Exchange Commission, or the SEC. Following the termination of our Deposit Agreement, on January 28, 2020, the NYSE suspended trading in our ADSs and filed a Form 25 with the SEC to permanently remove our ADSs from listing. This removal became effective on February 10, 2020. Once we meet the criteria for terminating our reporting obligations under the Exchange Act of 1934, as amended, or the Exchange Act, we intend to file a Form 15F with the SEC to deregister and terminate our reporting obligations under the Exchange Act. Immediately upon filing Form 15F, our legal obligation to file reports under the Exchange Act will be suspended, and deregistration is expected to become effective 90 days later.

The following significant developments have occurred in our business since the beginning of 2017:

·	On June 2, 2017, CPFL Transmissora de Energia Morro Agudo Ltda., or CPFL Morro Agudo, a subsidiary of CPFL Geração commenced operations. The concession contract has a duration of 30 years.
·	In June 27, 2017, the Pedra Cheirosa wind complex (Pedra Cheirosa I and II) commenced operations. Pedra Cheirosa, located in Itarema, in the state of Ceará, has Installed Capacity of 48.3 MW and a physical guarantee of 27.5 MWavg, as amended by Ordinance No. 192/2017. Until December 2017, when the A-5/2013 Energy Auction agreement took effect, the energy generated by Pedra Cheirosa was supplied to the system and sold in the spot market. Energy was sold through long-term contracts in the A-5/2013 Energy Auction, at R$166.83/MWh for Pedra Cheirosa I and at R$167.50/MWh for Pedra Cheirosa II, both in December 2019.
·	On December 15, 2017, the management of RGE Sul and its parent company CPFL Jaguariúna Participações Ltda., or CPFL Jaguariúna, approved the merger of CPFL Jaguariúna and RGE Sul. As a result of this merger, CPFL Jaguariúna was dissolved. This merger aimed to improve our governance structure and increase synergy with the other companies of our group.
·	On November 21, 2017, through the Resolution for Authorization No. 6,723/2017, ANEEL approved our proposal to consolidate the concessions of five of our distribution companies (CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari, together the Merged Companies), pursuant to Normative Resolution No. 716/2016. Effective as of January 1, 2018, the Merged Companies were merged with and into a company named CPFL Santa Cruz (which company was previously named CPFL Jaguari). This transaction was approved at the Extraordinary General Meetings held on December 31, 2017 at each of the Merged Companies. This merger led to the optimization of our administrative and operational costs and produced large-scale savings and synergy in 2018.
·	According to Normative Resolution No. 716/2016, until the first tariff review of the Merged Companies in March 2021, ANEEL may institute a policy that reconciles the variations in the old tariffs for each of the Merged Companies and the new unified tariff for CPFL Santa Cruz over time. ANEEL decided to introduce the unified tariff during the March 2018 tariff adjustment.
·	On June 29, 2018, we won the right to conduct transmission activities in Transmission Auction held by ANEEL. We were also awarded the concession for the Maracanaú II Substation and segments of transmission lines, located in the state of Ceará.
·	On August 31, 2018, at the A-6/2018 energy auction, or the A-6/2018 Energy Auction, CPFL Renováveis sold 28.5 MWavg to be generated by SHPP Lucia Cherobim, located in the state of Paraná, with Installed Capacity of 28.0 MW (16.6 MWavg) and by the Gameleira wind complex, located in the state of Rio Grande do Norte, with Installed Capacity of 69.3 MW (39.4 MWavg). The agreement will be extended for 30 years for SHPP Lucia Cherobim and 20 years for Gameleira wind complex, with energy supply starting on January 1, 2024. SHPP Lucia Cherobim sold 16.5 MWavg at R$189.95/MWh (base August 2018), with annual adjustments by the IPCA index. The Gameleira wind complex sold 12.0 MWavg at R$89.89/MWh (base August 2018), with annual adjustments by the IPCA index. Additionally, the Gameleira wind complex sold its remaining energy in the Free Market.

·	On October 14, 2018, SHPP Boa Vista 2 commenced operations, after receiving ANEEL’s authorization for commercial launch on the same date. SHPP Boa Vista 2 is located in the municipality of Varginha, in the state of Minas Gerais, has Installed Capacity of 29.9 MW and a physical guarantee of 15.5 MWavg. Until December 2019, when the A-5/2015 Energy Auction agreement took effect, the energy generated by SHPP Boa Vista 2 was supplied to the system and sold in the spot market.
·	On December 4, 2018, through the Resolution for Authorization No. 7,499/2018, ANEEL approved our proposal to consolidate the concessions of our two distribution companies (RGE and RGE Sul), pursuant to Normative Resolution No. 716/2016. Effective as of January 1, 2019, RGE was merged with and into RGE Sul, and RGE Sul began doing business under the name RGE. This transaction was approved at the Extraordinary General Meetings held on December 31, 2018 at each of RGE and RGE Sul. As a result of this merger transaction and the related transfer of the assets of RGE to RGE Sul, RGE no longer exists.
·	On December 20, 2018, we won the right to conduct transmission activities through Transmission Auction No. 4/2018 held by ANEEL. In this auction, we also won new Substations and transmission lines in the states of Santa Catarina and Rio Grande do Sul.
·	On May 21, 2019, our board of directors authorized the beginning of CPFL Renováveis’ integration into our administrative structure. Our integration plan for CPFL Renováveis involves (i) the implementation of plans to restructure and improve the operations of CPFL Renováveis, with the aim of creating synergies between CPFL Renováveis and our current business, and (ii) conducting studies and analysis of a corporate reorganization that could involve a total or partial consolidation of CPFL Geração and CPFL Renováveis, which is still subject to further review by and ultimately the approval of our management. On July 1, 2019, following the authorization from our board of directors, our board of executive officers approved the integration of CPFL Renováveis’ administrative structure into our organizational model to optimize operations and gain efficiency. This potential consolidation would only occur following a final decision with respect to the B3’s requirement to reestablish CPFL Renováveis’ free float.

On September 30, 2019, we, together with State Grid, announced the closing of the purchase and sale of the shares issued by CPFL Renováveis and the transfer by State Grid to us of all the shares of CPFL Renováveis directly held by State Grid at a purchase price of R$16.85 per share, as determined by the independent members of our board of directors on May 29, 2019 on the basis of an appraisal report prepared by financial advisory firm UBS. The total purchase price paid by us to State Grid was R$4.1 billion. We expect such transaction to enable potential synergies between us and our subsidiaries. On December 19, 2019, our board of directors and the board of executive officers of CPFL Geração approved CPFL Geração’s tender offer to acquire the remaining outstanding common shares of CPFL Renováveis to allow for the conversion of CPFL Renováveis’ registration as a category “A” publicly-held company into a category “B” publicly-held company and/or its delisting from the Novo Mercado. This tender offer is subject to CVM registration and to authorization by the B3. The offered price per share is R$16.85, as adjusted by the SELIC from the date of the mandatory tender offer carried out by State Grid in November 2018.

The following chart provides an overview of our corporate structure at March 31, 2020:

Notes:

(1) RGE is held by CPFL Energia (89.0107%) and CPFL Brasil (10.9893%).

(2) CPFL Soluções = CPFL Brasil + CPFL Serviços + CPFL Eficiência.

(3) 51.54% stake of the availability of power and energy of Serra da Mesa HPP, regarding the rental contract and a PPA between CPFL Geração and Furnas Centrais Elétricas S.A., or Furnas.

(4) CPFL Renováveis is held by CPFL Energia (46.7609%) and by CPFL Geração (53.1831%).

Our core businesses are:

Distribution. In 2019, our four fully-consolidated distribution subsidiaries delivered 68,055GWh of electricity to 9.8 million consumers primarily in the states of São Paulo and Rio Grande do Sul.

Conventional Generation. At December 31, 2019, our conventional generation subsidiaries had Installed Capacity of 2,173 MW. During 2019, we generated 7,180GWh of electricity, and we had 9,592GWh of Assured Energy at December 31, 2019, which consists of the amount of energy representing our long-term average electricity production, as established by ANEEL, which is the primary driver of our revenues from generation activities. We currently hold equity interests in eight Hydroelectric Power Plants: Serra da Mesa, Monte Claro, Barra Grande, Campos Novos, Luiz Eduardo Magalhães-Lajeado, Castro Alves, 14 de Julho and Foz do Chapecó.Although the concession for the Serra da Mesa Hydroelectric Facility is held by another party, Furnas, we are entitled to 51.54% of its Assured Energy. We also own two Thermoelectric Power Plants, Termonordeste and Termoparaíba. In addition, 10 of our 48 Small Hydroelectric Power Plants remain under the management of two of our conventional generation subsidiaries, CPFL Geração and CPFL Centrais Geradoras, and report their results within our conventional generation segment. On July 17, 2018, MME published Order No. 304/2018, which terminated the Cariobinha concession, without reversal of assets. In September 2019, SCG/ANEEL published Dispatch No. 039/2019, which declared the Cariobinha concession agreement null. Also in 2019, CGH Santa Alice’s register was cancelled, and the project was leased to TIM Celular S.A. and began operations as distributed generation services on June 1, 2019.

In 2017, we began to report within this business the activities of our two transmission assets held through CPFL Geração, CPFL Piracicaba and CPFL Morro Agudo, both of which are operational. Our transmission subsidiaries provide electricity transmission services to the Brazilian power grid. On June 29, 2018, we won the right to conduct transmission activities in Transmission Auction No. 2/2018 held by ANEEL by means of the concession for the Maracanaú II Substation (Lot 9) and segments of transmission lines, located in the state of Ceará. Lot 9 has annual allowed revenues, or RAP, of R$7.9 million, an estimated investment of R$102.2 million (as estimated by ANEEL) and its regulatory commercial operation is scheduled for March 2022. In December 2018, we won Lot 5 (Itá Substation, in Santa Catarina) and Lot 11 (Osório 3, Porto Alegre 1 and Vila Maria Substations, in Rio Grande do Sul) at ANEEL’s Transmission Auction of greenfield assets No. 4/2018. Lot 5 has a RAP of R$26.4 million, an estimated investment of R$366.0 million (as estimated by ANEEL) and its regulatory commercial operation is scheduled for March 2024. Lot 11 has a RAP of R$33.9 million, an estimated investment of R$348.9 million (as estimated by ANEEL) and its regulatory commercial operation is scheduled for March 2023. Besides their remuneration as stand-alone assets, this new business line is expected to have a positive effect on the reliability and quality of our Distribution Networks, as some are located in our distribution concession areas or have a direct impact on them.

Renewable Generation. Our indirect subsidiary, CPFL Renováveis, in which we own a 99.94% interest, concentrates our activities in energy generation through renewable sources. CPFL Renováveis operates all of our wind farms and Biomass Thermoelectric Power Plants, as well as 40 of our 48 Small Hydroelectric Power Plants. These 40 Small Hydroelectric Power Plants, which are all operational, are located in the states of São Paulo, Santa Catarina, Rio Grande do Sul, Minas Gerais, Mato Grosso and Paraná, and have aggregate Installed Capacity of 453.1 MW. One Small Hydroelectric Power Plant (SHPP Lucia Cherobim) is under construction, scheduled to commence operations by 2024, and expected to have an Installed Capacity of 28 MW. CPFL Renováveis also has 49wind farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, (i) 45 of which are operational and have aggregate Installed Capacity of 1,308.6 MW, and (ii) four of which make up the Gameleirawind complex and are under construction with operations scheduled to commence operations by 2024, and expected to have an Installed Capacity of 69.3 MW. CPFL Renováveis also has eight operational Biomass Thermoelectric Power Plants, with aggregate Installed Capacity of 370 MW, located in the states of Minas Gerais, Paraná, São Paulo and Rio Grande do Norte. CPFL Renováveis also operates the Tanquinho Solar Power Plant, which is located in the state of São Paulo and has Installed Capacity of 1.1 MW. At December 31, 2019, our total consolidated Installed Capacity through our renewable generation segment (calculated on the basis of our 99.94% interest in CPFL Renováveis) was 2,131.5 MW, and we expect that our renewable generation segment will reach an Installed Capacity of 2,228.7 MW by 2024. These capacity amounts do not include eventual decreases in our Installed Capacity ballast (limit of energy produced in our own power plants that we are allowed to sell). Those decreases are calculated by the MME, for power plants participating in the MRE. See “Regulatory Charges—Energy Reallocation Mechanism” for more information about the MRE.

Commercialization. Our commercialization subsidiaries handle our commercialization operations and provide agency services to Free Consumers before the CCEE and other agents, including guidance on their operational requirements. CPFL Brasil, our largest commercialization subsidiary, procures and sells electricity to Free Consumers, other commercialization and generation companies and distribution facilities. In 2019, we sold 19,186 GWh of electricity, of which 19,097 GWh was sold to unaffiliated third parties.

Services. We report the results of our services activities as a separate operating segment. Our activities in this sector include providing electricity-related services, such as project design and construction, to our affiliates and unaffiliated parties.

In addition to our five operating segments above, we consolidate a number of activities known as “Other.” The activities consolidated under Other consist mainly of our holding company expenses.

Our Strategy

Our overall objective is to be the leading power utility company in South America, supplying reliable electric energy and credible services to our customers while creating value for our shareholders. We seek to achieve these goals in all of our sectors (distribution, conventional generation, renewable generation, transmission, 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 and expand our generation portfolio by developing new conventional and renewable energy generation projects. At December 31, 2019, our total consolidated Installed Capacity (calculated on the basis of our 99.94% interest in CPFL Renováveis) was 4,304 MW, of which 2,173 MW was through conventional sources and 2,131.5 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, according to ANEEL.

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 have a consolidated portfolio of 2,131.5 MW (calculated on the basis of our 99.94% interest in CPFL Renováveis). We also have 110 MW under construction and a total portfolio of 2,904 MW of renewable generation projects to be developed by CPFL Renováveis in the coming years.

Focus on further improving our operating efficiency. The distribution of electricity in our distribution concession areas is our largest business segment, representing 66.8% of our consolidated profit for the year in 2019. We continue to focus on improving the quality of our service and maintaining efficient operational costs by exploiting synergies and technologies. We also make an effort to standardize and update our operations regularly, introducing automated systems where possible. We also acknowledge the need to invest in digital assets, such as Smart Grid technology and in 2019 we deployed 1,563 automatic circuit reclosers, or ACRs, bringing the total number of ACRs in our concession areas to 11,394. These ACRs allow greater flexibility in the operation of the electrical system and are supported by our robust proprietary communication infrastructure, including digital radiocommunication systems, radio frequency mesh and fiber optic network, as well as our partnership with telecommunications utility providers.

To this end, we plan to make capital expenditures aggregating R$3,069 million in 2020 and R$2,924 million in 2021. Of the total budgeted capital expenditures over this period, R$4,598 million, or 77%, are expected to be invested in our distribution segment, R$681 million, or 11%, in our renewable generation segment and R$33 million, or 1%, in our conventional generation segment and R$130 million, or 2%, in our commercialization and services activities. In addition, over this period, we plan to invest R$552 million, or 9%, in our transmission business. We have already contractually committed to part of these expenditures, particularly in generation projects. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments” and “Item 3. Key Information—3D. Risk Factors—Risks Relating to our Operations and the Brazilian Power Industry—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” for more information. 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.”

Expand and strengthen our commercialization. Free Consumers make up a significant segment of the electricity market in Brazil, representing more than 30% of the market. This percentage may increase in the future as a result of Ordinance No. 514/2018, issued by the MME on December 28, 2018, which lowers the requirements for being a Free Consumer of conventional energy, dropping the minimum contracted energy demand from 3.0 MW to 2.5 MW, effective as of July 1, 2019, and from 2.5 MW to 2.0 MW, effective as of January 1, 2020. Additionally, on December 12, 2019, through Ordinance No. 465, the MME announced the timeline to open the Free Market, thereby reducing the minimum contracted energy demand to 1.5 MW, effective as of January 1, 2021; from 1.5 MW to 1.0 MW, effective as of January 1, 2022; from 1.0 MW to 0.5 kW, effective as of January 1, 2023. This is expected to be followed by the publication of studies by ANEEL and the CCEE, by January 31, 2022, on the regulatory measures required to enable the Free Market to be opened for all consumers, including the creation of a new regulated energy trader, and on proposed opening schedule beginning on January 1, 2024. 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 the future may lead to substantial consolidation in the generation, transmission and, particularly, the distribution sectors. Over the last few years, we have successfully integrated RGE Sul (acquired from AES Guaíba II Empreendimentos Ltda. in 2016), exploring operational synergies with our neighboring legacy concession RGE, merged RGE and RGE Sul into one (RGE Sul, now operating under the name RGE), and also merged our smaller distribution subsidiaries into one (CPFL Santa Cruz) in order to benefit from a leaner corporate structure. Moreover, our expansion into the transmission business supports our distribution operations with added reliability and quality from the new Substations that we will put into operation.

Given our financial strength and managerial expertise, we believe that we are well-positioned to take advantage of this consolidation in the Brazilian electricity market. If promising assets are available on attractive terms, especially in areas where we already operate, we may make acquisitions that complement our existing operations and afford us and our consumers further opportunities to take advantage of economies of scale.

Strategy and management for sustainable development and social responsibility.We maintain a strategic focus on a low carbon business portfolio and have created and implemented our 2020-24 Sustainability Plan, or Sustainability Platform, which is structured based on three pillars, sustainable energy, smart solutions and shared value society, and three enablers, ethics, transparency and employee development & inclusion. The Sustainability Platform is our main management tool. It was created to strengthen our commitment to sustainable development and social responsibility and is aligned to the SDGs.

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. In this context, one of our main objectives is to promote the sustainable development of these communities through actions that contribute to the improvement of public policies and that foster inclusion, social development and networking, training and empowering each individual to face social challenges. In 2019, we invested R$39.4 million in projects that impacted approximately 320 thousand people, directly benefiting 121 municipalities in nine states, with 391 activities.

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 volume and the liquidity of our shares, seeking value for our shareholders.

Our Service Territory

Distribution

We are one of the largest electricity distributors in Brazil, based on the amount of electricity we delivered in 2019. Our four distribution subsidiaries together supply electricity to a region covering 300,411 square kilometers, primarily in the states of São Paulo and Rio Grande do Sul. Their concession areas include 687¹ municipalities and a population of 22.2 million people. Together, they provided electricity to 9.8 million consumers as of December 31, 2019. Effective as of January 1, 2019, RGE, one of our five distribution subsidiaries existing in 2018, was merged with and into RGE Sul, and RGE Sul began doing business under the name RGE. As a result ofthis merger and the related transfer of the assets of RGE to RGE Sul, RGE no longer exists and, as of January 1, 2019, we have four distribution subsidiaries. Our distribution subsidiaries distributed 14.3% of the total electricity distributed in Brazil in 2019, based on data from the EPE.

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

Distribution Companies

We have four distribution subsidiaries:

CPFL Paulista. CPFL Paulista supplies electricity to a concession area covering 90,486 square kilometers in the state of São Paulo with a population of 10.3 million people. Its concession area covers 234 municipalities, including the cities of Campinas, Bauru, Ribeirão Preto, São José do Rio Preto, Araraquara and Piracicaba. CPFL Paulista had 4.6 million consumers at December 31, 2019. In 2019, CPFL Paulista distributed 21,030 GWh of electricity. Considering CPFL Paulista’s sales in its concession area, including sales to Captive Consumers and TUSD, CPFL Paulista sold 31,369 GWh of electricity in 2019, accounting for 24.3%² of the total electricity distributed in the state of São Paulo and 6.6 % of the total electricity distributed in Brazil during the year.

CPFL Piratininga. Companhia Piratininga de Força e Luz, or CPFL Piratininga, supplies electricity to a concession area covering 6,954 square kilometers in the southern part of the state of São Paulo with a population of 3.9 million people. Its concession area covers 27 municipalities, including the cities of Santos, Sorocaba and Jundiaí. CPFL Piratininga had 1.8 million consumers at December 31, 2019. In 2019, CPFL Piratininga distributed 7,963 GWh of electricity. Considering CPFL Piratininga’s sales in its concession area, including sales to Captive Consumers and TUSD, CPFL Piratininga sold 14,058 GWh of electricity in 2019, accounting for 10.9%² of the total electricity distributed in the state of São Paulo and 3.0% of the total electricity distributed in Brazil during the year.

RGE. RGE supplies electricity to a concession area covering 182,722 square kilometers in the state of Rio Grande do Sul with a population of 6.9 million people. Its concession area covers 381 municipalities, including the cities of Canoas, São Leopoldo, Novo Hamburgo, Santa Maria, Uruguaiana, Caxias do Sul, Gravataí, Passo Fundo and Bento Gonçalves. RGE had 2.9 million consumers at December 31, 2019. In 2019, RGE distributed 14,573 GWh of electricity. Considering RGE’s sales in its concession area, including sales to Captive Consumers and TUSD, RGE sold 19,568 GWh of electricity in 2019, accounting for 70.9%² of the total electricity distributed in the state of Rio Grande do Sul and 4.1% of the total electricity distributed in Brazil during the year. As of January 1, 2019, RGE (previously named RGE Sul) is the surviving entity of its merger in December 2018 with our previous distribution company Rio Grande Energia S.A. See “—Overview” for more information regarding the merger.

CPFL Santa Cruz. CPFL Santa Cruz supplies electricity to a concession area covering 20,250 square kilometers, which includes 45 municipalities in the northwest part of the state of São Paulo, three municipalities in the state of Paraná and three municipalities in the state of Minas Gerais. In 2019, CPFL Santa Cruz distributed 2,333 GWh of electricity to 0.5 million consumers. Considering CPFL Santa Cruz’s sales in its concession area, including sales to Captive Consumers and TUSD, CPFL Santa Cruz sold 3,061 GWh of electricity in 2019, accounting for 2.3%² of the total electricity distributed in the state of São Paulo and 0.6% of the total electricity distributed in Brazil during the year.

Distribution Network

Our four 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, the 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).

2 Based on preliminary data as disclosed by the EPE on January 17, 2020. Final data is expected to be available in the second half of 2020.

At December 31, 2019, our Distribution Networks consisted of 329,370 kilometers of distribution lines, including 476,474 distribution transformers, and 12,856 km of High Voltage distribution lines between 34.5 kV and 138 kV. At that date, we had 525 transformer Substations for transforming High Voltage into Medium Voltages for subsequent distribution, with total transforming capacity of 18,743 mega-volt amperes. Of the industrial and commercial consumers in our concession area, 403 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

There are 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, billing errors and similar matters. Electricity loss rates of our distribution subsidiaries compare favorably to the average for other major Brazilian electricity distributors according to the most recent information available from ABRADEE, an industry association.

We are also actively engaged in efforts to reduce commercial losses from illegal connections, fraud or billing errors. To achieve this, in each of our four distribution subsidiaries, we have deployed trained technical teams to conduct inspections, enhanced monitoring for irregular consumption, increased replacements for obsolete measuring equipment and implemented a system to identify issues in internal processes that could generate losses (e.g., incorrect billing, lack of meter readings, meters with wrong parameters, among others). We conducted 567.4 thousand fraud inspections in the field during 2019, as a result of which we recovered around R$61.2 million in additional payments from consumers (retroactive billing relating to losses).

Power Outages

The following table sets forth the frequency and duration of electricity outages per consumer for the years ended December 31, 2019 and 2018 for each of our distribution subsidiaries:

	Year ended December 31, 2019
	CPFL Paulista	CPFL Piratininga	RGE⁽³⁾	CPFL Santa Cruz⁽⁴⁾
SAIFI⁽¹⁾	4.38	4.34	6.25	4.25
SAIDI⁽²⁾	6.72	6.48	14.01	5.56

______________________

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

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

(3) RGE merged into RGE Sul (which now operates under the name RGE) effective as of January 1, 2019. See “Item 4. Information on the Company—Overview”.

(4) CPFL Santa Cruz, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista merged into CPFL Santa Cruz (formerly CPFL Jaguari) effective as of January 1, 2018. See “Item 4. Information on the Company—Overview”.

	Year ended December 31, 2018
	CPFL Paulista	CPFL Piratininga	RGE⁽⁴⁾	RGE Sul⁽⁴⁾	CPFL Santa Cruz⁽³⁾
SAIFI⁽¹⁾	4.03	3.87	6.30	5.89	5.09
SAIDI⁽²⁾	6.17	5.92	13.43	15.56	6.01

______________________

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

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

(3) CPFL Santa Cruz, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista merged into CPFL Santa Cruz (formerly CPFL Jaguari) effective as of January 1, 2018. See “Item 4. Information on the Company—Overview”.

(4) RGE merged into RGE Sul (which now operates under the name RGE) effective as of January 1, 2019. See “Item 4. Information on the Company—Overview”.

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 2019, 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, CPFL Santa Cruz had its historically lowest SAIDI in 2019. CPFL Santa Cruz also had the lowest SAIDI and the second lowest SAIFI among Brazilian distribution companies in 2019. The duration and frequency of outages at CPFL Paulista and CPFL Piratininga are among the lowest in Brazil compared to companies of similar size. Although RGE’s duration of outages remains in line with the average rate for power companies in Southern Brazil, they are comparatively higher than those at CPFL Paulista and CPFL Piratininga, mainly as a result of logistical challenges in the region that specifically impact RGE’s SAIDI. CPFL Energia is focused on improving RGE’s SAIDI by continuously investing in technology and grid robustness. RGE’s SAIFI compares favorably to that of companies of similar size. Additionally, CPFL Energia has been conducting R&D projects aiming at demonstrating to ANEEL that the Southern Region of Brazil has unique operational characteristics that should be taken into account in future revisions of the regulatory framework by ANEEL.

ANEEL establishes performance indicators per consumer to be complied with by power companies. If these indicators are not reached, we are obligated to reimburse our consumers, and our revenues are negatively affected. In 2018 and 2019, according to data from ANEEL, the amount we reimbursed our consumers in the State of São Paulo remained lower than the average amount reimbursed by power companies of similar size. The amount RGE reimbursed consumers was slightly higher in 2019 than the average amount reimbursed by power companies of similar size in Brazil generally but it was in line with the average amount for power companies in the Southern Region of Brazil.

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 9.6% of total interruptions in 2019. Unscheduled interruptions due to accidents or natural causes, including lightning storms, fire and wind represented the remainder of our total interruptions. In 2019, we invested R$2,033 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; and (iii) customer service, among other things.

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

Purchases of Electricity

Most of the electricity we sell is purchased from unrelated parties, rather than generated by our facilities. In 2019, 11.6% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries (including our joint ventures).

In 2019, we purchased 11,021 GWh of electricity from the Itaipu Power Plant, amounting to 14.1% of the total electricity we purchased. Itaipu is located on the border of Brazil and Paraguay and is subject to a bilateral treaty between the two countries pursuant to which Brazil has committed to purchasing specified amounts of electricity. This treaty will expire in 2023. Electric utilities operating under concessions in the midwest, south and southeast regions of Brazil are required by law to purchase a portion of the electricity that Brazil is obligated to purchase from Itaipu. The amounts that these companies must purchase are governed by take-or-pay contracts withtariffs 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$27.87/kW. Our purchases represent 19.7% of Itaipu’s total supply to Brazil. This share was fixed by law according to the amount of electricity sold in 1991. The rates at which companies are required to purchase Itaipu’s electricity are established pursuant to the bilateral treaty and fixed to cover Itaipu’s operating expenses, payments of principal and interest on its U.S. dollar-denominated debts and the cost of transmitting the power to their concession areas.

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

In 2019, we paid an average of R$253.52 per MWh for purchases of electricity from Itaipu, compared with R$240.03 during 2018 and R$199.58 during 2017. These figures do not include the transmission fee.

We purchased 49,964 GWh of electricity in 2019 from generating companies other than Itaipu, representing 82% of the total electricity we purchased. We paid an average of R$237.61 per MWh for purchases of electricity from generating companies other than Itaipu, compared with R$227.30 per MWh in 2018 and R$191.88 per MWh in 2017. See “—The New Regulatory Framework—The Regulated Market” and “—The New Regulatory Framework—The Free Market” for more information on the Regulated Market and 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.

	2019	2018	2017
	GWh	GWh	GWh
Energy purchased for resale
Itaipu	11,021	11,117	11,779
Spot market/Proinfa Program	1,102	1,111⁽¹⁾	1,142⁽¹⁾
Energy purchased in the Regulated Market and through bilateral contracts	66,283	61,461⁽²⁾	65,053⁽²⁾
TOTAL	78,406	73,689	77,974

______________________

(1) Energy purchased for resale through the Proinfa Program only.

(2) Energy purchased for resale through the Regulated Market and bilateral contracts, as well as in the spot market.

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 auctions, for 100% of their forecast electricity needs and are only authorized to pass through the cost of up to 105% of this electricity to consumers, any involuntary quota to be purchased from generation companies whose concessions were renewed under Law 12,783/13 that takes a distributor’s energy volume to more than 105% of its forecast would lead to additional costs for the distributor. As a result, Normative Resolution No. 706 of March 29, 2016 provided that the costs resulting from involuntary purchase quotas can be passed on to consumers, and the energy volume can be offset from electricity auctions from existing power generation facilities in the following years. See “Item 3. Key Information—Risk Factors—Our operating results depend on prevailing hydrological conditions. Poor hydrological conditions may affect our results of operations” and “Item 3. Key Information—Risk Factors—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 purchaseor 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” for more information.

On June 10, 2018, ANEEL issued Normative Resolution No. 824/2018 establishing a new mechanism, called the Surplus Selling Mechanism, to allow the sale of surplus electricity purchased by distributors to Free and Special Consumers, generators and self-generators. The Surplus Selling Mechanism is voluntary for sellers and purchasers and is set to take place periodically several times per year through 12-month, 6-month and 3-month agreements, with settlement at the equilibrium price set for each submarket and energy type. In 2019, Surplus Selling Mechanisms were held on January 4, March 29, June 24-25 and September 24. We participated in the first two mechanisms. In 2019, ANEEL and CCEE began to evaluate improvements to the mechanism to predict for multiple bids for the same product, changes in tiebreaker procedures and new products for the 6 months between July and December 2019. These improvements, discussed in the context of Public Hearing No. 33/2019 and Public Consultation No. 34/2019 (Second Phase of Public Hearing No. 33/2019), were approved through ANEEL Normative Resolution No. 869/2020.

Transmission Tariffs. In 2019, we paid a total of R$2.464 million in tariffs for the use of the transmission network, including Basic Network tariffs, connection tariffs and transmission of high-voltage electricity from Itaipu at rates set by ANEEL.

Consumers and Tariffs

Consumers

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

·	*Industrial consumers.* Sales to final industrial consumers accounted for 16.5% of revenues from electricity sales in our distribution segment in 2019.
·	Residential consumers. Sales to final residential consumers accounted for 48.4% of our revenues from electricity sales in our distribution segment in 2019.
·	Commercial consumers. Sales to final commercial consumers, which include service businesses, universities and hospitals, accounted for 21.0% of our revenues from electricity sales in our distribution segment in 2019.
·	*Rural consumers.* Sales to final rural consumers accounted for 4.5% of our revenues from electricity sales in our distribution segment in 2019.
·	Other consumers. Sales to other consumers, which include public and municipal services such as street lighting, accounted for 9.6% of our revenue of electricity sales in our distribution segment in 2019.

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. See “—The Brazilian Power Industry” for a discussion of the regulatory regime applicable to our tariffs and their adjustment.

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

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

The following tables set forth our average retail prices for each consumer category for 2019 and 2018. These prices include taxes (ICMS, PIS and COFINS) and were calculated based on our revenues and the volume of electricity sold in 2019 and 2018.

	Year ended December 31, 2019
	CPFL Paulista	CPFL Piratininga	RGE⁽¹⁾⁽²⁾	RGE Sul⁽¹⁾	CPFL Santa Cruz⁽³⁾

Residential	702.33	744.71	860.73	-	704.68
Industrial	608.48	641.85	671.14	-	578.38
Commercial	656.58	680.27	848.56	-	668.44
Rural	411.09	463.59	471.62	-	437.15
Other	547.99	661.63	429.34	-	445.46
Average	641.21	702.08	694.22	-	591.94

	Year ended December 31, 2018
	CPFL Paulista	CPFL Piratininga	RGE⁽¹⁾⁽²⁾	RGE Sul⁽¹⁾	CPFL Santa Cruz⁽³⁾

Residential	639.65	673.63	820.70	757.09	666.20
Industrial	581.90	592.27	669.67	561.23	543.21
Commercial	611.34	624.76	812.30	730.86	632.51
Rural	362.50	420.49	365.84	386.52	403.56
Other	469.08	457.57	444.47	315.12	404.96
Average	583.47	620.97	665.83	572.79	555.37

______________________

(1)

On December 4, 2018, through the Resolution for Authorization No.7,499/2018, ANEEL approved our proposal to consolidate the concessions of our two distribution companies (RGE and RGE Sul), pursuant to Normative Resolution No. 716/2016. RGE merged into RGE Sul (which now operates under the name RGE) effective as of January 1, 2019. See “Item 4. Information on the Company—Overview” and"

(2)

Considers ten months of RGE before the consolidation of the concessions as described in item (1) above.

(3)

Under current regulations, residential consumers may be eligible to pay a reduced TSEE tariff. 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 chargeor 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.

Since the end of 2018, there has been a growing concern from the Brazilian government regarding the need for tariff reductions. Thus, on December 27, 2018, the Brazilian Government published Decree No. 9,642, which determined that, as of January 1, 2019, the discounts applied to rural and water, sewage and sanitation services consumers during their respective adjustments or ordinary tariff review procedures will be reduced at a rate of 20% per year over the initial value until terminated.

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 2019, tariff revenues for the use of our network by Free Consumers and Captive Consumers amounted to R$16,261 million. The average tariff for the use of our network was R$151.61/MWh and R$131.10/MWh in 2019 and 2018, respectively, including the TUSD we charge to other distributors connected to our Distribution Networks.

Billing Procedures

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

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

Customer Service

We strive to provide high-quality customer service to our distribution consumers. We provide customer service 24 hours a day, seven days a week. The requests are received using a variety of platforms such as call centers, our website, SMS and our smartphone application. In 2019, we responded to 91.2 million customer requests. We also provide customer service through our branch offices, which handled 9.1 million customer requests in 2019. The improvements we implemented on our digital channel (such as our IVR, website and app) has allowed us to reach 80% of our customer requests through digital channels, thereby reducing our customer service costs. In order to improve our customer experience, we created two new customer service channels in 2019: video service at our branches and chatbot. We have improved billing understanding through the “Learning about my bill” service. We send an SMS to customers who had a significant increase in their bill. The customer receives a link to a personalized digital service that compares their current invoice with their previous invoice and has inputs for the reasons for the increase. Customer service also reaches the customer in person as we dispatch our technicians to make any necessary repairs upon receiving a customer’s request.

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. See “—The Brazilian Power Industry—Generation Scaling Factor” for more information. 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 4,304 MW as of December 31, 2019. Most of the electricity we produce comes from our Hydroelectric Power Plants. We generated a total of 13,611 GWh in 2019, 10,648 GWh in 2018 and 10,137 GWh in 2017.

If less than the total Assured Energy is being generated (i.e., if the GSF is less than 1.0), hydroelectric companies must purchase energy in the spot market to cover the energy shortage and meet their Assured Energy volumes under 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 PPAs 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 PPA or the end of the concession, whichever occurs sooner. See “—The Brazilian Power Industry—Generation Scaling Factor” for more information on the GSF and Federal Law 13,204.

Conventional Generation

Hydroelectric Power Plants

At December 31, 2019, 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 4.15% (59.93% of 6.93%) interest in the Assured Energy from the Luis Eduardo Magalhães Power Plant.

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

Serra da Mesa. Our largest Hydroelectric Facility in operation is the Serra da Mesa facility, which we acquired in 2001 from ESC Energia S.A. (formerly VBC), one of our shareholders. Furnas began construction of the Serra da Mesa facility in 1985. In 1994, construction was suspended due to a lack of resources, which led to a public bidding procedure in order to resume construction. Serra da Mesa currently consists of three generation units 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/FGV index. This contract expires in 2028. Our share of the Installed Capacity and Assured Energy of the Serra da Mesa facility is 657 MW and 2,879 GWh/year, respectively. On May 30, 2014, the concession held by Furnas was formally extended to November 12,2039. In 2016, due to the renegotiated GSF, the Serra da Mesa concession was extended to September 30, 2040, in accordance with ANEEL’s Authoritative Resolution No. 6,055/2016.

CERAN Hydroelectric Complex. We own a 65.0% interest in CERAN, a subsidiary that was granted a 35-year concession in March 2001 to construct, finance and operate the CERAN hydroelectric complex. The other shareholders are CEEE (with 30.0%) and Desenvix (with 5.0%). The CERAN hydroelectric complex consists of three Hydroelectric Power Plants: Monte Claro, Castro Alves and 14 de Julho. The CERAN hydroelectric complex is located on the Antas River 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 1,449 GWh per year, of which our share is 942 GWh/year. We sell our participation in the Assured Energy of this complex to affiliates in our group. These facilities are operated by CERAN, under CPFL Geração’s supervision.

Monte Claro. Monte Claro’s first generating unit, which became operational in 2004, has an Installed Capacity of 65 MW and the second generating unit, which became operational in 2006, also has an Installed Capacity of 65 MW, giving total Installed Capacity of 130 MW and Assured Energy of 491.5 GWh per year.

Castro Alves. In March 2008, the first generation unit of the Castro Alves Power Plant became operational, with total Installed Capacity of 43.4 MW. In April 2008, the second generation unit became operational, with Installed Capacity of 43.4 MW. In June 2008, this plant became fully operational (when the third generation unit started operations), giving total Installed Capacity of 130 MW and annual Assured Energy of 541.4 GWh per year.

14 de Julho. The first generation unit of the 14 de Julho Power Plant became operational in December 2008, and the second generation unit became fully operational in March 2009. This plant has a total Installed Capacity of 100 MW and an annual Assured Energy of 416.1 GWh.

We are currently assessing alternative measures in order to improve our financial and operational results. Discussions are currently underway with ANEEL and other entities in the transmission sector, regarding the conditions under which we will transfer the Monte Claro Substation to the Basic Network, which could eliminate maintenance costs and our 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 3,266 GWh per year. CPFL Geração owns a 25.01% interest in this plant. The other shareholders of the joint venture are Alcoa (42.18%), CBA (Companhia Brasileira de Alumínio) (15.0%), DME (Departamento Municipal de Eletricidade de Poços de Caldas) (8.82%), andCamargo Corrêa Cimentos S.A. (9.0%). We sell our participation in the Assured Energy of this facility to affiliates in our group.

Campos Novos. We own a 48.72% interest in ENERCAN, a joint venture formed by a consortium of private and public sector companies that was granted a 35-year concession in May 2000 to construct, finance and operate the Campos Novos Hydroelectric Facility. The plant was constructed on the Canoas River in the state of Santa Catarina, and became fully operational in May 2007 with a total Installed Capacity of 880 MW and Assured Energy of 3,327 GWh per year, of which our interest is 1,621 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 3,743 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 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 theBasic 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 4.15% (59.93% of 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 4,425 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 two 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 341.7 MW and total Assured Energy of 2,170 GWh per year. On December 31, 2019, 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. In 2018, ANEEL passed Resolution No. 822/2018, allowing thermoelectric power plants to perform, and be compensated for, the recovery of system operational reserves for frequency control as an ancillary service. Thus, since October 2018, every week, thermoelectric power plants can offer prices up to 130% of their current dispatch cost and ONS schedules the dispatch considering the lowest cost for the electrical system. Resolution No. 822/2018 represents recognition by ANEEL of the additional expenses incurred by thermoelectric power plants in order to respond to ONS’s intermittent dispatches due to the variation in energy generation by wind farms in connection with operative restraints on hydropower plants. The 30% increase in price over the power plants’ operational cost is being tested by ANEEL while the agency examines the prices offered by Thermoelectric Power Plants, and is intended to allow for compensation for the maintenance and fuel consumption arising from the power plants’ need to start and stop operations at various times throughout any particular week. Before Resolution No. 822/2018, such additional costs were borne by the thermoelectric power plants for purposes of providing an ancillary service to customers for frequency control. Our EPASA complex has chosen to perform such ancillary service, resulting in additional revenues of R$176 million in 2019.

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 CCC Account. In response to our termination application, on August 14, 2019, MME published Order No. 315/2019, which terminated the Carioba concession, without reversal of assets. Its concession agreement was declared null trough Dispatch No.039/2019-SCG/ANEEL. Since 2016, we have ceased to include Carioba in our installed capacity since the facility is inactive.

Small Hydroelectric Power Plants

At December 31, 2019, 10 of our 48 Small Hydroelectric Power Plants were under the management of two of our conventional generation subsidiaries, CPFL Geração and CPFL Centrais Geradoras. These 10 Small Hydroelectric Power Plants reported their results within the conventional generation segment. They consist of two groups of facilities:

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

	During 2014, the concessions for the Salto do Pinhal and Ponte do Silva facilities were terminated under Authorizing Resolution No. 4,559/2014, which determined that concessions for inactive Micro Hydroelectric Power Plants would be extinguished without reversion of the respective assets to the government.
·	The remaining facility, Cariobinha, has been held by CPFL Geração since the signing of the concession contract. Since 2016, we have ceased to include Cariobinha in our Installed Capacity and Assured Energy data since the facility is inactive. We also applied to terminate the Cariobinha concession. In response to our termination application, on July 17, 2018, MME published Order No. 304/2018, which terminated the Cariobinha concession, without reversal of assets. In September 2019, SCG/ANEEL published Dispatch No. 039/2019, which declared the Cariobinha concession agreement null. Pursuant to the local law which allowed us to include Cariobinha in our generation assets, we are arranging to return Cariobinha’s facility to the municipality of Americana, where it is installed.

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

(i)	The energy generated must be sold to all distribution companies in Brazil according to quotas defined by ANEEL (previously, energy was sold only to the related distribution subsidiary);
(ii)	The concessionaire’s annual revenue is set by ANEEL, subject to tariff reviews (previously, the energy prices were defined contractually and adjusted according to the IPCA); and
(iii)	The assets that remained unamortized at the renewal date would be indemnified, and the indemnification payment would not be considered as annual revenue. The remuneration relating to new assets or existing assets that were not indemnified would be considered as annual revenue. Rio do Peixe I and II received a total of R$34.4 million in indemnification payments. The assets of Macaco Branco had been fully amortized, and therefore generated no indemnification payment.

The following table sets forth certain information relating to our principal conventional generation facilities in operation and the Small Hydroelectric Power Plants that reported their results within the conventional generation segment as of December 31, 2019:

	Holding company	Share ownership	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	2,878.6	5,585.1	1998	2039⁽¹⁾
Monte Claro	CPFL Geração	65.00%	84.5	130.0	319.5	491.5	2004	2036
Barra Grande	CPFL Geração	25.01%	172.5	690.0	816.7	3,266.1	2005	2036
Campos Novos	CPFL Geração	48.72%	428.8	880.0	1,620.8	3,326.6	2007	2035
Castro Alves	CPFL Geração	65.00%	84.5	130.0	351.9	541.4	2008	2036
14 de Julho	CPFL Geração	65.00%	65.0	100.0	270.5	416.1	2008	2036
Luis Eduardo Magalhães	CPFL Jaguari de Geração	4.15%	37.5	902.5	183.8	4,425.2	2001	2032
Foz do Chapecó	Chapecoense	51.00%	436.1	855.0	1,908.8	3,742.7	2010	2036
SUBTOTAL – Hydroelectric plants			1,966.0		8,350.6
Thermoelectric plants:
EPASA facilities:
Termonordeste	CPFL Geração	53.34%	91.1	170.9	578.5	1,084.6	2010	2042
Termoparaíba	CPFL Geração	53.34%	91.1	170.9	579.0	1,085.5	2011	2042
SUBTOTAL – Thermoelectric plants			182.3		1,157.5
Small Hydroelectric Plants
Lavrinha	CPFL Centrais Geradoras	100%	0.3	0.3	2.1	2.1	N/A	⁽²⁾
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	⁽²⁾
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	⁽²⁾
São José	CPFL Centrais Geradoras	100%	0.8	0.8	2.1	2.1	N/A	⁽²⁾
São Sebastião	CPFL Centrais Geradoras	100%	0.7	0.7	4.6	4.6	N/A	⁽²⁾
Turvinho	CPFL Centrais Geradoras	100%	0.8	0.8	2.2	2.2	N/A	⁽²⁾
SUBTOTAL – Small Hydroelectric Plants			24.3		84.1
TOTAL – Conventional Generation			2,172.6		9,592.2

______________________

(1) The concession for Serra da Mesa is held by Furnas. On May 30, 2014, the concession held by Furnas was formally extended to November 12, 2039. In 2016, due to the renegotiated GSF, the Serra da Mesa concession was extended to September 30, 2040, in accordance with ANEEL’s Authoritative Resolution No. 6,055/2016. We have a contractual right to 51.54% of the Assured Energy of this facility, under a 30-year agreement.

(2) 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.

Renewable Generation

At December 31, 2019, we owned a 99.94% interest in CPFL Renováveis, a company resulting from an association with another Brazilian renewable energy producer, ERSA – Energias Renováveis S.A., 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%. On November 29, 2018, State Grid acquired 243,771,824 common shares of CPFL Renováveis through a mandatory tender offer that State Grid was required to carry out upon gaining control of our company in accordance with applicable Brazilian law. As a result of this mandatory tender offer, State Grid and us, indirectly through our subsidiary CPFL Geração and CPFL Energia, held 99.94% of CPFL Renováveis’ total capital stock.

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.

23 subsidiaries involved in the generation of electric energy through 41 Small Hydroelectric Power Plants, consisting of (i) 40 SHPPs that are operational, with aggregate Installed Capacity of 453.1 MW, located in the states of São Paulo, Santa Catarina, Rio Grande do Sul, Paraná, Minas Gerais and Mato Grosso, and (ii) one SHPP, SHPP Lucia Cherobim, with 28 MW of Installed Capacity, which is under construction and scheduled to commence operations by 2024.

43 subsidiaries involved in the generation of electric energy from wind sources. 49 wind farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, consisting of (i) 45 wind farms that are operational, with an aggregate Installed Capacity of 1,308.6 MW, and (ii) four wind farms (Gameleira, Figueira Branca, Farol de Touros and Costa das Dunas), with an aggregate Installed Capacity of 69.3 MW, which are under construction and scheduled to commence operations by 2024.

Eight subsidiaries involved in the generation of electric energy from biomass, all of which are operational, with total Installed Capacity of 370 MW, located in the states of Minas Gerais, Paraná, São Paulo and Rio Grande do Norte.

One subsidiary involved in the generation of electric energy from a Solar Power Plant, Tanquinho, which is located in the state of São Paulo and has total Installed Capacity of 1.1 MW. Tanquinho started operations on November 27, 2012 and has the capacity to generate 1.7 GWh/year.

Existing Installed Capacity

The following describes our existing and operational renewable generation plants:

Small Hydroelectric Power Plants

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

CPFL Renováveis operates 40 of our 48 Small Hydroelectric Power Plants primarily under the concession and authorization regime, all located in the states 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 the power plants allows us to carry out control, supervision and operations remotely. Since CPFL Energia acquired CPFL Renováveis’ renewable business, we have established an operational center for the management and monitoring of our power plants in Jundiaí, in the state of São Paulo. Regarding the remote control, supervision and operation of the wind energy assets, we have also established a remote control center in Fortaleza, in the state of Ceará.

Biomass Thermoelectric Power Plants

Biomass-fueled Thermoelectric Power 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 Power 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 Power 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 Power Plant is generally more complex, as it involves the acquisition, logistics and production of organic inputs used for power generation. For this reason, the operational costs of Biomass-fueled Thermoelectric Power Plants tend to be higher than the operational costs of Small Hydroelectric Power Plants.

Despite being more complex, Biomass-fueled Thermoelectric Power 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 Power 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 established by the Paris Agreement (Mecanismo de Desenvolvimento Sustentável), yet to be regulated, and have the potential to generate carbon credits, Biomass-fueled Thermoelectric Power 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 Power Plants under the authorization regime, located in the states of São Paulo, Minas Gerais, Rio Grande do Norte and Paraná.

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 163.8 GWh. This project has an associated PPA in force until 2032 with CPFL Brasil.

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, which became operational in August 2010. This co-generation plant has total Installed Capacity of 45 MW. The plant has an Assured Energy of 91.1 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. 11 MWavg of energy were sold in the A-5 auction (see “—The New Regulatory Framework—Auctions on the Regulated Market”), with CCEARs in force until 2025.

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

CPFL Bio Ester. In October 2012, CPFL Renováveis completed the acquisition of the electricity 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 MWavg 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 energy produced is sold on the free market for 21 years.

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

CPFL Bio Pedra. In March 2010, CPFL Bio Pedra, which we formed to develop electric energy generation projects using sugarcane bagasse, executed a partnership agreement with Grupo Pedra Agroindustrial to develop new biomass generation projects. 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 209.4 GWh. The electricity from CPFL Bio Pedra has been sold through an auction held in 2010, with CCEARs in force until 2027.

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.

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 MW. We expect Tanquinho to generate 1.7 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 Brazilian Wind Power Association (ABEEólica – Associação Brasileira de Energia Eólica) indicate a wind energy potential of 500 GW in Brazil, a volume that greatly exceeds the country’s current total Installed Capacity of 15.4 GW as of December 2019 according to ANEEL, signaling a high growth potential in this segment. Wind farms are also eligible for MDL and have the potential to generate carbon credits for sale.

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

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 449.4 GWh. The electricity from these wind farms has been sold through an alternative energy auction held in 2010, or the 2010 Alternative Sources Auction, with CCEARs in force until 2033. The Atlântica complex commenced operations in March 2014.

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.

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.

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.

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.

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.

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.

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 145.2 MW and aggregate Assured Energy of 68.6 MWavg. The Morro dos Ventos complex sold its energy through the 2009 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 29.2 MW and aggregate Assured Energy of 15.4 MWavg. This wind farm commenced operations in April 2015.

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.

Pedra Cheirosa. The Pedra Cheirosa complex, located in the state of Ceará, consists of the Pedra Cheirosa I and Pedra Cheirosa II Wind Farms, which have an aggregate Installed Capacity of 48.3 MW and aggregate Assured Energy of 27.5 MWavg. This wind farm commenced operations in June 2017.

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.

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.

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.

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 Úrsulawind 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.

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.

The following table sets forth certain information relating to our principal renewable facilities, held by CPFL Renováveis (99.94% our share) in operation as of December 31, 2019:

	Capacity (MW)		Assured Energy (GWh)		Placed in service	Facility upgraded	Concession expires
	Our share	TOTAL	Our share	TOTAL
Small Hydroelectric plants:
Alto Irani	21.0	21.0	108.2	108.3	2008		2032
Americana	30.0	30.0	51.5	51.5	1949	2001	2027
Andorinhas	0.5	0.5	3.7	3.7	1941		⁽²⁾
Arvoredo	13.0	13.0	64.6	64.6	2010		2032
Barra da Paciência	23.0	23.0	130.4	130.4	2011		2029
Boa Vista 2	29.9	29.9	136.1	136.1	2018		2055
Buritis	0.8	0.8	3.1	3.1	1922	2016	2027⁽¹⁾
Capão Preto	4.3	4.3	19.0	19.0	1911	2007	2027
Chibarro	2.6	2.6	13.4	13.4	1912	2007	2027
Cocais Grande	10.0	10.0	40.4	40.4	2009		2029
Corrente Grande	14.0	14.0	74.7	74.7	2011		2030
Diamante	4.2	4.2	14.0	14.0	2005		2019
Dourados	10.8	10.8	49.8	49.8	1926	2013	2027
Eloy Chaves	19.0	19.0	96.4	96.4	1954	2013	2027
Esmeril	5.0	5.0	25.2	25.2	1912	2015	2027
Figueiropolis	19.4	19.4	110.3	110.4	2010		2034
Gavião Peixoto	4.8	4.8	31.8	31.8	1913	2007	2027
Guaporé	0.7	0.7	3.5	3.5	1950		⁽²⁾
Jaguari	11.8	11.8	39.4	39.4	1917	2001	2027
Lençóis	1.7	1.7	9.1	9.1	1917	2001	2027
Ludesa	30.0	30.0	111.4	185.7	2007		2032
Mata Velha	24.0	24.0	114.7	114.8	2016
Monjolinho	0.6	0.6	1.0	1.0	1893	2003	2027⁽²⁾
Ninho da Águia	10.0	10.0	56.9	56.9	2011		2029
Novo Horizonte	23.0	23.0	91.1	91.1	2011		2032
Paiol	20.0	20.0	91.7	91.7	2010		2032
Pinhal	6.8	6.8	32.4	32.4	1928	2014	2027
Pirapó	0.8	0.8	5.1	5.1	1952		⁽²⁾
Plano Alto	16.0	16.0	81.0	81.0	2008		2032
Saltinho	0.8	0.8	6.4	6.4	1950		⁽²⁾
Salto Góes	20.0	20.0	97.2	97.2	2012		2040
Salto Grande	4.5	4.6	22.6	22.6	1912	2002	2027
Santa Luzia	28.5	28.5	161.3	161.4	2011		2037
Santana	4.3	4.3	22.9	22.9	1951	2015	2027
São Gonçalo	11.0	11.0	63.2	63.2	2010		2030
São Joaquim	8.0	8.1	44.4	44.4	1911	2014	2027
Socorro	1.0	1.0	2.7	2.7	1909	2001	2027⁽¹⁾
Três Saltos	0.6	0.6	3.8	3.8	1928	2018	2027⁽¹⁾
Varginha	9.0	9.0	47.2	47.2	2010		2029
Várzea Alegre	7.5	7.5	42.7	42.7	2011		2029
SUBTOTAL – Small Hydroelectric Power Plants (our share)	452.8	453.1	2,198.2	2,199.5

Biomass Thermoelectric Power Plants:
Baldin (CPFL Bioenergia)	45.0	45.0	45.5	91.1	2010		2039
Bio Alvorada	50.0	50.0	163.7	163.8	2013		2042
Bio Buriti	50.0	50.0	184.2	187.5	2011		2040
Bio Coopcana	50.0	50.0	157.6	157.7	2013		2042

	Capacity (MW)		Assured Energy (GWh)		Placed in service	Facility upgraded	Concession expires
	Our share	TOTAL	Our share	TOTAL
Bio Ester	40.0	40.0	98.9	99.0	2010		2029
Bio Formosa	40.0	40.0	20.1	20.2	2011		2032
Bio Ipê	25.0	25.0	71.7	131.4	2012		2040
Bio Pedra	70.0	70.0	209.3	209.4	2012		2046
SUBTOTAL – Biomass Thermoelectric Power Plants (our share)	369.8	370.0	1,059.5	1,060.1

Wind farm plants
Atlântica I	30.0	30.0	114.7	114.8	2014		2046
Atlântica II	30.0	30.0	112.9	113.0	2014		2046
Atlântica IV	30.0	30.0	113.8	113.9	2014		2046
Atlântica V	30.0	30.0	107.7	107.8	2014		2046
Bons Ventos	50.0	50.0	143.3	143.4	2010		2033
Campo dos Ventos I	25.2	25.2	119.1	119.1	2016		2046
Campo dos Ventos II	30.0	30.0	131.3	131.4	2013		2046
Campo dos Ventos III	25.2	25.2	117.3	117.4	2016		2046
Campo dos Ventos V	25.2	25.2	114.7	114.8	2016		2046
Canoa Quebrada	57.0	57.0	210.8	211.1	2010		2032
Canoa Quebrada (Rosa dos Ventos)	10.5	10.5	29.0	29.0	2014		2032
Costa Branca	20.7	20.7	85.8	85.9	2014		2046
Enacel	31.5	31.5	89.6	89.6	2010		2032
Eurus I	30.0	30.0	135.7	135.8	2014		2046
Eurus III	30.0	30.0	141.0	141.1	2014		2046
Eurus VI	8.0	8.0	27.7	27.7	2011		2045
Foz do Rio Choró	25.2	25.2	64.6	64.6	2009		2032
Icaraizinho	54.6	54.6	193.3	193.4	2009		2032
Juremas	16.1	16.1	66.5	66.6	2014		2046
Lagoa do Mato	3.2	3.2	12.6	12.6	2014		2032
Macacos	20.7	20.7	85.8	85.9	2014		2046
Morro dos Ventos I	28.8	28.8	118.9	119.0	2014		2045
Morro dos Ventos III	28.8	28.8	121.8	121.9	2014		2045
Morro dos Ventos IV	28.8	28.8	120.3	120.4	2014		2045
Morro dos Ventos VI	28.8	28.8	114.7	114.8	2014		2045
Morro dos Ventos IX	30.0	30.0	125.3	125.4	2014		2045
Morro dos Ventos II	29.2	29.2	134.8	134.9	2015		2047
Paracuru	25.2	25.2	110.1	110.2	2008		2032
Pedra Cheirosa	48.3	48.3	240.8	240.9	2017		2049
Pedra Preta	20.7	20.7	90.2	90.2	2014		2046
Praia Formosa	104.9	105.0	252.5	252.6	2009		2032
Santa Clara I	30.0	30.0	120.0	120.1	2011		2045
Santa Clara II	30.0	30.0	111.7	111.8	2011		2045
Santa Clara III	30.0	30.0	109.5	109.6	2011		2045
Santa Clara IV	30.0	30.0	107.8	107.8	2011		2045
Santa Clara V	30.0	30.0	108.7	108.7	2011		2045
Santa Clara VI	30.0	30.0	107.6	107.7	2011		2045
São Domingos	25.2	25.2	⁽³⁾	⁽³⁾	2016		2032
Taiba	16.5	16.5	58.7	58.8	2008		2032
Ventos de São Benedito	29.4	29.4	⁽³⁾	⁽³⁾	2016		2032
Ventos de Santo Dimas	29.4	29.4	⁽³⁾	⁽³⁾	2016		2032
Ventos de São Martinho	14.7	14.7	⁽³⁾	⁽³⁾	2016		2032
Ventos de Santa Mônica	29.4	29.4	⁽³⁾	⁽³⁾	2016		2032
Ventos de Santa Úrsula	27.3	27.3	⁽³⁾	⁽³⁾	2016		2032
SUBTOTAL – Wind farms (our share)	1,307.8	1,308.6	4,370.7	4,373.4

Solar Power Plant
Tanquinho	1.1	1.1	1.7	1.7	2012		-
SUBTOTAL – Solar Power Plant (our share)	1.1	1.1	1.7	1.7
TOTAL (our share only)	2,131.5	2,132.7	7,630.1	7,634.6

______________________

(1) Hydroelectric projects with installed capacity equal to or less than 1,000 kW that have a concession contract. The legislation for SHPPs with installed capacity less than 5,000 kW has changed and currently only a Registration is required. The concession contracts are valid until the concession expires and will be automatically converted into the Registration regime after the concession’s expiration.

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

(3) Projects that had no Assured Energy figure through December 31, 2019.

Expansion of Installed Capacity

Consumption of electricity in Brazil increased 1.4% in 2019, reaching 482,085 GWh, as was expected by the EPE. To address this increase in demand and to improve our margins, we continue to expand our Installed Capacity in renewable generation.

Plants under development	Estimated Installed Capacity	Estimated Assured Energy	Start of Construction	Expected Start of Operations	Our Ownership	Estimated Installed Capacity Available to us	Estimated Assured Energy Available to us
	(MW)	(GWh/yr)			(%)	(MW)	(GWh/yr)
Cherobim Small Hydro Power Plant(one company)	28	145.2	-	2024	99.94	28.0	145.1
Gameleira Wind Complex	81.7	345.2	-	2024	99.94	81.7	345.0
TOTAL	109.7	490.4	-	-	-	109.7	490.1

SHPP Lucia Cherobim. SHPP Lucia Cherobim is located in the state of Paraná and is expected to commence operations in 2024. It is expected to have an aggregate Installed Capacity of 28 MW and aggregate Assured Energy of 145.2 GWh/year. In August 2018, in the A-6/2018 Energy Auction, SHPP Lucia Cherobim sold 16.5 MWavg at the auction price of R$189.95/MWh, with annual adjustments by the IPCA index to the auction ceiling price of R$290.00/MWh. For more information on the A-6/2018 Auction, see “Item 4. Information on the Company—Overview.”

Gameleira Wind Complex. Gameleira wind complex is located in the state of Rio Grande do Norte and is expected to commence operations in 2024. It is expected to have an aggregate Installed Capacity of 81.7 MW and aggregate Assured Energy of 345.2 GWh/year. In August 2018, in the A-6/2018 Energy Auction, the Gameleira wind complex sold 12.0 MWavg of the energy to be generated by it at the auction price of R$89.89/MWh, with annual adjustments by the IPCA index to the auction ceiling price of R$227.00/MWh. Additionally, the Gameleira wind complex sold its remaining energy in the Free Market. For more information on the A-6/2018 Auction, see “Item 4. Information on the Company—Overview.”

Energy Commercialization

We carry out electricity commercialization activities mainly through our subsidiary CPFL Brasil. The key areas of this activity are:

·	procuring electricity for commercialization activities by entering into bilateral contracts with energy companies (including our generation subsidiaries and third parties) and purchasing electricity in public auctions;
·	reselling electricity to Free Consumers and/or other players in the market;
·	reselling electricity to distribution companies (including CPFL Paulista, CPFL Piratininga and RGE) and other agents in the electricity market through bilateral contracts; and

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

As a retailer trade company CPFL Brasil is also responsible for the energy load of Free and Special Consumers, centralizing the management of contracts and the relationship with the CCEE. In this case, the companies do not need to be CCEE members, which simplifies the process. The focus of CPFL Brasil’s activities in retail market are potentially Free Consumers, such as retail chains, banks, supermarkets, universities, among others.

The rates at which CPFL Brasil purchases and sells electricity in the Free Market are determined by bilateral negotiations with its suppliers and consumers.

Services

Through CPFL Serviços, CPFL Atende, CPFL Total, CPFL Eficiência, CPFL Infra, CPFL Supre, CPFL Finanças and CPFL Pessoas, we offer our consumers a wide range of electricity-related services. These services are designed to help consumers improve the efficiency, cost and reliability of the electric equipment they use. Our main electricity-related services include:

·	Transmission networks: CPFL Serviços offers energy solutions in transmission assets of up to 138 kV, plans and drafts the civil, electrical and electromechanical projects, carries out material and equipment logistics, constructs transmission lines and Substations and, additionally, carries out the preventive and corrective maintenance of these assets afterwards in consideration of each consumer’s needs and growth expectations and in accordance with rigorous safety criteria, aiming for an optimal use of resources.
·	Distribution Networks: CPFL Serviços plans, constructs and performs maintenance on electric energy distribution system networks of up to 34.5 kV, including above and underground electricity grids, medium-voltage Substations and transformers and lighting solutions. It has significant experience in the market and familiarity with the various technical standards applicable in different regions of Brazil. As a result, it is able to bring quality and technologically-advanced energy solutions.
·	Self-production networks and energy-efficiency programs: The self-production networks, formerly offered by CPFL Serviços, consist of electric energy production alternatives. They ensure supply of energy to consumers, diversify inputs and reduce costs. It offers diesel and natural gas generators that operate mainly as a back-up energy source, and in peak periods, which reduce our customers’ electricity costs. Its natural gas co-generation activities include the simultaneous and sequential production of electricity and heat using a single fuel type. It also offers solutions in acclimatization and energy-efficiency projects as well as distributed generation of solar energy. After October 2014, all self-production activities were transferred to CPFL Eficiência, adding self-production to its services portfolio, which also includes services relating to cooling, cogeneration, motive power and lighting for the creation of customized solutions, promoting savings, sustainability and power security.

CPFL Eficiência also offers distributed generation services, through CPFL Geraçção Distribuída de Energia Ltda., a source of generation that injects power directly into the local distribution grid. This kind of generation reduces the use of the transmission system and requires less generation of centralized power plants, benefiting the consumer and the electricity sector as a whole. One such service is our solar photovoltaic systems (solar panels), which are offered through our Envo business line (created in 2017 to broaden the scope of services we offer to our customers, and its activities are directed at residential and smaller commercial customers), that enable customers to generate their own energy. The solar panels generate power whenever exposed to light, even on cloudy days. The power that is generated is injected into the grid and recorded as a credit by the energy distributor, which is then automatically discounted in the customer’s conventional electricity bill. The activities of our Envo business line expand to the state of São Paulo, including cities that are not within our concession area. In 2019, Envo provided services in connection with the construction of the Americana Solar Power Plant (Usina Solar Americana). In particular, Envoassisted in preparing the plans for the power plant, furnished and installed the solar photovoltaic systems (solar panels) and assisted in securing the power plant’s access to the local distribution grid. The Americana Solar Power Plant has 3,320 generator units, 1.12 MW of power and annual generation capacity of 1,771 MWh, enough to supply electricity to 738 residences with average consumption of 200 KWh/month during the period.

·	Equipment recovery: CPFL Serviços has its own framework for reverse logistics operation, which is responsible for the collection and disposal of all unusable material from the electricity grid. The reverse logistics operation has experience renovating up to 34 kV electrical equipment to restore efficiency. Its familiarity with retrofitting equipment also allows it to produce distribution transformers. The retrofitting equipment is ISO 9001 and ISO 14001 certified and has the Inmetro quality certification seal for the process of renovating distribution transformers. Currently, CPFL Serviços has an insulating oil regeneration park, as well as a laboratory with the ability to perform all current tests according to Brazilian technical standards. It also produces and manufactures measuring panels as well as panels for protection and control networks.
·	CPFL Atende: CPFL Atende is a contact center and customer relationship company, created to provide services both for companies within our group and for other companies. Among these services are face-to-face service, back office services, credit recovery, toll free customer support, ombudsman services, service desks and sales.
·	CPFL Total: CPFL Total provides the “Serviço em Conta,” which enables us to charge business customers for additional products and services through their electricity bills. Operations related to the collections and onlending activities offering bill payment services were discontinued as of 2016.
·	CPFL Infra: CPFL Infra provides asset management services, such as services with respect to car fleets, real estate and administrative functions and building maintenance and security.
·	CPFL Supre: CPFL Supre provides planning and logistics and supply chain management services. Theses services include purchasing, materials coordination, distribution and logistics.
·	CPFL Finanças: CPFL Finanças provides financial organization and operating services to support our businesses’ decision making. These services include accounting, budget, billings and payments.
·	CPFL Pessoas: CPFL Pessoas provides human resources and people management services. These services include payroll, benefits, third party management and recruiting, selecting and hiring employees.

Competition

We face competition from other generation and commercialization companies in the sale of electricity to Free Consumers. Distribution and transmission companies are required to permit the use of their lines and ancillary facilities for the distribution and transmission of electricity by other parties upon payment of a tariff.

Brazilian law and our concession agreements provide that all of our distribution and hydroelectric concessions or authorizations can be renewed once with approval from the MME or ANEEL as the granting authority, provided that the concessionaire so requests and that certain requirements related to the rendering of public services or hydropower exploitation are met. See “Item 3. Key Information—Risk Factors—We are uncertain as to the renewal of our concessions and authorizations” for more information. We intend to apply for the extension of each concession upon its expiration. We may face significant competition from third parties in bidding for renewal of such concessions or for any new concessions. The Brazilian government has absolute discretion over whether to renew existing concessions, and the acquisition of certain concessions by competing investors could adversely affect our results of operations. Furthermore, there can be no assurance as to whether the renewal of a certain concession will be granted on the same grounds as the current relevant concession.

In addition, under applicable legislation, other distributors cannot distribute energy in our concession area. As such, customers located in the respective region can only acquire energy from us, with the exception of consumers who become Free Consumers, who can acquire energy directly in the Free Market.

Our Concessions and Authorizations

Hydroelectric generation projects in Brazil are subject to three types of contractual framework, depending on their generation capacity:

·	Pursuant to Law No. 9,074/1995 (as amended by Law No. 13,360/2016), only hydroelectric generation projects with a capacity greater than 50,000 kW are now implemented through concessions granted by ANEEL following a public bidding process (which leads to the execution of a concession agreement). Requests to renew these concessions are examined by ANEEL on a case-by-case basis, according to the terms of the agreement, the public bidding note and regulations applicable at the time of the request for renewal. ANEEL has the power to deny a request to extend a concession period.
·	Hydroelectric Power Plants with capacity greater than 5,000 kW but equal to or lower than 50,000 kW (Small Hydroelectric Power Plants) now only require regulatory authorization from ANEEL, as opposed to a concession. Authorizations are renewable at the discretion of ANEEL on a case-by-case basis. ANEEL must provide justification for its decisions and any renewal must foster the public interest.
·	Hydroelectric Power Plants with capacity equal to or less than 5,000 kW (micro Hydroelectric Power Plants) only require registration with ANEEL rather than a concession agreement or an authorization. Under previously applicable regulations, certain micro Hydroelectric Power Plants were granted as concessions, and those concessions will remain valid until the end of their respective terms, and such micro Hydroelectric Power Plants will subsequently be subject to registration.

Other generation projects such as wind farms, solar and Thermoelectric Power Plants are implemented through an authorization from ANEEL, without a public bid or concession. The only exceptions are Thermoelectric Power Plants with a capacity greater than 50,000 kW and which have been designated as a service in the public interest: these projects are also subject to public bidding and concession procedures, similar to hydroelectric projects with a capacity greater than 50,000 kW mentioned above.

See “—Concessions and Authorizations—Concessions” for more information about concessions and authorizations.

Concessions

We operate under concessions granted by the Brazilian government through ANEEL for our generation, transmission and distribution businesses. We have the following concessions with respect to our distribution, transmission and generation business:

Distribution and Transmission

Concession no.	Concessionaire	State	Term
Distribution
014/1997	CPFL Paulista	São Paulo	30 years from November 1997
09/2002	CPFL Piratininga	São Paulo	30 years from October 1998
012/1997	RGE	Rio Grande do Sul	30 years from November 1997
015/1999	CPFL Santa Cruz	São Paulo, Minas Gerais and Paraná	30 years from July 2015
Transmission
003/2013	CPFL Piracicaba	São Paulo	30 years from February 2013
006/2015	CPFL Morro Agudo	São Paulo	30 years from March 2015
020/2018	CPFL Maracanaú	Ceará	30 years from September 2018
005/2019	CPFL Sul I	Santa Catarina	30 years from March 2019
011/2019	CPFL Sul II	Rio Grande do Sul	30 years from March 2019

Law No. 12,783/13 of 2013 provided that the type of existing distribution concession held by our four distribution subsidiaries that have now been merged into CPFL Santa Cruz could be renewed, subject to certain conditions, for a further term of up to 30 years. Accordingly, we applied for renewal of these concessions in 2014, and on November 9, 2015 the MME issued a decision extending the concessions to July 2045. The extension agreements were signed on December 9, 2015. Since the extensions were granted under current laws and regulations regarding distribution concessions, the concessions are now subject to the current targets and standards set by the Brazilian authorities.

According to Normative Resolution No. 716/2016, until the first tariff review of the Merged Companies in March 2021, ANEEL may institute a policy that reconciles the variations in the old tariffs for each of the Merged Companies and the new unified tariff for CPFL Santa Cruz over time. ANEEL decided to introduce the unified tariff during the March 2018 tariff adjustment.

As a result of this merger transaction and the related transfer of the assets of RGE to RGE Sul, RGE no longer exists. See “Item 4. Information on the Company—Overview”.

The tables below present a summary of the concessions of our generation business. In addition to these concessions, CPFL Centrais Geradoras, as an Independent Power Producer with generating capacity of less than 5,000 kW, operates under a regulatory registry and not under a concession contract.

Conventional generation

	Concession no.	Independent Power Producers / Concessionaire	Plant	State	Term
Hydroelectric plants
	005/2004	CPFL Geração	Serra da Mesa	Goiás	35 years from November 2004
	008/2001	CERAN	14 de Julho, Castro Alves and Monte Claro	Rio Grande do Sul	35 years from March 2001
	036/2001	Barra Grande	Barra Grande	Rio Grande do Sul	35 years from May 2001
	043/2000	ENERCAN	Campos Novos	Santa Catarina	35 years from May 2000
	005/1997	Lajeado Consortium	Luiz Eduardo Magalhães	Tocantins	35 years from December 1997
	128/2001	Foz do Chapecó	Foz do Chapecó	Santa Catarina and Rio Grande do Sul	35 years from November 2001
Small Hydroelectric Plants
	⁽³⁾	CPFL Centrais Geradoras⁽⁴⁾	Lavrinha (Micro Hydroelectric Power Plant)	São Paulo	⁽³⁾
	009/1999	CPFL Geração⁽⁵⁾	Macaco Branco (Small Hydroelectric Power Plant)	São Paulo	30 years (from December 2012)
	⁽³⁾	CPFL Centrais Geradoras⁽⁴⁾	Pinheirinho (Micro Hydroelectric Power Plant)	São Paulo	⁽³⁾
	010/1999	CPFL Geração⁽⁵⁾	Rio do Peixe I and II (Small Hydroelectric Power Plants)	São Paulo	30 years (from December 2012)
	⁽³⁾	CPFL Centrais Geradoras⁽⁴⁾	Santa Alice (Micro Hydroelectric Power Plant)⁽⁷⁾	São Paulo	⁽³⁾
	⁽³⁾	CPFL Centrais Geradoras⁽⁴⁾	São José (Micro Hydroelectric Power Plant)	São Paulo	⁽³⁾
	⁽³⁾	CPFL Centrais Geradoras⁽⁴⁾	São Sebastião (Micro Hydroelectric Power Plant)	São Paulo	⁽³⁾
	⁽³⁾	CPFL Centrais Geradoras⁽⁴⁾	Turvinho (Micro Hydroelectric Power Plant)	São Paulo	⁽³⁾

Renewable generation

	Concession no.	Independent Power Producers / Concessionaire	Plant	State	Term
Small Hydroelectric Plants
	003/2011	Jayaditya	Americana	São Paulo	up to November 2027
	Dispatch No. 1990⁽⁶⁾	CPFL Sul Centrais	Andorinhas	Rio Grande do Sul	⁽³⁾
	002/2011	Chimay	Buritis	São Paulo	up to November 2027
	002/2011	Chimay	Capão Preto	São Paulo	up to November 2027
	002/2011	Chimay	Chibarro	São Paulo	up to November 2027
	002/2011	Chimay	Dourados	São Paulo	up to November 2027
	004/2011	Mohini	Eloy Chaves	São Paulo	up to November 2027
	002/2011	Chimay	Esmeril	São Paulo	up to November 2027
	002/2011	Chimay	Gavião Peixoto	São Paulo	up to November 2027
	Dispatch No. 1,987/2005⁽⁶⁾	CPFL Sul Centrais	Guaporé	Rio Grande do Sul	undetermined
	004/2011	Mohini	Jaguari	São Paulo	up to November 2027
	002/2011	Chimay	Lençóis	São Paulo	up to November 2027
	004/2011	Mohini	Monjolinho	São Paulo	up to November 2027
	004/2011	Mohini	Pinhal	São Paulo	up to November 2027
	Dispatch No. 1989⁽⁶⁾	CPFL Sul Centrais	Pirapó	Rio Grande do Sul	⁽³⁾
	Dispatch No. 1988⁽⁶⁾	CPFL Sul Centrais	Saltinho	Rio Grande do Sul	⁽³⁾
	003/2011	Jayaditya	Salto Grande	São Paulo	up to November 2027
	002/2011	Chimay	São Joaquim	São Paulo	up to November 2027
	004/2011	Mohini	Socorro	São Paulo	up to November 2027
	003/2011	Jayaditya	Santana	São Paulo	up to November 2027
	003//2011	Jayaditya	Três Saltos	São Paulo	up to November 2027

(1)

We have the contractual right to 51.54% of the Assured Energy of this facility under a 30-year agreement, expiring in 2028. The concession for Serra da Mesa, held by Furnas, has been extended to September 30, 2040. The renewal was approved by the MME in Ordinance No. 262 published on April 27, 2012 and the final extension of the renegotiated GSF was approved by ANEEL in Authoritative Resolution No. 6,055 published on September 27, 2016.

(2)

Hydroelectric projects with an Installed Capacity greater than 5,000 kW that were granted through a concession process with the regulatory authority and the administrator of power concessions, prior to changes made by Law No. 13,360/2016. Pursuant to Law No. 13,360/2016,only Hydroelectric Power Plants with capacity greater than 50,000 kW now require a concession; those with capacity of more than 5,000 kW up to 50,000 kW are subject to an authorization from ANEEL; and those with capacity equal to or less than 5,000 kW only require registration with ANEEL rather than a concession or authorization.

(3)	Hydroelectric projects with an Installed Capacity equal to or less than 5,000 kW that are registered with the regulatory authority and the administrator of power concessions, but do not require concession or authorization processes for operating.
(4)	Since August 29, 2013 CPFL Centrais Geradoras has held the unbundled generation activities of the Macaco Branco and SHPPs Rio do Peixe I and II, as required by Resolution No. 521/12 for their renewal, together with the generation activities of the Santa Alice, Lavrinha, São José, Turvinho, Pinheirinho and São Sebastião Micro Hydroelectric Power Plants. Since November 17, 2016, due to changes made by Law No. 13,360/2016, hydroelectric projects with an Installed Capacity equal to or less than 5,000 kW no longer require concession or authorization processes for operating, but only registration with ANEEL.
(5)	The Macaco Branco and Rio do Peixe concessions were transferred from CPFL Centrais Geradoras to CPFL Geração in September 30, 2015 (see “–Overview”).
(6)	Hydroelectric Power Plants with capacity equal to or less than 5,000 kW only require registration with ANEEL. These Hydroelectric Power Plants have already received these registrations and are exempt from concession and authorization requirements.
(7)	In 2019, CGH Santa Alice’s register was cancelled. The project was leased to TIM Celular S.A. and has been operated as distributed generation services since June 1, 2019.

Authorizations

Conventional generation

	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term
Thermoelectric plants
	2277	EPASA	Termoparaíba Thermoelectric Power Plant	Paraíba	35 years from December 7, 2007
	2277	EPASA	Termonordeste Thermoelectric Power Plant	Paraíba	35 years from December 12, 2007

Renewable generation

	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term
Small Hydroelectric plants
	Resolution No. 587	SPE Alto Irani Energia S.A.	Alto Irani	Santa Catarina	30 years from October 30, 2002
	Resolution No. 606	SPE Arvoredo Energia S.A.	Arvoredo	Santa Catarina	30 years from November 7, 2002
	Resolution No. 348	SPE Barra da Paciência Energia S.A.	Barra da Paciência	Minas Gerais	30 years from December 20, 1999
	Resolution No. 349	SPE Cocais Grande Energia S.A.	Cocais Grande	Minas Gerais	30 years from December 23, 1999
	Resolution No. 17	SPE Corrente Grande Energia S.A.	Corrente Grande	Minas Gerais	30 years from January 17, 2000
	Resolution No. 198	Figueirópolis Energética S.A.	Figueirópolis	Mato Grosso	30 years from May 04, 2004
	Resolution No. 705	Ludesa Energética S.A.	Ludesa	Santa Catarina	30 years from December 17, 2002
	Resolution No. 262	Mata Velha Energética S.A.	Mata Velha	Minas Gerais	30 years from May 16, 2002
	Resolution No. 370	SPE Ninho da Águia Energia S.A.	Ninho da Águia	Minas Gerais	30 years from December 30, 1999

	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term
	Resolution No. 652	Novo Horizonte Energética S.A.	Novo Horizonte	Paraná	30 years from November 26, 2002
	Resolution No. 406	SPE Paiol Energia S.A.	Paiol	Minas Gerais	30 years from August 07, 2002
	Resolution No. 607	SPE Plano Alto Energia S.A.	Plano Alto	Santa Catarina	30 years from November 7, 2002
	Resolution No. 2510	SPE Salto Góes Energia S.A.	Salto Góes	Santa Catarina	30 years from August 19, 2010
	Resolution No. 13	SPE São Gonçalo Energia S.A.	São Gonçalo	Minas Gerais	30 years from January 14, 2000
	Ordinance No. 352	SPE Santa Luzia Energética S.A.	Santa Luzia	Santa Catarina	35 years from December 21, 2007
	Resolution No. 355	SPE Varginha Energia S.A.	Varginha	Minas Gerais	30 years from December 23, 1999
	Resolution No. 367	SPE Várzea Alegre Energia S.A.	Várzea Alegre	Minas Gerais	30 years from December 30, 1999
	Ordinance No. 502	SPE Boa Vista II Energia S.A.	Boa Vista 2	Minas Gerais	35 years from November 09, 2015
	Ordinance No. 475	CPFL Sul Centrais	Diamante	Mato Grosso	30 years from November 13, 1997
Biomass Thermoelectric Power Plants
	Resolution No.2106	CPFL Bioenergia	Baldin Thermoelectric Power Plant	São Paulo	30 years from September 24, 2009
	Resolution No. 3714	SPE Alvorada S.A.	Alvorada Thermoelectric Power Plant	Minas Gerais	30 years from October 29, 2012
	Resolution No. 2643	CPFL Bio Buriti S.A.	Buriti Thermoelectric Power Plant	São Paulo	30 years from December 16, 2010
	Resolution No. 3328	SPE Coopcana S.A.	Coopcana Thermoelectric Power Plant	Paraná	30 years from February 14, 2012
	Resolution No. 117	CPFL Bio Ester Ltda.	Ester Thermoelectric Power Plant	São Paulo	30 years from May 21, 1999
	Resolution No. 259	CPFL Bio Formosa S.A.	Baía Formosa Thermoelectric Power Plant	Rio Grande do Norte	30 years from May 15, 2002
	Resolution No. 2375	CPFL Bio Ipê S.A.	Ipê Thermoelectric Power Plant	São Paulo	30 years from May 3, 2010
	Ordinance No. 129	CPFL Bio Pedra S.A.	Pedra Thermoelectric Power Plant	São Paulo	35 years from February 28, 2011
Wind farm plants
	Ordinance No. 134	Atlântica I Parque Eólico S.A.	Atlântica I	Rio Grande do Sul	35 years from February 28, 2011
	Ordinance No. 148	Atlântica II Parque Eólico S.A.	Atlântica II	Rio Grande do Sul	35 years from March 04, 2011
	Ordinance No. 147	Atlântica IV Parque Eólico S.A.	Atlântica IV	Rio Grande do Sul	35 years from March 04, 2011
	Ordinance No. 168	Atlântica V Parque Eólico S.A.	Atlântica V	Rio Grande do Sul	35 years from March 22, 2011
	Resolution No. 093	Bons Ventos Geradora de Energia S.A.	Bons Ventos	Ceará	30 years from March 10, 2003
	Ordinance No. 257	Campo dos Ventos II Energias Renováveis S.A.	Campo dos Ventos II	Rio Grande do Norte	35 years from April 18, 2011
	Resolution No. 3967	Campo dos Ventos I Energias Renováveis S.A.	Campo dos Ventos I	Rio Grande do Norte	30 years from March 26, 2013
	Resolution No. 3968	Campo dos Ventos III Energias Renováveis S.A.	Campo dos Ventos III	Rio Grande do Norte	30 years from March 26, 2013

Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term
Resolution No. 3969	Campo dos Ventos V Energias Renováveis S.A.	Campo dos Ventos V	Rio Grande do Norte	30 years from March 26, 2013
Resolution No. 680	BVP Geradora de Energia S.A.	Canoa Quebrada	Ceará	30 years from December 11, 2002
Resolution No. 329	Rosa dos Ventos Geração e Comercialização de Energia S.A.	Canoa Quebrada	Ceará	30 years from June 19, 2002
Ordinance No. 585	SPE Costa Branca Energia S.A.	Costa Branca	Rio Grande do Norte	35 years from October 14, 2011
Resolution No. 625	BVP Geradora de Energia S.A.	Enacel	Ceará	30 years from November 13, 2002
Ordinance No. 264	Desa Eurus I S.A.	Eurus I	Rio Grande do Norte	35 years from April 19, 2011
Ordinance No. 266	Desa Eurus III S.A.	Eurus III	Rio Grande do Norte	35 years from April 27, 2011
Ordinance No. 749	Eurus VI Energias Renováveis Ltda.	Eurus VI	Rio Grande do Norte	35 years from August 25, 2010
Resolution No. 306	SIIF Cinco Geração e Comercialização de Energia S.A.	Foz de Choró	Ceará	30 years from June 05, 2002
Resolution No. 454	Eólica Icaraizinho Geração e Comercialização de Energia S.A.	Icaraizinho	Ceará	30 years from August 28, 2002
Ordinance No. 556	SPE Juremas Energia S.A.	Juremas	Rio Grande do Norte	35 years from September 29, 2011
Resolution No. 340	Rosa dos Ventos Geração e Comercialização de Energia S.A.	Lagoa do Mato	Ceará	30 years from June 26, 2002
Ordinance No. 557	Macacos Energia S.A.	Macacos	Rio Grande do Norte	35 years from September 29, 2011
Ordinance No. 664	Desa Morro dos Ventos I S.A.	Morro dos Ventos I	Rio Grande do Norte	35 years from July 27, 2010
Ordinance No. 373	Desa Morro dos Ventos II S.A.	Morro dos Ventos II	Rio Grande do Norte	35 years from June 12, 2012
Ordinance No. 685	Desa Morro dos Ventos III S.A.	Morro dos Ventos III	Rio Grande do Norte	35 years from August 04, 2010
Ordinance No. 686	Desa Morro dos Ventos IV S.A.	Morro dos Ventos IV	Rio Grande do Norte	35 years from August 04, 2010
Ordinance No. 663	Desa Morro dos Ventos VI S.A.	Morro dos Ventos VI	Rio Grande do Norte	35 years from July 27, 2010
Ordinance No. 665	Desa Morro dos Ventos IX S.A.	Morro dos Ventos IX	Rio Grande do Norte	35 years from July 27, 2010
Resolution No. 460	Eólica Paracuru Geração e Comercialização de Energia S.A.	Paracuru	Ceará	30 years from August 28, 2002
Ordinance No. 584	Pedra Preta Energia S.A.	Pedra Preta	Rio Grande do Norte	35 years from October 14, 2011
Resolution No. 307	Eólica Formosa Geração e Comercialização de Energia S.A.	Praia Formosa	Ceará	30 years from June 05, 2002
Ordinance No. 609	Santa Clara I Energia Renováveis Ltda.	Santa Clara I	Rio Grande do Norte	35 years from July 02, 2010
Ordinance No. 683	Santa Clara II Energia Renováveis Ltda.	Santa Clara II	Rio Grande do Norte	35 years from August 05, 2010
Ordinance No. 610	Santa Clara III Energia Renováveis Ltda.	Santa Clara III	Rio Grande do Norte	35 years from July 02, 2010
Ordinance No. 672	Santa Clara IV Energia Renováveis Ltda.	Santa Clara IV	Rio Grande do Norte	35 years from July 30, 2010

	Authorization no.	Independent Power Producers / Concessionaire	Plant	State	Term
	Ordinance No. 838	Santa Clara V Energia Renováveis Ltda.	Santa Clara V	Rio Grande do Norte	35 years from October 11, 2010
	Ordinance No. 670	Santa Clara VI Energia Renováveis Ltda.	Santa Clara VI	Rio Grande do Norte	35 years from July 30, 2010
	Resolution No. 4592	Santa Mônica Energias Renovaveis Ltda.	Santa Mônica	Rio Grande do Norte	30 years from April 01, 2014
	Resolution No. 4591	Santa Ursula Energias Renovaveis Ltda.	Santa Úrsula	Rio Grande do Norte	30 years from March 31, 2014
	Resolution No. 5074	São Domingos Energias Renováveis S.A.	São Domingos	Rio Grande do Norte	30 years from March 10, 2015
	Resolution No. 778	BVP Geradora de Energia S.A.	Taíba Albatroz	Ceará	30 years from December 24, 2002
	Resolution No. 4563	São Benedito Energias Renovaveis Ltda.	Ventos de São Benedito	Rio Grande do Norte	30 years from March 07, 2014
	Resolution No. 4562	Ventos de Santo Dimas Energias Renovaveis Ltda.	Ventos de Santo Dimas	Rio Grande do Norte	30 years from March 07, 2014
	Resolution No. 4572	Ventos de São Martinho Energias Renovaveis Ltda.	Ventos de São Martinho	Rio Grande do Norte	30 years from March 21, 2014
	Ordinance No. 387	Pedra Cheirosa I Energia S.A.	Pedra Cheirosa I	Ceará	35 years from August 04, 2014
	Ordinance No. 359	Pedra Cheirosa II Energia S.A.	Pedra Cheirosa II	Ceará	35 years from July 23, 2014
Solar Power Plants
	Of. ANEEL No. 961/2012	SPE CPFL Solar 1 Energia S.A.	Tanquinho	São Paulo	Undetermined^(*)

(1)

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 at the time of renewal and do not require concession or authorization processes for operating.

