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FORWARD‑LOOKING STATEMENTS

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

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

CERTAIN TERMS AND CONVENTIONS

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

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PRESENTATION OF FINANCIAL AND OTHER INFORMATION

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

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

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

ITEM 1.                        Identity of Directors, Senior Management and Advisers

Not applicable.

ITEM 2.                        Offer Statistics and Expected Timetable

Not applicable.

ITEM 3.                        Key Information

Selected Financial and Operating Data

The tables below contain a summary of our financial data as of and for years ended December 31, 2017, 2016, 2015, 2014, and 2013.  Our financial data as of December 31, 2017 and 2016 and for each of the three years in the period ended December 31, 2017, 2016 and 2015 was derived from our audited annual consolidated financial statements, which appear elsewhere in this annual report and were prepared in accordance with IFRS, as issued by the IASB.  You should read this selected financial data in conjunction with our audited annual consolidated financial statements and the related notes included in this annual report.  Our financial data as of December 31, 2014 and 2013 and for each of the two years ended December 31, 2014 and 2013 was derived from our audited annual consolidated financial statements that are not included in this annual report.

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

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STATEMENT OF OPERATIONS DATA

 

(1) Reflects the capital increases that took place on April 29, 2015, and April 29, 2016 through the issuance of 30,739,955 and 24,900,531 shares, respectively.  In accordance with IAS 33, when there is an increase in the number of shares without an increase in issued capital, the number of shares is adjusted retrospectively for all prior periods presented. 

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

(3) Translated at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2017 of R$3.308 to US$1.00.The average of the month-end commercial selling rates during the year 2017 was R$3.202 to US$1.00.  See “—Exchange Rates” below for more information regarding the real/U.S. dollar exchange rate.

(4) Data for 2014 and 2015 have been restated to reflect a change in presentation of the line item representing Changes in expected cash flows from Concession Financial Assets, which relates to our Distribution segment.  Since January 1, 2016 this line item has been included in Other operating revenues, within Net operating revenue, together with the other income related to the core activity of the asset.  This item was previously presented as part of Net financial expense.  We believe the new presentation more accurately reflects the business model of electricity distribution and provides a better representation of our operational and financial performance.  The reclassification does not affect total assets, equity, net income or cash flows.    The selected historical financial data for 2013 has not been restated to reflect the reclassification, and therefore is not fully comparable with the data for 2017, 2016, 2015 and 2014.

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BALANCE SHEET DATA

 

 

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

(2) Translated at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2017 of R$3.308 to US$1.00.

(3) Data for 2014 have been restated due the completion of the accounting for the purchase price allocation related to acquisition of Dobrevê Energia S.A.  - (“DESA”).

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OPERATING DATA

 

 

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

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

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

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

 

Convenience Translations into U.S. Dollars

Solely for the investor’s convenience, we have translated certain amounts included in this annual report from reais into U.S. dollars at the commercial selling rate at closing for the purchase of U.S. dollars, as reported by the Brazilian Central Bank, as of December 31, 2017 of R$3.308 to US$1.00.  The translated amounts have been rounded.  These translations should not be considered as a representation that any such amounts have been, could have been or could be converted into U.S. dollars at that or at any other exchange rate, as of those dates or any other date.  In addition, the translations should not be construed as a representation that the amounts translated into U.S. dollars are in accordance with generally accepted accounting principles.  See “—Exchange Rates” below for more information regarding the real/U.S. dollar exchange rate.

Exchange Rates

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

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

 

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

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

 

Risk Factors

Risks Relating to Our Operations and the Brazilian Power Industry

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

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

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

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

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

The Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as the Lei do Novo Modelo do Setor Elétrico, or New Industry Model Law.  Challenges to the constitutionality of the New Industry Model Law are still pending before the Brazilian Federal Supreme Court (Supremo Tribunal Federal), although preliminary injunctions have been dismissed.  It is not possible to estimate when these proceedings will be finally decided. If all or part of the New Industry Model Law were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework.  The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including our business and results of operations.

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

We carry out our generation, transmission and distribution activities pursuant to concession agreements entered into with the Brazilian government.  Our concessions range in duration from 20 to 35 years.  The Brazilian Federal constitution requires all concessions relating to public services to be awarded through public tender.  Under laws and regulations specific to the electric energy sector, the Brazilian government may renew existing concessions for an additional period of up to 20 or 30 years, depending on the nature of the concession, without public tender, provided that the concessionaire has met minimum performance, financial and other relevant standards, and provided that the proposal is otherwise acceptable to the Brazilian government.  The Brazilian government has considerable discretion under Law No.  8,987/95, or the Concession Law, Law No.  9,074/95, Decree No.  7,805/12, Law No.12,783/13, Decree No.  8,461/15, 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 tariffs that we charge for sales of electricity to Captive Consumers and the tariffs for using the distribution system that we charge to Free and Special Consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us.

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

Our concession agreements and Brazilian law establish a mechanism that allows for three types of tariff adjustments:  (i) annual adjustment (reajuste tarifário anual), or RTA, (ii) periodic revision (revisão tarifária periódica), or RTP, and (iii) extraordinary revision (revisão tarifária extraordinária), or RTE.  We are entitled to apply each year for the annual adjustment, which is designed to offset some effects of inflation on tariffs and pass through to consumers certain changes in our cost structure that are beyond our control, such as the cost of the electricity we purchase and certain regulatory charges, including charges for the use of transmission and distribution facilities.  ANEEL generally carries out the RTP periodic tariff revision every four or five years (according to the terms of each concession agreement).  The objective of this periodic revision is to share gains with consumers and incentivize concessionaires to increase efficiency levels.  As such, it aims to identify variations in our costs and set a reduction factor based on our operational efficiency that will be applied against the index of our ongoing annual tariff adjustments.  Extraordinary revisions of our tariffs may occur at any time, or may be requested by us.  Extraordinary revisions may have a negative effect on our results of operations or financial position, or may serve to offset unpredictable costs (such as taxes that significantly change our cost structure).  Previously, all revisions in methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.  However, in 2015, ANEEL changed this procedure to allow for the review of the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis.  Periodic tariff reviews will be held for CPFL Paulista and RGE Sul in April 2018 and for RGE in June 2018. 

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

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

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

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·	requiring the concessionaire’s controlling shareholders to carry out further capital expenditures (not applicable to authorizations);
·	intervention by ANEEL in the management of the concessionaire; and
·	termination of the concession or authorization.

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

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

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

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

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

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

On August 2, 2012, the Brazilian Ministry of Mines and Energy (MME) enacted Ordinance.  No.  455, which prohibited ex post adjustments to energy volume as of June 1, 2014 and required participants in the Free Market (although not Distributors) to register their expected consumption volume in advance with the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica), or CCEE, except in cases where they specifically indicate that the agreement concerned is linked to the effective consumption volume.  However, the Brazilian Association of Electricity Traders (or ABRACEEL) obtained an injunction preventing implementation of the rule requiring advance registration of volume requirements under Ordinance No.  455/2012.  As a result, Ordinance No.  455/2012 has been suspended for all CCEE participants (Generators, Traders and Free Consumers), since it may not be applied selectively to a specific group.  In addition, on January 9, 2018, a federal court nullified Ordinance No. 455/2012, on the basis that the MME has no authority to issue a regulation related to the commercialization of electrical energy. However, this decision will still have to be confirmed by the court of appeal due to the requirement for review of all cases involving the Brazilian government.  If this decision is overruled, and if our projected energy volume proves incorrect so that we purchase less or more electricity than we need in the Free Market, we would no longer be able to adjust for our exposure to the energy volume purchased.  See “Item 4.  Information on the Company—The New Industry Model Law—Recent Developments in the Free Market”.

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

We are dependent on the prevailing hydrological conditions in Brazil.  In 2017, according to data from the National Electrical System Operator (Operador Nacional do Sistema Elétrico), or ONS, approximately 69.9% (73.4% in 2016) of Brazil’s electricity supply came from Hydroelectric Power Plants. According to the ONS, this figure is expected to continue to decrease reaching 68.3% through 2021.

Brazil is subject to unpredictable hydrological conditions, with non‑cyclical deviations from average rainfall.  When hydrological conditions are poor, the ONS may dispatch Thermoelectric Power Plants, including those that we operate, to top up hydroelectric generation and maintain security levels in reservoirs and the electricity supply level in cases when the Hydroelectric Power Plants in Brazil, including those we operate, are unable to generate sufficient energy to honor their Assured Energy requirement in the Energy Reallocation Mechanism (Mecanismo de Realocação de Energia), or MRE.  This process to offset the deficit of hydroelectric energy, which was created in 2000 and is referred to as the Generation Scaling Factor, or GSF, therefore exposes operators of Hydroelectric Power Plants to spot price risk.  The GSF was activated in 2014, 2015 and 2016, requiring us to purchase energy, therefore leading to adverse results in our Generation segment.  Under Federal Law 13,203 of December 8, 2015, we have effectively capped our exposure to this risk for the life of our existing PPAs in our Generation segment, and have covered the cash outlay from January 2015 to July 2020 through the GSF payment we made in 2015 regarding the electricity required to serve our consumers in the Regulated Market.  We remain exposed to this spot price risk, however, with respect to the cost of electricity required to serve our consumers in the Free Market.  For further information, see “Item 4.  Information on the Company—The Brazilian Power Industry—Generation Scaling Factor.”

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

 

In January 2015, the electricity sector began to implement a mechanism of monthly “tariff flags” under which consumer invoices may be subject to tariff additions on a monthly basis when energy supply costs reach certain levels, enabling consumers to adapt their usage to current energy costs.  Revenues collected under the tariff flag system are repaid to distribution companies on the basis of their relative energy cost for the period.  Due to the poor hydrological conditions that were observed from 2013 through 2015, red tariff flags were applied throughout 2015 since introduction of the system in January 2015.  In 2016, due to an improvement in hydrological conditions, green tariff flags were applied in most months of the year, but 2017 consisted principally of yellow and red tariff flags.  In November 2017, ANEEL held a public hearing in order to review the tariff flags methodology.  In accordance with the new methodology, red tariff flags were applied in November and December 2017. However, in February and March 2018, green tariff flags were applied under the new methodology.  Although this mechanism mitigates the cash flow mismatch in part, it may be insufficient to cover the thermoelectric energy supply costs, and Distributors still bear the risk of cash flow mismatches in the short term.  See “Item 4.  Information on the Company—The Brazilian Power Industry—Basis for Calculation of Distribution Tariffs”.

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

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

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

Decree No. 2,655 of July 2, 1998 established that the Assured Energy of generation power plants would be revised every five years.  In 2017, this principle of five-year revision was extended to biomass plants, which led to a reduction in the Assured Energy of CPFL Renováveis’ biomass plants by an average of approximately 25% in that year.  As part of these revisions, the Brazilian Ministry of Mines and Energy (MME) can revise a company’s Assured Energy, limited to a maximum change of 5% per revision or 10% over the entire period of the concession agreement.  According to Ordinance No.  515/2015 issued by the MME, the first revision of Assured Energy under this process was originally expected to be implemented for Hydroelectric Power Plants (other than SHPPs)  in January 2017.  Since the application of the methodology of this new revision to each Power Plant is not yet available, however, the MME issued Ordinance No.  714/2016, pursuant to which the current Assured Energy for each Hydroelectric Power Plant would remain in effect until December 2017.  The first revision of Assured Energy was implemented in January 2018 under MME Ordinance No. 178/2017 and led to a reduction in the Assured Energy of our Hydroelectric Power Plants by an average of approximately 2.4%. SHPPs, unlike other Hydroelectric Power Plants, have been subject to annual revisions of their Assured Energy since 2010 in accordance with MME No. 463/2009.  These annual revisions have not resulted in reductions in the Assured Energy levels of CPFL Geração’s SHPPs, but have resulted in reductions for CPFL Renováveis’ SHPPs (although in 2017, CPFL Renováveis, together with certain other renewable energy producers, obtained a court order reinstating the initial Assured Energy levels of their SHPPs pending final resolution of their appeal against the revision process). 

We cannot be certain how future revisions will affect the Assured Energy of each of our individual Power Plants, whether the renewable energy producers will succeed in their appeal against the revision process, or whether the overall effect of revisions will increase or decrease our Assured Energy.  When the Assured Energy of a Power Plant is decreased, our ability to supply electricity under that plant’s power purchase agreements is adversely affected, which can lead to a decrease in our revenues and increase our costs if our generation subsidiaries are required to purchase power elsewhere.  We expect revisions of Assured Energy under Decree 2,655/98 to continue to take place every five years for our Power Plants other than SHPPs.  See “Item 4—Principal Regulatory Authorities—Ministry of Mines and Energy - MME”.

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

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

·         the inability to obtain required governmental permits and approvals;

·         the unavailability of equipment;

·         supply interruptions;

·         work stoppages;

·         labor unrest, including strikes;

·         social unrest;

·         weather and hydrological interferences;

·         unforeseen engineering, regulatory and/or environmental problems;

·         increases in electricity losses, including technical and commercial losses;

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·         construction and operational delays, or unanticipated cost overruns;

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

·         unavailability of adequate funding.

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

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

Our activities are subject to comprehensive federal, state and municipal legislation, the need to obtain and maintain licenses, as well as regulation and supervision by Brazilian governmental agencies that are responsible for the implementation of environmental and health laws and policies.  These agencies could take enforcement action against us for failure to comply with their regulations, or to obtain or maintain licenses.  These actions could include, among other things, the imposition of administrative and criminal sanctions, including fines and revocation of licenses.  The sanctions depend on the seriousness of the infraction or on the extent of damage caused, and any mitigating or aggravating circumstances applicable to the violator.  It is possible that enhanced environmental and health regulations will force us to allocate capital expenditures to compliance, and consequently, increase our level of investment or divert funds from existing planned investments, either of which could have a material adverse effect on our financial condition and results of operations.

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

                We plan to invest approximately R$455 million in our Generation activities (R$393 million in renewable sources and R$62 million in conventional sources), R$9,802 million in our Distribution activities and R$176 million in our commercialization and services activities during the period from 2018 through 2022. Our ability to carry out this capital expenditure program depends on a variety of factors, including our ability to charge adequate tariffs for our services, our access to domestic and international capital markets and a variety of operating, regulatory and other contingencies.  We cannot be certain that we will have the financial resources to complete our proposed capital expenditure program, and failure to do so could have a material adverse effect on the operation and development of our business.

 

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

We plan to make capital expenditures aggregating approximately R$2,139 million in 2018 and approximately R$2,108 million in 2019.  Of total budgeted capital expenditures over this period, R$3,787 million are expected to be invested in our Distribution segment, R$323 million in our Renewable Generation segment and R$35 million in our Conventional Generation segment.  In addition, over this period, we plan to invest R$102 million in our commercialization and services activities. We have already contractually committed to part of these expenditures, particularly in generation projects.  See “—Liquidity and Capital Resources—Funding Requirements and Contractual Commitments”.  Planned capital expenditures for development of our generation capacity, and the related financing arrangements, are discussed in more detail under “Item 4.  Information on the Company—Generation of Electricity”.

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

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

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

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

Through our subsidiary CPFL Renováveis we have made substantial capital investments (amounting to R$2,093 million for the last three fiscal years) in generation businesses other than hydroelectric power, principally wind and biomass generation.  These renewable generation businesses are dependent on certain factors that are not within our control and may significantly affect these businesses.

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

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

Our controlling shareholder’s interests could conflict with yours. 

On January 23, 2017, State Grid Brazil Power Participações S.A., or State Grid, consummated the acquisition of common shares representing approximately 54.6% of our voting capital, pursuant to which it has the power to control us. State Grid Brazil Power Participações S.A. is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.  In November 2017, State Grid launched a mandatory tender offer for our shares.  Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to approximately 94.75% of our total share capital.  State Grid has announced that it intends to (i) cancel our registration as a Class A publicly-held company with the CVM; (ii) delist our company from the Novo Mercado section of the B3; (iii) delist our ADSs from the New York Stock Exchange, or the NYSE, and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the U.S. Securities and Exchange Commission, or the SEC.

Our controlling shareholder may take actions that could be contrary to your interests, and our controlling shareholder will be able to prevent other shareholders, including you, from blocking these actions.  In particular, our controlling shareholder controls the outcome of decisions at shareholders’ meetings, and it can elect a majority of the members of our Board of Directors. 

Our controlling shareholder can direct our actions in areas such as business strategy, financing, distributions, acquisitions and dispositions of assets or businesses.  Its decisions on these matters may be contrary to the expectations or preferences of our non-controlling shareholders, including holders of our ADSs.  For further information regarding State Grid’s acquisition and its announced intentions regarding shareholdings in our company, see “Item 4.  Information on the Company— Overview”.

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

As of December 31, 2017, approximately 75.9% of our total indebtedness was denominated in reais and indexed to Brazilian money‑market rates or inflation rates, or bore interest at floating rates.  The remaining 24.1% of our total indebtedness as of December 31, 2017 was denominated in foreign currency, substantially U.S. dollars, compared to approximately 25.0% as of December 31, 2016, although this foreign currency denominated debt is substantially subject to currency swaps that convert these obligations into reais.  In addition, the costs of electricity purchased from the Itaipu Power Plant, or Itaipu, a Hydroelectric Power Plant that is one of our major suppliers, are indexed to the U.S. dollar exchange rate.  Our tariffs are adjusted annually in order to contemplate the losses or gains from these purchases from Itaipu.  Accordingly, when the Brazilian real appreciates against the U.S. dollar, our financing expenses decrease. 

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

As of December 31, 2017, we had total debt of R$20,168.6 million.  Our indebtedness increases the possibility that we may be unable to generate cash sufficient to pay when due the principal, interest or other amounts due in respect of our indebtedness.  In addition, we may incur additional debt from time to time to finance acquisitions, investments, joint ventures or for other purposes, subject to the restrictions applicable under our existing indebtedness, such as when we acquired RGE Sul in October 2016.  If we incur additional debt, the risks associated with our leverage would increase. 

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

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

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

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

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

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

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

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

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

Risks Relating to Brazil

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

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

·         interest rates;

·         monetary policy;

·         currency fluctuations;

·         inflation;

·         liquidity of domestic capital and lending markets;

·         tax policies;

·         changes in labor laws;

·         regulatory environment of our sector;

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

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

Uncertainty over whether the Brazilian government will change policies or regulations affecting these or other factors may contribute to political and economic uncertainty in Brazil and to heightened volatility in Brazilian securities markets and securities issued abroad by Brazilian issuers.  Standard & Poor’s downgraded Brazil below investment grade on September 9, 2015 and further downgraded Brazil from BB to BB- on January 11, 2018, with stable outlook; Fitch Ratings lowered its rating for Brazil from BBB- to BB+ on December 16, 2015 and later to BB with negative outlook on May 5, 2016; and Moody’s Investors Service downgraded Brazil to Ba2 with negative outlook on February 24, 2016 and this position was confirmed on May 26, 2017.  These downgrades reflected poor economic conditions, continued adverse fiscal developments and increased political uncertainty in Brazil.

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

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

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

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

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

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

 

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

The Brazilian currency has experienced frequent and substantial variations in relation to the U.S. dollar and other foreign currencies over the last decade.  The exchange rate of the real against the U.S. dollar was R$3.905 on December 31, 2015; R$3.259 on December 31, 2016; and R$3.308 on December 31, 2017.  On April 18, 2018, the exchange rate was R$3.384 per US$1.00.  The real may continue to fluctuate significantly against the U.S. dollar in the future.

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

Depreciation of the real  also reduces the U.S. dollar value of distributions and dividends on the ADSs and the U.S. dollar equivalent of the market price of our common shares and, as a result, our ADSs.

Inflation and interest rate policies may impact the Brazilian economy and could harm our business.

Brazil has in the past experienced extremely high rates of inflation and has therefore followed monetary policies that have resulted in one of the highest real interest rates in the world.  Between 2008 and March 2018, the base interest rate in Brazil, or SELIC, varied between 6.5% p.a.  and 14.0% p.a., reaching its lowest level (6.5%) in March 2018.  On April 18, 2018, the SELIC rate was 6.4% p.a.  Inflation has had and may in the future have significant effects on the Brazilian economy and our business.  Relatively lenient interest rate policies by the government and Brazilian Central Bank may trigger increases in inflation, and, consequently, volatility in growth and the need for sudden and significant interest rate increases, which could negatively affect our business.  In addition, if Brazil again experiences high inflation, we may not be able to adjust the rates we charge our consumers to offset the effects of inflation on our cost structure.  Conversely, tight monetary policies with high interest rates may restrict Brazil’s growth and the availability of credit.

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

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

Risks Relating to the ADSs and Our Common Shares

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

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

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

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

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

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

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

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

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

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

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

Investing in securities that trade in emerging markets, such as Brazil, often involves greater risk than investing in securities of issuers in the United States, and such investments are generally considered to be more speculative in nature.  The Brazilian securities market is substantially smaller, less liquid, more concentrated and can be more volatile than major securities markets in the United States.  Accordingly, although you are entitled to withdraw the common shares underlying the ADSs from the depositary at any time, your ability to sell the common shares underlying the ADSs at a price and time at which you wish to do so may be substantially limited.  There is also significantly greater concentration in the Brazilian securities market than in major securities markets in the United States.  The ten largest companies in terms of market capitalization represented 52.5% of the aggregate market capitalization of the B3 S.A. – Brasil, Bolsa e Balcão, or the B3 (previously known as BM&FBOVESPA), as of December 31, 2017.  The top ten stocks in terms of trading volume accounted for 32.1%, 42.8% and 39.3% of all shares traded in 2017, 2016, and 2015, respectively.