(*)

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

Independent Power Producers and Self-Generators

A generation company classified as an Independent Power Producer under Brazilian law receives a concession or authorization to produce energy for sale to local distribution companies, Free Consumers and other types of consumers (excluding Captive Consumers).

A generation company classified as a self-generator under Brazilian law receives a concession or authorization to produce energy for its own consumption. A self-generator may, upon specific authorization by ANEEL, sell or trade any excess energy it is unable to consume.

The prices that Independent Power Producers and self-generators may charge for the sale of energy to certain types of consumers are subject to tariffs established by ANEEL, whereas the sale price to other types of consumers can be freely negotiated between the parties. See “—Authorizations” for more information.

Concessionaires

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

The concession agreement and related documents establish the concession period and whether the related concession can be extended. For concessions to generate electric energy, the amortization period for the related investment is up to 35 years, renewable once for a maximum period of 20 years, according to Law No. 9,074/95 or for a maximum period of up to 30 years, if the concession period extension is subject to Law No. 12,783/13.

Although concession agreements and applicable laws generally allow for the extension of the concession period, such extension is not automatic. The decision to extend a concession agreement is subject to compliance by the concessionaire with certain requirements and the discretion of the granting authority, which must provide justification for its decision, and the decision must foster the public interest.

Properties

Our principal properties consist of hydroelectric generation plants. We have accounted for our distribution companies’ fixed assets, comprised mainly of Substations and Distribution Networks, partially as intangible assets and partially as financial assets of concession. The net book value of our total property, plant and equipment as of December 31, 2019 was R$9,084 million. No single one of our properties produces more than 10.0% of our total revenues. Our facilities are generally adequate for our present needs and suitable for their intended purposes. Pursuant to Brazilian law, the essential properties and facilities that we use in performing our obligations under our concession agreements cannot be transferred, assigned, pledged or sold to, or encumbered by, any of our creditors without prior approval from ANEEL.

Environmental

The Brazilian Federal constitution gives both the Brazilian federal and state governments the power to enact laws designed to protect the environment. A similar power is given to municipalities whose local interests may be affected. Municipal laws are considered to be a supplement to federal and state laws. A violator of applicable environmental laws may be subject to administrative and criminal sanctions, and will have an obligation to remediate and/or provide compensation for environmental damages. Administrative sanctions may include substantial fines and suspension of activities, while criminal sanctions may include fines and, for individuals (including executive officers and employees of companies who commit environmental crimes), imprisonment.

Our energy distribution, transmission and generation facilities are subject to environmental laws and licensing procedures, which include the undertaking of environmental impact studies prior to constructing new facilities and implementing programs to reduce negative environmental impacts. Once the respective environmental licenses are obtained, the company holding such license remains subject to compliance with specific requirements.

The environmental issues regarding the construction and operation of electricity generation facilities require specifically tailored oversight. For this reason, CPFL Geração manages these matters in order to ensure that its policies and environmental obligations are given adequate consideration. Decisions are made by environmental committees, whose members include representatives of each project partner and of each plant’s environmental management office. Our environmental committees are constantly interacting with government agencies to ensure environmental compliance and future electricity generation. In addition, we support local community programs that relocate rural families in collective resettlements and provide institutional support for families involved in the conservation of local biodiversity.

In order to ensure compliance with environmental laws, we have implemented an internal management system that complies with best environmental practices in all of our segments. We have established a process to identify, evaluate and update matters relating to applicable environmental laws, as well as other requirements applicable to our environmental management system. Additionally, our generation, transmission and distribution operating segments are subject to internal audits to ensure they are in compliance with our internal environmentalpolicies, as well as external audits that verify whether our activities are in compliance with ISO 14001. Our environmental management processes consider our budgets and realistic forecasts and always aim to achieve improvements at the financial, social and environmental levels.

The Brazilian Power Industry

According to ANEEL, as of December 31, 2019, the Installed Capacity of power generation in Brazil was 172.3 GW. Historically, approximately 65% of the total Installed Capacity in Brazil has derived from Hydroelectric Power Plants. Large Hydroelectric Power Plants tend to be far from the consumption centers. This requires construction of large transmission lines at High Voltage and extra-high voltage (230 kV to 750 kV) that often cross the territory of several states. Brazil has a robust electric grid system, with more than 154,430 kmof transmission lines with voltage equal to or greater than 230 kV and processing capacity of approximately 325,000 MVA from the state of Rio Grande do Sul through the state of Amazonas.

According to the EPE, electricity consumption in Brazil increased by 1.4% in 2019, reaching 482,085 GWh. However, the MME and the EPE estimate that electricity consumption will grow by 3.0% per year until 2027. According to the ten-year expansion plan published by the MME and the EPE in order to satisfy this expected growth in demand, Brazil’s Installed Capacity is expected to reach 216.3 GW by 2027, of which 112.4 GW (51.9%) is projected to be hydroelectric, 32.0 GW (14.8%) is projected to be thermoelectric and nuclear and 51.9GW (24.0%) is projected to be from other renewable sources.

Currently, 30.2% of the Installed Capacity in Brazil is owned by Eletrobras, a publicly traded corporation controlled by the Brazilian government. We are a relevant player within the electricity generation sector, with 2.5% of the market share.

Principal Regulatory Authorities

National Congress

The Brazilian National Congress is the legislative body of Brazil’s federal government. The Congress is bicameral, composed of the Federal Senate (the upper house) and the Chamber of Deputies (the lower house). In addition to lawmaking, the National Congress is responsible for the oversight of every accounting, financial and budgetary operation involving not only the federal government’s finances and properties but also any of the federal government’s branch departments’ or federal agencies’ finances and properties. It is the authority responsible for editing or amending Brazilian laws as well as the Federal Constitution.

Ministry of Mines and Energy — MME

After the National Congress, the MME is the Brazilian government’s primary authority in the power industry. Following the adoption of the New Regulatory Framework in 2004, the Brazilian government, acting primarily through the MME, has assumed certain duties that were previously the responsibility of ANEEL, including drafting guidelines for the granting of concessions and issuing directives governing the tender process for concessions that relate to public services and public assets.

National Energy Policy Council — CNPE

The CNPE, a committee created in August 1997, advises the President of Brazil on the development of national energy policy. The CNPE is chaired by the Minister of Mines and Energy and consists of eight government ministers, three members selected by the President of Brazil, another representative of the MME and the president of the EPE. The CNPE was created to optimize the use of Brazil’s energy resources and to guarantee national energy supply.

Brazilian Electricity Regulatory Agency — ANEEL

ANEEL is an independent federal regulatory agency whose primary responsibility is to regulate and supervise the power industry in accordance with policies set forth by the MME, together with other matters delegated to it by the Brazilian government and the MME. ANEEL’s current responsibilities include, among others: (i) administering concessions for electric energy generation, transmission and distribution, including the approval of electricity tariffs; (ii) enacting regulations for the electric energy industry; (iii) implementing and regulating the exploitation of energy sources, including the use of hydroelectric power; (iv) promoting the public tender process for new concessions; (v) settling administrative disputes among electricity generation entities and electricity purchasers; and (vi) defining the criteria and methodology for the determination of Transmission Tariffs.

National Electrical System Operator — ONS

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

Electric Energy Trading Chamber — CCEE

The CCEE is a nonprofit organization that is subject to authorization, inspection and regulation by ANEEL. The CCEE replaced the Wholesale Energy Market. The CCEE is responsible, among other things, for (i) registering all CCEARs and all agreements that result from market adjustments and the volume of electricity contracted in the Free Market, (ii) accounting for and clearing of short-term transactions, and (iii) managing and operating the CDE Account, the RGR Fund and the CCC Account. The CCEE consists of entities that hold concessions, permissions or authorizations within the electricity industry and Free and Special Consumers. Its board of directors is composed of four members appointed by these parties, together with one appointed by the MME. The member appointed by the MME also acts as chairman of the board of directors.

Energy Research Company — EPE

On August 16, 2004, the Brazilian government created the EPE, a state-owned company responsible for conducting strategic research on the energy industry, including with respect to electric energy, oil, gas, coal and renewable energy sources. The research carried out by EPE is used by MME in its policymaking role in the energy industry.

Energy Industry Monitoring Committee — CMSE

The New Regulatory Framework created the Energy Industry Monitoring Committee (Comitê de Monitoramento do Setor Elétrico), or CMSE, which acts under the direction of the MME. The CMSE is responsible for monitoring supply conditions within the system and for indicating steps to be taken to correct problems.

Concessions and Authorizations

The Brazilian Federal constitution provides that the development, use and sale of electric energy may be undertaken directly by the Brazilian government or indirectly through the granting of concessions, permissions or authorizations. Historically, the Brazilian electric energy industry has been dominated by generation, transmission and distribution concessionaires controlled by the federal or state governments.

Companies or consortia that wish to build or operate facilities for generation, transmission or distribution of electricity in Brazil must apply to the MME or to ANEEL, as representatives of the Brazilian government, for aconcession, permission or authorization, as the case may be. Concessions and permissions are granted through more complex proceedings or through public tender, whilst authorizations are granted through more simple administrative proceedings or through public auctions for power purchase and sale.

Concessions

Concessions grant rights to generate, transmit or distribute electricity in the relevant concession area for a specified period (as opposed to permissions, which may be revoked at any time at the discretion of the MME, in consultation with ANEEL). This period is usually 35 years for new generation concessions, and 30 years for new transmission or distribution concessions. An existing concession may be renewed at the granting authority’s discretion and subject to compliance by the concessionaire with certain requirements.

The Concession Law establishes, among other things, the conditions that the concessionaire must comply with when providing electricity services, the rights of consumers, and the obligations of the concessionaire and the granting authority. Furthermore, the concessionaire must comply with regulations governing the electricity sector. The main provisions of the Concession Law are summarized below:

Adequate service. The concessionaire must render adequate service with respect to regularity, continuity, efficiency, safety and accessibility.

Use of land. The concessionaire may use public land or request the granting authority to expropriate necessary private land for the benefit of the concessionaire. In such case, the concessionaire must compensate the affected private landowners.

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

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

Intervention by the granting authority. Pursuant to Law No. 12,767 of December 27, 2012, as modified by Law No. 12,839 of July 2013, the granting authority may intervene in the concession, acting through ANEEL, to ensure the adequate performance of services, as well as full compliance with applicable contractual and regulatory provisions. Within 30 days after the date of the decree, ANEEL is required to commence an administrative proceeding in which the concessionaire is entitled to contest the intervention. During the term of the administrative proceeding, a government appointed manager becomes responsible for carrying on the concession. The administrative proceeding must be completed within one year (which may be extended for two more years). In order for the intervention to cease and the concession to return to the concessionaire, the concessionaire’s shareholders are required to present a detailed recovery plan to ANEEL and correct the irregularities identified by ANEEL.

Termination of concessions. The termination of a concession agreement may be accelerated by means of expropriation and/or forfeiture. Expropriation is the early termination of a concession for reasons related to the public interest that must be expressly declared by law and for which indeminification must be provided. Furthermore, the criteria according to which such indemnification should be made is subject to changes in legislation. Forfeiture must be declared by the granting authority after ANEEL or the MME has made a final administrative ruling that the concessionaire, among other things, (i) has failed to render adequate service or to comply with applicable law or regulation, (ii) no longer has the technical, financial or economic capacity to provide adequate service, or (iii) has not complied with penalties assessed by the granting authority. The concessionaire may contest any expropriation or forfeiture in the courts. The concessionaire is entitled to indemnification for its investments in expropriated assets that have not been fully amortized or depreciated, after deduction of any fines and damages due by the concessionaire. However, the timeline for receiving the indemnification is not defined by law. Additionally, on December 10, 2014, our distribution companies signed a concession contract amendment that guarantees, at the concession period termination, that the company will receive or pay the balance of the remaining amounts under billed sector financial assets or liabilities. ANEEL Public Consultation No. 024/2019 has begandiscussions to define the rules for opening the process of expiration of concessions. It is expected that the theme will be regulated by the end of 2020.

Expiration. When the concession expires, all assets, rights and privileges that are materially related to the rendering of the electricity services revert to the Brazilian government. Following the expiration, the concessionaire is entitled to indemnification for its investments in assets that have not been fully amortized or depreciated as of the expiration. However, the timeline for receiving the indemnification is not defined by law.

Renewal. Law No. 12,783 of January 11, 2013 specified the conditions for the renewal of generation, transmission and distribution concessions obtained under Articles 17, 19 or 22 of Law No. 9,074 of July 7, 1995. Under Law No. 12,783/13, these concessions may be extended once, at the discretion of the Brazilian government, for up to 30 years, in order to ensure the continuity and efficiency of the services rendered and low tariffs. In addition, Law No. 12,783/13 enabled holders of concessions that were due to expire in 2015, 2016 and 2017 to apply for early renewal, subject to certain conditions. Renewal of generation concessions is contingent on the satisfaction of the following conditions: (i) tariffs calculated by ANEEL for each hydroelectric plan; (ii) allocation of energy quotas to distribution companies in the National Interconnected System; and (iii) submission to the standards of service quality set by ANEEL. For renewal, the assets remaining unamortized at the renewal date would be indemnified and the indemnification payment would not be considered to be annual revenue. The remuneration relating to new assets or existing assets that were not indemnified would be considered annual revenue. Resolution No. 521/12 published by ANEEL on December 14, 2012 established that if generation concessions operated by distribution companies are renewed under Law No. 12,783/13, the generation concession must be managed by an entity that is independent from the distribution company within twelve months after the renewal date. Law No. 12,783/13 also extinguished two sector charges, the CCC Account and the RGR Fund (see “—Regulatory Charges—RGR Fund and UBP” and “—Regulatory Charges—CDE Account”). Additionally, Law No. 13,360/2016 enabled holders of concessions of hydropower plants with up to 50 MW of Installed Capacity that have not yet been renewed to apply for 30-year renewals, subject to making a contribution for UBP, as set by the granting authority, and to paying a CFURH fee for the use of water to the municipality where such use occurs. See, “—Regulatory Charges—Fee for the Use of Water – CFURH” and “—Regulatory Charges—RGR Fund and UBP.”

In the specific case of distribution concessions, in 2015 the Brazilian government enacted Decree No. 8,461/2015 establishing new standards that concessionaires must achieve, mainly regarding quality, management and price. Within five years after the renewal date, the concessionaire must meet these standards and achieve annual targets. If the annual targets are not achieved, the concessionaire’s controlling shareholders may be required to make further capital expenditures. In addition, if the concessionaire fails to meet the annual targets for two consecutive years, or fails to meet any of the required standards at the end of the five-year term, the concession may be terminated or corporate control of the concessionaire may be transferred (see “—Risk Factors—We are uncertain as to the renewal of our concessions and authorizations”).

Penalties. ANEEL regulations govern the imposition of sanctions against the participants in the electricity sector and classify the appropriate penalties based on the nature and severity of the breach (including fines and forfeiture). For each breach, the fines can be up to 2.0% of the annual revenue (net of value-added tax and services tax) of the concessionaire or, if the concession in default is non-operative, up to 2.0% of the estimated value of energy that would be produced by the concessionaire in the 12-month period prior to the issuance of the infraction notice related to the breach. Infractions that may result in fines relate to the failure of the concessionaire to request ANEEL’s approval in the following cases, among others: (i) execution of contracts between related parties in the cases provided by regulation; (ii) sale or assignment of the assets related to services rendered as well as the imposition of any encumbrance (including any security, bond, guarantee, pledge and mortgage) on them or any other assets related to the concession or the revenues of the electricity services; and (iii) changes in the controlling interests in the holder of the concession. In cases of contracts executed between related parties that are submitted for ANEEL’s approval, ANEEL may seek to impose restrictions on the terms and conditions of these contracts and, in extreme circumstances, determine that the contract be rescinded. See “Item 3. Key Information—Risk Factors—We may not be able to comply with the terms of our concession agreements 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” for more information.

Authorizations

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

In the power generation sector, Independent Power Producers and self-generators hold an authorization as opposed to a concession. Independent Power Producers and self-generators do not receive public service concessions or permits to render public services. Rather, they are granted authorizations or specific concessions to explore water resources that merely allow them to produce, use or sell electric energy. Each authorization granted to an Independent Power Producer or self-generators sets forth the rights and duties of the authorized company. Authorized companies may have the right to ask ANEEL to carry out expropriations on their behalf, and to their benefit, are subject to ANEEL’s regulations and prior approval in the event of a change in their controlling interests. Moreover, early unilateral termination of the authorization entitles the authorized company to seek compensation from the granting authority for damages suffered. Authorizations have a term of up to 35 years, and can be renewed, at the discretion of the granting authority, for up to 20 years, pursuant to Law No. 9,074/1995.

An Independent Power Producer may sell part or all of its output to customers on its own account and at its own risk. A self-generator may, upon specific authorization by ANEEL, sell or trade any excess energy it is unable to consume. Independent Power Producers and self-generators are not granted monopoly rights and are not subject to price controls, with the exception of specific cases. Independent Power Producers compete with public utilities and among themselves for large customers, pools of customers of distribution companies or any customers not served by a public utility. Independent Power Producers and concessionaire companies are subject to a series of penalties for the failure to comply with provisions of the authorizations. The following penalties may be applied: (i) fines per breach of up to 2.0% of the annual revenues generated by the relevant authorization, or, if the relevant authorization is non-operational, up to 2.0% of the estimated value of the energy that would have been produced for the 12 months prior to the infraction notice related to the breach; (ii) injunctions related to construction activities; (iii) restrictions on the operation of existing facilities and equipment; (iv) temporary suspension from participating in new tenders, which may also be extended to controlling shareholders of the entity subject to the penalty; (v) intervention; or (vi) termination of the authorization.

Permissions

Permissions have a very limited use within the Brazilian electricity sector. Permissions are granted to rural power generation cooperatives that supply power to their members and occasionally to consumers that are not part of the cooperative, in areas not regularly served by large distributors. Permissions are not a material portion of the Brazilian power matrix.

The New Regulatory Framework

Since 1995, the Brazilian government has taken a number of measures to reform the Brazilian electric energy sector. These culminated, on March 15, 2004, in the enactment of the New Regulatory Framework, which further restructured the power industry with the ultimate goal of providing consumers with a secure electricity supply at an adequate tariff.

The New Regulatory Framework introduced material changes to the regulation of the power industry, with the intention to (i) provide incentives to private and public entities to build and maintain generation capacity and (ii) assure the supply of electricity within Brazil at adequate tariffs through competitive public electricity auction processes. The key features of the New Regulatory Framework include:

Creation of two “environments” for the trading of electricity, including: (i) the Regulated Market, a more stable market in terms of supply of electricity; and (ii) a market specifically addressed to certain participants (i.e., Free Consumers and commercialization companies), called the Free Market, that permits a certain degree of competition.

·	Restrictions on certain activities of distributors, so as to require them to focus on their core business of distribution, to promote more efficient and reliable services to Captive Consumers.
·	Elimination of self-dealing, in order to provide an incentive to distributors to purchase electricity at the lowest available prices rather than buying electricity from related parties.
·	Maintenance of contracts entered into prior to the New Regulatory Framework, in order to provide regulatory stability for transactions carried out before its enactment.

The New Regulatory Framework excludes Eletrobras and its subsidiaries from the National Privatization Program, which is a program originally created by the Brazilian government in 1990 to promote the process of privatization of state-owned companies.

Regulations under the New Regulatory Framework include, among other items, rules relating to auction procedures, the form of PPAs and the method of passing costs through to Final Consumers. Under these regulations, all parties that purchase electricity must contract all of their electricity demand under the guidelines of the New Regulatory Framework. Parties that sell electricity must have “ballast” for their sales (i.e., the amount of energy sold in CCEE must be previously purchased under PPAs and/or generated by the seller’s own power plants). Agents that do not comply with such requirements are subject to penalties imposed by ANEEL and CCEE.

Beginning in 2005, all electricity generation, distribution and transmission companies, Independent Power Producers and Free and Special Consumers are required to notify the MME, by August 1 of each year, of their estimated electricity demand or estimated electricity generation, as the case may be, for each of the subsequent five years. Each distribution company is required to notify the MME, within the 60-day period preceding each electricity auction, of the amounts of electricity that it intends to contract in the auction. Based on this information, the MME must establish the total amount of energy to be contracted in the Regulated Market and the list of generation projects that will be allowed to participate in the auctions.

On April 4, 2019, the MME issued Ordinance No. 187/2019, which established a working group aimed at developing legal and regulatory improvements on (i) price signals; (ii) reducing charges and subsidies and enhancing their transparency; (iii) adjusting generation expansion to new supply requirements; (iv) segregating capacity and energy products; and (v) establishing an adequate and gradual market opening. The working group’s report described a series of actions that involve, generally, initiating public hearing processes and developing detailed studies regarding the matters discussed by the working group from 2020 through 2022. The impact to the Brazilian legal and regulatory frameworks resulting from these actions are still uncertain.

Environments for the Trading of Electric Energy

Under the current regulatory model, electricity purchase and sale transactions are carried out in two different segments: (i) the Regulated Market, which contemplates the purchase by distribution companies through public auctions of all electricity necessary to supply their consumers, and (ii) the Free Market, which contemplates the purchase of electricity by non-regulated entities (such as Free Consumers and energy traders).

Electricity distribution companies fulfill their electricity supply obligations primarily through public auctions. Distribution companies may also purchase electricity outside the public auction process from: (i) generation companies that are connected directly to such distribution company, except for hydro generation companies with capacity higher than 30 MW, certain thermo-generation companies and affiliated generation companies; (ii) electricity generation projects participating in the initial phase of the Proinfa Program, a program designed to diversify Brazil’s energy sources; (iii) the Itaipu Power Plant; (iv) auctions administered by the distribution companies, if the market that they supply is no greater than 500 GWh/year; and (v) Hydroelectric Power Plants whose concessions have been renewed by the government under Law No. 12,783/13 (in this latter case, in “energy quotas” distributed among the distribution companies by the Brazilian government, at prices determined by MME/ANEEL). The electricity generated by Itaipu continues to be sold by Eletrobras to the distribution concessionaires operating in the South/Southeast/Midwest Interconnected Power System, although no specific contract was entered into by these concessionaires. The rates at which the electricity generated by Itaipu is tradedare denominated in U.S. dollars and established pursuant to a treaty between Brazil and Paraguay. As a consequence, Itaipu rates rise or fall in accordance with the variation of the U.S. dollar/realexchange rate. Changes in the price of electricity generated by Itaipu are, however, subject to the Parcel A Cost recovery mechanism discussed below under “—Basis for Calculation of Distribution Tariffs.” Furthermore, electricity distributors are also allowed to sell surplus energy to Free and Special Consumers, generators and self-generators by means of the Surplus Selling Mechanism, established by ANEEL’s Normative Resolution No. 824/2018, as amended by ANEEL’s Normative Resolution No. 833/2018. The Surplus Selling Mechanism is set to take place periodically several times per year through 12-month, 6-month and 3-month agreements, with settlement at the equilibrium price set for each submarket and energy type. See, “—Distribution—Purchases of Electricity.”

The Regulated Market

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

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

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

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

The Free Market

The Free Market covers transactions between generation concessionaires, Independent Power Producers, self-generators, energy traders, importers of electric energy, Free Consumers and Special Consumers. The Free Market can also include existing bilateral contracts between generators and distributors until they expire. Upon expiration, such contracts must be executed under the New Regulatory Framework guidelines. However, generators generally sell their generation simultaneously, sharing the total amount of energy between the Regulated and Free Markets. It is possible to sell energy separately in one or more markets.

Free Consumers are divided into two types: Conventional Free Consumers and Special Free Consumers:

Conventional Free Consumers are those whose contracted energy demand was at least 2.5 MW as of July 1, 2019. This limit was lowered by MME Ordinance No. 514/2018 and No. 465/2019. The new limits defined by MME will be 2.0 MW as of January 1, 2020, 1.5 MW as of January 1, 2021, 1 MW as of January 1, 2022 and 0.5 MW as of January 1, 2023. Pursuant to MME Ordinance No. 465/2019, by January 31, 2022, ANEEL and CCEE shall present a study on the regulatory measures necessary to allow the free market to be opened for consumers with loads below 500 kW, including the regulated energy trader and proposed opening schedule beginning January 1, 2024. These consumers may choose to purchase all or part of their conventional or incentive energy (renewable sources), from another authorized supplier under the terms of current legislation. We refer to consumers who have exercised this option as “Conventional Free Consumers.”

Special Free Consumers are individual or groups of consumers whose contracted energy demand is currently between 500 kV and 3 MW. These limits will be be reduced following the schedule detailed above. We refer to consumers who have exercised this option as “Special Free Consumers.” Special Free Consumers may only purchase energy from renewable sources: (i) Small Hydroelectric Power Plants with capacity superior to 5,000 kW and equal or inferior to 30,000 kW, (ii) hydroelectric generators with capacity superior to 5,000 kW and equal or inferior to 50,000 kW, under the independent power production regime; (iii) generators with capacity limited to 3,000 kW, and (iv) alternative energy generators (solar, wind and biomass enterprises) with system capacity not greater than 50,000 kW. State-owned generators may sell electricity to Free Consumers; however, unlike private generators, they may only do so through an auction process.

We also refer to consumers who meet the relevant demand requirement but have not exercised the option to migrate to the free market as “Potential Conventional Free Consumers” or “Potential Special Free Consumers,” as appropriate, and in general as “Potential Free Consumers.”

Recent Developments in the Free Market

On December 28, 2018, the MME issued the Ordinance No. 514/2018, which lowers the requirements for being a Free Consumer of conventional energy, dropping the minimum contracted energy demand from 3.0 MW to 2.5 MW, effective as of July 1, 2019, and from 2.5 MW to 2.0 MW, effective as of January 1, 2020. On December 12, 2019, the MME issued Ordinance No. 465/2019, which updated the requirements for being a Free Consumer of conventional energy by reducing the minimum contracted energy demand to 1.5 MW as of January 1, 2021, 1 MW as of January 1, 2022 and 0.5 MW as of January 1, 2023. This action does not increase the number of consumers eligible for the Free Market because consumers with 500 kW of charge can already migrate, but with the limitation of purchasing energy only from incentivized sources. The gradual reduction of load limits flexibilizes the rule by allowing consumers to acquire energy from conventional sources as well. MME also determined, through Ordinance No. 465/2019 that by January 2022, ANEEL and CCEE must submit studies on the regulatory measures necessary to allow for the opening of the Free Market for consumers with loads below 500 kW. A proposal for a schedule for a fully Free Market shall also be presented by January 2024.

Auctions on the Regulated Market

Pursuant to Decree No. 9,143/2017, electricity auctions for new generation projects in process are held as A-”n” auctions, where “n” means the number of years before the initial delivery date and currently ranges from three to seven (referred to as “A-3,” “A-4,” “A-5,” “A-6” and “A-7” auctions). Electricity auctions from existing power generation facilities take place (i) from one to five years before the initial delivery date (referred to as “A-1,” “A-2,” “A-3,” “A-4” and “A-5” auctions) or (ii) approximately four months before the delivery date (referred to as “market adjustments”). Traditionally, “A-4” and “A-6” auctions have been launched for new generation projects and “A-1” and “A-2” auctions for existing generation facilities. Auction bid announcements are prepared by ANEEL in compliance with guidelines established by the MME, which include a requirement to use the lowest energy price as the criterion to determine the winner of the auction.

Each generation company that participates in an auction executes a contract for purchase and sale of electricity with each distribution company, the CCEAR, in proportion to the distribution companies’ respective estimated demand for electricity and price established in the auction. The only exception to these rules refers to the market adjustment auction, in which the contracts are executed directly between generation and distribution companies and are limited to a two-year term. The total amount of energy contracted in such market adjustment auctions may not exceed 5.0% of the total amount of energy contracted by each distributor. The CCEAR contains standard, non-negotiable terms and conditions which are established by ANEEL. A significant portion of our CCEARs provide that the price will be adjusted annually in accordance with the IPCA. However, some of our CCEARs establish other indexes to adjust prices, such as fuel prices. Distributors grant financial guarantees (mainly receivables from the distribution service) to generators in order to secure their payment obligations under the CCEAR.

With respect to the CCEAR related to electricity generated by existing generation facilities, there are three alternatives for the permanent reduction of contracted electricity: (i) compensation for the exit of Potential Free Consumers from the Regulated Market; (ii) reduction, at the distribution company’s discretion, of up to 4.0% per year over the initial contracted amount from existing power generation, excluding the first year of supply, due to market deviations from estimated market projections, beginning two years after the initial electricity demand was declared; and (iii) adjustments to the amount of electricity established in energy acquisition contracts entered into before March 17, 2004. Furthermore, ANEEL’s Normative Resolution No. 824/2018, as amended by ANEEL’s Normative Resolution No. 833/2018, established the Surplus Selling Mechanism, which allows electricity distributors to voluntarily to sell excess energy to Free and Special Consumers, generators and self-generators periodically several times per year through 12-month, 6-month and 3-month agreements.

Since 2005, CCEE has sucessfuly conducted 27 auctions for new generation projects, 19 auctions specifically for existing power generation facilities, three auctions for alternative sources generation projects and nine auctions qualified as “reserve energy.” In accordance with Decree No. 9,143/2017, the MME must publish an estimated annual schedule of regulated auctions by March 30 of each year and, no later than August 1 of each year, distributors must provide their estimated electricity demand for the five subsequent years. Based on this information, the MME establishes the total amount of electricity to be traded in the auction and decides which generation companies may participate in the auction. As a general rule, contracts entered into in an auction have the following terms: (i) from 15 to 35 years from commencement of supply in cases of new generation projects; (ii) from one to 15 years beginning in the year following the auction in cases of existing power generation facilities; (iii) from 10 to 35 years from commencement of supply in cases of alternative generation projects; and (iv) a maximum of 35 years for reserve energy.

The Annual Reference Value

The regulation also establishes a mechanism, the Annual Reference Value, which limits the amounts of costs that can be passed through to Final Consumers. The Annual Reference Value corresponds to the weighted average of electricity prices in the “A-6,” “A-5,” “A-4” and “A-3” auctions, calculated for all distribution companies. The values of auctions for alternative generation projects and for the projects indicated as priorities by the CNPE are not considered when calculating the Annual Reference Value.

The Annual Reference Value creates an incentive for distribution companies to contract for their expected electricity demands at the lowest price in “A-6,” “A-5,” “A-4” and “A-3” auctions. The regulation establishes the following limitations on the ability of distribution companies to pass through costs to consumers: (i) no pass-through of costs for electricity purchases that exceed 105% of actual demand; and (ii) limited pass-through of costs for electricity purchases in “A-3” and “A-4” auctions, if the volume of the acquired electricity exceeds 2.0% of the demand for electricity. Pursuant to Decree 9,143/2017, the costs from new electricity generation projects and existing energy are passed through in full to consumers. The MME establishes the maximum acquisition price for electricity generated by existing projects that is included in auctions for the sale of electricity to distributors; and, if distributors do not comply with the obligation to fully contract their demand, the pass-through of the costs from energy acquired in the spot market will be the lower of the PLD and the Annual Reference Value.

The PLD is used to valuate the energy traded in the spot market. It is calculated for each submarket and load level on a weekly basis and it is based on the marginal cost of operation. The maximum value of PLD for 2019 was set at R$559.75, according to ANEEL’s Resolution No. 2,655/2019. Before such resolution, the maximum value of PLD was set at R$513.89 (Resolution No. 2,498/2018) and R$505.18 (Resolution No. 2,364/2017). ANEEL also established the maximum value of the hourly PLD for purposes of “shadow operation” in 2020 at R$ 1,148.36/MWh. The “shadow operation” is a simulation of the PLD as if it was calculated hourly. Hourly operation is set to officially begin as of January 1, 2021.

Electric Energy Trading Convention

ANEEL Resolutions No. 109 of 2004 and No. 210 of 2006 govern the Electric Energy Trading Convention (Convenção de Comercialização de Energia Elétrica). This convention regulates the organization and administration of the CCEE, as well as the conditions for trading electric energy. It also defines, among other things: (i) the rights and obligations of CCEE participants; (ii) the penalties to be imposed on defaulting participants;(iii) the structure for dispute resolution; (iv) the trading rules in both Regulated and Free Markets; and (v) the accounting and clearing process for transactions in the spot market.

Restricted Activities of Distributors

Distributors in the Interconnected Power System are not permitted to: (i) conduct businesses related to the generation or transmission of electric energy; (ii) hold, directly or indirectly, any interest in any other company, corporation or partnership; or (iii) conduct businesses that are unrelated to their respective concessions, except for those permitted by law or in the relevant concession agreement. Generators are not allowed to control or hold relevant equity interests in distributors.

Under Decree No. 9,143/2017, electricity distributors were allowed to negotiate energy surpluses with Free Consumers and other agents of the Free Market (generators, traders and self-producers). This ability has since been replaced by the Surplus Selling Mechanism, which was introduced by ANEEL’s Normative Resolution No. 824/2018, as amended by ANEEL’s Normative Resolution No. 833/2018, and went into effect in January 2019. See “—Distribution—Purchases of Electricity.”

Elimination of Self-Dealing

Since the purchase of electricity for Captive Consumers is currently performed through the Regulated Market, “self-dealing” (under which distributors were permitted to meet up to 30.0% of their electric energy needs through energy that was either self-generated or acquired from affiliated companies) is no longer permitted, except in the context of agreements that were approved by ANEEL before the enactment of the New Regulatory Framework.

Challenges to the Constitutionality of the New Regulatory Framework

Political parties are currently challenging the New Regulatory Framework on constitutional grounds before the Brazilian Federal Supreme Court. In October 2007, the Brazilian Federal Supreme Court issued a decision regarding injunctions that had been requested in the matter, denying the injunctions by a majority of votes. To date, the Brazilian Federal Supreme Court has not reached a final decision, and we do not know when such a decision may be reached. While the Brazilian Federal Supreme Court is reviewing the New Regulatory Framework, its provisions remain in effect. Regardless of the Brazilian Federal Supreme Court’s final decision, certain portions of the New Regulatory Framework relating to restrictions on distributors engaging in businesses unrelated to the distribution of electricity, including sales of energy by distributors to Free Consumers and the elimination of self-dealing, are expected to remain in full force and effect.

If the Brazilian Federal Supreme Court deems all or a material portion of the New Regulatory Framework to be unconstitutional, the regulatory scheme introduced by the New Regulatory Framework may become void, which will create uncertainty as to how and when the Brazilian government will be able to reform the electric energy sector.

Ownership Limitations

Under Resolution No. 378/2009, ANEEL submitted potential antitrust violations in the electric energy sector for analysis by the SDE, which has been the responsibility of CADE since Law No. 12,529/2011 went into effect. ANEEL also has the power to monitor potential antitrust activity, either at its own discretion or upon request of CADE, by identifying: (i) the relevant market; (ii) the influence of the parties involved in the exchange of energy on the submarkets where they operate; (iii) the actual exercise of market power in connection with market prices; (iv) the participation of the parties in the power generation market; (v) the transmission, distribution and commercialization of energy in all submarkets; and (vi) distribution entities’ efficiency gains during the tariff review process.

In practical terms, ANEEL’s role is limited to supplying CADE with technical information to support technical opinions by CADE. CADE, in turn, defers to ANEEL’s comments and decisions, and may only disregardthem if it demonstrates its reasons for doing so. Before Law No. 12,529/2011, certain responsibilities of CADE were performed by SDE and technical opinions regarding competition matters were issued by the SDE in the first instance and decided by CADE in the second instance.

System Tariffs

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

TUSD

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

·	The TUSD Wire (TUSD Fio), which is set in R$/kW, divided into time segments according to the tariff category, is applied to the electricity demand contracted by the party connected to the system, and remunerates the distribution and transmission concessionaire for costs of operating, maintaining and upgrading the distribution system. It also provides the distribution concessionaire with a legal margin.
·	The TUSD Charges (TUSD Encargos), which is set in R$/MWh, is applied to electricity consumption (in MWh) and contemplates certain regulatory charges applicable to the use of the local network, such as the Proinfa Program, the CDE Account, the TFSEE, the ONS and others. These charges are set by regulatory authorities and linked to the quantity of energy carried by the system.
·	The TUSD Loss (TUSD Perdas) compensates for technical losses of energy on the transmission and distribution systems, as well as non-technical losses of energy on the distribution system.

TUST

The TUST is paid by distribution companies, generation companies and Free Consumers who connect directly to the Basic Network. It applies to their use of the Basic Network and is revised annually according to (i) an inflation index; and (ii) the annual revenue of the transmission companies as determined by ANEEL. According to criteria established by ANEEL, owners of the different parts of the transmission network were required to transfer the coordination of their facilities to the ONS in return for receiving regulated payments from the transmission system users. Network users, including generation companies, distribution companies and Free Consumers directly connected to the transmission network, sign contracts with the ONS and the transmission companies (represented by the ONS) entitling them to the use of the transmission network in return for the payment of certain tariffs.

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

Basis for Calculation of Distribution Tariffs

ANEEL has the authority to adjust and review the above tariffs in response to changes in energy purchase costs and market conditions. When calculating distribution tariffs, ANEEL divides the costs of distributioncompanies between (i) costs that are not under the control of the distributor, or Parcel A Costs, and (ii) costs that are under the control of the distributor, or Parcel B Costs. The readjustment of tariffs is based on a formula that takes into account the division of costs between the two categories.

Parcel A Costs include, among others, the following factors:

·	costs of electricity mandatorily purchased from Itaipu and the generation companies renewed under Law No. 12,783/13;
·	costs of electricity purchased pursuant to bilateral agreements that are freely negotiated between the parties;
·	costs of electricity purchased pursuant to CCEARs;
·	certain other charges for use and connection to the transmission and distribution systems;
·	the cost of regulatory charges; and
·	the costs associated with research and development and energy-efficient consumption.

Parcel B Costs include, among others, the following factors:

·	a rate of return on investments in assets necessary to energy distribution activities (for more information, see “Item 5. Operating and Financial Review and Prospects—Background—Periodic Revisions – RTP”);
·	the depreciation on those assets;
·	the operating expenses related to the operation of those assets; and
·	irrecoverable receivables;

each as established and periodically revised by ANEEL.

The tariffs are established taking into consideration Parcel A and Parcel B Costs and certain market components used by ANEEL as reference for adjusting the tariffs.

Electricity distribution concessionaires are entitled to periodic revisions of their tariffs usually every four or five years. These revisions are aimed at:

assuring necessary revenues to cover efficient Parcel B operational costs and adequate compensation for investments deemed essential for the services within the scope of each such company’s concession;

incentivizing concessionaires to increase their efficiency levels; and

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

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

service quality; and

an operating expense target.

Increases in productivity and the operating expense target are determined at each periodic review. Starting in the fourth periodic revision cycle, the service quality is determined in connection with the annual adjustment and periodic review. For concessionaires whose contracts were extended in 2015 and that undergo tariff revisions after February 24, 2017, there will also be an annual update of the productivity (Pd) component.

The X factor is used to adjust the proportion of the change in the IGP-M/FGV index that is used in the annual adjustments. Accordingly, upon the completion of each periodic revision, application of the X factor requires distribution companies to share their productivity gains with Final Consumers.

Each distribution company’s concession agreement also provides for an annual adjustment. In general, Parcel A Costs are fully passed through to consumers. Parcel B Costs, however, are mostly restated for inflation in accordance with the IGP-M/FGV index and X factor. However, for concessionaires whose contracts were extended in 2015, the inflation index used to restate Parcel B is the IPCA.

In addition, electricity distribution concessionaires are entitled to an extraordinary tariff review (revisão extraordinária) on a case-by-case basis, to ensure their financial stability and compensate them for unpredictable costs, including taxes that significantly change their cost structure.

With the introduction of the New Regulatory Framework, the MME has acknowledged that the variable costs associated with the purchase of electric energy may be included by means of the Parcel A Account or CVA, an account created to recognize some of our costs when ANEEL adjusts the tariffs of our distribution subsidiaries. See “Item 5. Operating and Financial Review and Prospects—Overview—Recoverable Costs Variations—Parcel A Costs” for more information.

Beginning in 2005, the costs incurred with PIS and COFINS ceased to be considered in the periodic revisions as part of Parcel B, and electricity distribution concessionaires became entitled to add such costs directly over the tariffs established in the periodic revisions, based on an effective rate which is different than the nominal rate. The purpose of this change was to maintain neutrality in the financial equilibrium of the concession in view of the alteration in the way these taxes are collected, which became non-cumulative.

In December 2011, ANEEL established the methodology and procedures applicable to further periodic revisions as of that year. Previously, all revisions in methodologies were addressed in set cycles such as in 2008–2010 and 2010–2014. However, in 2015, ANEEL changed this procedure to allow for the review of the underlying methodologies applicable to the electricity sector from time to time on an item by item basis. See “Item 5. Operating and Financial Review and Prospects—Background” and “Item 3. Key Information—Risk Factors—The tariffs that we charge for sales of electricity to Captive Consumers and the tariffs for using the distribution system that we charge to Free and Special Consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us” for more information regarding tariff revisions and methodologies.

Since 2013, variables such as the need to dispatch of thermal plants have caused distributors to incur extraordinary costs that exceed their ability to pay. To cover the distributors’ involuntary exposure to these costs, a portion of the energy cost was reimbursed by the CDE Account (under Decree No. 7,945/2013) and the ACR Account (under Decree No. 8,221/2014). These reimbursements aimed to cover all or part of the costs incurred by distributors between January 2013 and December 2014 relating to (i) their involuntary exposure to the spot market and (ii) the dispatch of thermoelectric plants related to the CCEAR. The CCEE, which manages the ACR Account, obtained a credit facility from 13 banks to fund this payment. Starting January 2015, distribution companies have been collecting additional electricity tariffs from consumers in order to amortize the CDE reimbursement over five years and the credit facility over 54 months. The CDE quotas set by ANEEL in 2015 and passed through to consumers already take account of these obligations. In addition, since these CDE and energy purchase costs remain high, ANEEL increased tariffs by means of an extraordinary tariff review, the RTE, applicable to all distribution companies under Resolution No. 1,858 of February 27, 2015. This RTE aims to pass through to consumers the forecast costs in the period from March 2015 to the date of the distribution company’s next tariff review or adjustment. In September 2019, the credit facility referring to the ACR Account was paid in advance (the original maturity date was April 2020) after negotiations by ANEEL, MME and CCEE, withdrawing R$8.4 billion from Brazilian electricity bills until 2020.

In January 2015, the electricity sector began to implement a mechanism of monthly “tariff flags” under which consumer invoices may be subject to tariff additions on a monthly basis when energy supply costs reach certain levels, enabling consumers to adapt their usage to current energy costs. Previously, the pass-through of energy costs to tariffs was set annually. The tariff flag system was initially approved in 2011 and was tested during 2013 and 2014. At the beginning it consisted of a green (normal), yellow (heightened) or red (critical) tariff flag, determined by ANEEL on the basis of electricity generation conditions, pursuant to Decree 8,401 of February 4, 2015. As from February 1, 2016, the tariff system flag was modified by ANEEL, and currently consists of a green (normal), yellow (heightened) or two level of red (critical stage 1 and stage 2) tariff flags. Revenues billed under the tariff flag system are collected by the distribution companies and paid into a Tariff Flag Resources Centralizing Account (Conta Centralizadora dos Recursos de Bandeiras Tarifárias), or CCRBT administered by the CCEE from which the revenues are repaid to distribution companies on the basis of their relative energy cost for the period.

Due to the poor hydrological conditions that were observed from 2013 through 2015, red tariff flags were applied throughout 2015 since the system was introduced in January 2015. In 2016, due to an improvement in hydrological conditions, green tariff flags were applied in most months of the year, but 2017 consisted principally of yellow and red tariff flags. In 2018, green tariff flags were applied from January to April and again in December, yellow tariff flags were applied in May and November, and red tariff flags were applied from June to October. In 2019, green tariff flags were applied from January to April and again in June, yellow tariff flags were applied in May, July, October and December, and red tariff flags stage 1 were applied in August, September and November. Although this mechanism mitigates the cash flow mismatch in part, it may be insufficient to cover the thermoelectric energy supply costs, and distributors still bear the risk of cash flow mismatches in the short term.

Government Incentives to the Energy Sector

In 2000, a federal decree created the Thermoelectric Priority Program (Programa Prioritário de Termeletricidade), or PPT, for purposes of diversifying the Brazilian energy matrix and decreasing its strong dependency on Hydroelectric Power Plants. The incentives granted to the Thermoelectric Power Plants included in the PPT are: (i) guarantee of gas supply for up to twenty years, pursuant to MME regulations; (ii) an assurance that the costs related to the acquisition of the electric energy produced by Thermoelectric Power Plants will be transferred to tariffs up to the normative value established by ANEEL; and (iii) guaranteed access to a special financing program for the electric energy industry from BNDES.

In 2002, the Brazilian government established the Proinfa Program. Under the Proinfa Program, Eletrobras offers purchase guarantees of up to 20 years for energy generated from alternative sources, and this energy is acquired by distribution companies for delivery to Final Consumers. The purchase cost of this alternative energy is borne by the Final Consumers on a monthly basis (except for low income Final Consumers, who are exempt from such payments), based on an annual purchase estimation plan made by Eletrobras and approved by ANEEL. In its initial phase, the Proinfa Program was limited to a total contracted capacity of 3,299 MW. The objective of this initiative was to reach a contracted capacity of up to 10% of the total annual electricity consumption in Brazil within 20 years starting from 2002.

In order to create incentives for alternative generators, the Brazilian government has established that a reduction of not less than 50% applies to TUSD amounts owed by: (i) Hydroelectric Power Plants with capacity equal to or lower than 50,000 kW; and (ii) alternative energy generators (solar, wind power and biomass generators) with capacity up to 300,000 kW. As law and regulations change over the years, the applicable reductions are set forth in each power plant’s authorization. The reduction is applicable to the TUSD due by the generation entity and also by its consumer. The amount of the TUSD reduction is reviewed and approved by ANEEL and reimbursed through CDE, by an on a monthly basis deposit made by CCEE.

Regulatory Charges

EER

The EER is a regulatory charge assessed on a monthly basis designed to raise funds for energy reserves contracted by CCEE. These energy reserves are used to increase the safety of the energy supply in theInterconnected Power System. The EER is collected on a monthly basis from Final Consumers of the Interconnected Power System registered with CCEE.

RGR Fund and UBP

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

Independent Power Producers that use hydropower sources must also pay a fee similar to the fee levied on public service generation companies in connection with the RGR Fund. Independent Power Producers are required to make contributions for UBP, according to the rules set out in the public tender for the relevant concession and in ANEEL’s Normative Resolution No. 859/2019. Eletrobras received the UBP payments until December 31, 2002. All charges related to the UBP since December 31, 2002 have been paid directly to the Brazilian government.

CDE Account

In 2002, the Brazilian government instituted the CDE Account, which is funded through annual payments made by concessionaires for the use of public assets, penalties and fines imposed by ANEEL and the annual fees paid by agents offering electric energy to Final Consumers, by means of a charge to be added to the tariffs for the use of the transmission and distribution systems. These fees are adjusted annually. The CDE Account was originally created to support: (i) the development of energy production throughout Brazil; (ii) the production of energy by alternative energy sources; and (iii) the universalization of electric energy services throughout Brazil. In addition, the CDE Account subsidizes the operations of thermoelectric generation companies for the purchase of fuel in isolated areas not connected to the Interconnected Power System, which costs were supported by the CCC Account, before the enactment of Law No. 12,783/13. As from January 23, 2013, (Decree No. 7,891/13), the CDE Account subsidizes discounts for certain categories of consumers, such as Special Consumers, rural consumers, distribution concessionaires and permissionaires, among others. By Decree 7,945 dated March 7, 2013, the Brazilian government decided to use the CDE Account to subsidize: (i) a portion of the distribution companies’ energy costs on thermal generation in 2013; (ii) the hydrological risks of the generation concessions renewed under Law No. 12,783/13; (iii) the involuntary energy under contract shortage because some generation concessions did not seek to renew their contracts and the energy produced by those concessions could not be reallocated to distributors; and (iv) part of the ESS and the CVA, such that the impact of tariff adjustments in connection with these two accounts was limited to 3% of adjustments from March 8, 2013 to March 7, 2014. The CDE amounts authorized by Decree 7,945, dated March 7, 2013, were effective for five years and were no longer charged as of March 2019. The CDE Account will be in effect for 25 years from 2002. It is regulated by ANEEL and managed by CCEE.

ESS – System Service Charge

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

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

Fee for the Use of Water – CFURH

The current regulatory framework requires that holders of a concession and authorization to use water resources must pay a fee, which since the enactment of Law No. 13,360/2016 is 7.00% of the value of the energy they generate by using such facilities. This fee was previously 6.00% from 1998 to 2000, and 6.75% from 2000 to the enactment of Law No. 13,360/2016. This charge must be paid to the federal district, states and municipalities where the plant itself or the plant’s reservoir is located.

ANEEL Inspection Fee – TFSEE

The ANEEL Inspection Fee or TFSEE is an annual fee due by the holders of concessions, permissions or authorizations in the proportion of their dimension and activities.

ONS Fee

The ONS Fee, a monthly fee due by distribution concessionaires, is used to fund the budget of the ONS in its role to coordinate and control the production and transmission of energy in the Interconnected Power System.

Default on the Payment of Regulatory Charges

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

Energy Reallocation Mechanism

Centrally dispatched hydroelectric generators are protected against certain hydrological risks by the MRE, which attempts to mitigate the risks involved in the generation of hydrological energy by mandating that hydroelectric generators share the hydrological risks of the Interconnected Power System. Under Brazilian law, each Hydroelectric Power Plant is assigned an Assured Energy, which is determined in each relevant concession agreement, irrespective of the volume of electricity generated by the facility. The MRE transfers surplus electricity from those generators that have produced electricity in excess of their Assured Energy to those generators that have produced less than their Assured Energy. The effective generation dispatch is determined by ONS, who takes into account nationwide electricity demand and hydrological conditions. The volume of electricity actually generated by the plant, whether less than or in excess of the Assured Energy, is priced pursuant to a tariff denominated Energy Optimization Tariff (Tarifa de Energia de Otimização), which covers the operation and maintenance costs of the plant. This revenue or additional expense must be accounted for monthly by each generator.

Generation Scaling Factor

The Generation Scaling Factor, or GSF, is a ratio that compares the sum of the volume of energy generated by all hydroelectric companies participating in the MRE to the volume of Assured Energy that they committed to deliver in their contractual obligations. If the GSF ratio is below 1.0,i.e., less than the total Assured Energy is being generated, hydroelectric companies must purchase energy in the spot market to cover the energy shortage and meet their Assured Energy volumes under the MRE. From 2005 to 2012, the GSF remained above 1.0. The GSF began to deteriorate in 2013, worsening in 2014 when the GSF remained below 1.0 for the entire year. In 2015, the GSF ranged from 0.783 to 0.825, requiring electricity generators to purchase energy in the spot market, thereby incurring significant costs.

Following discussions between generation companies and the Brazilian government regarding these costs, the government enacted Federal Law 13,203 on December 8, 2015. This law addressed the GSF risk separately for the Regulated Market and the Free Market. In the Regulated Market, Federal Law 13,203 allowed generation companies to renegotiate their PPAs, setting the GSF cost at a risk premium of R$9.50/MWh per year through the end of the PPA or the end of the concession, whichever occurs sooner. This risk premium payment will be paid to the CCRBT.

In December 2015, our subsidiaries CERAN, CPFL Jaguari Geração (Paulista Lajeado) and CPFL Renováveis, as well as joint ventures ENERCAN and Chapecoense opted to renegotiate their Regulated Market contracts, and also cancelled their lawsuits. In January 2016, our joint venture BAESA opted to renegotiate its Regulated Market contracts. Therefore, the hydrologic risks were transferred to the CCRBT.

ITEM 4A. UNRESOLVED STAFF COMMENTS

None.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion should be read in conjunction with our audited annual consolidated financial statements and the notes thereto included elsewhere in this annual report.

We prepared our audited annual consolidated financial statements included in this annual report in accordance with IFRS, as issued by the IASB. As of January 1, 2019, IFRS 16 and IFRIC 22 came into effect. See Note 3.17 of our audited annual consolidated financial statements for the effects of our adoption of such new IFRS standards.

Beginning in 2018, all segment information related to prior periods was reclassified to conform to the 2018 presentation due to the way our new management monitors segment results. As a result, (i) intangible assets acquired in business combination transactions that are recorded in the parent company and were previously allocated to the respective segments are now allocated to the segment “Others”; and (ii) eliminations between different segments are now classified in the “elimination” column instead of being presented in each segment.

Overview

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

Two important drivers of our financial performance are our operating income margin and cash flows from our regulated distribution business. In recent years, our regulated distribution business has produced reasonably stable margins, and its cash flows, while sometimes subject to short-term variability, have been stable over the medium term. Nevertheless, there are factors beyond our control that can have a significant impact, positive or negative, on our financial performance. We face periodic changes in our tariff structure, resulting from the periodic regulatory review of our tariffs. Every periodic review since 2015, including the periodic tariff review of CPFL Piratininga performed in 2019, has resulted in an increase in the average tariffs. See “—Background—Periodic Revisions—RTP” for more information.

Background

Regulated Distribution Tariffs

Our results of operations are significantly affected by changes in regulated electricity tariffs. In particular, most of our revenues are derived from sales of electricity to Captive Consumers at regulated tariffs. In 2019, sales to Captive Consumers represented 62.47% of the volume of electricity we delivered and 65.7% of our operating revenues, compared to 66.2% of the volume of electricity we delivered and 63.3% of our operating revenues in 2018. These proportions may decline if consumers migrate from captive to free status.

Our operating revenues and our margins depend substantially on the tariff-setting process, and our Management focuses on maintaining a constructive relationship with ANEEL, the Brazilian government and other market participants so that the tariff-setting process fairly reflects our interests and those of our consumers and shareholders. See “Item 4. Information on the Company—Basis for Calculation of Distribution Tariffs” for a description of tariff regulations.

Tariffs are determined separately for each of our four distribution subsidiaries as follows:

·	Our concession agreements provide for an annual adjustment to take account of changes in our costs, which for this purpose are divided into costs that are beyond our control (known as Parcel A Costs) and costs that we can control (known as Parcel B Costs). Parcel A Costs include, among other things, increased prices under long-term supply contracts, and Parcel B Costs include, among others, the return on investment related to our concessions and their expansion, as well as maintenance and operational costs. Our ability to fully pass through our electricity acquisition costs to Final Consumers is subject to: (a) our ability to accurately forecast our energy needs and (b) a ceiling linked to a reference value, the Annual Reference Value. The Annual Reference Value is the weighted average of electricity acquisition costs resulting from electricity prices of all public auctions carried out by ANEEL and CCEE in the Regulated Market for electricity to be delivered five and three years from any such auction and only applies during the first three years following the commencement of delivery of the acquired electricity. See “Item 4. Information on the Company—The New Regulatory Framework” for more information regarding all the limitations on the ability of distribution companies to fully pass through their electricity acquisition costs to Final Consumers. Under agreements that were in force before the enactment of these regulatory reforms, we pass through the costs of acquired electricity subject to a ceiling determined by the Brazilian government. The annual tariff adjustment occurs every April for CPFL Paulista, every June for RGE, every October for CPFL Piratininga and every March for CPFL Santa Cruz. There is no annual adjustment in a year with a periodic revision.
·	Our concession agreements provide for a periodic revision (revisão periódica), every five years for CPFL Paulista, CPFL Santa Cruz and RGE, and every four years for CPFL Piratininga in order to restore the financial equilibrium of our tariffs as contemplated by the concession agreements and to determine a reduction factor (known as the X factor) in the amount of any increase to Parcel B Costs passed on to all of our consumers. ANEEL’s Resolution No. 457/2011 has established the methodology to be applied to the third periodic revision cycle (2011 to 2014). As of 2015, ANEEL now reviews the underlying methodologies applicable to the electricity 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. See “Item 3. Key Information—Risk Factors—The tariffs that we charge for sales of electricity to Captive Consumers and the tariffs for using the distribution system that we charge to Free and Special Consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us” and “Item 4. Information on the Company—Basis for Calculation of Distribution Tariffs” for more information.

Brazilian law also provides for an extraordinary revision (revisão extraordinária) to take account of unforeseen changes in our cost structure. The last extraordinary revisions took place on January 24, 2013 and February 27, 2015. The 2013 event aimed to adjust our tariffs as a result of the changes introduced by Law No. 12,783/13. Law No. 12,783/13 reduced the CDE Account charge and eliminated the CCC Account and RGR Fund charges, therefore reducing the Parcel A Costs (energy prices, charges for the use of the Basic Network and regulatory charges, which we pass on to our consumers). In 2015, tariffs were increased to take into account the extraordinary costs due to the full dispatch of thermal plants and distributors’ involuntary exposure. No extraordinary revision occurred in 2017, 2018 and 2019.

Tariff Adjustments

Our concession agreements and Brazilian law establish a mechanism that allows for three types of tariff adjustments: (i) annual adjustments (RTA), (ii) periodic revisions (RTP) and (iii) extraordinary revisions (RTE). We are entitled to apply each year for the RTA, 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 every four or five years (according to the terms of each concession agreement). As such, it aims to identify variations in our costs and set an adjustment factor based on our operational efficiency that will be applied against the index of our ongoing annual tariff adjustments. RTEs may occur at any time, or may be requested by us. There have been no RTEs of our tariffs since 2015.

The following table sets forth the average percentage increase in our tariffs resulting from each annual adjustment and periodic revision from 2017 through the date of this annual report. Rates of tariff increase should be evaluated in light of the Brazilian inflation rate. See “—Background—Brazilian Economic Conditions” for more information.

	CPFL Paulista	CPFL Piratininga	RGE⁽⁵⁾	RGE Sul	CPFL Santa Cruz⁽⁴⁾	CPFL Mococa⁽⁴⁾	CPFL Leste Paulista⁽⁴⁾	CPFL Sul Paulista⁽⁴⁾	CPFL Jaguari⁽⁴⁾
2020
Economic adjustment⁽¹⁾	6,09%⁽⁷⁾	⁽³⁾	⁽⁶⁾	⁽⁵⁾	3.20%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
Regulatory adjustment⁽²⁾	8,80%⁽⁷⁾	⁽³⁾	⁽⁶⁾	⁽⁵⁾	7.51%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
Total adjustment	14,09%⁽⁷⁾	⁽³⁾	⁽⁶⁾	⁽⁵⁾	10.71%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
2019
Economic adjustment⁽¹⁾	2.95%	(5.40)%	0.05%	⁽⁵⁾	2.02%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
Regulatory adjustment⁽²⁾	9.07%	7.27%	10.0%	⁽⁵⁾	11.68%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
Total adjustment	12.02%	1.88%	10.05%	⁽⁵⁾	13.70%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
2018
Economic adjustment⁽¹⁾	8.67%	8.83%	15.56%	11.57%	4.41%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
Regulatory adjustment⁽²⁾	4.01%	11.18%	5.71%	6.88%	1.30%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
Total adjustment	12.68%	20.01%	21.27%	18.45%	5.71%	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾	⁽⁴⁾
2017
Economic adjustment⁽¹⁾	2.13%	6.33%	2.37%	2.95%	1.37%	3.45%	3.18%	0.97%	3.88%
Regulatory adjustment⁽²⁾	(2.93)%	1.37%	1.21%	(3.15)%	(2.65)%	(1.80)%	(2.41)%	0.66%	(1.83)%
Total adjustment	(0.80)%	7.69%	3.57%	(0.20)%	(1.28)%	1.65%	0.77%	1.63%	2.05%

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

(2)	This portion of the adjustment reflects settlement of regulatory assets and liabilities we present in our regulatory financial information, primarily the CVA, and is not considered in the calculation of the following year’s adjustment.
(3)	Annual adjustments for CPFL Piratininga occur in October.
(4)	CPFL Santa Cruz, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista merged into CPFL Santa Cruz (formerly CPFL Jaguari) effective as of January 1, 2018. See “Item 4. Information on the Company—Overview” for more information.
(5)	RGE merged into RGE Sul (which now operates under the name RGE) effective as of January 1, 2019. See “Item 4. Information on the Company—Overview”.
(6)	Annual adjustments for RGE occur in June.
(7)	Homologatory Resolution No. 2,670/2020, dated April 7, 2020, approved the tariff readjustment of CPFL Paulista. However, due to the public calamity caused by the COVID-19 pandemic, the distributor and ANEEL agreed that the tariffs existing prior to the readjustment will remain in effect until June 30, 2020. In return, CPFL Paulista is not required to make payments to the CDE Account during the same period. As of July 1, 2020, the new tariffs will come into effect and CDE Account payments will resume. The portion of the payments to the CDE Account that will not be paid from April to June shall be paid to the CDE Account in up to six installments, beginning in July 2020, adjusted by the SELIC rate. Additionally, the difference in revenue from the readjusted tariff and the previous tariff will be adjusted following the effective market rate until June 30, 2020 plus the SELIC rate and considered in the subsequent tariff process.

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

On December 4, 2018, through the Resolution for Authorization No. 7,499/2018, ANEEL approved our proposal to consolidate the concessions of our two distribution companies (RGE and RGE Sul), pursuant to Normative Resolution No. 716/2016, amended by Normative Resolution No. 835/2018. RGE merged into RGE Sul (which now operates under the name RGE) effective as of January 1, 2019. This transaction was approved at the Extraordinary General Meetings held on December 31, 2018 at each of RGE and RGE Sul. This merger is expected to optimize our administrative and operational costs and produce large-scale savings and synergy in 2020. See “Item 4. Information on the Company—Overview”.

With respect to the RTP, on April 28, 2015, ANEEL established the methodology to be applied in the fourth periodic revision cycle (2015 to 2018) through Resolutions Nos. 648/2015, 649/2015, 650/2015, 652/2015, 657/2015, 660/2015, 682/2015, 685/2015 and 686/2015. The fourth cycle maintains most of the parameters used for the third cycle, such as the definition, by ANEEL, of the costs we may pass to our consumers. Some of the changes for the fourth cycle include a tariff incentive to the development of certain public policies and also the increased importance of the X Factor component in the new tariff formula. Compared to the previous tariff cycle, the new methodology positively impacted our financial condition and results of operations.

As of 2015, ANEEL now reviews the underlying methodologies applicable to the electricity 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.

During 2019, ANEEL held Public Hearing No. 09/2019 and Public Consultation 26/2019, or “CP 26/19,” with proposals to review the calculation methodology for the regulatory rate of return on capital, or “Regulatory WACC,” for the distribution, transmission and quota renewed generation of electric power segments.

On March 10, 2020, ANEEL approved in a public meeting the result of CP 26/2019 (Normative Resolution No. 874/2020). The approved WACC (real, after tax), is:

	Final Results of Public Consultation 26/2019
Regulatory WACC % (real, after tax)	Transmission Segment & Generation Renewed Quota Segment	Distribution Segment
2020	7.66%	⁽¹⁾
2019	7.39%	⁽¹⁾
2018	6.98%	7.32%

(1) For the years ended December 31, 2019 and 2018, in the distribution segment, the WACC (real, after tax) was 8.09% pursuant to Normative Resolution No. 807, of March 6, 2018.

Sales to Potential Free Consumers

Brazilian regulations permit Potential Free Consumers to opt out of the Regulated Market and become Free Consumers who contract freely for electricity. See “Item 4. Information on the Company—The New Regulatory Framework—The Free Market” for more information. Our Potential Free Consumers represent a relatively small portion of our total revenues, as compared to our Captive Consumers. These revenues consist of energy sales and TUSD network charges. If a Potential Free Consumer migrates from the Regulated Market and purchases energy in the Free Market, we no longer receive the energy sales revenues, but the Free Consumer is still required to pay us the TUSD network usage charge for their energy. Regarding the reduction in energy sales revenues, we are able in some cases to reduce our energy purchases by the amount required to service these customers in the year of the consumer’s migration, while in other cases we are able to offset the excess by adjusting our energy purchases in future years. Accordingly, we do not believe that the loss of Potential Free Consumers would have a material adverse effect on our results of operations.

Historically, relatively few of our Potential Free Consumers have elected to become Free Consumers. We believe this is because: (i) they consider the advantages of negotiating for a long-term contract at rates lower than the regulated tariff are outweighed by the need to bear additional costs (particularly transmission costs) and long-term price risk; and (ii) some of our Potential Free Consumers who have contracted demand lower than 2.0 MW, may only change to suppliers that purchase from renewable energy sources, such as Small Hydroelectric Power Plants or biomass. We do not expect that a substantial number of our consumers will become Free Consumers, but the prospects for migration between the different markets (Captive and Free Markets) over the long term, and its long-term implications for our financial results, are difficult to predict.

Prices for Purchased Electricity

The prices of electricity purchased by our distribution companies under long-term contracts executed in the Regulated Market are: (i) approved by ANEEL in the case of agreements entered into before the New Regulatory Framework; and (ii) determined in auctions for agreements entered into thereafter, while the prices of electricity purchased in the Free Market are agreed by bilateral negotiation based on prevailing market rates. In 2019, we purchased 78,406 GWh, compared to 73,689 GWh in 2018. The increase of 6.4%, or 4,717 GWh, was due to (i) an increase of 7.8%, or 4,822 GWh, in the volume of energy purchased through auctions in the Regulated Market, bilateral contracts and the spot market and (ii) a decrease of 0.9%, or 96 GWh, in purchases from Itaipu, each of which were driven by our increased electricity sales, and (iii) a decrease of 0.8%, or 9 GWh, in electricity purchased for resale under the Proinfa Program. Prices under long-term contracts are adjusted annually to reflect increases in certain generation costs and inflation. Most of our contracts have adjustments linked to the annual adjustment in distribution tariffs, so that the increased costs are passed through to our consumers in increased tariffs. Since an increasing proportion of our energy is purchased at public auctions, the success of our strategies in these auctions affects our margins and our exposure to price and market risk, as our ability to pass through costs of electricity purchases depends on the successful projection of our expected demand.

We also purchase a substantial amount of electricity from Itaipu under take-or-pay obligations at prices that are governed by regulations adopted under an international agreement. Electric utilities operating under concessions in the Midwest, South and Southeast regions of Brazil are required by law to purchase a portion of Brazil’s share of Itaipu’s available capacity. In 2019, we purchased 11,021 GWh of electricity from Itaipu (14.1% of the electricity we purchased in terms of volume), as compared to 11,117 GWh (15.1% of the electricity we purchased in terms of volume) in 2018. See “Item 4. Information on the Company—Distribution—Purchases of Electricity” for more information. The price of electricity from Itaipu is set in U.S. dollars to reflect the costs of servicing its indebtedness. Accordingly, the price of electricity purchased from Itaipu increases in Brazilianreaiswhen therealdepreciates against the U.S. dollar (and decreases when therealappreciates). The change in our costs for Itaipu electricity in any year is subject to the Parcel A Cost recovery mechanism described below.

Most of the electricity we acquired in the Free Market was purchased by our commercialization subsidiary CPFL Brasil, which resells electricity to Free Consumers and other concessionaires and licensees (including our subsidiaries). See “—The New Regulatory Framework—The Free Market” for more information.

Recoverable Cost Variations—Parcel A Costs

We use the CVA (the Parcel A cost variation account) to recognize some of our costs in the distribution tariff, referred to as “Parcel A Costs,” that are beyond our control. When these costs are higher than the forecasts used in setting tariffs, we are generally entitled to recover the difference through subsequent annual tariff adjustments.

The costs of electricity purchased from Itaipu are set in U.S. dollars and are therefore subject to U.S. dollar exchange rates. If the U.S. dollar appreciates against thereal, our costs will increase and, consequently, our income will decrease in the same period. These losses will be offset in the future, when the next annual tariff adjustments occur.

See Note 9 to our audited annual consolidated financial statements and “—Sector financial assets and liabilities.”

Sector financial assets and liabilities

According to the tariff-pricing mechanism applicable to the distribution companies, energy tariffs should be set at a price level (price-cap) that ensures the economic and financial equilibrium of the concession. Therefore, concessionaires are authorized to charge consumers (i) an annual tariff increase (after review and ratification by ANEEL) and (ii) usually every four or five years, as specified in the concession contract, the periodic review adjustment used to recalculate Parcel A and Parcel B adjustments of certain tariff components, such as changes in the cost of energy purchased and return in infrastructure investments. Furthermore, since January 2015, the electricity sector has implemented a mechanism of monthly “tariff flags,” under which consumer invoices may be subject to tariff additions on a monthly basis when energy supply costs reach certain levels. See “Item 4. Information on the Company—Basis for Calculation of Distribution Tariffs” for more information on the tariff flags system.

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

This tariff-pricing mechanism may lead to timing differences between the budgeted costs (Parcel A and other financial components) included in the tariff at the beginning of the tariff period and those actually incurred while it is in effect. This difference creates a contractual right to receive cash from consumers through subsequent tariffs, or to pay to (or receive from) the granting authority any remaining amounts at the expiration of the concession (see Note 9 to our audited annual consolidated financial statements). This leads to an adjustment to recognize the future increase (or decrease) in tariffs to take account of additional (or lower) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue recorded as sector financial assets or liabilities.

On November 25, 2014, ANEEL approved an amendment to distribution concession contracts. On December 10, 2014, the nine distribution subsidiaries we had at that time signed this addendum. This amendment introduced a new clause providing compensation for any outstanding balance (assets or liabilities) related to insufficient collection or reimbursement through the tariffs resulting from termination of the concession. This provision, which comes into effect once an addendum to each specific concession contract is executed, provides that the concessionaire has the unconditional right (or obligation) to receive (or deliver) cash or another financial instrument in respect of this amount. See Note 9 to our audited annual consolidated financial statements for more information.

Operating Segments

As discussed in Note 31 to our audited annual consolidated financial statements, we present our financial results in five operating segments: (i) distribution; (ii) conventional generation sources; (iii) renewable generation sources; (iv) commercialization; and (v) services.

In addition to our five operating segments above, we consolidate a number of activities known as “Other.” The activities consolidated under Other consist of (i) CPFL Telecom and (ii) our holding company expenses.

The profitability of each of our segments differs. Our distribution segment primarily reflects sales to Captive Consumers and TUSD charges paid by Free Consumers at prices determined by the regulatory authority. The volume sold varies according to external factors such as weather, income level and economic growth. This segment represented 81.1% of our net operating revenue in 2019 (compared with 79.9% in 2018), and its contribution to our profit for the year was also larger, at 66.8% of our profit for the year, as further explained in “—Results of Operations—2019 compared to 2018—Profit for the year” below (by comparison, our distribution segment accounted for 66.1% of our profit for the year in 2018 and 53.5% in 2017).

The contributions of our distribution, conventional generation, renewable generation, commercialization and services segments (disregarding our Others segment and intercompanies’ amounts) to the net operating revenues and profit for the year for the years ended December 31, 2019, 2018 and 2017 are presented in the following table:

	Distribution	Conventional Generation	Renewable Generation	Commercialization	Services	Other	Total
2019
Net operating revenue	81.1%	4.1%	6.4%	11.7%	2.1%	-5.3%	100.0%
Profit for the year	66.8%	31.4%	3.9%	1.7%	3.0%	-6.8%	100.0%
2018
Net operating revenue	79.9%	4.1%	6.9%	12.4%	1.9%	-5.1%	100.0%
Profit for the year	66.1%	35.5%	5.5%	2.5%	2.0%	-11.6%	100.0%
2017
Net operating revenue	78.8%	4.5%	7.3%	12.8%	1.8%	-5.2%	100.0%
Profit for the year	53.5%	52.6%	1.6%	7.3%	4.4%	-19.4%	100.0%

Our conventional generation sources segment consists in substantial part of Hydroelectric Power Plants, and our renewable generation sources segment consists of wind farms, Biomass Thermoelectric Power Plants, Small Hydroelectric Power Plants and a Solar Power Plant. All of our generation sources require a high level of investment in fixed assets, and in the early years there is typically a high level of construction financing. Once these projects become operational, they generally result in a higher margin (operating income as a percentage of revenue) than the distribution segment, but will also contribute to higher interest expenses and other financing costs. In 2017, we began to report within our conventional generation segment the activities of our two transmission assets held through CPFL Geração, CPFL Piracicaba and CPFL Morro Agudo, both of which are operational.

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

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

Our segments also purchase and sell electricity and value-added services from and to one another. In particular, our conventional generation sources, renewable generation sources, commercialization and services segments all sell electricity and provide services to our distribution segment. Our audited annual consolidated financial statements eliminate revenues and expenses that relate to sales from one subsidiary to another within a segment, which is reflected in the column entitled “Elimination” in the table below. However, the analysis of results by segment would be inaccurate if the same elimination were carried through with respect to sales between segments. As a result, sales from one segment to another have not been eliminated in the discussion of results by segment below.

We present below selected financial information of our five reportable segments as of and for the years ended December 31, 2019, 2018 and 2017:

	Distribution	Conventional Generation Sources	Renewable Generation Sources	Commercialization	Services	*Other^()**	Elimination	Total
2019
Net operating revenue	24,217,986	710,730	1,426,648	3,487,008	87,791	2,311	-	29,932,474
(-) Inter-segment Revenues	42,311	502,151	501,363	3,696	526,574	-	(1,576,095)	-
Income from electric energy service	2,875,809	838,765	557,810	92,442	111,848	(113,225)	-	4,363,450
Financial income	624,459	45,323	172,658	33,461	6,062	49,578	(27,966)	903,575
Financial expense	(821,739)	(197,998)	(576,292)	(56,160)	(4,270)	(1,329)	27,966	(1,629,822)
Profit (loss) before taxes	2,678,529	1,035,180	154,176	69,744	113,639	(64,976)	-	3,986,293
Income tax/social contribution	(843,954)	(171,594)	(47,152)	(22,269)	(30,357)	(122,671)	-	(1,237,996)
Profit (loss) for the year	1,834,575	863,586	107,024	47,475	83,282	(187,647)	-	2,748,296
2018
Net operating revenue	22,457,079	661,831	1,468,254	3,491,300	58,163	-	-	28,136,627
(-) Inter-segment Revenues	10,238	482,548	468,065	5,152	474,646	-	(1,440,650)	-
Income from electric energy service	2,237,434	820,979	585,655	94,074	72,579	(102,255)	-	3,708,467
Financial income	574,685	75,844	131,694	46,102	5,782	(22,092)	(49,602)	762,413
Financial expense	(884,583)	(324,121)	(635,820)	(59,128)	(5,908)	(5,143)	49,602	(1,865,100)
Profit (loss) before taxes	1,927,537	906,899	81,530	81,049	72,453	(129,490)	-	2,939,977
Income tax/social contribution	(495,120)	(137,089)	37,276	(27,945)	(29,529)	(121,575)	-	(773,982)
Profit (loss) for the year	1,432,416	769,810	118,805	53,104	42,924	(251,065)	-	2,165,995
2017⁽¹⁾
Net operating revenue	21,068,435	741,842	1,489,932	3,402,804	40,611	1,281	-	26,744,905
(-) Inter-segment Revenues	8,182	448,427	469,152	11,297	444,935	-	(1,381,993)	-
Income from electric energy service	1,530,833	765,990	604,596	167,724	67,598	(114,906)	-	3,021,834
Financial income	597,203	108,433	137,765	25,895	11,349	20,505	(20,835)	880,314
Financial expense	(1,163,689)	(437,009)	(648,571)	(58,801)	(7,101)	(73,532)	20,835	(2,367,868)
Profit (loss) before taxes	964,347	749,805	93,789	134,818	71,846	(167,933)	-	1,846,670
Income tax/social contribution	(299,510)	(95,688)	(74,125)	(44,527)	(16,994)	(72,784)	-	(603,629)
Profit (loss) for the year	664,837	654,117	19,665	90,290	54,852	(240,717)	-	1,243,044

(*)

Refers to recorded assets and transactions that are not related to any of our operating segments.

(1)

Beginning in 2018, due to the way our new Management monitors segment results, (i) intangible assets acquired in business combination transactions that are recorded in the parent company and were previously allocated to the respective segments are now allocated to the segment “Others”; and (ii) eliminations between different segments are now classified in the “elimination” column instead of being presented in each segment. For comparison purposes, the segment information disclosed for 2017 has been restated using the same criteria.

We also derive non-material income at the parent company level that is not related to or included in the results of our reportable segments and is reflected in the column “Other” in the table above. General expenses and indirect costs are generally allocated to the relevant segment and are reflected in the operating results of our reporting segments. Other expenses incurred by the parent company that can be directly allocated to a specific segment, are also allocated to our reporting segments.

Brazilian Economic Conditions

All of our operations are in Brazil, and we are affected by general Brazilian economic conditions. See “Item 3. Key Information—Risk Factors—Risks Relating to Brazil” for more information and “Item 3. Key Information—Risk Factors—Risks Relating to our Operations and the Brazilian Power Industry—An occurrence of a natural disaster, widespread health epidemic or pandemic or other outbreaks could significantly harm our business, financial condition and results of operations. Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in sporadic volatility in global markets. As a result, the Brazilian economy and outlook may be affected, and consequently, our business, financial condition and trading price of our common shares may be adversely affected” for information concerning the risks relating to the COVID-19 pandemic. In particular, the general performance of the Brazilian economy affects demand for electricity, and inflation affects our costs and our margins.

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

·	Residential and Commercial Consumers. These segments are highly affected by weather conditions, labor market performance, income distribution and credit availability, amongst other factors. Elevated temperatures and increases in income levels cause an increased demand for electricity and, therefore, increase our sales. Conversely, rising unemployment and decreasing household income tend to reduce demand and depress our sales.
·	Industrial consumers. Consumption for industrial consumers is related to economic growth and investments, mostly correlated to industrial production. During periods of financial crisis, this category suffers the strongest impact.

Inflation primarily affects our business by increasing operational costs and financial expenses to service our inflation-indexed debt instruments. We are able to recover a portion of these increased costs through a recovery mechanism, but there is a delay in time between when the increased costs are incurred and when the increased revenues are received following our annual tariff adjustments. The amounts owed to us under Parcel A Costs are primarily indexed to the variation of the SELIC rate until they are passed through to our tariffs and Parcel B costs are indexed to the IGP-M/FGV net of factor X (see “Item 4. Information on the Company—Basis for Calculation of Distribution Tariffs”).

Depreciation of therealincreases the cost of servicing our foreign currency denominated debt and the cost of purchasing electricity from the Itaipu Power Plant, a Hydroelectric Facility that is one of our major suppliers and that adjusts electricity prices based in part on its U.S. dollar costs.

The following table shows the main performance indicators of Brazilian economy for the years ended December 31, 2019, 2018 and 2017:

	2019	2018	2017
Growth in GDP (in reais)⁽¹⁾	1.1%	1.3%	1.3%
Unemployment rate - % average⁽²⁾	11.9%	12.3%	12.7%
Credit to individuals (non-earmarked resources) - % GDP	15.4%	13.9%	13.0%
Growth in Retail Sales	1.8%	2.3%	2.1%
Growth (contraction) in Industrial Production	(1.1%)	1.0%	2.5%
Inflation (IGP-M/FGV)⁽³⁾	7.3%	7.5%	(0.5%)
Inflation (IPCA)⁽⁴⁾	4.3%	3.7%	2.9%
Average exchange rate–US$1.00⁽⁵⁾	R$3.94	R$3.65	R$3.19
Year-end exchange rate–US$1.00	R$4.03	R$3.87	R$3.31
Depreciation (appreciation) of the real vs. U.S. dollar	4.1%	16.9%	1.5%

Sources:Focus Report, Instituto Brasileiro de Geografia e Estatística and the Brazilian Central Bank.

(1) Source: The Brazilian Institute for Geography and Statistics (Instituto Brasileiro de Geografia e Estatística, or IBGE).

(2) Unemployment rate based on the National Household Sampling Survey (Pesquisa Nacional por Amostra de Domicílios, or PNAD), released by IBGE.

(3) Inflation (IGP-M/FGV) is the general market price index measured by the Fundação Getúlio Vargas.

(4) Inflation (IPCA) is a broad consumer price index measured by IBGE and the reference for inflation targets set forth by the CMN.

(5) Represents the average of the commercial selling exchange rates on the last day of each month during the period.

The year 2016 in Brazil was marked by strong economic contraction with significant political crises and uncertainties, and poor economic indicators. However, in 2017 and 2018, the Brazilian economy began to improve, showing recovery in principal areas of activity and financial indicators, with GDP growth of 1.3% in each year (compared to a GDP contraction of 3.3% in 2016), according to IBGE. In 2019, Brazilian economic growth was 1.1%. Several events affected the Brazilian economy in 2019, posing an obstacle to a more robust growth, such as: (i) the Brumadinho dam collapse, which led to a sharp drop in iron ore extraction; (ii) the ongoing recession in Argentina, which negatively affects Brazilian exports, particularly that of manufactured goods; and (iii) the decelerating global economy and reductions in international trade.