ITEM 4.                        Information on the company

Overview

We are a corporation (sociedade por ações) incorporated and existing under the laws of Brazil with the legal name CPFL Energia S.A.  Our principal executive offices are located at Rodovia Engenheiro Miguel Noel Nascentes Burnier, km 2,5, Parque São Quirino, CEP 13088-900, Campinas, state of São Paulo, Brazil and our telephone number is +55 19  3756‑8704.  Our Investor Relations Department is located at the same address and its telephone number is +55 19 3756‑6083. 

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

We are one of the largest electricity distributors in Brazil, based on the 45,386 GWh of electricity we distributed to approximately 9.4 million consumers in 2017.  In electricity generation, our Installed Capacity at December 31, 2017 was 3,284 MW.  Through our interest in CPFL Renováveis, we are also involved in the construction of one SHPP, as a result of which we expect to increase our Installed Capacity to 3,299 MW over the next three years as this is completed.

We also engage in power commercialization, buying and selling electricity to power producers, Free Consumers and power trading companies.  We also provide agency services to Free Consumers before the CCEE and other agents as well as electricity‑related services to our affiliates and unaffiliated parties.  In 2017, the total amount of electricity sold by our commercialization subsidiaries was 64.6 GWh and 20,066 GWh to affiliated and unaffiliated parties, respectively.

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On September 2, 2016, our former shareholder Camargo Correa entered into an agreement to sell its 23.6% stake in our company to State Grid.  Following the announcement, other members of our controlling shareholders block also decided to sell their stakes to State Grid.  As a result, State Grid acquired approximately 54.6% of our voting capital.  State Grid Brazil Power Participações S.A. is an indirect subsidiary of State Grid Corporation of China, a state-owned enterprise of the People’s Republic of China.  The acquisition was approved by the Administrative Council for Economic Defense (Conselho Administrativo de Defesa Econômica – CADE), the Brazilian antitrust regulator, in September 2016 and by ANEEL in December 2016.  The acquisition was completed and control of our company was transferred to State Grid on January 23, 2017.  In November 2017, State Grid launched a mandatory tender offer for our shares.  Following the closing of this tender offer on December 5, 2017, State Grid jointly with ESC Energia S.A. held 964,521,902 of our common shares, equivalent to approximately 94.75% of our total share capital.  State Grid has announced that it intends to (i) cancel our registration as a Class A publicly-held company with the CVM; (ii) delist our company from the Novo Mercado section of the B3; (iii) delist our ADSs from the NYSE, and terminate the deposit agreement for our ADSs, and (iv) terminate our registration with the SEC.

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

·	In January 2015, we established CPFL Morro Agudo S.A., a subsidiary of CPFL Geração, which will operate electric energy transmission concessions and carry out construction, implementation, operation and maintenance of transmission facilities on the Basic Network in the Interconnected Power System.
·	In April 2015, Morro dos Ventos II Wind farm commenced operations.  Morro dos Ventos II, located in João Câmara, in the state of Rio Grande do Norte, has Installed Capacity of 29 MW and physical guarantee of 15.3 MW.  From April 2015 to January 2016, when the 2011 A-5 auction energy sale contract came into effect, the energy generated by Morro dos Ventos II was injected into the system and sold in the spot market.
·	In April 2015, at the 21st A-5/2015 Energy Auction, CPFL Renováveis traded an average of 14.8 MW of contracted energy to be generated by the Boa Vista II SHPPs.  The contract will have a duration of 30 years.
·	In an Extraordinary Shareholders’ Meeting held on September 30, 2015, our shareholders approved an internal transaction in which we transferred the Macaco Branco and Rio do Peixe plants from CPFL Centrais Geradoras Ltda. to CPFL Geração, in return for newly-issed shares of CPFL Geração in the amount of R$4 million, the book value of the plant transferred.  This transaction did not impact our audited annual consolidated financial statements for 2015.
·	On December 9, 2015, distribution concessions held by our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista (now merged into CPFL Santa Cruz) were extended to July 2045 due to application of Law No.  12,783/13 of 2013, which provided the renewal of certain type of distribution concession, subject to certain conditions, for a further term of up to 30 years.  See “Item 4—Information on the Company— Concessions and Authorizations —Concessions”.
·	In May 2016, two generation facilities at the Mata Velha SHPP commenced operations, over a year and a half ahead of schedule.  Mata Velha, located in Unaí, in the state of Minas Gerais, has Installed Capacity of 24 MW and average physical guarantee of 13.1 MW.  According to the A-5 auction of 2013, the plant’s energy trading agreement takes effect in January 2017.  Since the plant was completed ahead of schedule, a free market sale agreement was signed, valid until the A-5 2013 auction agreement takes effect.
·	In May 2016, the Campo dos Ventos and São Benedito wind complexes started to enter into operations.  As of December 31, 2016, all nine wind farms in these complexes were operational.  The complexes have 231.0 MW (our share is 119 MW) of Installed Capacity and are located in the state of Rio Grande do Norte.
·	On June 15, 2016, our subsidiary CPFL Jaguariúna Participações Ltda. agreed to acquire 100% of AES Sul Distribuidora Gaúcha de Energia S.A. (which subsequently changed its name to RGE Sul Distribuidora de Energia S.A., or RGE Sul) from AES Guaíba II Empreendimentos Ltda.  RGE Sul acts as an electric energy distributor in the State of Rio Grande do Sul and has the exclusive right for distribution of energy to the captive market of 118 cities in the State. The transaction closed on October 31, 2016, and the financial results of RGE Sul are reflected in our audited annual consolidated financial statements for November and December 2016.  The purchase price after adjustment amounted to R$1,592 million.  After accounting for R$95 million in cash and cash equivalents acquired within RGE Sul, our net cash outflow on acquisition of RGE Sul was R$1,497 million.

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

 

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

 

Notes:

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

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

Our core businesses are:

·	Distribution.  In 2017, our five fully-consolidated distribution subsidiaries delivered 45,386 GWh of electricity to approximately 9.4 million consumers primarily in the states of São Paulo and Rio Grande do Sul.
·	Conventional Generation.  At December 31, 2017, our conventional generation subsidiaries had Installed Capacity of 2,198 MW.  During 2017, we generated 6,642 GWh of electricity, and we had 9,952 GWh of Assured Energy at December 31, 2017, the amount of energy representing our long-term average electricity production, as established by ANEEL, which is the primary driver of our revenues from generation activities.  We hold equity interests in eight Hydroelectric Power Plants:  Serra da Mesa, Monte Claro, Barra Grande, Campos Novos, Luiz Eduardo Magalhães-Lajeado, Castro Alves, 14 de Julho and Foz do Chapecó.  Although the concession for the Serra da Mesa Hydroelectric Facility is held by another party, Furnas, we are entitled to 51.54% of its Assured Energy. We also own three Thermoelectric Power Plants, Termonordeste, Termoparaíba and Carioba, although the Carioba Thermoelectric Power Plant has been deactivated.  In addition, 10 of our 50 Small Hydroelectric Power Plants remain under the management of two of our conventional generation subsidiaries, CPFL Geração and CPFL Centrais Geradoras, and report their results within the Conventional Generation segment. In 2017, we began to report within this business the activities of our two transmission assets held through CPFL Geração, CPFL Piracicaba and CPFL Morro Agudo, both of which are operational.
·	Renewable Generation.  Our indirect subsidiary, CPFL Renováveis, in which we own a 51.60% interest through CPFL Geração, concentrates our activities in energy generation through renewable sources.  CPFL Renováveis operates all of our wind farms and Thermoelectric Biomass Power Plants as well as 40 of our 50 Small Hydroelectric Power Plants.  These 40 Small Hydroelectric Power Plants, of which (i) 39 Small Hydroelectric Power Plants located in the states of São Paulo, Santa Catarina, Rio Grande do Sul, Minas Gerais, Mato Grosso and Paraná, are operational and have aggregate Installed Capacity of 423 MW, and (ii) one Small Hydroelectric Power Plants (Boa Vista II SHPP) under construction, scheduled to commence operations in 2020, and expected to have Installed Capacity of approximately 29.9 MW.  CPFL Renováveis also has 45 wind farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, all of which are operational and have aggregate Installed Capacity of 1,309 MW.  CPFL Renováveis has eight operational Thermoelectric Biomass Power Plants, with aggregate Installed Capacity of 370 MW, located in the states of Minas Gerais, Paraná, São Paulo and Rio Grande do Norte.  CPFL Renováveis also operates the Tanquinho Solar Power Plant, which is located in the state of São Paulo and has Installed Capacity of 1.1 MWp.  At December 31, 2017, our total consolidated Installed Capacity through our Renewable Generation segment (calculated on the basis of our 51.60% interest in CPFL Renováveis) was 1,085 MW and we expect that our Renewable Generation segment will reach an Installed Capacity of 1,100 MW in 2020.  These capacity amounts do not include eventual decreases in our installed capacity ballast (limit of energy produced in our own power plants that we are allowed to sell).  Those decreases are calculated by the Ministry of Mines and Energy, for power plants participating in MRE.  For further details about MRE, see “—Regulatory Charges—Energy Reallocation Mechanism”.

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·	Commercialization.  Our commercialization subsidiaries handle our commercialization operations and provide agency services to Free Consumers before the CCEE and other agents, including guidance on their operational requirements.  CPFL Brasil, our largest commercialization subsidiary, procures and sells electricity to Free Consumers, other commercialization and generation companies and distribution facilities.  In 2017, we sold 20,131GWh of electricity, of which 20,066GWh was sold to unaffiliated third parties.
·	Services.  Commencing January 1, 2012, we report the results of our services activities as a separate operating segment.  Our activities in this sector include providing electricity-related services, such as project design and construction, to our affiliates and unaffiliated parties.

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

Our Strategy

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

Complete the development of our existing renewable generation projects, expand our generation portfolio by developing new conventional and renewable energy generation projects and maintain our position as market leader in renewable energy sources.  At December 31, 2017, our total consolidated Installed Capacity (calculated on the basis of our 51.60% interest in CPFL Renováveis) was 3,284 MW, of which 2,198MW was through conventional sources and 1,085 MW through renewable sources.  Through CPFL Renováveis, in August 2011 we became the largest renewable energy generation group in Brazil in terms of Installed Capacity and capacity under construction, according to ANEEL.  Today, we continue to be the largest energy renewable generation group in terms of Installed Capacity in operation in Brazil and in South America, according to ANEEL and Bloomberg New Energy Outlook.

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

Many of our generation facilities hold long‑term PPAs approved by ANEEL, which we believe will ensure us an attractive rate of return on our investment.  We also have a consolidated portfolio of 209 MW (calculated on the basis of our 51.60% interest in CPFL Renováveis’ total portfolio of 406 MW) of renewable generation projects to be developed by CPFL Renováveis in the coming years.  When electricity consumption in Brazil returns to growth, we believe that there will continue to be new opportunities for us to explore investments in additional conventional and renewable generation projects. 

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Focus on further improving our operating efficiency.  The distribution of electricity in our distribution concession areas is our largest business segment, representing approximately 48.6% of our consolidated net income in 2017.  We continue to focus on improving the quality of our service and maintaining efficient operating costs by exploiting synergies and technologies.  We also make an effort to standardize and update our operations regularly, introducing automated systems where possible.  We also understand the need to invest in digital assets, such as Smart Grid technology and in 2017 we deployed 1,355 automatic reclosers. These automatic reclosers are supported by our robust proprietary communication infrastructure, including digital radio communication systems, radio frequency mesh and a fiber optic network.

Expand and strengthen our commercialization.  Free Consumers make up a significant segment of the electricity market in Brazil, representing approximately 30% of the market.  Through our subsidiary CPFL Brasil, our commercialization subsidiary, we are focusing on signing bilateral contracts with former customers of our distribution companies that became Free Consumers, in addition to attracting additional Free Consumers from concession areas other than those covered by our distribution companies.  In order to achieve this objective, we foster positive relationships with customers by providing dedicated key account managers, CCEE operational support and PPAs customized to each consumer profile.

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

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

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

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

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Our Service Territory

    

Distribution

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

Distribution Companies

We have five distribution subsidiaries:

·	CPFL Paulista.  Companhia Paulista de Força e Luz, or CPFL Paulista, supplies electricity to a concession area covering 90,440 square kilometers in the state of São Paulo with a population of approximately 10.2 million people.  Its concession area covers 234 municipalities, including the cities of Campinas, Bauru, Ribeirão Preto, São José do Rio Preto, Araraquara and Piracicaba.  CPFL Paulista had approximately 4.4 million consumers at December 31, 2017.  In 2017, CPFL Paulista distributed 20,485 GWh of electricity, accounting for approximately 24.1% of the total electricity distributed in the state of São Paulo and 6.4% of the total electricity distributed in Brazil during the year.
·	CPFL Piratininga.  Companhia Piratininga de Força e Luz, or CPFL Piratininga, supplies electricity to a concession area covering 6,785 square kilometers in the southern part of the state of São Paulo with a population of approximately 4.2 million people.  Its concession area covers 27 municipalities, including the cities of Santos, Sorocaba and Jundiaí.  CPFL Piratininga had approximately 1.7 million consumers at December 31, 2017.  In 2017, CPFL Piratininga distributed 7,921GWh of electricity, accounting for approximately 9% of the total electricity distributed in the state of São Paulo and 2.5% of the total electricity distributed in Brazil during the year.

 

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·	RGE.  Rio Grande Energia S.A., or RGE, supplies electricity to a concession area covering 86,152 square kilometers in the state of Rio Grande do Sul with a population of approximately 3.9million people.  Its concession area covers 255 municipalities, including the cities of Caxias do Sul, Gravataí, Passo Fundo and Bento Gonçalves.  RGE had approximately 1.5 million consumers at December 31, 2017.  In 2017, RGE supplied 7,949 GWh of electricity, accounting for approximately 33.2% of the total electricity distributed in the state of Rio Grande do Sul and 2.5% of the total electricity distributed in Brazil during the year.
·	RGE Sul.  RGE Sul Distribuidora de Energia S.A., or RGE Sul, supplies electricity to a concession area covering 99,512 square kilometers in the state of Rio Grande do Sul with a population of approximately 3.4 million people.  Its concession area covers 118 municipalities, including the cities of Canoas, São Leopoldo, Novo Hamburgo, Santa Maria and Uruguaiana.  RGE Sul had approximately 1.3 million consumers at December 31, 2017.  In 2017, RGE Sul supplied 6,771 GWh of electricity.
·	CPFL Santa Cruz.  CPFL Santa Cruz supplies electricity to a concession area covering 20,684 square kilometers, which includes 39 municipalities in the northwest part of the state of São Paulo, three municipalities in the state of Paraná and three municipalities in the state of Minas Gerais. In 2017, CPFL Santa Cruz distributed 2,260 GWh of electricity to approximately 447,000 consumers, accounting for approximately 2% of the total electricity distributed in the state of São Paulo and 0.7% of the total electricity distributed in Brazil during the year.
	CPFL Santa Cruz is the surviving entity of the merger of our five previous distribution companies CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari.
	On December 9, 2015, the concessions held by the Merged Companies were extended to July 2045.  For further information on the extension of these concessions, see “—Our Concessions and Authorizations—Concessions”.

  

Distribution Network

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

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

At December 31, 2017, our distribution networks consisted of 318,018 kilometers of distribution lines, including 457,741 distribution transformers, and 12,504 km of High Voltage distribution lines between 34.5 kV and 138 kV.  At that date, we had 547 transformer substations for transforming High Voltage into Medium Voltages for subsequent distribution, with total transforming capacity of 18,468 mega‑volt amperes.  Of the industrial and commercial consumers in our concession area, 387 had 69 kV, 88 kV or 138 kV high‑voltage electricity supplied through direct connections to our High Voltage distribution lines.

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System Performance

Electricity Losses

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

We are also actively engaged in efforts to reduce commercial losses from illegal connections, fraud or billing errors.  To achieve this, in each of our five subsidiaries, we have deployed trained technical teams to conduct inspections, enhanced monitoring for irregular consumption, increased replacements for obsolete measuring equipment and developed a computer program to discover and analyze irregular invoicing.  We conducted approximately 441,000 inspections during 2017, which we believe led to a recognition of previously unbilled receivables estimated at approximately R$60.3 million.

Power Outages

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

 

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

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

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

 

 

 

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

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

(3) Acquired by us on October 31, 2016.  RGE Sul was not a subsidiary of our company for the first 10 months of 2016.  
(4) In our annual report for 2016, we published SAIFI of 3.80 and SAIDI of 6.97 for CPFL Piratininga, which statistics excluded the effect of a failure in transmission provided by CTEEP due to a storm.  A decision by ANEEL required us to include the effect of this outage in the statistics for CPFL Piratininga.

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

 

We seek to improve the quality and reliability of our power supply, as measured by the frequency and duration of our power outages.  According to data from ABRADEE for 2016, the most recent data available, our frequency and duration of interruptions per consumer in the past few years compare favorably to the averages for other Brazilian distribution companies. In addition, our SAIDI and SAIFI numbers have improved significantly from 2016 to 2017, evidencing the effectiveness of our maintenance and investments in these distribution companies.

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

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ANEEL establishes performance indicators per consumer to be complied with by power companies. If these indicators are not reached, we are obliged to reimburse our consumers, and our revenues are negatively affected. In 2017, according to data from ANEEL, the amount we reimbursed our consumers remained lower than the average amount reimbursed by power companies of similar size.

Our distribution subsidiaries have construction and maintenance technology that allows for repairs of the electricity network without interruption in electricity service, thereby allowing us to have low rates of scheduled interruption, which amounts to up to approximately 12.6% of total interruptions.  Unscheduled interruptions due to accidents or natural causes, including lightning storms, fire and wind represented the remainder of our total interruptions.  In 2017, we invested approximately R$1,882.5 million in our Distribution segment, primarily in: (i) expansion, maintenance, improvement, automation, modernization and reinforcement of the electrical system in order to meet market growth; (ii) operational infrastructure; (iii) customer service; and (iv) research and development programs, among other things.

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

Purchases of Electricity

Most of the electricity we sell is purchased from unrelated parties, rather than generated by our facilities.  In 2017, 9.0% of the total electricity our distribution subsidiaries acquired was purchased from our generation subsidiaries (including our joint ventures).

In 2017, we purchased 11,779 GWh of electricity from the Itaipu Power Plant, amounting to 15.1% of the total electricity we purchased.  Itaipu is located on the border of Brazil and Paraguay and is subject to a bilateral treaty between the two countries pursuant to which Brazil has committed to purchasing specified amounts of electricity.  This treaty will expire in 2023.  Electric utilities operating under concessions in the midwest, south and southeast regions of Brazil are required by law to purchase a portion of the electricity that Brazil is obligated to purchase from Itaipu.  The amounts that these companies must purchase are governed by take‑or‑pay contracts with tariffs established in US$/kW.  ANEEL determines annually the amount of electricity to be sold by Itaipu.  We pay for energy purchased from Itaipu in accordance with the ratio between the volume established by ANEEL and our statutorily established share, regardless of whether Itaipu generates such amount of electricity, at a price of US$28.73/kW.  Our purchases represent approximately 19.6% (including RGE Sul) of Itaipu’s total supply to Brazil, disregarding the two-month period purchases of electricity by our distribution subsidiary RGE Sul, which control was acquired on October 31, 2016.  This share was fixed by law according to the amount of electricity sold in 1991.  The rates at which companies are required to purchase Itaipu’s electricity are established pursuant to the bilateral treaty and fixed to cover Itaipu’s operating expenses, payments of principal and interest on its U.S. dollar‑denominated debts and the cost of transmitting the power to their concession areas.

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

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

We purchased 66,195 GWh of electricity in 2017 from generating companies other than Itaipu, representing 84.9% of the total electricity we purchased.  We paid an average of R$191.88 per MWh for purchases of electricity from generating companies other than Itaipu, compared with R$164.77 per MWh in 2016 and R$210.44 per MWh in 2015.  For more information on the Regulated Market and the Free Market, see “—The New Industry Model Law— The Regulated Market” and “—The New Industry Model Law— The Free Market”.

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

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

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

Transmission Tariffs.  In 2017, we paid a total of R$1,284 million in tariffs for the use of the transmission network, including Basic Network tariffs, connection tariffs and transmission of high‑voltage electricity from Itaipu at rates set by ANEEL.

Consumers and Tariffs

Consumers

We classify our consumers into five principal categories.  See note 25 to our audited annual consolidated financial statements for a breakdown of our sales by category.

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

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

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

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

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

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

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

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

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

 

 

 

 

(1) Average retail prices of RGE Sul reflect the two-month period (November and December 2016) following our acquisition of RGE Sul on October 31, 2016.
(2) On November 21, 2017, through the Resolution for Authorization No. 6,723/2017, ANEEL approved our proposal to consolidate the concessions of our five distribution companies (CPFL Santa Cruz; Companhia Leste Paulista de Energia; Companhia Sul Paulista de Energia; Companhia Luz e Força de Mococa; and CPFL Jaguari, together the Merged Companies), pursuant to Normative Resolution No. 716/2016.  Effective as of January 1, 2018, the Merged Companies were merged with and into a company named CPFL Santa Cruz (which company was previously named CPFL Jaguari). For more information, see “Item 4. Information on the Company—Overview” and note 14.4.2 of our audited annual consolidated financial statements.

 

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

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Conventional Generation

Hydroelectric Power Plants

At December 31, 2017, our subsidiary CPFL Geração owned a 51.54% interest in the Assured Energy from the Serra da Mesa Power Plant.  Through its generation subsidiaries CERAN, BAESA, ENERCAN and Chapecoense, CPFL Geração also owned interests in the Monte Claro, Barra Grande, Campos Novos, Castro Alves, 14 de Julho and Foz do Chapecó Power Plants, which have been operational since December 2004, November 2005, February 2007, March 2008, December 2008 and October 2010, respectively.  Through CPFL Jaguari Geração, we owned a 6.93% interest in the Assured Energy from the Luis Eduardo Magalhães Power Plant.

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

Serra da Mesa.  Our largest Hydroelectric Facility in operation is the Serra da Mesa facility, which we acquired in 2001 from ESC Energia S.A. (formerly VBC), one of our shareholders.  Furnas began construction of the Serra da Mesa facility in 1985.  In 1994, construction was suspended due to a lack of resources, which led to a public bidding procedure in order to resume construction.  Serra da Mesa currently consists of three Hydroelectric Facilities located on the Tocantins River in the state of Goiás.  The Serra da Mesa facility began operations in 1998 and has a total Installed Capacity of 1,275 MW.  The concession for the Serra da Mesa facility is owned by Furnas, which is also the operator, and we own part of the facility.  Under Furnas’ agreement with us, which has a 30-year term commencing in 1998, we have the right to 51.54% of the Assured Energy of the Serra da Mesa facility until 2028 even if, during the term of the concession, there is an expropriation or forfeiture of the concession or the term of the concession expires.  We sell all of such electricity to Furnas under an electricity purchase contract that was renewed in March 2014 at a price that is adjusted annually based on the IGP‑M.  This contract expires in 2028.  Our share of the Installed Capacity and Assured Energy of the Serra da Mesa facility is 657 MW and 3,030 GWh/year, respectively.  On May 30, 2014, the concession held by Furnas was formally extended to November 12, 2039. In 2016, due to the renegotiated GSF, the Serra da Mesa concession was extended to September 30, 2040, in accordance with ANEEL’s Authoritative Resolution No. 6,055/2016.

CERAN Hydroelectric Complex.  We own a 65.0% interest in CERAN, a subsidiary that was granted a 35‑year concession in March 2001 to construct, finance and operate the CERAN hydroelectric complex.  The other shareholders are CEEE (with 30.0%) and Desenvix (with 5.0%).  The CERAN hydroelectric complex consists of three Hydroelectric Power Plants:  Monte Claro, Castro Alves and 14 de Julho.  The CERAN Hydroelectric Complex is located on the Antas River approximately 120 km north of Porto Alegre, near the city of Bento Gonçalves, in the state of Rio Grande do Sul.  The entire CERAN Hydroelectric Complex has an Installed Capacity of 360 MW and estimated Assured Energy of 1,515.5 GWh per year, of which our share is 985 GWh/year.  We sell our participation in the Assured Energy of this Complex to affiliates in our group.  These facilities are operated by CERAN, under CPFL Geração’s supervision.

·	Monte Claro.  Monte Claro’s first generating unit, which became operational in 2004, has Installed Capacity of 65 MW and the second generating unit, which became operational in 2006, also has an Installed Capacity of 65 MW, giving total Installed Capacity of 130 MW and Assured Energy of 516.8 GWh per year.
·	Castro Alves.  In March 2008, the first generation unit of the Castro Alves Power Plant became operational, with total Installed Capacity of 43.4 MW.  In April 2008, the second generation unit became operational, with Installed Capacity of 43.4 MW.  In June 2008, this plant became fully operational (when the third generation unit started operations), giving total Installed Capacity of 130 MW and annual Assured Energy of 560.6 GWh per year.
·	14 de Julho.  The first generation unit of the 14 de Julho Power Plant became operational in December 2008, and the second generation unit became fully operational in March 2009.  This plant has a total Installed Capacity of 100 MW and an annual Assured Energy of 438 GWh.

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Small Hydroelectric Power Plants

At December 31, 2017, 10 of our 50 Small Hydroelectric Power Plants were under the management of two of our conventional generation subsidiaries, CPFL Geração and CPFL Centrais Geradoras.  These 10 Small Hydroelectric Power Plants reported their results within the Conventional Generation segment.  They consist of two groups of facilities:

·	Nine of these facilities were originally managed together with their associated distribution companies within our Distribution segment.  Law No.  12,783 of January 11, 2013 specified the conditions for the renewal of generation, transmission and distribution concessions obtained under articles 17, 19 or 22 of Law No.  9,074 of July 7, 1995.  Under Law No.  12,783/13, these concessions may be extended once, at the discretion of the Brazilian government, for up to 30 years, in order to ensure the continuity and efficiency of the services rendered and of low tariffs.  In addition, Law No.  12,783/13 provided that holders of concessions that were due to expire in 2015, 2016 and 2017 could apply for early renewal in 2013, subject to certain conditions.  However, Resolution No.  521/12 published by ANEEL on December 14, 2012 established that the generation concessions to be renewed under Law No.  12,783/13 must be partitioned into separate operating entities in cases where the Installed Capacity of the original concessionaire entity exceeded 1 MW.  On October 10, 2012, in anticipation of Law 12,783/13, we applied for early renewal of the concessions held by our distribution subsidiaries CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista (now all merged into CPFL Santa Cruz), which were originally granted in 1999 for a 16-year term.  Pursuant to the partition requirement under Resolution No.  521/12, we were required to separate the generation and distribution activities of three of the plants, Rio do Peixe I and II and Macaco Branco, whose generation facilities were transferred to CPFL Centrais Geradoras on August 29, 2013.  At that time, our Management decided for operational reasons to partition the generation and distribution activities of the remaining six facilities held by the five distribution subsidiaries (Santa Alice, Lavrinha, São José, Turvinho, Pinheirinho and São Sebastião), the generation facilities of which were also transferred to CPFL Centrais Geradoras.  In addition, the concession agreements for Macaco Branco and Rio do Peixe were transferred from CPFL Centrais Geradoras to CPFL Geração on September 30, 2015 (see “–Overview”).
·	During 2014, the concessions for the Salto do Pinhal and Ponte do Silva facilities were terminated under Authorizing Resolution No.  4,559/2014, which determined that concessions for inactive Micro Hydroelectric Power Plants would be extinguished without reversion of the respective assets to the government.
·	The remaining facility, Cariobinha, has been held by CPFL Geração since the signing of the concession contract.

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

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

 

The following table sets forth certain information relating to our principal conventional generation facilities in operation and the Small Hydroelectric Power Plants that reported their results within the Conventional Generation segment as of December 31, 2017: 

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	Holding company	Partic.	Capacity (MW)		Assured Energy (GWh)		Placed in service	Concession expires
			Our share	TOTAL	Our share	TOTAL
Hydroelectric plants:
Serra da Mesa	CPFL Geração	51.54%	657.1	1,275.0	3,029.5	5,878.0	1998	2039(1)
Monte Claro	CPFL Geração	65%	84.5	130.0	335.9	516.8	2004	2036
Barra Grande	CPFL Geração	25.01%	172.5	690.0	833.7	3,334.1	2005	2036
Campos Novos	CPFL Geração	48.72%	428.8	880.0	1,612.9	3,310.4	2007	2035
Castro Alves	CPFL Geração	65%	84.5	130.0	364.4	560.6	2008	2036
14 de Julho	CPFL Geração	65%	65.0	100.0	284.7	438.0	2008	2036
Luis Eduardo Magalhães	CPFL Jaguari de Geração	6.93%	62.5	902.5	319.7	4,613.0	2001	2032
Foz do Chapecó	Chapecoense	51%	436.1	855.0	1,930.0	3,784.3	2010	2036
SUBTOTAL - Hydroelectric plants			1,991.0		8,710.8
Thermoelectric plants:
Carioba	CPFL Geração	100%	-	-	-	-	1954	2027(2)
EPASA facilities:
Termonordeste	CPFL Geração	53.34%(4)	91.1	170.8	578.5	1,084.5	2010	2042
Termoparaíba	CPFL Geração	53.34%(4)	91.1	170.8	578.9	1,084.5	2011	2042
SUBTOTAL - Thermoelectric plants			182.2		1,157.4
Small Hydroelectric Plants
Cariobinha	CPFL Geração	100%	-	-	-	-	N/A	2027(2)
Lavrinha	CPFL Centrais Geradoras	100%	0.3	0.3	2.1	2.1	N/A	(3)
Macaco Branco	CPFL Geração	100%	2.4	2.4	14.5	14.5	N/A	2042
Pinheirinho	CPFL Centrais Geradoras	100%	0.7	0.7	4.2	4.2	N/A	(3)
Rio do Peixe I	CPFL Geração	100%	3.1	3.1	3.9	3.9	N/A	2042
Rio do Peixe II	CPFL Geração	100%	15.0	15.0	46.8	46.8	N/A	2042
Santa Alice	CPFL Centrais Geradoras	100%	0.6	0.6	3.6	3.6	N/A	(3)
São José	CPFL Centrais Geradoras	100%	0.8	0.8	2.1	2.1	N/A	(3)
São Sebastião	CPFL Centrais Geradoras	100%	0.7	0.7	4.6	4.6	N/A	(3)
Turvinho	CPFL Centrais Geradoras	100%	0.8	0.8	2.2	2.2	N/A	(3)
SUBTOTAL – Small Hydroelectric Plants			24.4		84.0
TOTAL – Conventional Generation			2,197.6		9,952.2

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

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

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

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

 

Renewable Generation

At December 31, 2017, through our subsidiary CPFL Geração, we owned a 51.60% interest in CPFL Renováveis, a company resulting from an association with another Brazilian renewable energy producer, Energias Renováveis S.A., or ERSA, which holds our subsidiaries engaged in the generation of electricity from renewable sources.  Through CPFL Renováveis, in August 2011, we became the largest renewable energy generation group in Brazil in terms of Installed Capacity and capacity under construction, according to ANEEL.  We have fully consolidated CPFL Renováveis in our financial statements since August 1, 2011.  CPFL Renováveis carried out its initial public offering in July 2013, resulting in a decrease in our shareholding from 63% to 58.84%.  On October 1, 2014, CPFL Renováveis acquired 100% of the shares of DESA through an issuance of shares of CPFL Renováveis, resulting in a decrease in our shareholding of CPFL Renováveis from 58.84% to 51.61%. 

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CPFL Renováveis invests in independent renewable energy production sources with low environmental and social impact, such as Small Hydroelectric Power Plants, wind farms, biomass‑fueled thermoelectric Power Plants and photovoltaic solar plants, focusing exclusively on the Brazilian market.  CPFL Renováveis has extensive experience in the development, acquisition, construction and operation of electricity-generating plants using renewable energy sources.  CPFL Renováveis operates in eight Brazilian states and its business contributes to the local and regional economic and social development.

At the date of this Annual Report, CPFL Renováveis consists of the generation entities described below.  All Installed Capacity and Assured Energy numbers stated in the discussion below refer to the full capacity of the plant in question rather than our consolidated share of such energy, which only reflects our interest in the plant. 

·	25 subsidiaries involved in the generation of electric energy through 40 Small Hydroelectric Power Plants, consisting of (i) 39 SHPPs that are operational, with aggregate Installed Capacity of 423 MW, located in the states of São Paulo, Santa Catarina, Rio Grande do Sul, Paraná, Minas Gerais and Mato Grosso, and (ii) one SHPP (Boa Vista 2), with 29.9 MW of Installed Capacity, which is under construction and scheduled to commence operations in 2020.
·	52 subsidiaries involved in the generation of electric energy from wind sources. 45 wind farms, located in the states of Ceará, Rio Grande do Norte and Rio Grande do Sul, are operational and have aggregate Installed Capacity of 1,308.5 MW.
·	Eight subsidiaries involved in the generation of electric energy from biomass, all of which are operational, with total Installed Capacity of 370 MW, located in the states of Minas Gerais, Paraná, São Paulo and Rio Grande do Norte.  On August 27, 2010, CPFL Bioenergia’s Baldin Plant, our first sugarcane bagasse-powered plant started operations, with 45 MW of total Installed Capacity.  CPFL Bio Formosa began operations on September 2, 2011, with total Installed Capacity of 40 MW.  CPFL Bio Buriti began operations on October 7, 2011 with total Installed Capacity of 50 MW.  Bio Ipê began operations on May 17, 2012 with total Installed Capacity of 25 MW.  Bio Pedra began operations on May 31, 2012 with total Installed Capacity of 70 MW.  On October 18, 2012, we completed the acquisition of the Ester Thermoelectric Power Plant, which has total Installed Capacity of 40 MW.  CPFL Coopcana and CPFL Alvorada, each with 50 MW of total Installed Capacity, began operations on August 28, 2013 and November 11, 2013, respectively.
·	One subsidiary involved in the generation of electric energy from a solar power plant, Tanquinho, which is located in the state of São Paulo and has total Installed Capacity of 1.1 MW.  Tanquinho started operations on November 27, 2012 and is expected to generate approximately 1.6 GWh/year.

 

Existing Installed Capacity

The following describes our existing and operational renewable generation plants:

Small Hydroelectric Power Plants

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

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

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

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

The following table sets forth certain information relating to our principal renewable facilities, held by CPFL Renováveis (51.60% our share) in operation as of December 31, 2017:

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 (1) Hydroelectric projects with installed capacity equal to or less than 1,000 kW that have a concession contract.  The legislation for SHPPS with installed capacity less than 5,000 kW has changed and currently only a Registration is required.  The concession contracts are valid until the concession expires. 

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

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

 

 

 

Expansion of Installed Capacity

Consumption of electricity in Brazil in 2017 increased 0.8% in 2017, reaching 465,130 GWh , as was expected by the Energetic Studies Company (Empresa de Pesquisas Energéticas), or EPE.  To address this increase in demand and to improve our margins, we continue to expand our Installed Capacity in renewable generation.  CPFL Renováveis is constructing the Boa Vista II SHPP, which is expected to have an aggregate Installed Capacity of 29.9 MW (of which our consolidated share will be 15.4 MW).  We expect that the total generating capacity from this facility will become fully operational by the end of 2020.

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

 

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Boa Vista 2 SHPP.  Boa Vista SHPP is located in the state of Minas Gerais.  Boa Vista SHPP is expected commence operations in 2020.  The SHPP construction commenced in February 2017.  It will have an aggregate Installed Capacity of 29.9 MW and aggregate Assured Energy of 136 GWh/year.  The energy was sold in the A-5/2015 Energy Auction, held in 2015.

Electricity Commercialization

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

·	procuring electricity for commercialization activities by entering into bilateral contracts with energy companies (including our generation subsidiaries and third parties) and purchasing electricity in public auctions;
·	reselling electricity to Free Consumers;
·	reselling electricity to distribution companies (including CPFL Paulista, CPFL Piratininga and RGE) and other agents in the electricity market through bilateral contracts; and
·	providing agency services to Free Consumers and Power Generators before the CCEE and other agents, such as guidance on their operational requirements.

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

The rates at which CPFL Brasil purchases and sells electricity in the Free Market are determined by bilateral negotiations with its suppliers and consumers.  The contracts with distribution companies are regulated by ANEEL.  In addition to marketing electricity to unaffiliated parties, CPFL Brasil resells electricity to CPFL Paulista, CPFL Piratininga and RGE, but profit margins from sales to related parties have been limited by ANEEL regulations.  The “self-dealing” provisions under which distributors were permitted to purchase electricity from affiliated companies were eliminated under the New Industry Model Law, with the exception of those contracts approved by ANEEL prior to March 2004, before the law was enacted.  However, we are allowed to sell electricity to distributors through the open bidding process in the Regulated Market. 

Services

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

·	Transmission networks:  CPFL Serviços plans, constructs, commissions and provides electricity to substations and transmission lines in consideration of each consumer’s needs and growth expectations and in accordance with rigorous safety criteria, aiming for an optimal use of resources.
·	Distribution Networks:  CPFL Serviços plans and constructs electric energy distribution system networks, including above and underground electricity grids, medium-voltage substations and transformers, industrial plants and lighting solutions.  It has significant experience in the market and familiarity with the various technical standards applicable in different regions of Brazil.  As a result, it is able to bring quality and technologically-advanced energy solutions.
·	Electric network maintenance:  CPFL Serviçosoffers maintenance services on medium and high-voltage networks on a one-time or periodic basis with rapid diagnosis and precise service.  It also performs renovations of substations, maintenance services for generating units and work on live-wire networks.

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·	Self-production networks and energy-efficiency programs:  The self-production networks, formerly offered by CPFL Serviços, consist of electric energy production alternatives.  They ensure supply of energy to consumers, diversify inputs and reduce costs.  It offers diesel and natural gas generators that operate mainly in peak periods, which reduce our customers’ electricity costs.  Its natural gas co-generation activities include the simultaneous and sequential production of electricity and heat using a single fuel type.  It also offers solutions in acclimatization and energy-efficiency projects as well as distributed generation of solar energy.  After October 2014, all self-production activities were transferred to CPFL Eficiência, which offers service relating to climatization, cogeneration, motive power and lighting for the creation of customized solutions in power efficiency, and promotes savings, sustainability and power security.  CPFL Eficiência also offers distributed photovoltaic generation services, through CPFL GD S.A., a source of generation that injects power into the local distribution company grid directly.  This kind of generation reduces the use of the transmission system and requires less generation of centralized power plants, benefiting the consumer and the electricity sector as a whole.
·	Equipment recovery:  CPFL Serviços has experience in refurbishing electric assets in order to restore their efficiency.  Its familiarity with refurbishing equipment also allows it to produce distribution and high-power transformers.  In addition, it self-produces and fabricates measurement panels as well as panels for protection and command networks.
·	CPFL Atende:  CPFL Atende is a contact center and customer relationship company, created to provide services both for companies within our group and for other companies.  Among these services are face-to-face service, back office services, credit recovery, toll free customer support, ombudsman services, service desks and sales.
·	CPFL Total:  CPFL Total provides the “Serviço em Conta”, which enables us to charge business customers for additional products and services through their electricity bills.  Operations related to collections and onlending company offering bill payment services were discontinued as of 2016.
·	Nect:  Nect provides administrative services such as human resources, materials purchasing and logistics, maintenance and administrative infrastructure for the companies within our group.  Nect aims to standardize processes and achieve productivity gains.
·	Authi:  Authi provides IT services, information technology maintenance, services related to system updates, program development and customization and computer and peripheral equipment maintenance services.

 

Competition

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

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

Our Concessions and Authorizations

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

·

Pursuant to Law No.  9,074/1995 (as amended by Law No.  13,360/2016), only hydroelectric generation projects with a capacity greater than 50,000 kW are now implemented through concessions granted by ANEEL following a public bidding process (which leads to the execution of a concession agreement).  Requests to renew these concessions are examined by ANEEL on a case-by-case basis, according to the 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.

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·	Hydroelectric Power Plants with capacity greater than 5,000 kW but equal to or lower than 50,000 kW now only require regulatory authorization from ANEEL, as opposed to a concession.  Authorizations are renewable at the discretion of ANEEL on a case-by-case basis.  ANEEL must provide justification for its decisions and any renewal must foster the public interest.
·	Hydroelectric Power Plants with capacity equal to or less than 5,000 kW only require registration with ANEEL rather than a concession agreement or an authorization.

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

For further information about concessions and authorizations, see “—Concessions and Authorizations—Concessions”.

Concessions

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

 

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

 

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

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

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

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According to Normative Resolution No. 716/2016, until the first tariff review of the Merged Companies in March 2021, ANEEL may institute a policy that reconciles the variations in the old tariffs for each of the Merged Companies and the new unified tariff for CPFL Santa Cruz over time. ANEEL decided to introduce the unified tariff during the March 2018 tariff adjustment. The tables below summarize our generation business concessions.  In addition to these concessions, CPFL Centrais Geradoras, as an Independent Power Producer with generating capacity of less than 5,000 kW, operates under a regulatory registration rather than a concession agreement. 