The recovery of household consumption was maintained as result of a gradual acceleration of employment in 2019, coupled with the improvement in credit conditions such as the reduction of household indebtedness and interest rates. According to IBGE, household consumption increased 1.8% in 2019, compared to a 2.1% growth in 2018. The unemployment rate, income and credit statistics, which are key indicators of electricity consumption, demonstrated a significant recovery in 2017, 2018 and 2019.

Despite the modest growth in the Brazilian economy in 2019, our industry experienced worse results in 2019 when compared to 2018. This decline in industry results was due to two main factors: (i) the collapse in mineral extraction resulting from the Brumadinho damn collapse; and (ii) a sharp decline in exports, mainly to Argentina, which is one of the main buyers of Brazilian manufactured products.

In 2019, the inflation rate (IPCA) reached a historical low level and was below the central target set forth by the CMN throughout the year. In November and December, hikes in protein prices driven by a shortage of pork in China brought the inflation rate closer to the target (4.25% end of period). Nevertheless, underlying inflation and core measures still reflect low capacity use, which allowed for a more flexible monetary policy. As a result, the Brazilian Central Bank was able to sustain continued reductions in the SELIC rate from July 2019 on, reaching 3.75% in March 2020.

Given the improvements in various macroeconomic factors in 2019, Brazil experienced an upgrade in its rating outlook from Standard & Poor’s in December 2019. This assessment reflects the passing of the social security reform bill, which is expected to prevent a marked long-term increase in social security spending, and consolidated the view that a structural interest rate decrease is underway, so that the yield curve overall corrected sharply, with reduced long-term rates.

Our credit risk and debt securities are rated by Standard and Poor’s, Fitch Ratings and Moody’s Investors Service. These classifications reflect, among other factors, the outlook for the Brazilian electricity sector, the political and economic context, country risk, hydrological conditions in the areas where our plants are located, our operational performance and our level of debt. In 2019, our rating was maintained as AAA with a stable outlook by Standard and Poor’s, Moody’s Investors Service and Fitch Rating.

Results of Operations—2019 compared to 2018

Net Operating Revenues

Compared to the year ended December 31, 2018 our net operating revenues increased 6.4% (or R$1,795 million) to R$29,932 million in the year ended December 31, 2019.

This increase in operating revenue was primarily due to the combined effect of: (i) an increase of R$2,417 million in revenue due to TUSD for Captive and Free Consumers; (ii) an increase of R$1,068 million in electricity sales to Final Consumers (net amount, considering of reclassification to network usage charge – TUSD – Captive Consumers), as discussed in the section “—Sales by Destination” below; and (iii) an increase of R$390 million in other concessionaires and licensees. These increases were partially offset by (i) a decrease of R$1,810 million in sector financial assets and liabilities; and (ii) an increase of R$587 million in deductions from operating revenues, as discussed in the section “—Deductions from operating revenues” below, which represents a decrease in net operating revenues.

The following discussion describes changes in our net operating revenues by destination and by segment, based on the items comprising our gross revenues.

Sales by Destination

Sales to Final Consumers

Compared to the year ended December 31, 2018, our gross operating revenues from sales to Final Consumers (which includes TUSD revenue from Captive Consumers) increased 9.44% (or R$2,740 million) in the year ended December 31, 2019, to R$31,761 million. Our gross operating revenues primarily reflect sales to Captive Consumers in concession areas from our distribution subsidiaries, as well as TUSD revenue from the use of our network by Captive Consumers, both of which are subject to tariff adjustment as described below. Our gross operating revenue also reflects sales to Free Consumers in commercial and industrial categories.

Distribution companies’ tariffs are adjusted every year, in percentages specific to each category of consumer. The month in which the annual tariff adjustment becomes effective varies by subsidiary, impacting both the year in which the tariff adjustment occurs as well as the following year. The adjustments for our largest subsidiaries occur in April (CPFL Paulista), June (RGE Sul) and October (CPFL Piratininga).

In the year ended December 31, 2019, overall average energy prices increased by 12.4%, mainly due to the result of the RTP for CPFL Piratininga and the RTA for CPFL Paulista, RGE Sul and CPFL Santa Cruz. In 2019, our tariff adjustments were of 13.7%, 12.0%, 10.1% and 1.9% for CPFL Santa Cruz, CPFL Paulista, RGE Sul and CPFL Piratininga, respectively. Furthermore, the green and yelow tariffs flags were in effect for the most part of 2019. For further information, see Note 27.2 of our audited annual consolidated financial statements. Overall, average prices for Final Consumers in 2019 were lower for all consumer classes:

·	Residential and commercial consumers. With respect to Captive Consumers (which represent 97.9% of the total R$22,032 million sold to this category in our consolidated statements), average prices decreased 9.2% for residential consumers and 7.9% for commercial consumers, due to the RTP and RTA described above. With respect to Free Consumers, the average price for the commercial consumers increased 8.0%.
·	Industrial consumers. With respect to Captive Consumers, average prices increased 6.8%, mainly due to the RTP and RTA described above. With respect to Free Consumers, the average price for industrial consumers increased 8.0% due to to new tariff negotiations in agreements with Free Consumers.

The total volume of energy sold to Final Consumers in the year ended December 31, 2019 increased 0.5% (or 283 GW) compared to the year ended December 31, 2018. This increase represents the effect of a slight increaseof 0.03% (or 14 GW) in the volume of energy sold to Final Captive Consumers and an increase of 2.88% (or 273 GW) in the volume of energy sold to Conventional Free Consumers.

The volume sold to residential and commercial categories, which accounts for 58.2% of our sales to Final Consumers, increased by 3.8% (or 738 GW) and increased by 4.8% (or 490 GW), respectively. These changes were due to the combined effect of:

·	Residential: an increase of 3.8% (or 738 GW) in the volume sold by our distribution subsidiaries to the residential customers due to the greater economic strength of our residential consumers in 2019.
·	Commercial: an increase of 26.8% (or 399 GW) in the volume sold by our commercialization subsidiaries due to (i) migration of Captive Consumers to the Free Consumers category; and (ii) an increase of 1.1% (or 94 GW) in the volume of energy sold to Captive Consumers in the commercial category, partially offset by a decrease of 4.0% (or 4 GW) in the volume of energy from renewable sources sold to commercial consumers that opted to become Special Free Consumers.

The volume sold to industrial consumers, which represented 24.7% of our sales to Final Consumers in 2019 (compared with 26.1% in 2018), decreased by 4.6% (or 636 GW) in the year ended December 31, 2019 compared to the year ended December 31, 2018. This decrease was mainly due to (i) a decrease of 7.8% (or 481GW) in the volume of Captive Consumers served by our distribution subsidiaries and (ii) a decrease of 2.0% (or 155 GW) in the migration of industrial consumers from the Captive Market to the Free Market. With respect to commercial Free Consumers, volumes sold increased by 26.8% (or 399 GW).

Sales to wholesalers

Compared to the year ended December 31, 2018, our gross operating revenues from sales to wholesalers in the year ended December 31, 2019 increased 11.5% (or R$615 million) to R$5,970 million (19.9% of gross operating revenues), due mainly to (i) an increase of 10.2% (or R$390 million) in revenues from other concessionaires and licensees, primarily due to an increase of 3.4% (or 594 GW) in the volume of energy sold to other concessionaires and licensees, and (ii) an increase of 20.1% (or R$ 226 million) in sales of energy in the short-term market, primarily due to an increase of 9.94% (or 380 GW) in the volume of energy sold to spot market energy; partially offset by a decrease of R$36 million in the transfer of revenue relating to the availability of the electric network. For more information on net operating revenues from our segments, see “—Sales by Segment.”

Other operating revenues

Compared to the year ended December 31, 2018, our other gross operating revenues (which excludes TUSD revenue from Captive Consumers) decreased 12.4% (or R$1,007 million) to R$7,145 million in the year ended December 31, 2019 (15.9% of our gross operating revenues), mainly due to the net effect of:

(i)

a decrease of R$1,810 million in revenue from sector financial assets and liabilities, from an asset of R$1,208 million in the year ended December 31, 2018 to a liability of R$602 million in the year ended December 31, 2019. This revenue reflects differences in timing between our budgeted costs included in the tariff at the beginning of the tariff period and those actually incurred by us while such tariff is in effect, creating a contractual obligation to pay, or right to receive, cash to or from consumers through subsequent tariffs or to pay or receive from the granting authority any amounts remaining at the maturity of the concession. This leads to an adjustment in order to recognize the future decrease (or increase) in tariffs to account for lower (or additional) costs in the current year, such adjustment being recognized as a positive (or negative) revenue item. The decrease in this item at December 31, 2019 was mainly driven by (a) a decrease of R$809 million in the CDE Account; (b) a decrease of R$739 million in pass-through costs from Itaipu; (c) a decrease of R$612 million related to the cost of electricity; (d) a decrease of R$354 million in over-contracting; and (e) a decrease of R$26 million related to Transmission from Itaipu; partially offset by (a) an increase of R$225 million in the ESS and the EER; (b) an increase of R$220 million in other financial components; (c) an increase of R$217 million related to the neutrality of sector charges; and (d) an increase of R$72 million related to the Basic Network Charges. For further information, see Note 9 of our audited annual consolidated financial statements;

(ii)	a decrease of R$111 million in other revenues and income; .
(iii)	an increase of R$708 million in revenue due to TUSD referring to Free Consumers; and
(iv)	an increase of R$306 million in revenue from concession infrastructure construction.

Deductions from operating revenues

We deduct certain taxes and industry charges from our gross operating revenue to calculate net operating revenue. The ICMS tax is calculated based on gross operating revenue from final consumers (billed), while federal PIS and COFINS taxes are calculated based on total gross operating revenue. The research and development and energy efficiency programs (regulatory charges) are calculated based on net operating revenue. Other regulatory charges vary depending on the regulatory effect reflected in our tariffs. These deductions represented 33.5% of our gross operating revenue in the year ended December 31, 2019 and 34.0% in the year ended December 31, 2018. Compared to the year ended December 31, 2018, these deductions increased 4.1% (or R$587 million) to R$15,077 million in 2019, mainly due to (i) an increase of 12.1% (or R$749 million) in ICMS taxes; (b) an increase of 4.2% (or R$154 million) in PIS and COFINS taxes, mainly due to the increase in our gross operating revenues (the basis for calculation of these taxes). These increases were partially offset by a decrease of R$374 million in contributions made to the CDE Account as a result of the new quotas established by ANEEL in 2019.

Sales by segment

Distribution

Compared to the year ended December 31, 2018, net operating revenues from our distribution segment (including intersegment transactions) increased 8.0% (or R$1,793 million) to R$24,260 million in the year ended December 31, 2019. This increase primarily reflected the increase of R$2,346 million in gross operating revenue due to the following fluctuations:

(i)	an increase of 15.3% (or R$1,709 million) in revenue from TUSD from Captive Consumers;
(ii)	an increase of 5.3% (or R$839 million) in the supply of electric energy, mainly due to increases of R$1,807 million and R$514 million in revenues from billed supply arising from residential and commercial consumer classes, respectively, partially offset by a decrease of 65.2% (or R$73 million) in revenue from net unbilled supply;
(iii)	an increase of 26.7% (or R$709 million) in revenue from TUSD from Free Consumers;
(iv)	an increase of R$589 million in supply of electric energy to other concessionaires and licensees; and
(v)	an increase of R$322 million in revenue from short-term electric energy.>

These increases were partially offset by:

(i)	a decrease of R$1,810 million in revenue from sector financial assets and liabilities (see ‘‘—Other operating revenues’’ above);
(ii)	an increase in the deductions from our distribution segments operating revenues of 4.0% (or R$553 million) to R$14,396 million in 2019, mainly due to the net effect of: (i) an increase of 9.5% (or R$880 million) in deductions related to PIS, COFINS and ICMS taxes, driven by the increase in our gross operating revenues (the basis for calculation of these taxes); and (ii) a decrease of 9.3% (or R$374 million) in contributions made to the CDE Account due to new quotas established by ANEEL in 2019 (see Note 27.4 to our audited annual consolidated financial statements and “—Deductions from operating revenues”); and

(iii)

a decrease of R$161 million in other operating revenues and income.

Generation (conventional sources)

Net operating revenues from our generation from conventional sources segment (including intersegment transactions) in the year ended December 31, 2019 amounted to R$1,213 million, an increase of 6.0% (or R$69 million) compared to R$1,144 million in the year ended December 31, 2018, due mainly to: (i) an increase of 6.4% (or R$35 million) in revenue from sales from our facility Serra da Mesa to Furnas; (ii) an increase of 4.2% (or R$26 million) in other concessionaries and licensees; and (iii) an increase of R$19 million of revenue from construction transmissions. These increases were partially offset by (i) a decrease of 48.5% (or R$16 million) in energy sold in the spot market; and (ii) an increase of 3.8% (or R$5 million) in PIS and COFINS tax deductions from revenue.

Generation (renewable sources)

Net operating revenues from our generation from renewable sources segment (including intersegment transactions) in the year ended December 31, 2019 amounted to R$1,928 million, a decrease of 0.4% (or R$8 million) compared to R$1,936 million in the year ended December 31, 2018. This decrease was due mainly to: (i) a decrease of 22.7% (or R$32 million) in short-term market; and (ii) a decrease of 25.0% (or R$2 million) in other revenues. These decreases were partially offset by (i) an increase of 1.7% (or R$32 million) in other concessionaires and licensees; and (ii) an increase of 4.9% (or R$5 million) in deductions of PIS, COFINS and ICMS taxes from revenue.

Commercialization

Net operating revenues from our commercialization segment (including intersegment transactions) in the year ended December 31, 2019 amounted to R$3,491 million, a decrease of 0.2% (or R$5 million) compared to R$3,496 million in the year ended December 31, 2018, reflecting the combined effect of: (i) a decrease of 8.8% (or R$166 million) in other concessionaries and licensees; (ii) a decrease of 38.0% (or R$49 million) in revenue from sales of electric energy in the short-term market; (iii) an increase of 4.2% (or R$19 million) in deductions of ICMS, PIS and COFINS taxes from operating revenues due to the increase in gross operating revenue in the segment (the tax assessable basis for these taxes); (iv) an increase of 11.8% (or R$227 million) in electricity sales to Final Consumers, driven by an increase of R$90 million and R$122 million in industrial and commercial classes; and (v) an increase of 39.1% (or R$2 million) in other revenues and income.

Services

Net operating revenues from our services segment (including intersegment transactions) in the year ended December 31, 2019 amounted to R$614 million, an increase of 15.2% (or R$81 million) compared to R$533 million in the year ended December 31, 2018. This increase was due mainly to (i) an increase of R$95 million in revenues from construction and maintenance services; and (ii) an increase of R$14 million in revenues from administrative outsourcing, call center, distributed generation and energy efficiency. These increases were partially offset by (i) a decrease of R$34 million in revenue from information technology; and (ii) an increase of 13.5% (or R$5 million) in deductions of PIS and COFINS from operating revenues, mainly due to the increase in gross operating revenues (the tax assessable basis for these taxes).

Income from Electric Energy Service by Destination

Cost of Electric Energy

Electricity purchased for resale. Our costs for the purchase of energy for resale increased 2.9% (or R$440 million) in the year ended December 31, 2019, to R$15,907 million (67.2% of our total operational costs andoperating expenses) compared with R$15,466 million for the year ended December 31, 2018 (representing 68.2% of our total operational costs and operating expenses), mainly due to an increase of 6.4% (or 4,717 GW) in the volume of energy purchased, reflecting:

(i)	increases of 1.6% (or R$229 million) and 7.9% (or 4,822 GWh) in the cost and volume of electric energy purchased through an auction in the Regulated Market, bilateral contracts and short-term energy; and
(ii)	an increase of 4.7% (or R$126 million) in cost of electric energy purchased from Itaipu.

Electricity network usage charges. Our charges for the use of our transmission and distribution system increased 3.9% (or R$92 million) to R$2,464 million in the year ended December 31, 2019, reflecting the combined effect of: (i) an increase of R$110 million in ESS, net of transfers from CCEE’s energy reserve account (conta de energia de reserva – CONER); (ii) a decrease of R$34 million in Basic Network Charges; and (iii) an increase of R$15 million in Itaipu charges.

Other costs and operating expenses

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

Compared to the year ended December 31, 2018, our other costs and operating expenses increased 9.2% (or R$609 million) to R$7,198 million in the year ended December 31, 2019, mainly due to: (i) an increase of 17.7% (or R$314 million) in expenses relating to the construction of concession infrastructure; (ii) an increase of 6.6% (or R$86 million) in depreciation and amortization; (iii) an increase of 37.9% (or R$64 million) in expenses related to allowances for doubtful accounts; (iv) an increase of 25.6% (or R$23 million) in expenses with private pension plans; and (v) a decrease of 3.3% (or R$23 million) in expenses relating to services provided by third-parties. These increases were partially offset by a decrease of 10.0% (or R$21 million) on gain (loss) disposal, retirement and other noncurrent assets.

Income from Electric Energy Service

Compared to the year ended December 31, 2018, our income from electric energy service increased 17.7% (or R$655 million) to R$4,363 million in the year ended December 31, 2019, mainly due to our net operating revenue having increased by more, in absolute terms (R$1,796 million), than the increase in our cost of generating and distributing electric energy and other operating costs and expenses (R$1,054 million).

Income from Electric Energy Service by Segment

Distribution

Compared to the year ended December 31, 2018, income from electric energy service from our distribution segment (including intersegment transactions) increased R$638 million to R$2,876 million in the year ended December 31, 2019. As discussed above, net operating revenues from the segment increased by 8.0% (or R$1,793 million) while other costs and operational expenses related to the segment increased by 5.7% (or R$1,101 million). The main contributing factors to the changes in costs and operational expenses were as follows:

Electricity costs. Compared to the year ended December 31, 2018, electricity costs (including intersegment transactions) increased 4.0% (or R$601 million), to R$15,623 million in the year ended December 31, 2019.

The cost of energy purchased for resale (including intersegment transactions) increased 4.1% (or R$522 million), reflecting the combined effect of: (i) an increase of 2.9% (or R$319 million) in the cost of electric energy purchased through an auction in the Regulated Market, bilateral contracts and short-term energy, as well as an increase of 13.6% (or 5,403 GWh) in the volume of electric energy purchased through an auction in the Regulated Market, bilateral contracts and short-termenergy; (ii) an increase of 4.7% (or R$126 million) in the purchases of electric energy from Itaipu, as well as a decrease of 0.9% (or 96 GW) in the volume of electric energy purchased from Itaipu; and (iv) a decrease of 0.9% (or R$11 million) in PIS and COFINS credits relating to purchases of electric energy.

In addition, as mentioned above, charges for the use of the transmission and distribution system increased 3.5% (or R$79 million), to R$2,363 million in the year ended December 31, 2019, mainly due to: (i) an increase of R$110 million in ESS, net of transfers from CCEE’s energy reserve account (conta de energia de reserva – CONER); (ii) a decrease of R$38 million in Basic Network Charges; (iii) a decrease of R$15 million in Transmission from Itaipu charges; and (iv) a decrease of R$13 million in EER.

Other costs and operating expenses. Compared to the year ended December 31, 2018, our other costs and operating expenses for the distribution segment (including intersegment transactions) increased 11.3% (or R$500 million), to R$4,941 million in the year ended December 31, 2019. This increase was mainly due to (i) an increase of 16.7% (or R$296 million) in costs related to the construction of concession infrastructure; (ii) an increase of 40.4% (or R$67 million) in allowances for doubtful accounts mainly due to tariff increases and consumer default or late payment in the commercial and residential classes; (iii) a decrease of 27.3% (or R$38 million) in expenses with a loss (gain) on disposal, retirement and other noncurrent assets; (iv) an increase of 3.9% (or R$36 million) in personnel expenses; (v) an increase of 26.1% (or R$23 million) in private pension expenses; and (vi) a decrease of 7.2% (or R$13 million) in legal, judicial and indemnification expenses.

Generation (conventional sources)

Compared to the year ended December 31, 2018, income from electric energy service from our conventional generation segment (including intersegment transactions) increased 2.2% (or R$18 million), to R$839 million in the year ended December 31, 2019. This increase was mainly due to the combined effect of: (i) an increase of 6.4% (or R$35 million) in revenue from sales from our facility Serra da Mesa to Furnas; (ii) an increase of 4.2% (or R$26 million) in other concessionaries and licensees; (iii) an increase of 30.4% (or R$31 million) in cost of energy, including electricity network usage charge; (iv) an increase of R$19 million in revenue from construction transmissions; (v) an increase of R$18 million in other costs and operating expenses; and (vi) a decrease of R$16 million in purchases of spot market energy.

Generation (renewable sources)

Compared to the year ended December 31, 2018, income from electric energy service from our renewable generation segment (including intersegment transactions) decreased 4.8% (or R$28 million), to R$558 million in the year ended December 31, 2019. This decrease was due to the combined effect of (i) a decrease of 0.4% (or R$8 million) in net operating revenue (as discussed in ‘‘—Sales by segment’’ above); and (ii) an increase of 1.9% (or R$20 million) in operating costs and expenses.

Commercialization

Compared to the year ended December 31, 2018, income from electric energy service from our commercialization segment (including intersegment transactions) decreased 1.7% (or R$2 million), to R$92 million in the year ended December 31, 2019. This decrease was due to the net effect of: (i) a decrease of 0.3% (or R$10 million) in the cost of electric energy; (ii) a decrease of 0.2% (or R$5 million) in net operating revenue from the segment, as discussed in ‘‘—Sales by segment’’ above; and (iii) an increase of 12.0% (or R$6 million) in other costs and operating expenses, was mainly due to an increase of R$5 million in depreciation and amortization.

Services

Compared to the year ended December 31, 2018, income from electric energy service from our services segment (including intersegment transactions) increased 54.1% (or R$39 million), to R$112 million in the year ended December 31, 2019. This increase was due to the combined effect of an increase of 15.2% (or R$81 million) in net operating revenue, as discussed in ‘‘—Sales by segment’’ above, which exceeded the increase of 8.7% (or R$38 million) in operating costs and expenses.

Profit for the year

Net Financial Expense

Compared to the year ended December 31, 2018, our net financial expense decreased 34.2% (or R$377 million), from R$1,103 million in 2018 to R$726 million in the year ended December 31, 2019, mainly due to a decrease of R$235 million in our financial expenses, offset by an increase of R$142 million in our financial income.

The reasons for the decrease in financial expenses are: (i) a decrease of R$615 million in financial expenses from monetary and exchange adjustments; and (ii) a decrease of R$74 million in adjustment for inflation and exchange rate changes.

The increase in financial income is mainly due to: (i) an increase of 45.0% (or R$50 million) in other income; (ii) an increase of 17.9% (or R$40 million) in income from financial investments; (iii) an increase of 13.0% (or R$36 million) in income from fines for late payments; (iv) an increase of 133.3% (or R$20 million) in tax credits; and (v) an increase of 8.0% (or R$10 million) in income from monetary adjustments to sector financial assets (for more information, see Note 10 of our audited annual consolidated financial statements). These increases were partially offset by a decrease of 10.0% (or R$7 million) in monetary and exchange adjustments.

At December 31, 2019, we had R$13,901 million (compared with R$14,746 million at December 31, 2018) in debt denominated inreais, which accrued both interest and inflation adjustments based on a variety of Brazilian indices and money market rates. The average CDI interbank rate during the year decreased to 5.94% in 2019, compared to 6.47% in 2018; and the average TJLP (which was replaced by the TLP (Long-Term Rate) in financing contracts executed on or after January 1, 2018) decreased to 6.20% in 2019, compared to 6.72% in 2018. We also had the equivalent of R$5,009 million (compared with R$5,631 million at December 31, 2018) of debt denominated in foreign currency in U.S. dollars and euros. In order to reduce the exchange rate risk with respect to this foreign currency-denominated debt and variations in interest rates, we implemented a policy of using exchange and interest rate derivatives.

Income and Social Contribution Taxes

Our net charge for income and social contribution taxes increased to R$1,238 million in the year ended December 31, 2019 compared with R$774 million in the year ended December 31, 2018. Our effective rate of 31.1% on pretax income in the year ended December 31, 2019 was lower than the official rate of 34%, principally due to our ability to recognize further prior year tax loss carry-forwards. Our unrecorded tax credits relate to losses generated for which it is not probable that future taxable income will be sufficient to absorb such losses (see Note 10.5 to our audited annual consolidated financial statements).

Profit for the year

Compared to the year ended December 31, 2018, and due to the factors discussed above, profit for the year increased 26.9% (or R$582 million), to R$2,748 million in the year ended December 31, 2019.

Profit for the year by Segment

In the year ended December 31, 2019, 66.8% of our profit for the year derived from our distribution segment (including intersegment transactions), 31.4% from our generation from conventional sources segment, 3.9% from our generation from renewable sources segment, 1.7% from our commercialization segment, 3.0% from our services segment and negative 6.8% from Other. See the table under “—Background—Operating Segments” earlier in this Item 5 for the equivalent contributions from our segments in 2018 and 2017.

Distribution

Compared to the year ended December 31, 2018, profit for the year from our distribution segment (including intersegment transactions) increased 28.1% (or R$402 million), to R$1,835 million in the year ended December 31, 2019, as a result of: (i) anincrease of 28.5% (or R$638 million) in income from electric energy service and (ii) a decrease of 36.1% (or R$112 million) in net financial expenses; partially offset by an increase of 70.5% (or R$349 million) in expenses related to income and social contribution taxes.

The decrease in the segment’s net financial expense was mainly due to:

(i)	a decrease of 7.1% (or R$63 million) in financial expenses, mainly due to the combined effect of: (a) a decrease of R$400 million in monetary and exchange adjustments; (b) an increase of R$394 million of revenues from derivatives; and (c) an increase of R$41 million in expenses with debt charges;
(ii)	an increase of 8.5% (or R$45 million) in financial income, mainly due to: (i) an increase of R$37 million in late payment interest and fines; (ii) an increase of R$24 million in adjustments for inflation of tax credits; (iii) a decrease of R$10 million in discounts on purchases of ICMS credit; and (iv) a decrease of R$7 million in monetary and exchange adjustments.

Generation (conventional sources)

Profit for the year from our generation from conventional sources segment (including intersegment transactions) increased 12.2% (or R$94 million), to R$864 million during the year ended December 31, 2019 from R$770 million for the year ended December 31, 2018. This increase was mainly due to: (i) an increase in net operating revenue from the segment of 6.0% (or R$69 million), as described in the section above; (ii) an increase in costs with electric energy of 30.4% (or R$31 million) mainly due to the purchases of electric energy through an auction in the Regulated Market, bilateral contracts and short-term energy; and (iii) an increase in operating costs and expenses relating to the segment of 17.1% (or R$18 million).

Generation (renewable sources)

Profit for the year from our generation from renewable sources segment (including intersegment transactions) decreased by 9.9% (or R$12 million), to R$107 million in the year ended December 31, 2019 compared to profit for the year of R$119 million in 2018, mainly due to (i) a decrease of 0.4% (or R$8 million) in net operating revenue (as discussed in ‘‘—Sales by segment’’ above) and (ii) a decrease in net financial expense of 20.0% (or R$100 million).

The decrease in net financial expense was driven by: (i) a decrease of 9.4% (or R$60 million) in financial expenses, mainly due to a decrease of R$100 million in interest on debt and adjustments for inflation and exchange rate changes, offset by a decrease in capitalized interest; and (ii) an increase of 31.1% (or R$41 million) in financial income, mainly due to an increase of R$60 million in other revenues, offset by a decrease of R$20 million in income from financial investments.

Commercialization

Compared to the year ended December 31, 2018, profit for the year from our commercialization segment (including intersegment transactions) decreased 10.6% (or R$6 million), to R$47 million in the year ended December 31, 2019, reflecting the combined effect of: (i) a decrease of R$6 million in expenses from income and social contribution taxes; and (ii) a decrease of 1.7% (or R$2 million) in income from electric energy service.

Services

Compared to the year ended December 31, 2018, profit for the year from our services segment (including intersegment transactions) increased 94.0% (or R$40 million), to R$83 million in the year ended December 31, 2019, reflecting the combined effects of: (i) an increase of 15.2% (or R$81 million) in income from services rendered; and (ii) an increase of R$8.7% (or R$38 million) in other costs and operating expenses related to third party services.

Results of Operations—2018 compared to 2017

Net Operating Revenues

Compared to the year ended December 31, 2017, our net operating revenues increased 5.2% (or R$1,392 million) to R$28,137 million in the year ended December 31, 2018.

This increase in operating revenue was primarily due to the combined effect of: (i) an increase of R$1,503 million in electricity sales to final consumers, as discussed in the section “—Sales by Destination” below; (ii) an increase of R$584 million in other concessionaires and licensees; (iii) an increase of R$513 million in revenue due to TUSD for Captive and Free Consumers; (iv) an increase of R$202 million in other revenues and income; and (v) an increase of R$117 million in judicial injunctions and other tariff discounts of the CDE Account. These increases were partially offset by (i) an increase of R$1,181 million in deductions from operating revenues, as discussed in the section “—Deductions from operating revenues” below, which represents a decrease in net operating revenues, and (ii) a decrease of R$693 million in sector financial assets and liabilities.

The following discussion describes changes in our net operating revenues by destination and by segment, based on the items comprising our gross revenues.

Sales by Destination

Sales to Final Consumers

Compared to the year ended December 31, 2017, our gross operating revenues from sales to Final Consumers (which includes TUSD revenue from Captive Consumers) increased 12.9% (or R$3,321 million) in the year ended December 31, 2018, to R$29,021 million. Our gross operating revenues primarily reflect sales to Captive Consumers in concession areas from our distribution subsidiaries, as well as TUSD revenue from the use of our network by Captive Consumers, both of which are subject to tariff adjustment as described below. Our gross operating revenue also reflects sales to Free Consumers in commercial and industrial categories.

In the year ended December 31, 2018, overall average energy prices increased by 12.4%, mainly due to the result of the RTP for CPFL Paulista and RGE Sul and the RTA for CPFL Piratininga and CPFL Santa Cruz. In 2018, our tariff adjustments were of 21.27%, 20.01%, 18.45%, 5.71% and 12.68% for RGE, CPFL Piratininga, RGE Sul, CPFL Santa Cruz and CPFL Paulista, respectively. Furthermore, the red tariff flag was in effect for the most part of 2018. For further information, see Note 27.2 of our audited annual consolidated financial statements. Overall, average prices for Final Consumers in 2018 were higher for all consumer classes:

·	Residential and commercial consumers. With respect to Captive Consumers (which represent 98.2% of the total amount sold to this category in our consolidated statements), average prices increased 13.2% for residential consumers and 11.8% for commercial consumers, due to the RTP described above. With respect to Free Consumers, the average price for the commercial consumers increased 5.9%.
·	Industrial consumers. Average prices increased 11.2%, mainly due to the tariff adjustments described above. With respect to Free Consumers, the average price for industrial consumers increased 1.7% due to the tariff adjustments, which resulted from new negotiations of tariffs in contracts with Free Consumers.

The total volume of energy sold to Final Consumers in the year ended December 31, 2018 decreased 0.5% compared to the year ended December 31, 2017. This decrease represents the effect of a decrease of 1.1% (or 106GW) in the volume of energy sold to Conventional Free Consumers, mainly due to a decrease of 413 GW in the volume of energy sold to industrial consumers offset by an increase of 261 GW in the volume of energy sold to commercial consumers and an increase of 46 GW to other consumers by our commercialization subsidiaries as a result of the migration of these consumers from the Captive to the Free Consumer categories.

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The volume sold to residential and commercial categories, which accounts for 56.2% of our sales to Final Consumers, increased by 2.6% (or 496 GW) and decreased by 0.1% (or 10 GW), respectively. These changes were due to the combined effect of:

·	Residential: an increase of 2.6% (or 496 GW) of the volume sold by our distribution subsidiaries to the residential category due to our residential consumers’greater economic strength in 2018, which was driven by the GDP growth of 1.1% in 2018 as compared to the GDP of 1.0% in 2017.
·	Commercial: an increase of 21.24% (or 261 GW) in the volume sold by our commercialization subsidiaries due to the migration of consumers from the Captive to the Free Consumer category, which was partially offset by a decrease of (i) 43.80% (or 73 GW) in the volume of energy from renewable sources sold to commercial consumers who elected to become Special Free Consumers, and (ii) 2.24% (or 198 GW) in the volume of energy sold to Captive Consumers in the commercial category.

The volume sold to industrial consumers, which represented 26.1% of our sales to Final Consumers in 2018 (compared with 27.5% in 2017), decreased by 1.4% in the year ended December 31, 2018 compared to the year ended December 31, 2017. Volumes to Captive Consumers in this category decreased 6.2% (or 405 GW) in our distribution subsidiaries and the migration of industrial consumers from the Captive to the Free Market decreased 5.1% (or 413 GW). Regarding Free Consumers, volumes sold increased by 4.3% (or 261 GW), reflecting the same migration of industrial consumers mentioned above, as well as improvements in Brazil’s economic conditions during 2018.

Sales to wholesalers

Compared to the year ended December 31, 2017, our gross operating revenues from sales to wholesalers in the year ended December 31, 2018 decreased 12.1% (or R$734 million) to R$5,356 million (12.6% of gross operating revenues), due mainly to a decrease of 53.7% (or R$1,258 million) in sales of energy in the spot market, which was mainly driven by (i) a decrease of 53.3% (or 4,366 GWh) in the volume of energy sold and (ii) a decrease of 1.0% in the average price of sales to wholesalers as compared to 2017. These decreases were partially offset by an increase of 18.0% (or R$585 million) in sales of electricity to other concessionaires and licensees. For more information on net operating revenues from our segments, see “—Sales by Segment.”

Other operating revenues

Compared to the year ended December 31, 2017, our other gross operating revenues (which excludes TUSD revenue from Captive Consumers) decreased 0.7% (or R$58 million) to R$8,152 million in the year ended December 31, 2018 (19.1% of our gross operating revenues), mainly due to:

(i)

a decrease of R$693 million in revenue from sector financial assets and liabilities, which posted revenue of R$1,208 million in 2018 compared to R$1,901 million in 2017. This revenue reflects timing differences between our budgeted costs included in the tariff at the beginning of the tariff period, and those actually incurred while such tariff is in effect, creating a contractual obligation to pay (or right to receive) cash to or from consumers through subsequent tariffs or to pay to or receive from the granting authority any remaining amounts at the expiration of the concession. This leads to an adjustment in order to recognize the future decrease (or increase) in tariffs to account for lower (or additional) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue. The decrease in this item in 2018 was driven mainly by (a) a decrease of R$2,954 million related to electric energy cost, (b) a decrease of R$22 million related to neutrality of sector charges; and (c) a decrease of R$11 million related to the pass-through costs from Itaipu, partially offset by (a) an increase of R$993 million in over-contracting, (b) an increase of R$760 million in the CDE Account and (c) an increase of R$744 million in the ESS and the EER. For further information, see Note 9 to our audited annual consolidated financial statements;

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(ii)	a decrease of R$301 million in revenue from construction of concession infrastructure;
(iii)	a decrease of R$58 million in compensation paid for failure to comply with the limits of continuity (performance indicators, such as individual interruption duration per consumer unit, individual interruption frequency per consumer unit and maximum continuous interruption duration per consumer unit or connection point);
(iv)	an increase of R$513 million in revenue due to TUSD relating to Free Consumers;
(v)	an increase of R$202 million in other revenues and income;
(vi)	an increase of R$141 million in concession financial assets adjustments;
(vii)	an increase of 8.3% (or R$117 million) in revenue related to the low income subsidy and discounts on tariffs reimbursed by funds from the CDE Account; and
(viii)	an increase of R$22 million in adjustment of revenues from excess demand and excess reactive power.

Deductions from operating revenues

We deduct certain taxes and industry charges from our gross operating revenue to calculate net operating revenue. The ICMS tax is calculated based on gross operating revenue from final consumers (billed), while federal PIS and COFINS taxes are calculated based on total gross operating revenue. The research and development and energy efficiency programs (regulatory charges) are calculated based on net operating revenue. Other regulatory charges vary depending on the regulatory effect reflected in our tariffs. These deductions represented 34.0% of our gross operating revenue in the year ended December 31, 2018 and 33.2% in the year ended December 31, 2017. Compared to the year ended December 31, 2017, these deductions increased by 8.9% (or R$1,181 million) to R$14,490 million in 2018, mainly due to: (i) an increase of 9.34% (or R$316 million) in PIS and COFINS taxes, mainly due to the increase in our gross operating revenues (the basis for calculation of these taxes); (ii) an increase of 13.43% (or R$733 million) in ICMS taxes; and (iii) an increase of R$831 million in contributions made to the CDE Account as a result of the new quotas established by ANEEL in 2018. These increases were partially offset by a decrease of R$700 million in recognized tariff flag revenues, which are required to be paid into the CCRBT administered by the CCEE.

Sales by segment

Distribution

Compared to the year ended December 31, 2017, net operating revenues from our distribution segment (including intersegment transactions) increased 6.6% (or R$1,391 million) to R$22,467 million in the year ended December 31, 2018. This increase primarily reflected the increase of R$2,542 million in gross operating revenue due to the following fluctuations:

(i)	an increase of 20.7% (or R$2,377 million) in revenue due to TUSD for Captive and Free Consumers;
(ii)	an increase of 224.4% (or R$202 million) in unbilled revenue;
(iii)	an increase of 8.3% (or R$117 million) in low-income subsidy;

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(iv)	an increase of R$203 million in other revenues and income; and
(v)	an increase of R$117 million in revenue related to discounts on tariffs reimbursed by funds from the CDE Account (see Note 27.4 to our audited annual consolidated financial statements and “—Other operating revenues” above).

These increases were partially offset by a decrease of R$693 million in revenue from sector financial assets and liabilities, which represented a revenue of R$1,208 million in 2018 compared with R$1,901 million in 2017 (see “—Other operating revenues” above).

The deductions from our distribution segments operating revenues (including intersegment transactions) increased by 9.1% (or R$1,151 million) to R$13,843 million in 2018, mainly due to: (i) an increase of 12.3% (or R$1,017 million) in deductions related to PIS, COFINS and ICMS taxes, driven by the increase in our gross operating revenues (the basis for calculation of these taxes) and (ii) an increase of 26.1% (or R$831 million) in contributions made to the CDE Account due to new quotas established by ANEEL in 2018 (see Note 27.3 to our audited annual consolidated financial statements). These increases were partially offset by a decrease of R$700 million in deductions related to recognized tariff flag revenues, which are required to be paid into the CCRBT administered by the CCEE. For more information, see “—Deductions from operating revenues.”

Generation (conventional sources)

Net operating revenues from our generation from conventional sources segment (including intersegment transactions) in the year ended December 31, 2018 amounted to R$1,144 million, a decrease of 3.9% (or R$46 million) compared to R$1,190 million in the year ended December 31, 2017, due mainly to: (i) a decrease of R$46 million of revenue from construction related to CPFL Morro Agudo; (ii) the price-driven decrease of 3.8% (R$21 million) in revenue from sales from our facility Serra da Mesa to Furnas; (iii) an increase of 10.3% (R$21 million) in PIS and COFINS tax deductions from revenue; and (iv) a decrease of R$12 million in other revenues and income. These decreases were partially offset by (i) an increase of 6.5% (or R$38 million) in other concessionaries and licensees; and (ii) an increase of R$16 million in spot market energy.

Generation (renewable sources)

Net operating revenues from our generation from renewable sources segment (including intersegment transactions) in the year ended December 31, 2018 amounted to R$1,936 million, a decrease of 1.2% (or R$23 million) compared to R$1,959 million in the year ended December 31, 2017. This decrease was due mainly to: (i) a decrease of R$55 million in revenue from energy sales on the spot market; (ii) a decrease of R$18 million in revenue from Free Consumers in the commercial sector driven mainly by Special Free Consumers migrating from the Captive Market to the Free Market and (iii) a decrease of 100% (or R$3 million) in global reversion reserve charges (RGR) used to finance improvement and expansion projects for companies in the energy sector. These decreases were partially offset by (i) an increase of R$53 million in revenue from other concessionaires and licensees; and (ii) an increase of 2.0% (or R$2 million) in PIS and COFINS tax deductions from revenue.

Commercialization

Net operating revenues from our commercialization segment (including intersegment transactions) in the year ended December 31, 2018 amounted to R$3,496 million, an increase of 2.4% (or R$82 million) compared to R$3,414 million in the year ended December 31, 2017. This increase was mainly due to: (i) an increase of 22.2% (or R$343 million) in revenue from sales to other concessionaires and licensees, driven by an increase of 8.7% (or 830 GW) in sales volume; and (ii) an increase of 28.4% (or R$73 million) in revenue from commercial Free Consumers, driven by an increase of 21.2% in sales volume. These increases were partially offset by: (i) a decrease of 68.1% (or R$276 million) in revenue from sales in the spot market, driven by a 62.2% (or 639 GW) decrease in sales volume; (ii) a decrease of 3.5% (or R$56 million) in revenue from industrial Free Consumers, driven by a decrease of 5.1% in sales volume; and (iii) an increase of 1.8% (or R$8 million) in ICMS, PIS and COFINS tax deductions from operating revenues, mainly due to the increase in gross operating revenues for the segment (the basis for calculation of these taxes).

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Services

Net operating revenues from our services segment (including intersegment transactions) in the year ended December 31, 2018 amounted to R$533 million, an increase of 9.7% (or R$47 million) compared to R$486 million in the year ended December 31, 2017. This increase was due mainly to: (i) an increase of R$23 million in revenues from construction and maintenance services; (ii) an increase of R$14 million in revenues from administrative and call center and information technology outsourcing; and (iii) an increase of R$7 million in scrap sales of used equipment. These increases were partially offset by an increase of 9.4% (or R$3 million) in PIS and COFINS tax deductions from operating revenues, mainly due to the increase in our gross operating revenues (the basis for calculation of these taxes).

Income from Electric Energy Service by Destination

Cost of Electric Energy

Electricity purchased for resale. Our costs for the purchase of energy for resale decreased 1.0% (or R$151 million) in the year ended December 31, 2018, to R$15,466 million (63.3% of our total operational costs and operating expenses) compared with R$15,617 million for the year ended December 31, 2017 (representing 65.8% of our total operational costs and operating expenses), mainly due to a decrease of 4.7% (or 3,632 GW) in the volume of energy purchased, reflecting:

(i)	a decrease of 3.9% (or R$566 million) in the cost of energy purchased; and
(ii)	a decrease of 5.6% (or 662 GWh) in the volume of energy purchased from Itaipu.

These decreases were partially offset by (i) an increase of R$317 million in purchases of energy from Itaipu and an increase of 20.3% in the average prices of energy purchased from Itaipu, reflecting an increase of 4.8% in the total average price of energy purchased, itself caused by a short decrease of 3.0% in the applicable Itaipu tariff and a 5.6% decrease in the volume of energy purchased; (ii) an increase of R$37 million (or 12.8%) in the cost of energy purchased in the Proinfa Program; and (iii) a decrease of R$60 million in PIS and COFINS tax credits (representing a decrease of 3.8% compared to 2017) related to purchases of energy, which represents an increase in the cost of energy.

Electricity network usage charges. Our charges for the use of our transmission and distribution system increased 84.7% (or R$1,088 million) to R$2,372 million in the year ended December 31, 2018, mainly as a result of: (i) an increase of R$573 million in Basic Network Charges; (ii) an increase of R$347 million in ESS, net of transfers from CCEE’s energy reserve account (conta de energia de reserva – CONER); (iii) an increase of R$135 million in Reserve Energy Charges; and (iv) an increase of R$106 million in transmission from Itaipu. These increases were partially offset by an increase of R$123 million in PIS and COFINS tax credits.

Other costs and operating expenses

Compared to the year ended December 31, 2017, our other costs and operating expenses decreased 3.4% (or R$232 million) to R$6,590 million in the year ended December 31, 2018, mainly due to the following events: (i) a decrease of 14.5% (or R$300 million) in expenses related to the construction of concession infrastructure; (ii) a decrease of 4.9% (or R$35 million) in expenses related to outsourced services; (iii) a decrease of 21.1% (or R$24 million) in private pension plans; and (iv) a decrease of R$20 million in impairment. These decreases were partially offset by (i) an increase of 59.5% (or R$79 million) in gain (loss) on disposal, retirement and other noncurrent assets; (ii) an increase of 5.2% (or R$64 million) in depreciation and amortization expenses; and (iii) an increase of 2.7% (or R$37 million) in our personnel expenses, reflecting increased costs under our collective bargaining agreements.

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Income from Electric Energy Service

Compared to the year ended December 31, 2017, our income from electric energy service increased 22.7% (or R$687 million) to R$3,709 million in the year ended December 31, 2018, since our net operating revenue increased by more in absolute terms (R$1,392 million) than the increase in our cost of generating and distributing electric energy and other operational costs and expenses (R$705 million).

Income from Electric Energy Service by Segment

Distribution

Compared to the year ended December 31, 2017, income from electric energy service from our distribution segment (including intersegment transactions) increased R$707 million to R$2,237 million in the year ended December 31, 2018. As discussed above, net operating revenues from the segment increased by 6.6% (or R$1,391 million) while costs and operational expenses related to the segment increased by 3.5% (or R$684 million). The main contributing factors to the changes in costs and operational expenses were as follows:

Electricity costs. Compared to the year ended December 31, 2017, electricity costs (including intersegment transactions) increased 6.2% (or R$876 million), to R$15,022 million in the year ended December 31, 2018.

The cost of energy purchased for resale (including intersegment transactions) decreased 1.8% (or R$231 million), reflecting: (i) a decrease of 15.5% (or R$1,785 million) in the cost of energy purchased in the Regulated Market, (ii) a decrease of 12.8% in the volume of energy purchased, and (iii) an increase of 4.8% in average energy purchase prices. The decrease in the cost of energy purchased for resale was partially offset by (i) an increase of 703.8% (or R$1,119 million) in the cost of purchases in the spot market, reflecting an increase of 421.9% in the volume of energy purchased and an increase of 54.4% in average purchase prices; (ii) an increase of R$317 million in purchases of energy from Itaipu, reflecting a decrease of 5.6% in the volume of energy purchased, itself caused by a 3.0% decrease in the tariff, reflecting the net effects of an increase of 20.3% in the average price of energy purchased and a 14.5% increase in the average rate of the real against the U.S. dollar during 2018 as compared to 2017; (iii) an increase of 12.8% (or R$37 million) in the Proinfa Program costs; and (iv) a decrease of 5.9% (or R$78 million) in PIS and COFINS tax credits related to purchases of energy.

In addition, as mentioned above, charges for the use of the transmission and distribution system increased 94.1% (or R$1,107 million) to R$2,284 million in the year ended December 31, 2018, mainly due to: (i) an increase of R$576 million in Basic Network Charges; (ii) an increase of R$347 million of ESS; (iii) an increase of R$135 million in EER; and (iv) an increase of R$9 million in charges for use of the distribution system.

Other costs and operating expenses. Compared to the year ended December 31, 2017, our other costs and operating expenses (including intersegment transactions) for the Distribution segment decreased 3.5% (or R$192 million) to R$5,207 million in the year ended December 31, 2018. This decrease was mainly due to (i) a decrease of 12.6% (or R$254 million) in expenses related to the construction of concession infrastructure; and (ii) a decrease of 21.4% (or R$24 million) in private pension plans. These decreases were partially offset by (i) an increase in the third-party services expenses of 1.6% (or R$14 million); and (ii) an increase of 8.6% (or R$13 million) in allowance for doubtful accounts.

Generation (conventional sources)

Compared to the year ended December 31, 2017, income from electric energy service from our conventional generation segment (including intersegment transactions) increased 7.2% (or R$55 million) to R$821 million in the year ended December 31, 2018. This increase was mainly due to (i) an increase of 6.5% (or R$38 million) related to sales to other concessionaries and licensees; and (ii) an increase of R$16 million in purchases in the spot market energy. These increases were partially offset by (i) a decrease of 18.8% (R$20 million) in PIS and COFINS tax deductions from revenue due to the increase in gross operating revenues from the segment (the basis for calculation of these taxes); (ii) a decrease of 4.5% (R$5 million) in depreciation and amortization expenses; (iii) a decrease of 10.7% (R$8.0 million) in personnel expenses; and (iv) a decrease of 11.5% (R$3 million) in expenses related to outsourced services.

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Generation (renewable sources)

Compared to the year ended December 31, 2017, income from electric energy service from our renewable generation segment (including intersegment transactions) decreased 3.1% (or R$19 million) to R$586 million in the year ended December 31, 2018. This decrease was the net effect of the decrease of 1.2% (or R$23 million) in net operating revenue (as discussed in the section “—Sales by Segment” above); offset by the increase of R$18 million (or 4.6%) in costs and operational expenses and a decrease of 8.0% (or R$28 million) in costs of electric energy. The increase in operational expenses was mainly due to (i) an increase of 6.0% (or R$15 million) in general and administrative expenses; and (ii) an increase of R$ 3 million in depreciation and amortization expenses.

Commercialization

Compared to the year ended December 31, 2017, income from electric energy service from our commercialization segment (including intersegment transactions) decreased 43.9% (or R$74 million) to R$94 million in the year ended December 31, 2018. This decrease was due to the net effect of the increase of 4.9% (or R$157 million) in costs and operational expenses, which exceeded the increase of 2.4% (or R$82 million) in net operating revenues of the segment, as discussed in the section “Sales by Segment” above. The increase in costs and expenses was mainly due to an increase of R$173 million in the cost of energy purchased in the Regulated Market, through bilateral contracts and in the spot market, driven by an increase of 0.5% in the volume of energy purchased and 1.34% in purchase prices.

Services

Compared to the year ended December 31, 2017, income from electric energy service from our services segment (including intersegment transactions) increased 7.4% (or R$5 million) to R$73 million in the year ended December 31, 2018. This increase was due to the net effect of the increase of 9.7% (or R$47 million) in net operating revenues as discussed in the section “—Sales by Segment” above, which exceeded the increase of 10.1% (or R$42 million) in costs and operational expenses.

Profit for the year

Net Financial Expense

Compared with the year ended December 31, 2017, our net financial expense decreased 25.8% (or R$385 million), from R$1,488 million in 2017 to R$1,103 million in the year ended December 31, 2018, mainly due a decrease of R$503 million in our financial expenses, offset by a decrease of R$118 million in our financial income.

The reasons for the decrease in financial expenses are: (i) a decrease of 31.8% (or R$172 million) in financial expenses from monetary and exchange adjustments because of lower average interest rates; (ii) a decrease of 20.0% (or R$332 million) in debt charges; (iii) a decrease of R$82 million in financial expenses from monetary adjustments of sector financial liabilities; and (iv) a decrease of 43.4% (or R$22 million) in capitalized borrowing costs, which is accounted for as a decrease in financial expenses.

The decrease in financial income is mainly due to the following reasons: (i) a decrease of 51.3% (or R$234 million) in income from financial investments due to the reduction of the cash and cash equivalents balance; (ii) a decrease of 24.6% (or R$12 million) in income from adjustments of escrow deposits; and (iii) a decrease of R$5 million in adjustments of tax credits. These decreases were partially offset by (i) an increase of 100% (or R$80 million) in income from monetary adjustments of sector financial assets (see Note 9 to our audited annual consolidated financial statements); (ii) an increase of 29.0% (or R$25 million) in other revenues; and (iii) an increase of 4.1% (or R$11 million) in interest and fine payments.

At December 31, 2018, we had R$14,746 million (compared with R$15,310 million at December 31, 2017) in debt denominated inreais, which accrued both interest and inflation adjustments based on a variety of Brazilian indices and money market rates. The average CDI interbank rate during the year decreased to 6.47% in 2018, compared to 10.06% in 2017; and the average TJLP (which was replaced by the TLP (Long-Term Rate) in financingcontracts executed on or after January 1, 2018) decreased to 6.72% in 2018, compared to 7.12% in 2017. We also had the equivalent of R$5,631 million (compared with R$4,858 million at December 31, 2017) of debt denominated in foreign currency in U.S. dollars and euros. In order to reduce the exchange rate risk with respect to this foreign currency-denominated debt and variations in interest rates, we implemented a policy of using exchange and interest rate derivatives.

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Income and Social Contribution Taxes

Our net charge for income and social contribution taxes increased to R$774 million in the year ended December 31, 2018 compared with R$604 million in the year ended December 31, 2017. Our effective rate of 26.3% on pretax income in the year ended December 31, 2018 was lower than the official rate of 34%, principally due to our ability to recognize further prior year tax loss carryforwards. Our unrecorded tax credits relate to losses generated for which it is not probable that future taxable income will be sufficient to absorb such losses (see Note 10.5 to our audited annual consolidated financial statements).

Profit for the year

Compared to the year ended December 31, 2017, and due to the factors discussed above, profit for the year increased 74.2% (or R$923 million), to R$2,166 million in the year ended December 31, 2018.

Profit for the year by Segment

In the year ended December 31, 2018, 66.1% of our profit for the year derived from our distribution segment, 35.5% from our generation from conventional sources segment, 5.5% from our generation from renewable sources segment, 2.5% from our commercialization segment, 2.0% from our services segment and negative 8.5% from Other. See the table under “—Background—Operating Segments” earlier in this Item 5 for the equivalent contributions from our segments in 2017.

Distribution

Compared to the year ended December 31, 2017, profit for the year from our distribution segment (including intersegment transactions) increased 115.5% (or R$768 million), to R$1,432 million in the year ended December 31, 2018, as a result of: (i) an increase of 46.2% (or R$707 million) in income from electric energy service; and (ii) a decrease of 45.3% (or R$257 million) in net financial expense; partially offset by an increase of 65.3% (or R$196 million) in income and social contribution taxes expenses.

The decrease in the segment’s net financial expense was mainly due to:

(i)	a decrease of 24.0% (or R$279 million) in financial expenses, mainly due to: (a) a decrease of R$580 million in derivatives expenses; (b) a decrease of R$41 million in financial expenses from debt charges as a result of lower indebtedness; and (c) an increase of R$469 million in expenses from monetary and exchange rate variations; and
(ii)	a decrease of R$23 million in financial income, mainly due to: (a) a decrease of 66.0% (or R$144 million) in income from financial investments; and (b) a decrease of 26.6% (or R$13 million) in income from interest of escrow deposits.

These decreases were partially offset by: (i) an increase of 100% (or R$163 million) in income from the adjustment of sector financial assets and liabilities (see Note 9 to our audited annual consolidated financial statements); (ii) an increase of 72.5% (or R$29 million) in income from monetary and exchange rate variations; (iii) an increase of 112.5% (or R$18 million) in discounts on the purchase of ICMS credit; and (iv) an increase of 4.3% (or R$11 million) in interests and fines.

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Generation (conventional sources)

Profit for the year from our generation from conventional sources segment (including intersegment transactions) increased by 17.7% (or R$116 million), to R$770 million during the year ended December 31, 2018 from R$654 million for the year ended December 31, 2017. This increase was mainly due to: (i) an increase of 7.2% (or R$55 million) in income from electric energy service; and (ii) a decrease of 24.4% (or R$80 million) in net financial expense.

The decrease in net financial expense was due mainly to: (i) a decrease of R$214 million of expenses from derivatives; and (ii) a decrease of 29.4% (or R$104 million) in interest on debt. These decreases were partially offset by: (i) an increase of R$163 million in monetary and exchange rate variation expenses; and (ii) a decrease of 50.6% (or R$41 million) in income from financial investments.

Generation (renewable sources)

The profit for the year from our generation from renewable sources segment (including intersegment transactions) increased by 504.2% (or R$99 million), to R$119 million in the year ended December 31, 2018 compared to profit for the year of R$20 million in 2017, mainly due to the combined effect of: (i) a decrease of R$111 million in income tax and social contribution tax expenses, (ii) the decrease of 3.1% (or R$19 million) in income from electric energy service; and (iii) a decrease of 1.3% (or R$7 million) in net financial expense.

The decrease in net financial expense was driven by (i) a decrease of R$109 million in debt expenses and monetary and exchange rate variation expenses; (ii) a decrease of R$19 million in capitalized borrowing costs, which is accounted for as a decrease in financial expenses; and (iii) an increase of R$26 million in other financial revenue from CCEE financial settlements, offset by (i) an increase of R$78 million in other financial expenses; and (ii) a decrease of R$33 million in income from financial investments.

Commercialization

Compared to the year ended December 31, 2017, profit for the year from our commercialization segment (including intersegment transactions) decreased 41.2% (or R$37 million), to R$53 million in the year ended December 31, 2018, reflecting the combined effect of: (i) a decrease of R$20 million in net financial income, mainly related to the impact in monetary and exchange rate variations and derivatives; and (ii) a decrease of R$17 million in income and social contribution tax expenses.

Services

Compared to the year ended December 31, 2017, profit for the year from our services segment (including intersegment transactions) decreased 21.7% (or R$12 million), to R$43 million in the year ended December 31, 2018, reflecting the combined effects of: (i) an increase of R$20 million in personnel and third party services; (ii) a decrease of R$4 million of net financial income; (iii) a decrease of R$13 million in income and social contribution tax expenses; and (iv) an increase of 7.4% (or R$5 million) in the income from electric energy service.

Liquidity and Capital Resources

Our credit risk and debt securities are rated by Standard and Poor’s, Fitch Ratings and Moody’s. These ratings reflect, among other factors, perspectives for the Brazilian electricity sector, the political and economic context, country risk, hydrological conditions in the areas where our power plants are located, our operational performance and debt levels, and the ratings and outlook of our controlling shareholders.

On December 31, 2019, our working capital was positive, reflecting an excess of current assets over current liabilities of R$275 million, a decrease of R$712 million compared to a positive working capital balance of R$987 million at December 31, 2018. The main causes of this decrease in working capital were:

(i)

an increase of R$862 million in our trade payables balance;

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(ii)	a decrease of R$237 million in our net sector financial assets and liabilities balance, from an assets position of R$1,094 million in 2019 compared to R$1,331 million in 2018;
(iii)	an increase of R$138 million in our private pension plan balance;
(iv)	an increase of R$95 million in our short term debt balance, which includes loans and financing, debentures and related accrued interest; and
(v)	a decrease of R$45 million in derivative instruments, net.

These factors were partially offset by an increase of R$46 million in our cash and cash equivalents balance, due to net cash generation of R$5,789 million in operating activities, offset by cash usage of R$2,674 million in financing activities and cash usage of R$3,069 million in investing activities.

As of December 31, 2019, we believe that our working capital is sufficient to meet our operational needs for the next 12 months.

Sources of Funds

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

Cash Flow

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

Our net cash provided by operating activities was R$5,789 million in the year ended December 31, 2019, compared to R$857 million in the year ended December 31, 2018 (an increase of R$4,932 million or 575.7%). The increase primarily reflects:

(i)	a net increase of R$2,134 million in cash generation arising from increases in operating liabilities, primarily due to accounts payables (R$1,738 million) and regulatory charges (R$513 million), partially offset by a decrease of R$268 million in provisions for tax, civil and labor risks and a decrease of R$92 million in payables of amounts provided by the CDE Account;
(ii)	a net decrease of R$1,666 million in operating assets, primarily driven by net sector financial assets and liabilities (R$1,513 million) and accounts receivable from consumers (R$375 million), partially offset by an increase of R$266 million in income tax and social contribution recoverable and CDE Accounts receivable (R$23 million);
(iii)	an increase of R$1,053 million in profit for the year, adjusted for the reconciliation of net cash; and
(iv)	a decrease of R$73 million in cash consumption in payments of interest, which amounted to R$221 million in 2019, offset by income tax and social contributions (R$147 million).

Our net cash provided by operating activities was R$857 million in the year ended December 31, 2018, compared to R$2,034 million in the year ended December 31, 2017 (a decrease of R$1,177 million or 57.9%). The decrease primarily reflects:

(i)	a net increase of R$823 million in operating assets, primarily driven by sector financial assets (R$421 million), dividends and interest on capital received (R$419 million) and accounts receivable from consumers (R$284 million), partially offset by a decrease in escrow deposits (R$271 million) and concession financial assets – transmission companies (R$57 million);

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(ii)	a net decrease of R$782 million in cash generation arising from increases in operating liabilities, primarily due to accounts payables (R$1,415 million) and regulatory charges (R$646 million), partially offset by an increase of R$1,025 million in sector financial liabilities, other taxes and social contributions (R$202 million) and payables of amounts provided by the CDE Account (R$54 million);
(iii)	an increase of R$413 million in profit for the year, adjusted for the reconciliation of net cash; and
(iv)	a decrease of R$15 million in cash consumption in income tax and social contributions (R$493 million), offset by payments of interest (R$478 million).

Our net cash from financing activities recorded a consumption of cash of R$2,674 million in the year ended December 31, 2019 compared to a consumption of cash of R$364 million in the year ended December 31, 2018. This increase of R$2,309 million was due to:

(i)	an increase of R$4,106 million due to our acquisition of equity interest in our subsidiary CPFL Renováveis;
(ii)	a decrease of R$4,354 million in borrowings and debentures;
(iii)	an increase of R$3,614 million in funds from our Follow-on Offering; and
(iv)	a decrease of R$3,068 million in repayment of principal of borrowings and debentures.

Our net cash from financing activities recorded a consumption of cash of R$364 million in the year ended December 31, 2018 compared to a generation of cash of R$2,440 million in the year ended December 31, 2017. This increase of R$2,076 million was due to:

(i)	an increase of R$6,213 million in fundraising from borrowings and debentures; and
(ii)	a decrease of R$4,285 million related to payments of loans, financing, debentures and derivatives.

Borrowings and Debentures

The following table sets forth our current and noncurrent borrowings and debentures (in millions) for the year ended December 31, 2019:

	2019
	Current	Noncurrent
Secured debt	1,331	4,337
Unsecured debt	2,129	11,113
Total	3,460	15,450

Our total borrowings and debentures decreased by R$1,467 million, or 7.2%, from December 31, 2018 to December 31, 2019, as result of the issuance of new debentures and other debt incurred by us, with amortization of principal loans and debentures in the amount of R$7,137 million, partially offset by the raising of R$5,257 million in loans and debentures. Our main fundings are as follows:

Issuances of debentures, principally in the amount of R$1,380 million by CPFL Paulista, R$838 million by CPFL Renováveis, R$740 million by RGE, R$325 million by CPFL Brasil, R$215 million by CPFL Piratininga and R$190 million by CPFL Santa Cruz, to improve working capital, finance debt payments, refinance maturing debt and fulfill required investments.

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·	Incurrence of new debt denominated in U.S. dollars, principally in the amount of R$628 million by CPFL Paulista, R$43 million by CPFL Piratininga and R$13 million by CPFL Geração. This debt was incurred in order to improve working capital, finance debt payments, refinance maturing debt and fulfill required investments.
·	Incurrence of new debt denominated in reais from BNDES, principally in the amount of R$154 million by RGE, R$100 million by CPFL Paulista, R$70 million by CPFL Santa Cruz and R$55 million by CPFL Piratininga to fulfill required investments.
·	Issuances of promissory notes in the amount of R$476 million by CPFL Paulista (R$351 million) and CPFL Piratininga (R$125 million) to improve working capital.

In 2020 and 2021, we expect to continue to take advantage of the financing opportunities offered by the market through issuing debentures and debt for working capital, both in the domestic and overseas markets, and those offered by the government through lines of financing provided by BNDES, in order to expand and modernize the electricity system of distributors, to undertake new investments in the generation segment.

Moreover, through fundraising we seek to maintain our group’s liquidity and a favorable debt profile through extending the average maturity of our debt and reducing its cost.

Terms of Outstanding Borrowings and Debentures

Our total borrowings and debentures outstanding at December 31, 2019 (including accrued interest) was R$18,910 million. R$5,009 million of our total outstanding debt, or 26.5%, was denominated in foreign currency, principally U.S. dollars. We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations. Of our total outstanding debt, R$3,459 million falls due in 2020.

Our major categories of borrowings and debentures are as follows:

·	Floating rate. At December 31, 2019, we had R$4,701 million outstanding under a number of loan agreements indexed at floating rates based on the TJLP and TLP indices (R$4,353 million), CDI and SELIC rate (R$263 million) and other loan agreements (R$84 million).These loans are denominated in reais. The most significant part of these loans relates to: (i) loans indexed to the TJLP and TLP incurred by our generation subsidiary CPFL Renováveis (R$2,626 million) and by our distribution subsidiaries, CPFL Paulista, CPFL Piratininga, CPFL Santa Cruz, and RGE (R$1,717 million); and (ii) loans indexed to the CDI incurred by our generation subsidiary CPFL Renováveis (R$158 million).
·	Fixed rate. At December 31, 2019, we had R$711 million outstanding under a number of loan agreements based on a fixed rate. These loans are denominated in reais. The most significant part of these loans relates to our generation subsidiary CPFL Renováveis (R$464 million).
·	Debentures. At December 31, 2019, we had indebtedness of R$8,546 million outstanding under several series of debentures. The most significant part of these debentures was issued by CPFL Paulista (R$2,157 million), CPFL Renováveis (R$1,703 million), RGE (R$1,379 million), CPFL Piratininga (R$826 million) and CPFL Geração (R$1,619 million). The terms of these debentures are summarized in Note 19 to our audited annual consolidated financial statements.
·	Foreign currency-denominated debt. At December 31, 2019, we had the equivalent of R$5,009 million outstanding under other loans denominated in foreign currency, principally U.S. dollars (US$1,036 million or R$4,173 million). We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations.

See Notes 18, 19 and 35 to our audited annual consolidated financial statements for more information on our borrowings, debentures and derivatives.

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Financial and Operating Covenants

We are subject to financial and operating covenants under our financial instruments and those of our subsidiaries. The main parameters established by financial institutions under these instruments are: (i) net indebtedness divided by EBITDA; (ii) EBITDA divided by finance income (costs); (iii) net indebtedness divided by the sum of net indebtedness and net equity; (iv) maintaining the debt coverage ratio and own capitalization ratio; and (v) other restrictions such as restrictions on the payment of dividends to our subsidiaries. Certain of these covenants require us to calculate the metrics used for covenant compliance on an as adjusted basis, to reflect proportional consolidation of the financial position and results of operations of all companies in which we hold 10% or more of the voting stock, and to reflect our equivalent stake in each company that we control with less than 100% (such as CPFL Energias Renováveis S.A. and CERAN – Companhia Energética Rio das Antas).

Our management and that of our subsidiaries monitor these ratios systematically and constantly to ensure that we and our subsidiaries remain in compliance with these contractual conditions. In the opinion of our management, we were in compliance with these covenants as at December 31, 2019.

Uses of funds

Our cash flow used for investing activities was R$3,069 million in the year ended December 31, 2019 compared with R$1,851 million in the year ended December 31, 2018. This increase of R$1,218 million (65.8%) primarily reflects:

(i)	a net increase of R$1,019 million in securities, pledges and restricted deposits; and
(ii)	an increase of R$285 million in additions to contractual assets.

Our cash flow used for investing activities was R$1,851 million in the year ended December 31, 2018 compared with R$2,509 million in the year ended December 31, 2017. This decrease of R$659 million (26.2%) primarily reflects:

(i)	a decrease of R$410 million in property, plant and equipment mainly due to the use of cash for investments in our renewable energy subsidiaries;
(ii)	a decrease of R$307 million in securities, pledges and restricted deposits; and
(iii)	a capital increase of R$93 million in existing investees.

Funding Requirements and Contractual Commitments

Our capital requirements are primarily for the following purposes:

·	We make capital expenditures to continue improving and expanding our distribution system and to complete our renewable generation projects. See “—Capital Expenditures” below for more information on our historical and planned capital expenditures;
·	Repayment or refinancing of maturing debt. At December 31, 2019 we had outstanding debt maturing during the following 12 months in the total amount of R$3,459 million; and
·	Dividends on a semiannual basis. We paid R$487 million in dividends in 2019 (R$279 million in 2018). See “Item 10. Additional Information—Allocation of Profit for the year and Distribution of Dividends—Interest Attributable to Shareholders’ Equity” and the Unconsolidated Statement of Cash Flow in Note 25.6 to our audited annual consolidated financial statements for more information on dividends.

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We have adopted a strategy to preserve minimum cash in order to access the capital markets at more favorable conditions and cover cash needs for the year. We employed this strategy in 2019, are continuing to employ it in 2020 and expect to continue to employ it in 2021. CPFL has broad access to the capital markets to raise funds and possible additional cash needs.

Capital Expenditures

Our principal capital expenditures in the past several years have been for the maintenance and upgrading of our Distribution Networks and for our renewable generation projects. In the years ended December 31, 2019, 2018 and 2017, all our capital expenditures have been made in Brazil. The following table sets forth our capital expenditures for the years ended December 31, 2019, 2018 and 2017:

	Year ended December 31,
	2019	2018	2017
	*(in millions ofreais***)
Distribution	2,033	1,770	1,883
Conventional Generation	12	12	9
Renewable Generation	126	225	621
Commercialization and other investments	62	56	58
Total	2,233	2,062	2,570

In addition to the capital expenditures shown above, we invested R$21 million in 2019, R$3 million in 2018 and, R$46 million in 2017 related to the construction of transmission lines through our transmission companies.

We plan to make capital expenditures aggregating R$3,069 million in 2020, R$2,924 million in 2021, R$2,906 million in 2022, R$2,334 million in 2023 and R$2,306 million in 2024. Of total budgeted capital expenditures over this period, R$11,587 million are expected to be invested in our distribution segment, R$1,085 million in our renewable generation segment and R$73 million in our conventional generation segment. In addition, over this period, we plan to invest R$564 million in our transmission activities and R$233 million in our commercialization and services activities. Part of these expenditures, particularly in generation projects, is already contractually committed. See “—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments” for more information. Planned capital expenditures for development of our generation capacity, and the related financing arrangements, are discussed in more detail under “Item 4. Information on the Company—Generation of Electricity.”

In addition, we invest in innovation and technology to improve the quality of our services and our operational efficiency, which are our enduring goals. The Smart Grid Program, which is focused on smart measurement for high and medium voltage consumers and excellence in workforce management through the use of smartphones and new software, increased our operational efficiency. Expanding the scope of smart measurement, in 2019 we started a pilot project in the city of Jaguariuna, in the Campinas region in São Paulo, which will evaluate four technologies that support the communication of more than 22,000 smart meters, RF Mesh, LoRa, PLC and LTE. The project aims at providing information to support the choice of technology and assist in defining a strategy for a large-scale deployment, in addition to providing our customers with an app with energy consumption information on a daily basis. By December 2019, there were 20,280 smart meters installed with the four technologies in operation.

With a focus on increasing operational efficiency, we started a project to replace and standardize technical systems for the operation of the electric system with the implementation of Advanced Distribution Manager System, or ADMS. This is the first system with this scope in Latin America and we expect it to bring significant benefits to our processes. The first go-live of the ADMS is scheduled to take place in July 2020. In addition, in 2019, we implemented 1,563 ACRs, bringing the total number of ACRs in our concession areas to 11,394, exceeding 10,000 installed reclosers. These ACRs allow greater flexibility in the operation of the electrical system and, associated with the technological resources provided by the new ADMS system, we expect they will further increase the quality of our energy supply.

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Termination of the statutory reserve of the financial asset of concession

The Extraordinary Shareholders’ Meeting held on April 27, 2018 approved the termination of the statutory reserve of the financial asset of concession and the transfer of the respective balance of R$827 million to the retained earnings account.

Dividends

For the year ended December 31, 2019, our board of directors recommended a dividend distribution of R$642 million, equivalent to R$0.557068261 per share for approval by our shareholders in our Annual Shareholders’ Meeting, which was scheduled to take place on April 30, 2020 but was postponed on April 6, 2020 until further notice in accordance with applicable Brazilian law due to concerns over the COVID-19 pandemic.

For the year ended December 31, 2018, our board of directors approved a dividend distribution of R$489 million, equivalent to R$0.480182232 per share, approved by shareholders in our Annual Shareholders’ Meeting, on April 30, 2019.

For the year ended December 31, 2017, our board of directors approved a dividend distribution of R$280 million, equivalent to R$0.275259517 per share, approved by shareholders in our Annual Shareholders’ Meeting, on April 27, 2018.

	December 31, 2019
Profit for the year	2,702,671
Realization of comprehensive income	25,672
Prescribed dividends	765
Profit basis for allocation	2,729,108
Legal reserve	(135,134)
Statutory reserve – working capital reinforcement	(518,795)
Minimum mandatory dividend	(641,884)
Proposed additional dividend	(1,433,295)

See Notes 25.5, 25.6 and 25.7 to our audited annual consolidated financial statements for additional information.

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2019 (including our noncurrent contractual obligations).

	Payments due by period
	Total	Less than 1 year	1–3 years	4–5 years	After 5 years
	(in millions of reais)
Contractual obligations as of December 31, 2019:
Suppliers	3,620	3,260	212	-	148
Borrowings and debentures⁽¹⁾	23,606	4,582	8,542	5,944	4,437
Public utilities⁽¹⁾	103	12	17	28	46
Post-employment benefits⁽²⁾	1,637	164	440	433	600
Regulatory liabilities	232	232	-	-	-
Others	456	259	3	3	190
Total of Balance Sheet items⁽¹⁾	29,654	8,510	9,315	6,408	5,421

Leasings and rentals	261	38	72	69	82
Electricity purchase agreements⁽³⁾	128,172	14,886	27,345	28,309	57,633
Distribution and transmission systems service charges⁽⁴⁾	44,852	2,762	7,193	9,172	25,725
Premium of Hydrological Risk renegotiation (GSF)⁽⁵⁾	320	16	38	36	229
Generation projects⁽⁶⁾	2,771	757	655	239	1,119
Total of other commitments	176,376	18,460	35,302	37,825	84,789
Total of contractual obligations	206,030	26,970	44,616	44,234	90,210

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(1) Includes interest payments, including future projected or estimated interest not recorded on our balance sheet.

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

(3) Amounts payable under long-term energy purchase agreements, which are subject to changing prices and provide for renegotiation under certain circumstances. The table represents the amounts payable for the contracted volumes applying the year-end 2019 price. See “—Background—Prices for Purchased Electricity” and Note 37 to our audited annual consolidated financial statements for more information.

(4) Estimated expenses related to distribution and transmission ESS through the end of the concessions.

(5) Estimated expenses for the payment of risk premium in connection with renegotiation of hydrological risk.

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

Research and Development and Electricity Efficiency Programs

In accordance with applicable Brazilian law, since June 2000, companies holding concessions, permissions and authorizations for distribution, generation and transmission of electricity have been required to dedicate a minimum of 1.0% of their net operating revenue each year to research and development and electricity efficiency programs. Small Hydroelectric Power Plants and wind, solar and biomass energy projects are not subject to this requirement. Beginning in April 2007, our distribution concessionaires dedicated 0.5% of their net operating revenue to research and development and 0.5% to electricity efficiency programs, while our generation concessionaires dedicated 1.0% of their net operating revenue to research and development. 0.3% of the net operating revenue of our distribution concessionaires that is dedicated to research and development is directed to the MME and the National Fund for Scientific and Technological Development (Fundo Nacional de Desenvolvimento Científico e Tecnológico), or the FNDCT, and the remaining 0.2% is managed and invested by our distribution concessionaires. 0.1% of the net operating revenue of our distribution concessionaires that is dedicated to electricity efficiency programs is directed to the National Program for Conservation of Electrical Energy (Programa Nacional de Conservação de Energia Elétrica) and the remaining 0.4% is managed and invested by our distribution concessionaires. Similarly, for our generation concessionaires, 0.6% of the net operating revenue dedicated to research and development is directed to the MME and the FNDCT and the remaining 0.4% is managed and invested by our generation concessionaires.

Our electricity efficiency program is designed to foster the efficient use of electricity by our consumers, to reduce technical and commercial losses and offer products and services that improve satisfaction and loyalty and enhance our corporate image. Our research and development programs utilize technological research to develop products, which may be used internally, as well as commercialized in the market. We carry out certain of these programs through strategic partnerships with national universities and research centers, and the vast majority of our resources are dedicated to innovation and development in new technologies applicable to our business.

Our disbursements on research and development and energy efficiency programs (regulatory charges) in the years ended December 31, 2019, 2018 and 2017 totaled R$ 117 million, R$116 million and R$105 million, respectively. The amount reported includes the disbursements of our distribution concessionaires, powertransmission companies and our generation concessionaires, including the companies with specific purposes in which CPFL holds a minority interest.

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Off-Balance Sheet Arrangements

As of December 31, 2019, we had no off-balance sheet arrangements that have or are reasonably likely to have a material impact on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

We have used the following amounts of our funding arrangements:

			*In 2019 (in thousands ofreais***)
Modality	Approval	Company	Borrowings and debentures	Released	Unfunded balance
BNDES FINEM	In 2018	RGE	1,133,024	684,000	449,024
BNDES FINEM	In 2018	CPFL Paulista	953,392	505,000	448,392
BNDES FNE	In 2018	Pedra Cheirosa I e II	209,205	198,821	10,384
BNDES FINEM	In 2018	CPFL Piratininga	347,264	231,000	116,264
BNDES FINEM	In 2018	CPFL Santa Cruz	174,954	149,000	25,954
BNDES FINEM	In 2018	Boa Vista 2	144,500	119,400	25,100
BNDES FNE	In 2018	CPFL Maracanaú	42,422	-	42,422
BNDES FNE	In 2019	SPE Costa das Dunas	70,482	-	70,482

Trend Information

Expectations for 2020 seemed auspicious. The approval of the social security reform bill by the Brazilian Congress, which is expected to prevent a strong escalation of social security spending in the long term, consolidated the view that a structural fall in interest rates would be underway, so that the interest curve, as a whole, underwent a sharp correction.

The monetary boost began to improve the Brazilian economy. Improved data were seen in the credit, retail, industrial and in some service segments. Even civil construction, a segment that suffered the consequences of the previous years’ crisis in a more profound and prolonged way, showed the first signs of a recovery.

The year 2019 ended, thus, with the Brazilian economy gaining traction and lagged effects of monetary expansion yet to be verified, with the first two months of 2020 moving as expected, pointing to a growth of 1.5% to 2% in 2020. However, in the end of February 2020, with the confirmation of the first case of COVID-19 in Brazil, the scenario changed radically.

Not only in Brazil, but throughout the world, national economies are experiencing a strong increase in the degree of uncertainty amidst the policies of social distancing necessary to prevent the collapse of health systems in the wake of the raise of COVID-19 infections.

This exceptionally high degree of economic uncertainty has caused a sharp deterioration in expectations and a significant increase in the dispersion in the projections for global GDP and, also, for Brazil. The pandemic is expected to lead to a GDP contraction in 2020 and to a recovery beginning in 2021, since it is difficult to determine when the epidemic will peak in Brazil and for how long its effects will continue.

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The significant decrease in domestic demand is expected to result in an even lower inflation rate in 2020, of approximately 2% on an annual basis, even if the U.S. dollar/real exchange rate is under pressure in the short term and presents a slower decompression throughout the year. This has allowed the Brazilian Central Bank to continue to reduce the SELIC basic interest rate.

In effect, projections point to an inflation rate, as well as the set of prices in the services industry, which are more sensitive to the economic cycle, running well below the middle of the inflation target (4.0% per year for 2020) on the horizon relevant to monetary policy. Thus, even if the Brazilian Central Bank seems reluctant to promote substantial additional interest cuts, markets currently estimate that the SELIC rate will be reduced to around 3.25% on an annual basis.

COVID-19 pandemic

On March 11, 2020, the World Health Organization declared COVID-19 to be a pandemic. The outbreak triggered significant decisions from governments and private sector entities that added to the potential impact of the outbreak, increased the degree of uncertainty for economic agents and may impact corporate financial statements. The world’s main economies and the main economic blocs are assessing significant stimulus packages to overcome the potential economic recession that the measures to mitigate the spread of COVID-19 may cause.

In Brazil, the executive and legislative branches of the government proposed legislation to prevent and contain the pandemic, as well as to mitigate its economic impact, particularly Legislative Decree No. 6, published on March 20, 2020, which declared a state of public calamity. The state and municipal governments also proposed legislation seeking to restrict the free movement of people and commercial and service activities, in addition to making emergency investments in the healthcare sector available.

Our management has continuously assessed the impact of the outbreak on our operations and our equity and financial position and that of our subsidiaries, in order to implement the appropriate measures to mitigate the impact on our operations. Up until the date of this annual report, the following measures have been taken and the primary matters that are constantly being monitored are listed below:

·	Implementing temporary measures for employees, such as home office plans, adapting collective spaces to avoid agglomerations of people, and other applicable health measures;
·	Negotiating with suppliers of imported equipment to evaluate delivery deadlines in light of the new scenario, considering that so far there have not been any indications of significant risks of delay that could impact our operations;
·	Evaluating contractual terms with financial institutions relating to loans and financing as well as supplier payments to mitigate any potential liquidity risks;
·	Monitoring the variations of market indexes that may affect our loans, financing and debentures;
·	Evaluating potential renegotiations with customers, due to a possible macroeconomic downturn and a resulting reduction in energy consumption. Our management’s expectation is that such renegotiations will be mostly directed towards temporary shifts in contracted quantities;
·	Monitoring possible over-contracting of our group’s distributors due to load reductions and consequent energy surpluses exceeding the 5% level contemplated by regulatory requirements; and
·	Monitoring the default of our group’s distributors, especially in light of the 90-day suspension beginning March 25, 2020 of the service interruption due to delinquency for certain consumers (residential and essential services, in accordance with the specific rules established by ANEEL). Our management’s expectation is that most of this impact will be temporary, until the service interruption due to delinquency policies are reestablished and/or new possible government subsidy actions are implemented.

Due to the significance and complexity of these matters from a regulatory perspective, many of these issues are being discussed with ANEEL.

The financial and economic effect on us and our subsidiaries during the course of the 2020 financial year will depend on the outcome of this crisis and its macroeconomic impacts, especially with respect to reductions in economic activity, as well as the extent of the social isolation policies. We and our subsidiaries will continue to regularly monitor the effects of the crisis and its impacts on our operations and financial statements.

For more information on the risks relating to the COVID-19 pandemic, see “Item 3. Key Information—Risk Factors—Risks Relating to our Operations and the Brazilian Power Industry—An occurrence of a natural disaster, widespread health epidemic or pandemic or other outbreaks could significantly harm our business, financial condition and results of operations. Furthermore, the spread of communicable diseases on a global scale, such as the COVID-19 pandemic, may affect investment sentiment, cause disruptions and result in sporadic volatility in global markets. As a result, the Brazilian economy and outlook may be affected, and consequently, our business, financial condition and trading price of our common shares may be adversely affected.”

Critical Accounting Policies

In preparing our financial statements, we make estimates concerning a variety of matters. Some of these matters are highly uncertain, and our estimates involve judgments we make based on the information available to us. In the discussion below, we have identified several other matters that would materially affect our financial presentation if either (i) we used different estimates that we could reasonably have used or (ii) in the future we change our estimates in response to changes that are reasonably likely to occur.

The discussion addresses only those estimates that we consider most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate. There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation. See the notes to our audited annual consolidated financial statements included herein for a more detailed discussion of the application of these and other accounting policies.

We initially adopted IFRS 16—Leases and IFRIC 23—Uncertainty regarding treatment of income taxes as of January 1, 2019.

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IFRIC 23 – Uncertainty over Income Tax Treatments

IFRIC 23was issued in May 2017 in order to clarify the accounting for tax positions that may not be accepted by the tax authorities in regard to IRPJ and CSLL matters. In general lines, the main point of analysis of the interpretation refers to the probability of acceptance by the tax authorities of the tax treatment chosen by a company’s corporate group.

IFRIC 23 will be effective for annual reporting periods beginning on or after January 1, 2019. A company’s corporate group assessed the interpretation and the impact of adopting the standard was the reclassification of the balance of provision for tax risks related to income taxes to the line item Corporate income tax.

Leases

This policy is applicable from January 1, 2019.

Issued on January 13, 2016, IFRS 16 establishes, from the lessee’s perspective, a new accounting method for leases previously classified as operating leases and their accounting registration is to be carried out in a manner similar to leases classified as financial leases. With respect to lessors, in practice, the standard maintains the requirements of IAS 17, while adding a few additional disclosure aspects.

The new standard introduced a single model for the accounting of leases in the balance sheet of lessees. We recognize a right of use asset that represents our right to use the leased asset and a lease liability that represents our obligation to make lease payments. We chose to adopt the recognition exemptions provided for in the standard for short-term leases (contracts with a maximum term of 12 months) and low value items (where the fair value of the identified leased asset is less than US$5 thousand). The lessor’s accounting remained similar to the current standard, which requires that lessors continue to classify leases as financial or operating.