Conventional generation

 

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Renewable generation

	Concession no.	Independent Power Producers / Concessionaire	Plant	State	Term	Maximum renewal period
Small Hydroelectric Plants
	003/2011	CPFL Renováveis	Americana	São Paulo	up to November 2027	30 years
	Dispatch No.  1990	CPFL Renováveis	Andorinhas	Rio Grande do Sul	(3)	(3)
	002/2011	CPFL Renováveis	Buritis	São Paulo	up to November 2027	(3)
	002/2011	CPFL Renováveis	Capão Preto	São Paulo	up to November 2027	(3)
	002/2011	CPFL Renováveis	Chibarro	São Paulo	up to November 2027	(3)
	Resolution No.  475	CPFL Renováveis	Diamante	Mato Grosso	up to November 2027	(3)
	002/2011	CPFL Renováveis	Dourados	São Paulo	up to November 2027	30 years
	004/2011	CPFL Renováveis	Eloy Chaves	São Paulo	up to November 2027	30 years
	002/2011	CPFL Renováveis	Esmeril	São Paulo	up to November 2027	30 years
	002/2011	CPFL Renováveis	Gavião Peixoto	São Paulo	up to November 2027	(3)
	Resolution No.  1,987/2005	CPFL Renováveis	Guaporé	Rio Grande do Sul	(3)	(3)
	004/2011	CPFL Renováveis	Jaguari	São Paulo	up to November 2027	30 years
	002/2011	CPFL Renováveis	Lençóis	São Paulo	up to November 2027	(3)
	004/2011	CPFL Renováveis	Monjolinho	São Paulo	up to November 2027	(3)
	004/2011	CPFL Renováveis	Pinhal	São Paulo	up to November 2027	30 years
	Dispatch No.  1989	CPFL Renováveis	Pirapó	Rio Grande do Sul	(3)	(3)
	Dispatch No.  1988	CPFL Renováveis	Saltinho	Rio Grande do Sul	(3)	(3)
	003/2011	CPFL Renováveis	Salto Grande	São Paulo	up to November 2027	(3)
	002/2011	CPFL Renováveis	São Joaquim	São Paulo	up to November 2027	20 years
	004/2011	CPFL Renováveis	Socorro	São Paulo	up to November 2027	(3)
	003/2011	CPFL Renováveis	Santana	São Paulo	up to November 2027	(3)
	003//2011	CPFL Renováveis	Três Saltos	São Paulo	up to November 2027	(3)

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

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

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

(4) Since August 29, 2013 CPFL Centrais Geradoras has held the unbundled generation activities of the Macaco Branco and Rio do Peixe I and II SHPPs, as required by Resolution No.  521/12 for their renewal, together with the generation activities of the Santa Alice, Lavrinha, São José, Turvinho, Pinheirinho and São Sebastião Micro Hydroelectric Power Plants.  Since November 17, 2016, due to changes made by Law No.  13,360/2016, hydroelectric projects with an Installed Capacity equal to or less than 5,000 kW no longer require concession or authorization processes for operating, but only registration with ANEEL.

(5) The Macaco Branco and Rio do Peixe concessions were transfered from CPFL Centrais Geradoras to CPFL Geração in Septemer 30, 2015 (see “–Overview”).

 

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Renewable generation

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

(*)   Project in planning phase.

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

 

Independent Power Producers and Self-Generators

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

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

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

Concessionaires

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

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

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

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

Permissions

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 Industry Model Law

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

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

·	Creation of two “environments” for the trading of electricity, including:  (i) the Regulated Market, a more stable market in terms of supply of electricity; and (ii) a market specifically addressed to certain participants (i.e., Free Consumers and commercialization companies), called the Free Market, that permits a certain degree of competition.
·	Restrictions on certain activities of Distributors, so as to require them to focus on their core business of distribution, to promote more efficient and reliable services to Captive Consumers.
·	Elimination of self-dealing, in order to provide an incentive to Distributors to purchase electricity at the lowest available prices rather than buying electricity from related parties.
·	Maintenance of contracts entered into prior to the New Industry Model Law, in order to provide regulatory stability for transactions carried out before its enactment.

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

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

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

Environments for the Trading of Electric Energy

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

Electricity distribution companies fulfill their electricity supply obligations primarily through public auctions.  Distribution companies may also purchase electricity outside the public auction process from:  (i) generation companies that are connected directly to such distribution company, except for hydro generation companies with capacity higher than 30 MW, certain thermo-generation companies and affiliated generation companies; (ii) electricity generation projects participating in the initial phase of the Proinfa Program, a program designed to diversify Brazil’s energy sources; (iii) the Itaipu Power Plant; (iv) auctions administered by the distribution companies, if the market that they supply is no greater than 500 GWh/year; and (v) Hydroelectric Power Plants whose concessions have been renewed by the government under Law No.  12,783/13 (in this latter case, in “energy quotas” distributed among the distribution companies by the Brazilian government, at prices determined by MME/ANEEL).  The electricity generated by Itaipu continues to be sold by Eletrobras to the distribution concessionaires operating in the South/Southeast/Midwest Interconnected Power System, although no specific contract was entered into by these concessionaires.  The rates at which the electricity generated by Itaipu is traded are denominated in U.S. dollars and established pursuant to a treaty between Brazil and Paraguay.  As a consequence, Itaipu rates rise or fall in accordance with the variation of the U.S. dollar/real  exchange rate.  Changes in the price of electricity generated by Itaipu are, however, subject to the Parcel A Cost recovery mechanism discussed below under “—Distribution Tariffs”. 

The Regulated Market

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

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

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

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

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The Free Market

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

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

·	Conventional Free Consumers are those whose contracted energy demand is at least 3 MW.  These consumers may opt to purchase conventional energy, entirely or partially, from another authorized selling agent under the terms of current legislation.  We refer to consumers who have exercised this option as “Conventional Free Consumers”.
·	Special Free Consumers are individual or groups of consumers whose contracted energy demand is between 500 kV and 3 MW.  We refer to consumers who have exercised this option as “Special Free Consumers”.  Special Free Consumers may only purchase energy from renewable sources:  (i) Small Hydroelectric Power Plants with capacity superior to 5,000 kW and equal or inferior to 30,000 kW, (ii) hydroelectric generators with capacity superior to 5,000 kW and equal or inferior to 50,000 kW, under the independent power production regime; (iii) generators with capacity limited to 3,000 kW, and (iv) alternative energy generators (solar, wind and biomass enterprises) with system capacity not greater than 50,000 kW.  State-owned generators may sell electricity to Free Consumers; however, unlike private generators, they may only do so through an auction process.
·	We also refer to consumers who meet the relevant demand requirement but have not exercised the option to migrate to the free market as “Potential Conventional Free Consumers” or “Potential Special Free Consumers”, as the case may be, and in general as “Potential Free Consumers”.

Recent Developments in the Free Market

On August 2, 2012, the MME enacted Act No. 455, providing for new rules regarding the registration of PPAs in the Free Market.  Under Act No. 455/2012, PPAs had to be registered in advance with the CCEE on a monthly basis, but the electricity volume contracted could be adjusted on an ex post basis after the consumption had taken place.  Under Act No. 455/2012, as of June 1, 2014, PPAs needed to be registered with the CCEE in advance on a weekly basis, and the ex post volume adjustment was prohibited.  As a result, parties had to state their expected consumption volume ex ante, except when they had specifically indicated to the CCEE that the PPA in question referred to effective consumption volume.  However, the Brazilian Association of Electricity Traders (ABRACEEL) obtained an injunction against Act No.  455/2012, preventing the implementation of the ex ante contract registration rule to energy traders.  The application of this Act in the CCEE was previously suspended for all agents (Generators, Traders and Consumer), since its applicability to specific groups of agents was unclear.  In addition, on January 9, 2018, a federal court declared Act No. 455/2012 null, stating that the MME has no competence to issue regulations related to the commercialization of electric energy. However, this decision will still have to be confirmed by the court of appeal due to the requirement for review of all cases involving the Brazilian government. The act only applied to the Free Market, not Distributors.

These restrictions in the freedom of negotiation between sellers and buyers may have an impact on the cost of energy purchased in the Free Market, and may reduce the benefit to us of trading in the Free Market.

Auctions on the Regulated Market

Electricity auctions for new generation projects in process are held (i) as A‑5 auctions or (ii) three years before the initial delivery date (referred to as “A‑3” auctions).  Electricity auctions from existing power generation facilities take place (i) one year before the initial delivery date (referred to as “A‑1” auctions) or (ii) approximately four months before the delivery date (referred to as “market adjustments”).  Auction bid announcements are prepared by ANEEL in compliance with guidelines established by the MME, which include a requirement to use the lowest energy price as the criterion to determine the winner of the auction.

Each generation company that participates in an auction executes a contract for purchase and sale of electricity with each distribution company, in proportion to the distribution companies’ respective estimated demand for electricity.  The only exception to these rules relates to the market adjustment auction, where the contracts are between specific selling and distribution companies.  The CCEAR of both “A‑5” and “A‑3” auctions have a term of between 15 and 30 years, and the CCEAR of “A‑1” auctions have a term of between one and 15 years.  Contracts arising from market adjustment auctions are limited to a two‑year term.  The total amount of energy contracted in such market adjustment auctions may not exceed 1.0% of the total amount of energy contracted by each Distributor.

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TUSD

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

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

TUST

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

TE

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

Basis for Calculation of Distribution Tariffs

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

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

·         costs of electricity mandatorily purchased from Itaipu and the generation companies renewed under Law 12,783/13;

·         costs of electricity purchased pursuant to bilateral agreements that are freely negotiated between the parties;

·         costs of electricity purchased pursuant to CCEARs;

·         certain other charges for use and connection to the transmission and distribution systems;

·         the cost of regulatory charges; and

·         the costs associated with research and development and energy‑efficient consumption.

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In December 2016, the last 15 of 110 wind turbines of the Campo dos Ventos wind complex (consisting of the São Domingos, Ventos de São Martinho and Campo dos Ventos I, III and V Wind Farms) and São Benedito wind complex (consisting of the Ventos de São Benedito, Ventos de Santo Dimas, Santa Mônica and Santa Úrsula Wind Farms) started to enter into operations.  The first wind turbines commenced operations in May 2016.  The complexes have 231 MW of Installed Capacity.  The Campo dos Ventos and São Benedito wind farms are located in the state of Rio Grande do Norte. 

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

By the end of 2020, when we expect the Boa Vista SHPP to become operational, we expect our total Installed Capacity to reach 3,299 MW.

Background

Regulated Distribution Tariffs

Our results of operations are significantly affected by changes in regulated tariffs for electricity.  In particular, most of our revenues are derived from sales of electricity to Captive Consumers at regulated tariffs.  In 2017, sales to Captive Consumers represented 65.9% of the volume of electricity we delivered and 59.7% of our operating revenues, compared to 67.9% of the volume of electricity we delivered and 72.8% of our operating revenues in 2016.  These proportions may decline if consumers migrate from captive to free status. 

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

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

·	Our concession agreements provide for an annual adjustment to take account of changes in our costs, which for this purpose are divided into costs that are beyond our control (known as Parcel A Costs) and costs that we can control (known as Parcel B Costs).  Parcel A Costs include, among other things, increased prices under long-term supply contracts, and Parcel B Costs include, among others, the return on investment related to our concessions and their expansion, as well as maintenance and operational costs.  Our ability to fully pass through our electricity acquisition costs to Final Consumers is subject to:  (a) our ability to accurately forecast our energy needs and (b) a ceiling linked to a reference value, the Annual Reference Value.  The Annual Reference Value is the weighted average of electricity acquisition costs resulting from electricity prices of all public auctions carried out by ANEEL and CCEE in the Regulated Market for electricity to be delivered five and three years from any such auction and only applies during the first three years following the commencement of delivery of the acquired electricity.  See “Item 4.  Information on the Company—The Brazilian Power Industry—The New Industry Model Law” for a more detailed description of all the limitations on the ability of distribution companies to fully pass through their electricity acquisition costs to Final Consumers.  Under agreements that were in force before the enactment of these regulatory reforms, we pass through the costs of acquired electricity subject to a ceiling determined by the Brazilian government.  The annual adjustment of tariffs occurs every April for CPFL Paulista and RGE Sul, every June for RGE, every October for CPFL Piratininga and as of February 2016, every March for CPFL Santa Cruz (prior to February 2016, the tariff adjustments for CPFL Santa Cruz occurred every February). There is no annual adjustment in a year with a periodic revision.
·	Our concession agreements provide for a periodic revision (revisão periódica), every five years for CPFL Paulista, CPFL Santa Cruz, RGE and RGE Sul, and every four years for CPFL Piratininga in order to restore the financial equilibrium of our tariffs as contemplated by the concession agreements and to determine a reduction factor (known as the X factor) in the amount of any increase to Parcel B Costs passed on to all of our consumers.  ANEEL’s Resolution No.  457/2011 has established the methodology to be applied to the third periodic revision cycle (2011 to 2014).  As of 2015, ANEEL now reviews the underlying methodologies applicable to the electrical energy sector from time to time on an item by item basis, whereas previously all methodologies were addressed in set cycles such as in 2008-2010 and 2010-2014.  For additional information, see “Item 3.  Risk Factors— The tariffs that we charge for sales of electricity to Captive Consumers and the tariffs for using the distribution system that we charge to Free and Special Consumers are determined by ANEEL pursuant to concession agreements with the Brazilian government, so our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are not favorable to us” and “Item 4.  Information on the Company—The Brazilian Power Industry—Distribution Tariffs”.

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·

Brazilian law also provides for an extraordinary revision (revisão extraordinária) to take account of unforeseen changes in our cost structure.  The last extraordinary revisions took place on January 24, 2013 and February 27, 2015.  The 2013 event aimed to adjust our tariffs as a result of the changes introduced by Law No.  12,783/13.  Law No.  12,783/13 reduced the CDE Account charge and eliminated the CCC and RGR charges, therefore reducing the Parcel A Costs (energy prices, charges for the use of the Basic Network and regulatory charges, which we pass on to our consumers).  In 2015, tariffs were increased to take into account the extraordinary costs due to the full dispatch of thermal plants and distributors’ involuntary exposure.  No extraordinary revision occurred in 2016 or 2017.

Annual Adjustment — RTA

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

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

 

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

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

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

(4)   Represents the effect of Periodic Revisions – RTP for CPFL Piratininga that occurred in 2015, considering that there is no Annual Adjustment – RTA in the year of Periodic Revisions – RTP.

(5)   Represents the effect of Periodic Revisions – RTP for CPFL Santa Cruz, CPFL Mococa, CPFL Leste Paulista, CPFL Sul Paulista and CPFL Jaguari (now all merged into CPFL Santa Cruz) that occurred in 2016, considering that there is no Annual Adjustment – RTA in the year of Periodic Revisions – RTP.  Additionally, on February 3, 2016, ANEEL changed the annual adjustment period for CPFL Santa Cruz, CPFL Leste Paulista, CPFL Sul Paulista, CPFL Mococa and CPFL Jaguari (now all merged into CPFL Santa Cruz) to March every year.

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

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

 

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Periodic Revisions — RTP

On November 22, 2011, ANEEL defined the methodology applicable to the third periodic revision cycle (2011 to 2014) through Resolution No.  457/2011.  For the third cycle, ANEEL has designated a method of recognizing which costs we may pass through to our consumers.  In addition, ANEEL approved the methodology for calculating the tariff for using the distribution system (Tarifa de Uso do Sistema de Distribuição), or TUSD, and other electricity tariffs, under which distribution companies assume all market risk resulting from tariff indicators.  As compared to the previous tariff cycle, this methodology negatively impacted our financial condition and results of operations.

On April 28, 2015, ANEEL established the methodology to be applied in the fourth periodic revision cycle (2015 to 2016) through Resolutions Nos.  648/2015, 649/2015, 650/2015, 652/2015, 657/2015, 660/2015, 682/2015, 685/2015 and 686/2015.  The fourth cycle maintains most of the parameters used for the third cycle, such as the definition, by ANEEL, of the costs we may pass to our consumers.  Some of the changes for the fourth cycle include a tariff incentive to the development of certain public policies and also the increased importance of the X Factor component in the new tariff formula.  Compared to the previous tariff cycle, the new methodology positively impacted our financial condition and results of operations. 

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

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

 

(1)   As a result of ANEEL’s delay in determining the methodology applicable to the third periodic revision cycle, the periodic review process for CPFL Piratininga was concluded on October 23, 2012, rather than the October 23, 2011, which is the date that complies with the concession agreement.  CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista (now merged into CPFL Santa Cruz) had their revision process concluded on February 3, 2013, rather than February 3, 2012, which is the date that complies with the concession agreement.  However, the difference of tariffs billed from the date of the revision process specified in the concession agreement and the actual date on which the process was concluded was reimbursed to consumers.

(2)   CPFL Santa Cruz, CPFL Jaguari, CPFL Mococa, CPFL Leste Paulista and CPFL Sul Paulista (now merged into CPFL Santa Cruz) filed administrative appeals questioning the results of their periodic review processes.  The appeals were assessed by ANEEL in January 2014, with the following results:  (i) Dispatch No.  165 of January 28, 2014 alters the tariff revision index from 7.20% to 7.18% for CPFL Mococa, mainly because of a Regulatory Asset Base, or RAB, reduction; (ii) Dispatch 212 of January 30, 2014 alters the tariff revision index from 4.36% to 4.16% for CPFL Santa Cruz, mainly because of a RAB reduction; (iii) Dispatch No.  166 of January 28, 2014 alters the tariff revision index from ‑2.20% to ‑2.00% for CPFL Leste Paulista, mainly because of an increase in RAB and regulatory non-technical losses; (iv) Dispatch No.  211 of January 30, 2014 alters the tariff revision index from -4.41% to ‑4.48 % for CPFL Sul Paulista, mainly because of a RAB reduction; and (v) Dispatch No.  167 of January 28, 2014 alters the tariff revision index of CPFL Jaguari only to the part relating to financial components, mainly because of a RAB increase.

(3)   CPFL Piratininga, CPFL Paulista and RGE filed administrative appeals questioning the results of their periodic review processes.  CPFL Piratininga questioned the regulatory losses in the periodic review process.  The appeal was assessed by ANEEL, and Dispatch No.  3,426, issued on October 8, 2013, altered the result of the periodic review process from -4.45% to -3.95%.  CPFL Paulista questioned the Regulatory Asset Base, and Dispatch No.  733 of March 25, 2014 altered the result of the periodic review process from 4.53% to 4.67%.  RGE also had the Regulatory Asset Base altered once the assets of the two municipalities, Putinga and Anta Gorda, that won on a tender, were included in the RAB.  Therefore, Dispatch No.  1,857 of June 17, 2014 altered the result of the periodic review process from -10.66% to -10.27%.

(4)   The fourth cycle of periodic revisions for CPFL Paulista and RGE Sul will take place in April 2018 and for RGE will take place in June 2018.

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

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

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Extraordinary Tariff Adjustment – RTE

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

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

 

 

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

	CPFL Paulista	CPFL Piratininga	RGE	RGE Sul	CPFL Santa Cruz(1)(3)	CPFL Mococa(1)(3)	CPFL Leste Paulista(1)(3)	CPFL Sul Paulista(1)(3)	CPFL Jaguari(1)(3)
2015
Economic adjustment	0.0%	0.0%	0.0%	(2)	0.0%	0.0%	0.0%	0.0%	0.0%
Regulatory adjustment	32.28%	29.78%	37.16%	(2)	5.16%	11.81%	14.52%	17.02%	16.80%
Total adjustment	32.28%	29.78%	37.16%	(2)	5.16%	11.81%	14.52%	17.02%	16.80%

 

(1)   On April 7, 2015 ANEEL changed, through Resolution No.  1,870/2015, the Extraordinary Tariff Review – RTE of the distributors CPFL Leste Paulista, CPFL Sul Paulista, CPFL Jaguari, CPFL Mococa and CPFL Santa Cruz (now all merged into CPFL Santa Cruz).  This correction was necessary to change the value of the monthly quotas of CDE – energy related to ACR, intended for repayment of loans contracted by CCEE in the management of ACR account.  The rates resulting from this rectification entered into force on April 8, 2015.

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

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

 

Sales to Potential Free Consumers

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

Historically, relatively few of our Potential Free Consumers have elected to become Free Consumers.  We believe this is because:  (i) they consider the advantages of negotiating for a long‑term contract at rates lower than the regulated tariff are outweighed by the need to bear additional costs (particularly transmission costs) and long‑term price risk; and (ii) some of our Potential Free Consumers, who entered into contracts before July 1995, may only change to suppliers that purchase from renewable energy sources, such as Small Hydroelectric Power Plants or biomass.  We do not expect that a substantial number of our consumers will become Free Consumers, but the prospects for migration between the different markets (captive and free) over the long term, and its long-term implications for our financial results, are difficult to predict.

 

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

 

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

Brazilian Economic Conditions

All of our operations are in Brazil, and we are affected by general Brazilian economic conditions.  See “Item 3.  Information on the Company—Risk Factors—Risks Relating to Brazil”.  In particular, the general performance of the Brazilian economy affects demand for electricity, and inflation affects our costs and our margins. 

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

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

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

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

The following table shows the main performance indicators of Brazilian economy for the years ended December 31, 2017, 2016 and 2015:

 

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

(1)    Source:  Focus Report.

(2)   Unemployment rate based on the National Household Sampling Survey (Pesquisa Nacional por Amostra de Domicílios, or PNAD), released by the Brazilian Institute for Geography and Statistics (Instituto Brasileiro de Geografia e Estatística – IBGE). 

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

(4)   Inflation (IPCA) is a broad consumer price index measured by IBGE and the reference for inflation targets set forth by the Brazilian Monetary Council (Conselho Monetário Nacional, or CMN).

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

 

                    The years 2015 and 2016 in Brazil were marked by strong economic contraction with significant political crises and uncertainties, and poor economic indicators. However, in 2017, the Brazilian economy began to improve, showing recovery in principal areas of activity and financial indicators, with GDP growth of 1.0% (compared with negative growth of 3.5% in both 2016 and 2015), according to the Brazilian Central Bank.

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

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

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

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                    However, despite the improvement in various macro factors in 2017, Brazil continues to experience successive downgrades of the country’s credit rating:  Standard & Poor’s (September 2015 and January 2018); Fitch Ratings (December 2015); Moody’s Investors Service (February 2016). These devaluations reflect continued adverse fiscal developments and continued political uncertainty in Brazil.

                    Our credit risk and debt securities are rated by Standard and Poor’s and Fitch Ratings. These classifications reflect, among other factors, the outlook for the Brazilian electricity sector, the political and economic context, country risk, hydrological conditions in the areas where our plants are located, our operational performance and our level of debt.  Our rating were reduced in 2016 from AA+ to AA- by Standard and Poor’s as a result of the downgrading of Brazil’s investment grade due to changes in economic and political scenarios, as mentioned in the paragraph above. Despite the downgrading of Brazil’s investment grade in September 2015, Fitch Ratings did not reduce our rating in 2016, maintaining it at AA. As of the date of this report, our ratings from both agencies have been sustained.

Reclassification of information for 2015

                    Data for 2015 has been restated to reflect a change in presentation of the line item representing Changes in expected cash flows from Concession Financial Assets, which relates to our Distribution segment.  Since January 1, 2016, this line item has been included in Other operating revenues, within Net operating revenue, together with the other income related to the core activity of the asset.  This item was previously presented as part of Net financial expense.  We believe the new presentation more accurately reflects the business model of electricity distribution and provides a better representation of our operational and financial performance.  The reclassification does not affect total assets, equity, net income or cash flows. 

Results of Operations—2017 compared to 2016

Net Operating Revenues   

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

This increase in operating revenue was primarily due to the combined effect of: (i) a positive variation of R$3,996 million in the Sector Financial Assets and Liabilities, as discussed in the section “Other Operating Revenue” below; (ii) an increase of R$1,699 million in energy sales in the spot market, as discussed in the section “Sales by Destination” below; (iii) an increase of R$1,430 million in electricity sales to final consumers, as discussed in the section “Sales by Destination” below; and (iv) an increase of R$869 million in other concessionaires and licensees, partially offset by an increase of R$1,637 million in deductions from operating revenues, discussed in the section “Deductions from operating revenues” below.

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

Sales by Destination

Sales to Final Consumers

Compared to the year ended December 31, 2016, our gross operating revenues from sales to Final Consumers (which includes TUSD revenue from captive consumers) increased 7.5% (or R$1,788 million) in the year ended December 31, 2017, to R$25,787 million.  Our gross operating revenues primarily reflect sales to Captive Consumers in concession areas from our distribution subsidiaries, as well as TUSD revenue from the use of our network by Captive Consumers, both of which are subject to tariff adjustment as described below.  Our gross operating revenue also reflects sales to Free Consumers in commercial and industrial categories.

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

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

·	Residential and commercial consumers.  With respect to Captive Consumers (which represent 95.3% of the total amount sold to this category in our consolidated statements), average prices decreased 5.3% for residential consumers and 3.6% for commercial consumers, due to the annual tariff adjustment described above.  With respect to Free Consumers, the average price for the commercial consumers decreased 25.7%.
·	Industrial consumers.  Average prices decreased 5.6%, mainly due to the tariff adjustments described above.  With respect to Free Consumers, the average price for industrial consumers decreased 31.4%.  The decrease in the average price for the industrial consumers was due to the tariff applied to the contracts governing the use of our TUSD by Free Consumers, which resulted from the annual tariff adjustment.

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

The volume sold to residential and commercial categories, which accounts for 66.6% for our sales to Final Consumers, increased by 16.1% (or 2,649 GW) and 5.2% (or 501 GW), respectively.  These increases were due to the combined effect of: 

·	Residential:  (i) the inclusion of RGE Sul’s distribution operations in our consolidated results for the full year in 2017 (compared to inclusion in only the last two months of 2016), which led to an increase of 2,230 GW sold to residential consumers, compared to 426 GW in 2016; and (ii) an increase of 2.6% of the volume sold by our distribution subsidiaries (excluding RGE Sul) to the residential category; due to our residential consumers’ greater economic strength in 2017, driven by the GDP growth of 1.0% in 2017 compared to the GDP contraction of 3.5% in 2016.
·	Commercial:  (i) an increase of 142 GW in the volume of energy sold to Captive Consumers in the commercial category; and (ii) an increase of 617 GW in the volume sold by our commercialization subsidiaries due to the migration of consumers from captive to the free consumer category.  This increase was partly offset by a reduction of 60.9% (or 258 GW) in the volume of energy from renewable sources sold to commercial consumers who elected to become Special Free Consumers, whose contracted energy demand is between 500 kV and 3 MW, and who are allowed to purchase energy only from renewable sources.

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

Sales to wholesalers

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

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Other operating revenues

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

(i)	a positive variation of R$3,996 million in revenue from Sector Financial Assets and Liabilities, which posted revenue of R$1,901 million in 2017 compared with an expense of  R$2,095 million in 2016.  This revenue reflects timing differences between our budgeted costs included in the tariff at the beginning of the tariff period, and those actually incurred while it is in effect, creating a contractual right to pay (or receive) cash to or from consumers through subsequent tariffs or to pay to or receive from the granting authority any remaining amounts at the expiration of the concession.  This leads to an adjustment in order to recognize the future decrease (or increase) in tariffs to take account of lower (or additional) costs in the current year, such adjustment being recognized as a positive (or negative) item of revenue.  The increase in this item in 2017 was driven mainly by (i) an increase of R$2,353 million related to electric energy cost, (ii) an increase of R$495 million related to the pass-through from Itaipu and (iii) an increase of R$610 million in contributions to the ESS and EER.  For further information, see note 8 to our audited annual consolidated financial statements;
(ii)	an increase of R$719 million in revenue from construction of concession infraestructure; and
(iii)	the increase of 12.1% (or R$153 million) in revenue related to the low income subsidy and discounts on tariffs reimbursed by funds from the CDE Account.

Deductions from operating revenues

We deduct certain taxes and industry charges from our gross operating revenue to calculate net revenue.  The state‑level value‑added tax (ICMS) is calculated based on gross operating revenue from final consumers (billed), while federal PIS and COFINS taxes are calculated based on total gross operating revenue.  The research and development and energy efficiency programs (regulatory charges) are calculated based on net operating revenue.  Other regulatory charges vary depending on the regulatory effect reflected in our tariffs.  These deductions represented 33.2% of our gross operating revenue in the year ended December 31, 2017 and 37.9% in the year ended December 31, 2016.  Compared to the year ended December 31, 2016, these deductions increased by 14.0% (or R$1,637 million) to R$13,309 million in 2017, mainly due to: (i) an increase of 27.9% (or R$736 million) in PIS and COFINS taxes, mainly due to the increase in our gross operating revenues (the calculation basis for these taxes); (ii) an increase of 10.55% (or R$521 million) in ICMS taxes; (iii) an increase of R$448 million in tariff flag revenues recognized, which are required to be paid into the Tariff Flag Resources Centralizing Account administered by the CCEE; and (iv) a decrease of R$175 million in contributions made to the CDE Account as a result of the new quotas defined by ANEEL in 2017.

Sales by segment

Distribution

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

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

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

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Generation (conventional sources)

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

Generation (renewable sources)

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

                                Commercialization

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

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

Services

Net operating revenues from our Services segment in the year ended December 31, 2017 amounted to R$486 million, an increase of 21.3% (or R$86 million) compared to R$400 million in the year ended December 31, 2016.  This increase was mainly due to:  (i) an increase of R$75 million in revenues from construction and maintenance services; (ii) an increase of R$27 million in revenues from administrative, call center and IT outsourcing.  These increases were partially offset by:  (i) a decrease of 23.5% (R$25 million) in revenue from our self-generation energy efficiency business; and (ii) an increase of 53.8% (or R$9 million) in PIS and COFINS tax deductions from operating revenues, mainly due to the increase in our gross operating revenues (the basis for calculation for these taxes).

Income from Electric Energy Service by Destination

                Cost of Electric Energy

Electricity purchased for resale.  Our costs for the purchase of energy for resale increased 58.6% (or R$5,768 million) in the year ended December 31, 2017, to R$15,617 million (65.8% of our total operating costs and operating expenses) compared with R$9,849 million for the year ended December 31, 2016 (representing 59.4% of our total operating costs and operating expenses), mainly due to an increase of 30.1% in average prices, reflecting:

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Services

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

Net Income

Net Financial Expense

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

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

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

At December 31, 2017, we had R$15,310 million (compared with R$16,452 million at December 31, 2016) in debt denominated in reais, which accrued both interest and inflation adjustments based on a variety of Brazilian indices and money market rates.  The average CDI interbank rate during the year decreased to 9.93% in 2017, compared to 14% in 2016; and the average TJLP decreased to 7.1% in 2017, compared to 7.5% in 2016.  We also had the equivalent of R$4,858 million (compared with R$5,502 million at December 31, 2016) of debt denominated in foreign currency, principally U.S. dollars.  In order to reduce the exchange rate risk with respect to this foreign currency‑denominated debt and variations in interest rates, we implement a policy of using exchange and interest rate derivatives.

Income and Social Contribution Taxes

Our net charge for income and social contribution taxes increased to R$604 million in the year ended December 31, 2017 compared with R$501 million in the year ended December 31, 2016.  Our effective rate of 32.7% on pretax income in the year ended December 31, 2017 was lower than the official rate of 34%, principally due to the ability to recognize further prior year tax loss carryforwards.  Our unrecorded tax credits relate to losses generated for which there is no currently reasonable certainty that future taxable income will be sufficient to absorb such losses (see note 9.6 to our audited annual consolidated financial statements). 

Net Income

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

Net Income by Segment

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

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Distribution

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

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

·	a decrease of 12.7% (or R$169 million) in financial expenses, mainly due to (i) a decrease of R$1,294 million in derivatives expenses; (ii) an increase of R$1,224 million in monetary and exchange rate variations; and (iii) a decrease of R$67 million in financial expenses from debt charges as a result of lower indebtedness;
·	a decrease of R$184 million in financial income, mainly due to: (i) a decrease of 41.4% (or R$153 million) in income from financial investments; (ii) a decrease of 48.5% (or R$38 million) in monetary and exchange rate variations; and (iii) a decrease of 100% (or R$33 million) in income from the adjustment of Sector Financial Assets and Liabilities (see note 8 to our audited annual consolidated financial statements). These decreases were partly offset by:  (i) an increase of 10% (or R$24 million) in arrears of interest and fines; and (ii) an increase of 33% (or R$12 million) in income from interest of escrow deposits.

Generation (conventional sources)

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

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

Generation (renewable sources)

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

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

Commercialization

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

Services

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

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Results of Operations—2016 compared to 2015

Net Operating Revenues  

Compared to the year ended December 31, 2015, our net operating revenues decreased 7.2% (or R$1,487 million) to R$19,112 million in the year ended December 31, 2016.  This decrease in operating revenue primarily reflected a negative variation of R$4,601 million in the Sector Financial Assets and Liabilities and the decrease of R$207 million in revenue from adjustment of expected cash flow related to the Concession Financial Asset, both discussed in the section “Other Operating Revenue” below.

The above-mentioned decreases were offset by:  (i) a decrease of R$2,031 million in deductions from operating revenues, discussed in the section “Deductions from operating revenues” below; (ii) an increase of R$836 million in other operating revenues, discussed in “Other Operating Revenue” below; and (iii) an increase of R$573 million in our gross operating revenues from sales to Final Consumers, discussed in “Sales by Destination” below.

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

Sales by Destination

Sales to Final Consumers

Compared to the year ended December 31, 2015, our gross operating revenues from sales to Final Consumers (which includes TUSD revenue from captive consumers) increased 2.4% (or R$573 million) in the year ended December 31, 2016, to R$23,998 million.  Our gross operating revenues primarily reflect sales to Captive Consumers in concession areas from the nine distribution subsidiaries we had at that time, as well as TUSD revenue from the use of our network by Captive Consumers, both of which are subject to tariff adjustment as described below.  Our gross operating revenue also reflects sales to Free Consumers in commercial and industrial categories.

Distribution companies’ tariffs are adjusted every year, in percentages that are specific to each category of consumer.  The month in which the annual tariff adjustment becomes effective varies, impacting both the year in which the tariff adjustment takes place as well as the following year.  The adjustments for our largest subsidiaries occur in April (CPFL Paulista), June (RGE) and October (CPFL Piratininga).  RGE Sul, which has been included in our consolidated income statements since November 1, 2016, has its annual tariff adjustment in April.

In the year ended December 31, 2016, overall average energy prices decreased by 0.8%, mainly due to the combined effect of:  (i) the adoption of a green tariff flag during most of 2016, leading to a reduction of the average tariff when compared to the red tariff flag that applied in most of 2015; and (ii) the combined positive effect of tariff adjustments for 2015 and 2016 (Annual Adjustment – RTA or Periodic Revision – RTP, since there is no Annual Adjustment in the year of Periodic Revisions) for our distribution subsidiaries (discussed under “Regulated Distribution Tariffs”).  Overall average prices for Final Consumers in 2016 were higher for all consumer classes:

·	Residential and commercial consumers.  With respect to Captive Consumers (which represent 98.5% of the total amount sold to this category in our consolidated financial statements), average prices increased 3.5% for residential and 3.8% for commercial, due to the positive average overall tariff adjustment, offset in part by lower prices linked to the green flag during most of 2016, as described above.  With respect to Free Consumers (which consists of commercial consumers only), the average price decreased 2.9%.
·	Industrial consumers. Average prices increased 0.5%, mainly due to tariff adjustments and the adoption of the green flag during most of 2016 as described above.  With respect to Free Consumers, the average price for industrial consumers decreased 1.9%.  The decrease in the average price for industrial consumers was due to the tariff decrease, which resulted from renegotiations of tariffs in contracts with Free Consumers.

The total volume of energy sold to Final Consumers in the year ended December 31, 2016 increased 3.3% compared to the year ended December 31, 2015.  This increase represents the combined effect of:

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(i) an increase of 33.5% (or 1,638 GW) in the volume of energy sold to Conventional Free Consumers (driven by increases of 1,210 GW to industrial and 421 GW to commercial consumers) by our commercialization subsidiaries, as a result of migration of consumers from captive to the free consumer category;

(ii) an increase of 405 GW in the volume of enery from renewable sources sold to Special Free Consumers (those consumers whose contracted energy demand between 500 kV and 3 MW, who may purchase energy from renewable sources only);

the inclusion of RGE Sul’s distribution operations in our consolidated results for the last two months of 2016, which led to an increase of 1,141 GW, compared with no contribution in 2015;

(iv) these effects were offset in part by a reduction of 4.2% (or 1,686 GW) in the volume sold by our distribution subsidiaries (other than RGE Sul, as discussed above) to Captive Consumers, mainly in the industrial (1,097 GW) and commercial (557 GW) categories, due to migration of some of these consumers to the “Free Consumer” category.

The volume sold to residential and commercial categories, which accounts for 65.8% for our sales to Final Consumers, increased by 1.9% (or 308 GW) and 5.0% (or 461 GW), respectively.  These increases were due to the combined effect of:

·	Residential:  (i) the inclusion of RGE Sul’s distribution operations in our consolidated results for the last two months of 2016, which led to an increase of 426 GW sold to residential consumers, compared to no volume in 2015; (ii) offset in part by a reduction of 0.7% (or 118 GW) of the volume sold by our distribution subsidiaries (excluding RGE Sul) to the residential category, due to an increase in unemployment, decreasing real incomes and an increase in electricity tariffs.
·	Commercial:  (i) an increase of 421 GW in the volume of energy sold to the commercial category by our commercialization subsidiaries, due to migration of consumers from captive to the free market; (ii) an increase of 405 GW in the volume of energy from renewable sources sold to commercial consumers who elected to become Special Free Consumers, whose contracted energy demand is between 500 kV and 3 MW, and are allowed to purchase energy only from renewable sources; (iii) the inclusion of RGE Sul’s distribution operations in our consolidated results for the last two months of 2016, which led to an increase of 191 GW sold to comercial consumers, compared to no volume in 2015; and (iv) partly offset by a reduction of 6.2% (or 557 GW) of energy sold to commercial consumers by our distribution subsidiaries, reflecting the migration of some consumers from the captive to the free market, as well as the impact of macroeconomic factors such as the increase in unemployment.

The volume sold to industrial consumers, which represented 22.0% of our sales to Final Consumers in 2016 (compared with 23.6% in 2015), increased by 2.1% in the year ended December 31, 2016 compared to the year ended December 31, 2015.  Volumes to Captive Consumers in this category decreased 11.5%, which represents the net effect of a decrease of 1,097 GW related to our distribution subsidiaries (except RGE Sul) offset in part by 162 GW contributed by RGE Sul in the last two months of 2016 (compared to no volume in 2015).  The net decrease reflects the migration of industrial consumers from the captive to the free market.  Regarding Free Consumers, volumes sold increased by 26.2% (or 1,210 GW), reflecting the same migration of consumers, as well as improvements in Brazilian economic conditions during 2016.

Sales to wholesalers

Compared to the year ended December 31, 2015, our gross operating revenues from sales to wholesalers in the year ended December 31, 2016 decreased 1.2% (or R$41 million) to R$3,496 million (11.4% of gross operating revenues), due mainly to a decrease of 26.7% (or R$233 million) in sales of energy in the spot market (driven by lower average prices despite an increase of 43.9% in our volume sold).  This decrease was offset by:  (i) an increase of 6.6% (or R$148 million) in sales of electricity to other concessionaires and licensees, which represents the net effect of an increase of 15.0% in the volume of energy sold and a decrease of 7.2% in the average price compared to 2015; and (ii) an increase of 9.9% (or R$48 million) in sales of electricity to Furnas, driven by an increase of 9.6% in the average price, with the volume remaining relatively stable.  For more information on net operating revenues from our segments, see “—Sales by Segment”. 

                Other operating revenues

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Other costs and operating expenses

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

Compared to the year ended December 31, 2015, our other costs and operating expenses increased 16.1% (or R$747 million) to R$5,389 million in the year ended December 31, 2016, mainly due to the following events:  (i) an increase of 29.4% (or R$307 million) in expenses related to the construction of concession infrastructure; (ii) an increase of 16.5% (or R$155 million) in our personnel expenses, reflecting increased costs under our collective bargaining agreements as well as a 33.6% increase in our number of employees at year-end, although this was mainly due to the acquisition of RGE Sul and only impacted expenses in November and December; (iii) an increase of 16.5% (or R$92 million) in expenses related to outsourced services; (iv) an increase of R$67 million in expenses related to disposal of assets; (v) an increase of 6% (or R$59 million) in depreciation and amortization expenses; (vi) an increase of 35.7% (or R$50 million) in inventory consumption; and (vii) an increase of 39% (or R$49 million) in allowance for doubtful accounts.

Those increases were offset by:  (i) a decrease of 31% (or R$82 million) in legal, judicial and indemnity expenses; and (ii) a decrease of 15.7% (or R$48 million) in expenses from Intangible Assets of Concession amortization.

                Income from Electric Energy Service

Compared to the year ended December 31, 2015, our income from electric energy service decreased 4.6% (or R$122 million) to R$2,523 million in the year ended December 31, 2016, since our net operating revenue decreased by more in absolute terms (R$1,491 million) than the decrease in our cost of generating and distributing electric energy and other operating costs and expenses (R$1,368 million). 

Income from Electric Energy Service by Segment

Distribution

Compared to the year ended December 31, 2015, income from electric energy service from our Distribution segment decreased 19.5% (or R$303 million) to R$1,254 million in the year ended December 31, 2016.  As discussed above, net operating revenues from the segment decreased by 11.4% (or R$1,928 million) while costs and operational expenses related to the segment decreased by 10.5% (or R$1,625 million).  The main contributing factors to the changes in costs and operational expenses were as follows:

Electricity costs.  Compared to the year ended December 31, 2015, electricity costs decreased 18.3% (or R$2,187 million), to R$9,760 million in the year ended December 31, 2016.  The cost of energy purchased for resale decreased 19.6%, (or R$2,065 million), reflecting:  (i) a decrease of 29.4% (or R$844 million) in purchases of energy from Itaipu, as described above; (ii) a decrease of 10.2% (or R$805 million) in the cost of energy purchased in the Regulated Market, reflecting an increase of 11.8% in the volume of energy purchased, which was more than offset by lower prices; and (iii) a decrease of 74.4% (or R$628 million) in the cost of energy purchased in the spot market and from PROINFA contracts driven by a decrease of 60.5% in the volume purchased.  These decreases were partially offset by a decrease of 19.6% (or R$211 million) in PIS and COFINS tax credits related to purchases of energy.

In addition, charges for the use of the transmission and distribution system decreased 8.8% (or R$122 million) mainly due to:  (i) a decrease of 34.5% (or R$191 million) in System Service Charges costs; and (ii) a decrease of R$16 million in Basic Network Charges cost.  These decreases in charges for the use of the transmission and distribution system were partially offset by:  (i) an increase of 95.2% (or R$52 million) in Reserve Energy Charges costs; (ii) an increase of 32.6% (or R$19 million) in Connection Charges costs; and (iii) a decrease of 8.2% (or R$11 million) in tax credits related to network usage charges (which represents an increase in electricity network usage charges).