The standard states that a contract is or contains a lease if it conveys the right to control the use of an identified asset for a period of time in exchange for consideration. As a result of the initial application of IFRS 16, in relation to leases that were previously classified as operating leases, we assessed the standard and concluded that there was no material impact on its adoption.

Intangible Assets and Contract Assets – In Progress

Intangible assets and contract assets – in progress includes rights related to intangible assets such as goodwill, concession exploitation rights, software and rights-of-way.

Goodwill that arises from the acquisition of subsidiaries is measured based on the difference between the fair value of the consideration paid for the acquisition of a business and the net fair value of the assets, adding the portion of noncontrolling interests and liabilities of the acquired subsidiary.

Goodwill is subsequently measured at cost less accumulated impairment losses. Goodwill and other intangible assets with indefinite useful lives, if any, are not subject to amortization and are tested annually for impairment.

Negative goodwill is recognized as a gain in the statement of profit or loss in the year of the business acquisition.

In the individual financial statements, fair value adjustments (value added) of net assets acquired in business combinations are included in the carrying amount of the investment and the amortization is classified in the individual statement of income as “equity interest in associates and joint ventures” in accordance with the Interpretation of the Accounting Pronouncements Committee (Interpretação do Comitê de Pronunciamentos Contábeis), or ICPC, 09 (R2). In the consolidated financial statements, the amount is stated as an intangible asset and its amortization is classified in the consolidated statement of profit and loss as “amortization of concession intangible asset” in other operating expenses.

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

(i)	Acquisitions through business combinations: the portion arising from business combinations that corresponds to the right to operate the concession amortized using the straight-line method over the remaining period of the concessions;
(ii)	Investments in infrastructure (International Financial Reporting Interpretations Committee, or IFRIC, 12 – Concession contracts) - in progress: under the electric energy distribution concession agreements with our subsidiaries, the recognized intangible assets correspond to the concessionaire’s right to charge the consumers for use of concession infrastructure. Since the exploration term is defined in the agreement, intangible assets with defined useful lives are amortized over the concession period in proportion to a curve that reflects the consumption pattern in relation to the expected economic benefits. Items comprised in the infrastructure are directly tied to our electric energy distribution operation and comply with the same regulatory rules;
(iii)	Use of public asset: certain generation concessions were granted with the condition of payments to the federal government for use of public asset. On the signing date of the respective agreements, our subsidiaries recognized intangible assets and the corresponding liabilities, at present value. The intangible assets, capitalized by interest incurred on the obligation until the start-up date, are amortized on a straight-line basis over the remaining period of each concession.

As of January 1, 2018, the concession infrastructure assets of our distribution companies must be classified as contract assets during the construction or improvement period in accordance with the criteria of IFRS 15.

Impairment of Financial Assets

This policy is applicable from January 1, 2018.

- Financial Assets

IFRS 9 replaces the incurred loss model in IAS 39 with an expected credit loss (ECL) model.

Our group assesses evidence of impairment for certain receivables at both an individual and a collective level. Receivables that are not individually significant are collectively assessed for impairment. Collective assessment is carried out by grouping together assets with similar risk characteristics.

Our group recognizes impairment losses for ECLs on: (i) financial assets measured at amortized cost; (ii) debt investments measured at fair value through other comprehensive income, or FVOCI, when applicable; and (iii) contract assets.

Our group measures impairment allowances, adopting the simplified method of recognition, at an amount equal to lifetime ECLs, except for debt securities that are determined to have low credit risk at the reporting date, which are measured at 12-month ECLs.

When determining whether the credit risk of a financial asset has increased significantly since initial recognition and when estimating the expected credit losses, our group considers a simplified approach of default assessment which consists of measuring the expected loss of a financial asset equivalent to the lifetime expected credit loss of an asset including reasonable and supportable information that is relevant and available without undue cost or effort. This includes both quantitative and qualitative information and analysis, based on our group’s historical experience, informed credit assessment and including forward-looking information.

Our group considers a financial asset to be in default when the borrower has not complied with its contractual payment obligations and is unlikely to pay its obligations.

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Our group uses an allowance matrix based on its historical default rates observed along the expected lifetime of the trade receivables to estimate the expected credit losses for the lifetime of the asset where the history of losses is adjusted to consider the effects of the current conditions and its forecasts of future conditions that did not affect the period in which the historical data were based.

The methodology developed by our group resulted in a percentage of expected loss for bills of consumers, concessionaires and licenses that is in compliance with IFRS 9 and is described as expected credit losses, comprising in a single percentage the probability of loss weighted by the expected loss and possible results, that is, comprising the Probability of Default, Exposure At Default and Loss Given Default.

At each reporting date, our group assesses whether financial assets carried at amortized cost and debt securities at FVOCI, when applicable, are credit-impaired. A financial asset is “credit-impaired” when one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred.

Evidence that a financial asset is credit-impaired includes the following observable data:

·	significant financial difficulty of the borrower or issuer;
·	a breach of contract;
·	the restructuring of a loan or advance by our group on terms that we would not consider otherwise;
·	probability that the borrower will enter bankruptcy or other financial reorganization; or
·	the disappearance of an active market for a security because of financial difficulties.

Impairment losses related to consumers, concessionaires and licensees recognized in financial assets and other receivables, including contract assets, are recognized in profit or loss.

- Non-Financial Assets

Non-financial assets that have indefinite useful lives, such as goodwill, are tested annually for impairment to assess whether the asset’s carrying amount exceeds its recoverable amount. Other assets subject to amortization are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may be impaired.

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

The assets (e.g., goodwill and concession intangible assets) are segregated and grouped together at the lowest level that generates identifiable cash flows (the “cash generating unit”). If there is an indication of impairment, the loss is recognized in profit or loss. Except in the case of goodwill impairment, which cannot be reversed in the subsequent period, impairment analyses are reassessed for any possible reversals.

Pension Liabilities

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

Deferred Tax Assets and Liabilities

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

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We regularly review our deferred tax assets for recoverability. If evidences are not enough to prove that it is more likely than not that we will recover such deferred tax assets, then such asset is not registered in the balance sheet of the company. Also, if there are no evidences that allow us to expect sufficient future taxable income, or if there is a material change in the actual effective tax rates or time period within which the underlying temporary differences become taxable or deductible, we could be required to establish a valuation allowance against all or a significant portion of our deferred tax assets resulting in a substantial increase in our effective tax rate and a material adverse impact on our operating results.

Provision for Tax, Civil and Labor Risks

We and our subsidiaries are party to certain legal proceedings in Brazil arising in the normal course of business regarding tax, labor, civil and other matters.

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

Financial Instruments

This policy is applicable from January 1, 2018.

- Financial Assets

Financial assets are initially recognized on the date that they are originated or on the trade date at which we or our subsidiaries become parties to the contractual provisions of the instrument. Derecognition of a financial asset occurs when the contractual rights to the cash flows from the asset expire or when the risks and rewards of ownership of the financial asset are transferred.

Subsequent Measurement of Gains and Losses: Policy applicable from January 1, 2018

Financial assets measured at fair value through profit or loss (FVTPL)	These assets are subsequently measured at fair value. Net gains or losses, including interest or dividend income, are recognized in profit or loss.
Financial assets at amortized cost	These assets are subsequently measured at amortized cost using the effective interest method. The amortized cost is reduced by impairment losses. Interest income, foreign exchange gains and losses and impairment are recognized in profit or loss. Any gain or loss on the derecognition is recognized in profit or loss.
Debt investments at fair value through other comprehensive income (FVOCI)	These assets are subsequently measured at fair value. Net gains and losses are recognized in other comprehensive income, except the interest income calculated using the effective interest method, foreign exchange gains and losses and impairment, which are recognized in profit or loss. Upon derecognition, gains and losses accumulated in other comprehensive income are reclassified to profit or loss. We have no financial assets of this classification.
Equity instruments at fair value through other comprehensive income	These assets are subsequently measured at fair value. All gains and losses are recognized in other comprehensive income and are never reclassified to profit or loss, except dividends which are recognized as income in profit or loss (unless the dividend clearly represents a recovery of part of the cost of the investment). We have has no financial assets of this classification.

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Subsequent Measurement of Gains and Loss: Policy applicable before January 1, 2018

Financial assets measured at fair value through profit or loss (FVTPL)	These assets are subsequently measured at fair value. Net gains or losses, including interest or dividend income, are recognized in profit or loss.
Held-to maturity financial assets	These assets are measured at amortized cost using the effective interest method.
Loans and receivables	These assets are measured at amortized cost using the effective interest method.
Available-for-sale financial assets	These assets are measured at fair value and changes therein (other than impairment losses, interest income and foreign currency differences on debt instruments), are recognized in Other Comprehensive Income and accumulated in the fair value reserve. When these assets were derecognized, the gain or loss accumulated in equity are reclassified to profit or loss.

The indemnification rights at the end of the concession term of our distribution subsidiaries are classified as measured at fair value through profit or loss and the changes in the fair value of this asset are recognized in profit or loss.

Financial assets are not reclassified subsequent to their initial recognition unless our group changes its business model for managing financial assets, in which case all affected financial assets are reclassified on the first day of the first reporting period following the change in the business model.

Amortized Cost: A financial asset is measured at amortized cost if it meets both of the following conditions and is not designated as at FVTPL.

·	it is held within a business model whose objective is to hold assets to collect contractual cash flows; and
·	its contractual terms give rise on specified dates to cash flows that are related solely to payments of principal and interest on the principal amount outstanding.

Fair Value through Other Comprehensive Income (FVOCI): A debt investment is measured at FVOCI if it meets both of the following conditions and is not designated as at FVTPL:

·	it is held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets; and
·	its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

On initial recognition of an equity investment that is not held for trading, our group may irrevocably elect to present subsequent changes in the investment’s fair value in Other Comprehensive Income. This election is made on an investment-by-investment basis.

All financial assets not classified as measured at amortized cost or as at FVOCI as described above are measured at FVTPL. This includes all derivative financial assets. (See Note 35 to our audited annual consolidated financial statements). On initial recognition, our group may irrevocably designate a non-derivative financial assetthat otherwise meets the requirements to be measured at amortized cost, at FVOCI or at FVTPL, if doing so eliminates or significantly reduces an accounting mismatch that would otherwise arise.

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Business Model Assessment:

Our group conducts an assessment of the objective of the business model in which a financial asset is held at the portfolio level because this best reflects the way the business is managed and information is provided to management. The information considered includes the stated policies and objectives for the portfolio and the operation of those policies in practice. These include whether:

·	management’s strategy focuses on earning contractual interest income, maintaining a particular interest rate profile, matching the duration of the financial assets to the duration of any related liabilities or expected cash outflows or realizing cash flows through the sale of the assets;
·	how the performance of the portfolio is evaluated and reported to our group’s management;
·	the risks that affect the performance of the business model (and the financial assets held within that business model) and how those risks are managed;
·	how managers of the business are compensated (e.g., whether compensation is based on the fair value of the assets managed or the contractual cash flows collected); and
·	the frequency, volume and timing of sales of financial assets in prior periods, the reasons for such sales and expectations about future sales activity.

Financial assets that are held for trading or are managed and whose performance is evaluated on a fair value basis are measured at FVTPL.

Assessment whether contractual cash flows are solely payments of principal and interest:

For the purposes of this assessment, “principal” is defined as the fair value of the financial asset on initial recognition. “Interest” is defined as consideration for the time value of money and for the credit risk associated with the principal amount outstanding during a particular period of time and for other basic lending risks and costs (e.g., liquidity risk and administrative costs), as well as a profit margin.

In assessing whether the contractual cash flows are solely payments of principal and interest, the Group considers the contractual terms of the instrument. This includes assessing whether the financial asset contains a contractual term that could change the timing or amount of contractual cash flows such that it would not meet this condition. In making this assessment, our group considers:

·	contingent events that would change the amount or timing of cash flows;
·	terms that may adjust the contractual coupon rate, including variable rate features;
·	prepayment and extension features; and
·	terms that limit our claim to cash flows from specified assets (e.g., based on the performance of an asset).

For transactions involving the purchase and sale of energy by the trading subsidiaries, our group has an accounting policy aligned with its business strategy with instruments measured at amortized cost, which refer to agreements already entered into and still held with the purpose of receipt or delivery of energy in accordance with the requirements by the company related to purchase or sale. The transactions are usually long term and are never settled by the net cash amount or with another financial instrument and, even if some contract has a certain flexibility, the strategy of the Group’s portfolio is not changed for this reason.

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- Financial Liabilities

Financial liabilities are initially recognized on the date that they are originated or on the trade date at which we or our subsidiaries become a party to the contractual provisions of the instrument. Our group has the following main financial liabilities:

(i)	Measured at fair value through profit or loss: these are financial liabilities that are: (i) held for trading; (ii) designated at fair value in order to match the effects of recognition of income and expenses to obtain more relevant and consistent accounting information; or (iii) derivatives. These liabilities are measured at fair value, which fair value changes recognized in profit or loss except for changes in fair value attributable to credit risk, which are recognized in comprehensive income.
(ii)	Measured at amortized cost: these are other financial liabilities not classified in the previous category. They are measured initially at fair value net of any cost attributable to the transaction and subsequently measured at amortized cost using the effective interest rate method.

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

Financial assets and liabilities are offset and presented at their net amount when there is a legal right to offset the amounts and the intent to realize the asset and settle the liability simultaneously.

The classifications of financial instruments (assets and liabilities) are described in Note 35 to our audited annual consolidated financial statements.

- Issued Capital

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

Revenue Recognition

This policy is applicable from January 1, 2018.

The operating revenue in the normal course of our subsidiaries’ activities is measured at the fair value of the consideration received or receivable. The operating revenue is recognized when it represents the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services.

IFRS 15 establishes a revenue recognition model that considers five steps: (i) identify the contract with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the entity satisfies a performance obligation.

Thus, revenue is recognized only when (or if) the performance obligation is satisfied, that is, when the “control” of the goods or services of a certain transaction is actually transferred to the customer.

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The revenue from electric energy distribution is recognized when the energy is supplied. The energy distribution subsidiaries perform the reading of the consumption of their customers based on a reading routine (calendar and reading route) and invoice the consumption of MWh monthly based on the reading performed for each consumer. As a result, part of the energy distributed during the month is not billed at the end of the month and, consequently, an estimate is developed by Management and recorded as “Unbilled.” This unbilled revenue estimate is calculated using as a base the total volume of energy of each distributor made available in the month and the annualized rate of technical and commercial losses.

The revenue from energy generation sales is recognized based on the assured energy and at tariffs specified in the terms of the supply contracts or the current market price, as appropriate.

The revenue from energy commercialization is recognized based on bilateral contracts with market agents and properly registered with the CCEE.

The revenue from services provided is recognized when the service is provided, under a service agreement between the parties.

The revenue from construction contracts is recognized based on the reach of the performance obligation over time, considering the fulfillment of one of the following criteria:

(i)	the customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs;
(ii)	the entity’s performance creates or enhances an asset (for example, work in progress) that the customer controls as the asset is created or enhanced; or
(iii)	the entity’s performance does not create an asset with an alternative use to the entity and the entity has an enforceable right to payment for performance completed to date.

The provision of infrastructure construction services for transmission companies is recognized in accordance with IFRS 15, against a contract asset.

The revenues of the transmission companies, recognized as operating revenue, are:

·	Construction Revenue: Refers to the services of construction of electric energy transmission facilities. These are recognized according to the percentage of completion of the construction works.
·	Remuneration: Refers to the interest recognized under the straight-line method on the amount receivable from the construction revenue.
·	Revenue from Operations and Maintenance: Refers to the services of operations and maintenance of electric energy transmission facilities aimed at non-interruption of availability of these facilities.

No single consumer accounts for 10% or more of our group’s total revenue.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

Board of Directors

Our board of directors’ main duties and responsibilities are established by Brazilian Corporate Law and our bylaws, and include, among others, the responsibility to determine our overall strategic guidelines, establish ourgeneral business policies, elect our executive officers and supervise their management. Our Board of Directors operates according to its Internal Regulations (which establish, among other matters, the rules concerning the relationship between the Board of Directors and the committees, commissions and other departments of CPFL Energia and its subsidiaries), with due observance to the provisions of the Brazilian Corporate Law and our bylaws.

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Under our bylaws, members of the Board of Directors are elected by the holders of our common shares at the annual general shareholders’ meeting. According to our bylaws, our board of directors consists of a minimum of five members. Members of the Board of Directors serve one-year terms, re-election being permitted provided that they may be removed at any time by our shareholders at an extraordinary general meeting of shareholders. Our bylaws do not provide for a mandatory retirement age for our directors. The Board of Directors has one chairman and one vice-chairman, appointed among its members in the first meeting following the election of the directors.

The office of director may be permanently vacated by resignation, dismissal, disability, loss of mandate, proven impediment, death or the occurrence of other situations referred to by law, in which case the alternate director, if one has been elected, shall take the place of the director until the election of his/her substitute, which shall take place at the first general shareholders’ meeting held after the vacancy occurred.

A director may resign by written communication to the chairman of the Board of Directors, which takes effect with regard to our company, from the receipt of such communication.

The Board of Directors shall meet at least 12 times a year and, whenever requested by the chairman in accordance with our bylaws and the Internal Regulations of our board of directors. In the event of a tie, the chairman, or in his/her absence, the vice-chairman will have the deciding vote.

Under Brazilian Corporate Law, if a director or an executive officer has a conflict of interest with the company in connection with any proposed transaction, the director or executive officer must not vote in any decision of the Board of Directors, or of the board of executive officers, regarding such transaction, and must disclose the nature and extent of the conflicting interest for transcription in the minutes of the meeting. A director or an executive officer may not transact any business with CPFL Energia, including accepting any loans, except on reasonable or fair terms and conditions that are identical to the terms and conditions prevailing in the market or offered by third parties. Any transaction entered into between our shareholders or related parties and CPFL Energia (or its subsidiaries) that exceeds R$12,746,000.00, as adjusted annually by the IGP-M/FGV index, must be previously approved by our board of directors.

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

Currently, our board of directors consists of nine members, of which two are independents (in accordance with the listing regulations of the New Market segment of the B3, or theNovo Mercado, and our bylaws). All nine members of our current Board of Directors were elected at our annual and extraordinary general meeting of shareholders held on April 30, 2019. The terms of all nine members of our board of directors are expected to expire at our next annual general meeting of shareholders, which was scheduled to take place on April 30, 2020 but was postponed on April 6, 2020 until further notice in accordance with applicable Brazilian law due to concerns over the COVID-19 pandemic.

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

Name	Age	Position
Bo Wen	54	Chairman
Shirong Lyu	55	Vice-chairman
Yang Qu	54	Member
Yumeng Zhao	46	Member
Gustavo Estrella	46	Member
Hong Li	49	Member
Anselmo Henrique Seto Leal	37	Member
Antonio Kandir	67	Independent Member
Marcelo Amaral Moraes	52	Independent Member

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Bo Wen – Graduated and got the bachelor’s degree of engineering in Power System and Automation from Chongqing University of China in 1988, got the master's degree in Management Science from Xian Jiaotong University of China in 2002. He began his career in State Grid Gansu Electric Power Company, having experience in the field of grid planning, grid dispatch, project design and construction, grid operation and maintenance, procurement, rural electrification, law and policy research, as well as enterprise management, serving as field engineer, section head, division head, general manager, department director, deputy chief engineer in different regional branches and headquarters. In 2005, he was appointed as senior vice president of State Grid Gansu Electric Power Company. In 2009, he was appointed as Executive vice president of State Grid Xinjiang Electric Power Company. From 2011 to 2018, he held positions of member of the Board of Directors and Technical Director of the National Grid Corporation of the Philippines, as well as General Director of the Phillippines branch of State Grid Corporation of China. As of 2019, he has held the position of Chairman of our Board of Directors, President CEO of State Grid Brazil Power Participações S.A. and Senior Vice President of State Grid International Development Corporation.

Shirong Lyu – Graduated in Electrical Power Systems and Automation from Xi'an Jiaotong University (1983-1987), and the Doctor's degree in Electrical Power Systems and Automation from Xi'an Jiaotong University（1995-1999）. He began his career in the electric power sector of State Grid Group, and of which CPFL Energia was a member, in Northwest China Gird Company Limited, where he served as Director of Construction Department since 2003. He was also the Deputy Director General of SGCC’s Office in the Philippines and Head of P&E Group of National Grid Corporation of the Philippines (NGCP) (2007-2010), Vice President of State Grid Brazil Holding Company (2010-2014), Vice President of State Grid International Development Co., Ltd. (2014-2016). From 2016 to 2018, he also held the positions of Deputy Director General of International Corporation Department of SGCC. He is currently the Senior Executive Vice President of CPFL Energia and Vice President of Strategy, Innovation and Business Excelence of CPFL Energia.

Yang Qu – Graduated in Electrical Power Systems and Automation from Chengdu University of Science and Technology (1982-1986). Since 1986, in the State Grid group, and of which CPFL Energia was a member, he began his career in Henan Transmission and Transformation Engineering Company (1986-2003). Between 2003 and 2006, he served as Deputy Chief Engineer and Director at the Henan Transmission and Transformation Engineering Company/ State Grid Henan Electric Power Company's Office in Vietnam. Then he held the position of Deputy Director of State Grid Henan Electric Power Company in Vietnam Office (2006-2008), Deputy Director at General Office of the International Cooperation Department of the State Grid Corporation of China (2008-2009), Deputy Director of the International Business Department of State Grid International Development Co., Ltd (2009-2010), and Director (2011-2014) of the Business Development Department of State Grid Brazil Holding SA. From 2014 to 2020, he held the position of Vice President of State Grid Brazil Holding S.A. Since March 11th, 2020, he has been serving as member of Board of Directors of Oman Electricity Transmission Company S.A.O.C.

Yumeng Zhao – Mr. Zhao graduated in Electromagnetic Instruments and Measuring from Huazhong University of Science and Technology in 1994 and later earned a Master’s Degree in Electrical Power Systems and Automation from Hefei University of Technology and an MBA from the Royal Melbourne Institute of Technology. He began his career in 1994 in the Electric Power Sector of State Grid Group. He held the position of Head of the Marketing Department at Hefei Power Supply Company from 2004 to 2006. He was also the manager of the Marketing Department of State Grid Anhui Electric Power Company in 2006, a deputy manager of Xuancheng Power Supply Company from 2006 to 2013, President of Chuzhou Electric Power Company from 2009 to 2013 and was general manager of Anqing Power Supply Company from 2013 to 2016. From 2016 to 2017, he was the Assistant President of State Grid International Development Co., Ltd. On March 26, 2018, Mr. Zhao was also elected as an alternate member to our Human Resources Management Committee. He also currently acts as our Executive Vice President and is a member of our Human Resources Management Committee.

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Gustavo Estrella – Mr. Estrella graduated in Business Administration from the State University of Rio de Janeiro (UERJ) in 1997. He earned a master’s degree in finance from the Brazilian Institute of Capital Markets (IBMEC / RJ) in 2000. He has worked at Lafarge Group, Light S.A. and Brasil Telecom S.A. He has held positions at our company since 2001, where he has worked as Manager of Economic and Financial Planning, Investor Relations Officer and Planning and Control Director. In 2013, he became Financial and Investor Relations Vice President at CPFL Energia; Financial and Investor Relations Officer at and member of the board of directors of CPFL Paulista, CPFL Piratininga, CPFL Geração and RGE, as well as Officer and member of the board of directors of several subsidiaries of the CPFL group. His term as officer at such positions ended on February 1, 2019, when he became Chief Executive Officer at CPFL Energia. He is also currently the Vice-Chairman of the board of directors of CPFL Renováveis.

Hong Li –Mr. Li Hong graduated in Accountancy from the Changsha Water Conservancy and Electric Power Normal College. He began his career in 1992 in the Finance Division of China International Water & Electric Corporation. In 1997, he began at the China Electric Power Technology Import & Export Corp. as a Senior Supervisor, being promoted in 2005 to the position of Director at the Finance Department, position which he held until 2009. He took over as Chief Financial Officer of State Grid International Development Limited Co. in 2011. In 2017, he was selected as the Leading Talent of National Top CFOs by the Ministry of Finance of China. Currently, Mr. Li Hong is a member of Board of Directors of ADMIE S.A. (Greece) and of CPFL Energia (Brazil).

Anselmo Henrique Seto Leal –Mr. Leal holds a degree in Electrical Engineering from Centro Universitário FEI, a graduation degree in Environmental Assessment, an MBA in Finance and a LL.M. in Corporate Law (on going). He started his career in 2004 at SIEMENS, an energy company, working as Senior Development Engineer until 2009. He also worked as Executive Manager – New Business in EDP Brasil, a company in the electricity sector. He joined State Grid Brazil Holding in 2016 as Chief Construction and Planning Control Officer of Xingu Rio Transmissora de Energia, working also as Deputy Officer and Chief Environment, Safety and Land Officer. Currently, he is Vice-President of State Grid Brazil Holding.

Antonio Kandir – Mr. Kandir graduated in Mechanical Engineering from Escola Politécnica of the Universidade de São Paulo (USP), earned a master’s degree in economics from the Universidade Estadual de Campinas – UNICAMP and a Ph.D. in economics from the Universidade Estadual de Campinas – UNICAMP. Mr. Kandir was Minister of Planning and Budget of the State, a Congressman, President of the Conselho Nacional de Desestatização, Governor of the Inter-American Development Bank, Special Secretary of Economic Policy, and President of the Instituto de Pesquisa Econômica Aplicada (IPEA). He currently sits on the Boards of Directors of the following companies: (i) CSU Cardsystem S.A., a technology services provider (since 2014); (ii) Comiex Empreendimentos e Participações Ltda., an investment management company (since 2017); (iii) GOL Linhas Aéreas Inteligentes, an aviation company (since 2016); (iv) Vibra Agroindustrial S.A., a poultry company (since 2015); (v) AEGEA Saneamento e Participações S.A., a sanitation company (since 2014); and (vi) MRV Engenharia e Participações S.A., a construction company (since 2018). He is also a member of our Related Parties Committee.

Marcelo Amaral Moraes – Mr. Moraes has been an independent director of CPFL Energia since 2017. He received a degree in economics from the Federal University of Rio de Janeiro (UFRJ) (1986-1990), completed an MBA from COPPEAD at UFRJ in November 1993, and received a post-graduate degree in Corporate Law and Arbitration from Fundação Getúlio Vargas in the state of São Paulo in November 2003. He is currently the Chairman of the Fiscal Council of Vale S.A. and has been a member of this fiscal council since 2004, where he also held the position of alternate member of the board of directors in 2003. He also serves as member of the Fiscal Council of GOL Linhas Aéreas S.A., Chairman of the Fiscal Council of Linux S.A. and member of the Fiscal Council of Ultrapar S.A.. Mr. Moraes also served as the chairman of the fiscal council of Aceco TI S.A. (2016-2018). He was also a member of the Board of Directors of Eternit SA. (2016-2018). His main professional experiences in recent years are: (i) Executive Officer of Stratus Investimentos Ltda. (2006-2010), (ii) Executive Officer of Capital Dynamics Investimentos Ltda. (2012 to 2015) and (iii) observing member of the Board of Directors of Infinity Bio-Energy S.A. (2011-2012). He is also a member of our Related Parties Committee.

Executive Officers

The main duties and responsibilities of the members of our board of executive officers are established by Brazilian Corporate Law and our bylaws, and include, among others, executing the decisions of our board ofdirectors and day-to-day management of the our company. Our board of executive officers operates pursuant to its internal regulations (which establish, among other matters, the rules concerning the meetings and duties of the executive officers), with due observance to the provisions of the Brazilian Corporate Law and our bylaws.

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Under our bylaws, our board of executive officers is comprised of 10 members that are appointed by our Board of Directors for a two-year term, with the possibility of re-election. Our current board of executive officers has nine members occupying the existing positions, as Mr. Shirong Lyu is currently acting as interim Strategy, Innovation and Business Excellence Vice President. The officers Gustavo Estrella, Shirong Lyu, Yumeng Zhao, Yuehui Pan, Luís Henrique Ferreira Pinto, Karin Regina Luchesi and Gustavo Pinto Gachineiro were elected at the Board of Directors’ meeting held on May 9, 2019, while Flavio Henrique Ribeiro and Vitor Fagali de Souza were elected at the Board of Directors’ meeting held on January 16, 2020.

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

Name	Age	Position
Gustavo Estrella	46	Chief Executive Officer
Shirong Lyu	55	Senior Executive Vice President
Yumeng Zhao	46	Executive Vice President
Yuehui Pan	38	Chief Financial Executive Officer and Investor Relations Officer
Luís Henrique Ferreira Pinto	59	Regulated Operations Vice President
Karin Regina Luchesi(*)	43	Market Operations Vice President
Gustavo Pinto Gachineiro(*)	48	Legal and Institutional Relations Vice President
Flavio Henrique Ribeiro	39	Business Management Vice President
Vitor Fagali de Souza	42	Business Development Vice President

(*) Gustavo Gachineiro is acting as interim Market Operations Vice President due to Karin Luchesi’s maternity leave.

Gustavo Estrella – Please see “Item 6.Directors, Senior Management and Employees—Directors and Senior Management—Board of Directors” for Mr. Estrella’s biography.

Shirong Lyu– Please see “Item 6. Directors, Senior Management and Employees—Directors and Senior Management—Board of Directors” for Mr. Lyu’s biography.

Yumeng Zhao– Please see “Item 6. Directors, Senior Management and Employees—Directors and Senior Management—Board of Directors” for Mr. Zhao’s biography.

Yuehui Pan – Mr. Pan graduated in Financial Management from Changsha University of Science and Technology in 2004, earned a master’s degree in Business Administration from North China Electric Power University and an MBA from the Kellogg School of Management at Northwestern University. He began his career at the department of finance at China Power Technology Import and Export Company, from 2007 to 2009, and later held the position of manager of the department of financial and assets management at State Grid International Development Co. Ltd., from 2009 to 2010. He has also held the positions of assistant director, from 2011 to 2013, and director, from 2013 to 2018, in the Financial Department of State Grid Brazil Holding S.A. He later served as Chairman of the Fiscal Council of Belo Monte Transmissora de Energia S.A. and Chairman of the Fiscal Council of CPFL Energia and CPFL Renováveis, from 2017 to 2018. He is CFA certified by the American Institute of Chartered Financial Analyst and CPA from the China Institute of Certified Public Accountants. In 2018, he became deputy Chief Financial Officer of our company, which term ended on January 31, 2019. He then became the Chief Financial Officer and Investor Relations Officer of our company. He also serves as Chief Executive Officer, Chief Financial Officer and Chief Investors Relations Officer at several of our subsidiaries, and is a member of our Budget and Corporate Finance Committee.

Luís Henrique Ferreira Pinto– Mr. Ferreira Pinto graduated in electrical and electronic engineering from the Engineering University of Barretos in 1985. He obtained a post-graduate degree in electric system engineeringat Federal University of Itajubá (UNIFEI) in 1990 and obtained a post-graduate degree in electrical engineering at the State University of Campinas (UNICAMP) in 2001, holding two specializations, including a MBA in Business Management obtained in 2004 and a MBA in Financial Management, Controllership and Auditing obtained in 2011 from Fundação Getúlio Vargas (FGV). He has held several positions at the company, serving as: Operations Planning Engineer between 1986 and 2000, Transmission Service Division Manager between 2000 and 2001, the Electric System Planning Division’s Manager between 2001 and 2002, the Manager of the Operational Controlling Department of CPFL Paulista and CPFL Piratininga between 2002 and 2006, Operation Executive Officer of RGE between 2006 and 2009, Executive Officer of RGE between 2009 and 2011, Chief Executive Officer of RGE between 2011 and 2013, and Chief Executive Officer of CPFL Paulista and CPFL Piratininga between 2013 and 2015. On May 2015 he was elected as Regulated Operations Vice President of CPFL Energia, responsible for the distribution business of CPFL Group and also as the Chairman of the Board of Directors of CPFL Paulista, CPFL Piratininga, RGE and RGE Sul. During his career he was also: CPFL Energia’s representative to the Interconnected Operations Coordination Group for the Electrical System in South/Southeastern Brazil - GCOI/GTPO/ELETROBRAS between 1986 and 1996, representative of CPFL Energia during the definition of the companies’ configuration to the privatization of the Distribution Sector in São Paulo in 1995, representative of the Distributors CPFL Paulista, CPFL Piratininga and RGE to the working group for the initial public offering of CPFL Energia on the São Paulo and New York Stock Exchanges in 2006. He has also served as the Coordinator of the technical losses group at ABRADEE between 2005 and 2006, and was a professor of the course on technical losses in the energy sector at the COGI Foundation between 2005 and 2006, member of the Board of Directors of NGO Parceiros Voluntários between 2009 and 2012. He headed the grouping of the five distributors CPFL Santa Cruz, CPFL Jaguariúna, CPFL Sul Paulista, CPFL Mococa and CPFL Leste Paulista (2017); and the grouping of the two distributors RGE and RGE Sul (2018) and was a member of the Board of Directors of ABRADEE (Brazilian Association of Electricity Distributors) from 2017 to 2019.

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Karin Regina Luchesi – Ms. Luchesi graduated in Material Production Engineering by the Federal University of São Carlos and obtained an executive master’s degree in Finance from Insper. She began her career in the electric sector at the Câmara de Comercialização de Energia Elétrica – CCEE. She has been working at CPFL since September 2001, serving for seven years as Head of the Department of Energy Purchase and Sale Contract Management. In June 2011, she became the Distribution Energy Tranding Executive Officer and also held the position of Energy Planning and Energy Management Officer from January to May 2014. On May 5, 2014, she was appointed as Head of CPFL Geração and also as Executive Officer of CPFL Piracicaba, Paulista Lajeado e CPFL Jaguari de Geração. She also sits on the Board of Directors of CPFL Renováveis, CERAN, Chapecoense, Foz do Chapecó, ENERCAN, BAESA e EPASA. In 2015, she was elected as Market Operations Vice-President of CPFL Energia.

Gustavo Pinto Gachineiro – Mr. Gachineiro received a bachelor’s degree in law from the University of São Paulo (USP) in 1993 and an MBA from Fundação Getúlio Vargas in 2007. He was elected legal and institutional relations vice president of CPFL Energia in 2017. He previously held positions at Global Village Telecom (GVT), where he worked as chief legal officer from 2003 to 2008, interim vice president for legal and HR from 2008 to 2012, and vice president for legal and institutional relations from 2012 to 2015. Following the acquisition of GVT by the Telefonica Group, he served as legal and corporate relations vice president at Telefônica Brasil S/A (Vivo) from 2015 to 2017. Prior to his positions at GVT and Vivo, he served as chief legal officer at Elucid (Grupo Rede) in 2003, chief legal officer at AT&T Brazil from 1999 to 2003, and as legal manager at Stiefel Laboratories in 1999. He also served as in-house counsel at Promon Eletrônica from 1997 to 1999 and at Bardella S/A Indústrias Mecânicas from 1995 to 1997. Mr. Gachineiro is also an alternate member of the board of directors of CPFL Renováveis.

Flavio Henrique Ribeiro – Mr. Ribeiro has 25 years of experience in areas like Digital, IT, Infrastructure, Facilities, Operation, Shared Services, Financing Controlling & Management, Business, BPO and HR. His career developed in countries such as Chile, Peru, Argentina, Colombia, Spain, Mexico and Brazil. His last position was IT, Infrastructure and Operations Vice President (COO), being responsible for IT Infrastructure and Operations strategy and KPI´s, Development, IT Products, Security, Telecom, Facilities, New Buildings, Process Design, IT Transformation and Global NOC, Shared Service, SOC and Service Desk.

Vitor Fagali de Souza– Mr. Souza was the Head of Department of Planning and Control of CPFL Energia from 2013 until January 2020. He is a Deliberative Director of Fundação CESP (Closed Entity of Social Security).He is graduated in Business Administration by PUCCAMP and holds a MBA in finance by FGV. He also took part in certain Singularity University executive programs and Ohio University leadership programs. He has been certified as investment analyst by CVM / APIMEC (CNPI) and as Independent Director by IBGC. At CPFL Energia, he worked in the areas of investment analysis, investor relations and financial planning. He also participated in important projects such as CPFL Energia IPO, CPFL Renováveis IPO and mandatory public tender offer and implementation of the Zero Base Budget. He began his career as an accounting auditor at Arthur Andersen / Deloitte, where he worked for four years before joining CPFL Energia in 2003.

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Fiscal Council

Under Brazilian Corporate Law, theConselho Fiscal, or fiscal council, is a corporate body independent of a company’s management and external auditors. Our fiscal council is permanent and is composed of three effective members and their respective alternate members. The primary responsibility of the fiscal council is to review Management’s activities and our financial statements, and to report its findings to our shareholders. Brazilian Corporate Law requires fiscal council members to receive as remuneration at least 10.0% of the average annual amount paid to our executive officers, excluding benefits and profit sharing. Non-controlling holders of common shares owning an aggregate of at least 10.0% of the common shares outstanding may also elect one member of the fiscal council (and her/his respective alternate member).

Under Brazilian Corporate Law, our fiscal council may not include members who are on our board of directors, are on the board of executive officers, are employed by us or a controlled company or a company of the same group, or are spouses or relatives (up to the third degree) of any member of our Management or Board of Directors. Brazilian Corporate Law also requires one of the members to be an independent member. Our fiscal council, elected at our shareholders’ meeting held on April 30, 2019 with a mandate lasting until our next annual shareholders’ meeting, which was scheduled to take place on April 30, 2020 but was postponed on April 6, 2020 until further notice in accordance with applicable Brazilian law due to concerns over the COVID-19 pandemic, is composed of the following members: Lisa Birmann Gabbai and her alternate Mr. Chenggang Liu, Ran Zhang and her alternate Mr. Jia Jia, and Ricardo Florence dos Santos and his alternate Mr. Reginaldo Ferreira Alexandre. For information regarding a proceeding related to one of our fiscal council’s alternate members, see “Item 8. Financial Information—Legal Proceedings—Proceedings Related to our Fiscal Council.” On December 31, 2019, Ms. Lisa Birmann Gabbai informed us of her resignation. Thus, her alternate member, Mr. Chenggang Liu, is currently taking part of our fiscal council until the election of the new members at our next annual shareholders’ meeting.

In accordance with the listed company audit committee rules of the NYSE and the SEC, on June 8, 2005 our board of directors designated and empowered our fiscal council to perform the role of the audit committee in reliance on the exemption set forth in Exchange Act Rule 10A-3(c)(3).

Advisory Committees

Our bylaws allow our board of directors to establish committees andad hoc commissions to assist the Board of Directors with strategic issues. Currently, there are five committees within our company: Strategy and Processes Management Committee, Human Resources Management Committee, Related Parties Committee, Risks Management Committee and Budget and Corporate Finance Committee, all governed by the Board of Directors of CPFL Energia’s Advisory Committees’ and Commissions’ Internal Regulation.

The committees and commissions do not have decision-making authority and their recommendations are not binding upon the Board of Directors.

Strategy and Processes Management Committee. Our Strategy and Processes Management Committee supports our board of directors in examining and monitoring the following processes: (i) strategic plan development and updates; (ii) asset acquisitions and investments in businesses relating to the generation, transmission, distribution and commercialization of energy, as well as the provision of related and/or correlated services in the energy sector; (iii) development of green field projects for the generation/cogeneration of energy, formation of strategic partnerships with agents of the electricity sector and participation in green field projects with strategic fit; (iv) funding for asset acquisitions and/or participation in green field projects, including the issuance of new shares by us or our directly and indirectly controlled companies; (v) inorganic growth investments and value-creation initiatives provided for in our multi-annual plan; (vi) financial feasibility and adherence of proposed investments toour strategic plan; (vii) project follow-up and post-project evaluation regarding the development of investments included in our strategic plan; (viii) operational strategy of electric energy commercialization by the traders of our group, including but not limited to directional position limit and the operation of the purchase and sale of electricity; (ix) supervision of our sustainability and ethics system; (x) forwarding proposals to improve the management of our business processes to our board of directors, if necessary; and (xi) any matter that is not within the scope of other committees/commissions and is submitted to our board of directors. The members of this committee are Shirong Lyu and his alternate Liu Mingyan, Tuo Ji and his alternate Quan Ge and Vitor Fagali and his alternate Gustavo Uemura.

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Human Resources Management Committee. Our Human Resources Management Committee is responsible for assisting our board of directors by: (i) coordinating the selection process for our CEO, Vice Presidents and any other Executive Officer our group, by request of the chairman of our board of directors; (ii) defining the global remuneration criteria for our administrators (board of directors and executive officers) and members of our fiscal council, in alignment with our strategy, our directly and indirectly controlled companies and companies with common control, including services agreements, short term incentive plans and long-term incentive plans; and (iii) managing our organizational structure, succession plan and the assessments of our executive officers. The members of this committee are Yumeng Zhao and his alternate Liu Yunwei, Li Zhang and his alternate Jin Ye and Rafael Lazzaretti and his alternate Valter Matta.

Related Parties Committee. Our Related Parties Committee is responsible for assisting our board of directors by: (i) evaluating the procedures to select suppliers and service providers for the acquisition of works, supplies and services; (ii) assessing the processes through which we close contracts to purchase and/or sell energy; and (iii) evaluating and examining other transactions. The members of this committee are Hongwu Ding, Antonio Kandir and Marcelo Amaral Moraes. There are no alternate members for this committee.

Risks Management Committee. Our Risks Management Committee is responsible for assisting our board of directors by: (i) supervising our internal audit work; (ii) supervising our risk management and compliance activities; and (iii) managing the delegation of our Sarbanes Oxley and Audit Committee activities to the fiscal council. The members of this committee are Liu Yunwei and his alternate Li Fu, Zhang Na and her alternate Xu Sheng and Gustavo Sablewski and his alternate Juliana Nunes.

Budget and Corporate Finance Committee. Our Budget and Corporate Finance Committee is responsible for assisting our board of directors by: (i) interacting with our executive officers on the evaluation of our annual budget and multi-year rolling budget, considering market and regulatory assumptions as well as our subsidiaries’ and affiliates’ capex, fundraising and guarantees, and providing decision making suggestions prior to the deliberation meeting of our board of directors; (ii) interacting with our executive officers to evaluate the proposed budget adjustment that had been previously approved by our board of directors and to update the following data: data from the previous fiscal year, industry charges, seasonal energy contracts and macroeconomic assumptions, among others; and (iii) interacting with our executive officers to examine proposals for our and our subsidiaries’ and affiliates’ fundraising plans and short and long term financing plans, and providing decision-making suggestions prior to the deliberation meeting of our board of directors. The members of this committee are Yuehui Pan and his alternate Zhou Kebing, Mingzhi Han and her alternate Fu Zhangyan and Rodrigo Ronzella and his alternate Sérgio Felice.

In addition to the advisory committees, our board of directors may createad hoc commissions, if deemed necessary. The main responsibilities of anad hoc commission include evaluating and addressing specific matters that may arise. In 2016, our board of directors set up twoad hoc commissions: the Strategy Commission and the Finance and Budget Commission. Thesead hoc commissions remained in place throughout 2017 and 2018, until June 2019, when a restructuring occurred that wound up the commissions and altered the committees’ structure.

Compensation

Under Brazilian Corporate Law, our shareholders are responsible for establishing the aggregate amount we pay to the members of our board of directors and our executive officers. Once our shareholders establish an aggregate amount of compensation for our board of directors and executive officers, the Human ResourcesManagement Committee of our board of directors is responsible for setting the criteria for global compensation levels.

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

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

The table below shows the aggregate compensation paid directly by CPFL Energia to the members of our board of directors and fiscal council and our executive officers for 2019:

	Compensation for the year ended December 31, 2019
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	2.50 members⁽¹⁾	2.00 members⁽¹⁾	6.75 members⁽¹⁾	11.25 members⁽¹⁾
	*(in thousands ofreais***)
Fixed annual compensation:
Salary	639	279	9,240	10,155
Direct or indirect benefits	-	-	548	551
Other	128	56	4,783	4,967
Variable compensation:
Bonus	-	-	7,811	7,811
Other	-	-	8,879	8,879
Post-employment benefits	-	-	843	843
Total compensation	767	335	32,104	33,206

(1) Represents the weighted average number of members.

The table below sets forth the compensation paid by our subsidiaries to our management for 2019:

	Year ended December 31, 2019
	Board of Directors	Fiscal Council	Executive Officers
	Fixed	Fixed	Total (fixed and variable)
	*(in thousands ofreais***)
Subsidiaries⁽¹⁾	-	-	4,028

(1) Compensation amounts include charges and accruals.

The table below shows the aggregate compensation expected to be paid directly by CPFL Energia to the members of our board of directors and fiscal council and our executive officers for 2020 (excluding any compensation to be paid by our subsidiaries to such individuals):

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	Approved compensation for the year ending December 31, 2020⁽¹⁾
Management Bodies	Board of Directors	Fiscal Council	Executive Officers	Total
Number of members	3 members⁽²⁾	2 members⁽²⁾	9 members⁽²⁾	14
	*(in thousands ofreais***)
Fixed annual compensation:
Salary	719	316	12,082	13,117
Direct or indirect benefits	-	-	518	518
Other	144	63	3,383	3,129
Variable compensation:
Bonus	-	-	9,476	9,476
Other	-	-	9,488	9,488
Post-employment benefits	-	-	1,096	1,096
Total compensation	863	379	35,043	36,285

(1)

Represents the expected compensation for a 12-month period (from May 2020 to April 2021), to be approved in our Annual Shareholders’ Meeting, which was scheduled to take place on April 30, 2020 but was postponed on April 6, 2020 until further notice in accordance with applicable Brazilian law due to concerns over the COVID-19 pandemic.

(2)

Represents the weighted average number of members.

In addition, the CVM requires us to disclose the aggregate compensation paid by the CPFL group to all members of the boards of directors and fiscal councils, and all executive officers, of all companies in our consolidated group. This aggregate compensation, including cash and benefits in kind, amounted to R$100.6 million for 2019, including R$83.7 million in variable compensation. The total amount set aside or accrued by the CPFL group to provide pension, retirement or similar benefits for the same period was R$2.3 million.

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

The table below shows the proportion of fixed and variable compensation and benefits paid to members of our board of directors and fiscal council and our executive officers:

	Board of Directors	Fiscal Council	Executive Officers*
Fixed compensation:	100%	100%	44%
Benefits:	0	0	4%
Variable compensation:
Short-term incentives	0	0	24%
Long-term incentives	0	0	28%
Total	100%	100%	100%

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

Compensation of Members of our Board of Directors and Fiscal Council

Our board of directors consists of nine members, three of whom are internal directors compensated only for their functions as our executive officers, two of whom are independent members compensated according to market standards and four of whom are external members, of which only one is compensated, which compensation follows market standards. No member of our board of directors receives additional compensation for his or her position as a member of our board’s advisory committees.

As for the fiscal council, except for two members who have fully and partially resigned their compensation, fees are paid in accordance with market standards and legal guidelines. Members of our board of directors and fiscal council receive fixed monthly fees.

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Compensation of Executive Officers

Our executive officers receive a fixed monthly salary (adjusted according to research annually carried out by specialized companies), benefits, and variable incentives. This compensation policy aims to encourage our executives to seek the greatest returns on our investments and projects, to align market practices and to provide for the retention of executives through the following tools:

·	benefits reflecting market practice;
·	short-term incentives: aim to direct our executive officers’ behavior to perfect our business strategy and achieve results;
·	long-term incentives, such as cash bonuses under our long-term incentive plan discussed below: aim to create a long-term vision and foster commitment, aligning the interests of our executive officers and our shareholders and rewarding positive results and the sustainable creation of value.

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

Long-term Incentive Plans

Our long-term incentive plan, known as the ILP (Plano de Incentivo de Longo Prazo), seeks to align the interests of the executive officers of CPFL Energia, the Chief Executive Officers of our controlled companies and eligible Directors and Managers of CPFL Energia, or Eligible Professionals, with those of our shareholders, including share price performance, as part of their overall compensation mix, with the aim of fostering long-term commitment and the consistent and sustainable creation of value. By linking a share valuation target with our long-term strategic plan, we seek to align the aims of the ILP with market recognition of the achievement of our strategic plan. The ILP also aims to incentivize and retain employees who provide the greatest value through their individual performance. Beneficiaries under the ILP receive cash bonuses after a vesting period when our share price reaches certain targets. ILP is reviewed annually by our board of directors through the Human Resources Management Committee, and may be suspended at any time.

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

In addition, in 2017, we established a new long-term incentive plan, known as the category of plan “Bônus de Longo Prazo.” TheBônus de Longo Prazo establishes certain targets for receiving bonus payments. These targets and the related bonuses are connected to the Eligible Professional’s position. TheBônus de Longo Prazo also aims to incentivize and retain employees who provide the greatest value through their individual performance. The bonus payments under theBônus de Longo Prazo are subject to an adjustment factor based on the average performance of our company during the three year vesting period, which can reduce the Eligible Professional’s bonus by up to 50% or increase the Eligible Professional’s bonus by up to 200%. Under the adjustment factor, our average performance is measured by the EBITDA and profit for the year targets established at the time of the Eligible Professional’sBônus de Longo Prazo. TheBônus de Longo Prazo is reviewed annually by our board of directors through the Human Resources Management Committee and may be suspended at any time.

As of December 31, 2019, the total expense amount accrued by us related to the long-term incentive plan was R$29.6 million, of which R$24.4 million related to theBônus de Longo Prazoand R$5.3 million related to theILP.

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Compensation or Benefits Linked to Corporate Events

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

Pension Plans

We provide pension plans for our executive officers, but not for members of our board of directors or fiscal council. The table below summarizes our pension plan arrangements regarding executive officers as at and for the year ended December 31, 2019:

	Pension Plans for Executive Officers
Name of pension plan	PGBL Bradesco	PGBL Brasil Prev
Number of Executive Officer members	9.67
Number of Executive Officer members eligible for retirement	4	2
Early retirement provisions	None	None
Inflation-adjusted value of pension plan contributions held at year-end, excluding contributions made directly by beneficiaries (in thousands of reais)	718	752
Amount of pension plan contributions made during the year, excluding contributions made directly by beneficiaries (in thousands of reais)*	516	236
Provisions for early redemption by beneficiary, if any	At any time, subject to vesting rules	At any time, subject to vesting rules

(*) Inflation-adjusted.

Share Ownership

None of our directors or executive officers owns common shares issued by us.

Indemnification of Officers and Directors

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

Employees

As of December 31, 2019, we had 13,302 full time employees, all of which were located in Brazil. The following table sets forth the number of our employees and a breakdown of employees by category of activity as of the dates indicated in each area of our operations.

	As of December 31,
	2019	2018	2017
Distribution	7,069	7,340	7,758
Conventional Generation	93	89	92
Renewable Generation	300	442	475
Commercialization	52	56	48
Services	3,687	3,704	3,431
Corporate staff	2,101	1,836	1,540
Total	13,302	13,467	13,344

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Some of our employees are members of unions, with which we have collective bargaining agreements. We renegotiate these agreements annually with the 39 principal unions that represent our various employee groups. Salary increases are generally provided for on an annual basis. We believe that we have good relationships with these unions, as evidenced by the fact that we have not had any labor strikes during the last 31 years that materially affected our operations.

We provide a number of benefits to our employees. The most significant is the sponsorship of Fundação CESP, in partnership with ten other electrical companies, which supplements the Brazilian government retirement and health benefits available to the employees of our subsidiaries CPFL Paulista, CPFL Piratininga, CPFL Geração and CPFL Brasil.

In accordance with Brazilian law and our compensation policy, our employees are eligible for our profit sharing program. This amount is set in the collective bargaining agreements of each company, which are adjusted annually. In 2019, we reserved R$129 million (R$99 million of which are booked in current liabilities) for our employee profit sharing program.

In addition, part of each employee’s compensation is linked to performance goals. Employees are evaluated based on criteria such as quality of work product, adherence to safety protocols and productivity. Our performance evaluation system is designed to evaluate required skill as well, and enables us to evaluate the development of our employees.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

The following table sets forth information relating to the beneficial ownership of our common shares by our major shareholders (beneficial owners of 5.0% or more of our common shares) as of March 31, 2020, reflecting the consummation of the acquisition of control of our company by State Grid. Percentages in the following table are based on 1,152,254,440 outstanding common shares.

	Common Shares	(%)
State Grid Brazil Power Participações S.A.⁽¹⁾	964,521,902	83.71
Executive officers and directors as a group	189	0.0
Total	964,522,091	83.71

(1)

State Grid Brazil Power Participações S.A., or State Grid, is our controlling shareholder. It holds 730,435,698shares directly (or 63.39%) and 234,086,204 shares indirectly (or 20.32%) through its wholly-owned subsidiary ESC Energia S.A. State Grid Brazil Power Participações S.A. is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.

As of March 31, 2020, we had 1,068,139,203 record holders in Brazil, representing 92.7% of our common shares, and 84,115,237 record holders abroad, representing 7.3% of our common shares. As of March 31, 2020, we had 24,744,502 record holders in the United States, representing 2.1% of our common shares.

State Grid acquired control of our company on January 23, 2017. In November 2017, State Grid launched a mandatory tender offer for our shares. Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to 94.75% of our total share capital.

On May 30, 2019, we announced the launch of our Follow-on Offering, which closed on June 14, 2019. Pursuant to the Follow-on Offering, we offered 116,817,126 of our common shares in a global offering consisting of (i) a public offering of common shares with restricted selling efforts in Brazil, and (ii) a concurrent international offering of common shares, including in the form of ADSs, in the United States and elsewhere outside of Brazil. Also pursuant to the Follow-on Offering, we sold 17,522,568 additional common shares under an over-allotment option that closed on June 28, 2019. As a result of the Follow-on Offering, we received net proceeds of approximately R$3,164.3 million before expenses, after deducting underwriting commissions. We received net proceeds of approximately R$474.7 million before expenses, after deducting underwriting commissions, as a resultof the over-allotment option. Following the closing of the Follow-on Offering, State Grid’s direct and indirect equity interest in our capital stock decreased to 83.71%.

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On December 18, 2019, our board of directors approved our intention to (i) terminate our Deposit Agreement regarding our ADSs, (ii) delist our ADSs from the NYSE, and (iii) terminate our registration with the U.S. Securities and Exchange Commission, or the SEC. On January 28, 2020, the NYSE suspended trading in our ADSs and filed a Form 25 with the SEC to permanently remove our ADSs from listing. This removal became effective on February 10, 2020. Once we meet the criteria for terminating our reporting obligations under the Exchange Act, we intend to file a Form 15F with the SEC to deregister and terminate our reporting obligations under the Exchange Act. Immediately upon filing Form 15F, our legal obligation to file reports under the Exchange Act will be suspended, and deregistration is expected to become effective 90 days later.

The shareholders’ agreement that was in effect relating to our shares prior to State Grid Brazil’s acquisition of control of our company was terminated in connection with that acquisition. There is currently no shareholders’ agreement in place. None of our major shareholders have differentiated voting rights.

Related Party Transactions

We are party to certain related party transactions. These transactions mainly fall into the following categories:

·	Purchase and sale of energy and charges: Refers to energy purchased or sold by distribution, commercialization and generation subsidiaries through short or long-term agreements and TUSD. Such transactions, when conducted in the Free Market, are carried out under conditions that we consider to be similar to market conditions at the time of the trading, according to internal policies previously established by our management. When conducted in the Regulated Market, the prices charged are set through mechanisms established by the regulatory authority; and
·	Intangible assets, Property, plant and equipment, Materials and Service: Refers to the purchase of equipment, cables and other materials for use in distribution and generation activities and the contracting of services such as construction and information technology consultancy.

For more information on our related party transactions, see Note 32 to our audited annual consolidated financial statements.

ITEM 8. FINANCIAL INFORMATION

Consolidated Statements and Other Financial Information

See “Item 18. Financial Statements.”

Legal Proceedings

Proceedings Related to Our Company and its Subsidiaries

Our distribution subsidiaries are defendants in numerous proceedings commenced by industrial consumers alleging that certain tariff increases that occurred in the past were illegal. The plaintiffs allege that electricity tariffs were among items subject to a price freeze under financial regulations that were in effect at the time of electricity usage. The total amount claimed under these proceedings was R$220 million as of December 31, 2019. Of this amount, we have classified an amount of R$35 million as having a probable loss; an amount of R$72 million as having a possible loss; and an amount of R$112 million as having a remote possibility of loss. A significant number of these proceedings have been decided against us or our subsidiaries, as applicable. We have made accounting provisions of R$35 million in respect of those proceedings, where the likelihood of loss is probable, in accordance with applicable accounting rules.

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

CPFL Piratininga is subject to a tax claim with respect to alleged improper tax deductions relating to payments made to the Fundação CESP pension fund. The payments in question originated from an agreement by CPFL Piratininga to pay a debt owed by the pension fund. In late 2016, the administrative court rejected CPFL Piratininga’s defense and issued an infraction notice. As a result, CPFL Piratininga filed a new defense in a judicial court. In January 2018, CPFL Piratininga obtained an order at the court of first instance for reconsideration of aspects of the administrative proceeding, although the Brazilian Federal Revenue (Receita Federal do Brasil) filed an appeal with respect to which a judgment is pending. The amount claimed in these Fundação CESP proceedings totaled R$199.8 million as of December 31, 2019. We believe that the likelihood of loss is possible.

CPFL Paulista is subject to a tax claim challenging the deductibility of expenses recognized in 1997 relating to a deficit in the Fundação CESP pension fund. CPFL Paulista deducted the expenses for income tax purposes in reliance on a favorable opinion from the Brazilian tax authority. We made escrow deposits with the court of first instance in the amount of R$360 million in 2007 and R$54 million in 2011 in order to prevent any attachment of assets by the tax authority and enable CPFL Paulista to appeal the claim. By year-end 2015, such escrow deposits as adjusted for inflation amounted to R$746 million. In January 2016, CPFL Paulista obtained court decisions that authorized CPFL Paulista to replace these escrow deposits with financial guarantees (letter of guarantee and performance bond), following which CPFL Paulista was able to withdraw the deposits in 2016. In February 2017, following a decision on appeal, CPFL Paulista paid into court a new escrow deposit in the amount of R$207 million (adjusted to R$248.7 million as of December 31, 2019 to account for inflation), related to the interest accrued on the original escrow deposits. This tax claim has also resulted in other execution proceedings, which together total R$1,478billion, which remain subject to decisions by higher courts. On September 17, 2020, our special appeal was judged unfavorably by the Superior Court of Justice (Superior Tribunal de Justiça), or STJ. We are currently waiting for the publication of the STJ’s decision and the judgment of the appeals by the Federal Supreme Court. We believe that the likelihood of loss in this tax claim is possible.

CPFL Paulista commenced proceedings against ANEEL in 2007 seeking annulment of the methodology applied in periodic tariff adjustments since the first periodic adjustment cycle in 2003, on the basis that the adjustments affected the economic basis of CPFL Paulista’s concessions. Following denial of its claim by the court of first instance, CPFL Paulista appealed this decision and the court of second instance ruled in favor of CPFL Paulista, returning the lawsuit to the original court so that an additional expert investigation is performed. The expert report was filed and CPFL Paulista agreed with the report’s result. The proceeding was then sent to the judge for a new decision. In addition, ABRADEE, a group of electricity distribution companies that includes CPFL Paulista, CPFL Piratininga and RGE, commenced proceedings against ANEEL in 2002 challenging the basis for remuneration of concession assets that has been in effect since the first periodic adjustment cycle. We are currently awaiting a final decision on these proceedings. If the relevant distribution companies succeed in any of these proceedings, the tariffs that they may charge will increase. If the distribution companies lose the cases, however, they may be required to pay court costs as well as legal fees that will be arbitrated by the court to ANEEL. We believe that the likelihood of loss in both proceedings is possible.

CPFL Geração and Furnas are subject to legal proceedings commenced by Mr. Alberto Vieira Borges and others. The claim relates to the Serra da Mesa joint venture, in which CPFL Geração and Furnas were joint venture partners, although the concession for the Serra da Mesa project is held by Furnas alone. The plaintiffs, who were owners of a lumberyard, seek compensation of R$2.3 billion as of December 31, 2019 on the basis that the Brazilian environmental agency prevented them from felling their trees before the area was flooded as part of the construction of the Hydroelectric Facility, and therefore that the Serra da Mesa joint venture expropriated the timber. In September 2018, a decision was issued ruling that the plaintiffs’ requests were unfounded and recognizing that the statute of limitations had expired on their claims. In January 2019, the plaintiffs filed an appeal that we plan to dispute. We believe that the likelihood of loss is remote.

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CPFL Geração is subject to a tax claim in the amount of R$485.0 million as of December 31, 2019 regarding an interpretation of the basis for calculation of PIS and COFINS taxes due. A ruling was issued in the administrative proceeding against CPFL Geração on all counts. As a result, CPFL Geração initiated a judicial proceeding against the Brazilian federal government. In March 2018, a decision favorable to CPFL Geração was issued in the court of first instance. The Brazilian federal government appealed such decision, and we are currently waiting for a decision in the court of second instance. We believe that the likelihood of loss is possible.

RGE has filed a petition to cancel an infraction notice in the amount of R$557 million as of December 31, 2019 in connection with IRPJ and CSLL levied from 1999 to 2003. The claim alleges excess goodwill amortization in the 10-year period under Law 9,532/97; excess asset depreciation charges; and the exclusion from the basis of tax calculation of certain inflation-related adjustments to items within Parcel A, known as CVA. The lower court ruled partially favorably on the claim relating to excess asset depreciation charges but unfavorably on the claims relating to amortization and inflation-related adjustments of CVA account. The proceeding is now awaiting a decision on the appeals presented by both parties. We believe that the likelihood of loss is possible. This claim has generated four separate administrative proceedings. In 2016, RGE filed a claim to suspend all four of these administrative proceedings until the decision on the underlying tax claim was issued, as the result of this claim indirectly affects the other proceedings, despite the fact that they relate to different periods. The likelihood of loss in these proceedings is possible and the potential losses amount to R$171.7 million as of December 2019.

CPFL Santa Cruz (two proceedings), CPFL Geração (three proceedings), RGE (two proceedings) and CPFL Paulista (one proceeding) are also subject to tax claims in the amounts of R$11.4 million, R$525.7 million, R$288.5 million and R$59.7 million, respectively, as of December 31, 2019, alleging excess goodwill amortization for purposes of calculating IRPJ and CSLL taxes. Our appeals in this case are pending decision. We believe that the likelihood of loss in all of the proceedings is possible.

Sul Geradora is subject to a tax claim in the amount of R$127.1 million as of December 31, 2019 regarding an infraction notice drawn up to collect income tax retained at the source (Imposto de Renda Retida na Fonte), or IRRF, on the payment of interest on an export prepayment transaction. Tax authorities claim that Sul Geradora used the funds obtained from the transaction to acquire credits against companies within its own economic group and not to fund its exports. The infraction notice was upheld in the administrative proceeding and a decision was issued ruling against Sul Geradora on all counts. As a result, Sul Geradora filed an ordinary proceeding in the judicial sphere seeking to revoke the infraction notice. The judicial proceeding is currently pending trial in the court of first instance, after the expert evaluation. We believe the likelihood of loss is possible.

CPFL Piratininga has commenced proceedings against the Brazilian Federal Revenue seeking the right to deduct in full the value of the CSLL based on the income tax (Imposto sobre a Renda) for the 2002 base year and all subsequent years. The initial request and CPFL Piratininga’s appeal were both denied. CPFL Piratininga then applied for a special and extraordinary appeal, both of which were denied in December 2017. As a result of these denials, the original decision is now final and enforceable. We have deposited the full amount into judicial escrow and will now begin the process to calculate the exact amount payable, which we believe amounts to R$199.8 million as of December 31, 2019.

CPFL Geração is subject to a tax claim in the amount of R$482.7 million as of December 31, 2019 regarding an infraction notice related to the collection of IRRF and CSLL. Tax authorities claim that CPFL Geração made capital gains and applied an incorrect tax basis on the merger of SMITA Empreendimentos e Participações S.A. into ERSA – Energias Renováveis S.A., which resulted in the creation of CPFL Renováveis in 2011. CPFL Geração filed an objection in January 2017. In August 2017, a decision was issued in the court of first instance ruling against CPFL Geração’s objection, fully upholding the infraction notice. CPFL Geração then filed a voluntary appeal seeking to cancel the infraction notice in its entirety. This appeal is currently pending a decision in the court of second instance by the Administrative Council on Fiscal Resources (Conselho Administrativo de Recursos Fiscais – CARF). We believe the likelihood of a loss is possible.

CPFL Paulista is the defendant in an indemnification proceeding for material damages and loss of profits commenced by Mr. Sebastião José Ismael, alleging an undue reduction in energy affecting his irrigation system for palm heart plants. CPFL Paulista made payments relating to the alleged damage and is currently in arbitrationregarding the amount of any loss of profits. We believe the likelihood of a loss is probable up to R$7.4 million, possible up to R$125.0 million and remote up to R$35.7 million in December 2019.

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CPFL Piratininga is the defendant in an environmental proceeding commenced by the Attorney-General of the state of São Paulo seeking to modify existing maintenance criteria on 10 transmission lines that run close to the preserved area of Parque Estadual da Serra do Mar because of the destruction of vegetation. We believe the risk of loss is possible but the amount involved cannot currently be estimated because the lawsuit remains in the initial stages and the extent of any losses to or obligations of CPFL Piratininga will depend on an environmental report and the judge’s review, neither of which has transpired.

RGE is a defendant in a Public Civil Action (Ação Civil Pública) that challenged RGE’s practice of subcontracting construction and maintenance services on electric energy networks. On February 2, 2017 the court ruled that RGE must refrain from outsourcing activities related to its core business, but rejected the State Labor Department’s claim for compensation for collective damages. In March 2018, the Regional Labor Court granted the State Labor Department’s appeal in part, rendering a judgment against RGE and ordering it to pay collective damages amounting to R$1 million. RGE filed an appeal, which is still pending judgment by the Superior Labor Court. In addition to seeking to reduce the amount of collective damages, RGE seeks to reverse the judgment relating to the obligation not to outsource certain services, particularly in light of recent reforms under Brazilian labor law passed on November 11, 2017, which expressly permits outsourcing. The likelihood of loss is probable, in the amount of R$1 million as of December 31, 2019.

RGE is subject to a tax claim in the amount of R$442.2million as of December 31, 2019 by the State Treasury of Rio Grande do Sul. The claim refers to two infraction notices relating to the collection of ICMS from February 2013 to August 2018 on subsidy installments received from the Brazilian federal government for indemnities paid due to the contractual imbalance resulting from the discount fixing for certain classes of clients. RGE filed an administrative proceeding against both infraction notices in January 2019 and a decision is currently pending. We understand that the likelihood of loss is possible.

RGE is party to certain proceedings brought by the public prosecutor’s office challenging the validity of RGE’s tariff composition. RGE monitors these proceedings since they relate to events that occurred prior to our acquisition of RGE Sul. Of these proceedings, we consider two material based on their potential impact in the event of a ruling against RGE. These proceedings are: (i) a proceeding which challenges the totality of the tariff composition and would require the complete refund of previously paid amounts; and (ii) a proceeding challenging the tariff policy as established by law and the tariff readjustment methodology, adopted by ANEEL in 2002. We have received favorable judgments in both proceedings in the court of first instance. Both proceedings were then appealed by the public prosecutor’s office and, in both cases, we are currently awaiting judgment. We understand that the likelihood of loss from these proceedings is remote. The value of any potential loss cannot be estimated at this time.

RGE is a defendant in a declaratory action of administrative impropriety filed by the state of Rio Grande do Sul and Companhia Estadual de Energia Elétrica – CEEE on February 22, 2001 discussing CEEE’s corporate restructuring process for subsequent privatization, including the MME, the President of CEEE, the Financial Director of CEEE, the Administrative Director of Companhia Centro-Oeste de Distribuição de Energia Elétrica – CCODEE (RGE) and Companhia Norte-Nordeste de Distribuição de Energia Elétrica – CNNDEE (RGE Sul) and the accountants who signed the appraisal report. In it is defense, RGE alleged illegitimacy and lack of participation and responsibility in the discussions, considering that the corporate restructuring happened before the RGE and RGE Sul concessions were acquired, as well as the non-existence of damage to the seller, considering that RGE and RGE Sul concessions were acquired at a higher price than the initial evaluation. The lawsuit is currently pending, and we understand that the likelihood of loss in this proceeding is remote. The value of any potential loss cannot be estimated at this time.

In 2014, a class action was filed by the Sport Fishing Association against the National Environmental Agency, the Brazilian Institute of Environment and Renewable Natural Resources (Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis), Furnas and CPFL Geração seeking to require the defendants to repair and mitigate the environmental impact caused by the construction and operation of the Serra da Mesa Hydroelectric Power Plant, based on the alleged damming of the Tocantins River. In September 2017, CPFLGeração obtained a favorable decision in the court of first instance. We are currently awaiting judgment on the plaintiffs’ appeal. We understand that the likelihood of loss in this proceeding is remote as to an estimated amount of R$336 million and possible as to an estimated amount of R$31 million, as of December 31, 2019.

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In 2018, the public prosecutor's office for the State of São Paulo filed a public civil action (ação civil pública) against CPFL Paulista for administrative impropriety conduct. By means of this suit, the Public Prosecutor’s Office requests that: (i) a decision is rendered against CPFL Paulista and the mayor of the Municipality of Bebedouro as co-defendants; (ii) charging and collecting a contribution for public lighting be found unconstitutional; and (iii) an agreement executed between CPFL Paulista and the Municipality of Bebedouro be declared null and void. CPFL Paulista has been notified to provide information and requested that its inclusion in the proceeding be denied. The lawsuit is currently in the court of first instance and we assess that the likelihood of loss is possible. This proceeding is pending a decision by the court. At this moment, it is not possible to estimate the values involved in the proceeding.

RGE Sul is involved in a proceeding that claims loss due to the impact of ANEEL Order No. 288, which altered commercialization rules of the energy wholesale market (Mercado Atacadista de Energia Elétrica), or MAE. The lawsuit seeks to annul the order and requests that the exposure rules in the MAE are kept, thereby preserving the accounting treatment and allowing for its liquidation. In 2016, RGE Sul received a favorable decision, which was disputed and is waiting a new decision. Any consequences from the decision in this proceeding will be borne by RGE Sul's former owner, AES Guaíba II Empreendimentos Ltda. We understand that the likelihood of loss of this proceeding is remote and estimated at R$455 million as of December 31, 2019.

CPFL Renováveis, CPFL Brasil, CPFL Bio Pedra, CPFL Bio Buriti and CPFL Bio Ipê are respondents in a civil arbitration involving the amount of R$200 million. The exclusion of CPFL Brasil from the proceeding has been requested on the ground that it is not a legitimate party. We understand that the potential impact of this arbitration is only financial and limited to CPFL Renováveis, and the likelihood of loss in this proceeding is possible. In light of the liability and debt assumption instrument executed by CPFL Brasil in favor of CPFL Renováveis, we understand that there would be no financial impact to CPFL Brasil, and the likelihood of loss for CPFL Brasil is remote.

We establish balance sheet provisions relating to potential losses from litigation based on estimates of such losses. For this purpose, we classify these losses as remote, possible or probable. IFRS practices require us to establish provisions in connection with probable losses, and it is therefore our policy to establish provisions in connection with those claims only. As of December 31, 2019, our provisions for contingencies were R$600.8 million, reflecting our ongoing contingency monitoring and risk control. Our management believes that none of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition. See Notes 22 and 23 to our audited annual consolidated financial statements for more information on the status of our litigation and “Item 5. Operating and Financial Review and Prospects—Critical Accounting Policies—Provision for Tax, Civil and Labor Risks” for more information about our provisions.

Lawsuits that Challenge Technical Notes No. 23/2003-SEM/ANEEL and 81/2003-SFF/ ANEEL

In 2004, our commercialization subsidiary, CPFL Brasil, filed lawsuits seeking to prohibit the retroactive application of the criteria set forth by Technical Notes No. 23/2003-SEM/ANEEL and 81/2003-SFF/ANEEL so that the prices of the previously executed electric energy purchase contracts and resulting passing through to tariffs remained governed by the ANEEL resolutions that govern the so called “normative value” at the time of the execution of the purchase contracts.

The two lawsuits filed by CPFL Brasil dispute the so called self-dealing contracts executed with our distribution subsidiaries, CPFL Piratininga and CPFL Paulista, and the likelihood of loss for both lawsuits is possible. One of such lawsuits is currently at the court of appeals pending a decision on the appeal. The second lawsuit already received a favorable decision on plaintiff's appeal before the court of appeals to reestablish the normative rule in effect at the time of execution of the contracts, allowing for the contracting and corresponding pass through as agreed by the parties.

The table below sets forth the estimated amounts involved with respect to the two self-dealing lawsuits, as disclosed by ANEEL in corresponding proceedings in 2019. These amounts have been adjusted according to theIGP-M/FGV index and relate to the difference in contractual revenue that would result from a favorable decision in the respective lawsuit that eventually reestablishes the original contractual price in its entirety, for the benefit of CPFL Brasil. In the event the favorable decision on such lawsuits becomes definitive, the actual values from the contractual difference shall be the subject of a specific procedure of judicial determination by means of a calculation of the award.As a result, the amounts presented in the table below are merely illustrative and remain fully subject to revision and eventual change until a final decision is reached for each ongoing legal proceeding. Under no circumstances should the estimates set forth herein be regarded as a representation, warranty or prediction that we will achieve or are likely to achieve any particular future result and you should not therefore place undue reliance on these estimates.

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Proceeding No.	Historic value disclosed by ANEEL	Adjusted value (IGP-M/FGV)
4975-46.2004.4.01.3400 (2004.34.00.004988-3) CPFL Brasil x CPFL Paulista	R$1,368,997,568.48	R$2.910.341.418,15 (December/2019)
14862-54.2004.4.01.3400 (2004.34.00.014895-2) CPFL Brasil x CPFL Piratininga	R$381,045,306.60	R$767.087.629,52 (December/2019)

We do not expect to update or revise these estimates to reflect circumstances existing after the date of this annual report.These estimates do not constitute a guarantee that we will be successful in the lawsuits and will benefit from the amounts set forth in the table above.

Exclusion of ICMS taxes from the PIS and COFINS Tax Calculation Base

Our distribution subsidiaries and our commercialization subsidiary CPFL Brasil are parties to ongoing legal proceedings involving the Brazilian federal government aiming at (i) excluding the ICMS (tax on distribution of goods and services) from the tax basis of the social contributions of PIS and COFINS (due by them based on the revenues gained); and (ii) refunding the PIS and COFINS tax amounts previously paid.

In the first quarter of 2019, our subsidiary CPFL Santa Cruz (representing CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa, which are the four companies that were merged into CPFL Santa Cruz and which were original parties to the legal proceedings) received a favorable final judicial decision on these matters. On March 31, 2019, CPFL Santa Cruz recognized a PIS and COFINS tax credit using the calculation methodology provided in the “Federal Revenue Orientation (Solução de Consulta da Receita Federal) n° 13/2018” and recognized a liability related to PIS and COFINS tax credits that need to be refunded to the relevant Final Consumers for the maximum period of 10 years.

In the quarter ended March 31, 2019, CPFL Santa Cruz recognized an increase of R$168.87 million in ‘‘Taxes Recoverable,’’ as well as an increase of R$132.37 million in ‘‘Other Payable—Consumers’’ and a decrease of R$34.50 million in ‘‘Deduction from operating revenues—PIS and COFINS.’’ For the period ended December 31, 2019, CPFL Santa Cruz recorded an asset of R$ 167.78 million, a value addition of R$0.91 from March 31, 2019, in “Taxes Recoverable,” against a liability of R$ 132.61 million, a value addition of R$0.23 million from March 31, 2019, in “Other Payable—Consumers” and a decrease of R$ 34.50 million in “Deduction from operating revenues—PIS and COFINS” and a monetary adjustment of R$0.68.

Based on the advice of external legal counsel, we understand that the amounts to be eventually received by our distribution subsidiaries as PIS and COFINS credits would have to be refunded to consumers once the Brazilian Federal Revenue approves such tax credits as compensation payable to affected Final Consumers. With our external legal counsel, we continue to analyze the relevant time period applicable to calculating the refunds of these PIS and COFINS credits to Final Consumers, which may be for a period of three, five or ten years. Currently, it is still possible that the full amount of these PIS and COFINS credits will need to be refunded to our Final Consumers.

In the case of our commercialization subsidiary CPFL Brasil, given that the PIS and COFINS credits related to this matter were not from collections made through regulated tariffs (and as such, passed on to our Final Consumers), we understand that all corresponding PIS and COFINS tax credits would have to be returned by the Brazilian Federal Revenue directly for the benefit of CPFL Brasil. No other amounts have been recognized in ourfinancial statements in connection with the judicial proceedings involving our other distribution subsidiaries or CPFL Brasil, since final decisions are still pending in their corresponding legal proceedings. Based on the advice of external legal counsel and our best and most up-to-date estimates, the legal proceedings involving our other distribution companies will have outcomes similar to CPFL Santa Cruz’s proceeding.

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In addition, because of the subjective judgments, the inherent uncertainties of estimates, and since these estimates are based on a number of assumptions, which are subject to significant uncertainties and contingencies that are beyond our control, there can be no assurance that these estimates or the conclusions derived therefrom will be realized. The final amounts of tax credits, if any, will depend on the existence of necessary documentation or other evidence confirming the relevant amounts of PIS and COFINS overpayments.

The amounts of our actual recoverable PIS and COFINS tax credits may be significantly lower than the estimates described in the table below. Under no circumstances should the estimates set forth herein be regarded as a representation, warranty or prediction that we will achieve or are likely to achieve any particular future result and you should not therefore place undue reliance on these estimates. There can be no assurance that our future results or estimates will not vary significantly from those set forth herein. See “Item 3. Key Information—Risk Factors—Changes in Brazilian tax legislation, tax incentives and benefits, or different interpretations of tax legislation or case law may negatively affect our results of operations.”

Company	Sector	Date of Court Filing	Potential benefit for CPFL (“Deduction from operating revenue—PIS and COFINS”)— R$ thousand	Potential Refund to Consumers (“Other Payable- Consumers”) R$ thousand	Potential value of PIS and COFINS paid in excess (“Taxes Recoverable”)— R$ thousand
CPFL Brasil	Commercialization	06/07/2010	53,924	—	53,924
CPFL Paulista	Distribution	06/07/2010	981,609	1,826,44	2,808,053
CPFL Piratininga	Distribution	06/07/2010	422,688	1,010,170	1,432,858
RGE	Distribution	03/08/2017	—	677,808	677,808
RGE Sul	Distribution	06/29/2007	366,957	1,144,594	1,511,552
CPFL Santa Cruz	Distribution	03/14/2017 (after Law No. 12,973/2014) 06/07/2010	38,785	79,884	118,669
Total			1,863,963	4,738,896	6,602,864

We do not expect to update or revise these estimates to reflect circumstances existing after the date of this annual report.These estimates do not constitute a guarantee that we will be able to benefit from PIS and COFINS tax credits described in the table above.

Proceedings Related to our Fiscal Council

An alternate member to our fiscal council, Reginaldo Ferreira Alexandre, is involved in a proceeding with the CVM involving members of the executive board, board of directors and fiscal council of Petróleo Brasileiro S.A., or Petrobras, and relating to irregularities and inconsistencies in the preparation of certain impairment tests reflected in Petrobras’s financial statements for the year ended December 31, 2013. Reginaldo Ferreira Alexandre served on Petrobras’ fiscal council during the period in question. The CVM has stated that the supervisory board should have issued an opinion against the approval of Petrobras’ 2013 financial statements, citing the possibility of these irregularities and inconsistencies. This proceeding is currently pending judgment.

Proceedings Related to our Board of Directors

An independent member of our board of directors, Antônio Kandir, is involved in a proceeding with the CVM for alleged irregularities involving the administration and management of the investment fund MAP FIM, or MAP FIM, from December 2010 to May 2013. Antônio Kandir acted as the officer responsible for portfolio management for Governança e Gestão Investimentos Ltda., or G&G Investimento, MAP FIM's manager during theperiod in question. On May 7, 2019, the CVM reached an unfavorable decision against G&G Investimento and Antônio Kandir and delivered a warning. Currently, the proceeding is under appeal at the National Financial System Resources Council (Conselho de Recursos do Sistema Financeiro Nacional). The effects of the decision are suspended until the appeal is decided.

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Dividends

See “Item 10. Additional Information—Allocation of Profit for the year and Distribution of Dividends” for information on our dividend distributions.

ITEM 9. THE OFFER AND LISTING

Trading Markets

Our common shares are listed on the B3 under ticker CPFE3. As described below, until February 10, 2020, our ADSs were listed on the New York Stock Exchange under ticker CPL. The ADSs commenced trading on the NYSE on September 29, 2004. As of December 31, 2019, the ADSs represented 0.8% of our total outstanding shares and 4.9% of our global public float.

On May 30, 2019, we announced the launch of our Follow-on Offering, which closed on June 14, 2019. Pursuant to the Follow-on Offering, we offered 116,817,126 of our common shares in a global offering consisting of (i) a public offering of common shares with restricted selling efforts in Brazil, and (ii) a concurrent international offering of common shares, including in the form of ADSs, in the United States and elsewhere outside of Brazil. Also pursuant to the Follow-on Offering, we sold 17,522,568 additional common shares under an over-allotment option that closed on June 28, 2019. As a result of the Follow-on Offering, we received net proceeds of approximately R$3,164.3 million before expenses, after deducting underwriting commissions. We received net proceeds of approximately R$474.7 million before expenses, after deducting underwriting commissions, as a result of the over-allotment option. Following the closing of the Follow-on Offering, State Grid’s direct and indirect equity interest in our capital stock decreased to 83.71%.

On December 18, 2019, our board of directors approved our intention to (i) terminate our Deposit Agreement regarding our ADSs, (ii) delist our ADSs from the NYSE, and (iii) terminate our registration with the U.S. Securities and Exchange Commission, or the SEC. On January 28, 2020, the NYSE suspended trading in our ADSs and filed a Form 25 with the SEC to permanently remove our ADSs from listing. This removal became effective on February 10, 2020. Once we meet the criteria for terminating our reporting obligations under the Exchange Act, we intend to file a Form 15F with the SEC to deregister and terminate our reporting obligations under the Exchange Act. Immediately upon filing Form 15F, our legal obligation to file reports under the Exchange Act will be suspended, and deregistration is expected to become effective 90 days later.

Corporate Governance Practices

In 2000, the B3 (at that time known as BM&FBOVESPA) introduced three special listing segments, known as Level 1, Level 2 and theNovo Mercado, aiming at fostering a secondary market for securities issued by Brazilian companies with securities listed on the B3, by prompting such companies to follow good practices of corporate governance. The listing segments were designed for the trading of shares issued by companies voluntarily undertaking to abide by corporate governance practices and disclosure requirements in addition to those already imposed by Brazilian law. These rules generally increase shareholders’ rights and enhance the quality of information provided to shareholders and stakeholders. In order to maintain high standards of corporate governance, we have signed an agreement with the B3 to list our securities on theNovo Mercado.

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Our corporate governance guidelines apply to us and all of our subsidiaries and affiliated companies. They aim at regulating the interaction among our shareholders, board of directors and its advisory committees and commissions, fiscal council and board of executive officers. Such guidelines are founded on four basic principles, pursuant to the Brazilian Code of Best Practices for Corporate Governance:

1	Transparency/Disclosure – the desire to provide stakeholders with information of interest to them, not limited to what is required by laws or rules and financial information.
2	Impartiality/Fairness – fair and equal treatment of all shareholders and other stakeholders, taking into consideration their rights, duties, needs, interests and expectations.
3	Accountability – provision of information by our management in a clear, concise, understandable and timely manner, assuming the consequences of their acts and omissions in full, and performing their roles diligently and responsibly.
4	Corporate responsibility/Compliance – dedication for economic and financial viability of our company, the reduction of negative externalities impacting our businesses and operations and the increase in positive externalities, while taking into account the various types of capital (financial, manufactured, intellectual, human, social, environmental, reputational, etc.) in the short-, medium- and long-term.

We implemented this model in 2003 and redesigned it in 2017 and 2019 in order to adjust our corporate governance structure to the current making-business scenario and decision-making process, as well as to consider our new corporate structure. In December 2017, our board of directors approved the revision of our Corporate Governance Guidelines as related to their application to our controlled and affiliated companies. In addition, in 2012, it was registered that the members of our board of directors’ advisory committees shall no longer receive compensation. In 2017, our board of directors approved an amendment to our Corporate Governance Guidelines, to specify that the internal audit and corporate governance advisors report directly to the Board of Directors. In October 2019, our board of directors approved a new version of our Corporate Governance Guidelines, which was created based on the Brazilian Corporate Governance Code and current company dynamics. Presently, our corporate governance advisors shall report to the Board through the Corporate Governance Department.

Our board of directors is our decision-making body, responsible for determining our overall guidelines. Our Board of directors can request advice on strategic matters from five of our advisory committees, such as executive remuneration, related party transactions, follow-up on internal audits, business management processes, corporate risk management, sustainability and financial policies. Ad hoc commissions are installed to advise our board of directors on specific issues, as deemed necessary.

A revision of these rules was under discussion between the companies listed in each segment and the B3, and it was approved during the second half of 2010 to provide for a further enhancement of the special corporate governance and disclosure rules. The revised rules entered in force and effect on May 10, 2011, including those related to theNovo Mercado segment. The main changes to the rules in the segment that we are listed include, among others: (i) prohibition to include dispositions that restrict or create obligations to the shareholders which vote favorably to a suppression or amendment of dispositions of the bylaws; (ii) prohibition of the same individual to hold the positions of chairman of the board of directors and chief executive officer (or equivalent position as the main executive of the company); and (iii) obligation of the board of directors to issue a justified opinion on any tender offers for the acquisition of the shares representative of the corporate capital of the company. On December 19, 2011, we amended our bylaws to incorporate these rules, among other changes. In 2013 we amended our bylaws to include the creation of a “Reserve for Adjustment of the Concession Financial Assets,” with subsequent amendment to items “a” and “c” and addition of items “d” and “e” of paragraph 2, Article 27. In 2015, we amended our bylaws, in order to include: (i) a capital increase through the capitalization of profit reserves, with consequent stock bonus; (ii) modifications in the composition of the Board of Executive Officers; (iii) modifications in the scope of powers to approve certain matters by the Board of Executive Officers; (iv) monetary adjustment of values expressly determined by the bylaws; and (v) language improvements and inclusion of cross references for improved understanding of the bylaws.

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

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

In accordance with Section 303A.11 of the NYSE Listed Company Manual, we have posted a summary of significant differences between the NYSE corporate governance standards and our corporate governance practices on our website, at http://www.cpfl.com.br/ir.

In parallel, ANEEL issued Normative Resolution No. 787/2017, effective for a two-year trial period as of January 1, 2018 and in full force as of January 1, 2020, which is intended to evaluate the quality of corporate governance of electricity distribution companies according to five criteria, namely (i) transparency, (ii) top management structure, (iii) ownership and controlling relationships, (iv) internal control and (v) regulatory compliance. Under this resolution, electricity distribution companies will be classified as “high,” “average,” “insufficient” or “non applicable,” reflecting the level of regulatory scrutiny to which the companies will be subject. Companies listed in special segments in B3 such as theNovo Mercado, Level 1, Level 2 and Bovespa Mais may be classified as “high” if they comply with the standards of the first four criteria (transparency, top management structure, ownership and controlling relationships and internal control).

ITEM 10. ADDITIONAL INFORMATION

Memorandum and Articles of Incorporation

Corporate Purpose

Our corporate purpose, as defined by our bylaws, includes:

·	fostering enterprises in the electricity generation, distribution, transmission, commercialization and related activities;
·	providing services related to electricity, as well as providing technical, operational, administrative and financial support services, especially to affiliated or subsidiary companies; and
·	holding interest in the capital of other companies or associations, engaged in activities similar to those that we perform, especially companies having as their corporate purpose to foster, build, and/or operate projects concerning electricity generation, distribution, transmission, commercializatoin and its related services.

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Qualification of Directors and Executive Officers

Members of our board of executive officers must be residents of Brazil, but such requirement does not apply to members of our board of directors.

Allocation of Profit for the year and Distribution of Dividends

The discussion below summarizes the provisions of Brazilian law regarding the establishment of reserves by corporations and the distribution of dividends, including interest attributable to shareholders’ equity.

Mandatory Distribution

Brazilian Corporate Law generally requires that the bylaws of each Brazilian corporation specify a minimum percentage of the amounts available for distribution by such corporation for each fiscal year that must be distributed to shareholders as dividends, also known as the mandatory distribution.

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

Under our bylaws, the net profit for the preceding fiscal year, as calculated under Brazilian Accounting Principles and adjusted under Brazilian Corporate Law, shall be allocated as follows: (i) 5.0%, before any other allocation, to form the legal reserve, until it reaches 20.0% of CPFL Energia’s capital stock (under Brazilian Corporate Law, we are not forced to make any allocation to the legal reserve in relation to any fiscal year in which the sum of the legal reserve and certain capital reserves exceeds 30.0% of CPFL Energia’s capital stock); and (ii) payment of mandatory dividends.

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

Payment of Dividends

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

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

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In general, shareholders who are not residents of Brazil must register their equity investment with the SISBACEN to have dividends, sales proceeds or other amounts with respect to their shares eligible to be remitted outside of Brazil.

Dividends paid to persons who are not Brazilian residents, including holders of common shares, are not subject to Brazilian withholding income tax, except for: (i) dividends declared based on profits generated prior to December 31, 1995; and (ii) in 2014 dividends possibly paid in excess of profits, due to a difference in the calculation of profits resulting from a change of accounting standards adopted in Brazil, which are subject to Brazilian withholding income tax at varying tax rates. See “—Brazilian Tax Considerations” for more information.

Under current Brazilian legislation, the Brazilian government may impose temporary restrictions of foreign capital abroad in the event of a serious imbalance or an anticipated serious imbalance of Brazil’s balance of payments (see “Item 3. Key Information—Risk Factors—Risks Relating to Our Common Shares”).

Interest Attributable to Shareholders’ Equity

Under Brazilian tax legislation, Brazilian companies are permitted to make distributions to shareholders of interest attributable to shareholders’ equity and treat such payments as a deductible expense for purposes of calculating Brazilian corporate income tax and social contribution on net profits, as long as the limits described below are observed. Payment of such interest may be made at the discretion of our board of directors, subject to the ratification of the shareholders at a general shareholders’ meeting. In order to calculate this interest attributable to shareholders’ equity, the TJLP is applied to certain equity accounts for the applicable period. The deduction of the interest attributable to shareholders’ equity payments for IRPJ and CSLL purposes is limited to the greater of:

·	50.0% of net profit (determined after the deduction of the provisions for social contribution on net profits but before taking into account the provision for corporate income tax and the interest attributable to shareholders’ equity) for the period in respect of which the payment is made; or
·	50.0% of the accrued profits and profit reserves as of the beginning of the year in respect of which such payment is made.

As a general rule, the payment of interest attributable to shareholders’ equity to non-Brazilian holders is subject to Brazilian withholding tax at the rate of 15.0%, or 25.0% if the non-Brazilian holder is domiciled in a jurisdiction defined as a “Low or Nil Tax Jurisdiction.” See “—Brazilian Tax Considerations” for more information. If such payments are accounted for, at their net value, as part of any mandatory dividend, the tax is paid by the company on behalf of its shareholders, upon distribution of the interest (gross up). If we distribute interest attributable to shareholder’s equity in any year, and that distribution is not accounted for as part of mandatory distribution, Brazilian income tax would be borne by the shareholders. For accounting purposes, interest attributable to shareholders’ equity is reflected as a dividend payment.

Under our bylaws, interest attributable to shareholders’ equity may be treated as a dividend for purposes of the mandatory dividend, therefore, our board of directors may recommend that future distributions of profits should be made by means of interest attributable to shareholders’ equity instead of by means of dividends.

Dividend Policy

On May 21, 2019, we announced to our shareholders and to the market that our board of directors approved, at the meeting held on that date, the adoption of a dividend distribution policy.

Under such dividend policy, we must distribute annually, as dividends, at least 50% of our adjusted profit for the year, in accordance with the Brazilian Corporate Law. Furthermore, the dividend policy sets forth the factorsthat will influence the amount of the distributions, such as the our financial conditions, our future prospects, macroeconomic conditions, tariff reviews and adjustments, regulatory changes and our growth strategies, as well as any other issue considered relevant by our Board of Directors and shareholders. The dividend policy also highlights that certain obligations contained in our financial contracts may limit the amount of dividends and/or interest attributable to shareholders’ equity that may be distributed, considering that it may be of our interest in the future to distribute interest attributable to shareholders’ equity.

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The approved dividend policy is merely indicative, with the purpose of signaling to the market the treatment that we intend to give to the distribution of dividends to our shareholders, having, therefore, a programmatic character, not binding upon us or our governing bodies.

Our dividend policy is available at our investor relationswebsitehttp://www.cpfl.com.br/ir.

Reserve Accounts

We have two principal reserve accounts—profits reserve and capital reserve. Our profits reserve account consists of legal reserve and statutory reserve—working capital reinforcement.

Legal Reserve

Under Brazilian Corporate Law and our bylaws, we are required to maintain a legal reserve and allocate 5% of our profit for the year for each fiscal year to that reserve until the aggregate amount of the reserve equals 20% of our issued share capital. However, we are not required to make any allocations to our legal reserve in a fiscal year in which the legal reserve, when added to our other established capital reserves, exceeds 30% of our total capital. Any net loss may be offset with amounts in the legal reserve.

Statutory Reserve

Under Brazilian law, we are permitted to allocate part of our net profits to discretionary reserve accounts established in accordance with our bylaws�� however, we may not do so if the allocation prevents distribution of the mandatory distributable amount.

Statutory Reserve—Working Capital Reinforcement: Our working capital reinforcement reserve is a form of discretionary reserve account. We may allocate net profit (after the allocation to the legal reserve and payment of the mandatory distributable amount) to provide our company with additional working capital. The amount set aside in this working capital reinforcement reserve cannot at any time exceed the value of our share capital. Considering the current Brazilian macroeconomic environment, including the incipient economic recovery, and the uncertainties regarding weather, rain and drought conditions in Brazil that affect our operations, our management has proposed the allocation of R$518.8 million to our statutory reserve—working capital reinforcement for consideration by our shareholders in our annual shareholders’ meeting, which was scheduled to take place on April 30, 2020 but was postponed on April 6, 2020 until further notice in accordance with applicable Brazilian law due to concerns over the COVID-19 pandemic.

Shareholder Meetings

Actions to be taken at our shareholders’ meetings

At our shareholders’ meetings, shareholders are generally empowered to take any action relating to our corporate purpose and to pass such resolutions as they deem necessary. Shareholders’ meetings may be ordinary, such as the annual meeting, or extraordinary. The approval of our financial statements and the determination of the allocation of our net profits with respect to each fiscal year take place at the annual shareholders’ meeting to be held by April 30 of the year immediately following such fiscal year. The election of our directors and members of our fiscal council (and the definition of the global compensation to be paid to the members of the Board of Directors, the fiscal council and the executive officers), if the requisite shareholders request its establishment, typically takes place at the annual shareholders’ meeting, although under Brazilian law it may also occur at a special shareholders’ meeting.

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

·	the cancellation of the registration with the CVM as a publicly-held company;
·	the delisting of our shares from the Novo Mercado of the B3;
·	the appointment of a specialized firm to determine the economic value of our company’s shares, in the event of a public offering as contemplated under Chapters VII of the bylaws, based on a list of three selected firms provided by the Board of Directors;
·	the plans for the granting of stock options to members of management and employees of our company and companies directly or indirectly controlled by our company, without the preemptive rights being available to the shareholders;
·	amendment of our bylaws;
·	suspension of the rights of a shareholder who has violated Brazilian Corporate Law or our bylaws;
·	acceptance or rejection of the valuation of in-kind contributions offered by a shareholder in consideration for shares of our capital stock;
·	approval of our transformation into a limited liability company (sociedade limitada) or any other corporate form;
·	approval of our participation in a group of companies (grupo de sociedades, as defined in Brazilian Corporate Law);
·	approval of the dissolution of CPFL Energia;

·	reduction of capital stock;
·	the increase in CPFL Energia’s capital stock, as well as the issuance of convertible debentures or subscription warrants (bônus de subscrição) beyond the limits of the authorized capital; and
·	authorization to petition for bankruptcy or judicial or extrajudicial restructuring (recuperação judicial ou extrajudicial).

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

·	the right to participate in the distribution of profits;
·	the right to participate in any remaining residual assets in the event of liquidation of the company;
·	the right to inspect and monitor our Management, in accordance with the Brazilian Corporate Law;
·	the right to preemptive rights in the event of subscription of shares, convertible debentures or subscription warrants (bônus de subscrição), except in some specific circumstances under Brazilian law described in “—Preemptive Rights”; and
·	the right to withdraw from our company in the cases specified in Brazilian Corporate Law, described in “—Withdrawal Rights and Redemption.”

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Quorum

As a general rule, Brazilian Corporate Law provides that a quorum for purposes of holding a shareholders’ meeting shall consist of shareholders representing at least 25% of a company’s issued and outstanding voting capital on the first call and, if that quorum is not reached, any percentage on the second call. There are certain exceptions to the general rule, as in the case of a shareholders’ meeting with the purposes of amending our bylaws, which shall only be held with the presence of shareholders representing at least two-thirds of our issued and outstanding voting capital on the first call and any percentage on the second call.

As a general rule, the affirmative vote of shareholders representing at least the majority of our issued and outstanding common shares present in person or represented by proxy or casting votes remotely (subject to the conditions provided under Brazilian Corporate Law) at a shareholders’ meeting is required to ratify any proposed action, with abstentions not taken into account. However, other qualified quorums may be imposed under Brazilian Corporate Law and the bylaws. An example of an exception is the requirement under Brazilian Corporate Law due to which the affirmative vote of shareholders representing at least one-half of our issued and outstanding voting capital is required to, among other matters:

·	reduce the percentage of mandatory dividends;
·	change our corporate purpose;
·	merge us with another company or consolidate us with another company;
·	spin off a portion of our assets or liabilities;
·	approve our participation in a group of companies (as defined in Brazilian Corporate Law);
·	apply for cancellation of any voluntary liquidation; and
·	approve our dissolution.

According to our bylaws and for so long as we are listed on theNovo Mercado, we may not issue preferred shares or founders’ shares.

Notice of our Shareholders’ Meetings

Notice of our shareholders’ meetings must be published at least three times in theDiário Oficial do Estado de São Paulo, the official newspaper of the state of São Paulo, and in the newspaperValor Econômico. The first notice must be published no later than 15 days before the date of the meeting on the first call, and no later than eight days before the date of the meeting on the second call. However, in certain circumstances, the CVM may require that the first notice be published 30 days in advance of the meeting. The call notice must contain the date, time, place and agenda of the meeting, and in case of amendments to the bylaws, the indication of the relevant matters. CVM Rule No. 481, of December 17, 2009, as amended, or CVM Rule No. 481, requires that additional information is disclosed for certain matters. For example, in the event of an election of directors, the relevant company shall disclose, among other information, the minimum percentage of equity interest required from a shareholder to request the adoption of multiple voting procedures, as well as the relevant ballot paper for casting votes remotely.

Documents and Information

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

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·	matters with interest of related parties;
·	ordinary Shareholders’ Meeting;
·	election of members of the Board of Directors;
·	compensation of the Management of our company;
·	amendment to our company’s bylaws;
·	capital increase or capital reduction;
·	issuance of debentures or subscription bonuses;
·	issuance of preferred shares;
·	reduction of the mandatory dividend distribution;
·	acquisition of the control of another company;

·	appointment of evaluators;
·	any matter which entitles the shareholders to exercise their withdrawal right; and
·	merger, spin-off, stock swap merger or consolidation with at least one publicly-held company enrolled with the CVM in a certain category (category A – in which we are enrolled).

Location of our Shareholders’ Meetings

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

Who May Call our Shareholders’ Meetings

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

·	any shareholder, if our directors fail to call a shareholders’ meeting within 60 days after the date they were required to do so under applicable laws and our bylaws;;
·	shareholders holding at least five percent of our capital stock, if our directors fail to call a meeting within eight days after receipt of a request to call the meeting by those shareholders indicating the proposed agenda; and
·	our fiscal council, if the Board of Directors delays calling an annual shareholders’ meeting for more than one month. The fiscal council may also call a special shareholders’ meeting any time if it believes that there are important or urgent matters to be addressed.

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Conditions of Admission

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

A shareholder may be represented at a shareholders’ meeting by a proxy, as long as the proxy is appointed less than a year before the shareholders’ meeting. The proxy must be a shareholder, an officer of the corporation, a lawyer or, in certain cases, a financial institution. An investment fund must be represented by its investment fund officer. The company and/or its shareholders may also carry out a public proxy request directed to all shareholders with voting rights, subject to certain procedures governed by Brazilian Corporate Law. For shareholders who are legal persons, in accordance with the understanding of the Joint Committee of the CVM issued in a meeting held on November 4, 2014 (CVM Proceeding RJ2014/3578), there is no need for the proxy to be (i) a shareholder or manager of the company, (ii) a lawyer or (iii) a financial institution.

Recent amendments to CVM Rule No. 481 have also ruled, among other provisions, the right of our shareholders casting votes remotely. For such purposes and subject to certain procedures governed by Brazilian Corporate Law, (i) we are requested to provide our shareholders, up to one month before the date scheduled for certain shareholders’ meetings, with the ballot paper to cast votes remotely, and (ii) our shareholders are requested to send back the relevant ballot paper directly to us (by post or e-mail), or by giving instructions to certain authorized services providers, no later than seven days before the date scheduled for the shareholders’ meeting. In the case of instructions given to authorized services providers, such authorized services providers may accept instructions by any means that they usually use to communicate with the shareholders and also refuse to accept voting instructions from shareholders according with their internal rules. We (and also certain authorized services providers) may request rectifications in the ballot paper sent by shareholders wishing to cast votes remotely. In certain specific cases and under certain conditions, we might provide our shareholders with a more beneficial deadline or mechanism to send back the ballot papers, or to attend our shareholders’ meetings (for example, by means of an electronic system which may allow them to remotely attend our meetings).

CVM Rule No. 481 also established the right of shareholders to request the inclusion of candidates and proposals in the ballot, to the extent that the terms provided for in CVM Rule No. 481 are observed. The inclusion of proposals in the ballot must be requested up to 45 days before the annual general meeting. In relation to the inclusion of candidates in the annual general meeting or in the extraordinary general meeting, in both cases the request must be made up to 25 days before the date of such meeting. If the inclusion of a candidate is requested properly, we must present a new version of the ballot at least 20 days before the date of the referred meeting in order for the shareholders to decide whether they want to change their votes or not. If the shareholders do not provide new voting instructions, the previous one will be considered. We may request rectifications to requests made by shareholders wishing to include proposals or candidates on the ballot. A request made by a shareholder may be revoked at any time up to the relevant general meeting, upon notice by the requesting shareholder to the Investor Relations Officer, in which case any votes may be disregarded.

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

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

Preemptive Rights

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

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

Withdrawal Rights and Redemption

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

If our shareholders wish to withdraw from our company due to a merger or a participation in a group of companies, such right may only be exercised provided that our company’s shares have neither liquidity nor dispersion in the market.

The withdrawal right entitles the shareholder to the reimbursement of the value of its shares, upon request within 30 days of the publication of the minutes of the shareholders meeting, except in certain specific cases provided for in Brazilian Corporate Law. After a term provided for in Brazilian Corporate Law, our Management bodies may choose to call a general meeting to ratify or reconsider the decision which triggered the withdrawal rights, should the payment of such rights threaten the financial stability of the company.

Material Contracts

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

Exchange Controls and Other Limitations Affecting Security Holders

There are no restrictions on ownership of our capital stock by individuals or legal entities domiciled outside Brazil. However, the right to convert dividend payments and proceeds from the sale of common shares into foreign currency and to remit such amounts outside Brazil is subject to restrictions under foreign investment legislation which generally requires, among other things, that the relevant investment be registered with the SISBACEN. These restrictions on the remittance of foreign capital abroad could hinder or prevent the custodian for the common shares, or holders who have exchanged ADSs for common shares, from remitting proceeds related to dividends, or distributions or the proceeds from any sale of common shares abroad. Delays in, or refusal to grant any required government approval for conversions of Brazilian currency payments and remittances abroad of amounts owed to holders of common shares not residing in Brazil could adversely affect these holders.

Resolution No. 4,373, issued by the National Monetary Council on September 29, 2014, or Resolution No. 4,373, provides that foreign investors may invest in financial and capital markets in Brazil, including through the issuance of depositary receipts in foreign markets in respect of shares of Brazilian issuers.

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Pursuant to Resolution No. 4,373, in order to be entitled to trade our common shares directly on the B3, the investor domiciled outside Brazil is required to appoint a Brazilian financial institution duly authorized by the Brazilian Central Bank and the CVM to act as its legal representative. Any such shareholder would need to enter into foreign exchange transactions (without the effective remittance of funds) in order to be able to remit dividends and other distributions outside Brazil. The holder may not be able to remit outside Brazil any distributions, or proceeds from dispositions of shares, until he or she has entered into these foreign exchange transactions and updated his or her SISBACEN registration.

Under Brazilian law, whenever there is a serious imbalance in Brazil’s balance of payments or reasons to foresee a serious imbalance, the Brazilian government may impose temporary restrictions on the remittance to foreign investors of the proceeds of their investments in Brazil, and on the conversion of Brazilian currency into foreign currencies. Such restrictions may hinder or prevent shareholders domiciled outside Brazil from converting distributions or the proceeds from any sale of such shares, as the case may be, into U.S. dollars and remitting such U.S. dollars abroad.

Taxation

The following discussion summarizes certain Brazilian and U.S. federal income tax consequences of the acquisition, ownership and disposition of common shares, but it does not purport to be a comprehensive description of all the tax considerations that may be relevant to a decision to purchase, own or dispose of common shares. The summary is based upon the tax laws of Brazil and regulations thereunder and on the tax laws of the United States and regulations thereunder as in effect on the date hereof, which are subject to change (possibly on a retroactive basis) and different interpretations. Holders of common shares should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common shares.

Although there is currently no income tax treaty between Brazil and the United States, the tax authorities of the two countries have had discussions that may culminate in such a treaty. No assurance can be given, however, as to whether or when a treaty will enter into force or how it will affect the U.S. holders (as defined below) of common shares. Prospective holders of common shares should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common shares in their particular circumstances.

Brazilian Tax Considerations

The following discussion summarizes the material Brazilian tax consequences of the acquisition, ownership and disposition of our common shares by a holder that is not domiciled in Brazil for purposes of Brazilian taxation, or a non-Brazilian Holder.

Pursuant to Brazilian law, foreign investors may invest in the financial and capital markets of Brazil, including shares issued by Brazilian publicly traded corporations, provided that the applicable requirements are met, especially those provided under Resolution No. 4,373.

According to Resolution No. 4,373, investments of foreign investors shall be made in Brazil pursuant to the same instruments and operational modalities available to the investors resident or domiciled in Brazil. The definition of foreign investor includes individuals, legal entities, funds and other collective investment entities, resident, domiciled or headquartered abroad.

Pursuant to Resolution 4,373, among the requirements applicable to the investment of foreign investors in the Brazilian financial and capital markets, the foreign investors must: (i) appoint at least one representative in Brazil, which must be a financial institution or other institution authorized by the Brazilian Central Bank to operate in Brazil. The local representative appointed by the foreign investor shall be responsible for performing and updating the registration of the investments made by the foreign investor to the Brazilian Central Bank, as well as the registration of the foreign investor with the CVM; (ii) obtain a registry as foreign investor with the CVM, through the representative appointed pursuant to item (i) above; and (iii) establish or contract one or more custodians authorized by the CVM to perform custody activities.

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Securities and other financial assets held by foreign investors pursuant to Resolution No. 4,373 must be registered or maintained in deposit accounts or under the custody of an entity duly licensed by the Brazilian Central Bank or the CVM, or be registered with clearing houses or other entities that provide services of registration, clearing and settlement duly licensed by the Brazilian Central Bank or the CVM.

For purposes of the mandatory registry with the Brazilian Central Bank of foreign investments in the Brazilian financial and capital markets, Resolution No. 4,373 expressly provides that simultaneous foreign exchange transactions (i.e. without effective transfer of funds) shall be required in specific situations, including: (i) conversion of credits held by foreign investors in Brazil into foreign investment in the Brazilian financial and capital markets; (ii) transfer of investments made in depositary receipts into foreign direct investments (orinvestimento externo direto) or investments in the Brazilian financial and capital markets; and (iii) transfer of investments in the Brazilian financial and capital markets into foreign direct investments.

In addition, Resolution No. 4,373 does not allow foreign investors to perform investments outside of organized markets, except as expressly authorized by the CVM through specific regulation. Pursuant to CVM Rule No. 560/15, the exceptions for investments outside of organized markets include subscription, stock bonus, among others.

Taxation of Dividends

Stock dividends paid by a Brazilian company to foreign investors, with respect both to foreign direct investments and to foreign investments carried out under the rules of Resolution No. 4,373, are generally not subject to withholding income tax in Brazil, to the extent that such amounts are related to profits generated as of January 1, 1996, as provided under article 10 of Law No. 9,249, dated December 26, 1995, or Law No. 9,249/95. The Brazilian government has been discussing the implementation of a tax reform involving an extensive restructuring of the Brazilian tax system, which may include changes to the rules governing the taxation of dividends. In certain political and economic cenarios, changes in rules governing the taxation of dividends may occur even outside of the context of a broader reform in the Brazilian tax system. For more information on risks relating to changes to the rules governing the taxation of dividends, including a possible tax reform, see “Item 3. Key Information—Risk Factors—Risks Relating to Brazil—Political conditions may have an adverse impact on the Brazilian economy and on our business.”

Interest Attributable to Shareholders’ Equity

Law No. 9,249, of December 26, 1995, as amended, allows a Brazilian corporation, such as us, to make payments to shareholders of interest attributable to shareholders' equity as an alternative to carrying out dividend distributions and treat those payments as a deductible expense for purposes of calculating Brazilian corporate income tax and social contribution on profit for the year.

For tax purposes, this interest is limited to the daily variation of the pro rata variation of the TJLP and the amount of the distribution may not exceed the greater of:

·	50% of net profits (after the deduction of the social contribution on profit for the year and before taking into account the provision for corporate income tax and the amounts of interest attributable to shareholders' equity) for the period in respect of which the payment is made; or
·	50% of the sum of retained profits and profits reserves for the year prior to the year in respect of which the payment is made.

Payments of interest attributable to shareholders' equity to a non-Brazilian Holder are subject to WHT at the rate of 15%, or 25% if the non-Brazilian Holder is domiciled in a Low or Nil Tax Jurisdiction (as defined below).

Payments of interest attributable to shareholders' equity may be included, at their net value, as part of any minimum mandatory dividend. In accordance with applicable law, we are required to pay to shareholders an amount sufficient to ensure that the net amount they receive in respect of interest attributable to shareholders' equity, after payment of the applicable withholding tax, plus the amount of declared dividends, is at least equivalent to the amount of the minimum mandatory dividend. Distributions of interest attributable to shareholders' equity to a non-Brazilian Holder may be converted into U.S. dollars and remitted outside Brazil, subject to applicable exchange controls, to the extent that the investment is registered with the Brazilian Central Bank.

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Taxation of Gains

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

With respect to the disposition of our common shares, as they are assets located in Brazil, the non-Brazilian Holder should be subject to income tax on the gains assessed, following the rules described below.

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

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

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

·	exempt from income tax when realized by a non-Brazilian Holder that: (i) has registered the investment in Brazil with the Brazilian Central Bank under the rules of Resolution No. 4,373, or a 4,373 Holder; and (ii) is not resident or domiciled in a country or location which is defined as a Low or Nil Tax Jurisdiction;
·	subject to income tax at a 15% rate, in the case of gains realized by: (i) a non-Brazilian Holder that (a) is not a 4,373 Holder, and (b) is not resident or domiciled in a Low or Nil Tax Jurisdiction; or by (ii) a non-Brazilian Holder that (a) is a 4,373 Holder, and (b) is resident of or domiciled in a Low or Nil Tax Jurisdiction; or
·	subject to income tax at a rate of up to 25%, in the case of gains realized by a non-Brazilian Holder that (i) is not a 4,373 holder, and (ii) is a resident of or domiciled in a Low or Nil Tax Jurisdiction.

In any case, a withholding income tax rate of 0.005% shall be applicable and withheld by the intermediary institution (i.e., a broker) that receives the order directly from the non-Brazilian Holder, which can be later offset against any income tax due on the capital gain earned by the non-Brazilian Holder.

Subject to the discussion in the next paragraph, any other gains assessed on the disposition of common shares that are not carried out on a Brazilian stock exchange are:

·	subject to income tax at a rate of 15% when realized by any non-Brazilian Holder that is not resident or domiciled in a Low or Nil Tax Jurisdiction, and is a 4,373 Holder, although different interpretations may be raised to sustain the application of the progressive rates set forth by Law No. 13,259;
·	subject to income tax at progressive rates, from a rate of 15% to 22.5%, in the case of gains realized by (i) a non-Brazilian Holder that: (A) is not a 4,373 Holder; and (B) is not resident or domiciled in a Low or Nil Tax Jurisdiction; and (ii) Non-Brazilian Holder that (A) is a 4,373 Holder and (B) is resident or domiciled in a Low or Nil Tax Jurisdiction (as defined below);
·	subject to income tax at a rate of up to 25% when realized by a non-Brazilian Holder that is a not a 4,373 Holder and is resident or domiciled in a Low or Nil Tax Jurisdiction.

On September 22, 2015, the Brazilian government enacted Provisional Measure No. 692/2015, later converted into Law No. 13,259/2016, which introduced a regime based on the application of progressive tax ratesfor income taxation of capital gains recognized by Brazilian individuals on the disposition of assets in general and, as per Normative Instruction 1,732 of August 25, 2017, also by non-resident entities and individuals on the disposition of permanent assets (generally noncurrent assets from an accounting perspective) not carried out on a Brazilian stock exchange. Under Law No. 13,259/2016, effective as of January 1, 2017 (as confirmed by Declaratory Act No. 3, of April 27, 2016), capital gains recognized by Brazilian individuals on the disposition of assets in general and by non-resident entities and individuals on the disposition of permanent assets outside of a Brazilian stock exchange would be subject to the following rates of income tax: (i) 15% for the part of the gain that does not exceed R$5 million; (ii) 17.5% for the part of the gain that exceeds R$5 million but does not exceed R$10 million; (iii) 20% for the part of the gain that exceeds R$10 million but does not exceed R$30 million; and (iv) 22.5% for the part of the gain that exceeds R$30 million. There are, however, good arguments to sustain that the progressive tax rates provided for in Law No. 13,259/2016 should not apply to gains recognized by a non-Brazilian Holder that is not a resident of or domiciled in a Low or Nil Tax Jurisdiction, and is a 4,373 Holder. If these gains are related to transactions conducted on the Brazilian non-organized over-the-counter market with intermediation, the withholding income tax of 0.005% on the sale value shall also be applicable and can be offset against the eventual income tax due on the capital gain. However, Normative Ruling No. 1,732/2017 issued by the Brazilian tax authorities amended Normative Ruling No. 1,455/2015 (which consolidates the tax treatments applied to earnings and income derived by non-residents), expressly determining that such income tax rates generally apply to capital gains derived by non-residents.

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In the case of redemption of securities or capital reduction by a Brazilian corporation, such as us, the positive difference between the amount effectively received by the non-Brazilian Holder and the corresponding acquisition cost is treated, for tax purposes, as capital gain derived from sale or exchange of shares not carried out on a Brazilian stock exchange, and is therefore subject to income tax at rates varying from 15% to 22.5% or 25%, in case of non-Brazilian Holders in Low or Nil Tax Jurisdictions, as the case may be. There are, however, good arguments to sustain that these progressive tax rates should not apply to gains recognized by a non-Brazilian Holder that is not a resident of or domiciled in a Low or Nil Tax Jurisdiction, and is a 4,373 Holder.

Any exercise of preemptive rights relating to our common shares will not be subject to Brazilian taxation. Any gain on the sale or assignment of preemptive rights relating to our common shares will be subject to Brazilian income taxation according to the same rules applicable to the sale or disposition of our common shares.

There can be no assurance that the current favorable tax treatment of 4,373 Holders will continue in the future.

Interpretation of the Discussion on the Definition of “Low or Nil Tax Jurisdiction”

On June 4, 2010, Brazilian tax authorities enacted Normative Ruling No. 1,037 listing: (i) the countries and jurisdictions considered as Low or Nil Tax Jurisdictions or where the local legislation does not allow access to information related to the shareholding composition of legal entities, to their ownership or to the identity of the effective beneficiary of the income attributed to non-residents; and (ii) the privileged tax regimes, the definition of which is provided by Law No. 11,727, of June 23, 2008.

A Low or Nil Tax Jurisdiction is a country or location that: (i) does not impose taxation on income; (ii) imposes income tax at a maximum rate lower than 20.0%; or (iii) imposes restrictions on the disclosure of shareholding composition or the ownership of the investment. A regulation issued by the Brazilian tax authorities on November 28, 2014 (Ordinance No. 488, of 2014) decreased, from 20.0% to 17.0%, the minimum threshold for certain specific cases. The reduced 17.0% threshold applies only to countries and regimes aligned with international standards of fiscal transparency in accordance with rules to be established by the Brazilian tax authorities. Although Ordinance No. 488/14 has lowered the threshold rate, Normative Ruling No. 1,037/10, which identifies the countries considered to be Low or Nil Tax Jurisdictions and the locations considered as privileged tax regimes, has not been amended yet to reflect such threshold modification.

Law No. 11,727/08 created the concept of "privileged tax regimes," which encompasses the countries and jurisdictions that (i) do not tax income or tax it at a maximum rate lower than 20.0%; (ii) grant tax advantages to a non-resident entity or individual (a) without the need to carry out a substantial economic activity in the country or a said territory or (b) conditioned to the non-exercise of a substantial economic activity in the country or a saidterritory; (iii) do not tax or tax proceeds generated abroad at a maximum rate lower than 20.0%; or (iv) restrict the ownership disclosure of assets and ownership rights or restrict disclosure about economic transactions carried out. Although we believe that the best interpretation of the current tax legislation is that the above mentioned “privileged tax regime” concept should apply solely for purposes of Brazilian transfer pricing and thin capitalization rules, we are unable to ascertain whether or not the privileged tax regime concept will be extended to the concept of Low or Nil Tax Jurisdiction in view of the provisions introduced by Normative Ruling No. 1,037/10, as amended, which presents two different lists (Low or Nil Tax Jurisdictions—taking into account the non-transparency rules—and privileged tax regimes).

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Prospective investors should consult their own tax advisors as to tax consequences of Normative Ruling No. 1,037/10 and Law No. 11,727/08. If the Brazilian tax authorities consider that payments were made to a non-Brazilian Holder who is resident or domiciled in a Low or Nil Tax Jurisdiction, the withholding income tax applicable to such payments could be assessed at a rate of up to 25%.

Tax on Foreign Exchange Transactions

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

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

Other Relevant Brazilian Taxes

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

U.S. Federal Income Tax Consequences

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

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This discussion does not purport to be a comprehensive description of all of the U.S. federal income tax consequences that may be relevant to a particular holder (including tax considerations that arise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known by investors) and holders are urged to consult their own tax advisors regarding their specific tax situations. This discussion applies only to holders of common shares who hold the common shares as “capital assets” (generally, property held for investment) under the Code and does not address the tax consequences that may be relevant to holders in special tax situations, including, for example:

·	brokers or dealers in securities or currencies;
·	U.S. holders whose functional currency is not the U.S. dollar;
·	holders that own or have owned stock constituting 10.0% or more of our total combined voting power or value (whether such stock is directly, indirectly or constructively owned);
·	tax-exempt organizations;
·	regulated investment companies;
·	realestate investment trusts;
·	grantor trusts;
·	common trust funds;
·	banks or other financial institutions;
·	persons liable for the alternative minimum tax;
·	securities traders who elect to use the mark-to-market method of accounting for their securities holdings;
·	insurance companies;
·	persons that acquired common shares as compensation for the performance of services;
·	U.S. expatriates; and
·	persons holding common shares as part of a straddle, hedge or conversion transaction or as part of a synthetic security, constructive sale or other integrated transaction.

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

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

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If a partnership (or other entity or arrangement classified as a partnership for U.S. federal income tax purposes) owns common shares, the tax treatment of a partner in such partnership will generally depend on the status of the partner and the activities of the partnership holding common shares. Partnerships that are beneficial owners of common shares, and partners in such partnerships, should consult their own tax advisors regarding the U.S. federal, state, local and non-U.S. tax considerations applicable to them with respect to the acquisition, beneficial ownership and disposition of common shares.

Taxation of Distributions

Subject to the discussion below under“—Passive Foreign Investment Company Rules,” the gross amount of any distributions of cash or property made with respect to common shares (including distributions characterized as interest attributable to shareholders’ equity for Brazilian law purposes and any amounts withheld to reflect Brazilian withholding taxes) generally will be taxable as dividends for U.S. federal income tax purposes to the extent of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles.

A U.S. holder will generally include such dividends in gross income as ordinary income on the day such dividends are actually or constructively received. Distributions in excess of our current and accumulated earnings and profits will be treated first as a non-taxable return of capital, thereby reducing the U.S. holder’s adjusted tax basis (but not below zero) in common shares, as applicable, and thereafter as either long-term or short-term capital gain (depending on whether the U.S. holder has held common shares for more than one year as of the time such distribution is actually or constructively received). We do not, however, expect to determine earnings and profits in accordance with U.S. federal income tax principles. Therefore, a U.S. holder should expect that a distribution will generally be treated as a dividend.

If any cash dividends are paid inreais, the amount of the dividends paid inreaiswill be the U.S. dollar value of thereaisreceived, calculated by reference to the exchange rate in effect on the date of actual or constructive receipt, regardless of whether the payment inreaisis in fact converted into U.S. dollars at that time. If thereaisreceived as a dividend are converted into U.S. dollars on the date of actual or constructive receipt, a U.S. holder should not recognize foreign currency gain or loss in respect of such dividend. If thereais received as a dividend are not converted into U.S. dollars on the date of actual or constructive receipt, a U.S. holder will have a tax basis in thereaisequal to their U.S. dollar value on the date of receipt. If anyreais actually or constructively received by a U.S. holder are later converted into U.S. dollars, such U.S. holder may recognize foreign currency gain or loss, which would be treated as ordinary gain or loss. Such gain or loss generally will be treated as gain or loss from sources within the United States for U.S. foreign tax credit purposes. U.S. holders should consult their own tax advisors concerning the possibility of foreign currency gain or loss if any suchreaisare not converted into U.S. dollars on the date of actual or constructive receipt.

Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code. See below for a discussion regarding our PFIC determination.

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

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Subject to certain limitations (including a minimum holding period requirement), a U.S. holder may be entitled to claim a U.S. foreign tax credit in respect of any Brazilian income taxes withheld on dividends received with respect to the common shares. A U.S. holder that does not elect to claim a credit for any foreign income taxes paid or accrued during a taxable year may instead claim a deduction in respect of such Brazilian income taxes, provided that the U.S. holder elects to deduct (rather than credit) all foreign income taxes paid or accrued for the taxable year. Dividends received with respect to the common shares generally will be treated as dividend income from sources outside of the United States and generally will constitute “passive category income” for U.S. foreign tax credit limitation purposes for most U.S. holders. The rules governing foreign tax credits are complex and U.S. holders should consult their own tax advisors regarding the availability of foreign tax credits in their particular circumstances.

Distributions of additional common shares to holders with respect to their common shares that are made as part of a pro rata distribution to all our shareholders generally will not be subject to U.S. federal income tax.

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

Taxation of Sales, Exchanges or Other Taxable Dispositions

Subject to the discussion below under “—Passive Foreign Investment Company Rules,” upon the sale, exchange or other taxable disposition of common shares, a U.S. holder will generally recognize gain or loss for U.S. federal income tax purposes in an amount equal to the difference between the amount realized in consideration for the disposition of the common shares and the U.S. holder’s adjusted tax basis in the common shares, in each case as determined in U.S. dollars. Such gain or loss generally will be treated as capital gain or loss and will be long-term capital gain or loss if the common shares have been held for more than one year at the time of the sale, exchange or other taxable disposition. Under current law, certain non-corporate U.S. holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. The deductibility of capital losses is subject to limitations under the Code.

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

A U.S. holder’s initial tax basis on our common shares will be the U.S. dollar value of thereaisdenominated purchase price determined on the date of purchase. With respect to the sale, exchange or other taxable disposition of common shares, the amount realized generally will be the U.S. dollar value of the payment received determined on (1) the date of actual or constructive receipt of payment in the case of a cash basis U.S. holder and (2) the date of disposition in the case of an accrual basis U.S. holder. If the common shares are traded on an “established securities market,” a cash basis U.S. holder, or an electing accrual basis U.S. holder, will determine the U.S. dollar rate of the cost of the common shares or the amount realized based on the exchange rate on the settlement date of the sale. If a U.S. holder sells or otherwise disposes of our common shares in exchange for currency other than U.S. dollars, any gain or loss that results from currency exchange fluctuations during the period from the date of the sale or other disposition until the date that the currency is converted into U.S. dollars generally will be treated as ordinary income or loss and will not be eligible for the reduced tax rate applicable to long-term capital gains. Such gain or loss generally will be U.S.-source income or loss. If the currency is converted into U.S. dollars on the date of receipt, a U.S. holder generally would not be required to recognize foreign currency gain or loss in respect of the amount realized. U.S. holders are urged to consult their own tax advisors regarding the treatment of any foreign currency gain or loss realized with respect to any currency received in a sale or other disposition of the common shares that is converted into U.S. dollars (or otherwise disposed of) on a date subsequent to receipt.

A non-U.S. holder will not be subject to U.S. federal income tax or withholding tax on gain realized on the sale or other taxable disposition of common shares unless (i) such non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the sale or other taxable disposition and certain other conditions are met; or (ii) such gain is effectively connected with the conduct by the non-U.S. holder of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment or fixed base). If the first exception (i) applies, the non-U.S. holder generally will be subject to tax at a rate of 30% (or such lower rate provided by an applicable treaty) on the amount by which the gains derived from the sales that are from U.S. sources exceed capital losses allocable to U.S. sources. If the second exception (ii) applies, the non-U.S. holder generally will be subject to U.S. federal income tax with respect to the gain in the same manner as U.S. holders, as described above. In addition, in the case of (ii), if such non-U.S. holder is a foreign corporation, it may be subject to a branch profits tax equal to 30% (or such lower rate provided by an applicable treaty) of its effectively connected earnings and profits for the taxable year, subject to certain adjustments.

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Passive Foreign Investment Company Rules

Special U.S. federal income tax rules apply to U.S. persons owning shares of a PFIC. In general, a non-U.S. corporation will be classified as a PFIC for any taxable year during which, after applying relevant look through rules with respect to the income and assets of subsidiaries, either: (i) 75.0% or more of the non-U.S. corporation’s gross income is “passive income”; or (ii) 50.0% or more of the gross value (determined based on a quarterly average) of the non-U.S. corporation’s assets produce passive income or are held for the production of passive income. For these purposes, passive income generally includes, among other things, dividends, interest, rents, royalties, gains from the disposition of passive assets and gains from commodities and securities transactions, other than certain active business gains from the sale of commodities (subject to various exceptions). In determining whether a non-U.S. corporation is a PFIC, a pro rata portion of the income and assets of each corporation in which it owns, directly or indirectly, at least 25.0% interest (by value) is taken into account.

The determination as to whether a non-U.S. corporation is a PFIC is based on the composition of the income and assets of the non-U.S. corporation from time to time and the application of complex U.S. federal income tax rules, which are subject to different interpretations and involves uncertainty. Based on our audited annual consolidated financial statements, the nature of our business, and relevant market and shareholder data, we believe that we would not be classified as a PFIC for our last taxable year or our current taxable year (although the determination cannot be made until the end of the current taxable year), and we do not expect to be classified as a PFIC in the foreseeable future, based on our current business plans and our current interpretation of the Code and Treasury regulations that are currently in effect. However, because the application of the Code and Treasury regulations are not entirely clear and because our PFIC status depends on the composition of our income and assets and the market value of our assets from time to time, there can be no assurance that we will not be treated as a PFIC for any taxable year.

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

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

In general, if we are treated as a PFIC, the rules described above can be avoided by a U.S. holder that elects to be subject to a mark-to-market regime for stock in a PFIC. A U.S. holder may elect mark-to-market treatment for its common shares, provided the common shares, for purposes of the rules, constitute “marketable stock” as defined in Treasury regulations. The common shares, which are listed on the B3, will be “marketable stock” if the B3 meets certain requirements and if the common shares are traded on the B3, other than inde minimisquantities, on at least 15 days during each calendar quarter. A U.S. holder electing the mark-to-market regime generally would compute gain or loss at the end of each taxable year that we are a PFIC as if the common shares had been sold at fair market value. Any gain recognized by the U.S. holder under mark-to-market treatment, or on an actual sale in a year that we are a PFIC, would be treated as ordinary income, and the U.S. holder would be allowed an ordinary deduction for any decrease in the value of common shares as of the end of any taxable year that we are a PFIC, and for any loss recognized on an actual sale in a year that we are a PFIC, but only to the extent, in each case, of previously included mark-to-market income not offset by previously deducted decreases in value. Any loss on an actual sale of common shares would be a capital loss to the extent in excess of previously included mark-to-market income not offset by previously deducted decreases in value. A U.S. holder’s adjusted tax basis in common shares would increase or decrease by gain or loss taken into account under the mark-to-market regime. A mark-to-market election is generally irrevocable unless the IRS consents to the revocation of the election or the common shares cease to be “marketable stock.” In addition, a mark-to-market election with respect to common shares would not apply to any lower-tier PFIC, and a U.S. holder would not be able to make such a mark-to-market election in respect of its indirect ownership interest in that lower-tier PFIC. Consequently, the PFIC rules could apply with respect to income of a lower-tier PFIC, the value of which would already have been taken into account indirectly via mark-to-market adjustments in respect of common shares.

We do not intend to make available the information necessary for a U.S. holder to make a “qualified electing fund” election with respect to our company.

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A U.S. holder that owns common shares during any taxable year that we are treated as a PFIC generally would be required to file IRS Form 8621 in order to comply with an additional annual filing requirement for U.S. persons owning shares of a PFIC. U.S. holders should consult their independent tax advisors regarding the application of the PFIC rules to common shares, the availability and advisability of making an election to avoid the adverse tax consequences of the PFIC rules should we be considered a PFIC for any taxable year and the reporting requirements that may apply to their particular situation.

Backup Withholding and Information Reporting

Dividends paid on, and proceeds from the sale, exchange or other taxable disposition of, common shares to a U.S. holder generally may be subject to the information reporting requirements of the Code and may be subject to backup withholding of U.S. federal income tax (currently at a rate of 24.0%) unless the U.S. holder (i) provides an accurate taxpayer identification number and certifies that it is a U.S. person and that no loss of exemption from backup withholding has occurred or (ii) establishes that it is an exempt recipient. The amount of any backup withholding collected from a payment to a U.S. holder will be allowed as a credit against the U.S. holder’s U.S. federal income tax liability and may entitle the U.S. holder to a refund, provided that certain required information is timely furnished to the IRS.

In addition, U.S. holders should be aware that additional reporting requirements apply with respect to the holding of certain foreign financial assets, including stock of foreign issuers which is not held in an account maintained by certain financial institutions, if the aggregate value of all such assets exceeds U.S.$50,000 on the last day of the tax year or U.S.$75,000 at any time during the tax year. U.S. holders should consult their own tax advisors regarding the application of the information reporting rules to common shares and the application of the foreign financial asset rules to their particular situations.

Non-U.S. holders generally will not be subject to information reporting and backup withholding tax, but may be required to comply with certain certification and identification procedures in order to establish their eligibility for such exemption.

Documents on Display

Statements contained in this annual report regarding the contents of any contract or other document are not necessarily complete, and, where the contract or other document is an exhibit to the annual report, each of these statements is qualified in all respects by the provisions of the actual contract or other documents.

We are subject to the information requirements of the Securities Exchange Act of 1934, as amended, applicable to a foreign private issuer, and accordingly, we file or furnish reports, information statements and other information with the SEC. Reports and other information filed by us with the SEC can be inspected at, and subject to the payment of any required fees, copies may be obtained from, the public reference facilities of the SEC, 100 F Street, N.E., Washington, D.C. 20549. Our filings will also be available at the SEC’s website at http://www.sec.gov.

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Reports and other information may also be inspected and copied at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. As a foreign private issuer, however, we are exempt from the proxy requirements of Section 14 of the Exchange Act and from the short-swing profit recovery rules of Section 16 of the Exchange Act.

Our website is located at http://www.cpfl.com.br and our investor relations website is located at http://www.cpfl.com.br/ir. (These URLs are intended to be an inactive textual reference only. They are not intended to be an active hyperlink to our website. The information on our website, which might be accessible through a hyperlink resulting from this URL is not, and shall not be deemed to be, incorporated into this annual report.)

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in both foreign currency exchange rates and rates of interest and indexation. We have foreign exchange rate risk with respect to our debt denominated in U.S. dollars. We are subject to market risk deriving from changes in rates which affect the cost of our financing.

Exchange Rate Risk

At December 31, 2019, 26.5% of our indebtedness was denominated in foreign currency. Also at December 31, 2019, we had swap agreements indexed to the CDI rate that offset the exchange rate risk exposure in foreign currency loans. As our net exposure is an asset denominated in U.S. dollars since the swap has higher balances than the liability, our exchange rate risk is associated with the risk of a drop in the value of the U.S. dollar. The potential gain to us that would result from a hypothetical unfavorable 1.22% change in foreign currency exchange rates (an expected scenario reported by the Brazilian Central Bank on the Focus Report from December 27, 2019), after giving effect to the swaps, would be R$51 million, primarily due to the increase, in Brazilianreais, in the principal amount of our foreign currency indebtedness. The potential loss to us that would result from a hypothetical favorable 50.0% change in foreign currency exchange rates (an expected scenario reported by the B3), after giving effect to the swaps, would be R$23.0 million (R$11.0 million if considering a hypothetical favorable 25% change in foreign currency exchange rates), primarily due to the increase, in Brazilianreais, in the principal amount of our foreign currency indebtedness. The total increase in our foreign currency indebtedness would be reflected as an expense in our income statement. See Note 35.d.1 to our audited annual consolidated financial statements for more information on other scenarios.

Risk of Index Variation

We have indebtedness and financial assets that are denominated inreaisand that bear interest at variable rates or, in some cases, are fixed. The interest or indexation rates include several different Brazilian money-market rates and inflation rates. At December 31, 2019, the amount of such liabilities, net of such assets and after giving effect to swaps, was R$8,573 million. See Note 35.d.2 to our audited annual consolidated financial statements for more information on other scenarios.

A hypothetical, instantaneous and unfavorable change of 25% in rates applicable to floating rate financial assets and liabilities held at December 31, 2019, would result in a net additional cash outflow of R$487 million. This sensitivity analysis is based on the assumption of an unfavorable 25% movement of the interest rates applicable to each homogeneous category of financial assets and liabilities (an expected scenario available in the market). A homogeneous category is defined according to the currency in which financial assets and liabilities are denominated and assumes the same interest rate movement within each homogeneous category (e.g., U.S. dollars). As a result, our interest rate risk sensitivity model may overstate the impact of interest rate fluctuations for such financial instruments as unfavorable movements of all interest rates are unlikely.

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ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

American Depositary Shares

Citibank N.A. was the depositary of our American Depositary Receipt (ADR) program from January 8, 2015 until the termination of our Deposit Agreement on January 27, 2020. In August 2019, we received reimbursements from the depositary in the amount of US$647 thousand for expenses incurred by us relating to the ADR program.

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

ITEM 15. CONTROLS AND PROCEDURES

We have evaluated, with the participation of our chief executive officer and chief financial officer, the effectiveness of our disclosure controls and procedures (including those related to cybersecurity risks and incidents and their potential impacts) as of December 31, 2019. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon our evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures (including those related to cybersecurity risks and incidents and their potential impacts) were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to our Management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

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

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

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Our Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2019 based on the updated criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in 2013. Based on such assessment and criteria, our Management has concluded that our internal control over financial reporting was effective as of December 31, 2019.

Attestation Report of the Registered Public Accounting Firm

ITEM 16. [RESERVED]

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

As described in Item 16D below, we have given our fiscal council the necessary powers to qualify for the exemption from the audit committee requirements set forth in Exchange Act Rule 10A-3(c)(3). Our Board of Directors recognizes that one member of our fiscal council, Ran Zhang, qualifies as an audit committee financial expert and meets the applicable independence requirements for fiscal council membership under Brazilian law. She also meets the New York Stock Exchange independence requirements that would apply to audit committee members in the absence of our reliance on the exemption set forth in Exchange Act Rule 10A-3(c)(3). Some of the members of our fiscal council are currently employed by some of our principal shareholders or their affiliates.

ITEM 16B. CODE OF ETHICS

We consider ethics to be an essential value for our reputation and longevity. Our Ethics Management and Development System (SGDE) aims to turn concerns with ethical behavior into effective practices, focusing on avoiding breaches and promoting development of ethical quality throughout the Organization’s actions. The system is composed of a set of provisions, implemented in all of our subsidiaries with direct management. SGDE aims to prevent, monitor, assess, revise and improve individual and institutional actions of the company that directly or indirectly imply in ethical behavior, partially or fully of our stakeholders. Our Code of Ethical Conduct (“Code of Ethics”) has a scope that is similar to the one required for a U.S. domestic company under the NYSE rules. We report each year under Item 16B of our annual report on Form 20-F any waivers of the Code of Ethics in favor of our CEO, CFO, principal accounting officer and persons performing similar functions. Besides the initiatives that directly involve our partners, we seek to ensure that our business values are shared by the chain of suppliers through contractual items that require compliance with the Code of Ethics. In our services contracts, there is an exclusive clause regarding the Code of Ethics in the contracting processes. The Code of Ethics governs all relations between companies of the Group and their stakeholders (shareholders, clients, employees, suppliers, service providers, governments, communities and society). The detailed Code of Ethics is available on our website at https://cpfl.riweb.com.br/show.aspx?idMateria=TJJ0DQFsfdvDqqPuQGlX+Q==&linguagem=en (This URL is intended to be an inactive textual reference only. It is not intended to be an active hyperlink to our website. The information on our website, which might be accessible through a hyperlink resulting from this URL, is not and shall not be deemed to be, incorporated into this annual report).

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit and Non-Audit Fees

The following table sets forth the fees billed to us by our independent registered and public accounting firm during the years ended December 31, 2019 and 2018. Our independent accounting firm was KPMG Auditores Independentes for the years ended December 31, 2019 and 2018.

	Year ended December 31,
	2019	2018
	(in thousands of reais)
Audit fees	8,327	5,021
Audit-related fees	549	735
Tax fees	1,222	1,297
Total	10,098	7,054

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“Audit Fees” are the aggregated fees billed by KPMG Auditores Independentes for the audit of our consolidated and annual financial statements, reviews of interim financial statements and attestation services that are provided in connection with statutory and regulatory filings or engagements for fiscal years 2019, as well the issuance of comfort letter related to the Company’s offering, and 2018, respectively.

“Audit-related fees” are fees charged by KPMG Auditores Independentes for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements for the years ended December 31, 2019 and 2018, respectively.

“Tax fees” in the above table are for services related to tax compliance charged by KPMG Auditores Independentes for the years ended December 31, 2019 and 2018, respectively.

Audit Committee Approval Policies and Procedures

Our fiscal council currently serves as our audit committee for purposes of the Sarbanes-Oxley Act of 2002. Our fiscal council has not established pre-approval policies or procedures for recommending the engagement of our independent auditors for services to our board of directors. Pursuant to Brazilian law, our board of directors is responsible for the engagement of independent auditors. Brazilian law prohibits our independent auditors from providing any consulting services to our subsidiaries, or to us that may impair their independence. The internal regulations of our fiscal council set forth that it is the fiscal council’s duty to opine on the hiring of the independent auditors to perform any other services that have not been subject to our board of director’s prior approval.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Under the listed company audit committee rules of the NYSE and the SEC, we must comply with Exchange Act Rule 10A-3, which requires that we establish an audit committee composed of members of the Board of Directors that meets specified requirements. We have designated and empowered our fiscal council to perform the role of the audit committee in reliance on the exemption set forth in Exchange Act Rule 10A-3(c)(3). In our assessment, our fiscal council acts independently in performing the responsibilities of an audit committee under the Sarbanes-Oxley Act and satisfies the other requirements of Exchange Act Rule 10A-3.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

None.

ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

None.

ITEM 16G. CORPORATE GOVERNANCE

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

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Section of the New York Stock Exchange Listed Company Manual	New York Stock Exchange Listing Standard	Ways that CPFL’s Corporate Governance Practices Differ from Those Followed by Domestic Companies Listed on the New York Stock Exchange
303A.01	A company listed on the New York Stock Exchange (a “listed company”) must have a majority of independent directors on its Board of Directors. “Controlled companies” are not required to comply with this requirement.	CPFL is a controlled company, because more than a majority of its voting power is controlled by State Grid Brazil Power Participações S.A., an indirect subsidiary of State Grid Corporation of China. As a controlled company, CPFL would not be required to comply with the majority of independent directors requirements if it were a U.S. domestic issuer. CPFL has two independent directors, as defined by the B3 rules.
303A.03	The non-Management directors of a listed company must meet at regularly scheduled executive sessions without Management.	The non-Management directors of CPFL do not meet at regularly scheduled executive sessions without Management.
303A.04	A listed company must have a Nominating/Corporate Governance Committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties. “Controlled companies” are not required to comply with this requirement.	As a controlled company, CPFL would not be required to comply with the Nominating/Corporate Governance Committee requirements if it were a U.S. domestic issuer.
303A.05	A listed company must have a compensation committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties. “Controlled companies” are not required to comply with this requirement.	As a controlled company, CPFL would not be required to comply with the compensation committee requirements. The Human Resources Management Committee of CPFL is an advisory committee of the Board of Directors. It has three effective members and the same number of alternate members, none of whom is independent. According to its charter, this committee is responsible for assisting the Board of Directors by: (i) coordinating the selection process for our CEO, Vice Presidents and any other Executive Officer our group, by request of the chairman of our board of directors; (ii) defining the global remuneration criteria for our administrators (board of directors and executive officers) and members of our fiscal council, in alignment with our strategy, our directly and indirectly controlled companies and companies with common control, including services agreements, short term incentive plans and long-term incentive plans; and (iii) managing our organizational structure, succession plan and the assessments of our executive officers.
303A.06 and 303A.07	A listed company must have an audit committee with a minimum of three independent directors that satisfy the independence requirements of Rule 10A-3 under the Exchange Act, with a written charter that covers certain minimum specified duties.	In lieu of appointing an audit committee composed of independent members of the Board of Directors, CPFL has a permanentConselho Fiscal, or fiscal council, in accordance with the applicable provisions of the Brazilian Corporate Law, and CPFL has granted the fiscal council with additional powers that meet the requirements of Exchange Act Rule 10A-3(c)(3). Under Brazilian Corporate Law, which enumerates standards for the independence of the fiscal council from CPFL and its Management, none of the members of the fiscal council may be: (i) members of the Board of Directors; (ii) members of the board of executive officers; (iii) employed by CPFL or an affiliate or company controlled by CPFL or (iv) a spouse or relative, to a certain degree, of any member of our Management or Board of Directors. Members of the fiscal council are elected at the company’s general shareholders’ meeting for a one-year term of office. The fiscal council of CPFL currently has three members, all of whom comply with standards (i) to (iv) above. The responsibilities of the fiscal council, which are set forth in its charter, includes reviewing Management’s activities and the company’s financial statements, and reporting findings to the company’s shareholders.
303A.08	Shareholders must be given the opportunity to vote on all equity-compensation plans and material revisions thereto, with limited exemptions set forth in the NYSE rules.	Under Brazilian Corporate Law, shareholder pre-approval is required for the adoption of any equity compensation plans.
303A.09	A listed company must adopt and disclose corporate governance guidelines that cover certain minimum specified subjects.	CPFL has formal corporate governance guidelines that address the matters specified in the NYSE rules. CPFL’s corporate governance guidelines are available on http://www.cpfl.com.br/ir.
303A.10	A listed company must adopt and disclose a code of business conduct and ethics for directors, officers and employees, and promptly disclose any waivers of the code for directors or executive officers.	CPFL has a formal Code of Ethics that applies to its directors, officers, employees and direct controlling shareholders. CPFL’s Code of Ethics has a scope that is similar, but not identical, to that required for a U.S. domestic company under the NYSE rules. CPFL reports each year under Item 16B of our annual report on Form 20-F any waivers, if existent, of the code of ethics in favor of our chief executive officer, our chief financial officer, our principal accounting officer and persons performing similar functions. We will disclose such amendment or waiver on our website.
303A.12	Each listed company CEO must certify to the NYSE each year that he or she is not aware of any violation by the company of NYSE corporate governance listing standards.	CPFL’s CEO provides to the NYSE a Foreign Private Issuer Annual Written Affirmation, and he will promptly notify the NYSE in writing after any executive officer of CPFL becomes aware of any material non-compliance with any applicable provisions of the NYSE corporate governance rules.

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ITEM 16H. MINE SAFETY DISCLOSURE

Not applicable.

ITEM 17. FINANCIAL STATEMENTS

Not applicable.

ITEM 18. FINANCIAL STATEMENTS

See pages F-1 through F-89, incorporated herein by reference.

ITEM 19. EXHIBITS

No.	Description
1.1	Amended and Restated Bylaws of CPFL Energia S.A. (together with an English version).
8.1	List of subsidiaries, their jurisdiction of incorporation and names under which they do business.
12.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
12.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
13.1	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1	Consent of KPMG Auditores Independentes.

The amount of long-term debt securities of CPFL Energia or its subsidiaries authorized under any outstanding agreement does not exceed 35.1% of CPFL Energia’s total assets on a consolidated basis. CPFL Energia hereby agrees to furnish the SEC, upon its request, a copy of any instruments defining the rights of holders of its long-term debt or of its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed.

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GLOSSARY OF TERMS

ABRACEEL: Brazilian Association of Electricity Traders (Associação Brasileira dos Comercializadores de Energia).

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

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

ADRs: American Depositary Receipts.

ADSs:American Depositary Shares.

ANEEL: Brazilian Electricity Regulatory Agency (Agência Nacional de Energia Elétrica).

Annual Reference Value: Mechanism which limits the amounts of costs that can be passed through to Final Consumers. The Annual Reference Value corresponds to the weighted average of electricity acquisition costs resulting from electricity prices of all public auctions carried out by ANEEL and CCEE in the Regulated Market for electricity to be delivered five and three years from any such auction and only applies during the first three years following the commencement of delivery of the acquired electricity.

Assured Energy: Amount of energy that generators are allowed to sell in long-term contracts.

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

Basic Network: Interconnected transmission lines, dams, energy transformers and equipment with voltage equal to or higher than 230 kV, or installations with lower voltage as determined by ANEEL.

Basic Network Charges: Amounts related to the provision of transmission services on the Basic Network owed by users to the transmission concessionaires and to the ONS, calculated by the product of the transmission tariff for the basic network and the amount used. These amounts are charged at the distributor’s rate and passed on to the transmission concessionaires.

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

BNDES: Brazilian Economic and Social Development Bank (Banco Nacional de Desenvolvimento Econômico e Social).

Brazilian Corporate Law:Federal Law No. 6,404, enacted on December 15, 1976, which governs, among other things, corporations (sociedade por ações) and the rights and duties of their shareholders, directors and officers.

CADE:Administrative Council for Economic Defense (Conselho Administrativo de Defesa Econômica).

Capacity Agreement: Agreement under which a generator commits to make a certain amount of capacity available to the Regulated Market. In such case, the generator’s revenue is guaranteed and the distributors must bear the risk of a supply shortage.

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Captive Consumers: Consumers in a Captive Market that acquire energy from the distribution company or holder of a permit to whose network the consumer is connected. Captive Consumers include all residential consumers, as well as certain companies, industries and rural consumers.

Captive Market: Market segment in which each Captive Consumer is obliged to purchase electricity solely from the local distributor. In the Captive Market, tariffs are determined by ANEEL and not subject to negotiation.

CCC Account: Fuel Usage Quota Account (Conta de Consumo de Combustível).

CCEAR: Agreements on Energy Commercialization in the Regulated Market (Contratos de Comercialização de Energia no Ambiente Regulado).

CCEE: Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica). The short-term electricity market, established in 1998 through the Power Industry Law, which replaced the prior system of regulated generation prices and supply contracts, formerly known as the Wholesale Energy Market.

CCRBT: Tariff Flag Resources Centralizing Account (Conta Centralizadora dos Recursos de Bandeiras Tarifárias), administered by the CCEE.

CDE Account: Energetic Development Account (Conta de Desenvolvimento Energético).

CFURH: Financial Compensation for the Use of Water Resources (Compensação Financeira pela Utilização de Recursos Hídricos).

CMN: Brazilian Monetary Council (Conselho Monetário Nacional).

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

COFINS: Contribution for the financing of social security (contribuição para o financiamento da seguridade social) tax.

Concession Law: Federal Law No. 8,987, enacted on February 13, 1995, which establishes, among other things, the conditions that the concessionaire must comply with when providing electricity services, the rights of consumers, and the obligations of the concessionaire and the granting authority.

Conventional Free Consumers: Consumers whose contracted energy demand is at least 3 MW. These consumers may opt to purchase conventional energy, entirely or partially, from another authorized selling agent under the terms of current legislation. We refer to consumers who have exercised this option as “Conventional Free Consumers,” and those who meet the demand requirements but have not exercised the option to migrate to the Free Market as “Potential Conventional Free Consumers.”

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

CSLL: Social Contribution on Net Profits (Contribuição Social sobre o Lucro Líquido).

CVA: Parcel "A" cost variation account (Conta de Compensação de Variação de Valores de Itens da Parcela “A”).

CVM:Brazilian Securities Commission (Comissão de Valores Mobiliários).

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

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

EBITDA: Earnings before interest, taxes, depreciation and amortization.

EER: Reserve Energy Charge (Encargo de Energia de Reserva).

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

EPE: Energy Research Company (Empresa de Pesquisas Energéticas).

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

Final Consumer: A party that uses electricity for its own needs.

Free Consumer: Consumers that may choose to purchase electricity through negotiations with any available electricity distributor.

Free Market: Market segment that permits a certain degree of competition (Ambiente de Contratação Livre – ACL). The Free Market specifically contemplates purchases of electricity by non-regulated entities such as Free Consumers and energy traders.

GDP: Gross Domestic Product.

Gigawatt (GW): One billion Watts.

Gigawatt average (GWavg): Average of GWh.

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

High Voltage: A class of nominal system voltages greater than 138 kV and equal to or lower than 230 kV.

Hydroelectric Facility: A power plant that uses hydraulic water power for the production of electricity.

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

IASB:The International Accounting Standards Board.

ICMS: State-level value-added tax (Imposto sobre Operações Relativas à Circulação de Mercadorias e Prestação de Serviços de Transporte Interestadual e Intermunicipal e de Comunicação).

IFRS: International Financial Reporting Standards.

IGP-M/FGV: Market General Price Index (Índice Geral de Preços –Mercado published byFundação Getúlio Vargas).

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

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

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

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

IRPJ: Corporate income tax (Imposto de Renda – Pessoa Jurídica).

ISS: Tax on services (imposto sobre serviços).

Kilovolt (kV): One thousand volts.

Kilowatt (kW): One thousand Watts.

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

Low Voltage:According to ANEEL, a class of nominal system voltages equal to or lower than 2.3 kV.

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

Megawatt (MW): One million Watts.

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

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

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

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

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

MVA:Mega Volt Ampère.

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

Parcel A Costs: Costs that are not under the control of the distributor.

Parcel B Costs: Costs that are under control of distributors. Such costs are determined by subtracting all of the Parcel A costs from the distribution company’s revenues, excluding ICMS and PIS and COFINS, a state and federal tax levied on sales. Parcel B costs include, among others, the return on investment in assets necessary to energy distribution activities, as well as maintenance and operational costs.

PFIC: A passive foreign investment company.

PIS: Program of social integration (programa de integração social) tax.

PLD: Spot price used to evaluate the energy traded in the spot market (Preço de Liquidação de Diferenças).

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Potential Conventional Free Consumers: Consumers who meet the relevant contracted demand requirements but have not exercised the option to migrate to the free market as Conventional Free Consumers.

Potential Free Consumer: Consumer that meets all the requirements established for migration to the Free Market, but still chooses to be serviced by the relevant concessionaire.

Potential Special Free Consumers:Consumers who meet the relevant contracted demand requirements but have not exercised the option to migrate to the free market as Special Free Consumers.

Proinfa Program: Electric Energy Alternative Sources Incentive Program (Programa de Incentivo às Fontes Alternativas de Energia Elétrica).

Rationing Program: The Brazilian government program to reduce electricity consumption that was in effect from June 1, 2001 to February 28, 2002 as a result of poor hydrological conditions that threatened the country’s electricity supply.

Regulated Market: Market segment in which distribution companies purchase all the electricity needed to supply customers through public auctions. The auction process is administered by ANEEL, either directly or through CCEE, under certain guidelines provided by the MME. The Regulated Market is generally considered to be more stable in terms of supply of electricity.

Retail Distribution Tariff: Revenue charged by distribution companies to its customers. Each customer falls within a certain tariff level defined by law and based on the customer’s classification, although some flexibility is available according to the nature of each customer’s demand. Retails tariffs are subject to annual readjustments by ANEEL.

RGE: Rio Grande Energia S.A., prior to the merger of Rio Grande Energia S.A. into RGE Sul Distribuidora de Energia S.A. Post-merger, RGE Sul Distribuidora de Energia S.A.

RGE Sul: RGE Sul Distribuidora de Energia S.A., prior to the merger of the merger of Rio Grande Energia S.A. into RGE Sul Distribuidora de Energia S.A.

RGR Fund: Global Reversion Reserve Fund (Fundo da Reserva Global de Reversão – RGR).

RTA: Annual Tariff Adjustment (reajuste tarifário annual).

RTE: Extraordinary Tariff Adjustment (reajuste tarifário extraordinário).

RTP: Periodic Tariff Revision (revisão tarifária periódica).

SAIDI:System Average Interruption Duration Index.

SAIFI:System Average Interruption Frequency Index.

SDE:Economic Law Department of the Ministry of Justice(Secretaria de Direito Econômico).

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

SEC: U.S. Securities and Exchange Commission.

SHPPorSmall Hydroelectric Power Plants: Power projects with capacity from 3 MW to 30 MW.

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SISBACEN:The Brazilian Central Bank’s Information System (Sistema de Informações do Banco Central).

Solar Power Plant: A structure capable of transforming solar energy electric energy.

Special Free Consumers or Special Consumers:Individual or groups of consumers whose contracted energy demand was between 500 kV and 2.0 MW. This limit was lowered by MME Ordinance No. 465/2019. The new limits defined by MME will be 2.0 MW as of January 1, 2020, 1.5 MW as of January 1, 2021, 1 MW as of January 1, 2022 and 0.5 MW as of January 1, 2023. Special Free Consumers may only purchase energy from renewable sources: (i) Small Hydroelectric Power Plants with capacity superior to 3,000 kW and equal or inferior to 30,000 kW; (ii) hydroelectric generators with capacity superior to 3,000 kW and equal or inferior to 50,000 kW, under the independent power production regime; (iii) generators with capacity limited to 3,000 kW; and (iv) alternative energy generators (solar, wind and biomass enterprises) with system capacity not greater than 50,000 kW.

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

TE: Energy Tariff (Tarifa de Energia).

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

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

TJLP: Long-term interest rate (taxa de juros ao longo prazo) published by the Brazilian Central Bank.

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

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

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

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

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

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

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

Watt: The basic unit of electrical power.

177

SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant, CPFL Energia S.A., hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Campinas, in the state of São Paulo, Brazil, on April 24, 2020.

CPFL ENERGIA S.A.

By: /s/ Gustavo Estrella

Name: Gustavo Estrella

Title: Chief Executive Officer

By: /s/ Yuehui Pan

Name: Yuehui Pan

Title: Chief Financial Executive Officer and Investor Relations Officer

178

KPMG Auditores Independentes

Av. Coronel Silva Teles, 977, 10º andar, Conjuntos 111 e 112 - Cambuí

Edifício Dahruj Tower

13024-001 - Campinas/SP - Brasil

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

Telefone +55 (19) 3198-6000

kpmg.com.br

Report of Independent Registered Public Accounting Firm

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

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

We have audited the accompanying consolidated statements of financial position of CPFL Energia S.A. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established inInternal Control – Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 based on criteria established inInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinions

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

KPMG Auditores Independentes, uma sociedade simples brasileira e firma-membro da rede KPMG de firmas-membro independentes e afiliadas à KPMG International Cooperative (“KPMG International”), uma entidade suíça.

KPMG Auditores Independentes, a Brazilian entity and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity.

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

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

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Assessment of the recoverability of the deferred tax assets from the subsidiary CPFL Energias Renováveis S.A.

As discussed in Notes 3.11 and 10 to the consolidated financial statements, the Company recognized deferred tax assets related to tax loss carryforwards and temporary differences from the subsidiary CPFL Energias Renováveis S.A. to the extent that the generation of future income against which the amount of deferred tax assets will be realized is probable. In determining the amount of deferred tax assets, the Company considers the impact of the uncertainties that are inherent to the process of estimating future taxable income, for which the assessment relies on estimates and assumptions and involve a series of judgments about future events supported in its business plan.

We identified the assessment of the recoverability of the deferred tax assets from the subsidiary CPFL Energias Renováveis S.A. as a critical audit matter due to the high degree of judgement required in assessing the assumptions for the determination of the estimates, as well as the interpretation of tax laws that are considered in the forecast of future taxable income. We involved professionals with specialized skill and knowledge to assist in performing procedures and evaluating the audit evidence obtained.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls of the subsidiary over the deferred tax assets recoverability assessment process. This included controls related to the preparation and review of the business plan, budget, technical studies, analyses as to the probability of existence of future taxable income, and interpretation and application of tax laws. We compared the budget approved for the previous year with the actual results incurred in order to confirm the reliability of the projections of future results. We also assessed whether the projections indicated sufficient future taxable profits against which the tax loss carry-forward and deductible temporary differences could be used. We involved corporate finance professionals with specialized skills and knowledge, who assisted in analyzing the consistency of the data and assumptions used for the forecasting of future taxable income, particularly those related to the forecasted economic growth, volume of energy, and price of sales of energy. This was accomplished by comparing the forecasted economic growth and price of sales of energy with data obtained from external sources. We also involved tax professionals with specialized skills and knowledge, who assisted us in evaluating the application of tax laws and tax deductions in calculating the deferred tax assets.

We have served as the Company’s auditor since 2017

/s/ KPMG Auditores Independentes

Campinas, São Paulo - Brazil
April 24, 2020

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AT DECEMBER 31, 2019 AND 2018

(In thousands of Brazilian reais - R$)

ASSETS	Note	Dec 31, 2019	Dec 31, 2018

CURRENT ASSETS
Cash and cash equivalents	5	1,937,163	1,891,457
Securities	6	851,004	-
Consumers, concessionaires and licensees	7	4,985,578	4,547,951
Dividend and interest on capital	13	100,297	100,182
Income tax and social contribution recoverable	8	87,698	123,739
Other taxes recoverable	8	331,428	287,517
Derivatives	35	281,326	309,484
Sector financial asset	9	1,093,588	1,330,981
Contract assets	16	24,387	-
Other receivables	12	648,161	811,005
TOTAL CURRENT ASSETS		10,340,630	9,402,316

NONCURRENT ASSETS
Consumers, concessionaires and licensees	7	713,068	752,795
Escrow Deposits	23	757,370	854,374
Income tax and social contribution recoverable	8	101,528	67,966
Other taxes recoverable	8	370,595	185,725
Sector financial assets	9	2,748	223,880
Derivatives	35	369,767	347,507
Deferred tax assets	10	1,064,716	956,380
Concession financial asset	11	8,779,717	7,430,149
Investments at cost		116,654	116,654
Other receivables	12	736,019	927,440
Investments by equity	13	997,997	980,362
Property, Plant and Equipment	14	9,083,710	9,456,614
Contract asset	16	1,322,822	1,046,433
Intangible assets	15	9,320,953	9,462,935
TOTAL NONCURRENT ASSETS		33,737,664	32,809,214

TOTAL ASSETS		44,078,293	42,211,530

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

F - 1

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AT DECEMBER 31, 2019 AND 2018

(In thousands of Brazilian reais - R$)

LIABILITIES AND EQUITY	Note	Dec 31, 2019	Dec 31, 2018

CURRENT LIABILITIES
Trade payables	17	3,260,180	2,398,085
Borrowings	18	2,776,193	2,446,113
Debentures	19	682,582	917,352
Private pension plan	20	224,851	86,623
Regulatory charges	21	232,251	150,656
Income tax and social contribution payable	22	218,961	100,450
Other taxes, fees and contributions	22	741,536	664,989
Dividends		668,859	532,608
Estimated payroll		125,057	119,252
Derivatives	35	29,400	8,139
Use of public asset		11,771	11,570
Other payables	24	1,094,269	979,296
TOTAL CURRENT LIABILITIES		10,065,908	8,415,132

NONCURRENT LIABILITIES
Trade payables	17	359,944	333,036
Borrowings	18	7,587,102	8,989,846
Debentures	19	7,863,696	8,023,493
Private pension plan	20	2,153,327	1,156,639
Income taxes and social contribution payable	22	156,198	-
Other taxes, fees and contributions	22	805	9,691
Deferred tax liabilities	10	1,048,069	1,136,227
Provision for tax, civil and labor risks	23	600,775	979,360
Derivatives	35	6,157	23,659
Sector financial liability	9	102,561	46,703
Use of public asset		91,181	89,965
Other payables	24	759,331	475,396
TOTAL NONCURRENT LIABILITIES		20,729,147	21,264,015

EQUITY	25
Issued capital		9,388,081	5,741,284
Capital deficit		(1,640,962)	469,257
Legal reserve		1,036,125	900,992
Statutory reserve - working capital reinforcement		4,046,305	3,527,510
Additional dividend proposed		1,433,295	-
Accumulated comprehensive income		(1,268,465)	(376,294)
		12,994,381	10,262,749
Equity attributable to noncontrolling interests		288,857	2,269,634
TOTAL EQUITY		13,283,238	12,532,383

TOTAL LIABILITIES AND EQUITY		44,078,293	42,211,530

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

F - 2

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017

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

	Note	2019	2018	2017

Net operating revenue	27	29,932,474	28,136,627	26,744,905
Cost of electric energy services
Cost of electric energy	28	(18,370,994)	(17,838,165)	(16,901,518)

Cost of operation		(2,894,165)	(2,733,754)	(2,771,145)
Depreciation and amortization		(1,278,272)	(1,237,627)	(1,143,795)
Other operating costs	29	(1,615,893)	(1,496,127)	(1,627,350)

Cost of services rendered to third parties	29	(2,089,732)	(1,775,339)	(2,074,611)

Gross profit		6,577,583	5,789,369	4,997,632
Operating expenses
Sales expenses		(699,910)	(608,184)	(590,232)
Depreciation and amortization		(5,211)	(4,260)	(5,403)
Allowance for doubtful accounts		(233,424)	(169,259)	(155,097)
Other sales expenses	29	(461,275)	(434,665)	(429,732)
General and administrative expenses		(1,027,230)	(987,291)	(947,072)
Depreciation and amortization		(109,132)	(65,319)	(93,639)
Other general and administrative expenses	29	(918,098)	(921,972)	(853,433)
Other operating expenses		(486,993)	(485,427)	(438,494)
Amortization of concession intangible assets		(288,438)	(286,858)	(286,215)
Other operating expenses	29	(198,555)	(198,569)	(152,279)

Income from electric energy services		4,363,450	3,708,467	3,021,834

Equity interests in associates and joint ventures	13	349,090	334,198	312,390

Profit before finance results		4,712,540	4,042,664	3,334,224

Finance income (expenses)	30
Finance income		903,575	762,413	880,314
Finance expenses		(1,629,822)	(1,865,100)	(2,367,868)
		(726,247)	(1,102,687)	(1,487,554)

Profit before taxes		3,986,293	2,939,977	1,846,670

Social contribution	10	(336,610)	(213,673)	(168,728)
Income tax	10	(901,386)	(560,310)	(434,901)
		(1,237,996)	(773,982)	(603,629)

Profit for the year		2,748,297	2,165,995	1,243,042

Profit attributable to the owners of the Company		2,702,671	2,058,040	1,179,750
Profit attributable to noncontrolling interests		45,626	107,955	63,292

Basic earnings per share attributable to owners of the Company (R$):	26	2.48	2.02	1.16
Diluted earnings per share attributable to owners of the Company (R$):	26	2.47	2.01	1.16

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

F - 3

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017

(In thousands of Brazilian reais - R$)

	2019	2018	2017

Profit for the year	2,748,297	2,165,995	1,243,042

Other comprehensive income
Items that will not be reclassified subsequently to profit and loss
- Actuarial gains (losses), net of tax effects	(865,402)	(238,780)	96,000
- Credit risk in Fair value adjustment of financial liabilities	(1,097)	17,963	-

Total Comprehensive income for the year	1,881,799	1,945,178	1,339,042

Attributable to owners of the Company	1,836,173	1,837,223	1,275,750
Attributable to noncontrolling interests	45,626	107,955	63,292

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

F - 4

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017

(In thousands of Brazilian reais - R$)


			Earning reserves				Accumulated comprehensive income				Noncontrolling interests
				Statutory reserves
	Issued capital	Capital reserves (deficit)	Legal reserve	Concession financial asset	Working capital reinforcement	Dividends	Deemed cost	Private pension plan / Credit risk in Fair value adjustment	Retained earnings	Total	Accumulated comprehensive income	Other equity component	Total equity
Balance at December 31, 2016	5,741,284	468,014	739,102	702,928	545,505	7,820	431,713	(666,346)	-	7,970,021	13,572	2,389,076	10,372,668

Total comprehensive income
Profit for the year	-	-	-	-	-	-	-	-	1,179,750	1,179,750	-	63,292	1,243,042
Other comprehensive income - actuarial gains	-	-	-	-	-	-	-	96,000	-	96,000	-	-	96,000

Internal changes of shareholders'equity
Realization of deemed cost of property, plant and equipment	-	-	-	-	-	-	(39,202)	-	39,202	-	(2,634)	2,634	-
Tax on realization of deemed cost	-	-	-	-	-	-	13,329	-	(13,329)	-	896	(896)	-
Recognition of legal reserve	-	-	58,988	-	-	-	-	-	(58,988)	-	-	-	-
Changes in statutory reserve in the year	-	-	-	123,673	746,541	-	-	-	(870,213)	-	-	-	-
Other changes in noncontrolling interests	-	-	-	-	-	-	-	-	-	-	-	(113)	(113)

Capital transactions with owners
Capital increase (reduction)	-	-	-	-	-	-	-	-	-	-	-	(122,791)	(122,791)
Time-barred dividends	-	-	-	-	-	-	-	-	3,768	3,768	-	-	3,768
Interim dividends	-	-	-	-	-	-	-	-	-	-	-	(7,226)	(7,226)
Additional dividend proposed	-	-	-	-	-	-	-	-	-	-	-	-	-
Dividend proposal approved	-	-	-	-	-	(7,820)	-	-	(280,191)	(288,011)	-	(110,994)	(399,005)
Capital increase in subsidiaries with no change in control	-	-	-	-	-	-	-	-	-	-	-	-	-

Balance at December 31, 2017	5,741,284	468,014	798,090	826,600	1,292,046	-	405,840	(570,346)	-	8,961,528	11,833	2,212,983	11,186,344

Total comprehensive income	-	-	-	-	-	-	-	(186,671)	1,975,433	1,788,762	-	107,955	1,896,717
Profit for the year	-	-	-	-	-	-	-	-	2,058,040	2,058,040	-	107,955	2,165,995
Other comprehensive income - credit risk in Fair value adjustment of financial liabilities	-	-	-	-	-	-	-	52,109	(34,146)	17,963	-	-	17,963
Effects of first adoption of IFRS 9	-	-	-	-	-	-	-	-	(48,461)	(48,461)	-	-	(48,461)
Other comprehensive income - actuarial gains	-	-	-	-	-	-	-	(238,780)	-	(238,780)	-	-	(238,780)

Internal changes of shareholders'equity	-	5	102,902	(826,600)	2,235,465	-	(25,118)	-	(1,486,648)	5	(1,777)	1,664	(108)
Realization of deemed cost of property, plant and equipment	-	-	-	-	-	-	(38,057)	-	38,057	-	(2,693)	2,693	-
Tax on realization of deemed cost	-	-	-	-	-	-	12,939	-	(12,939)	-	916	(916)	-
Recognition of legal reserve	-	-	102,902	-	-	-	-	-	(102,902)	-	-	-	-
Changes in statutory reserve in the year	-	-	-	(826,600)	2,235,465	-	-	-	(1,408,864)	-	-	-	-
Other changes in noncontrolling interests	-	5	-	-	-	-	-	-	-	5	-	(113)	(108)

Capital transactions with owners	-	1,238	-	-	-	-	-	-	(488,785)	(487,547)	-	(63,024)	(550,571)
Interim dividends	-	-	-	-	-	-	-	-	-	-	-	(4,452)	(4,452)
Dividend proposal approved	-	-	-	-	-	-	-	-	(488,785)	(488,785)	-	(64,233)	(553,018)
Other changes	-	1,238	-	-	-	-	-	-	-	1,238	-	5,661	6,899

Balance at December 31, 2018	5,741,284	469,257	900,992	-	3,527,510	-	380,721	(757,016)	-	10,262,749	10,055	2,259,578	12,532,383

Total comprehensive income	-	-	-	-	-	-	-	(866,499)	2,702,671	1,836,172	-	45,626	1,881,798
Profit for the year	-	-	-	-	-	-	-	-	2,702,671	2,702,671	-	45,626	2,748,297
Other comprehensive income - credit risk in Fair value adjustment of financial liabilities	-	-	-	-	-	-	-	(1,097)	-	(1,097)	-	-	(1,097)
Other comprehensive income - actuarial gains	-	-	-	-	-	-	-	(865,402)	-	(865,402)	-	-	(865,402)

Internal changes of shareholders'equity	-	-	135,134	-	518,795	-	(25,672)	-	(628,257)	-	(1,777)	1,697	(80)
Realization of deemed cost of property, plant and equipment	-	-	-	-	-	-	(38,897)	-	38,897	-	(2,693)	2,693	-
Tax on realization of deemed cost	-	-	-	-	-	-	13,225	-	(13,225)	-	916	(916)	-
Recognition of legal reserve	-	-	135,134	-	-	-	-	-	(135,134)	-	-	-	-
Changes in statutory reserve in the year	-	-	-	-	518,795	-	-	-	(518,795)	-	-	-	-
Other changes in noncontrolling interests	-	-	-	-	-	-	-	-	-	-	-	(80)	(80)

Capital transactions with owners	3,646,797	(2,110,218)	-	-	-	1,433,295	-	-	(2,074,414)	895,459	-	(2,026,323)	(1,130,864)
Capital increase (reduction)	3,694,342	-	-	-	-	-	-	-	-	3,694,342	-	122	3,694,464
Cost of issuing shares	(47,544)	-	-	-	-	-	-	-	-	(47,544)	-	-	(47,544)
Capital increase (reduction) in subsidiaries with no change in control of CPFL Geração	-	(75,298)	-	-	-	-	-	-	-	(75,298)	-	75,298	-
Acquisition of non-controlling interests of CPFL Renováveis (note 1.c)	-	(2,034,920)	-	-	-	-	-	-	-	(2,034,920)	-	(2,072,635)	(4,107,555)
Additional dividend proposed	-	-	-	-	-	1,433,295	-	-	(1,433,295)	-	-	-	-
Time-barred dividends	-	-	-	-	-	-	-	-	765	765	-	-	765
Dividend proposal approved	-	-	-	-	-	-	-	-	(641,884)	(641,884)	-	(29,109)	(670,993)

Balance at December 31, 2019	9,388,081	(1,640,962)	1,036,125	-	4,046,305	1,433,295	355,049	(1,623,514)	-	12,994,381	8,278	280,578	13,283,238

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

F - 5

CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017

(In thousands of Brazilian reais – R$)

	2019	2018	2017
OPERATING CASH FLOW
Profit before taxes	3,986,293	2,939,977	1,846,670

ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIES
Depreciation and amortization	1,681,053	1,594,064	1,529,052
Provision for tax, civil and labor risks	204,795	153,977	176,609
Allowance for doubtful accounts	233,424	169,259	155,097
Interest on debts, inflation adjustment and exchange rate changes	919,836	1,117,742	1,863,311
Pension plan expense	112,603	89,909	113,898
Equity interests in associates and joint ventures	(349,090)	(334,198)	(312,390)
Impairment	-	-	20,437
Loss on disposal of noncurrent assets	189,566	216,275	132,195
Others	(121)	(27,052)	(18,111)
	6,978,359	5,919,953	5,506,768

DECREASE (INCREASE) IN OPERATING ASSETS
Consumers, concessionaires and licensees	(631,078)	(1,006,291)	(722,406)
Dividends and interest on capital received	331,754	311,347	730,178
Taxes recoverable	(174,263)	92,090	68,184
Escrow deposits	130,725	22,926	(248,128)
Sectorial financial asset	628,157	(846,216)	(425,004)
Receivables - amounts from the Energy Development Account - CDE / CCEE	36,240	59,196	(29,354)
Concession financial assets (transmission companies)	-	-	(56,665)
Other operating assets	(70,790)	(47,835)	91,607

INCREASE (DECREASE) IN OPERATING LIABILITIES
Trade payables	889,002	(848,880)	565,945
Other taxes and social contributions	10,344	(59,102)	(261,194)
Other liabilities with private pension plan	(144,494)	(107,668)	(79,724)
Regulatory charges	81,595	(430,944)	215,522
Tax, civil and labor risks paid	(484,153)	(215,873)	(206,788)
Sectorial financial liability	(25,696)	(64,361)	(1,089,592)
Payables - amounts provided by the CDE	(20,187)	71,779	17,544
Other operating liabilities	349,303	176,308	141,759
CASH FLOWS PROVIDED BY OPERATIONS	7,884,817	3,026,428	4,218,652
Interest paid on debts and debentures	(1,132,479)	(1,353,339)	(1,846,453)
Income tax and social contribution paid	(963,806)	(816,402)	(338,175)
NET CASH FROM OPERATING ACTIVITIES	5,788,530	856,686	2,034,024

INVESTING ACTIVITIES
Capital reduction (increase) in investees	-	(1,096)	91,599
Purchases of property, plant and equipment	(188,994)	(275,986)	(685,856)
Purchases of contract asset – in progress	(2,054,306)	(1,769,573)	-
Purchases of intangible assets	(19,147)	(16,864)	(1,884,577)
Securities, pledges and restricted deposits	(1,184,804)	(554,669)	(93,933)
Securities, pledges and restricted deposits - withdraw	378,560	767,500	-
Sale of noncurrent assets	-	-	26,807
Intragroup loans	-	-	36,639
NET CASH USED IN INVESTING ACTIVITIES	(3,068,691)	(1,850,688)	(2,509,321)

FINANCING ACTIVITIES
Capital increase by noncontrolling interests	3,622,305	7,994	(122,791)
Capital reduction (increase) in investees	(4,107,555)	-	-
Borrowings and debentures raised	5,256,705	9,610,814	3,398,084
Repayment of principal of borrowings and debentures	(7,136,612)	(10,204,257)	(5,273,261)
Repayment of derivatives	219,257	543,427	(102,641)
Dividends and interest on capital paid	(534,061)	(322,163)	(336,934)
Advance for future capital increase	12	-	-
Repayment of principal of intercompany loans	5,813	-	-
Repayment for business combinations	-	-	(2,514)
NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES	(2,674,135)	(364,185)	(2,440,057)
NET INCREASE IN CASH AND CASH EQUIVALENTS	45,704	(1,358,187)	(2,915,354)
CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR	1,891,457	3,249,642	6,164,997
CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR	1,937,163	1,891,457	3,249,642

The accompanying notes are an integral part of these financial statements

F - 6

CPFL ENERGIA S.A.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017

(Amounts in thousands of Brazilian reais – R$, unless otherwise stated)

( 1 ) OPERATIONS

CPFL Energia S.A. (“CPFL Energia” or “Company”) is a publicly-held corporation incorporated for the principal purpose of operating as a holding company, with equity interests in other companies primarily engaged in electric energy distribution, generation and commercialization activities in Brazil.