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Compared to the year ended December 31, 2015, net income from our Distribution segment decreased 34.9%, (or R$219 million), to R$407 million in the year ended December 31, 2016, as a result of:  (i) a decrease of 19.5% (or R$303 million) in income from electric energy service and an increase of 6.7% (or R$35 million) in net financial expenses, partly offset by a decrease of 28.7% (or R$119 million) in Income and Social Contribution Taxes expenses.

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

·	an increase of R$75 million in financial expenses, mainly due to an increase of R$108 million in financial expenses from debt charges and monetary and exchange rate variations as a result of higher indebtedness, partially offset by a decrease of R$31 million in other financial expenses, mainly interest on intercompany loans and Tax on Financial Transactions (Impostos sobre Operações Financeirasor IOF); partly offset by
·	an increase of R$41 million in financial income, mainly due to:  (i) an increase of 126.5% (or R$207 million) in income from financial investments; and (ii) an increase of 13.6% (or R$29 million) in arrears of interest and fines.  These increases were partly offset by:  (i) a decrease of 79.6% (or R$130 million) in income from the adjustment of Sector Financial Assets and Liabilities (see note 8 to our audited annual consolidated financial statements); and (ii) a reduction of 56.6% (or R$48 million) in income from adjustment of escrow deposits.

Generation (conventional sources)

 

Net income from our Generation from Conventional Sources segment increased by 78.5% (or R$222 million) to R$505 million during the year ended December 31, 2016 from R$283 million for the year ended December 31, 2015.  This increase is mainly due to:  (i) the increase of 23.7% (or R$129 million) in income from electric energy service; (ii) the increase of 43.6% (or R$95 million) in equity interests in joint ventures (see note 12 to our audited annual consolidated financial statements); and (iii) a decrease of 13.6% (or R$60 million) in net financial expenses.  These increases were partially offset by an increase of 162.3% (or R$61 million) in Income and Social Contribution Taxes expenses.

The decrease in net financial expenses was due mainly to:  (i) an increase of 102.9% (or R$52 million) in income from financial investments; and (ii) an increase of 106.1% (or R$35 million) in positive monetary and exchange variations.  These increases were partially offset by an increase of R$13 million in debt charges and negative monetary and exchange variations, due mainly to the increase in our indebtedness level.

Generation (renewable sources)

The net loss from our Generation from Renewable Sources segment increased by 150.1% (or R$85 million) to R$141 million in the year ended December 31, 2016 compared to net loss of R$56 million in 2015, mainly due to the combined effect of the decrease of 4.5% (or R$21 million) in income from electric energy service and an increase of 14.3% (or R$67 million) in net financial expenses and, slightly offset by a decrease of R$3 million in Income and Social Contribution Taxes expenses.

The increase in net financial expenses was driven by an increase of R$92 million in debt expenses and monetary and exchange rate variations, offset by an increase of R$22 million in capitalized borrowing costs, which is accounted for as a decrease in financial expenses. 

Commercialization

Compared to the year ended December 31, 2015, net income from our Commercialization segment increased 27.5% (or R$24 million), to R$112 million in the year ended December 31, 2016, reflecting the combined effect of an increase of 27.1% (or R$34 million) in the income from electric energy service and a slight decrease of R$2 million of net financial income, partly offset by an increase of R$12 million in Income and Social Contribution Taxes expenses.

Services

Compared to the year ended December 31, 2015, net income from our Services segment increased 4.2% (or R$2 million), to R$54 million in the year ended December 31, 2016.  This relatively stable number reflects an increase of 113.5% (or R$35 million) in the segment’s income from electric energy service, partially offset by a decrease of 86.1% (or R$34 million) in net financial income (driven mainly by a decrease of R$37 million in income from financial investments due to the reduction in average bank account balances).  Income and social contribution taxes expenses for the segment decreased by R$1 million.

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Liquidity and Capital Resources

Our credit risk and debt securities are rated by Standard and Poor’s and Fitch Ratings.  These ratings reflect, among other factors, perspectives for the Brazilian electricity sector, the political and economic context, country risk, hydrological conditions in the areas where our power plants are located, our operational performance and debt levels, and the ratings and outlook of our controlling shareholders.  Our ratings were reduced in 2016 from AA+ to AA as a result of Brazil’s downgrade from investment grade, due to changes in the country’s economic and political scenario, as discussed earlier in this Item 5.  Downgrades can increase our cost of capital and lead lenders to include additional financial covenants in the instruments that regulate our debt.

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

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

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

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

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

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

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

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

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

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

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

                Sources of Funds

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

Cash Flow

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

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

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

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

Our net cash provided by operating activities was R$4,684 million in the year ended December 31, 2016, compared to R$2,558 million in the year ended December 31, 2015 (an increase of R$2,127 million or 83.1%).  The increase primarily reflects:

(i)	an increase of R$539 million in net income, adjusted for the reconciliation of net cash;
(ii)	net decrease of R$5,537 million in operating assets (which represents an increase in the cash provided by operating activities), primarily driven by Sector Financial Assets (R$3,353 million) and accounts receivable from consumers (R$849 million);
(iii)	a decrease of R$3,407 million in cash generation arising from increases in operating liabilities, primarily due to accounts payables (R$1,607 million) and regulatory charges (R$1,323 million); and
(iv)	an increase of R$575 million in cash consumption in income tax and social contributions (R$600 million), offset by payments of interest (R$25 million).

Our net cash from financing activities recorded a consumption of cash of R$2,440 million in the year ended December 31, 2017 compared to generation of cash of R$337 million in the year ended December 31, 2016.  This increase of R$2,103 million was due to:

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

Our net cash from financing activities recorded a consumption of cash of R$337 million in the year ended December 31, 2016 compared to generation of cash of R$292 million in the year ended December 31, 2015.  This decrease of R$629 million was due to:

(i)	a decrease of R$758 million in fund-raising from borrowings and debentures;
(ii)	an increase of R$227 million related to payment of dividends; and
(iii)	a reduction of R$315 million related to payments of loans, financing, debentures and derivatives.

Indebtedness

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

 

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

·	Issuances of debentures in the amount of R$700 million by CPFL Paulista; R$380 million by RGE; R$530 million by CERAN; R$350 million by CPFL Renováveis; R$306 million by CPFL Piratininga and R$220 million by RGE Sul.
·	Incurrence of new debt denominated in U.S. dollars, principally in the amount of R$400 million by CPFL Brasil; and R$169 million by RGE.  This debt was incurred in order to improve working capital, finance debt payments, refinance maturing debt and fulfill required investments.

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

In 2018 and 2019, we expect to continue to take advantage of the financing opportunities offered by the market through issuing debentures and debt for working capital, both in the domestic and overseas markets, and those offered by the government through lines of financing provided by BNDES, in order to expand and modernize the electricity system, to undertake new investments in the Generation segment (both from Conventional Sources and Renewable Sources).

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

Terms of Outstanding Debt

Our total debt outstanding at December 31, 2017 (including accrued interest) was R$20,169 million.  Approximately R$4,858 million of our total outstanding debt, or 24.1%, was denominated in foreign currency, principally U.S. dollars.  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations.  Of our total outstanding debt, R$5,351 million falls due in 2018.

Our major categories of indebtedness are as follows:

·	BNDES.  At December 31, 2017, we had R$4,549 million outstanding under a number of facilities provided through BNDES.  These loans are denominated in reais.  The most significant part of these loans relates to:  (i) loans to our indirect generation subsidiary CPFL Renováveis (R$3,543 million); (ii) financing of investment programs for our distribution subsidiaries, primarily CPFL Paulista, CPFL Piratininga, CPFL Santa Cruz, RGE Sul and RGE (R$944 million); and (iii) loans to our subsidiaries CPFL Serviços, CPFL Brasil, CPFL Eficiência, and CPFL Transmissão Piracicaba (R$62 million).
·	Debentures.  At December 31, 2017, we had indebtedness of R$9,177 million outstanding under several series of debentures issued by CPFL Energia, CPFL Paulista, CPFL Piratininga, RGE, RGE Sul, CPFL Santa Cruz, CPFL Brasil, CPFL Geração and CPFL Renováveis.  The terms of these debentures are summarized in note 17 to our audited annual consolidated financial statements.
·	Working capital.  At December 31, 2017, we had R$859million outstanding under a number of loan agreements indexed to the CDI relating to working capital for our distribution, generation and services subsidiaries.
·	Other real-denominated debt.  As of December 31, 2017, we had R$757 million outstanding under a number of other real-denominated facilities.  These real-denominated facilities relate to our renewable energy subsidiaries (R$682 million) and our distribution subsidiaries (R$75 million).  They are indexed based on the CDI or TJLP and bear interest at different rates.
·	Other foreign currency-denominateddebt.  At December 31, 2017, we had the equivalent of R$4,858 million outstanding under other loans denominated in foreign currency, principally U.S. dollars (US$1,469 million).  We have entered into swap agreements in order to reduce our exposure to exchange rates that arises from these obligations.

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Advisory Committees

Our bylaws allow our Board of Directors to establish committees and ad hoc commissions to assist the Board of Directors with strategic issues.  Currently, there are three committees within the Company:  the Management Processes, Risks and Sustentability Committee, the Human Resources Management Committee and the Related Parties Committee, all governed by the Internal Rules of Committees of the Board of Directors.

The committees do not have decision‑making authority and their recommendations are not binding upon the Board of Directors.

Management Processes, Risks and Sustainability Committee.  Our Management Processes, Risks and Sustainability Committee supports the Board of Directors in examining and monitoring the following processes:  (i) supervising internal audit; (ii) supervising risk management and compliance activities; (iii) supervising  the Sustainability Platform and the Ethics System, including the channels for reporting complaints; (iv) managing the delegation of Sarbanes Oxley and Audit Committee activities to the Fiscal Council; and (v) forwarding to the Board of Directors proposals for improvements in business management processes, as needed.  The members of this committee are Yunwei Liu, Zhangyan Fu and Gustavo Henrique de Aguiar Sablewski.

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

Related Parties Committee.  Our Related Parties Committee is responsible for assisting the Board of Directors by:  (i) evaluating the selection procedures of suppliers and third‑party construction and other services from related parties and ensuring these transactions are conducted fairly and consistent with market practice; (ii) evaluating energy purchase or sale agreements with related parties ensuring these transactions are conducted fairly and consistent with market practice; and (iii) issuing our list of related parties. The members of this committee are Hongwu Ding, Fu Li and Marcelo Amaral Moraes.

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

Compensation

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

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

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

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

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

 

(1)   Compensation amounts include charges and accruals.

 

                The table below shows the aggregate compensation expected to be paid directly by CPFL Energia to the members of our Board of Directors and Fiscal Council and our executive officers for 2018 (excluding any compensation to be paid by our subsidiaries to such individuals):

 

 

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

⁽²⁾        Represents the weighted average number of members.

In addition, the CVM requires us to disclose the aggregate compensation paid by the CPFL group to all members of the boards of directors and fiscal councils, and all executive officers, of all companies in our consolidated group.  This aggregate compensation, including cash and benefits in kind, amounted to approximately R$73.7 million for 2017, including R$7.6 million in variable compensation.  The total amount set aside or accrued by the CPFL group to provide pension, retirement or similar benefits for the same period was approximately R$1.5 million.

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

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

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Compensation of Members of our Board of Directors and Fiscal Council

Members of our Board of Directors and Fiscal Council receive fixed monthly fees that are set in accordance with market standards and reviewed annually.  Since 2012, the Chairman of our Board of Directors has received additional compensation in light of the specific duties of that position.  Alternate members do not receive any compensation, except when actually representing the relevant effective member.

Compensation of Executive Officers

Our executive officers receive a fixed monthly salary (adjusted according to research annually carried out by specialized companies), benefits, and variable incentives.  This compensation policy aims to encourage our executives to seek the greatest returns on our investments and projects, to align market practices and to provide for the retention of executives through the following tools:

·         benefits reflecting market practice;

·         short‑term incentives, such as variable salary;

·         medium-term incentives, such as bonuses based on pre‑established targets; and

·         long-term incentives, such as cash bonuses under our long-term incentive plan discussed below, through which we aim to create a long‑term vision and foster commitment, aligning the interests of our executive officers and our shareholders and rewarding positive results and the sustainable creation of value.

This variable compensation policy reflects corporate and individual goals established under our strategic plan and our Shareholder Value Creation System.  Our Human Resources Management Committee tracks and evaluates our executive officers’ performance in accordance with annual goals, which include financial results, individual growth, value creation and human resource management.

Long-term Incentive Plan

Our long-term incentive plan, known as the ILP (Plano de Incentivo de Longo Prazo), seeks to align the interests of our Eligible Professionals (the executive officers of CPFL Energia, the Chief Executive Officers of our controlled companies and eligible Directors and Managers of CPFL Energia) with those of our shareholders, including share price performance, as part of their overall compensation mix, with the aim of fostering long-term commitment and the consistent and sustainable creation of value.  By linking a share valuation target with our long-term strategic plan, we seek to align the aims of the ILP with market recognition of the achievement of our strategic plan.  The ILP also aims to incentivize and retain employees who provide the greatest value through their individual performance.  Beneficiaries under the ILP receive cash bonuses after a vesting period when our share price reaches certain targets.  The cash bonuses reflect our stock performance through a “phantom stock” grant mechanism, such that no physical shares are issued.  The ILP is reviewed annually by our Board of Directors through the Human Resources Management Committee, and may be suspended at any time.

We measure individual performance under the ILP using a matrix (or, if such matrix is replaced, another instrument of compulsory distribution) of nine potential and actual performance goals that aims to track whether the individual possesses the necessary skills and potential, and has achieved certain individual targets.  The number of phantom shares granted to each beneficiary is based on targets that follow best practices in the market.  In 2017, 183,416 phantom stocks were granted, considering the valuation of the CPFL Energia, divided by the number of shares available in the market.

 

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

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

 

Compensation or Benefits Linked to Corporate Events

We provide indemnification for our executive officers in the event of a change of control of our company that results in elimination of the officer’s post, termination of the officer by our Board of Directors or a change in working conditions that is deemed to be a constructive termination.  We do not provide any compensation or benefit to members of our Board of Directors or Fiscal Council linked to corporate events.

Pension Plans

We provide pension plans for our executive officers, but not for members of our Board of Directors or Fiscal Council.  The table below summarizes our pension plan arrangements regarding executive officers as at and for the year ended December 31, 2017:         

(*)           Inflation-adjusted.

 

Share Ownership

The total number of common shares owned by our directors and executive officers as of March 31, 2018 was 189. None of our directors or executive officers beneficially owns one percent or more of our common shares. 

Indemnification of Officers and Directors

Neither the laws of Brazil nor our bylaws provide for specific indemnification of directors or officers.  We have held directors’ and officers’ liability insurance since February 2006.

Employees

As of December 31, 2017, we had 13,344 full time employees.  The following table sets forth the number of our employees and a breakdown of employees by category of activity as of the dates indicated in each area of our operations. 

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CPFL Paulista is subject to several tax collection proceedings filed by the city of Ribeirão Preto, charging land use taxes for the years of 2005, 2007, 2008, 2009 and 2014.  We have submitted a defense for this claim, which was accepted due to previously recognized unconstitutionality of the tax.  Currently, we are waiting for the judgment of several appeals filed by the city of Ribeirão Preto.  We believe that the likelihood of loss is remote.  Following a successful partial decision in favor of CPFL Paulista in 2017, the amount claimed totaled approximately R$334 million as of December 31, 2017.  In February 2018, the city of Ribeirão Preto withdrew one of its claims in the amount of R$164 million.

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

CPFL Piratininga has commenced proceedings against the Brazilian Federal Revenue Authority seeking the right to deduct in full the value of the Contribuição Social sobre o Lucro (CSLL) based on the income tax (Imposto sobre a Renda) for the 2002 base year and all subsequent years.  The initial request and CPFL Piratininga’s appeal were both denied. CPFL Piratininga then applied for a special and extraordinary appeal, both of which were denied in December 2017. As a result of these denials, the original decision is now final and enforceable, although we have not yet received official notice of this decision. We have deposited the full amount  into judicial escrow and will now begin the process to calculate the exact amount payable, which we believe amounts to R$152 million as of December 31, 2017. 

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

CPFL Paulista is the defendant in an indemnification proceeding for material damages and loss of profits commenced by Mr.  Sebastião José Ismael, alleging an undue reduction in energy affecting his irrigation system for palm heart plants.  CPFL Paulista made payments relating to the alleged damage and is currently in arbitration regarding the amount of any loss of profits.  We believe the likelihood of a loss is probable up to R$5.6 million and possible up to R$97.5 million in December 2017.

CPFL Piratininga is the defendant in an environmental proceeding commenced by the Attorney-General of the State of São Paulo seeking to modify existing maintenance criteria on 10 transmission lines that run close to the Parque Estadual da Serra do Mar because of the destruction of vegetation.  We believe the risk of loss is possible but the amount cannot currently be estimated because the lawsuit remains in the initial stages and the extent of any losses will depend on an environmental report, which has not yet been performed.

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

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

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

Dividend Policy

For our policy on dividend distributions, see “Item 10.  Additional Information—Allocation of Net Income and Distribution of Dividends”.

ITEM 9.                        The Offer and Listing

Trading Markets

Our common shares are listed on the B3, and our ADSs are listed on the New York Stock Exchange.  Each ADS represents two shares.  The ADSs commenced trading on the NYSE on September 29, 2004.  As of December 31, 2017, the ADSs represented 1.6% of our shares and 29.9% of our current global public float.

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

Price Information

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

(*)   Prices were adjusted to reflect the change in the ratio of our ADSs and the simultaneous reverse stock split and forward stock split of our common shares.

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ITEM 16C.    Principal Accountant Fees and Services

Audit and Non‑Audit Fees

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

 

“Audit Fees” are the aggregated fees billed by KPMG Auditores Independentes and Deloitte Touche Tohmatsu Auditores Independentes for the audit of our consolidated and annual financial statements, reviews of interim financial statements and attestation services that are provided in connection with statutory and regulatory filings or engagements for fiscal years 2017 and 2016, respectively.

“Audit‑related fees” are fees charged by KPMG Auditores Independentes and Deloitte Touche Tohmatsu Auditores Independentes for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements for the years ended December 31, 2017 and 2016, respectively.

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

Audit Committee Approval Policies and Procedures

Our fiscal council currently serves as our audit committee for purposes of the Sarbanes‑Oxley Act of 2002.  Our fiscal council has not established pre-approval policies or procedures for recommending the engagement of our independent auditors for services to our Board of Directors.  Pursuant to Brazilian law, our Board of Directors is responsible for the engagement of independent auditors.  Brazilian law prohibits our independent auditors from providing any consulting services to our subsidiaries, or to us, that may impair their independence. 

ITEM 16D.    Exemptions from the Listing Standards for Audit Committees

Under the listed company audit committee rules of the NYSE and the SEC, we must comply with Exchange Act Rule 10A‑3, which requires that we establish an audit committee composed of members of the Board of Directors that meets specified requirements.  We have designated and empowered our fiscal council to perform the role of the audit committee in reliance on the exemption set forth in Exchange Act Rule 10A‑3(c)(3).  In our assessment, our fiscal council acts independently in performing the responsibilities of an audit committee under the Sarbanes‑Oxley Act and satisfies the other requirements of Exchange Act Rule 10A‑3.

ITEM 16E.    Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

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KPMG Auditores Independentes

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

13020-431 - Campinas/SP - Brasil

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

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

www.kpmg.com.br

 

Report of Independent Registered Public Accounting Firm

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

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

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

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

Basis for Opinions

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

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

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

CPFL Energia S.A.

São Paulo – SP

We have audited the accompanying consolidated balance sheet of CPFL Energia S.A. and subsidiaries (the “Company”) as of December 31, 2016, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for each of the two years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of CPFL Energia S.A. and subsidiaries as of December 31, 2016, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2016, in accordance with International Financial Reporting Standards - IFRS, issued by the International Accounting Standards Board - IASB.

Campinas, São Paulo, Brazil

April 17, 2017

/s/ DELOITTE TOUCHE TOHMATSU

Auditores Independentes

 

Deloitte refers to one or more of Deloitte Touche Tohmatsu Limited, a UK private company limited by guarantee ("DTTL"), its network of member firms, and their related entities. DTTL and each of its member firms are legally separate and independent entities. DTTL (also referred to as "Deloitte Global") does not provide services to clients. Please see www.deloitte.com/about for a more detailed description of DTTL and its member firms.   Deloitte provides audit, consulting, financial advisory, risk management, tax and relates services to public and private clients spanning multiple industries. Deloitte serves four out of five Fortune Global 500® companies through a globally connected network of member firms in more than 150 countries bringing world-class capabilities, insights, and high-quality service to address clients’ most complex business challenges. To learn more about how Deloitte’s approximately 225,000 professionals make an impact that matters, please connect with us on Facebook, LinkedIn or Twitter.   © 2018 Deloitte Touche Tohmatsu. All rights reserved.

 

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CPFL ENERGIA S.A. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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

 

 

 

 

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

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CPFL ENERGIA S.A.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

(Amounts in thousands of Brazilian reais – R$, unless otherwise stated)

 

CPFL Energia S.A. (“CPFL Energia” or “Company”) is a publicly-held corporation incorporated for the principal purpose of operating as a holding company, with equity interests in other companies primarily engaged in electric energy distribution, generation and commercialization activities in Brazil.