The Company’s registered office is located at Rua Jorge Figueiredo Corrêa, nº 1,632, Jardim Professora Tarcília, CEP 13087-397 - Campinas - SP - Brazil.

The Company has direct and indirect interests in the following subsidiaries and joint ventures:

Energy distribution

Company type

Equity interest

Location (state)

Number of municipalities

Approximate number of consumers (in thousands)

Concession period

End of the concession

Companhia Paulista de Força e Luz ("CPFL Paulista")

Publicly-held corporation

Direct
100%

Interior of
São Paulo

234

4,581

30 years

November 2027

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

Publicly-held corporation

Direct
100%

Interior and coast of São Paulo

1,789

30 years

October 2028

RGE Sul Distribuidora de Energia S.A. ("RGE") (f)

Publicly-held corporation

Direct and Indirect
100%

Interior of
Rio Grande do Sul

381

2,922

30 years

November 2027

Companhia Jaguari de Energia ("CPFL Santa Cruz")

Privately-held corporation

Direct
100%

Interior of São Paulo, Paraná and Minas Gerais

466

30 years

July 2045

Installed power (MW)

Energy generation
(conventional and renewable sources)

Company type

Equity interest

Location (state)

Number of plants / type of energy

Total

CPFL share

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

Publicly-held corporation

Direct 100%

São Paulo and Goiás

3 Hydropower plants (a)

1,295

678

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

Privately-held corporation

Indirect 65%

Rio Grande do Sul

3 Hydropower plants

360

234

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

Privately-held corporation

Indirect 51% (d)

Santa Catarina and
Rio Grande do Sul

1 Hydropower plant

855

436

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

Privately-held corporation

Indirect 48.72%

Santa Catarina

1 Hydropower plant

880

429

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

Privately-held corporation

Indirect 25.01%

Santa Catarina and
Rio Grande do Sul

1 Hydropower plant

690

173

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

Privately-held corporation

Indirect 53.34%

Paraíba

2 Thermal plants

342

182

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

Privately-held corporation

Indirect 59.93% (b)

Tocantins

1 Hydropower plant

903

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

Publicly-held corporation

Direct and Indirect 99.94%

(c)

CPFL Centrais Geradoras Ltda ("CPFL Centrais Geradoras")

Limited liability company

Direct 100%

São Paulo and Minas Gerais

6 small hydropower plants

CPFL Transmissão de Energia Piracicaba Ltda. ("CPFL Piracicaba")

Limited liability company (h)

Indirect 100%

São Paulo

n/a

CPFL Transmissão de Energia Morro Agudo Ltda. ("CPFL Morro Agudo")

Limited liability company (h)

Indirect 100%

São Paulo

n/a

CPFL Transmissão de Energia Maracanaú Ltda. ("CPFL Maracanaú") (e)

Limited liability company (h)

Indirect 100%

Ceará

n/a

CPFL Transmissão de Energia Sul I Ltda. ("CPFL Sul I") (e)

Limited liability company (h)

Indirect 100%

Santa Catarina

n/a

��

n/a

CPFL Transmissão de Energia Sul II Ltda. ("CPFL Sul II") (e)

Limited liability company (h)

Indirect 100%

Rio Grande do Sul

n/a

F - 7

Energy commercialization	Company type	Core activity	Equity interest

CPFL Comercialização Brasil S.A. ("CPFL Brasil")	Privately-held corporation	Energy commercialization	Direct 100%
Clion Assessoria e Comercialização de Energia Elétrica Ltda. ("CPFL Meridional")	Limited liability company	Commercialization and provision of energy services	Indirect 100%
CPFL Comercialização de Energia Cone Sul Ltda. ("CPFL Cone Sul")	Limited liability company (h)	Energy commercialization and participation in the capital of other companies	Indirect 100%
CPFL Planalto Ltda. ("CPFL Planalto")	Limited liability company	Energy commercialization	Direct 100%
CPFL Brasil Varejista de Energia S.A. ("CPFL Brasil Varejista")	Limited liability company (h)	Energy commercialization	Indirect 100%

Provision of services	Company type	Core activity	Equity interest

CPFL Serviços, Equipamentos, Industria e Comércio S.A. ("CPFL Serviços")	Privately-held corporation	Manufacturing, commercialization, rental and maintenance of electro-mechanical equipment and service provision	Direct 100%
Nect Serviços Administrativos de Infraestrutura Ltda. ("CPFL Infra") (g)	Limited liability company	Provision of infrasctructure services	Direct 100%
Nect Serviços Administrativos de Recursos Humanos Ltda. ("CPFL Pessoas") (g)	Limited liability company	Provision of human resources services	Direct 100%
Nect Serviços Administrativos Financeiros Ltda. ("CPFL Finanças") (g)	Limited liability company	Provision of finance services	Direct 100%
Nect Serviços Adm de Suprimentos Ltda. ("CPFL Supre") (g)	Limited liability company	Provision of supply and logistics services	Direct 100%
CPFL Atende Centro de Contatos e Atendimento Ltda. ("CPFL Atende")	Limited liability company	Provision of call center services	Direct 100%
CPFL Total Serviços Administrativos Ltda. ("CPFL Total")	Limited liability company	Collection services	Direct 100%
CPFL Eficiência Energética S.A ("CPFL Eficiência")	Limited liability company (h)	Energy efficiency management	Direct 100%
TI Nect Serviços de Informática Ltda. ("Authi")	Limited liability company	Provision of IT services	Direct 100%
CPFL Geração Distribuída de Energia Ltda. ("CPFL GD")	Limited liability company (h)	Provision of maintenance services for energy generation companies	Indirect 100%

Others	Company type	Core activity	Equity interest

CPFL Jaguari de Geração de Energia Ltda ("Jaguari Geração")	Limited liability company	Holding company	Direct 100%
Chapecoense Geração S.A. ("Chapecoense")	Privately-held corporation	Holding company	Indirect 51%
Sul Geradora Participações S.A. ("Sul Geradora")	Privately-held corporation	Holding company	Indirect 99.95%
CPFL Telecom S.A ("CPFL Telecom")	Limited liability company (h)	Telecommunication services	Direct 100%

a)	CPFL Geração has 51.54% of assured energy and power of the Serra da Mesa hydropower plant, whose concession is controlled by Furnas.
b)	Paulista Lajeado has a 7% share in the installed power of Investco S.A. (5.94% interest in total capital).
c)	CPFL Renováveis has operations in the states of São Paulo, Minas Gerais, Mato Grosso, Santa Catarina, Ceará, Rio Grande do Norte, Paraná and Rio Grande do Sul and its main activities are: (i) holding investments in companies of the renewable energy segment; (ii) identification, development, and exploration of generation potentials; and (iii) sale of electric energy. At December 31, 2019, CPFL Renováveis had a portfolio of 107 projects with installed capacity of 2,446.3 MW (2,132.7 MW in operation), as follows:
		Hydropower generation: 41 SHP’s (481.1 MW) with 40 SHPs (small hydroelectric power plants) in operation (453.1 MW) and 1 SHPs under development (28 MW);
		Wind power generation: 57 projects (1,594.1 MW) with 45 projects in operation (1,308.5 MW) and 12 projects under construction/development (285.6 MW);
		Biomass power generation: 8 plants in operation (370 MW);
		Solar power generation: 1 solar plant in operation (1.1 MW).
d)	The joint venture Chapecoense has as its direct subsidiary Foz do Chapecó and fully consolidates its financial statements.
e)	Created in March 2019, whose objective is the exploration of electric power transmission concessions, including the construction, operation and maintenance of basic network transmission facilities.

F - 8

f)	As described in note 13.5 of the December 2018 Financial Statements, the merger of RGE with RGE Sul was approved by ANEEL. Since January 1, 2019, the operations of these subsidiaries have been carried out only by RGE Sul, which adopted the trade name “RGE”.
g)	On September 30, 2019, the partial spin-off of Nect Serviços Administrativos de Infraestrutura Ltda. - “CPFL Infra” (formerly Nect Serviços Administrativos Ltda.) into four specific business segments (Supplies, Human Resources, Financial Services and Infrastructure) was approved, together with the merger of the spun-off portion into the three new companies; namely, CPFL Supre, CPFL Finanças and CPFL Pessoas. The purpose of the transaction is to optimize the operating and administrative structure of the companies. The net assets in this transaction were appraised at R$16,746 and did not have any effect on the consolidated financial statements of the group or result in any change in the equity interest of the companies.
h)	Subsidiaries that were transformed from corporations to limited liability companies, as decided in shareholders meetings held in January 2020.

Acquisition of interests in the subsidiary CPFL Renováveis

On September 30, 2019, the Company entered into a share purchase and sale agreement with its parent company State Grid Brazil Power Participações S.A. (“State Grid”) thereby purchasing 243,771,824 shares of subsidiary CPFL Renováveis, thus increasing its total (direct and indirect) equity interest from 51.60% to 99.94% in CPFL Renováveis. The amount paid in cash was R$ 16.85 per share, totaling R$ 4,107,555. The related effects were a decrease of R$ 2,072,635 in the shareholders equity attributable to noncontrolling interests and a decrease of R$ 2,034,920 in the capital reserve account.

Delisting on New York Stock Exchange

On December 18, 2019, the Company's Board of Directors Meeting approved the Company’s intention to: (i) terminate the Second Amended and Restated Deposit Agreement (“Deposit Agreement”) with Citibank N.A. (“Citibank”) with respect to its American Depositary Receipts (“ADRs”); (ii) delist its American Depositary Shares (“ADSs”) from the New York Stock Exchange (“NYSE”); and (iii) once the Company complies with the applicable requirements, cancel its registration with the U.S. Securities and Exchange Commission (“SEC”). The Company believes that the economic rationale for maintaining a listing on the NYSE has decreased partly due to: (i) increases in the volume of Brazilian shares traded on B3 S.A. – Bolsa, Brasil, Balcão (“B3”) in Brazil by foreign investors due to the internationalization of the Brazilian financial and capital markets, as well as the narrowing of the differences between the Brazilian and the US international financial reporting standards; and (ii) a downward trend in recent years in the trading volume of the Company's ADSs on the NYSE.

On February 10, 2020, the Company, through a Notice to the Market, informed that the delisting of its NYSE ADSs, mentioned in item (ii) above, will be effective as of this date.

( 2 ) PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1 Basis of presentation

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

Management states that all information material to the financial statements is being disclosed and corresponds to what is used in managing the Group.

The consolidated financial statements were approved by Management and authorized for issue on April 24, 2020.

2.2 Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis except for the following items recorded in the statements of financial position: (i) derivative financial instruments measured at fair value and (ii) non derivative financial instruments measured at fair value through profit or loss. The classification of the fair value measurement in the level 1, 2 or 3 categories (depending on the degree of observance of the inputs used) is presented in note 35 – Financial Instruments.

F - 9

2.3 Use of estimates and judgments

The preparation of consolidated financial statements requires the Group’s management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses.

By definition, the accounting estimates are rarely the same as the actual results. Accordingly, the Group’s management reviews the estimates and assumptions on an ongoing basis, based on previous experience and other relevant factors. Adjustments resulting from revisions to accounting estimates are recognized in the period in which the estimates are revised and applied on a prospective basis.

The main accounts that require the adoption of estimates and assumptions, which are subject to a greater degree of uncertainty and may result in a material adjustment if these estimates and assumptions suffer significant changes in subsequent periods, are:

·	Note 7 – Consumers, Concessionaires and Licensees (Allowance for doubtful accounts: key assumptions regarding the expected credit losses – ECL and assumptions for measurement of unbilled supply and Distribution System Usage Tariff - TUSD);


·	Note 9 – Sector financial asset and liability (Regulatory discretion and judgement over certain items);
·	Note 10 – Deferred tax assets and liabilities (recognition of assets: availability of future taxable profit against which the tax losses can be utilized);

·	Note 11 – Concession financial asset (assumptions for fair value measurement, based on significant unobservable inputs, see note 34);

·	Note 12 – Other assets (allowance for doubtful accounts, key assumptions regarding the expected credit losses - ECL);

·	Note 14 – Property, plant and equipment (application of definite useful lives and key assumptions regarding recoverable amounts);

·	Note 15 – Intangible assets (key assumptions regarding recoverable amounts);
·	Note 16 – Contract Assets (key assumptions regarding recoverable amounts);
·	Note 20 – Private pension plan (key actuarial assumptions used in the measurement of defined benefit obligations); and

·	Note 23 – Provision for tax, civil and labor risks and escrow deposits (recognition and measurement: key assumptions on the probability and magnitude of outflow of resources).

2.4 Functional currency and presentation currency

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

2.5 Segment information

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

F - 10

The Group´s Management use reports to make strategic decisions, segmenting the business into: (i) electric energy distribution activities (“Distribution”); (ii) electric energy generation and transmission from conventional sources activities (“Generation”); (iii) electric energy generation activities from renewable sources (“Renewables”); (iv) energy commercialization activities (“Commercialization”); (v) service activities (“Services”); and (vi) other activities not listed in the previous items.

Beginning in 2018, due to the way our new Management monitors segment results, (i) intangible assets acquired in business combination transactions that are recorded in the parent company that were previously allocated to the respective segments are now allocated to the segment “Others”; and (ii) eliminations between different segments are now classified in the “elimination” column instead of being presented in each segment. For comparison purposes, the segment information disclosed for 2017 has been restated using the same criteria.

2.6 Information on equity interests

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

At December 31, 2019 and 2018, the noncontrolling interests recognized in the financial statements refer to the interests held by third parties in subsidiaries CERAN, Paulista Lajeado and CPFL Renováveis.

2.7 New presentation of financial statements of 2018 and 2017 – reclassification for presentation purposes

Starting in 2019, focusing on improving the presentation of the financial statements for the monitoring of results by Group Management, through a better analysis of costs and expenses accounts, the Company split the depreciation, amortization lines into two captions in the income statement.

For comparability purposes, these changes were applied retrospectively according to IAS 8, and therefore, the financial statements regarding 2018 and 2017 are being reclassified for presentation purposes. There are no changes in costs and expenses assumptions.

The following table summarizes the impacts on financial statements:

F - 11

	2018			2017
	Originally disclosed	Reclassification for presentation purposes	New presentation	Originally disclosed	Reclassification for presentation purposes	New presentation
Net operating revenue	28,136,627	-	28,136,627	26,744,905	-	26,744,905
Cost of electric energy services
Cost of electric energy	(17,838,165)	-	(17,838,165)	(16,901,518)	-	(16,901,518)
Cost of operation	(2,733,754)	-	(2,733,754)	(2,771,145)	-	(2,771,145)
Depreciation and amortization	-	(1,237,627)	(1,237,627)	-	(1,143,795)	(1,143,795)
Other operating costs	-	(1,496,127)	(1,496,127)	-	(1,627,350)	(1,627,350)
Cost of services rendered to third parties	(1,775,339)	-	(1,775,339)	(2,074,611)		(2,074,611)

Gross profit	5,789,369	-	5,789,369	4,997,631	-	4,997,631
Operating expenses
Sales expenses	(608,184)	-	(608,184)	(590,232)	-	(590,232)
Depreciation and amortization	-	(4,260)	(4,260)	-	(5,403)	(5,403)
Allowance for doubtful accounts	(169,259)	-	(169,259)	(155,097)	-	(155,097)
Other sales expenses	(438,925)	4,260	(434,665)	(435,135)	5,403	(429,732)
General and administrative expenses	(987,291)	-	(987,291)	(947,072)	-	(947,072)
Depreciation and amortization	-	(65,319)	(65,319)	-	(93,639)	(93,639)
Other general and administrative expenses	-	(921,972)	(921,972)	-	(853,433)	(853,433)
Other operating expenses	(485,427)	-	(485,427)	(438,494)	-	(438,494)
Amortization of concession intangible assets	-	(286,858)	(286,858)	-	(286,215)	(286,215)
Other operating expenses	-	(198,569)	(198,569)	-	(152,279)	(152,279)

Income from electric energy services	3,708,467	-	3,708,467	3,021,833	-	3,021,833

Equity interests in subsidiaries, associates and joint ventures	334,198	-	334,198	312,390	-	312,390

Finance income (expenses)
Finance income	762,413	-	762,413	880,314	-	880,314
Finance expenses	(1,865,100)	-	(1,865,100)	(2,367,868)	-	(2,367,868)
��	(1,102,687)	-	(1,102,687)	(1,487,554)	-	(1,487,554)

Profit before taxes	2,939,977	-	2,939,977	1,846,669	-	1,846,669

Social contribution	(213,673)	-	(213,673)	(168,728)	-	(168,728)
Income tax	(560,310)	-	(560,310)	(434,901)	-	(434,901)
	(773,982)	-	(773,982)	(603,629)		(603,629)

Profit for the year	2,165,995		2,165,995	1,243,040		1,243,040

Profit attributable to the owners of the Company	2,058,040		2,058,040	1,179,750		1,179,750
Profit attributable to noncontrolling interests	107,955		107,955	63,292		63,292
Basic earnings per share attributable to owners of the Company (R$):	2.02		2.02	1.16		1.16
Diluted earnings per share attributable to owners of the Company (R$):	2.01		2.01	1.16		1.16

( 3 )SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used in preparing the Group’s financial statements are set out below. These policies have been consistently applied to all reporting periods, except for the new accounting standards and interpretations adopted by the Group on January 1, 2019 described in note 3.17.

3.1 Cash and cash equivalents

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

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

The purpose of determining the components of the company's cash and cash equivalents is to maintain sufficient cash to ensure the continuity of investments and the fulfillment of short- and long-term obligations, maintaining the return on its capital structure at appropriate levels aimed at business continuity and increased value for shareholders and investors.

F - 12

3.2 Concession agreements

Distribution companies

The IFRIC 12 – Service Concession Arrangements establish general guidelines for the recognition and measurement of obligations and rights related to concession agreements and apply to situations in which the granting authority controls or regulates which services the concessionaire should provide with the infrastructure, to whom the services should be provided and at what price, and controls any significant residual interest in the infrastructure at the end of the concession period.

When these criteria are met, the infrastructure of distribution concessionaires is segregated as contract assets at the time of construction, up to the completion of construction, in accordance with the IFRS requirements, so that, when operational, the following are reclassified in the financial statements from contract assets to (i) intangible asset corresponding to the right to operate the concession and collect from the users of public utilities, and (ii) financial asset corresponding to the unconditional contractual right to receive cash (indemnity) by transferring control of the assets at the end of the concession.

The concession financial asset of distribution companies is measured based on its fair value, determined in accordance with the remuneration base for the concession assets, pursuant to the legislation in force established by the Brazilian Electricity Regulatory Agency (Agência Nacional de Energia Elétrica - ANEEL), and takes into consideration changes in the fair value, mainly based on factors such as new replacement value, and adjustment for Extended Comprehensive Consumer Price Index (“IPCA”) for the distribution subsidiaries. The financial asset of distribution companies is classified as fair value through profit or loss, with the corresponding fair value changes entry in the Net Operating Revenue in the statement of profit or loss for the year (notes 4 and 25).

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

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

Transmission companies:

The Group’s transmission companies are responsible for constructing and operating the transmission infrastructure in order to carry the energy from the generation centers to the distribution points, according to their concession arrangements.

The energy transmission company has the obligation to maintain its transmission infrastructure available to its users to guarantee the receipt of the Permitted Annual Revenue (RAP) during the concession agreement term. Potential unamortized investments generate the right to indemnity at the end of the concession arrangement.

The transmission infrastructure is classified as a contract asset. The right to consideration for goods and services is subject to the satisfaction of performance obligations and not only to the passage of time.

3.3 Financial instruments

Policy applicable from January 1, 2018

- Financial assets

Financial assets are recognized initially on the date that they are originated or on the trade date at which the Company or its subsidiaries become parties to the contractual provisions of the instrument. Derecognition of a financial asset occurs when the contractual rights to the cash flows from the asset expire or when the risks and rewards of ownership of the financial asset are transferred.

Subsequent measurement and gains and losses: Policy applicable from January 1, 2018

F - 13

Financial assets measured at fair value through profit or loss (FVTPL)	These assets are subsequently measured at fair value. Net gains and losses, including any interest or dividend income, are recognized in profit or loss.
Financial assets at amortized cost	These assets are subsequently measured at amortized cost using the effective interest method. The amortized cost is reduced by impairment losses. Interest income, foreign exchange gains and losses and impairment are recognized in profit or loss. Any gain or loss on derecognition is recognized in profit or loss.
Debt instruments at fair value through other comprehensive income (FVOCI)	These assets are subsequently measured at fair value. Net gains and losses are recognized in other comprehensive income, except for interest income calculated using the effective interest method, foreign exchange gains and losses and impairment, which are recognized in profit or loss. On derecognition, gains and losses accumulated in other comprehensive income are reclassified to profit or loss. The Group has no financial assets of this classification.
Equity instrument at fair value through other comprehensive income.	These assets are subsequently measured at fair value. All gains and losses are recognized in other comprehensive income and are never reclassified to profit or loss, except dividends which are recognized as income in profit or loss (unless the dividend clearly represents a recovery of part of the cost of the investment). The Group has no financial assets of this classification.

Subsequent measurement and gain and loss: Policy applicable before January 1, 2018

Financial assets measured at fair value through profit or loss (FVTPL)	These assets are subsequently measured at fair value. Net gains or losses, including interest or dividend income, are recognized in profit or loss.
Held-tomaturityfinancial assets	These assets are measured at amortized cost using the effective interest method.
Loansand receivables	These assets are measured at amortized cost using the effective interest method.
Available-for-salefinancialassets	These assets are measured at fair value and changes therein, other than impairment losses, interest income and foreign currency differences on debt instruments, were recognized in Other Comprehensive Income and accumulated in the fair value reserve.When these assets were derecognized, the gain or loss accumulated in equity was reclassified to profit or loss.

Financial assets are not reclassified subsequent to their initial recognition unless the Group changes its business model for managing financial assets, in which case all affected financial assets are reclassified on the first day of the first reporting period following the change in the business model.

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Amortized Cost: A financial asset is measured at amortized cost if it meets both of the following conditions and is not designated as at FVTPL:

o	it is held within a business model whose objective is to hold assets to collect contractual cash flows; and
o	its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Fair Value through Other Comprehensive Income (FVOCI): A debt investment is measured at FVOCI if it meets both of the following conditions and is not designated as at FVTPL:

o	it is held within a business model whose objective is to hold assets to collect contractual cash flows, as the selling of financial assets; and
o	its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

On initial recognition of an equity investment that is not held for trading, the Group may irrevocably elect to present subsequent changes in the investment’s fair value in Other Comprehensive Income. This election is made on an investment-by-investment basis.

All financial assets not classified as measured at amortized cost or FVOCI as described above are measured at FVTPL. This includes all derivative financial assets (see Note 35). On initial recognition, the Group may irrevocably designate a non-derivative financial asset that otherwise meets the requirements to be measured at amortized cost or at FVOCI as at FVTPL if doing so eliminates or significantly reduces an accounting mismatch that would otherwise arise.

Business model assessment:

The Group makes an assessment of the objective of the business model in which a financial asset is held at a portfolio level because this best reflects the way the business is managed and information is provided to management. The information considered includes the stated policies and objectives for the portfolio and the operation of those policies in practice. These include whether:

- management’s strategy focuses on earning contractual interest income, maintaining a particular interest rate profile, matching the duration of the financial assets to the duration of any related liabilities or expected cash outflows or realizing cash flows through the sale of the assets;

- how the performance of the portfolio is evaluated and reported to the Group’s management;

- therisksthataffecttheperformanceofthebusinessmodel(andthefinancialassetsheldwithin thatbusinessmodel)andhowthoserisksaremanaged;

-how managers of the business are compensated – e.g. whether compensation is based on the fair value of the assets managed or the contractual cash flows collected; and

- thefrequency,volumeandtimingofsalesoffinancialassetsinpriorperiods,thereasonsforsuchsalesandexpectationsaboutfuturesalesactivity.

Financial assets that are held for trading or are managed and whose performance is evaluated on a fair value basis are measured at FVTPL.

Assessment whether contractual cash flows are solely payments of principal and interest:

For the purposes of this assessment, ‘principal’ is defined as the fair value of the financial asset on initial recognition. ‘Interest’ is defined as consideration for the time value of money and for the credit risk associated with the principal amount outstanding during a particular period of time and for other basic lending risks and costs (e.g. liquidity risk and administrative costs), as well as a profit margin.

o	contingent events that would change the amount or timing of cash flows;
o	terms that may adjust the contractual coupon rate, including variable rate features;

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o	prepayment and extension features; and
o	terms that limit the Group’s claim to cash flows from specified assets (e.g. non-recourse features).

For transactions involving the purchase and sale of energy conducted by the trading subsidiaries, the Group keeps an accounting policy defined in accordance to its business strategy with instruments measured at amortized cost, whichrefer to contracts already signed and still held with the purpose of receipt or delivery of energy according to the expected requirements by the Company related to purchase or sale.The transactions are generally long-term and are never settled by the net cash amount or another financial instrument and, even if some contract has a certain flexibility, the strategy of the Group’s portfolio is not changed for this reason.

- Financial liabilities

Financial liabilities are initially recognized on the date that they are originated or on the trade date at which the Company or its subsidiaries become a party to the contractual provisions of the instrument. The classification of financial liabilities are as follows:

Measured at fair value through profit or loss: these are financial liabilities that are: (i) designated at fair value in order to match the effects of recognition of income and expenses to obtain more relevant and consistent accounting information, or (ii) derivatives. These liabilities are measured at fair value, which changes are recognized in profit or loss and any subsequent change in their fair value attributable to credit risk in liabilities is subsequently recognized in comprehensive income.

ii.

Measured at amortized cost: these are other financial liabilities not classified into the previous category. They are measured initially at fair value net of any cost attributable to the transaction and subsequently measured at amortized cost using the effective interest rate method.

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

Financial assets and liabilities are offset and presented at their net amount when, and only when, there is a legal right to offset the amounts and the intent to realize the asset and settle the liability simultaneously.

The classifications of financial instruments (assets and liabilities) are described in note 35.

- Issued Capital

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

3.4 Property, plant and equipment

Items of property, plant and equipment are measured at acquisition, construction or formation cost less accumulated depreciation and, if applicable, accumulated impairment losses. Cost also includes any other costs attributable to bringing the assets to the place and in a condition to operate as intended by Management, the cost of dismantling and restoring the site on which they are located and capitalized borrowing costs on qualifying assets.

The replacement cost of items of property, plant and equipment is recognized if it is probable that it will involve economic benefits for the subsidiaries and if the cost can be reliably measured, and the value of the replaced item is written off. Maintenance costs are recognized in profit or loss as they are incurred.

Depreciation is calculated on a straight-line basis, at annual rates of 2% to 20%, taking into consideration the estimated useful life of the assets, as instructed and defined by the granting authority.

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Gains and losses on disposal/ write-off of an item of property, plant and equipment are determined by comparing the proceeds from disposal with the residual value of the asset, and are recognized net within other operating income/expenses.

Assets and facilities used in the electric generation, transmission and distribution activities are tied to these services and may not be removed, donated, disposed of, assigned or pledged in mortgage without the prior and express authorization of ANEEL. ANEEL, through Resolution No. 20 of February 3, 1999, amended by Normative Resolution No. 691 of December 8, 2015, releases Public Electric Energy Utility concessionaires from prior authorization for release of assets of no use to the concession, but determines that the proceeds from the disposal be deposited in a restricted bank account for use in the acquisition of new assets related to electric energy services.

3.5 Intangible assets and contract assets

Includes rights related to non-physical assets such as goodwill and concession exploration rights, software and rights-of-way.

Goodwill that arises on the acquisition of subsidiaries is measured based on the difference between the fair value of the consideration transferred for acquisition of a business, adding the portion of noncontrolling interests, and the net fair value of the assets and liabilities of the subsidiary acquired.

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

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

i.	Acquisitions through business combinations: the portion arising from business combinations that corresponds to the right to operate the concession amortized over the remaining period of the concessions, on a straight-line basis;
ii.	Investments in infrastructure in service (application of IFRIC 12 - Concession Agreements): under the electric energy distribution concession agreements with the subsidiaries, the recognized intangible asset corresponds to the concessionaires' right to charge the consumers for use of the concession infrastructure. Since the exploration term is defined in the agreement, intangible assets with defined useful lives are amortized over the concession period in proportion to a curve that reflects the consumption pattern in relation to the economic benefits. For further information see note 3.2.
	Items comprised in the infrastructure are directly tied to the Group’s electric energy distribution operation and shall comply with the same regulatory rules described in item 3.4.
iii.	Use of Public Asset: upon certain generation concessions were granted with the condition of payments to the federal government for Use of Public Asset. The Company records this obligation at present value, on the signing date, and the corresponding intangible assets. This intangible assets balance, comprising the interests capitalized until the operation date, is being amortized on a straight-line basis over the period of each concession.

From January 1, 2018, the concession infrastructure assets of the distribution companies were classified as contract assets during the construction or improvement period in accordance with the criteria of IFRS 15.

3.6 Impairment

Policy applicable from January 1, 2018

- Financial assets

The Groups assesses evidence of impairment for certain receivables at both an individual and a collective level. Receivables that are not individually significant are collectively assessed for impairment. Collective assessment is carried out by grouping together assets with similar risk characteristics.

The Group recognizes loss allowances for ECLs on: (i) financial assets measured at amortized cost; (ii) debt investments measured at FVOCI, when applicable; and (iii) contract assets.

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The Group measures loss allowances, using the simplified recognition approach, at an amount equal to lifetime ECLs.

When determining whether the credit risk of a financial asset has increased significantly since initial recognition and when estimating ECLs, the Group considers reasonable and supportable information that is relevant and available without undue cost or effort. This includes both quantitative and qualitative information and analysis, based on the Group's historical experience and informed credit assessment and including forward-looking information.

The Group considers a financial asset to be in default when the borrower has not complied with its contractual payment obligations and is unlikely to pay its obligations.

The Group uses an allowance matrix based on its historical default rates observed along the expected lifetime of the trade receivables to estimate the expected credit losses for the lifetime of the asset where the history of losses is adjusted to consider the effects of the current conditions and its forecasts of future conditions that did not affect the period in which the historical data were based.

The methodology developed by the Group resulted in a percentage of expected loss for bills of consumers,concessionaires and licensees that is in compliance with IFRS 9 described as expected credit losses, comprising in a single percentage the probability of loss weighted by the expected loss and possible results, that is, comprising the Probability of Default (“PD”), Exposure At Default (“EAD”) and Loss Given Default (“LGD”).

At each reporting date, the Group assesses whether financial assets carried at amortized cost and debt securities at FVOCI, when applicable, are credit-impaired.A financial asset is ‘credit‑impaired’ when one ormoreeventsthathaveadetrimentalimpactontheestimatedfuturecashflowsofthefinancial asset haveoccurred.

Evidence that a financial asset is credit‑impaired includes the following observable data:

o	significant financial difficulty of the borrower or issuer;
o	a breach of contractual clauses;
o	the restructuring of a loan or advance by the Group on terms that the Group would not consider otherwise;
o	it is probable that the borrower will enter bankruptcy or other financial reorganization; or
o	the disappearance of an active market for a security because of financial difficulties.

Impairment losses related to consumers, concessionaires and licensees recognized in financial assets and other receivables, including contract assets, are recognized in profit or loss.

- Non-financial assets

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

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

The assets (e.g. goodwill, concession intangible asset) are segregated and grouped together at the lowest level that generates identifiable cash flows (the "cash generating unit", or “CGU”). If there is an indication of impairment, the loss is recognized in profit or loss. Except in the case of goodwill impairment, which cannot be reversed in the subsequent period, impairment losses are reassessed annually for triggering events that would lead to possibility of reversals.

3.7 Provisions

A provision is recognized if, as a result of a past event, there is a legal or constructive obligation that can be estimated reliably, and it is probable (more likely than not) that an outflow of economic benefits will be required to settle the obligation. When applicable, provisions are determined by discounting the expected future cash outflows at a rate that reflects current market assessment and the risks specific to the liability.

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3.8 Employee benefits

Certain subsidiaries have post-employment benefits and pension plans and are regarded as Sponsors of these plans. Although the plans have particularities, they have the following characteristics:

Defined contribution plan: a post-employment benefit plan under which the Sponsor pays fixed contributions into a separate entity and will have no liability for the actuarial deficits of the plan. The obligations are recognized as an expense in the statement of profit or loss in the periods during which the services are rendered.

ii.

Defined benefit plan: The net obligation is calculated as the difference between the present value of the actuarial obligation based on assumptions, biometric studies and interest rates in line with market rates, and the fair value of the plan assets as of the reporting date. The actuarial liability is calculated annually by independent actuaries, under the responsibility of Management, using the projected unit credit method. Actuarial gains and losses are recognized in other comprehensive income when they occur. Net Interest (income or expense) is calculated by applying the discount rate at the beginning of the period to the net amount of the defined benefit asset or liability. When applicable, the cost of past services is recognized immediately in profit or loss.

If the plan records a surplus and it becomes necessary to recognize an asset, the recognition is limited to the present value of future economic benefits available in the form of reimbursements or future reductions in contributions to the plan.

3.9 Dividends and Interest on capital

Under Brazilian law, the Company is required to distribute a mandatory minimum annual dividend of 25% of profit adjusted in accordance with the Company´s bylaws. A provision may only be made for the minimum mandatory dividend, and dividends declared but not yet approved are only recognized as a liability in the financial statements after approval by the competent body. According to Law 6,404/76, they will therefore be held in equity, in the “additional dividend proposed” account, as they do not meet the present obligation criteria at the reporting date.

On May 21, 2019, the Company's Board of Directors approved a Dividend Policy that establishes the Company’s annual dividend distribution of at least 50% of the adjusted profit in accordance with Law 6,404/76. This policy establishes factors that will influence the distribution amounts, such as the Company's financial condition, future prospects, macroeconomic conditions, tariff reviews and adjustments, regulatory changes and the Company's growth strategy. It also highlights that certain obligations specified in financial contracts may limit the amount to be distributed. The approved policy is merely indicative in order to signal to the market the treatment the Company intends to give to the dividend distribution and, therefore, it has a programmatic nature and is not binding on the Company or its managing bodies.

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

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

3.10 Revenue recognition

The operating revenue in the normal course of the subsidiaries’ activities is measured at the consideration received or receivable. The operating revenue is recognized when it represents the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services.

IFRS 15 establishes a revenue recognition model that considers five steps: (i) identify the contract with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv)allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the entity satisfies a performance obligation.

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The revenue from electric energy distribution is recognized when the energy is supplied. The energy distribution subsidiaries perform the reading of the consumption of their customers based on a reading routine (calendar and reading route) and invoice monthly the consumption of MWh based on the reading performed for each consumer. As a result, part of the energy distributed during the month is not billed at the end of the month and, consequently, an estimate is developed by Management and recorded as “Unbilled”. This unbilled revenue estimate is calculated using as a base the total volume of energy of each distributor made available in the month and the annualized rate of technical and commercial losses.

The revenue from energy generation sales is recognized based on the assured energy and at tariffs specified in the terms of the supply contracts or the current market price, as appropriate.

The revenue from energy trading is recognized based on bilateral contracts with market agents and properly registered with the Electric Energy Trading Chamber – CCEE.

The revenue from services provided is recognized when the service is provided, under a service agreement between the parties.

The revenue from construction contracts is recognized based on the reach of the performance obligation over time, considering the fulfillment of one of the following criteria:

(a)	the customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs;
(b)	the entity’s performance creates or enhances an asset (for example, work in progress) that the customer controls as the asset is created or enhanced;
(c)	the entity’s performance does not create an asset with an alternative use to the entity and the entity has an enforceable right to payment for performance completed to date.

The provision of infrastructure construction services is recognized in accordance with IFRS 15, against a contract asset.

The revenues of the transmission companies, recognized as operating revenue, are:

·	Construction revenue: Refers to the services of construction of electric energy transmission facilities. These are recognized according to the percentage of completion of the construction works.
·	Financing component: Refers to the interest recognized under the accrual basis on the amount receivable from the construction revenue.
·	Revenue from operation and maintenance: Refers to the services of operation and maintenance of electric energy transmission facilities aimed at non-interruption of availability of these facilities, recognized based on incurred costs.

No single consumer accounts for 10% or more of the Group’s total revenue.

3.11 Income tax and social contribution

Income tax and social contribution expenses are calculated and recognized in accordance with the legislation in force and comprise current and deferred taxes. Income tax and social contribution are recognized in the statement of profit or loss except to the extent that they relate to items recognized directly in equity or other comprehensive income, when the net amounts of these tax effects are already recognized, and those arising from the initial recognition in business combinations.

Current taxes are the expected taxes payable or receivable/recoverable on the taxable profit or loss, which reflects the uncentanties related to the calculation, if any. Deferred taxes are recognized for temporary differences between the carrying amounts of assets and liabilities for accounting purposes and the equivalent amounts used for tax purposes and for tax loss carryforwards and reflects the uncertainty related to the income tax, if any.

F - 20

The Company and certain subsidiaries recognize in their financial statements the effects of tax loss carryforwards and deductible temporary differences, based on projections of future taxable profits, approved annually by the Boards of Directors and examined by the Fiscal Council. The subsidiaries also recognized tax credits relating to the tax benefits created by the corporate restructuring, which are amortized on a straight line basis for the remaining period of each concession agreement.

Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to taxes levied by the same tax authority on the same taxable entity.

Deferred income tax and social contribution assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related taxes benefit will be realized.

3.12 Earnings per share

Basic earnings per share are calculated by dividing the profit or loss for the year attributable to the Group’s controlling shareholders by the weighted average number of shares outstanding during the year. Diluted earnings per share are calculated by dividing the profit or loss for the year attributable to the controlling shareholders, adjusted by the effects of instruments that potentially would have impacted the profit or loss for the year by the weighted average of the number of shares outstanding, adjusted by the effects of all dilutive potential convertible notes for the reporting periods, in accordance with IAS 33.

3.13 Government grants – CDE (Energy Development Account)

Government grants are only recognized when it is reasonably certain that these amounts will be received by the Group. They are recognized in profit or loss for the periods in which the Group recognizes as income the discounts granted in relation to the low-income subsidy and other tariff discounts.

The subsidies received through funds from the CDE (note 25) have the main purpose of offsetting discounts granted in order to provide immediate financial support to the distribution companies, in accordance with IAS 20.

3.14 Sector financial asset and liability

According to the tariff pricing mechanism applicable to distribution companies, the energy tariffs should be set at a price level (price cap) that ensures the economic and financial equilibrium of the concession, therefore, the concessionaires and licensees are authorized to charge their consumers (after review and ratification by ANEEL) for: (i) the annual tariff increase; and (ii) every four or five years, according to each concession agreement, the periodic review for purposes of reconciliation of part of Parcel B (controllable costs) and adjustment of Parcel A (non-controllable costs).

The distributors' revenue is mainly comprised of the sale of electric energy and for the delivery (transport) of the electric energy via the distribution infrastructure (network). The distribution concessionaires' revenue is affected by the volume of energy delivered and the tariff. The electric energy tariff is comprised of two parcels which reflect a breakdown of the revenue:

·	Parcel A (non-controllable costs): this parcel should be neutral in relation to the entity's performance,i.e., the costs incurred by the distributors, classifiable as “Parcel A”, are fully passed through the consumer or borne by the granting authority ; and
·	Parcel B (controllable costs) – comprised of capital expenditure on investments in infrastructure, operational costs and maintenance and remuneration to the providers of capital. It is this parcel that actually affects the entity's performance, since it has no guarantee of tariff neutrality and thus involves an intrinsic business risk.

This tariff pricing mechanism can cause temporary differences arising from the difference between the expected costs (Parcel A and other financial components) included in the tariff at the beginning of the tariff period and those actually incurred while it is in effect. This difference constitutes a right of the concessionaire to receive cash when the expected costs included in the tariff are lower than those actually incurred, or an obligation to pay if the expected costs are higher than those actually incurred.

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3.15 Business combination

Business combinations are accounted for by applying the acquisition method. The consideration transferred in a business combination is measured at fair value, calculated as the sum of the fair values of the assets transferred by the acquirer, the liabilities incurred and the equity interests issued by the Company and subsidiaries in exchange for control of the acquiree. Costs related to the acquisition are recognized in profit or loss, when incurred.

At the acquisition date, assets and liabilities are recognized at fair value, except for: (i) deferred taxes, (ii) employee benefits and (iii) share-based payments.

The noncontrolling interests are initially measured either at fair value or at the noncontrolling interests’ proportionate share of the acquiree’s identifiable net assets. The measurement method is chosen on a transaction-by-transaction basis.

The excess of the consideration transferred, added to the portion of noncontrolling interests, over the fair value of the identifiable assets (including the concession intangible asset) and net liabilities assumed at the acquisition date are recognized as goodwill. In the event that the fair value of the identifiable assets and net liabilities assumed exceeds the consideration transferred, a bargain purchase is identified and the gain is recognized in the statement of profit or loss at the acquisition date.

3.16 Basis of consolidation

(i) Business combinations

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

(ii) Subsidiaries and joint ventures

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

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

The consolidated financial statements include the balances and transactions of the Company and its subsidiaries. The balances and transactions of assets, liabilities, income and expenses have been fully consolidated for the subsidiaries.

Intragroup balances and transactions, and any income and expenses derived from these transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity accounted investees are eliminated against the investment to the extent of the Company’s interest in the investee. Unrealized losses are eliminated in the same way as unrealized gains, but only to the extent that there is no evidence of impairment.

In the case of subsidiaries, the portion related to noncontrolling interests is stated in equity and in the statements of profit or loss and comprehensive income in each period presented.

The balances of joint ventures, as well as the Company’s interest in each of them are described in note 13.2.

(iii) Acquisition of noncontrolling interests

Accounted for as transaction among shareholders. Consequently, no asset or goodwill is recognized as a result of such transaction.

3.17 New standards and interpretations issued and effective

A number of IASB standards were issued or revised and are mandatory for accounting periods beginning on January 1, 2019:

a) IFRS 16 Leasing

Issued on January 13, 2016, establishes, in the lessee’s view, a new form for accounting for leases currently classified as operating leases, which are now recognized similarly to leases classified as finance leases. Asregards the lessors, it virtually retains the requirements of IAS 17, including only some additional disclosure aspects. IFRS 16 is effective for annual reporting periods beginning on or after January 1, 2019.

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IFRS 16 introduces a single model of accounting for leases in the statement of financial position for lessees, eliminating the prior classification between finance and operating leases. The lessee shall recognize an asset relating to the right to use the leased asset and a lease liability that represents the obligation to make lease payments. Exemptions are available for short-term leases (contracts with a maximum term of 12 months) and low-value items (fair value of the identified leased asset is less than US$ 5,000).

The standard defines that a contract is or contains a lease if it conveys the right to control the use of the identified asset over a period of time in exchange for a certain consideration. The Company and its subsidiaries assessed the standard, mainly for the land lease agreements of the wind farms of CPFL Renováveis’ indirect subsidiaries, as they involve material amounts and are long-term. As most of these agreements involve variable considerable payable to lessor based on the energy generated by each wind farm, IFRS 16 does not allow the recognition of the lease liability and, consequently, of the right of use relating to these agreements. For other agreements in which lessor is entitled to receive fixed consideration, the Group assessed the standard and concluded that there was no material impact on its adoption.

For other agreements in which the Company and/or its subsidiaries act as lessees, as a result of the initial application of IFRS 16, with respect to leases that were previously classified as operating, the amounts resulting from the right-of-use asset and from the lease liability were considered immaterial and were not recorded.

b) IFRIC23 – Uncertainty over Income Tax Treatments

Issued in May 2017 in order to clarify the accounting for tax positions that may not be accepted by the tax authorities in regard to IRPJ and CSLL matters. In general lines, the main point of analysis of the interpretation refers to the probability of acceptance by the tax authorities of the tax treatment chosen by the Group.

IFRIC 23 / ICPC 22 is effective for annual reporting periods beginning on or after January 1, 2019. The Group assessed the interpretation and the impact of adopting the standard was the reclassification of the balance of provision for tax risks related to income taxes to the line item Corporate income tax (Note 22).

3.18 New standards and interpretations not yet effective and not early adopted

New standards and amendments to standards and IFRS interpretations were issued by the IASB and are not yet effective for the year ended December 31, 2019. The Group has not adopted these amendments in preparing these financial statements:

Definition of a business (amendment to IFRS 3):this amendment clarifies the definition of ‘business’, aiming to facilitate the decision of companies on how to classify the acquisition of a set of activities and assets between a business combination or simply an acquisition of groups of assets.

Disclosure Initiative - Definition of Material (Amendments to IAS 1 and IAS 8): this amendment clarifies the definition of ‘material’, aiming to help companies make a better judgment to define whether information on a particular item, transaction or other event shall be disclosed in the financial statements without substantially changing existing requirements.

Based on a preliminary assessment, Management believes that application of these amendments will not have a material effect on the disclosures and amounts recognized in its consolidated financial statements.

( 4 ) DETERMINATION OF FAIR VALUES

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

The Group measures fair value as the price that would be received for the sale of the asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

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- Property, plant and equipment, intangible assets and contract assets

The fair value of items of property, plant and equipment, intangible assets and contract assets are based on the market approach and cost approaches using quoted market prices for similar items when available and replacement cost when appropriate.

- Financial instruments

Financial instruments measured at fair values are valued based on quoted prices in an active market, or, if such prices were not available, assessed using pricing models, applied individually for each transaction, taking into consideration the future cash flows, based on the conditions contracted, discounted to present value at market interest rate curves, based on information obtained, when available, from theB3 S.A. – Brasil, Bolsa, Balcão (“B3”) andAssociação Brasileira das Entidades dos Mercados Financeiro e de Capitais (“ANBIMA”) (note 35) and also includes the debtor's credit rating.

The right to compensation, to be paid by the Federal Government, regarding the assets of the distribution concessionaires at the end of the concession agreement are recognized at fair value through profit and loss. The methodology adopted for marking these assets to fair value is based on the tariff review process for distributors. This review, conducted every four or five years according to each concessionaire, involves assessing the replacement price for the distribution infrastructure, in accordance with criteria established by the granting authority (“ANEEL”). This valuation basis is used for setting the distribution companies tariff, which is increased annually up to the next tariff review, based on the parameter of the main inflation indices.

Accordingly, at the time of the tariff review, each distribution concessionaire adjusts the position of the financial asset base for compensation at the amounts ratified by the granting authority and uses the Extended Consumer Price Index (“IPCA”) as the best estimates for adjusting the original value until next tariff review process.

( 5 ) CASH AND CASH EQUIVALENTS

	Dec 31, 2019	Dec 31, 2018
Bank balances	450,622	422,968
Short-term financial investments	1,486,541	1,468,489
Overnight investment (a)	-	66
Bank certificates of deposit (b)	1,279,740	639,601
Investment funds (c)	206,801	828,822
Total	1,937,163	1,891,457

(a)	Current account balances, which earn daily interest by investment in repurchase agreements secured on Bank Certificate Deposit (CDB) and interest of 15% of the variation in the Interbank Certificate of Deposit (CDI).
(b)	Short-term investments in (i) Bank Certificates of Deposit (CDB) R$ 994,521 in December 31, 2019 and R$ 462,551 in December 31, 2018, (ii) secured debentures R$ 284,863 and R$ 177,050 in December 31, 2018 and (iii) leasing notes (R$356), with major financial institutions that operate in the Brazilian financial market, with daily liquidity, short term maturity, low credit risk and interest equivalent, on average, to 94.13% of the CDI.
(c)	Investments funds, with high liquidity and interest equivalent, on average, to 92.26% of the CDI, subject to floating rates tied to the CDI linked to federal government bonds, CDBs, financial bills and secured debentures of major financial institutions, with low credit risk and short term maturity.

( 6 ) SECURITIES

Securities	Dec 31, 2019
Investment funds (a)	449,786
Direct application (b)	401,218
Total	851,004

F - 24

(a)	This refers to amounts invested in government securities, Financial Bills ("LF") and Financial Treasury Bills ("LFT"), through investment fund quotas, yielding on average 99.87% of the CDI, with maturity date as from September 2020.
(b)	This refers to amounts invested in government securities and LFT, yielding on average 100% of the CDI, with maturity date in September 2020.

( 7 )CONSUMERS, CONCESSIONAIRES AND LICENSEES

The balance derives mainly from the supply of electric energy. The following table shows the breakdown at December 31, 2019 and 2018:

	Amounts coming due	Past due		Total
	Amounts coming due	until 90 days	> 90 days	Dec 31, 2019	Dec 31, 2018
Current
Consumer classes
Residential	862,310	623,993	74,327	1,560,630	1,459,186
Industrial	338,849	77,400	87,829	504,078	480,184
Commercial	365,729	96,886	35,884	498,499	466,483
Rural	110,692	27,253	11,919	149,864	123,392
Public administration	87,233	28,149	4,007	119,389	99,051
Public lighting	66,735	6,890	5,747	79,373	77,868
Public utilities	99,803	19,536	5,317	124,655	121,840
Billed	1,931,351	880,107	225,030	3,036,488	2,828,004
Unbilled	1,230,883	-	-	1,230,883	1,158,106
Financing of consumers' debts	172,992	37,469	36,970	247,431	224,903
CCEE transactions	319,728	2,313	28,313	350,354	175,176
Concessionaires and licensees	387,444	3,838	12,346	403,628	428,361
Others	50,191	-	-	50,191	34,002
	4,092,589	923,727	302,659	5,318,975	4,848,552
Allowance for doubtful accounts				(333,396)	(300,601)
Total				4,985,578	4,547,951

Noncurrent
Financing of consumers' debts	179,045	-	-	179,045	196,635
Free Energy	6,739	-	-	6,739	6,360
CCEE transactions	221,382	305,901	-	527,284	549,800
Total	407,166	305,901	-	713,068	752,795

Financing of Consumers' Debts -Refers to the negotiation of overdue receivables from consumers, principally public administration. Payment of some of these receivables is guaranteed by the debtors by pledging the bank accounts through which their ICMS (VAT) tax is received.

Electric Energy Trading Chamber (CCEE) transactions -The amounts refer to the sale of electric energy on the spot market. The noncurrent amounts mainly comprise: (i) adjustments of entries made by the CCEE in response to certain legal decisions (preliminary decisions) in the accounting processes for the period from September 2000 to December 2002; and (ii) provisional accounting entries established by the CCEE (iii) opening balances due to the CCEE temporary situation in function of injuctions from generating companies due to the hydrological scenario and its financial impacts over free market. The subsidiaries consider that there is no significant risk on the realization of these assets and consequently no allowance was recognized for these transactions.

Concessionaires and Licensees- Refer basically to receivables for the supply of electric energy to other concessionaires and licensees, mainly by the subsidiaries CPFL Geração, CPFL Brasil and CPFL Renováveis.

Allowance for doubtful accounts

The allowance for doubtful accounts is recognized based on the expected credit loss (ECL), adopting the simplified method of recognizing, based on historical and future probability of default. The allowance methodology is detailed in note 35(e).

F - 25

Movements in the allowance for doubtful accounts are shown below:

	Consumers, concessionaires and licensees	Other receivables (note 12)	Total
As of December 31, 2016	(261,525)	(27,992)	(289,517)
Allowance - reversal (recognition)	(263,668)	(1,439)	(265,107)
Recovery of revenue	110,008	-	110,008
Write-off of accrued receivables	148,309	52	148,361
As of December 31, 2017	(266,876)	(29,379)	(296,255)
Allowance - reversal (recognition)	(277,802)	1,419	(276,383)
Recovery of revenue	107,122	-	107,122
Effects on first adoption of IFRS 9	(72,687)	(738)	(73,426)
Write-off of accrued receivables	209,641	-	209,641
As of December 31, 2018	(300,601)	(28,698)	(329,299)
Allowance - reversal (recognition)	(433,224)	(320)	(433,543)
Recovery of revenue	200,046	73	200,119
Write-off of accrued receivables	200,382	(73)	200,309
As of December 31, 2019	(333,396)	(29,019)	(362,415)

( 8 )TAXES RECOVERABLE

	Dec 31, 2019	Dec 31, 2018
Current
Prepayments of social contribution - CSLL	5,088	12,373
Prepayments of income tax - IRPJ	12,522	36,972
Income tax and social contribution to be offset	70,088	74,395
Income tax and social contribution recoverable	87,698	123,739

Withholding income tax - IRRF on interest on capital	40,432	8,163
Withholding income tax - IRRF	80,499	92,210
State VAT - ICMS to be offset	144,415	125,669
Social Integration Program - PIS	10,958	9,970
Contribution for Social Security Funding - COFINS	51,084	46,741
Others	4,039	4,764
Other taxes recoverable	331,428	287,517

Total current	419,126	411,256

Noncurrent
Social contribution to be offset - CSLL	65,589	62,458
Income tax to be offset - IRPJ	35,939	5,508
Income tax and social contribution recoverable	101,528	67,966

State VAT - ICMS to be offset	191,523	174,596
Social Integration Program - PIS	30,987	1,060
Contribution for Social Security Funding - COFINS	142,779	4,885
Others	5,306	5,185
Other taxes recoverable	370,595	185,725

Total noncurrent	472,123	253,691

Withholding income tax - IRRF – Relates mainly to IRRF on financial investments.

F - 26

Social contribution to be offset – CSLL – In noncurrent, it refers basically to the final unappealable favorable decision in a lawsuit filed by the subsidiary CPFL Paulista. The subsidiary CPFL Paulista is awaiting the authorization for utilization of credit from the Federal Revenue in order to carry out its subsequent offset.

State VAT - ICMS to be offset – In noncurrent, it refers mainly to the credit recorded on purchase of assets that results in the recognition of property, plant and equipment, intangible assets and financial assets.

Exclusion of ICMS from the PIS and COFINS tax base

A number of subsidiaries of the Group are parties to several pending legal proceedings involving the Brazilian federal government that address the exclusion of ICMS amounts from the PIS and COFINS tax base, as well as the Group subsidiaries’ rights to receive refunds of other amounts previously paid. In 2019, CPFL Santa Cruz (related to the original lawsuit presented by four merged companies -CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari and CPFL Mococa) received a favorable final judicial decision on these matters, which is not subject to further appeal. As a result, CPFL Santa Cruz recognized a tax credit of R$ 166,870 using the calculation method in accordance with the “Federal Revenue Orientation 13/2018”. Based on advice of external legal counsel, the Group understands that amounts received as tax credits by its distribution subsidiaries and will need to be refunded to consumers as soon the Brazilian Federal Revenue approves such tax credits as compensation payable to affected consumers. The Group is still discussing with its external legal advisors the relevant time period applicable to calculating the refunds of tax credits to consumers, which may be for a period of three, five or ten years. On 2019, CPFL Santa Cruz recognized a liability related to tax credits that need to be refunded for the maximum period of 10 years.

As a result, for the year ended December 31, 2019, CPFL Santa Cruz recognized an increase of R$ 167,777 as “Taxes Recoverable”, against R$ 132,607 of increase in “Other Payable – Consumers” and a decrease of R$ 34,495 as “Deduction from operating revenues – PIS and COFINS”financial adjustment of R$ 675. No other amounts have been recognized as the other Group subsidiaries await final decisions in their respective legal proceedings.

( 9 )SECTOR FINANCIAL ASSETS AND LIABILITIES

The breakdown and changes for the year in the balances of Sector financial asset and liability is as follows:

	As of December 31, 2018			Operating revenue (note 27)		Finance results (note 30)	As of December 31, 2019
	Deferred	Approved	Total	Constitution	Realization	Monetary adjustment	Deferred	Approved	Total
Parcel "A"	1,306,751	592,281	1,899,031	753,571	(1,367,194)	103,815	891,247	497,977	1,389,225
CVA (*)
CDE (**)	208,156	(7,275)	200,881	50,609	(149,085)	16,954	1,277	118,083	119,360
Electric energy cost	586,027	634,599	1,220,626	130,313	(925,376)	49,173	294,291	180,446	474,737
ESS and EER (***)	(562,800)	(450,230)	(1,013,030)	(441,381)	857,459	(45,704)	(341,381)	(301,275)	(642,656)
Proinfa	246	3,129	3,375	43,537	(24,907)	2,236	881	23,361	24,242
Basic network charges	36,256	23,526	59,782	180,488	(55,344)	3,728	180,686	7,967	188,654
Pass-through from Itaipu	1,141,254	465,184	1,606,438	902,954	(1,200,945)	82,886	848,587	542,747	1,391,334
Transmission from Itaipu	31,784	12,439	44,222	37,098	(35,857)	2,575	29,275	18,763	48,038
Neutrality of industry charges	(40,763)	(8,370)	(49,133)	(42,280)	67,696	(971)	9,636	(34,324)	(24,688)
Overcontracting	(93,409)	(80,721)	(174,130)	(107,768)	99,164	(7,062)	(132,005)	(57,791)	(189,796)
Other financial components	(275,550)	(115,325)	(390,875)	(86,443)	97,605	(15,737)	(285,566)	(109,885)	(395,451)

Total	1,031,201	476,956	1,508,156	667,128	(1,269,589)	88,079	605,681	388,092	993,775

Current assets			1,330,981						1,093,588
Noncurrent assets			223,880						2,748
Noncurrent liabilities			(46,703)						(102,561)

F - 27

	As of December 31, 2017			Operating revenue		Finance income /expense	Receipt	As of December 31, 2018
	Deferred	Approved	Total	Constitution	Realization	Monetary adjustment	Tariff flag (note 25.4)	Deferred	Approved	Total
Parcel "A"	924,943	(235,916)	689,026	1,416,031	656	90,658	(297,340)	1,306,751	592,281	1,899,031
CVA (*)
CDE (**)	(235,901)	(263,520)	(499,422)	352,202	358,731	(10,630)	-	208,156	(7,275)	200,881
Electric energy cost	1,625,759	(18,280)	1,607,479	416,476	(599,527)	93,538	(297,340)	586,027	634,599	1,220,626
ESS and EER (***)	(974,091)	(167,048)	(1,141,139)	(686,829)	878,350	(63,412)	-	(562,800)	(450,230)	(1,013,030)
Proinfa	(610)	(17,961)	(18,572)	8,456	13,411	80	-	246	3,129	3,375
Basic network charges	(20,163)	23,387	3,224	69,335	(16,318)	3,540	-	36,256	23,526	59,782
Pass-through from Itaipu	959,518	125,860	1,085,378	1,222,806	(781,341)	79,596	-	1,141,254	465,184	1,606,438
Transmission from Itaipu	7,802	7,806	15,608	38,876	(11,909)	1,648	-	31,784	12,439	44,222
Neutrality of industry charges	32,566	112,084	144,651	(81,435)	(110,305)	(2,044)	-	(40,763)	(8,370)	(49,133)
Overcontracting	(469,937)	(38,244)	(508,181)	76,143	269,565	(11,657)	-	(93,409)	(80,721)	(174,130)
Other financial components	(193,496)	21,812	(171,685)	(327,883)	119,112	(10,419)	-	(275,550)	(115,325)	(390,875)

Total	731,447	(214,104)	517,341	1,088,148	119,768	80,240	(297,340)	1,031,201	476,956	1,508,156

Current assets			210,834							1,330,981
Noncurrent assets			355,003							223,880
Current liabilities			(40,111)							-
Noncurrent liabilities			(8,385)							(46,703)

(*) Deferred tariff costs and gains variations from Parcel “A” items
(**) Energy Development Account – CDE
(***) System Service Charge (ESS) and Reserve Energy Charge (EER)

a) CVA

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

b) Neutrality of industry charges

Refers to the neutrality of the industry charges contained in the electric energy tariffs, calculating the monthly differences between the amounts billed relating to such charges and the respective amounts considered at the time the distributors’ tariff was set.

c) Energy overcontracting

Electric energy distribution concessionaires are required to guarantee 100% of their energy market through contracts approved, registered and ratified by ANEEL. It is also assured to the distribution concessionaries that costs or revenues derived from energy overcontracting will be passed through the tariffs, limited to 5% of the energy load requirement, as well as the costs related to electric energy deficits. These amounts are adjusted based on SELIC rate and are compensated in the subsequent tariff processes.

d) Other financial components

Refers mainly to: (i) excess demand and excess reactive power that, will be amortized upon the approval of the periodic tariff review cycles; (ii) recalculations of the tariff processes; and (iii) Tariff effect arising from the bilateral agreement between the parties signatories of the Power Trading Chamber in the Regulated Environment – CCEAR and (iv) financial guarantees for energy contracts.

F - 28

( 10 ) DEFERRED TAX ASSETS AND LIABILITIES

10.1 Breakdown of tax assets and liabilities


	Dec 31, 2019	Dec 31, 2018
Social contribution credit (debit)
Tax losses carryforwards	124,852	137,577
Tax benefit of merged intangible	89,511	97,288
Temporarily nondeductible/taxable differences	(218,616)	(292,257)
Subtotal	(4,254)	(57,392)

Income tax credit (debit)
Tax losses carryforwards	345,462	382,359
Tax benefit of merged goodwill	288,754	315,189
Temporarily nondeductible/taxable differences	(602,934)	(809,917)
Subtotal	31,282	(112,369)

PIS and COFINS credit (debit)
Temporarily nondeductible/taxable differences	(10,380)	(10,086)

Total	16,647	(179,847)

Total tax credit	1,064,716	956,380
Total tax debit	(1,048,069)	(1,136,227)

10.2 Tax benefit of merged intangible

Refers to the tax benefit calculated on the intangible derived from the acquisition of subsidiaries, as shown in the following table, which had been incorporated and is recognized in accordance with Instructions No. 319/99 and No. 349/01 issued by the Brazilian Securities and Exchange Commission (“CVM”). The benefit is realized proportionally to the tax amortization of the merged intangible that gave rise to it, during the remaining concessions period, as shown in note 14.

	December 31, 2019		December 31, 2018
	Social contribution	Income tax	Social contribution	Income tax
CPFL Paulista	36,620	101,723	41,246	114,572
CPFL Piratininga	9,145	31,385	10,180	34,938
RGE Sul (RGE)	43,746	144,878	45,863	153,618
CPFL Geração	-	10,769	-	12,061
Total	89,511	288,754	97,288	315,189

F - 29

10.3 Accumulated balances of temporarily nondeductible/nontaxable differences

	December 31, 2019			December 31, 2018
	Social contribution	Income tax	PIS/COFINS	Social contribution	Income tax	PIS/COFINS
Temporarily nondeductible differences
Provision for tax, civil and labor risks	41,817	116,158	-	57,635	160,096	-
Private pension fund	4,006	11,127	-	2,913	8,093	-
Allowance for doubtful debts	33,288	92,466	-	30,316	84,211	-
Free energy supply	9,632	26,756	-	9,166	25,462	-
Research and development and energy efficiency programs	33,289	92,468	-	27,506	76,405	-
Personnel-related provisions	6,225	17,293	-	5,208	14,467	-
Depreciation rate difference	4,097	11,380	-	4,764	13,235	-
Derivatives	(46,344)	(128,733)	-	(58,698)	(163,051)	-
Recognition of concession - adjustment of intangible asset (IFRS)	(5,352)	(14,867)	-	(6,399)	(17,775)	-
Recognition of concession - adjustment of financial asset (IFRS)	(171,599)	(476,664)	-	(148,561)	(410,608)	-
Actuarial losses (IFRS)	25,567	71,020	-	26,001	72,223	-
Fair value adjustment - Derivatives	(8,670)	(24,082)	-	2,711	7,532	-
Fair value adjustment - Debts	9,440	26,222	-	(1,854)	(5,147)	-
Others	(28,477)	(77,238)	(10,380)	(18,030)	(50,236)	(10,086)
Temporarily nondeductible differences - accumulated comprehensive income:
Property, plant and equipment - adjustment of deemed cost (IFRS)	(45,568)	(126,578)	-	(48,806)	(135,572)	-
Actuarial losses (IFRS)	137,853	382,925	-	58,071	161,307	-
Fair value adjustment - Derivatives	(318)	(883)	-	(89)	(247)
Fair value adjustment - Debts	(6,638)	(18,439)	-	(6,683)	(18,567)
Temporarily nondeductible differences - Business combination - CPFL Renováveis
Deferred taxes - asset:
Provision for tax, civil and labor risks	10,748	29,855	-	11,620	32,277	-
Fair value of property, plant and equipment (negative value added of assets)	18,344	50,955	-	19,817	55,047	-
Deferred taxes - liability:
Value added derived from determination of deemed cost	(19,177)	(53,270)	-	(24,690)	(68,584)	-
Intangible asset - exploration right/authorization in indirect subsidiaries acquired	(216,651)	(601,809)	-	(227,199)	(631,106)	-
Other temporary differences	(4,128)	(8,995)	-	(6,976)	(19,379)	-
Total	(218,616)	(602,934)	(10,380)	(292,257)	(809,917)	(10,086)

10.4 Reconciliation of the income tax and social contribution amounts recognized in the statements of income for the years ended December 31, 2019, 2018 and 2017

	2019		2018		2017
	Social contribution	Income tax	Social contribution	Income tax	Social contribution	Income tax
Profit before taxes	3,986,293	3,986,293	2,939,977	2,939,977	1,846,670	1,846,670
Reconciliation to reflect effective rate:
Equity interest in associates and joint ventures	(349,090)	(349,090)	(334,198)	(334,198)	(312,390)	(312,390)
Amortization of intangible asset acquired	48,649	62,756	48,649	62,756	48,649	62,756
Effect of presumed profit regime	(383,968)	(444,168)	(242,700)	(289,923)	(352,101)	(430,296)
Adjustment of revenue from excess demand and excess reactive power	162,438	162,438	153,302	153,302	134,778	134,778
Tax incentive - operating profit	-	-	-	(52,336)	-	(71,340)
Other permanent additions (exclusions), net	103,889	50,343	101,581	87,162	74,015	82,631
Tax base	3,568,211	3,468,572	2,666,611	2,566,740	1,439,621	1,312,809
Statutory rate	9%	25%	9%	25%	9%	25%
Tax credit (debit)	(321,139)	(867,143)	(239,995)	(641,685)	(129,566)	(328,202)
Recognized (unrecognized) tax credit, net	(12,903)	(29,148)	26,323	81,375	(39,162)	(106,699)
Provision for tax risks	(2,570)	(5,097)	-	-	-	-
Total	(336,610)	(901,386)	(213,673)	(560,310)	(168,728)	(434,901)

Current	(303,332)	(804,994)	(227,464)	(578,381)	(153,543)	(387,076)
Deferred	(33,279)	(96,392)	13,791	18,071	(15,185)	(47,825)

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

Recognized (unrecognized) tax assets, net– the recognized tax assets refer to the amount of tax assets on tax loss carryforwards recorded as a result of review of projections of future profits. The unrecognized tax assets refer to losses generated for which currently there is no reasonable assurance that sufficient future taxable profits will be generated to absorb them.

The deferred income tax and social contribution expense recorded in the statement of profit or loss in the amount of R$129,671 (revenue R$ 31,863 in 2018) refers to (i) income tax and social contribution losses (expense of R$49,703 in 2019 and revenue of R$ 112,491 in 2018); (ii) tax benefit of the merged intangible of R$45,257 in 2019 and R$ 45,778 in 2018.

F - 30

10.5 Income tax and social contribution amounts recognized in equity

The deferred income tax and social contribution recognized directly in equity (other comprehensive income) in 2019, 2018 and 2017 were as follows:

	2019		2018		2017
	Social Contribution	Income tax	Social Contribution	Income tax	Social Contribution	Income tax
Actuarial losses (gains)	1,122,747	1,122,747	313,243	313,243	(166,857)	(166,857)
Limits on the asset ceiling	44,058	44,058	6,617	6,617	21,399	21,399
Basis of calculation	1,166,805	1,166,805	319,860	319,860	(145,458)	(145,458)
Statutory rate	9%	25%	9%	25%	9%	25%
Calculated taxes	(105,012)	(291,701)	(28,786)	(79,964)	13,092	36,365
Limitation on recognition (reversal) of tax credits	25,229	70,080	7,325	20,347	-	-
Taxes recognized in other comprehensive income	(79,783)	(221,621)	(21,461)	(59,617)	13,092	36,365


Credit risk fair value measurement of financial liabilities	1,662	1,662	(78,953)	(78,953)	-	-
Deemed cost of property, plant and equipment	38,897	38,897	38,057	38,057	39,202	39,202
Subtotal	40,559	40,559	(40,896)	(40,896)	39,202	39,202
Statutory rate	9%	25%	9%	25%	9%	25%
Calculated taxes	(3,650)	(10,140)	3,681	10,224	(3,528)	(9,801)

Total taxes recognized in other comprehensive income	(83,434)	(231,760)	(17,780)	(49,393)	9,564	26,564

10.6 Unrecognized deferred tax assets

As of December 31, 2019, the parent company has tax credits on tax loss carryforwards that were not recognized amounting to R$ 82,573 since it is not probable that taxable profits will be available in the future. This amount can be recognized in the future, according to the annual reviews of taxable profit projections.

Some subsidiaries have also income tax and social contribution credits on tax loss carryforwards that were not recognized because currently it is not probable that sufficient future taxable profits will be generated to absorb them. At December 31, 2019, the main subsidiaries that have such non-recognized income tax and social contribution credits are CPFL Renováveis (R$ 748,435), RGE Sul (R$ 71,894), Sul Geradora (R$ 72,711), CPFL Telecom (R$ 32,978), CPFL Serviços (R$6,188) and Jaguari Geração (R$ 2,467). These tax losses can be carried forward indefinitely.

F - 31

( 11 ) CONCESSION FINANCIAL ASSET

	Distribution	Transmission	Consolidated
As of December 31, 2016	5,193,511	180,333	5,373,844
Current	-	10,700	10,700
Noncurrent	5,193,511	169,633	5,363,144

Additions	972,254	52,211	1,024,465
Adjustment of expected cash flow	212,294	-	212,294
Adjustment - financial asset measured at amortized cost	-	27,807	27,807
Cash inputs - RAP	-	(15,677)	(15,677)
Disposals	(35,039)	-	(35,039)
Business combination	(12,338)	-	(12,338)

As of December 31, 2017	6,330,681	238,723	6,569,404
Current	-	23,736	23,736
Noncurrent	6,330,681	214,987	6,545,668

Transfer - contract assets	836,516	-	836,516
Transfer - intangible assets	(52,803)	-	(52,803)
Adjustment - fair value	362,073	-	362,073
Disposals	(46,318)	-	(46,318)
Adoption IFRS 15	-	(238,723)	(238,723)

As of December 31, 2018	7,430,149	-	7,430,149
Noncurrent	7,430,149	-	7,430,149

Transfer - contract assets	1,090,393	-	1,090,393
Transfer - intangible assets	(3,502)	-	(3,502)
Adjustment - fair value	296,037	-	296,037
Disposals	(33,361)	-	(33,361)

As of December 31, 2019	8,779,717	-	8,779,717
Noncurrent	8,779,717	-	8,779,717

The amount refers to the financial asset corresponding to the right established in the concession agreements of the energy distributors to receive cash by compensation upon the return of the assets to the granting authority at the end of the concession, measured at fair value.

According to the current tariff model, the remuneration for this asset is recognized in profit or loss upon billing to consumers and the realization occurs upon receipt of the electric energy bills. Moreover, the difference to adjust the balance at fair value (new replacement value - “VNR” - note 4) is recognized as a balancing item to the operating income account (note 27) in the statement of profit or loss.

F - 32

( 12 ) OTHER ASSETS

	Current		Noncurrent
	Dec 31, 2019	Dec 31, 2018	Dec 31, 2019	Dec 31, 2018
Advances - FUNCESP	13,562	3,929	6,797	6,797
Advances to suppliers	43,587	4,031	-	-
Pledges, funds and restricted deposits	1,431	77,442	569,733	524,461
Orders in progress	130,954	142,708	9,448	6,844
Services rendered to third parties	23,388	9,281	-	-
Energy pre-purchase agreements	-	-	10,432	25,390
Prepaid expenses	76,756	172,155	4,608	6,367
GSF Insurance Premium	6,488	13,701	-	5,782
Receivables - CDE	147,470	183,710	-	-
Advances to employees	20,640	22,287	-	-
Contract asset of transmission	-	23,535	-	226,117
Others	212,904	186,923	135,000	125,681
(-) Allowance for doubtful accounts (note 7)	(29,019)	(28,698)	-	-
Total	648,161	811,005	736,019	927,440

Pledges, funds and restricted deposits: guarantees offered for transactions conducted in the CCEE and short-term investments required by the subsidiaries’ loans agreements.

Orders in progress: encompass costs and revenues related to ongoing decommissioning or disposal of intangible assets and the service costs related to expenditure on projects in progress under the Energy Efficiency (“PEE”) and Research and Development (“P&D”) programs. Upon the closing of the respective projects, the balances are amortized against the respective liability recognized in Other Payables (note 24).

Receivables – CDE: refer to: (i) low income subsidies totaling R$ 16.944 (R$12,536 as of December 31, 2018). (ii) other tariff discounts granted to consumers amounting to R$130,516 (R$ 170,858 as of December 31, 2018) and (iii) tariff discounts – judicial injunctions totaling R$9 (R$ 317 as of December 31, 2018).

( 13 ) EQUITY METHOD INVESTEES

	Dec 31, 2019	Dec 31, 2018
Equity interests - equity method
By equity method of the Joint Venture	988,516	970,302
Fair value of assets, net	9,481	10,060
Total	997,997	980,362

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

	Share of equity		Share of profit (loss)
Joint ventures	Dec 31, 2019	Dec 31, 2018	2019	2018	2017
Baesa	156,185	175,189	750	791	11,849
Enercan	207,868	175,122	123,240	101,392	85,808
Chapecoense	381,219	378,558	140,949	127,250	120,651
EPASA	243,244	241,433	84,730	105,343	94,663
Fair value adjustments of assets, net	9,481	10,060	(579)	(579)	(579)
	997,997	980,362	349,090	334,198	312,390

13.1 Dividends and Interest on capital

At December 31, 2019 and 2018, the Group has the following amounts receivable from the joint ventures below, relating to dividends and interest on capital:

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	Dividend		Interest on own capital		Total
Investments	Dec 31, 2019	Dec 31, 2018	Dec 31, 2019	Dec 31, 2018	Dec 31, 2019	Dec 31, 2018
Investco	-	-	415	1,436	415	1,436
EPASA	-	-	-	-	-	-
Baesa	3,504	3	-	-	3,504	3
Enercan	59,289	65,010	-	-	59,289	65,010
Chapecoense	37,090	33,733	-	-	37,090	33,733
Total	99,883	98,746	415	1,436	100,297	100,182

13.2 Joint Ventures

Summarized financial information on joint ventures at December 31, 2019 and 2018 and income statement for the years ended December 31, 2019, 2018 and 2017 is as follows:

	December 31, 2019
Joint venture	Enercan	Baesa	Chapecoense	Epasa
Current assets	219,117	66,863	379,359	294,877
Cash and cash equivalents	77,290	18,315	240,645	96,130
Noncurrent assets	982,032	915,379	2,472,085	470,864

Current liabilities	390,817	72,383	451,803	93,512
Borrowings and debentures	133,548	-	138,759	35,660
Other financial liabilities	7,131	35,944	75,668	1,416
Noncurrent liabilities	383,699	285,269	1,652,152	216,233
Borrowings and debentures	255,756	-	913,308	115,842
Other financial liabilities	25,513	271,267	731,113	-
Equity	426,632	624,591	747,489	455,996

Net operating revenue	650,900	286,378	881,458	560,203
Operational costs and expenses	(192,780)	(201,494)	(195,973)	(319,024)
Depreciation and amortization	(49,110)	(50,832)	(124,244)	(34,690)
Interest income	5,573	1,850	16,309	3,990
Interest expense	(33,399)	(31,533)	(163,977)	(13,972)
Income tax expense	(126,313)	(1,124)	(136,830)	(38,983)
Profit (loss) for the year	252,941	2,999	276,370	158,839
Equity Interests and voting capital	48.72%	25.01%	51.00%	53.34%

	December 31, 2018
Joint venture	Enercan	Baesa	Chapecoense	Epasa
Current assets	208,326	68,956	345,737	327,084
Cash and cash equivalents	66,519	17,425	184,002	18,269
Noncurrent assets	1,033,320	966,664	2,604,162	502,618

Current liabilities	385,271	50,639	424,635	152,168
Borrowings and debentures	137,225	-	138,706	34,473
Other financial liabilities	5,869	34,832	74,156	1,346
Noncurrent liabilities	496,953	284,391	1,782,993	224,933
Borrowings and debentures	383,358	-	1,045,402	151,964
Other financial liabilities	26,936	272,079	734,630	-
Equity	359,422	700,590	742,271	452,601

Net operating revenue	591,875	321,142	863,861	840,005
Operational costs and expenses	(188,756)	(214,448)	(191,749)	(562,097)
Depreciation and amortization	(50,051)	(50,609)	(117,858)	(34,525)
Interest income	4,793	4,176	15,729	5,106
Interest expense	(46,042)	(53,946)	(191,818)	(17,491)
Income tax expense	(101,484)	(1,229)	(124,284)	(38,740)
Profit (loss) for the year	208,100	3,164	249,510	197,481
Equity Interests and voting capital	48.72%	25.01%	51.00%	53.34%

F - 34

	December 31, 2017
Joint venture	Enercan	Baesa	Chapecoense	Epasa
Net operating revenue	580,430	412,329	829,525	789,402
Operational costs and expenses	(273,339)	(265,955)	(186,638)	(518,352)
Depreciation and amortization	(52,773)	(50,621)	(126,811)	(35,640)
Interest income	32,849	4,906	24,639	6,102
Interest expense	(31,135)	(27,986)	(183,237)	(26,197)
Income tax expense	(88,229)	(25,442)	(123,307)	(39,892)
Profit (loss) for the year	176,113	47,385	236,570	177,458
Equity Interests and voting capital	48.72%	25.01%	51.00%	53.34%

Although holding more than 50% in EPASA and Chapecoense, CPFL Geração controls these investments jointly with other shareholders. The analysis of the classification of the type of investment is based on the Shareholders' Agreement of each joint venture.

The borrowings from the BNDES obtained by the joint ventures ENERCAN, BAESA and Chapecoense establish restrictions on the payment of dividends to subsidiary CPFL Geração above the mandatory minimum dividend of 25% without the prior consent of the BNDES.

13.3 Joint operation

Through its wholly-owned subsidiary CPFL Geração, the Company holds part of the assets of the Serra da Mesa hydropower plant, located on the Tocantins River, in Goiás State. The concession and operation of the hydropower plant belong to Furnas Centrais Elétricas S.A. In order to maintain these assets operating jointly with Furnas (joint operation), CPFL Geração was assured 51.54% of the installed power of 1,275 MW (657 MW) and the assured energy of mean 637.5 MW (mean 328.57 MW) until 2028.

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( 14 ) PROPERTY, PLANT AND EQUIPMENT

	Land	Reservoirs, dams and water mains	Buildings, construction and improvements	Machinery and equipment	Vehicles	Furniture and fittings	In progress	Total
At December 31, 2016	176,145	1,394,162	1,153,220	6,655,391	76,217	7,562	250,302	9,712,998
Historical cost	206,330	2,060,191	1,652,934	9,066,408	106,920	21,507	250,302	13,364,592
Accumulated depreciation	(30,185)	(666,028)	(499,714)	(2,411,017)	(30,704)	(13,945)	-	(3,651,594)

Additions	-	-	-	772	2,978	-	753,137	756,887
Disposals	(22)	(132)	(140)	(32,336)	(2,248)	(635)	(8,332)	(43,845)
Transfers	2,950	400	154,737	574,944	20,434	1,484	(754,948)	-
Transfers from/to other assets - cost	(1,893)	6,393	(154,880)	98,579	(126)	(330)	11,033	(41,224)
Depreciation	(8,004)	(79,276)	(59,736)	(431,393)	(18,055)	(1,332)	-	(597,795)
Write-off of depreciation	2	124	120	9,529	1,379	387	-	11,540
Transfers from/to other assets - depreciation	(683)	(2,413)	1,930	9,690	(8)	108	-	8,624
Business combination	-	-	-	-	(4,800)	-	-	(4,800)
Imparment	-	-	(474)	(14,787)	-	-	-	(15,261)

At December 31, 2017	168,494	1,319,257	1,094,777	6,870,389	75,771	7,245	251,192	9,787,125
Historical cost	207,365	2,066,850	1,652,178	9,693,512	122,540	22,026	251,192	14,015,662
Accumulated depreciation	(38,870)	(747,593)	(557,400)	(2,823,123)	(46,769)	(14,782)	-	(4,228,537)

Additions	-	-	-	-	-	-	296,165	296,165
Disposals	(8)	-	(7,908)	(16,434)	(3,517)	(31)	(8,478)	(36,376)
Transfers	20,181	151,754	41,464	101,468	12,250	793	(327,908)	-
Transfers from/to other assets - cost	(2,755)	-	(100,720)	106,775	-	6	(6,584)	(3,279)
Depreciation	(8,082)	(79,237)	(61,540)	(432,524)	(19,402)	(546)	-	(601,329)
Write-off of depreciation	2	-	-	8,180	2,032	44	-	10,259
Transfers from/to other assets - depreciation	(994)	-	20,714	(22,706)	(2)	-	-	(2,987)
Others	-	-	15	645	-	-	6,373	7,033

At December 31, 2018	176,839	1,391,775	986,800	6,615,793	67,135	7,512	210,760	9,456,614
Historical cost	224,783	2,218,604	1,585,723	9,905,396	131,549	23,039	210,760	14,299,854
Accumulated depreciation	(47,944)	(826,829)	(598,923)	(3,289,603)	(64,415)	(15,527)	-	(4,843,240)

Additions	-	-	-	-	-	-	301,459	301,459
Disposals	-	(5)	(31,080)	(31,033)	(33,045)	-	(8)	(95,171)
Transfers	603	15,882	51,413	111,804	7,358	449	(187,510)	-
Transfers from/to other assets - cost	(1,333)	(8,249)	(6,952)	12,987	-	(40)	1,924	(1,662)
Depreciation	(8,880)	(84,660)	(61,634)	(446,046)	(17,156)	(851)	-	(619,228)
Write-off of depreciation	-	5	2,231	17,616	21,846	-	-	41,698

At December 31, 2019	167,228	1,314,749	940,779	6,281,123	46,136	7,070	326,625	9,083,710
Historical cost	224,053	2,226,232	1,599,104	9,999,155	105,863	23,447	326,625	14,504,478
Accumulated depreciation	(56,825)	(911,483)	(658,325)	(3,718,031)	(59,727)	(16,377)	-	(5,420,768)

Average depreciation rate 2019	3.86%	3.89%	3.94%	4.54%	13.77%	5.80%
Average depreciation rate 2018	3.86%	3.65%	3.96%	4.45%	13.89%	3.70%
Average depreciation rate 2017	3.86%	3.93%	3.69%	4.53%	13.09%	8.31%

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The balance of construction in progress refers mainly to works in progress of the operating subsidiaries and/or those under development, especially for CPFL Renováveis’ projects, which has construction in progress of R$248,018 (R$ 139,614 as of December 31, 2018).

In accordance with IAS 23, the interest on borrowings taken by subsidiaries to finance the works is capitalized during the construction phase. During 2019, there were no capitalization and during 2018, R$10,591 (R$ 29,817 in 2017) was capitalized in the financial statements at a rate of 8.74% p.a. (8.80% p.a. in 2017).

In the financial statements, depreciation expenses are recognized in the statement of profit or loss in line itens “depreciation and amortization”.

At December 31, 2019, the total amount of property, plant and equipment pledged as collateral for borrowings, as mentioned in note 16, is R$ 3,957,132, mainly relating to the subsidiary CPFL Renováveis (R$ 3,908,099).

14.1 Impairment testing

For all the reporting years the Company assesses whether there are indicators of impairment of its assets that would require an impairment test. The assessment was based on external and internal information sources, taking into account fluctuations in interest rates, changes in market conditions and other factors.

In 2017, due to the changes in the Brazilian political, economic and energy scenario, the subsidiary CPFL Renováveis recognized an impairment loss of R$ 15,261 relating to property, plant and equipment of the Bio Baia Formosa and Solar Tanquinho projects. This impairment loss was recognized in the statement of profit or loss in line item “Other operating expenses” (note 27). For 2018 and 2019, based on the mentioned assessment of any indicators, it was not necessary to set upor a reverseprovision for impairment.

Such impairment was based on the assessment of the cash-generating units comprising fixed assets of subsidiaries which, separately, are not featured as an operating segment. Additionally, during 2019, 2018 and 2017 the Company did not change the form of aggregation of the assets for identification of these cash-generating units.

Fair value was measured by using the cost approach, a valuation technique that reflects the amount that would be required at present to replace the service capacity of an asset (normally referred to as the cost of substitution or replacement). A provision for impairment of assets, when applicable, is recognized owing to the unfavorable scenario for the business of these subsidiaries and is calculated based on their fair values, net of selling expenses.

For 2019 and 2018 no provision for impairment was required.

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( 15 ) INTANGIBLE ASSETS

15.1 Intangible assets

		Concession right
	Goodwill	Acquired in business combinations	Distribution infrastructure - operational	Distribution infrastructure - in progress	Public utilities	Other intangible assets	Total
As of December 31, 2016	6,115	4,466,516	5,550,502	666,008	27,324	59,147	10,775,613
Historical cost	6,152	7,602,941	11,987,109	666,008	35,840	183,138	20,481,188
Accumulated Amortization	(37)	(3,136,425)	(6,436,607)	-	(8,516)	(123,990)	(9,705,576)

Additions	-	-	-	1,898,434	-	9,344	1,907,778
Amortization	-	(286,215)	(639,292)	-	(1,419)	(9,390)	(936,318)
Transfer - intangible assets	-	-	814,643	(814,643)	-	-	-
Transfer - financial asset	-	-	131	(972,385)	-	-	(972,254)
Disposal and transfer - other assets	-	(16,244)	(91,214)	48,061	-	1,723	(57,674)
Corporate restructuring - note 12.6.1	-	(26,766)	(73,215)	-	-	-	(99,981)
Business combination	-	(5,129)	-	-	-	(47)	(5,176)
Impairment losses	-	(15,057)	(7,108)	-	-	-	(22,165)

As of December 31, 2017	6,115	4,117,105	5,554,447	825,476	25,904	60,777	10,589,824
Historical cost	6,152	7,558,645	11,442,528	825,476	35,840	174,407	20,043,048
Accumulated Amortization	(37)	(3,441,540)	(5,888,080)	-	(9,936)	(113,630)	(9,453,223)

Additions	-	-	-	-	-	18,670	18,670
Amortization	-	(286,858)	(703,511)	-	(1,419)	(8,989)	(1,000,777)
Transfer - intangible assets	-	-	723,813	-	-	-	723,813
Transfer - financial asset	-	-	52,803	-	-	-	52,803
Disposal and transfer - other assets	-	(63,187)	(43,419)	-	-	5,504	(101,102)
IFRS 15 adoption (note 3)	-	-	-	(825,476)	-	-	(825,476)
Others	-	5,130	-	-	-	47	5,177

As of December 31, 2018	6,115	3,772,188	5,584,136	-	24,485	76,009	9,462,935
Historical cost	6,152	7,495,458	11,909,149	-	35,840	217,542	19,664,141
Accumulated Amortization	(37)	(3,723,270)	(6,325,012)	-	(11,355)	(141,532)	(10,201,206)

Additions	-	-	-	-	-	19,147	19,147
Amortization	-	(288,438)	(761,884)	-	(1,419)	(16,840)	(1,068,581)
Transfer - contract assets	-	-	949,548	-	-	-	949,548
Transfer - financial asset	-	-	3,502	-	-	-	3,502
Disposal and transfer - other assets	-	-	(47,263)	-	-	1,663	(45,600)

As of December 31, 2019	6,115	3,483,750	5,728,040	-	23,065	79,981	9,320,953
Historical cost	6,152	7,495,458	12,814,937	-	35,840	238,352	20,590,739
Accumulated Amortization	(37)	(4,011,708)	(7,086,896)	-	(12,774)	(158,372)	(11,269,787)

The amortization of intangible assets is recognized as follows: (i) “depreciation and amortization” for amortization of distribution infrastructure intangible assets, use of public asset and other intangible assets; and (ii) “amortization of concession intangible asset” for amortization of the intangible asset acquired in business combination.

In conformity with IAS 23, the interest on borrowings taken by subsidiaries for construction financing is capitalized during the construction stage for qualifying assets. In the consolidated, for of the year of 2019, R$25,641 (R$ 18,015 in 2018) were capitalized at a rate of 8.09% (7.99% p.a.. in 2018).

15.2 Intangible asset acquired in business combinations

The breakdown of the intangible asset related to the right to operate the concessions acquired in business combinations is as follows:

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	Dec 31, 2019			Dec 31, 2018	Annual amortization rate
	Historical cost	Accumulated amortization	Net value	Net value	2019	2018	2017
Intangible asset - acquired in business combinations
Intangible asset acquired, not merged
Parent company
CPFL Paulista	304,861	(226,974)	77,888	87,873	3.28%	3.28%	3.28%
CPFL Piratininga	39,065	(27,629)	11,435	12,730	3.31%	3.32%	3.31%
RGE Sul (RGE)	3,768	(2,369)	1,399	1,575	4.68%	4.70%	4.25%
CPFL Geração	54,555	(39,179)	15,376	17,221	3.38%	3.38%	3.38%
Jaguari Geração	7,896	(4,391)	3,505	3,775	3.41%	3.41%	3.41%
CPFL Renováveis	3,653,906	(1,210,510)	2,443,397	2,602,622	4.36%	5.90%	5.39%
Subtotal	4,064,052	(1,511,051)	2,553,000	2,725,797

Intangible asset acquired and merged – Deductible
Subsidiaries
RGE Sul (RGE)	1,433,007	(1,023,268)	409,739	461,795	3.63%	3.63%	3.63%
CPFL Geração	426,450	(343,396)	83,053	93,020	2.34%	2.34%	2.34%
Subtotal	1,859,457	(1,366,664)	492,792	554,816

Intangible asset acquired and merged – Reassessed
Parent company
CPFL Paulista	1,074,026	(819,075)	254,952	287,156	3.00%	3.00%	3.00%
CPFL Piratininga	115,762	(81,875)	33,887	37,723	3.31%	3.31%	3.31%
Jaguari Geração	15,275	(9,296)	5,978	6,438	3.01%	3.01%	3.01%
RGE Sul (RGE)	366,887	(223,746)	143,141	160,256	4.67%	4.67%	4.67%
Subtotal	1,571,949	(1,133,992)	437,958	491,574

Total	7,495,458	(4,011,708)	3,483,750	3,772,188

The intangible asset acquired in business combinations is associated to the right to operate the concessions and comprises:

- Intangible asset acquired, not merged

Refers basically to the intangible asset from acquisition of the shares held by noncontrolling interests prior to adoption of IFRS 3.

- Intangible asset acquired and merged

Refers to the intangible asset from the acquisition of subsidiaries that were merged into the respective equity, without application of CVM Instructions No. 319/99 and No. 349/01, that is, without segregation of the amount of the tax benefit.

- Intangible asset acquired and merged – Reassessed

In order to comply with ANEEL requirements and avoid the amortization of the intangible asset resulting from the merger of parent company causing a negative impact on dividends paid to noncontrolling interests, the subsidiaries applied the concepts of CVM Instructions No. 319/99 and No. 349/01 to the intangible asset. A reserve was therefore recognized to adjust the intangible, against a special intangible reserve on the merger of equity in each subsidiary, so that the effect of the transaction on the equity reflects the tax benefit of the merged intangible asset. These changes affected the Company's investment in subsidiaries, and in order to adjust this, a non-deductible intangible asset was recognized for tax purposes.

15.3 Impairment testing

In 2017, the subsidiary CPFL Renováveis recognized a loss of R$ 5,176, relating to intangible assets acquired in the business combination of the Pedra Cheirosa I and Bio Formosa projects. For 2018 and 2019, based on the mentioned assessment of any indicators, it was not necessary to set upor a reverseprovision for impairment.

The provision for impairment were based on the assessment of the cash-generating units comprising intangible assets of those subsidiaries which, separately, are not featured as an operating segment.

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15.4 Corporate restructuring in 2019

Partial spin-off of Nect

On September 30, 2019, the partial spin-off of Nect Serviços Administrativos de Infraestrutura Ltda. - “CPFL Infra” (formerly Nect Serviços Administrativos Ltda.) into four specific business segments (Supplies, Human Resources, Financial Services and Infrastructure) was approved, together with the merger of the spun-off portion into the three new companies; namely, CPFL Supre, CPFL Finanças and CPFL Pessoas. The purpose of the transaction is to improve the quality of services provided by the companies, through specialization in its activities. The net assets in this transaction were appraised at R$16,746 and did not have any effect on the consolidated financial statements of the group or result in any change in the equity interest of the companies.

( 16 ) CONTRACT ASSETS

	Distribution	Transmission	Total
At December 31, 2017

Adoption of IFRS 15	825,476	-	825,476
Additions	1,787,588	-	1,787,588
Transfer - intangible assets in service	(723,813)	-	(723,813)
Transfer - financial assets	(836,516)	-	(836,516)
Disposal and transfer - other assets	(6,303)	-	(6,303)

At December 31, 2018	1,046,433	-	1,046,433

Reclassification from other assets	-	249,652	249,652
Additions	2,061,715	20,970	2,082,685
Transfer - intangible assets in service	(949,548)	-	(949,548)
Transfer - financial assets	(1,090,393)	-	(1,090,393)
Monetary adjustment	-	31,725	31,725
Cash inputs - RAP	-	(23,344)	(23,344)

At December 31, 2019	1,068,207	279,003	1,347,210
Current	-	24,387	24,387
Noncurrent	1,068,207	254,616	1,322,822

Contractual asset of distribution companies: Refers to concession infrastructure assets of the distribution companies during the construction period.

Contract asset of transmission companies:refers to the right to receive the “Permitted Annual Revenue – RAP” over the concession period as well as an indemnity at the end of the concession of the transmission subsidiaries.

( 17 ) TRADE PAYABLES

F - 40

	Dec 31, 2019	Dec 31, 2018
Current
System service charges	2,707	62,674
Energy purchased	2,288,441	1,607,116
Electricity network usage charges	250,600	205,656
Materials and services	554,940	368,344
Energy from the Free Market	163,492	154,296
Total	3,260,180	2,398,085

Noncurrent
Energy purchased	359,944	333,036

F - 41

( 18 ) BORROWINGS

The movements in borrowings are as follows:

	At December 31, 2017	Raised	Repayment	Interest, inflation adjustment and Fair value adjustment	Exchange rates	Interest paid	At December 31, 2018
Measured at cost
Local currency
Fixed Rate	900,257	166,404	(173,528)	53,283	-	(53,641)	892,776
Floating Rate
TJLP and TLP	3,449,468	1,315,898	(442,504)	288,171	-	(262,744)	4,348,289
Selic	140,099	-	(33,875)	11,251	-	(3,358)	114,117
CDI	1,541,278	23,359	(1,112,713)	72,957	-	(138,609)	386,272
IGP-M	57,291	-	(10,511)	9,788	-	(4,679)	51,889
UMBNDES	2,293	-	(500)	515	-	(156)	2,152
Others	74,740	32,418	(45,807)	6,477	-	(1,426)	66,403
Total at cost	6,165,427	1,538,079	(1,819,438)	442,442	-	(464,613)	5,861,896

*Borrowing costs ()**	(31,816)	(35,984)	-	10,607	-	-	(57,193)

Measured at fair value
Foreign currency
Dollar	4,698,184	2,666,880	(3,289,857)	170,383	774,483	(164,965)	4,855,108
Euro	218,814	879,500	(215,824)	3,348	(1,873)	(4,466)	879,499
Fair value adjustment	(58,552)	-	-	(44,799)	-	-	(103,351)
Total at fair value	4,858,446	3,546,380	(3,505,681)	128,932	772,610	(169,431)	5,631,255

Total	10,992,057	5,048,475	(5,325,119)	581,980	772,610	(634,044)	11,435,958
Current	3,589,607						2,446,113
Noncurrent	7,402,450						8,989,846

	At December 31, 2018	Raised	Repayment	Interest, inflation adjustment and Fair value adjustment	Exchange rates	Interest paid	At December 31, 2019
Measured at cost
Local currency
Fixed Rate	892,776	-	(177,669)	48,661	-	(52,370)	711,398
Floating Rate
TJLP	3,158,119	-	(435,016)	243,332	-	(222,102)	2,744,332
TLP (IPCA)	1,190,169	379,000	-	102,519	-	(62,650)	1,609,038
Selic	114,117	-	(36,830)	8,441	-	(2,655)	83,073
CDI	386,272	476,000	(679,021)	46,756	-	(49,995)	180,012
IGP-M	51,889	-	(11,142)	5,935	-	(4,077)	42,605
UMBNDES	2,152	-	(540)	213	-	(131)	1,694
Others	66,403	-	(26,354)	2,209	-	(2,482)	39,777
Total at cost	5,861,896	855,000	(1,366,572)	458,066	-	(396,462)	5,411,928

*Borrowing costs ()**	(57,193)	(8,747)	-	8,256	-	-	(57,684)

Measured at fair value
Foreign currency
Dollar	4,855,108	726,314	(1,542,785)	148,189	142,957	(151,366)	4,178,417
Euro	879,499	-	(47,004)	6,824	14,217	(6,844)	846,692
Fair value adjustment	(103,351)	-	-	87,295	-	-	(16,056)
Total at fair value	5,631,255	726,314	(1,589,789)	242,308	157,174	(158,210)	5,009,052

Total	11,435,958	1,572,567	(2,956,361)	708,630	157,174	(554,672)	10,363,296
Current	2,446,113						2,776,193
Noncurrent	8,989,846						7,587,102

(*) In accordance with IFRS 9, this refers to the fundraising costs attributable to issuance of the respective debts.

The detail on borrowings are as follows:

F - 42

Category	Annual interest		December 31, 2019	December 31, 2018	Maturity range	Collateral
Measured at cost - Local Currency
Fixed rate
FINEM	Fixed rate from 2.5% to 8%	(a)	264,093	418,336	2011 to 2024	(i) CPFL Energia guarantee (ii) Liens on equipment and receivables (iii) Pledge of shares of SPE, authorized by ANEEL and receivables of operation contracts (iv) guarantee of Bioenergia S.A., CPFL Renováveis, CPFL Energia and State Grid.
FINAME	Fixed rate from 2.5% to 10%	(a)	54,328	48,672	2012 to 2025	(i) Liens on equipment (ii) Guarantee of CPFL Renováveis(iii) CPFL Energia guarantee (iv) Liens on assets
FINEP	Fixed rate from 3.5% to 5%		944	6,576	2013 to 2021	Bank guarantee
BNB	Fixed rate of 9.5% to 10.14%		392,033	419,191	2027 to 2037	(i) Liens on equipment and receivables (ii) Pledge of shares of SPE, authorized by ANEEL and receivables of operation contracts (iii) SIIF Énergies do Brasil and BVP S.A guarantee
			711,398	892,776
Floating rate
TJLP
FINEM	TJLP and TJLP + from 1.72% to 5.5%	(b)	2,721,358	3,128,625	2009 to 2033	(i) Pledge of receivables, equipment and assignment of credit and concession rights authorized by ANEEL and shares of SPE (ii) Liens on equipment and receivables (iii) guarantee of CPFL Renováveis, CPFL Energia and State Grid; (viii) Bank guarantee
FINAME	TJLP + 2.2% to 4.2%	(b)	14,853	20,935	2017 to 2027	CPFL Energia guarantee, Liens on equipment and receivables
FINEP	TJLP and TJLP + 5%		4,284	3,491	2016 to 2024	Bank guarantee
Bank loans	TJLP + 2.99% to 3.1%		3,837	5,069	2005 to 2023	CPFL Energia guarantee
			2,744,331	3,158,119
IPCA
FINEM	IPCA + 4.74% to 4.80%		1,609,038	1,190,169	2020 to 2028	CPFL Energia guarantee and receivables
SELIC
FINEM	SELIC + 2.19% to 2.66%	(c)	79,131	108,752	2015 to 2022	SGBP and CPFL Energia guarantee and receivables
FINAME	SELIC + 2.70% to 3.90%		3,943	5,365	2016 to 2022	CPFL Energia guarantee and liens on equipment and receivables
			83,073	114,117
CDI
Bank loans	(i) 105% of CDI (ii) CDI - 1,25% to + 1,90%	(c)	180,012	208,384	2012 to 2023	(i) CPFL Energia and CPFL Renováveis guarantee (ii) Redeemable preferred shares
Promissory note	103,4% CDI	(c)	-	177,888	2019	CPFL Energia guarantee
			180,012	386,272

IGPM
Bank loans	IGPM + 8.63%		42,605	51,889	2023	(i) Liens on equipment and receivables (ii) Pledge of shares of SPE and rights authorized by ANEEL and receivables of operation contracts

UMBNDES
Bank loans	UMBNDES + from 1.99% to 5%		1,694	2,152	2006 to 2023	CPFL Energia guarantee
Other
Other	RGR		39,777	66,403	2007 to 2023	Promissory notes, bank guarantee and receivables

Total - Local currency			5,411,928	5,861,897

*Borrowing costs ()**			(57,684)	(57,193)


Measured at fair value - Foreign currency
Dollar
Bank loans (Law 4.131)	US$ + Libor 3 months + from 0.80% to 1.55%		975,333	1,866,418	2017 to 2022	CPFL Energia guarantee and promissory notes
Bank loans (Law 4.131)	US$ + from 1.96% to 4.32%		3,203,083	2,988,689	2017 to 2022	CPFL Energia guarantee and promissory notes
			4,178,417	4,855,108
Euro
Bank loans (Law 4.131)	Euro + from 0.42% to 0.96%		846,692	879,499	2019 to 2022	CPFL Energia guarantee and promissory notes

Fair value adjustment			(16,056)	(103,351)

Total in foreign currency			5,009,052	5,631,255

Total			10,363,296	11,435,958

(*) In accordance with IFRS 9, this refers to borrowing costs directly attributable to the issuance of the respective debts., measured at cost.
The subsidiaries hold swaps converting the operating cost of currency variation to interest tax variation in reais.For further information about the considered rates, see note 35.
Effective rate:
(a) 30% to 70% of CDI	(b) 60% to 110% of CDI		(c) 100% to 130% of CDI

As segregated in the tables above, in conformity with IFRS 9, the Group classified their debts as (i) financial liabilities (measured at amortized cost), and (ii) financial liabilities measured at fair value through profit or loss.

The objective of the classification as financial liabilities of borrowings measured at fair value is to compare the effects of the recognition of income and expenses derived from fair value adjustment of derivatives, debt-related derivatives, in order to obtain more relevant and consistent accounting information, reducing the accounting mismatching.

F - 43

Changes in the fair values of these borrowings are recognized in the finance income / cost of the Group, except for the variation of the fair value of credit risk calculation, which is recorded in other comprehensive income. At December 31, 2019, the accumulated gains of R$16,056 (R$ 103,351 at December 31, 2018) to record the borrowing at fair value, adding the unrealized gains of R$ 24,178 (losses of R$ 65,678 at December 31, 2018) of fair value adjustments of the derivative financial instruments contracted as a hedge against foreign exchange variations (note 35), resulted in a total unrealized net gain of R$ 40,234 (R$37,673 at December 31, 2018).

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

2021		2,587,780
2022		1,521,850
2023		894,184
2024		495,832
2025		471,073
2026 to 2030		1,319,711
2030 to 2034		227,898
2035 to 2039		66,074
Subtotal		7,584,402
Fair value adjustment		2,700
Total		7,587,102

The main ratios used for inflation adjustment of the borrowings and the indebtedness profile in local and foreign currency, already considering the effects of the derivative instruments, are shown below:

	Accumulated variation (%)
Index	2019	2018	Dec 31, 2019	Dec 31, 2018
IGP-M	7.30	7.54	0.2	0.5
TJLP and TLP	6.3 and 7.69	6.72 and 7.42	26.0	38.0
CDI	5.97	6.40	62.1	52.6
Others			11.7	8.9
			100.00	100.00

Main borrowings in the year:

Bank / credit issue

Total approved

Released in 2019

Released net of fundraising costs

Interest

Repayment

Utilization

Interest rate

Annual efective rate

Local Currency:

CDI - promissory note

CPFL Paulista

351,000

350,649

Single installment

Single installment in december 2019

Working capital

103.4% of CDI

104.95% of CDI

CPFL Piratininga

125,000

124,818

Single installment

Single installment in december 2019

Working capital

103.4% of CDI

104.95% of CDI

IPCA - BNDES

CPFL Paulista

953,392

100,000

98,124

Monthly

Monthly from april 2020

Investment plan

IPCA + 4.74%

IPCA + 5.43%

CPFL Piratininga

347,264

55,000

53,968

Monthly

Monthly from april 2020

Investment plan

IPCA + 4.80%

IPCA + 5.45%

RGE

1,133,024

154,000

151,110

Monthly

Monthly from april 2020

Investment plan

IPCA + 4.74%

IPCA + 5.43%

CPFL Santa Cruz

174,954

70,000

68,686

Monthly

Monthly from april 2020

Investment plan

IPCA + 4.80%

IPCA + 5.53%

Foreign currency

Dollar Law 4131

CPFL Santa Cruz

28,000

Biannual

Single installment in march 2022

Working capital

USD + 3.06%

CPFL Geração

13,500

Biannual

Single installment in september 2020

Working capital

USD + 1.96%

CPFL Santa Cruz

14,000

Biannual

Single installment in september 2020

Working capital

USD + 1.96%

CPFL Piratininga

43,000

Biannual

Single installment in september 2020

Working capital

USD + 1.96%

CPFL Paulista

309,814

Biannual

Single installment in september 2020

Working capital

USD + 2.17%

CPFL Paulista

318,000

Biannual

Single installment in september 2020

Working capital

USD + 1.96%

3,810,948

1,581,314

1,573,670

(a) the agreement has no restrictive covenants

RESTRICTIVE COVENANTS

Borrowings raised by Group companies require the compliance with certain restrictive financial clauses, under penalty of restriction in the distribution of dividends and/or advance maturity of the related debts. Furthermore, failure to comply with the obligations or restrictions mentioned may result in default in relation to other contractual obligations (cross default), depending on each borrowing agreement.

F - 44

The calculations are made on an annual or semiannual basis, as appropriate. As the maximum and minimum ratios vary among the contracts, we present below the most critical parameters of each ratio, considering all contracts in effect at December 31, 2019:

Ratios required for the individual financial statements of its subsidiaries CPFL Paulista, CPFL Piratininga, CPFL Santa Cruz and RGE, which own contracts:

Net indebtedness divided by EBITDA maximum between 3.50 and 3.75 and
Net indebtedness divided by the sum of Equity and Net indebtedness maximum of 0.9.

Ratios required for the individual of subsidiaries financial statements of CPFL Renováveis owners of the contract:

Debt Service Coverage Ratio minimum between 1.0 and 1.3.
Company capitalization ratio minimum between 25% and 30%.
General Indebtedness Ratio maximum of 80%.

Ratios required in the consolidated financial statements of CPFL Renováveis

Net indebtedness divided by EBITDA maximum of 3.75.
Net indebtedness divided by the sum of Equity and Net indebtedness maximum of 0.55.

Ratios required for the consolidated financial statements of CPFL Energia

Net indebtedness divided by EBITDA maximum of 3.75.
Net indebtedness divided by the sum of Equity and Net indebtedness maximum of 0.72.
EBITDA divided by the financial income (expenses) minimum of 2.25.

Ratio required in the consolidated financial statements of State Grid Brazil Power Participações S.A.

Equity divided by Total Assets (disregarding the effects of IFRIC 12) minimum of 0.3.

For purposes of determining covenants, the definition of EBITDA at the Company takes into consideration mainly the consolidation of subsidiaries, associates and joint ventures based on the Company’s direct or indirect interests in those companies (for both EBITDA and assets and liabilities).

The Group’s management monitors these ratios on a systematic and constant basis, so that all conditions are met. As of December 31, 2019, the Company was in compliance with all covenants and financial and non-financial clauses.

( 19 ) DEBENTURES

The movements in debentures are as follows:

F - 45

	At December 31, 2017	Raised	Repayment	Interest, inflation adjustment and market to mark	Exchange rates	At December 31, 2018
Category	At December 31, 2017	Raised	Repayment	Interest, inflation adjustment and market to mark	Exchange rates	At December 31, 2018
Measured at cost - Floating rate
TJLP	495,408	-	(46,768)	37,539	(5,080)	481,099
CDI	7,446,556	4,163,000	(4,832,370)	592,746	(652,185)	6,717,747
IPCA	1,311,432	-	-	118,026	(62,030)	1,367,428
Total at cost	9,253,396	4,163,000	(4,879,138)	748,311	(719,295)	8,566,274

*Borrowing costs ()**	(76,870)	(17,261)	-	34,334	-	(59,796)

Measured at fair value - Floating rate
IPCA	-	416,600	-	10,389	-	426,989
Fair value adjustment	-	-	-	7,378	-	7,378
Total at fair value	-	416,600	-	17,767	-	434,367

Total	9,176,527	4,562,339	(4,879,138)	800,412	(719,295)	8,940,845
Current	1,703,073					917,352
Noncurrent	7,473,454					8,023,493

	At December 31, 2018	Raised	Repayment	Interest, inflation adjustment and market to mark	Exchange rates	At December 31, 2019
Category	At December 31, 2018	Raised	Repayment	Interest, inflation adjustment and market to mark	Exchange rates	At December 31, 2019
Measured at cost - Floating rate
TJLP	481,099	-	(70,761)	33,384	(4,732)	438,990
CDI	6,717,747	3,688,000	(4,000,383)	421,070	(489,966)	6,336,467
IPCA	1,367,428	-	(109,106)	123,090	(60,504)	1,320,909
Total at cost	8,566,274	3,688,000	(4,180,250)	577,544	(555,202)	8,096,368

*Borrowing costs ()**	(59,796)	(3,541)	-	21,122	-	(42,215)

Measured at fair value - Floating rate
IPCA	426,989	-	-	40,556	(22,606)	444,939
Fair value adjustment	7,378	-	-	39,808	-	47,186
Total at fair value	434,367	-	-	80,364	(22,606)	492,125

Total	8,940,845	3,684,459	(4,180,250)	679,030	(577,808)	8,546,278
Current	917,352					682,582
Noncurrent	8,023,493					7,863,696

(*) In accordance with IFRS 9 this refers to borrowing costs directly attributable to the issuance of the respective debts.

��

The detail on debentures are as follows :

Category	Annual Interest		December 31, 2019	December 31, 2018	Maturity range	Collateral

Measured at cost - Floating rate

TJLP	TJLP + 1%	(c)	438,990	481,099	2009 to 2029	Liens
CDI	(i) From 103.6% to 109.5% of CDI (ii) CDI + 0.75% to 0.83%	(a)	5,339,824	5,858,319	2018 to 2025	CPFL Energia guarantee
CDI	From 104.75% to 110% of CDI	(a)	996,644	859,428	2015 to 2022	No guarantee
IPCA	IPCA + from 4.42% to 5.8%	(b)	1,320,909	1,367,428	2019 to 2027	CPFL Energia guarantee
			8,096,368	8,566,274

	*Borrowing costs ()**		(42,215)	(59,796)

Measured at fair value - Floating rate
IPCA	IPCA + 5.80%	(b)	444,939	426,989	2024 to 2026	CPFL Energia guarantee

	Fair value adjustment		47,186	7,378

	Total consolidated		8,546,278	8,940,845

Some debentures hold swaps converting IPCA variation to CDI variation.
For further information about the considered rates, see note 35.
Effective rates:
(a) From 104.68% to 110.77% of CDI \| CDI + from 0.76% to 0.89%
(b) IPCA + 4.84% to 6.31%
(c) TJLP + 3.48%

(*) In accordance with IFRS 9 this refers to borrowing costs directly attributable to the issuance of the respective debts.

F - 46

As shown in the table above, the Company, in compliance with IFRS 9, classified its debentures as (i) financial liabilities measured at amortized cost; and (ii) financial liabilities measured at fair value through profit or loss.

The classification of debentures measured at fair value as financial liabilities is aimed at matching the effects of the recognition of revenues and expenses derived from the fair value adjustment of hedging derivatives linked to such debentures, in order to obtain a more relevant and consistent accounting information.

The changes in the fair values of these debentures are recognized in the Company’s finance income (costs), except for the component of credit risk calculation, which is recognized in other comprehensive income. As of December 31, 2019, the accumulated losses obtained from the fair value adjustment of such debentures amounted to R$ 47,186 (R$ 7,378 as of December 31, 2018) which, offset by the gains obtained from the fair value adjustment of the derivative instruments of R$70,517 (R$ 21,012 as of December 31, 2018), undertaken to hedge the interest rate changes (note 35), generated a total gain of R$23,331 (R$ 13,634 as of December 31, 2018).

The maturities of the debentures’ principal recognized in noncurrent liabilities are scheduled as follows:

2021		1,191,059
2022		1,732,136
2023		2,321,213
2024		1,932,174
2025		404,271
2026 to 2030		235,657
Subtotal		7,816,510
Fair value adjustment		47,186
Total		7,863,696

Main debentures issuances during the year

R$ thousand

Category

Issue

Quantity issued

Released in 2019

Released net of fundraising costs

Interests

Repayment

Annual interests

Effective annual rate

Local currency - CDI

CPFL Brasil

5th issue
1st serie

105,000

104,834

Biannual

single installment in december 2019

103.6% of CDI

106.82% of CDI

CPFL Brasil

5th issue
2nd serie

220,000

219,652

Biannual

2 annual installments from january 2023

108.25% of CDI

109.06% of CDI

CPFL Paulista

10th issue

1,380,000

1,378,596

Biannual

2 annual installments from may 2023

107% of CDI

107.84% of CDI

CPFL Piratininga

11th issue

215,000

214,697

Biannual

2 annual installments from may 2023

107% of CDI

107.84% of CDI

CPFL Santa Cruz

3rd issue

190,000

189,703

Biannual

Single installment in may 2022

107% of CDI

107.84% of CDI

RGE

10th issue

740,000

739,206

Biannual

2 annual installments from may 2023

107% of CDI

107.84% of CDI

CPFL Renováveis

9th issue
1st serie

30,000

300,000

299,955

Biannual

Single installment in november 2022

104.75% of CDI

105.45% of CDI

CPFL Renováveis

9th issue
2nd serie

53,800

538,000

537,815

Biannual

3 semiannual installments from november 2022

106% of CDI

106.66% of CDI

3,688,000

3,684,459

The funds obtained from the main issuances were used in the investment plan, refinancing of debts and improvement of working capital of subsidiaries.

Pre-payment

In 2019, R$3,506,174 (R$ 3,247,401 as of December 31, 2018) were paid of issue of debentures, whose due date were November 2028.

F - 47

RESTRICTIVE COVENANTS

The debentures issued by the Group companies require the compliance with certain financial covenants.

Ratios required in the consolidated financial statements of CPFL Energia

Net indebtedness divided by EBITDA maximum of 3.75.
EBITDA divided by Finance Income (Expenses) minimum of 2.25.

( 20 ) PRIVATE PENSION PLAN

The subsidiaries sponsor supplementary retirement and pension plans for their employees. The main characteristics of these plans are as follows:

20.1 Characteristics

CPFL Paulista

The plan currently in force for the employees of the subsidiary CPFL Paulista through FUNCESP is a Mixed Benefit Plan, with the following characteristics:

i.	Defined Benefit Plan (“BD”) – in force until October 31, 1997 – a defined benefit plan, which grants a Proportional Supplementary Defined Benefit (“BSPS”), in the form of a lifetime income convertible into a pension, to participants enrolled prior to October 31, 1997, the amount being defined in proportion to the accumulated past service time up to that date, based on compliance with the regulatory requirements for granting. The total responsibility for coverage of actuarial deficits of this plan falls to the subsidiary.
ii.	Mixed model, as from November 1, 1997, which covers:
		benefits for risk (disability and death), under a defined benefit plan, in which the subsidiary assumes responsibility for Plan’s actuarial deficit, and
		scheduled retirement, under a variable contribution plan, consisting of a benefit plan, which is a defined contribution plan up to the granting of the income, and does not generate any actuarial liability for the subsidiary CPFL Paulista. The benefit plan only becomes a defined benefit plan, consequently generating actuarial responsibility for the subsidiary, after the granting of a lifetime income, convertible or not into a pension.

Additionally, the subsidiary’s Managers may opt for a Free Benefit Generator Plan – “PGBL” (defined contribution), operated by either Banco do Brasil or Bradesco.

CPFL Piratininga

As a result of the spin-off of Bandeirante Energia S.A. (subsidiary’s predecessor), the subsidiary CPFL Piratininga assumed the responsibility for the actuarial liabilities of that company’s employees retired and terminated until the date of spin-off, as well as for the obligations relating to the active employees transferred to CPFL Piratininga.

On April 2, 1998, the Secretariat of Pension Plans – “SPC” approved the restructuring of the retirement plan previously maintained by Bandeirante, creating a "Proportional Supplementary Defined Benefit Plan – BSPS”, and a "Mixed Benefit Plan", with the following characteristics:

Defined Benefit Plan (“BD”) - in force until March 31, 1998 – a defined benefit plan, which grants a Proportional Supplementary Defined Benefit (BSPS), in the form of a lifetime income convertible into a pension to participants enrolled until March 31, 1998, in an amount calculated in proportion to the accumulated past service time up to that date, based on compliance with the regulatory requirements for granting. In the event of death while working or the onset of a disability, the benefits incorporate the entire past service time. CPFL Piratininga has full responsibility for covering the actuarial deficits of this Plan.

F - 48

ii.

Defined Benefit Plan - in force after March 31, 1998 – defined-benefit type plan, which grants a lifetime income convertible into a pension based on the past service time accumulated after March 31, 1998, based on 70% of the average actual monthly salary for the last 36 months of active service. In the event of death while working or the onset of a disability, the benefits incorporate the entire past service time. The responsibility for covering the actuarial deficits of this Plan is equally divided between CPFL Piratininga and the participants.

iii.

Variable Contribution Plan – implemented together with the Defined Benefit plan effective after March 31, 1998. This is a defined-contribution type pension plan up to the granting of the income, and generates no actuarial liability for CPFL Piratininga. The pension plan only becomes a Defined Benefit type plan after the granting of the lifetime income, convertible (or not) into a pension, and accordingly starts to generate actuarial liabilities for the subsidiary.

Additionally, the subsidiary’s Managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Bradesco.

RGE Sul (RGE)

The subsidiary RGE has retirement and pension plans for its employees and former employees managed by Fundação Famíllia Previdência, former Fundação CEEE, comprising:

(i)

“Plan 1” (“Plano Único RGE”): A “defined benefit” plan with benefit level equal to 100% of the inflation adjusted average of the last salaries, deducting the presumed benefit from the Social Security, with a Segregated Net Asset. that is closed to new participants since 1997. This plan was recorded at the dissolved Rio Grande Energia S.A. until the merger of the distribution companies approved on December 31, 2018, as mentioned in note 15.4; and

(ii)

“Plan 2” (“Plano Único RGE”): A “defined benefit” plan that is closed to new participants since February 2011. The subsidiary’s contribution matches the contribution from the benefitted employees, in the proportion of one for one, including as regards the Fundação’s administrative funding plan.

For employees hired after the closing of the plans of Fundação Família Previdência, “defined contribution” private pension plans were implemented, being Bradesco Vida e Previdência for employees hired between 1997 and 2018 by the dissolved Rio Grande Energia S.A., and Itauprev for employees hired by RGE as from 2011, as well as for new employees to be hired after the event of merger of the distribution companies.

CPFL Santa Cruz

With the 2017 merger event, the company’s official plan is the CMSPREV, managed by IHPREV Fundo de Pensão. The same plan was maintained for employees that had the benefits plan managed by BB Previdência - Fundo de Pensão from Banco do Brasil.

CPFL Geração

The employees of the subsidiary CPFL Geração participate in the same pension plan as CPFL Paulista.

In addition, managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Bradesco.

F - 49

20.2 Changes in the defined benefit plans

	December 31, 2019

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE Sul (RGE)		Total
	CPFL Paulista	CPFL Piratininga	CPFL Geração	*Plan 1*	*Plan 2*	Total
Present value of actuarial obligations	6,164,035	1,773,089	152,254	464,335	681,363	9,235,076
Fair value of plan's assets	(4,517,265)	(1,353,050)	(105,914)	(466,390)	(503,867)	(6,946,486)
Present value of net obligations (fair value of assets)	1,646,770	420,039	46,340	(2,055)	177,496	2,288,590
Effect of asset ceiling	74,849	-	-	2,055	-	76,904
Net actuarial liability recognized in the statement of financial position	1,721,619	420,039	46,340	-	177,496	2,365,494

	December 31, 2018
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul (RGE)	Total
	CPFL Paulista	CPFL Piratininga	CPFL Geração	*Plan 1*	*Plan 2*	Total
Present value of net obligations (fair value of assets)	5,123,238	1,416,391	119,964	382,993	553,493	7,596,079
Fair value of plan's assets	(4,215,431)	(1,205,647)	(98,836)	(413,043)	(463,571)	(6,396,529)
Net actuarial liability recognized in the statement of financial position	907,807	210,744	21,129	(30,050)	89,922	1,199,550
Effect of asset ceiling	-	-	-	30,050	-	30,050
Net actuarial liability recognized in the statement of financial position	907,807	210,744	21,129	-	89,922	1,229,600

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

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE Sul (RGE)		Total
	CPFL Paulista	CPFL Piratininga	CPFL Geração	**Plan 1 ()***	*Plan 2*	Total
Present value of actuarial obligations at December 31, 2016	4,524,008	1,202,596	108,486	352,879	480,081	6,668,050
Gross current service cost	707	3,153	73	270	2,153	6,356
Interest on actuarial obligations	476,613	127,561	11,431	37,395	50,927	703,927
Participants' contributions transferred during the year	37	2,044	-	302	990	3,373
Actuarial loss: effect of changes in demographic assumptions	225	328	14	326	16,490	17,383
Actuarial loss: effect of changes in financial assumptions	(6,993)	(3,586)	(372)	(45)	8,153	(2,843)
Benefits paid during the year	(379,536)	(84,634)	(8,831)	(25,203)	(34,501)	(532,705)
Present value of actuarial obligations at December 31, 2017	4,615,061	1,247,462	110,801	365,924	524,293	6,863,541
Gross current service cost	835	4,365	78	175	2,790	8,243
Interest on actuarial obligations	421,083	114,628	10,109	33,552	48,218	627,590
Participants' contributions transferred during the year	24	2,078	-	395	842	3,339
Actuarial loss: effect of changes in demographic assumptions	-	-	-	-	345	345
Actuarial loss: effect of changes in financial assumptions	485,142	135,540	8,409	8,921	12,774	650,786
Benefits paid during the year	(398,907)	(87,682)	(9,433)	(25,974)	(35,769)	(557,765)
Present value of actuarial obligations at December 31, 2018	5,123,238	1,416,391	119,964	382,993	553,493	7,596,079
Gross current service cost	925	5,449	84	185	2,352	8,995
Interest on actuarial obligations	449,173	125,059	10,507	34,342	48,796	667,877
Participants' contributions transferred during the year	-	1,886	-	620	1,136	3,642
Actuarial loss: effect of changes in demographic assumptions	(2,900)	(77)	(165)	-	-	(3,142)
Actuarial loss: effect of changes in financial assumptions	1,037,048	321,011	31,516	73,759	113,836	1,577,170
Benefits paid during the year	(443,449)	(96,628)	(9,652)	(27,564)	(38,250)	(615,543)
Present value of actuarial obligations at December 31, 2019	6,164,035	1,773,089	152,254	464,335	681,363	9,235,076

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE Sul (RGE)		Total
	CPFL Paulista	CPFL Piratininga	CPFL Geração	**Plan 1 ()***	*Plan 2*	Total
Fair value of actuarial assets at December 31, 2016	(3,723,563)	(1,062,638)	(89,533)	(347,906)	(405,251)	(5,628,892)
Expected return during the year	(392,819)	(113,470)	(9,437)	(37,412)	(43,258)	(596,396)
Participants' contributions transferred during the year	(37)	(2,044)	-	(302)	(990)	(3,373)
Sponsors' contributions	(50,308)	(17,296)	(753)	(7,296)	(6,169)	(81,822)
Actuarial loss (gain): return on assets	(137,870)	5,076	(3,486)	(19,610)	(25,503)	(181,393)
Benefits paid during the year	379,536	84,634	8,831	25,203	34,501	532,705
Fair value of actuarial assets at December 31, 2017	(3,925,061)	(1,105,738)	(94,378)	(387,322)	(446,670)	(5,959,170)
Expected return during the year	(359,588)	(102,621)	(8,634)	(35,950)	(41,166)	(547,959)
Participants' contributions transferred during the year	(24)	(2,078)	-	(395)	(842)	(3,339)
Sponsors' contributions	(65,096)	(25,460)	(1,027)	(7,643)	(6,712)	(105,938)
Actuarial loss (gain): return on assets	(264,569)	(57,432)	(4,230)	(7,707)	(3,950)	(337,888)
Benefits paid during the year	398,907	87,682	9,433	25,974	35,769	557,765
Fair value of actuarial assets at December 31, 2018	(4,215,431)	(1,205,647)	(98,836)	(413,043)	(463,571)	(6,396,529)
Expected return during the year	(372,121)	(107,795)	(8,699)	(37,500)	(40,947)	(567,063)
Participants' contributions transferred during the year	-	(1,886)	-	(620)	(1,136)	(3,643)
Sponsors' contributions	(92,756)	(34,444)	(1,604)	(7,748)	(6,959)	(143,512)
Actuarial loss (gain): return on assets	(280,404)	(99,905)	(6,426)	(35,042)	(29,504)	(451,281)
Benefits paid during the year	443,449	96,628	9,652	27,564	38,250	615,543
Fair value of actuarial assets at December 31, 2019	(4,517,265)	(1,353,050)	(105,914)	(466,390)	(503,867)	(6,946,486)

(*) Plan 1 was recorded at the dissolved RGE until the merger of the distribution companies.

20.3 Changes in the recognized assets and liabilities

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The changes in net liability are as follows:

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul (RGE)	Total
	CPFL Paulista	CPFL Piratininga	CPFL Geração	*Plan 1*	*Plan 2*	Total
Net actuarial liability at December 31, 2016	800,445	139,958	18,954	4,972	74,830	1,039,158
Expenses (income) recognized in the statement of profit or loss	84,501	17,244	2,067	253	9,822	113,887
Sponsors' contributions transferred during the year	(50,308)	(17,296)	(753)	(7,296)	(6,169)	(81,822)
Actuarial loss (gain): effect of changes in demographic assumptions	225	328	14	326	16,490	17,383
Actuarial loss (gain): effect of changes in financial assumptions	(6,993)	(3,586)	(372)	(45)	8,153	(2,843)
Actuarial loss (gain): return on assets	(137,870)	5,076	(3,486)	(19,610)	(25,503)	(181,393)
Effect of asset ceiling	-	-	-	21,399	-	21,399
Net actuarial liability at December 31, 2017	690,000	141,724	16,424	-	77,623	925,770
Other contributions						15,391
Total liability						941,160

Current						60,801
Noncurrent						880,360

	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul (RGE)	Total
	CPFL Paulista	CPFL Piratininga	CPFL Geração	*Plan 1*	*Plan 2*	Total
Net actuarial liability at December 31, 2017	690,000	141,724	16,424	-	77,623	925,770
Expenses (income) recognized in the statement of profit or loss	62,330	16,372	1,553	(188)	9,842	89,909
Sponsors' contributions transferred during the year	(65,096)	(25,460)	(1,027)	(7,643)	(6,712)	(105,938)
Actuarial loss (gain): effect of changes in demographic assumptions	-	-	-	-	345	345
Actuarial loss (gain): effect of changes in financial assumptions	485,142	135,540	8,409	8,921	12,774	650,786
Actuarial loss (gain): return on assets	(264,569)	(57,432)	(4,230)	(7,707)	(3,950)	(337,888)
Effect of asset ceiling	-	-	-	6,617	-	6,617
Net actuarial liability at December 31, 2018	907,807	210,744	21,129	-	89,922	1,229,600
Other contributions						13,662
Total liability						1,243,263

Current						86,623
Noncurrent						1,156,639


	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE Sul (RGE)		Total
	CPFL Paulista	CPFL Piratininga	CPFL Geração	**Plan 1 ()***	*Plan 2*	Total
Net actuarial liability at December 31, 2018	907,807	210,744	21,129	-	89,922	1,229,600
Expenses (income) recognized in the statement of profit or loss	77,977	22,711	1,892	(178)	10,201	112,602
Sponsors' contributions transferred during the year	(92,756)	(34,444)	(1,604)	(7,748)	(6,959)	(143,512)
Actuarial loss (gain): effect of changes in demographic assumptions	(2,900)	(77)	(165)	-	-	(3,143)
Actuarial loss (gain): effect of changes in financial assumptions	1,037,048	321,011	31,516	73,759	113,836	1,577,170
Actuarial loss (gain): return on actuarial assets	(280,404)	(99,905)	(6,426)	(35,042)	(29,504)	(451,281)
Effect of asset ceiling	74,849	-	-	(30,791)	-	44,058
Net actuarial liability at December 31, 2019	1,721,619	420,039	46,340	-	177,496	2,365,494
Other contributions						12,683
Total liability						2,378,178

Current						224,851
Noncurrent						2,153,327

(*) Plan 1 was recorded at the dissolved RGE until the merger of the distribution companies.

20.4Expected contributions and benefits

The expected contributions to the plans for 2020 are shown below:

	2020
CPFL Paulista	121,055
CPFL Piratininga	40,263
CPFL Geração	2,481
RGE Sul (RGE) - Plan 1	7,393
RGE Sul (RGE) - Plan 2	6,102
Total	177,294

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

F - 51

	2020	2021	2022	2023	2024 to 2029	Total
CPFL Paulista	436,163	448,553	460,445	471,438	3,017,325	4,833,924
CPFL Piratininga	99,957	104,651	108,695	113,023	774,546	1,200,872
CPFL Geração	10,728	10,992	11,238	11,494	73,016	117,468
RGE Sul (RGE) - Plan 1	28,695	29,642	30,980	32,025	213,150	334,492
RGE Sul (RGE) - Plan 2	38,642	40,078	41,785	43,447	293,489	457,441
Total	614,185	633,916	653,143	671,427	4,371,526	6,944,197

At December 31, 2019, the average duration of the defined benefit obligation was 10.3 years for CPFL Paulista, 12.5 years for CPFL Piratininga, 10.7 years for CPFL Geração, 11.3 years for plan 1 for RGE and 12.5 years for plan 2 for RGE.

20.5 Private pension plan income and expense

Supported by on the opinion of external actuarial, the Group’s management presents the estimate of the expenses (income) to be recognized in 2020 and the expense (income) recognized in 2019, 2018 and 2017 is as follows:

	2020 Estimated
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE Sul (RGE)		Total
				*Plan 1*	*Plan 2*
Service cost	1,533	9,135	124	(308)	2,244	12,728
Interest on actuarial obligations	441,784	128,027	10,914	33,434	49,190	663,349
Expected return on plan assets	(323,926)	(98,386)	(7,563)	(33,885)	(36,272)	(500,032)
Effect of asset ceiling	5,561	-	-	153	-	5,714
Total expense (income)	124,952	38,776	3,475	(606)	15,162	181,759

	2019 Actual
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE Sul (RGE)		Total
				**Plan 1 ()***	*Plan 2*
Service cost	925	5,449	84	185	2,352	8,993
Interest on actuarial obligations	449,173	125,059	10,507	34,342	48,796	667,877
Expected return on plan assets	(372,121)	(107,795)	(8,699)	(37,500)	(40,947)	(567,062)
Effect of asset ceiling	-	-	-	2,795	-	2,795
Total expense (income)	77,977	22,711	1,892	(178)	10,201	112,603

	2018 Actual
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul (RGE)	Total
				*Plan 1*	*Plan 2*
Service cost	835	4,365	78	175	2,790	8,243
Interest on actuarial obligations	421,083	114,628	10,109	33,552	48,218	627,590
Expected return on plan assets	(359,587)	(102,622)	(8,634)	(35,950)	(41,166)	(547,959)
Effect of asset ceiling	-	-	-	2,035	-	2,035
Total expense (income)	62,330	16,372	1,553	(188)	9,842	89,909

	2017 Actual
	CPFL Paulista	CPFL Piratininga	CPFL Geração	RGE	RGE Sul (RGE)	Total
				*Plan 1*	Plan 2*
Service cost	707	3,153	73	270	2,153	6,356
Interest on actuarial obligations	476,613	127,561	11,431	37,395	50,927	703,927
Expected return on plan assets	(392,819)	(113,470)	(9,437)	(37,412)	(43,258)	(596,396)
Total expense (income)	84,501	17,244	2,067	253	9,822	113,887

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

20.6 Plan assets

The following tables show the allocation (by asset segment) of the assets of the CPFL´s Group pension plans, at December 31, 2019 and 2018 managed by Fundações CESP and Família Previdência. The tables also show the distribution of the guarantee resources established as target for 2020, obtained in light of the macroeconomic scenario in December 2019.

Assets managed by the plans are as follows:

F - 52

CPFL Paulista, CPFL Geração and CPFL Piratininga

RGE (Plans 1 and 2)

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Nominal discount rate for actuarial liabilities:

7.43% p.a.

9.10% p.a.

9.51% p.a.

7.43% p.a.

9.10% p.a.

9.51% p.a.

Nominal Return Rate on Assets:

7.43% p.a.

9.10% p.a.

9.51% p.a.

7.43% p.a.

9.10% p.a.

9.51% p.a.

Estimated Rate of nominal salary increase:

5.56% p.a.(*)

6.08% p.a.(*)

5.97% p.a.(**)

6.10% p.a. (**)

Estimated Rate of nominal benefits increase:

4.00% p.a.

Estimated long-term inflation rate (basis for determining the nominal rates above)

4.00% p.a.

General biometric mortality table:

AT-2000 (-10)

BR-EMS sb v.2015

Biometric table for the onset of disability:

Low Light (-30)

Medium Light

Expected turnover table:

ExpR_2012

Null

Likelihood of reaching retirement age:

After 15 years of membership and 35 years of service for men and 30 years for women

100% on first eligibility to a full retirement benefit

(*) Estimated rate of nominal salary increase for CPFL Piratininga was 6.39% on December 31, 2019, 2018 and 2017.

(**) Estimated rate of nominal salary increase for RGE (plan 1) was 5.15% on December 31, 2019 and 2018 and 6.13%¨on December 31, 2017.

	Assets managed by FUNCESP				Assets managed by Fundação Família Previdência CEEE
	CPFL Paulista and CPFL Geração		CPFL Piratininga		RGE Sul (RGE)
	CPFL Paulista and CPFL Geração		CPFL Piratininga		*Plan 1*		*Plan 2*
	2019	2018	2019	2018	2019	2018	2019	2018
Fixed rate	75%	77%	76%	81%	76%	78%	74%	77%
Federal governament bonds	61%	55%	58%	53%	66%	68%	64%	67%
Corporate bonds (financial institutions)	1%	3%	2%	5%	5%	5%	5%	5%
Corporate bonds (non financial institutions)	0%	1%	0%	1%	2%	3%	3%	3%
Multimarket funds	4%	4%	4%	4%	2%	2%	2%	2%
Other fixed income investments	9%	15%	12%	18%	-	-	-	-
Variable income	17%	15%	17%	13%	21%	18%	21%	18%
Investiment funds - shares	17%	15%	17%	13%	21%	18%	21%	18%
Structured investments	4%	2%	4%	2%	-	1%	1%	1%
Equity funds	-	-	-	-	-	0%	0%	1%
Real estate funds	-	-	-	-	-	1%	1%	1%
Multimarket fund	4%	2%	4%	2%	-	-	-	-
Total quoted in an active market	96%	94%	97%	97%	96%	96%	96%	96%

Real estate	3%	3%	2%	2%	2%	2%	2%	2%
Transactions with participants	1%	1%	1%	2%	1%	2%	2%	2%
Other investments	0%	1%	-	-	-	-	-	-
Escrow deposits and others	0%	1%	-	-	-	-	-	-
Total not quoted in an active market	4%	6%	3%	3%	4%	4%	4%	4%

The plan assets do not hold any properties occupied or assets used by the Company.

	Target for 2020
	Fundação CESP		Fundação Família Previdência
	CPFL Paulista and CPFL Geração	CPFL Piratininga	RGE Sul (RGE)
	CPFL Paulista and CPFL Geração	CPFL Piratininga	Plan 1	Plan 2
Fixed income investments	61.3%	51.6%	76.0%	76.0%
Variable income investments	24.9%	35.5%	9.0%	11.0%
Real estate	3.6%	1.8%	2.0%	3.0%
Transactions with participants	1.9%	2.7%	2.0%	2.0%
Structured investments	-	-	11.0%	8.0%
Investments abroad	8.4%	8.4%	-	-
Total	100%	100%	100%	100%

The allocation target for 2020 was based on the recommendations for allocation of assets made at the end of 2019 by Fundações CESP e Família Previdência, in their Investment Policy. This target may change at any time during 2020, in light of changes in the macroeconomic situation or in the return on assets, among other factors.

The asset management aims at maximizing the return on investments, but always seeking to minimize the risks of actuarial deficit. Accordingly, investments are always made considering the liability that they must honor. The two main studies forFundações CESP e Família Previdência to achieve the investment management objectives are the Asset Liability Management – ALM and the Technical Study of Compliance and Appropriateness of the Real Interest Rate, both conducted at least once a year, taking into consideration the projected flow of benefit payments (liability flow) of the pension plans managed by the Foundations.

The ALM study is used as a base to define the strategic allocation of assets, which comprises the target participations in the asset classes of interest, from the identification of efficient combinations of assets,considering the existence of liabilities and the need for return, immunization and liquidity of each plan, considering projections of risk and return. The simulations generated by the ALM studies assist in the definition of the minimum and maximum limits of allocation in the different asset classes, defined in the plans’ Investment Policy, which is also used as a risk control mechanism.

F - 53

The Technical Study of Compliance and Appropriateness of the Real Interest Rate aims at proving the appropriateness and compliance of the annual real interest rate to be adopted in the actuarial valuation of the plans and the projected annual real rate of return of the investments, considering their projected flows of revenues and expenses.

These studies are used as a base to determine the assumptions of estimated real return of the pension plans’ investments for short-term and long-term horizons and assist in the analysis of their liquidity, since they consider the flow of benefit payments against the assets considered liquid. The main assumptions considered in the studies are, in addition to the liability flow projections, the macroeconomic and asset price projections, through which estimates of the expected short-term and long-term profitability are obtained, taking into account the current portfolios of the benefit plans.

20.7 Sensitivity analysis

The significant actuarial assumptions for determining the defined benefit obligation are discount rate and mortality. The following sensitivity analyses were based on reasonably possible changes in the assumptions at the end of the reporting period, with the other assumptions remaining constant.

Furthermore, in the presentation of the sensitivity analysis, the present value of the defined benefit obligation was calculated using the projected unit credit method at the end of the reporting period, the same method used to calculate the defined benefit obligation recognized in the statement of financial position, according to IAS 19.

See below the effects on the defined benefit obligation if the discount rate were 0.25 percentage points lower (higher) and if life expectancy were to decrease (increase) in one year:

					RGE Sul (RGE)
	Increase (Decrease)	CPFL Paulista	CPFL Piratininga	CPFL Geração	Plan 1	Plan 2	Total

Nominal discount (p.a.)*	-0.25 p.p.	160,456	56,441	4,116	13,297	21,548	255,858
	+0.25 p.p.	(153,552)	(53,580)	(3,928)	(12,683)	(20,456)	(244,199)

General biometric mortality table**	+1 year	(169,890)	(40,984)	(4,005)	(11,057)	(15,957)	(241,893)
	-1 year	169,223	40,473	3,993	10,917	15,743	240,349

* The Company´s assumption based on the actuarial report for the nominal discount rate was 7.43% p.a.. The projected rates are increased or decreased by 0.25 p.p. to 7.18% p.a. and 7.68% p.a..

** The Company´s assumption based on in the actuarial report for the mortality table was AT-2000 (-10) for Fundação CESP and BREMS sb v.2015 for Fundação Família Previdência. The projections were performed with 1 year of aggravation or softening on the respective mortality tables.

20.8 Investment risk

The major part of the resources of the Company’s benefit plans is invested in the fixed income segment and, within this segment, the greater part of the funds is invested in federal government bonds, indexed to the IGP-M, IPCA and SELIC, which are the indexes for adjustment of the actuarial liabilities of the Company’s plans (defined benefit plans), representing the matching between assets and liabilities.

Management of the Company’s benefit plans is monitored by the Investment and Pension Plan Management Committee, which includes representatives of active and retired employees, as well as members appointed by the Company. Among the duties of the Committee are the analysis and approval of investment recommendations made by investment managers of Fundação CESP, which occurs at least quarterly.

Fundações CESP and Família Pervidência use the following tools to control market risks in the fixed income and variable income segments: VaR, Traking Risk, Tracking Error and Stress Test.

F - 54

Fundação Família Previdência also uses Sharpe, Generalized Sharpe and Drawn Down. In addition, to assess the market risk exposure of the plans' portfolios, the Base EBA Year Exposure is calculated and Stress Simulations are performed. The EBA consists of a metric that expresses the risk exposure of the portfolio as a percentage of equity, considering the sum of the exposures generated by each asset, based on the definition of increase/decrease of the respective risk factors.

Fundações CESP and Família Previdência Investment Policies determine additional restrictions that, along with those already established by law, define the percentages of diversification for investments and establish the strategy of the plans, including the limit of credit risk in assets issued or co-obligation of the same legal entity to be adopted internally.

( 21 ) REGULATORY CHARGES

	Dec 31, 2019	Dec 31, 2018
Fee for the use of water resources	1,265	1,701
Global reversal reserve - RGR	17,260	17,288
ANEEL inspection fee - TFSEE	7,375	5,470
Tariff flags and others	206,352	126,196
Total	232,251	150,656

Tariff flags and others: Refer basically to the amount to be passed through to the Centralizing Account of Tariff Flag Resources (“CCRBT”), whose amount receivable was recognized through the issue of electricity bills. Refers basically to the tariff flag adopted for bills in November and December 2019 and 2018 and not yet ratified by the Centralizing Account For Tariff Flag Resources (“CCRBT”).

( 22 ) TAXES, FEES AND CONTRIBUTIONS PAYABLE

	Dec 31, 2019	Dec 31, 2018
Current
IRPJ (corporate income tax)	156,240	73,058
CSLL (social contribution on net income)	62,721	27,392
Income tax and social contribution	218,961	100,450

ICMS (State VAT)	435,155	430,149
PIS (tax on revenue)	36,657	30,760
COFINS (tax on revenue)	168,195	152,945
PIS/COFINS installments	9,323	-
Income tax withholding on interest on capital	40,099	-
Others	52,105	51,135
Other taxes	741,536	664,989

Total current	960,497	765,438

Noncurrent
Income Tax - IRPJ	156,198	-

ICMS (State VAT)	805	722
PIS/COFINS installments	-	8,919
Other taxes	805	9,691

Total noncurrent	157,003	9,691

Corporate Income tax – IRPJ:in noncurrent, due to the initial application of IFRIC 23 - Uncertainty Over Income Tax Treatments, this refers to the reclassification of provision for tax risks related to income tax payable. The case refers to the Writ of Mandamus filed by the subsidiary CPFL Piratininga, which discussed the possibility of excluding the Social Contribution on Profit (CSLL) from its own calculation base, as well as from the calculation base of the Corporate Income Tax (IRPJ); for such case, the Company has recorded a provision based on the Company’s estimate of the most likely amount in a range of possible outcomes related to the uncertainty regarding the tax authorities’ acceptance of the Company’s methodology.

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The Group also has some uncertain income tax treatments for which management concluded that it is more likely than not that they will be accepted by the tax authority and for which the effect of potential contingencies is disclosed in note 23 – Provision for tax, civil and labor risks and escrow deposits.

( 23 ) PROVISION FOR TAX, CIVIL AND LABOR RISKS AND ESCROW DEPOSITS

	December 31, 2019		December 31, 2018
	Provision for tax, civil and labor risks	Escrow Deposits	Provision for tax, civil and labor risks	Escrow Deposits

Labor	235,085	96,094	219,314	103,760

Civil	245,464	66,243	281,304	99,604

Tax
FINSOCIAL	-	-	39,727	99,146
Income Tax	7,571	417,664	154,717	401,381
Others	46,255	177,369	195,379	150,472
	53,825	595,033	389,823	650,999

Others	66,401	1	88,920	12

Total	600,775	757,370	979,360	854,374

The changes in the provision for tax, civil, labor and other risks are shown below:

	December 31, 2018	Additions	Reversals	Payments	Monetary Restatements	Adjustment (note 22)	December 31, 2019
Labor	219,314	86,735	(29,967)	(68,927)	27,932	-	235,085
Civil	281,304	107,671	(43,679)	(123,054)	23,223	-	245,464
Tax	389,823	121,146	(55,221)	(276,652)	30,927	(156,198)	53,825
Others	88,920	6,571	(16,420)	(15,518)	2,849	-	66,401
Total	979,360	322,121	(145,288)	(484,153)	84,932	(156,198)	600,775

The provision for tax, civil, labor and other risks was based on the assessment of the risks of losing the lawsuits to which the Company and its subsidiaries are parties, where the likelihood of loss is probable in the opinion of the outside legal counselors and the Management of the Group.

The principal pending issues relating to litigation, lawsuits and tax assessments are summarized below:

a) Labor:The main labor lawsuits relate to claims filed by former employees or labor unions for payment of salary adjustments (overtime, salary parity, severance payments and other claims).

b) Civil

Bodily injury –refer mainlyto claims for indemnities relating to accidents in the subsidiaries' electrical grids, damage to consumers, vehicle accidents, etc.

Tariff increase –refer to various claims by industrial consumers as a result of tariff increases imposed by DNAEE Administrative Rules 38 and 45, of February 27 and March 4, 1986, when the “Plano Cruzado” economic plan price freeze was in effect.

c) Tax: this refers to lawsuits in progress at the judicial and administrative levels resulting from the subsidiaries' operations, related to tax matters involving INSS, FGTS, SAT, PIS and COFINS.

d) Others:The line item of “others” refers mainly to lawsuits involving regulatory matters.

Possible losses

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The Group is party to other lawsuits in which Management, supported by its external legal counselors, believes that the chances of a successful outcome are possible, therefore no provision was registered. It is not yet possible to predict the outcome of the courts’ decisions or any other decisions in similar proceedings considered probable or remote.

The claims relating to possible losses, at December 31, 2019 and 2018 were as follows:

	Dec 31, 2019	Dec 31, 2018	Main reasons for claims
Labor	583,348	786,901	Work accidents, risk premium for dangerousness at workplace and overtime
Civil	1,815,143	1,630,630	Personal injury, environmental impacts and overfed tariffs
Tax	4,350,740	3,822,488	Social Contributions and Income tax (note 22)
Tax - others	2,654,331	2,377,101	ICMS, FINSOCIAL, PIS and COFINS
Regulatory	76,404	139,593	Technical, commercial and economic-financial supervisions
Total	9,479,966	8,756,713

(a) Tax:

(i) There is a discussion about the deductibility for income tax of the expense recognized in 1997 relating to the commitment assumed in regard to the pension plan of employees of the subsidiary CPFL Paulista with Fundação CESP in the estimated amount of R$ 1,478,266 with a linked escrow deposit in the amount of R$ 248,725 Further to such deposit, there are escrow deposits in the amount of R$ 22,264 and financial guarantee (insurance and letters of guarantee), under the terms required by the relevant procedural law. On May 23, June 6 and September 17, 2019, unfavorable rulings on the special appeal filed by the Company were rendered by the Second Panel of Judges of the Higher Court of Justice (STJ). These rulings have not yet been fully published, and the Company, when it has access to the decision, may evaluate the applicable appeals still at the level of the STJ. Additionally, the Company has an extraordinary appeal in the initial stage at the Federal Supreme Court (STF). Consequently, based on the current stage of the appeal, both at the STJ and at the STF, and based on the opinion of its legal advisors, the Company remains confident in the legal grounds consubstantiating the appeal and will continue to defend its arguments before the judiciary branch, assessing the chances of loss as not probable, there is a new opportunity for the analysis of the case at the Federal Supreme Court (STF), with a constitutional approach with sound bases, indicating possible success in the extraordinary appeals, and will continue to try to avoid possible cash outflows should it be required to replace existing judicial guarantees with cash deposits.

(ii) In August 2016, the subsidiary CPFL Renováveis received a tax legal proceeding notice in the amount of R$ 327,547 relating to the collection of Withholding Income Tax - IRRF on remuneration of capital gain incurred by parties resident and/or domiciled abroad, arising from the transaction of sale of Jantus SL, in December 2011, which the Company’s management, supported by the opinion of its outside legal counselors, , assessing the chances of loss as not probable.

(iii) In 2016, the subsidiary CPFL Geração received a tax legal proceeding notice that, summed up and updated, total R$ 482,734 relating to the collection of Corporate Income Tax - IRPJ and Social Contribution on Profit – CSLL relating to calendar year 2011, calculated on the alleged capital gain identified on the acquisition of ERSA Energias Renováveis S.A. and recording of differences from the fair value remeasurement of SMITA Empreendimentos e Participações S.A., company acquired in a downstream merger, which the Company’s management, supported by its outside legal counselors, , assessing the chances of loss as not probable.

(b) Labor:

As regards to labor contingencies, there is discussion about the possibility of changing the inflation adjustment index adopted by the Labor Court. Currently there is a decision of the Federal Supreme Court (STF) that suspends the change taken into effect by the Superior Labor Court (TST), which intended to change the index currently adopted by the Labor Court (“TR”), the IPCA-E. The Supreme Court considered that the TST’s decision entailed an unlawful interpretation and was not compliant with the determination of the effects of prior court decisions, violating its competence to decide on a constitutional matter. In view of such decision, and until there is a final decision by the STF, the index currently adopted by the Labor Court (“TR”) remains valid, which has been acknowledged by the TST (Superior Labor Court) in recent decisions. Accordingly, the management of the Group considers the risk of loss as possible and, as this matter still requires definition by the Courts, it is not possible to reliably estimate the amounts involved. Furthermore, in accordance with Law 13,467/17, ofNovember 11, 2017, TR is the index for inflation adjustment used by the Labor Court since the date the law became effective.

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Based on the opinion of their external legal advisers, Management of the Group and its subsidiaries consider that the registered amounts represent best estimate.

( 24 ) OTHER PAYABLES

	Current		Noncurrent
	Dec 31, 2019	Dec 31, 2018	Dec 31, 2019	Dec 31, 2018
Consumers and concessionaires	114,610	93,612	183,938	47,831
Energy efficiency program - PEE	230,451	183,225	89,522	120,563
Research & Development - P&D	93,658	110,495	125,111	72,941
EPE/FNDCT/PROCEL (*)	49,275	38,052	-	-
Reversion fund	1,712	1,712	12,615	14,327
Advances	234,556	197,470	43,263	48,724
Tariff discounts - CDE	76,632	96,819	-	-
Provision for socio-environmental costs and asset retirement obligation	24,485	22,489	203,844	110,261
Payroll	18,004	15,674	-	-
Profit sharing	98,713	95,502	29,631	20,575
Collections agreement	93,740	85,018	-	-
Business combination	7,901	7,598	-	-
Others	50,533	31,630	71,406	40,174
Total	1,094,269	979,296	759,331	475,396

(*) EPE – Energy Research Company;

FNDCT - National Fund for Scientific Development;

PROCEL - National Electricity Conservation Program.

Consumers and concessionaires: refer to liabilities with consumers in connection with overpayments and adjustments of billing to be offset or returned to consumers as well the participation of consumers in the “Programa de Universalização” program. In noncurrent, this refers mainly to the transfer of PIS and COFINS to consumers (Note 8) and to spot market electricity (CCEE) related to ANEEL Order No. 288.

Research & Development and Energy Efficiency Programs: the subsidiaries recognized liabilities relating to amounts already billed in tariffs (1% of net operating revenue), but not yet invested in the research & development and energy efficiency programs. These amounts are subject to adjustment for SELIC rate, through the date of their realization.

Advances: refer mainly to advances from customers in relation to advance billing by the subsidiary CPFL Renováveis, before the energy or service has actually been provided or delivered.

Provision for socio environmental costs and asset retirement: refers mainly to provisions recognized by the subsidiary CPFL Renováveis in relation to socio environmental licenses as a result of events that have already occurred and obligations to remove assets arising from contractual and legal requirements related to leasing of land on which the wind farms are located. Such costs are accrued against property, plant and equipment and will be depreciated over the remaining useful life of the asset. These provisions are made based on estimates and assumptions related to discount rates, the expected cost for demobilization and removal at the end of the authorization period for these plants. These costs may differ from what may be incurred by the Company. The real discount rate used to calculate the present value was 3.22%, based on government bond rates with a similar maturity date until the end of the authorizations.

Tariff discounts – CDE:refers to the difference between the tariff discount granted to consumers and the amounts received via the CDE.

Profit sharing:mainly comprised by:

(i) in accordance with a collective labor agreement, the Group introduced an employee profit-sharing program, based on the achievement of operating and financial targets previously established;

(ii) Long-Term Incentive Program: refers to the Long-Term Incentive Plan for the Group’s Executives, approved by the Board of Directors, which consists in an incentive in financial resources based on salary multiples andthat are driven by the company’s results and average performance in the three fiscal years after each concession.

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( 25 ) EQUITY

The shareholders’ interest in the Company’s equity at December 31, 2019 and 2018 is shown below:

	Number of shares
	December 31, 2019		December 31, 2018
Shareholders	Common shares	Interest %	Common shares	Interest %
State Grid Brazil Power Participações S.A.	730,435,698	63.39%	730,435,698	71.76%
ESC Energia S.A.	234,086,204	20.32%	234,086,204	23.00%
Members of the Executive Board	189	0.00%	189	0.00%
Other shareholders	187,732,349	16.29%	53,392,655	5.25%
Total	1,152,254,440	100.00%	1,017,914,746	100.00%

25.1 Capital management

The Company’s policy is to maintain a solid capital base in order to keep the trust of the investor, the creditors and the market and to ensure the business sustainability. Management monitors the return on capital and the strategy of rising dividends from the subsidiaries to the Company and from the Company to the controlling shareholders.

The Company manages the leverage ratio analyzing the advantages and the security provided by an improved equity capital position. The Company monitors capital using the gearing ratio calculated by net debt to EBITDA.

In 2019, the consolidated capital structure and leverage ratio of CPFL Energia remained at adequate levels. The Company’s net debt reached 2.52 times the EBITDA at the end of 2019 under the criterion for measuring the Company’s financial covenants, lower than in the prior year. The Group’s policy is to keep such ratio below 3.5, since most of its agreements use this measurement. Historically, the Company has not acquired its own shares in the market.

25.2 Changes in shareholding structure and Mandatory Tender Offer (MTO)

On April 2, 2019, the Company informed B3 S.A. - Brasil, Bolsa, Balcão of its intention to carry out a public offering of common shares ("Offering"), and on April 18, 2019, B3 approved its request for extension of the term to reach a minimum percentage of outstanding (free float) shares in the market of 15% of the Company's total capital up to October 31, 2019. On April 24, 2019, a Material Fact was disclosed by the Company, stating that it had filed a Registration Statement on Form F-3 ("Form F-3") with the Securities and Exchange Commission ("SEC"), allowing the Company to carry out certain public offerings of common shares issued by it in the United States, including as American Depositary Shares ("ADS").

On June 12, 2019, following the announcements previously made, the Company disclosed in a Material Fact that the Board of Directors had approved, within the scope of the Offering and pursuant to CVM Instruction 476, a price per share of R$ 27.50 and the Company's capital increase amounting to R$ 3,212,471, through the issue of 116,817,126 new shares. As a result, capital increased from R$ 5,741,284 to R$ 8,953,755 and the total number of registered common shares with no par value increased from 1,017,914,746 to 1,134,731,872. On June 27, 2019, the number of shares was increased by a supplementary lot of 15% of the total shares initially offered (without considering the Additional Lot), i.e., 17,522,568 common Company-issued shares under the same conditions and price of the shares initially offered, increasing the total number of shares to 1,152,254,440. On June 28, 2019, these shares were settled, totaling R$ 481,871 from the capital increase, increasing capital to R$ 9,435,626 at December 31, 2019.

The issue costs totaled R$ 47,544, net of tax effects, up to December 31, 2019.

The Offering was carried out, simultaneously: (i) with restricted efforts of placement in Brazil, in the non-organized over-the-counter market,; and (ii) abroad. There was no reallocation of shares between the Brazilian Offering and the International Offering, due to the demand verified in Brazil and abroad during the course of the Offering and, therefore, there was no allocation of ADSs in the context of the International Offering, and therefore, all the shares were distributed under the Brazilian Offering.

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On December 19, 2019, the Company’s Board of Directors and the Executive Board of CPFL Geração approved the holding of a public tender offer of the common shares issued by CPFL Energias Renováveis, outstanding in the market, for the purpose of converting its registration as a publicly-held company category “A” into category “B” (“OPA Conversion of Registration”) and/or exit from the New Market (“OPA Exit from the New Market”, and, together with the OPA Conversion of Registration, “OPA”), to be carried out by CPFL Geração, direct controlling shareholder of CPFL Renováveis. The holding of the OPA is subject to its registration by the CVM and its authorization by B3 and will be intended for the acquisition of up to 291,550 common shares issued by CPFL Renováveis outstanding in the market, which represent, on that date, 0.056% equity interest in CPFL Renováveis (“Outstanding Shares”).

25.3 Capital reserves

This refers basically to the registration of operations involving subsidiary CPFL Renováveis: (i) business combination in 2011 (R$ 228,322); (ii) public offering of shares in 2013 (R$ 59,308); (iii) association with DESA in 2014 (R$ 180,297); decrease due to: (iv) acquisition, by the Company, of equity interest previously held by the parent company State Grid in 2019 (R$ 2,034,920) (Note 1.c) and (v) change in equity interest without change in control in 2019 (R$ 75,298) .

In accordance with IFRS 10, these effects were recognized as transactions between shareholders, directly in Equity.

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25.4 Earnings reserves

The balance of earnings reserve at December 31, 2019 is R$ 5,082,430 that refers to: i) Legal Reserve of R$ 1,036,125; and ii) statutory reserve - working capital reinforcement of R$ 4,046,305.

25.5 Accumulated other comprehensive income

The accumulated other comprehensive income is comprised of:

i. Deemed cost: refers to the recognition of the fair value adjustments of the deemed cost of the generating plants' property, plant and equipment, of R$ 355,049;

ii. Private pension plan: The debt balance of R$1,674,527 (net of taxes) refers to the effects of the actuarial gains and losses recognized directly in other comprehensive income, in accordance with IAS 19.

iii. Effects of the credit risk in the fair value adjustment of financial liabilities, net of income taxes, in accordance with IFRS 9 (credit amount of R$ 51,012).

25.6 Dividends

At the Extraordinary Shareholders' Meeting held on April 30, 2019 approval was given for the declaration dividend for 2018 in the amount of R$ 488,785.

Furthermore, in 2019 the Company proposed R$ 641,884 of minimum mandatory dividend, as set forth by Law 6,404/76, and for each share the amount of R$ 0.557068261 was attributed.

In 2019, the Company paid R$ 486,906 relating to the dividend for 2018.

25.7 Termination of the statutory reserve of the financial asset of concession

The Extraordinary Shareholders' Meeting held on April 27, 2018 approved the extinction of the statutory reserve of the financial asset of concession and the transfer of the respective balance of R$ 826,600 to the Retained Earnings account.

25.8 Allocation of profit for the year

The Company’s bylaws assure shareholders a minimum dividend of 25% of profit for the year, adjusted in accordance with the law.

The proposed allocation of profit for the year is shown below:

	2019
Profit for the year - Parent company	2,702,671
Realization of comprehensive income	25,672
Time-barred dividends	765
Profit base for allocation	2,729,108
Legal reserve	(135,134)
Statutory reserve - working capital	(518,795)
Mandatory dividend	(641,884)
Additional dividend	(1,433,295)

For this year, considering the current scenario with the incipient economic recovery and also considering the uncertainties regarding the hydrology, the Company’s management is proposing the allocation of R$518,795 to the statutory reserve - working capital reinforcement.