The Company’s registered office is located at Rodovia Eng^o Miguel Noel Nascentes Burnier, Km 2,5, Parque São Quirino - Campinas - SP - Brazil.

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

 

 

 

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a)    CPFL Geração has 51.54% of assured energy and power of the Serra da Mesa hydropower plant, whose concession is controlled by Furnas. The small hydropower plant Cariobinha and the thermoelectric plant Carioba are inactive while they await he position of the Ministry of Mines and Energy on the early termination of their concession and are not included in the table.

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

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

·       Hydropower generation: 46 SHP’s (543.2 MW) with 39 SHPs (small hydroelectric power plants) in operation (423 MW) and 7 SHPs under development (120.2 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)    As described in note 14.4.2, on December 31, 2017, approval was given for the merger of the subsidiaries Companhia Luz e Força Santa Cruz, Companhia Leste Paulista de Energia, Companhia Jaguari de Energia, Companhia Sul Paulista de Energia and Companhia Luz e Força de Mococa into Companhia Jaguari de Energia, which adopted the trade name “CPFL Santa Cruz”.

 

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

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

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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 23, 2018.

2.2 Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis except for the following items recorded in the statements of financial position: (i) derivative financial instruments measured at fair value, (ii) financial instruments measured at fair value through profit or loss, and (iii) available-for-sale financial assets measured at fair value. The classification of the fair value measurement in the level 1, 2 or 3 categories (depending on the degree of observance of the inputs used) is presented in note 33 – Financial Instruments.

2.3 Use of estimates and judgments

The preparation of consolidated financial statements requires the Group’s management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses.

By definition, the accounting estimates are rarely the same as the actual results. Accordingly, the Group’s management reviews the estimates and assumptions on an ongoing basis, based on previous experience and other relevant factors. Adjustments resulting from revisions to accounting estimates are recognized in the period in which the estimates are revised and applied on a prospective basis.

The main accounts that require the adoption of estimates and assumptions, which are subject to a greater degree of uncertainty and may result in a material adjustment if these estimates and assumptions suffer significant changes in subsequent periods, are:

·       Note 6 – Consumers, Concessionaires and Licensees (Allowance for doubtful accounts: key assumptions regarding recoverable amounts);

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

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

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

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

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

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

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

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

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

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

 

2.4 Functional currency and presentation currency

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

 

2.5 Segment information

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

The Group´s Management use reports to make strategic decisions, segmenting the business into: (i) electric energy distribution activities (“Distribution”); (ii) electric energy generation from conventional sources activities (“Generation”); (iii) electric energy generation activities from renewable sources (“Renewables”); (iv) energy commercialization activities (“Commercialization”); (v) service activities (“Services”); and (vi) other activities not listed in the previous items.

The presentation of the operating segments includes items directly attributable to them, as well as any allocations required, including intangible assets, further details see note 29.

 

2.6 Information on equity interests

The Company's equity interests in direct and indirect subsidiaries and joint ventures are described in note 1. Except for (i) the companies ENERCAN, BAESA, Chapecoense and EPASA, which use the equity method of accounting, and (ii) the investment stated at cost by the subsidiary Paulista Lajeado in Investco S.A., all other entities are fully consolidated.

At December 31, 2017 and 2016, the noncontrolling interests recognized in the financial statements refer to the interests held by third parties in subsidiaries CERAN, Paulista Lajeado and CPFL Renováveis.

 

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

3.1  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 value and are used by the Company in the management of short-term obligations.

 

3.2 Concession agreements

The IFRIC 12 – Service Concession Arrangements establish general guidelines for the recognition and measurement of obligations and rights related to concession agreements and apply to situations in which the granting authority controls or regulates which services the concessionaire should provide with the infrastructure, to whom the services should be provided and at what price, and controls any significant residual interest in the infrastructure at the end of the concession period.

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

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The concession financial asset of distribution companies is measured based on its fair value, determined in accordance with the remuneration base for the concession assets, pursuant to the legislation in force established by the Brazilian Electricity Regulatory Agency (Agência Nacional de Energia Elétrica - ANEEL), and takes into consideration changes in the estimated cash flow, mainly based on factors such as new replacement price, and adjustment for Extended Comprehensive Consumer Price Index (“IPCA”) for the distribution subsidiaries. The financial asset of distribution companies is classified as available-for-sale, with the corresponding cash flow changes entry in the Net Operating Revenue in the statement of profit or loss for the year (notes 4 and 25).

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

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

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

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

 

3.3 Financial instruments

- Financial assets

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

 i.      Fair value through profit or loss: these are assets held for trading or designated as such upon initial recognition. The Group manages such assets and make purchase and sale decisions based on their fair value in accordance with their documented risk management and investment strategy. These financial assets are measured at fair value, and changes therein are recognized in profit or loss for the year.

ii.      Held-to-maturity: these are assets that the Group has the positive intent and ability to hold to maturity. Held-to-maturity financial assets are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method, less any impairment losses.

iii.     Loans and receivables: these are assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method, less any impairment losses.

iv.      Available-for-sale: these are non-derivative financial assets that are designated as available-for-sale or that are not classified into any of the previous categories. Subsequent to initial recognition, interest calculated using the effective interest method is recognized in the statement of profit or loss as part of the Net Operating  Revenue for the variations on the expected cash flows of distribution companies, and changes in fair value of these financial assets are recognized in other comprehensive income. The accumulated result in other comprehensive income is transferred to profit or loss when the asset is realized.

- Financial liabilities

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Financial liabilities are initially recognized on the date that they are originated or on the trade date at which the Company or its subsidiaries become a party to the contractual provisions of the instrument. The Group has the following main financial liabilities:

 i.      Measured at fair value through profit or loss: these are financial liabilities that are: (i) held for short-term trading, (ii) designated at fair value in order to match the effects of recognition of income and expenses to obtain more relevant and consistent accounting information, or (iii) derivatives. These liabilities are measured at fair value and any change in their fair value is subsequently recognized in profit or loss.

ii.      Other financial liabilities (not measured at fair value through profit or loss): these are other financial liabilities not classified into the previous category. They are measured initially at fair value net of any cost attributable to the transaction and subsequently measured at amortized cost using the effective interest rate method.

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

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

The classifications of financial instruments are described in note 33.

- Capital

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

 

3.4 Property, plant and equipment

Items of property, plant and equipment are measured at acquisition, construction or formation cost less accumulated depreciation and, if applicable, accumulated impairment losses. Cost also includes any other costs attributable to bringing the assets to the place and in a condition to operate as intended by Management, the cost of dismantling and restoring the site on which they are located and capitalized borrowing costs on qualifying assets.

The replacement cost of items of property, plant and equipment is recognized if it is probable that it will involve economic benefits for the subsidiaries and if the cost can be reliably measured, and the value of the replaced item is written off. Maintenance costs are recognized in profit or loss as they are incurred.

Depreciation is calculated on a straight-line basis, at annual rates of 2% to 20%, taking into consideration the estimated useful life of the assets, as instructed and defined by the granting authority.

Gains and losses on disposal/ write-off of an item of property, plant and equipment are determined by comparing the proceeds from disposal with the carrying amount of the asset, and are recognized net within other operating income/expenses.

Assets and facilities used in the regulated activities are tied to these services and may not be removed, disposed of, assigned or pledged in mortgage without the prior and express authorization of ANEEL. ANEEL, through Resolution No. 20 of February 3, 1999, amended by Normative Resolution No. 691 of December 8, 2015, releases Public Electric Energy Utility concessionaires from prior authorization for release of assets of no use to the concession, but determines that the proceeds from the disposal be deposited in a restricted bank account for use in the concession.

 

3.5 Intangible assets

Includes rights related to non-physical assets such as goodwill and concession exploration rights, software and rights-of-way.

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

- Non-financial assets

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

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

The assets (e.g. goodwill, concession intangible asset) are segregated and grouped together at the lowest level that generates identifiable cash inflows (the "cash generating unit", or “CGU”). If there is an indication of impairment, the loss is recognized in profit or loss. Except in the case of goodwill impairment, which cannot be reversed in the subsequent period, impairment losses are reassessed annually for triggering events that would lead to possibility of reversals.

3.7 Provisions

A provision is recognized if, as a result of a past event, there is a legal or constructive obligation that can be estimated reliably, and it is probable (more likely than not) that an outflow of economic benefits will be required to settle the obligation. When applicable, provisions are determined by discounting the expected future cash outflows at a rate that reflects current market assessment and the risks specific to the liability. The unwinding of the discount is recognized as finance cost.

 

3.8 Employee benefits

Certain subsidiaries have post-employment benefits and pension plans, recognized in accordance with IAS 19 “Employee benefits” (as revised 2011), and are regarded as Sponsors of these plans. Although the plans have particularities, they have the following characteristics:

 i.       Defined contribution plan: a post-employment benefit plan under which the Sponsor pays fixed contributions into a separate entity and will have no liability for the actuarial deficits of the plan. The obligations are recognized as an expense in the statement of profit or loss in the periods during which the services are rendered.

ii.       Defined benefit plan: The net obligation is calculated as the difference between the present value of the actuarial obligation based on assumptions, biometric studies and interest rates in line with market rates, and the fair value of the plan assets as of the reporting date. The actuarial liability is calculated annually by independent actuaries, under the responsibility of Management, using the projected unit credit method. Actuarial gains and losses are recognized in other comprehensive income when they occur. Net Interest (income or expense) is calculated by applying the discount rate at the beginning of the period to the net amount of the defined benefit asset or liability. When applicable, the cost of past services is recognized immediately in profit or loss.

If the plan records a surplus and it becomes necessary to recognize an asset, the recognition is limited to the present value of future economic benefits available in the form of reimbursements or future reductions in contributions to the plan.

 

3.9 Dividends and Interest on capital

Under Brazilian law, the Company is required to distribute a mandatory minimum annual dividend of 25% of profit adjusted in accordance with the Company´s bylaws. In conformity with IAS 10 a provision may only be made for the minimum mandatory dividend, and dividends declared but not yet approved are only recognized as a liability in the financial statements after approval by the competent body. According to Law 6,404/76, they will therefore be held in equity, in the “additional dividend proposed” account, as they do not meet the present obligation criteria at the reporting date.

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

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

 

3.10 Revenue recognition

The operating revenue in the normal course of the subsidiaries’ activities is measured at the fair value of the consideration received or receivable. The operating revenue is recognized when there is persuasive evidence that all significant risks and rewards were transferred to the buyer, it is probable that future economic benefits will flow to the entity, the associated costs can be reliably measured, and the amount of the operating revenue can be reliably measured.

The revenue from electric energy distribution is recognized when the energy is supplied. The energy distribution subsidiaries perform the reading of their customers based on a reading routine (calendar and reading route) and invoice monthly the consumption of MWh based on the reading performed for each consumer. As a result, part of the energy distributed during the month is not billed at the end of the month and, consequently, an estimate is developed by Management and recorded as “Unbilled”. This unbilled revenue estimate is calculated using as a base the total volume of energy of each distributor made available in the month and the annualized rate of technical and commercial losses. The revenue from energy generation sales is recognized based on the assured energy and at tariffs specified in the terms of the supply contracts or the current market price, as appropriate. The revenue from energy trading is recognized based on bilateral contracts with market agents and properly registered with the Electric Energy Trading Chamber – CCEE. No single consumer accounts for 10% or more of the Company’s total revenue.

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

The revenue from construction contracts is recognized based on the percentage of completion method, and losses, if any, are recognized the statement of profit or loss as incurred.

 

3.11 Income tax and social contribution

Income tax and social contribution expenses are calculated and recognized in accordance with the legislation in force and comprise current and deferred taxes. Income tax and social contribution are recognized in the statement of profit or loss except to the extent that they relate to items recognized directly in equity or other comprehensive income, when the net amounts of these tax effects are already recognized, and those arising from the initial recognition in business combinations.

Current taxes are the expected taxes payable or receivable/recoverable on the taxable profit or loss. Deferred taxes are recognized for temporary differences between the carrying amounts of assets and liabilities for accounting purposes and the equivalent amounts used for tax purposes and for tax loss carryforwards.

The Company and certain subsidiaries recognize in their financial statements the effects of tax loss carryforwards and deductible temporary differences, based on projections of future taxable profits, approved annually by the Boards of Directors and examined by the Fiscal Council. The subsidiaries also recognized tax credits relating to the tax benefits created by the corporate restructuring, which are amortized on a straight line basis for the remaining period of each concession agreement.

Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to taxes levied by the same tax authority on the same taxable entity.

Deferred income tax and social contribution assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related taxes benefit will be realized.

 

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3.12 Earnings per share

Basic earnings per share are calculated by dividing the profit or loss for the year attributable to the Company’s controlling shareholders by the weighted average number of shares outstanding during the year. Diluted earnings per share are calculated by dividing the profit or loss for the year attributable to the controlling shareholders, adjusted by the effects of instruments that potentially would have impacted the profit or loss for the year by the weighted average of the number of shares outstanding, adjusted by the effects of all dilutive potential convertible notes for the reporting periods.

 

3.13 Government grants – CDE (Energy Development Account)

Government grants are only recognized when it is reasonably certain that these amounts will be received by the Group. They are recognized in profit or loss for the periods in which the Company recognizes as income the discounts granted in relation to the low-income subsidy and other tariff discounts.

The subsidies received through funds from the CDE (note 25) have the main purpose of offsetting discounts granted in order to provide immediate financial support to the distribution companies.

 

3.14 Sector financial asset and liability

According to the tariff pricing mechanism applicable to distribution companies, the energy tariffs should be set at a price level (price cap) that ensures the economic and financial equilibrium of the concession, therefore, the concessionaires and licensees are authorized to charge their consumers (after review and ratification by ANEEL) for: (i) the annual tariff increase; and (ii) every four or five years, according to each concession agreement, the periodic review for purposes of reconciliation of part of Parcel B (controllable costs) and adjustment of Parcel A (non-controllable costs).

The distributors' revenue is mainly comprised of the sale of electric energy and for the delivery (transport) of the electric energy via the distribution infrastructure (network). The distribution concessionaires' revenue is affected by the volume of energy delivered and the tariff. The electric energy tariff is comprised of two parcels which reflect a breakdown of the revenue:

·  Parcel A (non-controllable costs): this parcel should be neutral in relation to the entity's performance, i.e., the costs incurred by the distributors, classifiable as “Parcel A”, are fully passed through the consumer or borne by the granting authority ; and

·  Parcel B (controllable costs) – comprised of capital expenditure on investments in infrastructure, operational costs and maintenance and remuneration to the providers of capital. It is this parcel that actually affects the entity's performance, since it has no guarantee of tariff neutrality and thus involves an intrinsic business risk.

This tariff pricing mechanism can cause temporary differences arising from the difference between the budgeted costs (Parcel A and other financial components) included in the tariff at the beginning of the tariff period and those actually incurred while it is in effect. This difference constitutes a right of the concessionaire to receive cash when the budgeted costs included in the tariff are lower than those actually incurred, or an obligation to pay if the budgeted costs are higher than those actually incurred.

 

3.15 Business combination

Business combinations are accounted for by applying the acquisition method. The consideration transferred in a business combination is measured at fair value, calculated as the sum of the fair values of the assets transferred by the acquirer, the liabilities incurred and the equity interests issued by the Company and subsidiaries in exchange for control of the acquiree. Costs related to the acquisition are generally recognized in profit or loss, when incurred.

At the acquisition date, assets and liabilities are recognized at fair value, except for: (i) deferred taxes, (ii) employee benefits and (iii) equity instruments.

The noncontrolling interests are initially measured either at fair value or at the noncontrolling interests’ proportionate share of the acquiree’s identifiable net assets. The measurement method is chosen on a transaction-by-transaction basis.

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The excess of the consideration transferred, added to the portion of noncontrolling interests, over the fair value of the identifiable assets (including the concession intangible asset) and net liabilities assumed at the acquisition date are recognized as goodwill. In the event that the fair value of the identifiable assets and net liabilities assumed exceeds the consideration transferred, a bargain purchase is identified and the gain is recognized in the statement of profit or loss at the acquisition date.

 

3.16 Basis of consolidation

(i) Business combinations

The Company measures goodwill as the fair value of the consideration transferred including the recognized amount of any noncontrolling interest in the acquiree, less the recognized fair value of the identifiable assets acquired and liabilities assumed, all measured at the acquisition date.

(ii) Subsidiaries and joint ventures

The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. Joint ventures are accounted for using the equity method of accounting from the moment joint control is established.

The accounting policies of subsidiaries and joint ventures taken into consideration for purposes of consolidation and/or equity method of accounting, as applicable, are aligned with the Company's accounting policies.

The consolidated financial statements include the balances and transactions of the Company and its subsidiaries. The balances and transactions of assets, liabilities, income and expenses have been fully consolidated for the subsidiaries.

Intragroup balances and transactions, and any income and expenses derived from these transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity accounted investees are eliminated against the investment to the extent of the Company’s interest in the investee. Unrealized losses are eliminated in the same way as unrealized gains, but only to the extent that there is no evidence of impairment.

In the case of subsidiaries, the portion related to noncontrolling interests is stated in equity and in the statements of profit or loss and comprehensive income in each period presented.

The balances of joint ventures, as well as the Company’s interest in each of them are described in note 12.2.

(iii) Acquisition of noncontrolling interests

Accounted for as transaction among shareholders. Consequently, no asset or goodwill is recognized as a result of such transaction.

 

3.17 New standards and interpretations issued and effective

A number of IASB standards were issued or revised and are mandatory for accounting periods beginning on January 1, 2017:

a)   Amendments to IAS 12 – Recognition of deferred tax assets for unrealized losses

Issued on January 19, 2016, the amendments to IAS 12 clarify the requirements of recognition of deferred tax assets for unrealized losses on debt instruments and the method to assess whether taxable profits will be available against which the entity can utilize a deductible temporary difference, to address the diversity in practice.

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

b)   Amendments to IAS 7 – Statement of Cash Flows

Issued on January 29, 2016, the amendments to IAS 7 Disclosure Initiative require an entity to provide disclosures that enable users of financial statements to evaluate changes in liabilities arising from financing activities.

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

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c)   Annual Improvements to IFRS / 2014 – 2016 Cycle

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

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

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

 

3.18 New standards and interpretations issued but not yet effective

A number of new IFRS standards and amendments to the standards and interpretations were issued by the IASB and had not yet come into effect for annual periods beginning on January 1, 2017. Consequently, the Company has not early adopted them:

a) IFRS 9 - Financial instruments

IFRS 9 is effective for the financial statements of an entity prepared in accordance with IFRS for annual periods beginning on or after January 1, 2018.

This standard establishes new requirements for classification and measurement of financial assets and liabilities. Financial assets are classified into three categories: (i) measured at fair value through profit or loss; (ii) measured at amortized cost, based on the business model within which they are held and the characteristics of their contractual cash flows; and; (iii) measured at fair value through other comprehensive income.

With regard to financial liabilities, the main alteration in relation to the requirements already set by IAS 39 requires any change in fair value of a financial liability designated at fair value through profit or loss attributable to changes in the liability's credit risk to be stated in other comprehensive income and not in the statement of profit or loss.

In relation to the impairment of financial assets, IFRS 9 requires an expected credit loss model, as opposed to an incurred credit loss under IAS 39. The expected credit loss model requires an entity to account for expected credit losses and changes in those expected credit losses at each reporting date to reflect changes in credit risk since initial recognition. In other words, it is no longer necessary for a default event to have occurred before credit losses are recognized.

Regarding the modifications related to hedge accounting, IFRS 9 retains three types of hedge accounting mechanisms currently available in IAS 39. Under IFRS 9, greater flexibility has been introduced to the types of risks components of non-financial items that are eligible for hedge accounting. In addition, the effectiveness test has been overhauled and replaced with the principle of an “economic relationship”. Retrospective assessment of hedge effectiveness is also no longer required. Enhanced disclosure requirements about an entity’s risk management have also been introduced.

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

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

Moreover, as the Group do not apply hedge accounting, Management concluded that there will not be material impact on the information disclosed or amounts recorded in its consolidated financial statements as a result of the amendments to standard. 

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

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

 

b) IFRS 15 - Revenue from contracts with customers

IFRS 15 provides a straightforward model for accounting for contracts with customers and it will supersede the current guide for revenue recognition provided in IAS 18 – Revenue and IAS 11 - Construction contracts and related interpretations.

The standard establishes that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard introduces a five-step model for revenue recognition: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract and (v) recognize revenue when (or as) the entity satisfies a performance obligation.

Under IFRS 15, an entity recognizes revenue when (or as) the entity satisfies a performance obligation, i.e., when the "control" over the goods and services in a certain operation is transferred to the customer, and will establish a greater level of detail in the disclosures.

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

 

c) IFRS 16 Leases

Issued on January 13, 2016, establishes, in the lessee’s view, a new form for accounting for leases currently classified as operating leases, which are now recognized similarly to leases classified as finance leases. As regards the lessors, it virtually retains the requirements of IAS 17, including only some additional disclosure aspects.

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

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(a)   Current account balances, which earn daily interest by investment in repurchase agreements secured on Bank Certificate Deposit (CDB) and interest of 15% of the variation in the Interbank Certificate of Deposit (CDI).