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25.9 Noncontrolling interests

The disclosure of interests in subsidiaries, in accordance with IFRS 12, is as follows:

25.9.1 Changes in noncontrolling interests

	CERAN	CPFL Renováveis		Paulista Lajeado	Total
As of December 31, 2016	263,719	2,060,963		77,966	2,402,648
Equity interests and voting capital	35.00%	48.40%		40.07%

Equity attributable to noncontrolling interests	37,949	13,720		11,623	63,292
Dividends	(92,832)	(16,619)		(8,769)	(118,220)
Capital increase (reduction)	(122,806)	15		-	(122,791)
Other movements	-	-		(113)	(113)
As of December 31, 2017	86,031	2,058,079		80,707	2,224,816
Equity interests and voting capital	35.00%	48.40%		40.07%

Equity attributable to noncontrolling interests	34,731	62,470		10,754	107,955
Dividends	(44,314)	(13,511)		(10,860)	(68,685)
Other movements	-	5,656		(108)	5,548
As of December 31, 2018	76,448	2,112,693		80,493	2,269,634
Equity interests and voting capital	35.00%	48.44%		40.07%

Equity attributable to noncontrolling interests	36,914	950		7,762	45,625
Gain in equity without change in control	-	75,298		-	75,298
Acquisition of non-controlling interests	-	(2,072,635)	(1)	-	(2,072,635)
Dividends	(9,228)	(11,895)		(7,986)	(29,109)
Other movements	-	122		(77)	45
As of December 31, 2019	104,134	104,532		80,191	288,857
Equity interests and voting capital	35.00%	0.06%		40.07%

(1) Refers to acquisition of 46.76% interest in subsidiary CPFL Renováveis by the Company from the controlling shareholder State Grid.

25.9.2 Summarized financial information of subsidiaries that have interests of noncontrolling shareholders

The summarized financial information on subsidiaries in which there is noncontrolling interests at December 31, 2019 and 2018, and for income statement for the years ended December 31, 2019, 2018 and 2017 are as follows:

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	December 31, 2019
	CERAN	CPFL Renováveis	Paulista Lajeado
Current assets	78,836	1,312,372	19,734
Cash and cash equivalents	33,140	412,579	9,564
Noncurrent assets	751,546	10,496,351	141,185

Current liabilities	215,198	1,545,741	35,374
Borrowings and debentures	106,128	617,030	-
Other financial liabilities	13,256	430,257	250
Noncurrent liabilities	317,660	5,616,562	782
Borrowings and debentures	211,051	4,387,676	-
Other financial liabilities	91,181	-	-
Equity	297,523	4,646,421	124,763
Attributable to owners of the Company	297,523	4,544,434	124,763
Attributable to noncontrolling interests	-	101,987	-

	2019
Net operating revenue	339,041	1,928,011	42,206
Operational costs and expenses	(102,685)	(724,479)	(25,224)
Depreciation and amortization	(43,033)	(645,722)	(4)
Interest income	4,821	73,216	679
Interest expense	(39,623)	(420,775)	-
Income tax expense	(52,197)	(47,152)	(2,814)
Profit (loss) for the year	105,468	107,024	19,370
Attributable to owners of the Company	105,468	96,628	19,370
Attributable to noncontrolling interests	-	10,396	-

	December 31, 2018
	CERAN	CPFL Renováveis	Paulista Lajeado
Current assets	80,367	1,330,819	15,499
Cash and cash equivalents	32,729	876,571	5,687
Noncurrent assets	799,390	10,845,036	144,863

Current liabilities	246,482	1,396,120	33,883
Borrowings and debentures	106,556	819,993	-
Other financial liabilities	13,406	7,670	282
Noncurrent liabilities	414,852	6,528,563	1,033
Borrowings and debentures	316,581	4,738,841	-
Other financial liabilities	89,965	-	-
Equity	218,423	4,251,172	125,446
Attributable to owners of the Company	218,423	4,147,795	125,446
Attributable to noncontrolling interests	-	103,377	-

	2018
Net operating revenue	333,289	1,936,319	52,510
Operational costs and expenses	(95,321)	(727,557)	(26,114)
Depreciation and amortization	(41,378)	(623,106)	(4)
Interest income	6,191	93,076	691
Interest expense	(53,629)	(517,403)	(614)
Income tax expense	(48,239)	37,276	(3,145)
Profit (loss) for the year	99,230	118,805	26,838
Attributable to owners of the Company	99,230	109,264	26,838
Attributable to noncontrolling interests	-	9,542	-

	2017
	CERAN	CPFL Renováveis	Paulista Lajeado
Net operating revenue	321,743	1,959,084	38,278
Operational costs and expenses	(103,671)	(737,472)	(10,566)
Depreciation and amortization	(45,212)	(617,017)	(4)
Interest income	30,489	126,041	2,089
Interest expense	2,029	(648,571)	(4,050)
Income tax expense	(40,202)	(74,125)	(2,911)
Profit (loss) for the year	108,427	19,645	29,006
Attributable to owners of the Company	108,427	11,484	29,006
Attributable to noncontrolling interests	-	8,162	-

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( 26 ) EARNINGS PER SHARE

Earnings per share – basic and diluted

The calculation of the basic and diluted earnings per share at December 31, 2019, 2018 and 2017 was based on the profit for the year attributable to controlling shareholders and the weighted average number of common shares outstanding during the reporting years. For diluted earnings per share, the calculation considered the dilutive effects of instruments convertible into shares, as shown below:

	2019		2018	2017
Numerator
Profit attributable to controlling shareholders	2,702,671		2,058,040	1,179,750
Denominator
Weighted average number of shares held by shareholders	1,087,828,995	(**)	1,017,914,746	1,017,914,746
Earnings per share - basic	2.48		2.02	1.16

Numerator
Profit attributable to controlling shareholders	2,702,671		2,058,040	1,179,750
Dilutive effect of convertible debentures of subsidiary CPFL Renováveis (*)	(13,764)		(7,525)	(11,966)
Profit attributable to controlling shareholders	2,688,907		2,050,515	1,167,783

Denominator
Weighted average number of shares held by shareholders	1,087,828,995	(**)	1,017,914,746	1,017,914,746
Earnings per share - diluted	2.47		2.01	1.15

(*) Proportional to the percentage of the Company's interest in the subsidiary in each period presented.
(**) Considers the events that took place on June 12 and 28, 2019, related to the Public Offering process of the Company (note 25.2)

(*)The dilutive effect of the numerator in the calculation of diluted earnings per share considers the dilutive effects of the debentures convertible into shares issued by by indirect subsidiaries of the Company (note 19). These financial instruments reduce the amount of earnings available to the Company’s controlling shareholders. The effects were calculated taking into account the assumption that said debentures would be converted into common shares of the subsidiaries at the beginning of each year.

( 27 ) NET OPERATING REVENUE

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	Number of Consumers			In GWh			R$ thousand
Revenue from Eletric Energy Operations	2019	2018	2017	2019	2018	2017	2019	2018	2017
Consumer class
Residential	8,721,256	8,544,035	8,330,237	20,355	19,618	16,473	15,356,697	13,549,879	11,663,084
Industrial	57,116	58,241	59,825	13,198	13,834	13,022	5,222,522	5,188,778	5,095,840
Commercial	529,815	532,592	545,095	10,700	10,211	9,720	6,674,870	6,038,086	5,498,867
Rural	363,500	361,908	359,106	3,231	3,583	2,474	1,430,315	1,334,868	1,173,569
Public administration	61,868	60,685	60,639	1,468	1,459	1,271	957,935	879,910	787,967
Public lighting	11,809	11,659	11,230	2,039	2,003	1,746	838,116	767,246	654,950
Public services	10,512	10,194	9,790	2,348	2,348	1,840	1,241,696	1,150,227	978,286
(-) Adjustment of revenues from excess demand and excess reactive power	-	-	-	-	-	-	-	-	(65,991)
Billed	9,755,876	9,579,314	9,375,922	53,339	53,057	46,546	31,722,151	28,908,995	25,786,572
Own comsuption	-	-	-	36	34	32	-	-	-
Unbilled (net)	-	-	-	-	-	-	39,477	112,441	(89,575)
(-) Transfer or revenue related to the network availability for Captive Consumers	-	-	-	-	-	-	(12,769,168)	(11,095,762)	(9,273,840)
Electricity sales to final consumers	9,755,876	9,579,314	9,375,922	53,375	53,091	46,578	18,992,460	17,925,674	16,423,157

Furnas Centrais Elétricas S.A.				2,875	2,875	3,026	578,603	544,342	565,592
Other concessionaires and licensees				18,351	17,757	16,337	4,215,041	3,825,201	3,240,571
(-) Transfer or revenue related to the network availability for Captive Consumers				-	-	-	(133,073)	(96,717)	(56,528)
Spot market energy				4,208	3,828	8,194	1,309,117	1,082,945	2,340,463
Electricity sales to wholesalers				25,435	24,459	27,557	5,969,688	5,355,771	6,090,098

Revenue due to Network Usage Charge - TUSD - Captive Consumers							12,902,241	11,192,479	9,330,368
Revenue due to Network Usage Charge - TUSD - Free Consumers							3,359,298	2,650,565	2,137,566
(-) Compensation paid for failure to comply with the limits of continuity							(84,461)	(57,630)	-
(-) Adjustment of revenues from excess demand and excess reactive power							-	-	(21,861)
Revenue from construction of concession infrastructure							2,087,995	1,772,222	2,073,423
Sector financial asset and liability (Note 9)							(602,461)	1,207,917	1,900,837
Concession financial asset - Adjustment of expected cash flow (note 11)							280,632	345,015	204,443
Energy development account - CDE - Low-income, tariff discounts - judicial injunctions and other tariff discounts							1,516,077	1,536,366	1,419,128
Other revenues and income							587,668	697,878	496,340
Other operating revenues							20,046,989	19,344,812	17,540,244
Total gross operating revenue							45,009,138	42,626,257	40,053,498

Deductions from operating revenue
ICMS							(6,936,560)	(6,188,323)	(5,455,718)
PIS							(676,174)	(659,352)	(603,050)
COFINS							(3,173,715)	(3,037,164)	(2,777,626)
ISS							(19,830)	(16,871)	(15,929)
Global reversal reserve - RGR							-	-	(2,952)
Energy development account - CDE							(3,642,384)	(4,016,362)	(3,185,693)
Research and development and energy efficiency programs							(224,642)	(207,653)	(191,997)
PROINFA							(175,283)	(151,718)	(166,743)
Tariff flags and others							(180,572)	(178,536)	(878,460)
Financial compensation for the use of water resources						��	(9,359)	-	-
IPI							-	-	(102)
FUST e FUNTEL							-	-	(19)
Others							(38,145)	(33,651)	(30,304)
							(15,076,664)	(14,489,630)	(13,308,593)

Net operating revenue							29,932,474	28,136,627	26,744,905

27.1 Adjustment of revenues from excess demand and excess reactive power

As provided for in Sub-module 2.7 of the Tariff Regulation Procedures – PRORET, approved through Normative Resolution No. 463/2011, since the 4th cycle of period tariff review of the distribution subsidiaries, the revenues earned from excess demand and excess reactive power have been recorded as sector liability, since May 2015. The recorded amounts will be amortized as from the 5th cycle (already in force for CPFL Piratininga), when they will be deducted from Portion B (portion of manageable costs of the tariffs), except for subsidiary CPFL Santa Cruz, whose amortization started in the Annual Tariff Review – RTA of March 2017 due to the renewal of its concession in 2015.

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27.2 Periodic tariff review (“RTP”) and Annual tariff adjustment (“RTA”)

		2019		2018		2017
Subsidiary	Month	RTA / RTP	Effect perceived by consumers (a)	RTA / RTP	Effect perceived by consumers (a)	RTA / RTP	Effect perceived by consumers (a)
CPFL Paulista	April	12.02%	8.66%	12.68%	16.90%	-0.80%	-10.50%
CPFL Piratininga	October	1.88%	-7.80%	20.01%	19.25%	7.69%	17.28%
RGE	June	10.05% (c)	8.63%	21.27%	20.58%	3.57%	5.00%
RGE Sul (RGE)	June	10.05% (c)	1.72%	18.45%	22.47%	-0.20%	-6.43%
CPFL Santa Cruz	March	13.7%	13.31%	(b)	(b)	-1.28%	-8.42%

(a) Represents the average effect perceived by consumers, as a result of the elimination from the tariff base of financial components that had been added in the prior tariff adjustment.

(b) In 2018, the average annual tariff adjustment of CPFL Santa Cruz was at 5.71%, 4.41% regarding the economic tariff adjustment and 1.30% regarding relevant financial components. The average effect to be perceived by consumers of the original concessions are:

				Jaguari		Mococa		Leste Paulista		Sul Paulista		Santa Cruz
Effect perceived by consumers				21.15%		3.40%		7.03%		7.50%		5.32%

27.3 Energy Development Account (CDE) – Low-income, tariff discounts – judicial injunctions, and other tariff discounts

Law No. 12,783 of January 11, 2013 determined that the amounts related to the low-income subsidy, as well as other tariff discounts shall be fully subsidized by amount from the CDE.

In 2018, the Company recognized income of R$1,516,077 (R$1,536,366 in 2018 and R$1,419,128 in 2017), of which (i) R$78,277 relates to the low-income subsidy (R$78,081 in 2018 and R$ 96,882 in 2017), (ii) R$1,255,000 relates to other tariff discounts (R$1,354,845 in 2018 and R$1,226,777 in 2017) and (iii) R$182,800 relates to tariff discounts – CCRBT injunctions and subsidy (R$103,440 in 2018 and R$95,469 in 2017).

27.4 Energy Development Account – CDE

ANEEL, by means of Ratifying Resolution (“REH”) No. 2,510 of December 18, 2018, amended by REH No. 2,368 of February 9, 2018, established the definitive annual quotas of CDE for the year 2019. These quotas comprise: (i) annual quota of the CDE – USAGE account; and (ii) quota of the CDE – Energy account, (final settlements finished in March 2019), related to part of the CDE contributions received by the electric energy distribution concessionaires in the period from January 2013 to January 2014, charged from consumers and passed on to the CDE Account in up to five years from the RTE of 2015. ANEEL, by means of REH n° 2,521 of March 20, 2019, ANEEL established the payment in advance of quota intended for the amortization of the ACR Account, due to its positive balance, with payment and pass through to the CDE Account for March 2019 to August 2019, cancelling the previously REH nº 2,231 of 2017.

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( 28 ) COST OF ELECTRIC ENERGY

	In GWh			R$ thousand
	2019	2018	2017	2019	2018	2017
Electricity purchased for resale
Itaipu Binacional	11,021	11,117	11,779	2,793,901	2,668,346	2,350,858
PROINFA	1,102	1,111	3,595	397,242	330,638	560,153
Energy purchased through auction in the regulated market, bilateral contracts and spot market	66,283	61,461	62,600	14,199,139	13,969,953	14,269,265
PIS and COFINS credit	-	-	-	(1,483,542)	(1,502,673)	(1,562,779)
Subtotal	78,406	73,689	77,974	15,906,740	15,466,264	15,617,498

Electricity network usage charge
Basic network charges				2,080,667	2,114,720	1,541,629
Transmission from Itaipu				281,185	266,153	159,896
Connection charges				173,593	162,852	122,536
Charges for use of the distribution system				47,828	48,811	39,451
System service charges - ESS, net of transfers from CONER				4,385	(106,002)	(452,978)
Reserve energy charges - EER				122,553	134,824	(303)
PIS and COFINS credit				(245,958)	(249,458)	(126,213)
Subtotal				2,464,254	2,371,901	1,284,020

Total				18,370,994	17,838,165	16,901,518

( 29 ) OPERATING COSTS AND EXPENSES

	2019
	Cost of operation	Cost of services rendered to third parties	Operating Expenses			Total
	Cost of operation	Cost of services rendered to third parties	Selling	General and administrative	Others	Total
Personnel	945,628	2	173,133	361,787	-	1,480,550
Private pension plans	112,603	-	-	-	-	112,603
Materials	256,423	1,039	13,708	8,118	-	279,288
Third party services	219,464	2,641	173,376	319,403	-	714,884
Cost of infrastructure construction	-	2,086,057	-	-	-	2,086,057
Others	81,776	(7)	101,057	228,789	198,555	610,169
Collection fees	-	-	99,520	-	-	99,520
Rentals	50,974	-	-	22,397	-	73,371
Publicity and advertising	55	-	-	21,272	-	21,327
Legal, judicial and indemnities	-	-	-	172,495	-	172,495
Donations, contributions and subsidies	1,687	-	-	3,849	-	5,536
Gain (loss) on disposal, retirement and other noncurrent assets	-	-	-	-	189,566	189,566
Amortization of premium paid - GSF	13,470	-	-	-	-	13,470
Others	15,589	(7)	1,537	8,776	8,989	34,884
Total	1,615,893	2,089,732	461,275	918,099	198,555	5,283,551

	2018
	Cost of operation	Cost of services rendered to third parties	Operating Expenses			Total
	Cost of operation	Cost of services rendered to third parties	Selling	General and administrative	Others	Total
Personnel	901,333	-	172,700	340,442	-	1,414,476
Private pension plans	89,909	-	-	-	-	89,909
Materials	228,001	888	9,089	20,100	-	258,078
Third party services	210,234	2,294	166,693	312,533	-	691,754
Cost of infrastructure construction	-	1,772,162	-	-	-	1,772,162
Others	66,650	(6)	86,183	248,897	198,569	600,293
Collection fees	-	-	87,432	-	-	87,432
Rentals	43,898	-	-	22,898	-	66,796
Publicity and advertising	21	-	15	19,155	-	19,191
Legal, judicial and indemnities	-	-	-	186,686	-	186,686
Donations, contributions and subsidies	2,053	-	-	5,108	-	7,161
Gain (loss) on disposal, retirement and other noncurrent assets	-	-	-	-	210,840	210,840
Amortization of premium paid - GSF	13,413	-	-	-	-	13,413
Others	7,265	(6)	(1,264)	15,049	(12,271)	8,773
Total	1,496,127	1,775,339	434,665	921,972	198,569	4,826,672

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	2017
	Cost of operation	Cost of services rendered to third parties	Operating Expenses			Total
	Cost of operation	Cost of services rendered to third parties	Selling	General and administrative	Others	Total
Personnel	882,150	2	170,859	324,147	-	1,377,158
Private pension plans	113,887	-	-	-	-	113,887
Materials	222,650	1,061	2,444	23,818	-	249,973
Third party services	251,549	1,856	186,525	287,221	-	727,151
Cost of infrastructure construction	-	2,071,698	-	-	-	2,071,698
Others	157,113	(7)	69,903	218,247	152,279	597,535
Collection fees	11,710	-	68,757	-	-	80,467
Rentals	52,734	-	(148)	19,740	-	72,326
Publicity and advertising	202	-	1	17,412	-	17,615
Legal, judicial and indemnities	-	-	-	188,355	-	188,355
Donations, contributions and subsidies	88	-	2	3,924	-	4,014
Gain (loss) on disposal, retirement and other noncurrent assets	-	-	-	-	132,195	132,195
Amotization of the risk premium paid -GSF	9,594	-	-	-	-	9,594
Financial compensation for use of water resources	8,656	-	-	-	-	8,656
Impairment	-	-	-	-	20,437	20,437
Others	74,130	(7)	1,291	(11,184)	(353)	63,877
Total	1,627,350	2,074,611	429,732	853,433	152,279	5,137,405

( 30 ) FINANCE INCOME (EXPENSES)

	2019	2018	2017
Finance Income
Income from financial investments	263,241	222,773	457,255
Late payment interest and fines	312,450	276,350	265,455
Adjustment for inflation of tax credits	35,328	14,819	19,623
Adjustment for inflation of escrow deposits	33,721	37,322	49,502
Adjustment for inflation and exchange rate changes	62,969	70,201	60,999
Discount on purchase of ICMS credit	23,605	33,779	16,386
Adjustments to the sector financial asset (note 8)	88,079	80,240	-
PIS and COFINS on other finance income	(46,035)	(46,217)	(48,322)
PIS and COFINS on interest on capital	(32,040)	(39,355)	(27,798)
Other	162,285	112,503	87,214
Total	903,575	762,413	880,314

Finance expenses
Interest on debts	(1,130,447)	(1,328,693)	(1,661,060)
Adjustment for inflation and exchange rate changes	(295,189)	(368,141)	(540,053)
(-) Capitalized interest	25,641	28,606	50,543
Adjustments to the sector financial liability (note 8)	-	-	(82,333)
Use of public asset	(12,911)	(17,759)	(8,048)
Others	(216,916)	(179,114)	(126,917)
Total	(1,629,822)	(1,865,100)	(2,367,868)

Finance expenses, net	(726,247)	(1,102,687)	(1,487,554)

Interests were capitalized at an average rate of 8.09% p.a. in 2019 (8.27% p.a. in 2018 and 8.54% p.a. in 2017) on qualifying assets, in accordance with IAS 23.

In line item of Adjustment for inflation and exchange rate changes includes the effects of gains of R$207,055 (R$ 617,545 at 2018 and losses of R$ 235,852 in 2017) on derivative instruments (note 35).

( 31 ) SEGMENT INFORMATION

The segregation of the Company’s operating segments is based on the internal financial information and management structure and is made by type of business: electric energy distribution, electric energy generation (conventional and renewable sources), electric energy commercialization and services rendered activities.

Profit or loss per segment include items directly attributable to the segment, as well as those that can be allocated on a reasonable basis, if applicable. Prices charged between segments are based on similar market transactions. Note 1 presents the subsidiaries in accordance with their areas of operation and provides further information on each subsidiary and its business area and segment.

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The information segregated by segment is presented below, in accordance with the criteria established by Executive Officers:

2019	Distribution	Generation (conventional source)	Generation (renewable source)	Commercialization	Services	Subtotal	*Other ()**	Elimination	Total

Net operating revenue	24,217,986	710,730	1,426,648	3,487,008	87,791	29,930,163	2,311	-	29,932,474
(-) Intersegment revenues	42,311	502,151	501,363	3,696	526,574	1,576,095	-	(1,576,095)	-
Cost of electric energy	(15,623,488)	(133,035)	(319,634)	(3,342,502)	-	(19,418,659)	-	1,047,664	(18,370,994)
Operating costs and expenses	(4,940,793)	(122,509)	(404,845)	(48,710)	(476,006)	(5,992,863)	(52,544)	528,431	(5,516,977)
Depreciation and amortization	(820,206)	(118,573)	(645,722)	(7,048)	(26,511)	(1,618,061)	(62,992)	-	(1,681,053)
Income from electric energy service	2,875,809	838,765	557,810	92,443	111,848	4,476,675	(113,225)	-	4,363,450
Equity	-	349,090	-	-	-	349,090	-	-	349,090
Finance income	624,459	45,323	172,658	33,461	6,062	881,963	49,578	(27,966)	903,575
Finance expenses	(821,739)	(197,998)	(576,292)	(56,160)	(4,270)	(1,656,459)	(1,329)	27,966	(1,629,822)
Profit (loss) before taxes	2,678,529	1,035,180	154,176	69,744	113,639	4,051,269	(64,976)	-	3,986,293
Income tax and social contribution	(843,954)	(171,594)	(47,152)	(22,269)	(30,357)	(1,115,326)	(122,671)	-	(1,237,996)
Profit (loss) for the year	1,834,575	863,586	107,024	47,475	83,282	2,935,943	(187,647)	-	2,748,297
Purchases of PP&E and intangible assets	2,033,342	32,536	126,158	8,577	52,058	2,252,671	1,778	-	2,254,449

2018	Distribution	Generation (conventional source)	Generation (renewable source)	Commercialization	Services	Total	*Other ()**	Elimination	Total
Net operating revenue	22,457,079	661,831	1,468,254	3,491,300	58,163	28,136,627	-	-	28,136,627
(-) Intersegment revenues	10,238	482,548	468,065	5,152	474,646	1,440,650	-	(1,440,650)	-
Cost of electric energy	(15,022,304)	(102,421)	(320,346)	(3,352,745)	-	(18,797,816)	-	959,650	(17,838,165)
Operating costs and expenses	(4,440,783)	(104,606)	(407,211)	(47,287)	(437,709)	(5,437,597)	(39,333)	481,000	(4,995,931)
Depreciation and amortization	(766,796)	(116,372)	(623,106)	(2,346)	(22,521)	(1,531,143)	(209)	-	(1,531,351)
Income from electric energy service	2,237,434	820,979	585,655	94,074	72,579	3,810,721	(39,542)	-	3,771,179
Equity	-	334,198	-	-	-	334,198	-	-	334,198
Finance income	574,685	75,844	131,694	46,102	5,782	834,107	(22,092)	(49,602)	762,413
Finance expenses	(884,583)	(324,121)	(635,820)	(59,128)	(5,908)	(1,909,559)	(5,143)	49,602	(1,865,100)
Profit (loss) before taxes	1,927,537	906,899	81,530	81,049	72,453	3,069,467	(66,778)	-	3,002,690
Income tax and social contribution	(495,120)	(137,089)	37,276	(27,945)	(29,529)	(652,408)	(121,575)	-	(773,982)
Profit (loss) for the year	1,432,416	769,810	118,805	53,104	42,924	2,417,060	(188,352)	-	2,228,707
Purchases of PP&E and intangible assets	1,769,569	11,517	225,202	2,926	52,855	2,062,069	353	-	2,062,422

2017	Distribution	Generation (conventional source)	Generation (renewable source)	Commercialization	Services	Total	*Other ()**	Elimination	Total
Net operating revenue	21,068,435	741,842	1,489,932	3,402,804	40,611	26,743,625	1,281	-	26,744,905
(-) Intersegment revenues	8,182	448,427	469,152	11,297	444,935	1,381,993	-	(1,381,993)	-
Cost of electric energy	(14,146,739)	(147,380)	(348,029)	(3,196,028)	-	(17,838,176)	-	936,658	(16,901,518)
Operating costs and expenses	(4,695,445)	(156,345)	(389,443)	(47,296)	(398,188)	(5,686,717)	(51,121)	445,336	(5,292,502)
Depreciation and amortization	(703,601)	(120,554)	(617,017)	(3,054)	(19,760)	(1,463,986)	(65,066)	-	(1,529,052)
Income from electric energy service	1,530,833	765,990	604,596	167,724	67,598	3,136,740	(114,906)	-	3,021,834
Equity	-	312,390	-	-	-	312,390	-	-	312,390
Finance income	597,203	108,433	�� 137,765	25,895	11,349	880,644	20,505	(20,835)	880,314
Finance expenses	(1,163,689)	(437,009)	(648,571)	(58,801)	(7,101)	(2,315,170)	(73,532)	20,835	(2,367,868)
Profit (loss) before taxes	964,347	749,805	93,789	134,818	71,846	2,014,605	(167,933)	-	1,846,670
Income tax and social contribution	(299,510)	(95,688)	(74,125)	(44,527)	(16,994)	(530,845)	(72,784)	-	(603,629)
Profit (loss) for the year	664,837	654,117	19,665	90,290	54,852	1,483,761	(240,717)	-	1,243,042
Purchases of PP&E and intangible assets	1,882,502	8,973	621,046	2,927	54,149	2,569,598	835	-	2,570,433

(*) Others – refer basically to assets and transactions which are not related to any of the identified segments.

( 32 ) RELATED PARTY TRANSACTIONS

The Company’s controlling shareholders were, as of December 31, 2019, as follows:

· State Grid Brazil Power Participações S.A

Indirect subsidiary of State Grid Corporation of China, a Chinese state-owned company primarily engaged in developing and operating businesses in the electric energy sector.

· ESC Energia S.A.

Subsidiary of State Grid Brazil Power Participações S.A.

The direct and indirect interest in operating subsidiaries are described in note 1.

Controlling shareholders, associates companies, joint ventures and entities under common control that in some way exercise significant influence over the Company are considered to be related parties.

The main transactions are listed below:

a) Purchase and sale of energy and charges -refer basically to energy purchased or sold by distribution, commercialization and generation subsidiaries through short or long-term agreements and tariffs for the use of the distribution system (TUSD). Such transactions, when conducted in the free market, are carried out under conditions considered by the Company as similar to market conditions at the time of the trading, according to internal policies previously established by the Company’s management. When conducted in the regulated market, the prices charged are set through mechanisms established by the Grant Authority.

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b) Intangible assets, Property, plant and equipment, Materials and Service– refers mainly to rendered services in advisory and management of energy plants, consulting and engineering.

c) Advances –refer to advances for investments in research and development.

In September 2019, the Company acquired 243,771,824 shares from State Grid of its subsidiary CPFL Renováveis, as described in note 1.

Certain Company’s subsidiaries have supplemental retirement plans with Fundações CESP and Família Previdência, offered to their employees. For additional information, see note 20 Private Pension Plan.

The Group has a “Related Parties Committee”, comprising representatives of two independent members and one officer of the Company, responsible for analyzing the main transactions with related parties.

Management has considered the closeness of relationship with the related party together with other factors to determine the level of detail of the disclosed transactions and believes that significant information regarding transactions with related parties has been adequately disclosed.

The total compensation of key management personnel in 2019 was R$100,588 (R$ 90,783 in 2018 and R$ 73,670 in 2017). This amount comprises R$83,636 (R$78,335 in 2018 and R$64,516 in 2017) in respect of short-term benefits, R$2,251 (R$2,160 in 2018 and R$1,516 in 2017) of post-employment benefits and R$14,701 (R$10,288 in 2018 and R$ 7,638 in 2017) for other long-term benefits, and refers to the amount recognized on an accrual basis.

The intercompany loan balance at the parent company in the amount of R$ 424,387 refers mainly to the loan to the subsidiary CPFL Renováveis, with maturity until July 2020 and subject to interest equivalent to 107% of the CDI.

Transactions with entities under common control basically refer to transmission system charge paid by the Company’s subsidiaries to the direct or indirect subsidiaries of State Grid Corporation of China.

Transactions involving controlling shareholders, entities under common control or with significant influence and joint ventures:

	ASSETS		LIABILITIES		INCOME			EXPENSES
	December 31, 2019	December 31, 2018	December 31, 2019	December 31, 2018	2019	2018	2017	2019	2018	2017

Advances
BAESA – Energética Barra Grande S.A.	-	-	-	657	-	-	-	-	-	-
Foz do Chapecó Energia S.A.	-	-	-	930	-	-	-	-	-	-
ENERCAN - Campos Novos Energia S.A.	-	-	-	1,155	-	-	-	-	-	-
EPASA - Centrais Elétricas da Paraiba	-	-	-	418	-	-	-	-	-	-

Energy purchases and sales, and charges
Entities under common control (Subsidiaries of State Grid Corporation of China)*	-	-	2,998	16	-	-	-	200,771	152,369	91,302
BAESA – Energética Barra Grande S.A.	3,082	-	6,544	2,993	3,095	12	-	33,792	44,575	80,362
Foz do Chapecó Energia S.A.	1,773	-	45,009	41,850	20,901	18	-	495,111	490,713	381,193
ENERCAN - Campos Novos Energia S.A.	1,017	943	62,330	78,639	11,674	10,338	8,763	364,383	354,430	281,530
EPASA - Centrais Elétricas da Paraiba	-	-	6,737	13,397	-	19	-	79,701	143,845	137,376

Intangible assets, property, plant and equipment, materials and services rendered
Entities under common control (Subsidiaries of the State Grid Corporation of China)	-	-	-	-	-	-	-	77	-	-
BAESA – Energética Barra Grande S.A.	198	2	-	-	2,240	2,225	1,582	-	-	-
Foz do Chapecó Energia S.A.	11	15	-	-	2,148	2,143	1,726	-	-	-
ENERCAN - Campos Novos Energia S.A.	2	2	-	-	1,991	1,902	1,665	-	-	-
EPASA - Centrais Elétricas da Paraíba S.A.	-	534	-	-	392	3	(469)	-	-	-

Dividend and interest on own capital
BAESA – Energética Barra Grande S.A.	3,504	3	-	-	-	-	-	-	-	-
Chapecoense Geração S.A.	37,090	33,733	-	-	-	-	-	-	-	-
ENERCAN - Campos Novos Energia S.A.	59,289	65,010	-	-	-	-	-	-	-	-

Others
Instituto CPFL	-	-	-	-	-	-	-	3,711	4,151	3,613

( 33 ) INSURANCE

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The subsidiaries maintain insurance policies with coverage based on specialized advice and takes into account the nature and degree of risk. The amounts are considered sufficient to cover any significant losses on assets and/or responsibilities. The main insurancedw coverages are as follows:

Description	Type of cover	Dec. 31, 2019
Concession financial asset / Intangible assets	Fire, lightning, explosion, machinery breakdown, electrical damage and engineering risk	3,054,310
Transport	National and international transport	700,408
Stored materials	Fire, lightning, explosion and robbery	-
Automobiles	Comprehensive cover	3,396
Civil liability	Electric energy distributors, enviroment risks and others	255,000
Personnel	Group life and personal accidents	877,387
Warranties	Insurance guarantee	3,995,725
Others	Civil liability of administrators and others	310,237
Total		9,196,463

For the civil liability insurance of the officers, the insured amount is shared among the companies of the CPFL Energia Group. The premium is paid individually by each company involved, and the gross revenue is the base for the apportionment criterion.

( 34 ) RISK MANAGEMENT

The business of the Group comprise mainly the generation, commercialization and distribution of electric energy. As public utilities concessionaires, the activities and/or tariffs of its principal subsidiaries are regulated by ANEEL.

Risk management structure

At CPFL Group, the risk management is conducted through a structure that involves the Board of Directors and Supervisory Board, Advisory Committees from Board of Directors, Executive Board, Internal Audit, Risks and Compliance Management and business areas. This management is regulated by the Corporate Risk Management Policy, which describes the risk management model as well as the attributions of each agent.

The Board of Directors of CPFL Energia is responsible for deciding on the risk limit methodologies recommended by the Executive Board, and for being aware of the exposures and mitigation plans presented in the event these limits are exceeded. This forum is also responsible for being aware of and monitoring any important weaknesses in controls and/or processes, as well as relevant regulatory compliance failures, following up on the plans proposed by the Executive Board to correct them.

The Advisory Committee(s) of the Board of Directors, in its role(s) of technical body(ies), is responsible for becoming aware of (i) the risk monitoring models, (ii) the exposures to risks, and (iii) the control levels (including their effectiveness), as well as follow the progress of the mitigation actions signaled to readapt the exposures to the approved limits, supporting the Board of Directors in the performance of its statutory role related to risk management.

The Supervisory Board of CPFL Energia is responsible for, among other things, certifying that Management has means to identify the risks on the preparation and disclosure of the financial statements to which the CPFL Group is exposed, as well as for monitoring the effectiveness of the control environment.

The Executive Board of CPFL Energia is responsible for conducting businesses within the risk limits defined, and should take the required measures to avoid that the exposure to risks exceeds such limits and report any excess of the limit to the Board of Directors of CPFL Energia, presenting mitigation actions.

The Internal Audit, Risks and Compliance Management is responsible for the (i) coordination of the risk management process at the CPFL Group, developing and keeping updated Corporate Risk Management methodologies that involve the identification, measurement, monitoring and reporting of the risks to which the CPFL Group is exposed; (ii) periodic monitoring of the risk exposures and monitoring of the implementation of mitigation actions by the business managers; (iii) monitoring and reporting of the status of the mitigation plans signaled by for reclassification of the exposures to the approved limits; and (iv) assessment of the internalcontrol environment of the CPFL Group companies and interaction with the respective Business Managers, seeking the definition of action plans in the event of deficiencies identified.

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The business areas have the primary responsibility for the management of the risks inherent to its processes, and should conduct them within the exposure limits defined and implementing mitigation plans for the main exposures, as well as developing and maintaining an adequate environment of operational controls for the effectiveness and continuity of the business of their respective management units.

The main market risk factors that affect the businesses are as follows:

Foreign exchange risk: This risk derives from the possibility of the Group incurring losses and cash constraints due to fluctuations in exchange rates, increasing the balances of liabilities denominated in foreign currency or decreasing the portion of revenue arising from annual adjustment of part of the tariff based on the fluctuation of the dollar, in power sale agreements of the joint venture ENERCAN. The exposure related to funding in foreign currency is hedged by swap transactions. The exposure related to ENERCAN revenue, proportional to the interest held by the Group, is hedged by financial instruments such as the zero cost collar described in note 35.b.1. The quantification of these risks is presented in note 35. In addition, the subsidiaries are exposed in their operating activities to fluctuations in exchange rates on purchase of electricity from Itaipu. The compensation mechanism - CVA protects the distribution subsidiaries against any economic losses.

Interest rate risk and inflation indexes: This risk arises due to the possibility of the Group incurring losses due to fluctuations in interest rates and in inflation indexes, which would increase the finance costs related to borrowings and debentures. The quantification of this risk is presented in note 35.

Credit risk: This risk arises from the possibility of the subsidiaries incurring losses resulting from difficulties in collecting amounts billed to customers. This risk is managed by the sales and services segments through norms and guidelines applied in terms of the approval, guarantees required and monitoring of the operations. In the distribution segment, even though it is highly pulverized, the risk is managed through monitoring of defaults, collection measures and cutting off supply. In the generation segment there are contracts under the regulated environment (ACR) and bilateral agreements that call for the posting of guarantees.

Risk of under/overcontracting from distributors: Risk inherent to the energy distribution business in the Brazilian market to which the distributors of the CPFL Group and all distributors in the market are exposed. Distributors can be prevented from fully passing through the costs of their electric energy purchases in two situations: (i) volume of energy contracted above 105% of the energy demanded by consumers and (ii) level of contracts lower than 100% of such demanded energy. In the first case, the energy contracted above 105% is sold in the CCEE (Electric Energy Trading Chamber) and is not passed through to consumers, that is, in PLD (Spot price used to evaluate the energy traded in the spot market - “Preço de Liquidação de Diferenças”) scenarios lower than the purchase price of these contracts, there is a loss for the concession. In the second case, the distributors are required to purchase energy at the PLD price at the CCEE and do not have guarantees of full pass-through to the consumer tariffs, and there is also a penalty for insufficiency of contractual guarantee. These situations may be mitigated if the distributors are able to justify the involuntary exposures or surpluses.

Market risk of commercialization companies: This risk arises from the possibility of commercialization companies incurring losses due to variations in the spot prices that will value the positions of energy surplus or deficit of its portfolio in the free market, marked against the market price of electricity.

Risk of shortage of hydroelectric energy: The energy sold by the Company is mostly generated by hydro power plants. The lack of rain for a long period may result in reduction of the water volume in plants’ dams, which jeopardizes the recovery of its volume, and may result in losses due to an increase in costs for purchasing energy or in revenue reduction due to the implementation of extensive energy saving programs or the adoption of a new rationing program, as occurred in 2001.

In 2019, the rain levels were below the average, mainly in the second half of the year, leading to a reduction in storage levels in dams.

Risk of acceleration of debts: The Company has borrowing agreements and debentures with restrictive covenants normally applicable to these types of transactions, involving compliance with economic and financial ratios. These covenants are monitored and do not restrict the capacity to operate normally.

Regulatory risk: The electric energy supplied tariffs charged to captive consumers by the distribution subsidiaries are set by ANEEL, at intervals established in the concession agreements entered into with the Federal Government and in accordance with the periodic tariff review methodology established for the tariff cycle. Once the methodology has been ratified, ANEEL establishes tariffs to be charged by the distributor to thefinal consumers. In accordance with Law No. 8,987/1995, the tariffs set shall ensure the economic and financial equilibrium of the concession agreement at the time of the tariff review, but could result in lower adjustments than expected by the electric energy distributors.

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Financial instruments risk management

The Group maintains operating and financial policies and strategies to protect the liquidity, safety and profitability of their assets. Accordingly, control and follow-up procedures are in place as regards the transactions and balances of financial instruments, for the purpose of monitoring the risks and current rates in relation to market conditions. An assessment of this potential impact arising from the volatility of risk factors and their correlations is performed periodically to execute the decision making process and to comply with the risk management strategy, which may incorporate financial instruments, including derivatives.

Portfolios composed of these financial instruments are monitored monthly, allowing the monitoring of financial results and their impact on cash flow.

For the construction contracts for transmission companies signed in 2019, the Group is also exposed to market risks related to the volatility of commodity and construction material prices, such as the aluminum needed for the construction stage. In line with its risk management policy, risk mitigation strategies are used to reduce this volatility in cash flows. These mitigation strategies include derivative instruments, mainly forward transactions, futures and options.

Risk management controls: In order to manage the risks inherent to the financial instruments and to monitor the procedures established by Management, the Company and its subsidiaries use Luna and Bloomberg software systems to calculate the fair value adjustment, stress testing and duration of the instruments, and assess the risks to which the Company and its subsidiaries are exposed. Historically, the financial instruments contracted by the Company and its subsidiaries supported by these tools have produced adequate risk mitigation results. It must be stressed that the Company and its subsidiaries routinely contract derivatives, always with the appropriate levels of approval, only in the event of exposure that Management regards as a risk. The Company and its subsidiaries do not enter into transactions involving speculative derivatives.

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( 35 ) FINANCIAL INSTRUMENTS

The main financial instruments, at fair value and/or the carrying amount is significantly different of the respective fair value, classified in accordance with the Group’s accounting practices, are:


				December 31, 2019
	Note	Category / Measurement	*Level ()**	Carrying amount	Fair value

Asset
Cash and cash equivalent	5	(a)	Level 2	1,937,163	1,937,163
Investment assets	6	(a)	Level 1	851,004	851,004
Derivatives	35	(a)	Level 2	645,674	645,674
Derivatives - zero-cost collar	35	(a)	Level 3	5,419	5,419
Concession financial asset - distribution	11	(a)	Level 3	8,779,717	8,779,717
Total				12,218,977	12,218,977

Liability
Borrowings - principal and interest	18	(b)	Level 2 (***)	5,354,243	5,350,030
Borrowings - principal and interest (**)	18	(a)	Level 2	5,009,052	5,009,052
Debentures - Principal and interest	19	(b)	Level 2 (***)	8,054,153	8,056,757
Debentures - Principal and interest (**)	19	(a)	Level 2	492,125	492,125
Derivatives	35	(a)	Level 2	35,557	35,557
				18,945,130	18,943,521
(*) Refers to the hierarchy for fair value measurement
(**) As a result of the initial designation of this financial liability, the consolidated balances reported a loss of R$ 127,102 in 2019 (a gain of R$ 37,421 in 2018).
(***) Only for disclosure purposes, in accordance with IFRS 7

Key
Category:
(a) - Measured at fair value through profit or loss
(b) - Measured at amortized cost

The classification of financial instruments in “amortized cost” or “fair value through profit or loss” is based on business model and in the characteristics of expected cash flow for each instrument.

The financial instruments for which the carrying amounts approximate the fair values at the end of the reporting period are:

·	Financial assets: (i) consumers, concessionaires and licensees, (ii) leases, (iii) associates, subsidiaries and parent company, (iv) receivables – CDE, (v) pledges, funds and restricted deposits, (vi) services rendered to third parties, (vii) Collection agreements, and (viii) sector financial asset.
·	Financial liabilities: (i) trade payables, (ii) regulatory charges, (iii) use of public asset, (iv) consumers and concessionaires payable, (v) FNDCT/EPE/PROCEL, (vi) collection agreement, (vii) reversal fund, (viii) payables for business combination, (ix) tariff discount CDE, and (x) sector financial liability.

In addition, in 2019 there were no transfers between hierarchical levels of fair value.

a) Valuation of financial instruments

As mentioned in note 4, the fair value of a security corresponds to its maturity value (redemption value) adjusted to present value by the discount factor (relating to the maturity date of the security) obtained from the market interest curve, in Brazilian reais.

The three levels of the fair value hierarchy are:

· Level 1: quoted prices in an active market for identical instruments;

· Level 2: observable inputs other than quoted prices in an active market that are observable for the asset or liability, directly (i.e. as prices) or indirectly (i.e. derived from prices);

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· Level 3: inputs for the instruments that are not based on observable market data.

Pricing of forward and futures contracts is on the basis of future curves of the underlying assets. Said curves are usually provided by the stock exchanges on which these assets are traded, or other market price providers. When price is not available for the intended maturity, it is obtained on the basis of interpolation between available maturities.

As the distribution subsidiaries have classified their concession financial asset as fair value through profit or loss, the relevant factors for fair value measurement are not publicly observable. The fair value hierarchy classification is therefore level 3. The changes between years and the respective gains in profit for the year of R$281,340 (R$345,015 in 2018 and R$ 204,443 in 2017), and the main assumptions are described in note 11 and 27.

Additionally, the main assumptions used in the fair value measurement of the zero-cost collar derivative, the fair value hierarchy of which is Level 3, are disclosed in note 35 b.1.

The Company recognizes in “investments” in the financial statements the 5.94% interest held by the indirect subsidiary Paulista Lajeado Energia S.A. in the total capital of Investco S.A. (“Investco”), in the form of 28,154,140 common shares and 18,593,070 preferred shares not quoted in stock markets. The main objective of its operations is to generate electric energy for commercialization by the shareholders holding the concession. The Company recognizes theinvestment at fair value, for which cost is the best estimate of it, since there are no available reliable information at fair value, according to IFRS 9.

b) Derivatives

The Group has the policy of using derivatives to reduce their risks of fluctuations in exchange and interest rates (economichedge), without any speculative purposes. The Group has exchange rate derivatives compatible with the exchange rate risks net exposure, including all the assets and liabilities tied to exchange rate changes.

The derivative instruments entered into by the Group are currency or interest rate swaps with no leverage component, margin call requirements or daily or periodical adjustments. Furthermore, in 2015 subsidiary CPFL Geração contracted a zero-cost collar (see item b.1 below) and, in 2019, a forward purchase derivative of aluminum without physical delivery.

As a large part of the derivatives entered into by the subsidiaries have their terms fully aligned with the hedged debts, and in order to obtain more relevant and consistent accounting information through the recognition of income and expenses, these debts were designated at fair value, for accounting purposes (note 18 and 19). Other debts with terms different from the derivatives contracted as a hedge continue to be recognized at amortized cost. Furthermore, the Group did not adopt hedge accounting for derivative instruments.

In 2019, the subsidiary CPFL Geração, aiming at hedging input purchases for the construction of new transmission projects, carried out transactions with derivatives, through forward purchases of aluminum for future settlement, in order to reduce the risk of price fluctuation for the aluminum (pure) purchase period.

At December 31, 2019, the Group had the following swap transactions, all traded on the over-the-counter market:

Fair values (carrying amounts)

Strategy

Assets

Liabilities

Fair value, net

Values at cost, net (1)

Gain (loss) on Fair value adjustment

Currency / debt index

Currency /swap index

Maturity range

Notional

Derivatives to hedge debts designated at fair value

Exchange rate hedge

Bank Loans - Law 4.131

542,278

(29,231)

513,047

487,030

26,017

US$ + (Libor 3 months + 0.8% to 1.55%) or (1.96% to 3.65%)

99.80% to 116% of CDI or CDI + 0.12%

October 2018 to March 2022

3,838,488

Bank Loans - Law 4.131

13,391

(6,157)

7,234

9,074

(1,840)

Euro + 0.42% to 0.96%

102% to 105.8% of CDI

April 2019 to March 2022

834,630

555,670

(35,388)

520,282

496,104

24,178

Hedge variation price index

Debêntures

90,004

19,486

70,517

IPCA + 5.8%

100.15% to 104.3% of CDI

August 2025

416,600

Subtotal debt hedge

645,673

(35,388)

610,285

515,591

94,695

Other (2):

Index / currency

Maturity range

Notional in US$

Zero cost collar

5,419

US$

from jul/18 to sep/20

22,174

Term of product (aluminum)

(16)

aluminum (US$/ton)

Jul-20

3,889

NDF - aluminum

(153)

(205)

US$

Jul-20

6,296

Subtotal other

5,419

(169)

5,250

5,198

Total

651,093

(35,557)

615,536

515,643

99,893

Current

281,326

(29,400)

Noncurrent

369,767

(6,157)

⁽¹⁾The value at cost are the derivative amount without the respective fair value adjustment, while the notional refers to the balance of the debt and is reduced according to the respective amortization;

⁽²⁾Due to the characteristics of these derivatives, the notional amount is presented in U.S. dollar.

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For further details on terms and information on debts and debentures, see notes 18 and 19.

Changes in derivatives are stated below:

	December 31, 2018	Interests and monetary restatements	Repayments of principal	December 31, 2019
Derivatives
to hedge debts designated at fair value	631,368	75,241	(191,018)	515,591
to hedge debts not designated at fair value	21,548	(857)	(20,691)	-
Others	-	7,600	(7,548)	52
Mark-to-market (*)	(27,722)	127,615	-	99,893
	625,194	209,599	(219,257)	615,536

	December 31, 2017	Interests and monetary restatements	Repayments of principal	December 31, 2018
Derivatives
to hedge debts designated at fair value	526,148	662,147	(556,927)	631,368
to hedge debts not designated at fair value	17,881	(21,817)	25,484	21,548
Others	-	11,984	(11,984)	-
Mark-to-market (*)	9,095	(36,817)	-	(27,722)
	553,124	615,497	(543,427)	625,194

	December 31, 2016	Interests and monetary restatements	Repayments of principal	December 31, 2017
Derivatives
to hedge debts designated at fair value	602,476	(189,466)	113,138	526,148
to hedge debts not designated at fair value	7,181	(1,175)	11,875	17,881
Others (zero cost collar)	-	22,372	(22,372)	-
Mark-to-market (*)	76,679	(67,584)	-	9,095
	686,336	(235,853)	102,641	553,124

(*) The effects on profit or loss and OCI for the year ended December 31, 2019 related to the fair value adjustments (MTM) of the derivatives are: (i) a gain of R$ 139,361 for debts designated at fair value, (ii) a loss of R$ 577 for debts not designated at fair value and (iii) a loss of R$ 11,169 for other derivatives.

As mentioned above, certain subsidiaries applied the fair value option to borrowings and debentures for which there were derivative instruments totally related (note 18 and 19).

The Group have recognized gains and losses on their derivatives. However, as these derivatives are used as a hedge, these gains and losses minimized the impact of variations in exchange and interest rates on the hedged debts. For the years 2019, 2018 and 2017, the derivatives resulted in the following impacts on the result, recognized in the line item of finance costs on adjustment for inflation and exchange rate changes and in the consolidated comprehensive income in the credit risk in the fair value adjustment, the last one related to debts at fair value:

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	Gain (Loss) on Profit or Loss			Gain (Loss) on Comprehensive Income
Hedged risk / transaction	2019	2018	2017	2019	2018
Interest rate variation	16,559	(19,747)	1,446	-	-
Fair value adjustment	46,243	13,135	8,960	2,685	272
Exchange variation	65,424	672,061	(169,714)	-	-
Fair value adjustment	78,829	(47,904)	(76,544)	(148)	(2,025)
	207,055	617,545	(235,852)	2,537	(1,753)

b.1) Zero-cost collar derivative contracted by CPFL Geração

In 2015, subsidiary CPFL Geração contracted US$ denominated put and call options, involving the same financial institution as counterpart, and which on a combined basis are characterized as an operation usually known as zero-cost collar. The contracting of this operation does not involve any kind of speculation, inasmuch as it is aimed at minimizing any negative impacts on future revenues of the joint venture ENERCAN, which has electric energy sale agreements with annual restatement of part of the tariff based on the variation in the US$. In addition, according to Management’s view, the scenario in 2015 was favorable for contracting this type of financial instrument, considering the high volatility implicit in dollar options and the fact that there is no initial cost for same.

The total amount contracted was US$ 111,817, with due dates between October 1, 2015 and September 30, 2020. As at December 31, 2018, the total amount contracted was US$ 22,174, considering the options already settled up to date. The exercise prices of the dollar options vary from R$ 4.20 to R$ 4.40 for the put options and from R$ 5.40 to R$ 7.50 for the call options.

These options have been measured at fair value in a recurring manner, as required by IFRS 9. The fair value of the options that are part of this operation has been calculated based on the following premises:

Valuation technique(s) and key information	We used the Black Scholes Option Pricing Model, which aims to obtain the theoretical value of the options involving the following variables: the current price of the asset, the strike price of the option, the risk-free interest rate, the time left until the option’s maturity date and the volatility of the asset.
Significant unobservable inputs	Volatility determined based on the average market pricing calculations, future dollar and other variables applicable to this specific transaction, with average variation of 13.22%.
Relationship between unobservable inputs and fair value (sensitivity)	A slight rise in long-term volatility, analyzed on an isolated basis, would result in an insignificant increase in fair value. If the volatility were 10% higher and all the other variables remained constant, the net carrying amount (asset) would increase by R$ 203, resulting in a net asset of R$ 5,623.

The following table reconciles the opening and closing balances of the call and put options for the year ended December 31, 2019, as required by IFRS 13:

	Assets	Liabilities	Net

As of December 31, 2016	57,715	-	57,715
Measurement at fair value	16,715	-	16,715
Net cash received from settlement of flows	(22,372)	-	(22,372)
As of December 31, 2017	52,058	-	52,058
Measurement at fair value	(23,707)	-	(23,707)
Net cash received from settlement of flows	(11,984)	-	(11,984)
As of December 31, 2017	16,367	-	16,367
Measurement at fair value	(3,400)	-	(3,400)
Net cash received from settlement of flows	(7,548)	-	(7,548)
As of December 31, 2018	5,419	-	5,419

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The fair value measurement of these financial instruments was recognized in the statement of profit or loss for the year, and no effects were recognized in other comprehensive income.

c) Concession financial assets

As the distribution subsidiaries have classified the respective financial assets of the concession as measured at fair value through profit or loss, the relevant factors to measure the fair value are not publicly observable and there is no active market. Therefore, the classification of the fair value hierarchy is level 3.

d) Market risk

Market risk is the risk that changes in market prices – e.g. foreign exchange rates and interest rates – will affect the Group’s income or the value of its holdings of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return. The Group uses derivatives to manage market risks.

Sensitivity Analysis

The Group performed sensitivity analyses of the main risks to which their financial instruments (including derivatives) are exposed, mainly comprising variations in exchange and interest rates.

If the risk exposure is considered an asset, the risk to be taken into account is a reduction in the pegged indexes, resulting in a negative impact on the results of the Group. Similarly, if the risk exposure is considered a liability, the risk is of an increase in the pegged indexes and the consequent negative effect on the results. The Group therefore quantify the risks in terms of the net exposure of the variables (dollar, euro, CDI, IGP-M, IPCA, TJLP and SELIC), as shown below:

d.1) Exchange ratevariation

Considering the level of net exchange rate exposure at December 31, 2019 is maintained, the simulation of the effects by type of financial instrument for three different scenarios would be:

				Income (expense) - R$ thousand
Instruments	Exposure R$ thousand (a)		Risk	Currency depreciation (b)	Currency appreciation / depreciation of 25%	Currency appreciation / depreciation of 50%
Financial liability instruments	(4,174,769)			(87,520)	978,052	2,043,624
Derivatives - Plain Vanilla Swap	4,221,801			88,506	(989,071)	(2,066,647)
	47,032		drop in the dollar	986	(11,019)	(23,023)

Financial liability instruments	(835,977)			(34,709)	182,963	400,634
Derivatives - Plain Vanilla Swap	847,774			35,198	(185,545)	(406,288)
	11,797		drop in the euro	489	(2,582)	(5,654)

Total	58,829			1,475	(13,601)	(28,677)

Effects in the accumulated comprehensive income				1,271	(11,312)	(23,896)
Effects in the profit or loss for the year				204	(2,289)	(4,781)

				Income (expense) - R$ thousand
Instruments	Exposure US$ thousand		Risk	Currency depreciation (b)	Currency appreciation / depreciation of 25%(c)	Currency appreciation / depreciation of 50%(c)
Derivatives - Zero-cost collar	22,174	(d)	dollar apprec.	(682)	(8,989)	(17,296)
Term of product (aluminum)	3,889	(d)	drop in the aluminum (US$/ton)	-	(2,891)	(3,852)
NDF - aluminum	6,296	(d)	drop in the dollar	-	(6,255)	(12,511)

(a) The exchange rates considered as of December 31, 2019 were R$ 4.03 per US$ 1.00 and R$ 4.53 per € 1.00.

(b) As per the exchange curves obtained from information made available by B3 S.A. Brasil, Bolsa, Balcão, with the exchange rate beingconsidered at R$ 4.12 and R$ 4.72, and exchange depreciation at 2.10% and 4.15%, for the US$ and €, respectively, as of December 31, 2019.

(c) As required by CVM Instruction 475/2008, the percentage increases in the ratios applied refer to the information made available by the B3 S.A. Brasil, Bolsa, Balcão.

(d) Owing to the characteristics of these derivatives, the notional amount is presented in US$.

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Except for the zero cost collar, based on the net exchange exposure in US$ and euro being an asset, the risk is a drop in the dollar and euro and, therefore, the local exchange rate is appreciated by 25% and 50% in relation to the probable exchange rate.

d.2) Interest rate variation

Assuming that the scenario of net exposure of the financial instruments indexed to variable interest rates at December 31, 2019 is maintained, the net finance cost for the next 12 months for each of the three scenarios defined, would be:

Income (expense) - R$ thousand

Instruments

Exposure
R$ thousand

Risk

Rate in the period

Most likely scenario (a)

Likely scenario

Raise/drop of
index by 25% (b)

Raise/drop of
index by 50% (b)

Financial asset instruments

2,919,915

132,564

165,705

198,846

Financial liability instruments

(6,516,480)

(295,848)

(369,810)

(443,772)

Derivatives -Plain Vanilla Swap

(4,976,115)

(225,916)

(282,395)

(338,873)

(8,572,680)

raise of CDI

5.97%

4.54%

(389,200)

(486,500)

(583,799)

Financial liability instruments

(145,558)

(4,469)

(5,586)

(6,703)

(145,558)

raise of IGP-M

7.3%

3.07%

(4,469)

(5,586)

(6,703)

Financial liability instruments

(3,183,323)

(162,031)

(202,539)

(243,047)

(3,183,323)

raise of TJLP

6.3%

5.09%

(162,031)

(202,539)

(243,047)

Financial liability instruments

(3,422,062)

(156,388)

(117,291)

(78,194)

Derivatives -Plain Vanilla Swap

516,826

23,619

17,714

11,809

Concession financial asset

8,779,717

401,233

300,925

200,617

5,874,481

drop in the IPCA

4.2%

4.57%

268,464

201,348

134,232

Sector financial asset and liability

993,775

45,316

33,987

22,658

Financial liability instruments

(83,073)

(3,788)

(2,841)

(1,894)

910,702

drop in the SELIC

5.97%

4.56%

41,528

31,146

20,764

Total

(5,116,378)

(245,708)

(462,131)

(678,553)

Effects in the accumulated comprehensive income

1,289

1,047

804

Effects in the profit or loss for the year

(246,997)

(463,178)

(679,357)

(a) The indexes were obtained from information available in the market.

(b) In compliance with CVM Instruction 475/08, the percentages of increase were applied to the indexes in the probable scenario.

Additionally, the debts exposed to fixed indexes would generate an expense of R$ 52,075.

e) Credit risk

Credit risk is the risk of financial loss to the Group if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Group’s receivables from Consumers, Concessionaires and Licensees and financial instruments. Monthly, the risk is monitored and classified according to the current exposure, considering the limit approved by Management.

Impairment losses on financial assets recognized in profit or loss are presented in note 7 – Consumers, Concessionaires and Licensees.

Receivables and contract assets – Consumers, Concessionaries and Licensees

The Group’s exposure to credit risk is influenced mainly by the individual characteristics of each customer. However, Management also considers the factors that may influence the credit risk of its customer base.

The Group uses a provision matrix to measure the expected credit losses of trade receivables according to the consumer class (Residential, Commercial, Rural, Public Power, Public Lighting, Public Services), Other Revenues and Unbilled Revenue, comprising mostly a large number of dispersed balances.

F - 79

Loss rates are based on actual credit loss experience over the past. These rates reflect differences between economic conditions during the period over which the historical data have been collected, current conditions and the Group’s view of future economic conditions over the expected lives of the receivables. Accordingly, an “adjusted” revenue was calculated, reflecting the Group perception on expected loss. Such “adjusted” revenue was allocated by consumption class (matrix).

F - 80

According to the interval currently used in the allowance guided by the regulatory parameters as follows:

Class	Days	Period
Residential	90	Revenue of 3 months prior to the current month
Commercial and other revenues	180	Revenue of 6 months prior to the current month
Industrial, rural, public power in general	360	Revenue of 12 months prior to the current month
Unbilled	-	Uses revenue of the same month

Therefore, based on the assumptions above, an “Adjusted” ratio of the expected credit losses (“ECL”) allowance for the month is calculated, which was determined dividing the “Actual ECL” allowance by the “Adjusted Revenue” for each month. Then, the ECL allowance is estimated monthly, considering the respective moving average for the months of the "Adjusted” monthly ratios andcalculated overthe actual revenue for the current month.

Based on this criterion, the ECL allowance percentage to be applied is changed monthly to the extent that the moving average is calculated.

The methodology used by Management includes a percentage that is compliant with the IFRS rule described as expected credit losses, including in a single percentage the probability of loss, weighted by the expected loss and possible outcomes, that is, includingProbability of default (“PD”),Exposure at default (“EAD”) andLoss Given Default (“LGD”).

Macroeconomic factors

After studies developed by the Company to assess which variables present a correlation ratio with the actual amount of Expected Credit Losses Allowance, no ratios or macroeconomic factors that would have material impacts or that had direct correlation with the default level were identified, due to the electric sector characteristic of having instruments that mitigate the risk of losses, such as cutting energy supply to default customers.

Cash and cash equivalents

The Group limits its exposure to credit risk by investing only in liquid debt securities and only with counterparties that have a credit rating of at least AA-.

The Group considers that its cash and cash equivalents have low credit risk based on the external credit ratings of the counterparties.Management did not identify for the years 2018 and 2019 that the securities had a significantly change in credit risk.

f) Liquidity analysis

The Company manages liquidity risk by continuously monitoring forecast and actual cash flows, and by matching the maturity profiles of its financial liabilities. The table below sets out details of the contractual maturities of the financial liabilities at December 31, 2019, taking into account principal and future interest, and is based on the undiscounted cash flow, considering the earliest date on which the Group have to settle their respective obligations.

December 31, 2019	Note	Less than 1 month	1-3 months	3 months to 1 year	1-3 years	4-5 years	More than 5 years	Total
Trade payables	17	3,238,843	21,258	78	211,697	-	148,247	3,620,123
Borrowings - principal and interest	18	222,237	580,245	2,842,610	4,941,612	1,890,206	2,845,013	13,321,923
Derivatives	35	-	9,332	45,060	9,572	-	-	63,964
Debentures - principal and interest	19	10,811	101,704	770,047	3,691,282	4,053,800	1,592,045	10,219,689
Regulatory charges	21	231,130	1,122	-	-	-	-	232,252
Use of public asset		981	1,962	8,828	17,096	28,494	45,591	102,952
Others	24	103,808	110,173	45,357	3,423	3,423	189,707	455,891
Consumers and concessionaires		57,182	57,429	-	-	-	183,938	298,549
EPE / FNDCT / PROCEL (*)		44	5,158	44,073	-	-	-	49,275
Collections agreement		46,439	47,301	-	-	-	-	93,740
Reversal fund		143	285	1,284	3,423	3,423	5,769	14,327
Total		3,807,810	825,796	3,711,980	8,874,682	5,975,923	4,820,603	28,016,794

F - 81

Derivatives

The Group adopts a policy of using derivatives with the purpose of hedge (economic hedge) against the risks of fluctuations in exchange rates and interest rates, mostly comprising currency and interest rate swaps. The derivative transactions are entered into with first-tier banks and financial institutions with a rating of at least AA-, based on the main credit rating agencies in the market (note 35).

The Group adopts the policy of offering financial guarantees for the obligations of its subsidiaries and joint ventures. At December 31, 2019 and December 31, 2018, the Company had provided guarantees to certain financial institutions for the credit facilities granted to its subsidiaries and joint ventures, as mentioned in notes 18 and 19.

( 36 ) NON-CASH TRANSACTIONS

	December 31, 2019	December 31, 2018

Interest capitalized	25,641	28,606
Repayment of intercompany loans with of noncontrolling shareholders' dividends	81	377
Provision for environmental costs capitalized in property, plant and equipment	83,334	1,684
Transfers between property, plant and equipment, intangible and other assets	1,662	5,515

( 37 ) COMMITMENTS

The Group’s commitments, mainly related to long term agreements for energy purchases and power plant constructions, at December 31, 2019, are as follows:

Subsidiaries		Consolidated
Commitments at December 31, 2019	Duration	Less than 1 year	1-3 years	4-5 years	More than 5 years	Total
Rentals	Up to 13 years	38,223	71,906	68,779	82,430	261,338
Energy purchase agreements (except Itaipu)	Up to 25 years	11,988,989	21,701,899	22,211,015	41,829,746	97,731,649
Energy purchase from Itaipu	Up to 25 years	2,896,696	5,642,618	6,097,490	15,803,644	30,440,448
Energy system service charges	Up to 29 years	2,762,294	7,192,517	9,172,126	25,725,396	44,852,333
GSF renegotiation	Up to 28 years	16,468	37,886	36,484	228,865	319,703
Power plant constrution projects	Up to 14 years	757,367	654,777	239,322	1,119,285	2,770,751
Total		18,460,037	35,301,603	37,825,216	84,789,366	176,376,222

Joinv Venture		Consolidated
Commitments at December 31, 2019	Duration	Less than 1 year	1-3 years	4-5 years	More than 5 years	Total
Power plant constrution projects	Up to 5 years	3,502,439	5,321,975	693,788	-	9,518,202
GSF renegotiation	Up to 17 years	33,566	132,856	132,965	396,102	695,489
		3,536,005	5,454,831	826,754	396,102	10,213,692

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

F - 82

( 38 ) SUBSEQUENT EVENTS

a. Borrowings

From January 1, 2020 to the date of approval of these financial statements, the Company’s subsidiaries obtained borrowings with the following conditions and details:

R$ thousand

Category

Subsidiary

Released until March

Interest

Repayment

Utilization

Annual finance charges

Annual effective rate

Effective rate with derivatives

Foreign currency - Law 4.131

US$

CPFL Paulista

174,960

Quarterly

Annual from february 2023

Working capital reinforcement

USD + 2.39%

CDI + 0.85%

CPFL Paulista

196,567

Quarterly

Single installment in february 2025

Working capital reinforcement

USD + 2.40%

CDI + 0.89%

RGE

100,000

Semiannual

Single installment in january 2025

Working capital reinforcement

USD + 2.64%

CDI + 0.90%

CPFL Brasil

107,000

Semiannual

Single installment in february 2023

Working capital reinforcement

USD + 1.83%

CDI + 0.61%

CPFL Renováveis

120,000

Semiannual

Annual from february 2023

Working capital reinforcement

USD + 2.07%

CDI + 0.80%

CPFL Santa Cruz

108,000

Semiannual

Annual from february 2023

Working capital reinforcement

USD + 2.07%

CDI + 0.80%

RGE

418,280

Semiannual

Annual from february 2023

Working capital reinforcement

USD + 2.07%

CDI + 0.80%

RGE

185,000

Quarterly

Annual from february 2023

Working capital reinforcement

USD + Libor 3M + 0.87%

CDI + 0.83%

RGE

225,497

Quarterly

Annual from february 2023

Working capital reinforcement

USD + 1.84%

(1.94% in Mar/2021)

USD + 1.84%

(1.94% in Mar/2021)

CDI + 0.85%

CPFL Paulista

274,046

Quarterly

Annual from february 2023

Working capital reinforcement

USD + Libor 3M + 0.99%

CDI + 0.80%

Euro

CPFL Piratininga

419,760

Quarterly

Single installment in march 2025

Working capital reinforcement

EURO + 0.70%

CDI + 0.83%

CPFL Paulista

534,880

Quarterly

Single installment in february 2023

Working capital reinforcement

EURO + 0.43%

CDI + 0.58%

CPFL Paulista

566,000

Quarterly

Single installment in march 2023

Working capital reinforcement

EURO + 0.57%

CDI + 1,10%

3,429,989

F - 83

b. COVID-19

On March 11, 2020, the World Health Organization (WHO) declared the coronavirus (COVID-19) to be a pandemic. The outbreak triggered significant decisions from governments and private sector entities that added to the potential impact of the outbreak, increased the degree of uncertainty for economic agents and may impact financial statements. The world’s main economies and the main economic blocs are assessing significant stimulus packages to overcome the potential economic recession that the measures to mitigate the spread of COVID-19 may cause.

In Brazil, the executive and legislative branches of the government edited various acts to prevent and contain the pandemic, as well as to mitigate the respective economic impacts, particularly Legislative Decree No. 6, edited on March 20, 2020, which declared a state of public calamity. The state and municipal governments also edited various acts seeking to restrict the free movement of people and commercial and service activities, in addition to making emergency investments in the healthcare sector available.

Management has constantly assessed the impact of the outbreak on the operations and the equity and financial position of the Company and its subsidiaries, in order to implement the appropriate measures to mitigate the impact to operations. Up until the authorization date for the issuance of these financial statements, the following measures have been taken and the primary matters that are constantly being monitored are listed below:

o	Implementing temporary measures for employees, such as home office plans, adapting collective spaces to avoid agglomerations of people, and other applicable measures relating to health;
o	Negotiating with suppliers of equipment to evaluate delivery deadlines in light of the new scenario, being that so far there have not been any indications of significant risks of delay that could impact operations;
o	Evaluating contractual terms with financial institutions relating to loans and financing as well as supplier payments to mitigate any potential liquidity risks;
o	Monitoring the variations of market indexes that may affect loans, financing and debentures;
o	Evaluating potential renegotiations with customers, due to a possible macroeconomic downturn and a consequent reduction in energy consumption. Management’s expectation is that such renegotiations will be mostly directed towards temporary shifts in contracted quantities;
o	Monitoring possible over-contracting of the Group’s distributors due to load reductions and consequent energy surpluses exceeding the 5% provided for in the regulatory requirements;
o	Monitoring the default of the Group’s distributors, especially in light of the 90-day suspension beginning March 25, 2020 of the service interruption due to delinquency for certain consumers (residential and essential services, in accordance with the specific rules established by ANEEL). Management’s expectation is that most of this impact will be temporary, until the service interruption due to delinquency policies are reestablished and/or new possible actions to offset these impacts through regulatory mechanism may be implemented.

Due to the relevance and complexity of these matters from a regulatory perspective, many of these issues are being discussed with the regulatory agency, ANEEL.

The financial and economic effect on the Company and its subsidiaries during the course of the 2020 financial year will depend on the outcome of this crisis and its macroeconomic impacts, especially with respect to reductions in economic activity, as well as the extent of social isolation. The Company and its subsidiaries will continue to monitor the effects of the crisis and its impacts on their operations and financial statements constantly.

( 39 ) CONDENSED UNCONSOLIDATED FINANCIAL INFORMATION

Since the condensed unconsolidated financial information required by Rule 12-04 of Regulation S-X is not required under IFRS issued by the International Accounting Standards Board - IASB, such information was not included in the original financial statements filed with the Brazilian Securities and Exchange Commissions – CVM. In order to attend the specific requirements of the Securities and Exchange Commission (the “SEC”), Management has incorporated the condensed unconsolidated information in these financial statements as part of the Form 20-F.

The condensed unconsolidated financial information of CPFL Energia, as of December 31, 2019 and December 31, 2018 and income statements for the years ended on December 31, 2019, 2018 and 2017 presented herein was prepared considering the same accounting policies as described in note 3 to Company’s consolidated financial statements.

F - 84

UNCONSOLIDATED STATEMENTS OF FINANCIAL POSITION

ASSETS	December 31, 2019	December 31, 2018
Cash and cash equivalents	33,909	79,364
Dividends and interest on capital	816,205	701,731
Income tax and social contribution recoverable	78	9,441
Other taxes recoverable	58,947	8,646
Other receivables	400	417
Total current assets	909,539	799,599
Intragroup loans	424,387	72,933
Escrow deposits	453	703
Deferred tax assets	85,474	112,522
Other receivables	3,960	4,863
Investments	12,327,132	9,816,139
Property, Plant and Equipment	2,226	1,087
Intangible assets	120	110
Total noncurrent assets	12,843,753	10,008,356
Total assets	13,753,291	10,807,954

LIABILITIES	December 31, 2019	December 31, 2018
Trade payables	4,698	2,854
Income tax and social contribution payable	40,629	8,261
Other taxes, fees and contributions	25,315	5,258
Dividends	645,737	491,602
Other payables	22,318	23,405
Total current liabilities	738,697	531,380
Provision for tax, civil and labor risks	123	241
Other payables	20,090	13,584
Total noncurrent liabilities	20,213	13,825
Equity	12,994,381	10,262,749
Total liabilities and equity	13,753,291	10,807,954

UNCONSOLIDATED STATEMENTS OF PROFIT OR LOSS FOR THE YEAR

	2019	2018	2017
Net operating revenue	2,309	1	1
General and administrative expenses	(52,712)	(43,930)	(42,771)
Depreciation and amortization	(273)	(201)
Other general and administrative expenses	(52,439)	(43,729)
Other operating expenses	-	9	-
Income from electric energy service	(50,403)	(43,920)	(42,770)
Equity interests in subsidiaries, associates and joint ventures	2,827,718	2,250,835	1,349,766

Profit before finance results	2,777,315	2,206,915	1,306,996

Finance income (expenses)	48,019	(27,300)	(56,471)

Profit before taxes	2,825,333	2,179,616	1,250,525
Social contribution and income tax	(122,662)	(121,575)	(70,775)
Profit for the year	2,702,671	2,058,040	1,179,750

F - 85

UNCONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEAR

	2019	2018	2017
OPERATING CASH FLOW
Profit before taxes	2,825,333	2,179,616	1,250,525
ADJUSTMENT TO RECONCILE PROFIT TO CASH FROM OPERATING ACTIVITIES
Depreciation and amortization	273	201	217
Provision for tax, civil and labor risks	408	(117)	61
Interest on debts, inflation adjustment and exchange rate changes	(6,318)	2,932	61,520
Equity interests in subsidiaries, associates and joint ventures	(2,827,718)	(2,250,835)	(1,349,766)
	(8,022)	(68,204)	(37,443)
DECREASE (INCREASE) IN OPERATING ASSETS AND LIABILITIES
Dividends and interest on capital received	1,295,427	596,100	1,172,336
Taxes recoverable	(5,388)	109,719	65,182
Escrow deposits	260	(25)	68
Other operating assets and liabilities	6,689	7,554	(16,792)
Trade payables	1,845	1,210	(2,116)
Tax, labor and civil suits paid	(542)	(259)	(466)
Other taxes, fees and contributions	19,815	4,541	263
CASH FLOWS PROVIDED BY OPERATIONS	1,310,084	650,636	1,181,032
Interest paid on debts and debentures	-	(4,235)	(71,844)
Income tax and social contribution paid	(21,388)	(80,234)	(47,438)
NET CASH FROM OPERATING ACTIVITIES	1,288,696	566,167	1,061,750

INVESTING ACTIVITIES
Capital reduce (increase) in investees	(4,107,555)	-	(9,400)
Purchases of property, plant and equipment	(1,763)	(286)	(185)
Purchases of intangible assets	(15)	(42)	(51)
Advance for future capital increases	(14,160)	(82,415)	(383,340)
Securities, pledges and restricted deposits	-	(250)	-
Intercompany loan - granted	(424,371)	(80,512)	(72,199)
Intercompany loan - received	78,391	135,222	-
NET CASH USED IN INVESTING ACTIVITIES	(4,469,473)	(28,283)	(465,175)

FINANCING ACTIVITIES
Capital increase by noncontrolling shareholders	3,622,305	-	-
Repayment of principal of borrowings and debentures	-	(186,000)	(434,000)
Dividends and interest on capital paid	(486,984)	(279,101)	(220,966)
NET CASH GENERATED BY (USED IN) FINANCING ACTIVITIES	3,135,321	(465,101)	(654,966)
NET INCREASE IN CASH AND CASH EQUIVALENTS	(45,456)	72,783	(58,390)
CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR	79,364	6,581	64,973
CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR	33,909	79,364	6,581

Following is the information relating to CPFL Energia's unconsolidated condensed financial statements presented above:

a. Cash and cash equivalents:

	December 31, 2019	December 31, 2018
Bank balances	2,195	2,824
Investment funds	31,714	76,540
Total	33,909	79,364

Amounts invested in an Investment funds, involving investments subject to floating rates tied to the CDI in federal government bonds, CDBs, secured debentures of major financial institutions, with daily liquidity, low credit risk and interest equivalent, on average, to 94.13% of CDI.

F - 86

b. Dividends and interest on equity:

	Dividend		Interest on own capital		Total
Subsidiary	December 31, 2019	December 31, 2018	December 31, 2019	December 31, 2018	December 31, 2019	December 31, 2018
CPFL Paulista	504,789	92,596	115,928	110,214	620,717	202,810
CPFL Piratininga	32,172	6,226	35,254	31,708	67,426	37,934
CPFL Santa Cruz	-	-	39,728	19,160	39,728	19,160
CPFL Leste Paulista	-	-	-	-	-	-
CPFL Sul Paulista	-	-	-	-	-	-
CPFL Jaguari	3,473	-	-	-	3,473	-
CPFL Mococa	-	-	-	-	-	-
RGE Sul (RGE)	-	26,795	-	94,312	-	121,107
CPFL Geração	-	71,099	53,937	102,436	53,937	173,535
CPFL Centrais Geradoras	815	815	-	-	815	815
CPFL Jaguari Geração	10,194	3,398	-	-	10,194	3,398
CPFL Brasil	-	111,083	1,200	2,451	1,200	113,534
CPFL Planalto	-	-	-	-	-	-
CPFL Serviços	3,193	-	-	-	3,193	-
CPFL Atende	-	-	343	876	343	876
Nect Serviços	-	-	-	-	-	-
CPFL Total	-	-	-	-	-	-
CPFL Telecom	-	1,111	-	-	-	1,111
CPFL Eficiência	2,630	12,195	2,550	15,104	5,179	27,299
AUTHI	10,000	151	-	-	10,000	151
	567,266	325,469	248,940	376,261	816,205	701,731

c. Deferred tax assets

	December 31, 2019	December 31, 2018
Social contribution credit (debit)
Tax losses carryforwards	22,174	29,750
Temporarily nondeductible differences	553	(355)
Subtotal	22,727	29,395

Income tax credit (debit)
Tax losses carryforwards	61,209	84,113
Temporarily nondeductible differences	1,537	(986)
Subtotal	62,747	83,127

Total	85,474	112,522

	2019		2018
	Social contribution	Income tax	Social contribution	Income tax
Income before taxes	2,825,333	2,825,333	2,179,615	2,179,615
Adjustments to reflect effective rate:
Equity in subsidiaries	(2,827,718)	(2,827,718)	(2,250,835)	(2,250,835)
Amortization of intangible asset acquired	(13,528)	-	(13,528)	-
Interest on capital income	345,484	345,484	424,892	424,892
Other permanent additions (exclusions), net	12,959	24,239	14,840	22,449
Tax base	342,530	367,338	354,984	376,121
Statutory rate	9%	25%	9%	25%
Tax credit/(debit)	(30,828)	(91,834)	(31,949)	(94,030)
Recorded (unrecognizad) Tax credit,net	-	-	1,134	3,270
Total	(30,828)	(91,835)	(30,814)	(90,760)

Current	(17,677)	(53,445)	(22,401)	(65,916)
Deferred	(13,151)	(38,390)	(8,413)	(24,844)

F - 87

d. Investment:

The financial information of subsidiaries and joint ventures are accounted for using the equity method of accounting.

	December 31, 2019				December 31, 2019	December 31, 2018	2019	2018	2017
Investment	Total assets	Issued capital	Equity	Profit or loss for the period	Share of equity of investees		Share of profit (loss) of investees
CPFL Paulista	10,917,071	1,308,373	1,522,421	837,604	1,522,421	1,910,866	837,604	649,516	280,354
CPFL Piratininga	4,073,042	249,321	564,024	281,634	564,024	516,235	281,634	182,654	152,080
CPFL Santa Cruz	1,463,945	170,413	465,625	101,228	465,625	392,040	101,228	81,191	23,447
CPFL Leste Paulista	-	-	-	-	-	-	-	-	9,589
CPFL Sul Paulista	-	-	-	-	-	-	-	-	10,545
Companhia Jaguari de Energia (CPFL Santa Cruz)	-	-	-	-	-	-	-	-	11,720
CPFL Mococa	-	-	-	-	-	-	-	-	6,999
RGE	-	-	-	-	-	-	-	232,731	117,700
RGE Sul (RGE)	9,997,093	2,809,820	4,000,469	614,109	3,489,745	3,286,587	559,783	255,854	57,305
CPFL Geração	5,401,315	1,043,922	3,068,752	862,726	3,068,752	2,625,465	862,726	766,451	594,026
CPFL Renováveis (*)	8,662,437	3,698,060	4,544,433	96,628	2,125,023	-	52,388		-
CPFL Jaguari Geração	68,518	40,108	58,310	9,849	58,310	58,656	9,849	13,592	15,709
CPFL Brasil	1,394,345	3,000	86,651	109,090	86,651	72,680	109,090	91,502	94,455
CPFL Planalto	6,706	630	6,466	4,022	6,466	2,444	4,022	3,567	3,550
CPFL Serviços	238,200	120,929	131,181	13,445	131,181	120,929	13,445	(24,076)	(12,863)
CPFL Atende	31,513	13,991	24,296	11,266	24,296	19,363	11,266	9,527	7,128
Nect	-	-	-	-	-	-	-	-	17,392
CPFL Infra (**)	20,598	38	14,025	17,643	14,025	16,558	17,643	19,087	-
CPFL Pessoas (**)	7,260	811	4,517	2,047	4,517	-	2,047	-	-
CPFL Finanças (**)	9,123	385	5,566	3,982	5,566	-	3,982	-	-
CPFL Supre (**)	5,432	826	3,267	1,232	3,267	-	1,232	-	-
CPFL Total	39,793	9,005	35,348	25,665	5,348	19,953	25,665	21,690	20,865
CPFL Jaguariuna	-	-	-	-	-	-	-	-	(8,360)
CPFL Telecom	4,381	1,928	4,188	113	4,188	5,465	113	4,442	(14,021)
CPFL Centrais Geradoras	19,746	16,128	16,020	22	16,020	15,998	22	618	735
CPFL Eficiência	143,512	76,073	118,189	(3,835)	118,189	85,744	(3,835)	(11,908)	(2,582)
AUTHI	23,473	10	11,846	11,836	11,846	21,463	11,836	28,604	24,912
Subtotal - by subsidiary's equity					11,725,460	9,170,444	2,901,740	2,325,042	1,410,685
Amortization of fair value adjustment of assets					-	-	(74,023)	(74,207)	(60,918)
Total					11,725,460	9,170,444	2,827,719	2,250,835	1,349,766

Investment					11,711,300	9,088,049
Advances for future capital increases					14,160	82,395

(*) See note 1.h
(**) See note 1.g

As of December 31, 2019, the balances of advances for future capital increase ("AFAC") refer to funds granted by the Company to the subsidiary CPFL Eficiência. As of December 2018, the balance refers to the subsidiaries CPFL Eficiência (R$ 42,400) and CPFL Serviços (R$ 39,900).

Dividends and interest on own capital received

The net cash provided by operating activities is comprised mainly by dividends and interest on own capital received from the Company’s subsidiaries.

After the decisions made by the subsidiaries’ shareholders at their Annual and Extraordinary General Meetings (AGM/EGM), in 2019 the Company recognized the amount of R$ 598,534 by way of dividends and interest on capital for the year 2018. The subsidiaries also declared in 2019: (i) interim dividends and interest on capital of R$417,984, related to interim profit of 2019; (ii) R$ 293,661 of interest on capital for the year 2019; and (iii) R$ 121,841 as minimum mandatory dividend receivable related to 2019.

Of the amounts recorded as receivables, the amount of R$1,295,427 was paid to the Company by the subsidiaries in 2019.

The dividends received are comprised as follows:

F - 88

	2019	2018	2017
CPFL Brasil	197,474	2,859	166,695
CPFL Planalto	-	5,304	1,471
CPFL Paulista	178,214	100,120	2,228
CPFL Piratininga	37,935	28,445	112,638
CPFL Santa Cruz	-	-	8,427
CPFL Leste Paulista	-	-	4,449
CPFL Santa Cruz	-	45,770	-
RGE	-	23,525	24,672
RGE Sul (RGE)	409,670	-	-
CPFL Geração	423,553	298,511	779,533
CPFL Jaguari Geração	3,398	2,508	11,061
CPFL Atende	6,723	10,094	5,666
CPFL Infra	14,087	22,392	13,424
CPFL Total	10,270	22,361	17,810
CPFL Telecom	2,500
CPFL Eficiência	-	2,300	-
AUTHI	11,603	31,912	24,264
TOTAL	1,295,427	596,100	1,172,336

e. Other payables:

The primary accounts payable that the parent company has registered as noncurrent liabilities are due to loans and financing guarantees for subsidiaries and profit sharing of the Executive Officers.

************

F - 89

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

CPFL Energy (CPL) 20-F2019 FY Annual report (foreign)

Content analysis

2.1 Basis of presentation

2.2 Basis of measurement

2.3 Use of estimates and judgments

25.9 Noncontrolling interests

25.9.1 Changes in noncontrolling interests

a) Valuation of financial instruments

f) Liquidity analysis