(b)  Short-term investments in Bank Certificates of Deposit (CDB) and repurchase agreements secured on debentures with major financial institutions that operate in the Brazilian financial market, with daily liquidity, short-term due, low credit risk and interest equivalent, on average, to 101.87% of the CDI.

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

 

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

 

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The maturities of the debentures recognized in noncurrent liabilities are scheduled as follows:

 

 

 

Main debentures issuances during the year

 

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Pre-payment

 

6th issue - CPFL Paulista, CPFL Piratininga and RGE – At 2017, R$ 1,060,538 were paid of the 6th issue of debentures of the subsidiaries CPFL Paulista (R$ 681,279), CPFL Piratininga (R$ 67,610) and RGE (R$ 311,649), whose due date were July 2017 to July 2019.

 

5th issue of debentures - CPFL Energia – At 2017, R$ 460,194 of the Company’s 5th issue of debentures, with original maturities in October 2019 and 2020, were settled.

 

RESTRICTIVE COVENANTS

The debentures are subject to certain restrictive covenants, which include clauses that require the Company and its subsidiaries to maintain certain financial ratios within pre-established parameters. Moreover, these agreements contain restrictive non-financial covenants, which are complied with as per the last  measurement period.

 

CPFL Energia, CPFL Paulista, CPFL Piratininga, RGE, RGE Sul, CPFL Geração, CPFL Brasil, Companhia Jaguari de Energia (“CPFL Santa Cruz”)

Maintaining, by the Company, of the following ratios:

·      Net indebtedness divided by EBITDA – maximum of 3.75;

·      EBITDA divided by Finance Income (Costs) - minimum of 2.25;

For purposes of determination of covenants, the definition of EBITDA, in the Company, takes into consideration the consolidation of subsidiaries, associates and joint ventures based on the Company’s interest in those companies (for EBITDA and assets and liabilities).

CPFL Renováveis

The issues of debentures for the year ended December 31, 2017 contain clauses that require the subsidiary CPFL Renováveis to maintain the following financial ratios:

- 1^st issue of CPFL Renováveis

·      Operating debt service coverage ratio - minimum of 1.00;

·      Debt service coverage ratio - minimum of 1.05;

·      Net indebtedness divided by EBITDA - maximum of 5.4 in 2016, 4.6 in 2017, 4.0 in 2018 and 2019 and 3.75 from 2020;

·      EBITDA divided by Net finance costs - minimum of 1.75.

As at December 31, 2017, the subsidiary obtained approval from debenture holders for not comply with the following ratios:

(i)   Operating DSCR relating to the June 2017 calculation, through the General Meeting of Debenture Holders held on June 28, 2017;

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The plan currently in force for the employees of the subsidiary CPFL Paulista through Fundação CESP is a Mixed Benefit Plan, with the following characteristics:

i.        Defined Benefit Plan (“BD”) – in force until October 31, 1997 – a defined benefit plan, which grants a Proportional Supplementary Defined Benefit (“BSPS”), in the form of a lifetime income convertible into a pension, to participants enrolled prior to October 31, 1997, the amount being defined in proportion to the accumulated past service time up to that date, based on compliance with the regulatory requirements for granting. The total responsibility for coverage of actuarial deficits of this plan falls to the subsidiary.

ii.        Mixed model, as from November 1, 1997, which covers:

·      benefits for risk (disability and death), under a defined benefit plan, in which the subsidiary assumes responsibility for Plan’s actuarial deficit, and

·      scheduled retirement, under a variable contribution plan, consisting of a benefit plan, which is a defined contribution plan up to the granting of the income, and does not generate any actuarial liability for the subsidiary CPFL Paulista. The benefit plan only becomes a defined benefit plan, consequently generating actuarial responsibility for the subsidiary, after the granting of a lifetime income, convertible or not into a pension.

Additionally, the subsidiary’s Managers may opt for a Free Benefit Generator Plan – “PGBL” (defined contribution), operated by either Banco do Brasil or Bradesco.

 

CPFL Piratininga

As a result of the spin-off of Bandeirante Energia S.A. (subsidiary’s predecessor), the subsidiary CPFL Piratininga assumed the responsibility for the actuarial liabilities of that company’s employees retired and terminated until the date of spin-off, as well as for the obligations relating to the active employees transferred to CPFL Piratininga.

On April 2, 1998, the Secretariat of Pension Plans – “SPC” approved the restructuring of the retirement plan previously maintained by Bandeirante, creating a "Proportional Supplementary Defined Benefit Plan – BSPS”, and a "Mixed Benefit Plan", with the following characteristics:

i.         Defined Benefit Plan (“BD”) - in force until March 31, 1998 – a defined benefit plan, which grants a Proportional Supplementary Defined Benefit (BSPS), in the form of a lifetime income convertible into a pension to participants enrolled until March 31, 1998, in an amount calculated in proportion to the accumulated past service time up to that date, based on compliance with the regulatory requirements for granting. In the event of death while working or the onset of a disability, the benefits incorporate the entire past service time. CPFL Piratininga has full responsibility for covering the actuarial deficits of this Plan.

ii.        Defined Benefit Plan - in force after March 31, 1998 – defined-benefit type plan, which grants a lifetime income convertible into a pension based on the past service time accumulated after March 31, 1998, based on 70% of the average actual monthly salary for the last 36 months of active service. In the event of death while working or the onset of a disability, the benefits incorporate the entire past service time. The responsibility for covering the actuarial deficits of this Plan is equally divided between CPFL Piratininga and the participants.

iii.      Variable Contribution Plan – implemented together with the Defined Benefit plan effective after March 31, 1998. This is a defined contribution type pension plan up to the granting of the income, and generates no actuarial liability for CPFL Piratininga. The pension plan only becomes a Defined Benefit type plan after the granting of the lifetime income, convertible (or not) into a pension, and accordingly starts to generate actuarial liabilities for the subsidiary.

Additionally, the subsidiary’s Managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Bradesco.

 

RGE

A defined benefit type plan, with a benefit level equal to 100% of the adjusted average of the most recent salaries, less the presumed Social Security benefit, contribution with a Segregated Net Asset managed by Fundação CEEE. Only those whose employment contracts were transferred from CEEE to RGE are entitled to this benefit. A defined contribution private pension plan was set up in January 2006 with Bradesco Vida e Previdência for employees hired from 1997.

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RGE Sul

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

 

Companhia Jaguari de Energia (“CPFL Santa Cruz”)

Until December 31, 2017, the subsidiaries Companhia Leste Paulista de Energia, Companhia Jaguari de Energia, Companhia Sul Paulista de Energia and Companhia Luz e Força de Mococa  had a private pension plan named CMSPREV, managed by IHPREV Fundo de Pensão, and subsidiary Companhia Luz e Força Santa Cruz had a benefits plan managed by BB Previdência - Fundo de Pensão from Banco do Brasil, both majority structured as a defined contribution plan.

After December 31, 2017, with the grouping event mentioned in note 14.4.2, the company’s official plan is the CMSPREV, managed by IHPREV Fundo de Pensão. The same plan was maintained for employees that had the benefits plan managed by BB Previdência - Fundo de Pensão from Banco do Brasil.

 

CPFL Geração

The employees of the subsidiary CPFL Geração participate in the same pension plan as CPFL Paulista.

In addition, managers may opt for a Free Benefit Generator Plan – PGBL (defined contribution), operated by either Banco do Brasil or Bradesco.

 

 

 

 

18.2 – Changes in the defined benefit plans

 

 

 

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18.3 Changes in the recognized assets and liabilities

The changes in net liability are as follows:

 

 

 

 

 

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Tariff discounts – CDE: refers to the difference between the tariff discount granted to consumers and the amounts received via the CDE.

Profit sharing: mainly comprised by:

(i)   in accordance with a collective labor agreement, the Group introduced an employee profit-sharing program, based on the achievement of operating and financial targets previously established;

(ii)  Long-Term Incentive Program: refers to the Long-Term Incentive Plan for the Group’s Executives, approved by the Board of Directors, which consists in an incentive in financial resources based on salary multiples and that are driven by the company’s results and average performance in the three fiscal years after each concession.

 

The shareholders’ interest in the Company’s equity at December 31, 2017 and 2016 is shown below:

 

On January 23, 2017, the Company received a correspondence from State Grid Brazil Power Participações S.A.. (“State Grid Brazil”) informing that on that date the Share Purchase Agreement between State Grid Brazil, Camargo Corrêa S.A., Caixa de Previdência dos Funcionários do Banco do Brasil – PREVI, Fundação CESP, Fundação Sistel de Seguridade Social, Fundação Petrobras de Seguridade Social – PETROS, Fundação SABESP de Seguridade Social — SABESPREV, and certain other parties, had been signed.

After finalizing the transaction, State Grid Brazil became the parent company of CPFL Energia with 54.64% (556,164,817 shares, direct or indirect) of the Company’s voting and total capital. With the transaction, State Grid Brazil became the only controlling shareholder of the Company, and the Shareholders’ Agreement dated March 22, 2002 signed among the former shareholders was terminated.

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At the Company’s extraordinary general meeting held on March 27, 2017, the following resolutions were made (i) the selection of Credit Suisse (Brasil) S.A. to determine the Company’s economic value; (ii) the cancelation of the Company’s listing with the CVM as category “A”, and its conversion into category “B”; and (iii) withdrawal of the Company from the Listing Segment of Novo Mercado.

State Grid Brazil informed, through Significant Events:

(i)   on February 16, 2017, that it would conduct a public offering for acquisition of all the common shares held by the remaining shareholders of the Company (“Public Offering for Acquisition of Shares through Sale of Control”) and, on July 7, 2017, that it had decided to proceed only with the Public Offering for Acquisition of Shares through sale of control of the Company and through indirect sale of control of CPFL Renováveis;

(i)   on October 30 and 31, 2017, that CVM had formally approved all relevant documents and the proceeding with the Public Offering for Acquisition of Shares through Sale of Control and, as a result of the approval, State Grid Brazil published on October 31, 2017 the Public Offering Notice with the related terms and conditions.

In a Significant Event Notice and Communication to the Market on November 30 and December 5, 2017, respectively, the Company informed that it had successfully conducted the public offering auction on the trading system of B3 S.A.– Brasil, Bolsa, Balcão (“Auction”). As a result of the auction, State Grid Brazil acquired 408,357,085 common shares of the Company, representing 88.44% of the total shares object of the Public Offering and 40.12% of the Company’s capital. The common shares were acquired for the price of R$ 27.69, totaling R$ 11,307,408. State Grid Brazil started holding, jointly with ESC Energia S.A., 964,521,902 common shares of the Company, increasing its joint interest from 54.64% to 94.75% of the Company’s total capital.

 

23.2        Capital reserves

Refer basically to: (i) R$ 228,322 related to the CPFL Renováveis business combination in 2011, (ii) effect of the public offer of shares, in 2013, of the subsidiary CPFL Renováveis amounting to R$ 59,308, as a result of the reduction of the indirect interest in CPFL Renováveis, (iii) effect of the acquisition of DESA, amounting to R$ 180,297 in 2014, and (iv) other movements with no change of control amounting to R$87. In accordance with IFRS 10, these effects were recognized as transactions between shareholders, directly in Equity.

 

23.3        Earnings reserves

Comprised of:

i.      Legal reserve, amounting to R$ 798,090;

ii.   Statutory reserve – concession financial asset: the distribution subsidiaries recognize in profit or loss the adjustment to the expected cash flow from the concession financial asset, however its financial realization will occur only upon the write-off of the concession financial asset arising from disposal or corporate restructuring or upon the indemnity (at the end of the concession). As result, the Company recognizes a statutory reserve – concession financial asset for these amounts, supported by article 194 of Law No. 6,404/76, until their financial realization. This statutory reserve amounts to R$826,601 (R$ 702,928 at December 31, 2016).

 

23.4        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$ 405,840;

ii.    Private pension plan: The debt balance of R$ 570,346 (net of taxes) refers to the effects of the actuarial gains and losses recognized directly in other comprehensive income, in accordance with IAS 19.

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23.5        Dividends

At the Board of Directors’ Meeting held on January 5, 2017, approval was given for the declaration of interim dividend for 2016 in the amount of R$ 7,820.

Furthermore, in 2017 the Company proposed R$ 280,191 of minimum mandatory dividend, as set forth by Law 6,404/76, and for each share the amount of R$ 0.275259517 was attributed.

In 2017, the Company paid R$ 220,966 relating basically to the dividend for 2016.

 

23.6        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:

 

 

For this year, considering the current macro scenario with the incipient economic recovery and, also considering the uncertainties regarding the hydrology, the Company’s management is proposing the allocation of R$746,541 to the statutory reserve - working capital reinforcement.

 

23.7        Noncontrolling interests and joint ventures

The disclosure of interests in subsidiaries, in accordance with IFRS 12, is as follows:

 

23.7.1         Changes in noncontrolling interests

 

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23.7.2         Summarized financial information of subsidiaries that have interests of noncontrolling shareholders

The summarized financial information on subsidiaries in which there is noncontrolling interests at December 31, 2017 and 2016, and for the years ended December 31, 2017, 2016 and 2015 are as follows:

 

 

 

 

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25.1        Adjustment of revenues from excess demand and excess reactive power

The tariff regulation procedure (“Proret”), in submodule 2.7 Other Revenues approved by ANEEL Normative Resolution No. 463 of November 22, 2011, determined that revenues from distribution subsidiaries received as a result of excess demand and excess reactive power, from the contractual tariff review date for the 3rd periodic tariff review cycle, should be accounted for as special obligations and would be amortized from the next tariff review. Beginining May 2015 for subsidiary CPFL Piratininga and September 2015 for subsidiary Companhia Jaguari de Energia (“CPFL Santa Cruz”), due to the 4^th cycle of periodic tariff review, and November 2017 for CPFL Paulista and RGE Sul, this special obligation started being amortized and the new values from excess demand and excess reactive power started being recognized in sector financial assets and liabilities and will only be amortized when the 5^th cycle of periodic tariff review is approved.

On February 7, 2012, the Brazilian Association of Electric Energy Distributors (Associação Brasileira de Distribuidores de Energia Elétrica - ABRADEE) succeeded in suspending the effects of Normative Resolution No. 463, whereby the request for preliminary judicial injunction relief was granted and the order to account for revenues from excess demand and excess reactive power as special obligations was suspended. The suspensive effect required by ANEEL in its interlocutory appeal was granted in June 2012 and the preliminary judicial injunction relief originally granted in favor of ABRADEE was suspended. The distribution subsidiaries are awaiting the court’s decision on the final treatment of these revenues. These amounts are accrued as sector financial liability, under special obligations which are being amortized, presented net in concession intangible asset, in compliance with IAS 37.

 

 

 

25.2 Extraordinary Tariff Review (“RTE”) – 2015

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

The average effects for the distributors’ consumers were:

 

(*) Information not audited by the independent auditors

 

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Indirect subsidiary of State Grid Corporation of China, a Chinese state-owned company primarily engaged in developing and operating businesses in the electric energy sector.

·        ESC Energia S.A.

Subsidiary of State Grid Brazil Power Participações S.A.

The direct and indirect interest in operating subsidiaries are described in note 1.

Controlling shareholders, associates companies, joint ventures and entities under common control that in some way exercise significant influence over the Company are considered to be related parties.

The main transactions are listed below:

a)         Purchase and sale of energy and charges - refer basically to energy purchased or sold by distribution, commercialization and generation subsidiaries through short or long-term agreements and tariffs for the use of the distribution system (TUSD). Such transactions, when conducted in the free market, are carried out under conditions considered by the Company as similar to market conditions at the time of the trading, according to internal policies previously established by the Company’s management. When conducted in the regulated market, the prices charged are set through mechanisms established by the Grant Authority.

b)         Intangible assets, Property, plant and equipment, Materials and Service – refer to the purchase of equipment, cables and other materials for use in distribution and generation activities and contracting of services such as construction and information technology consultancy.

c)         Advances – refer to advances for investments in research and development.

d)         Intragroup loans – refer mainly to contracts with the noncontrolling shareholder of the subsidiary CPFL Renováveis, with maturity defined for the date of distribution of earnings of the indirect subsidiary to its shareholders and remuneration of 8% p.a. + IGP-M.

To ensure that commercial transactions with related parties are conducted under usual market conditions, the Company set up a “Related Parties Committee”, comprising representatives of the controlling shareholders, responsible for analyzing the main transactions with related parties.

The subsidiaries CPFL Paulista and CPFL Piratininga renegotiated with the subsidiary Ceran the extension of the original maturities of the energy purchase bills, previously from 15 November 2017 and 15 December 2017, to January 2018.

The total compensation of key management personnel in 2017was R$ 73,670 (R$ 58,132 in 2016 and R$ 43,208 in 2015). This amount comprises R$64,516 (R$49,989 in 2016 and R$ 44,061 in 2015) in respect of short-term benefits, R$1,516 (R$1,212 in 2016 and R$ 1,087 in 2015) of post-employment benefits and a provision of R$7,638 (R$ 6,930 in 2016 and reversal of provision of R$ 1,940 in 2015) for other long-term benefits, and refers to the amount recognized on an accrual basis.

Transactions with entities under common control basically refer to transmission system charge paid by the Company’s subsidiaries to the direct or indirect subsidiaries of State Grid Corporation of China.

Transactions between related parties involving controlling shareholders, entities under common control or with significant influence and joint ventures are as follows:

 

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The Board of Directors of CPFL Energia is responsible for deciding on the risk limit methodologies recommended by the Executive Board, and for being aware of the exposures and mitigation plans presented in the event these limits are exceeded. This forum is also responsible for being aware of and monitoring any important weaknesses in controls and/or processes, as well as relevant regulatory compliance failures, following up on the plans proposed by the Executive Board to correct them.

The Advisory Committee(s) of the Board of Directors, in its role(s) of technical body(ies), is responsible for becoming aware of (i) the risk monitoring models, (ii) the exposures to risks, and (iii) the control levels (including their effectiveness), supporting the Board of Directors in the performance of its statutory role related to risk management.

The Supervisory Board of CPFL Energia is responsible for, among other things, certifying that Management has means to identify the risks on the preparation and disclosure of the financial statements to which the CPFL Group is exposed as well as for monitoring the effectiveness of the control environment.

The Executive Board of CPFL Energia is responsible for conducting businesses within the risk limits defined, and should take the required measures to avoid that the exposure to risks exceeds such limits and report any excess of the limit to the Board of Directors of CPFL Energia, presenting mitigation actions.

The Internal Audit and Corporate Risks Management is responsible for coordinating the risk management process at CPFL Group, developing and keeping up-to-date Corporate Risk Management methodologies that involve the identification, measurement, monitoring and reporting of risks to which the CPFL Group is exposed.

The business areas have the primary responsibility for the management of the risks inherent to its processes, and should conduct them within the exposure limits defined and implementing mitigation plans for the main exposures.

The main market risk factors that affect the businesses are as follows:

Foreign exchange risk: This risk derives from the possibility of the Group incurring losses and cash constraints due to fluctuations in exchange rates, increasing the balances of liabilities denominated in foreign currency or decreasing the portion of revenue arising from annual adjustment of part of the tariff based on the fluctuation of the dollar, in power sale agreements of the joint venture ENERCAN. The exposure related to funding in foreign currency is hedged by swap transactions. The exposure related to ENERCAN revenue, proportional to the interest held by the Company, is hedged by financial instruments such as the zero cost collar described in note 33.b.1. The quantification of these risks is presented in note 33. In addition, the subsidiaries are exposed in their operating activities to fluctuations in exchange rates on purchase of electricity from Itaipu. The compensation mechanism - CVA protects the distribution subsidiaries against any economic losses.

Interest rate risk and inflation indexes: This risk arises due to the possibility of the Group incurring losses due to fluctuations in interest rates and in inflation indexes, which would increase the finance costs related to borrowings and debentures. The quantification of this risk is presented in note 33.

Credit risk: This risk arises from the possibility of the subsidiaries incurring losses resulting from difficulties in collecting amounts billed to customers. This risk is managed by the sales and services segments through norms and guidelines applied in terms of the approval, guarantees required and monitoring of the operations. In the distribution segment, even though it is highly pulverized, the risk is managed through monitoring of defaults, collection measures and cutting off supply. In the generation segment there are contracts under the regulated environment (ACR) and bilateral agreements that call for the posting of guarantees.

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As mentioned above, certain subsidiaries applied the fair value hedge to some of its financial instruments and as a result debts were marked to market (note 16).

The Group have recognized gains and losses on their derivatives. However, as these derivatives are used as a hedge, these gains and losses minimized the impact of variations in exchange and interest rates on the hedged debts. For the years 2017, 2016 and 2015, the derivatives resulted in the following impacts on the result, recognized in the line item of finance costs on adjustment for inflation and exchange rate changes:

 

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b.1) Zero-cost collar derivative contracted by CPFL Geração

In 2015, subsidiary CPFL Geração contracted US$ denominated put and call options, involving the same financial institution as counterpart, and which on a combined basis are characterized as an operation usually known as zero-cost collar. The contracting of this operation does not involve any kind of speculation, inasmuch as it is aimed at minimizing any negative impacts on future revenues of the joint venture ENERCAN, which has electric energy sale agreements with annual restatement of part of the tariff based on the variation in the US$. In addition, according to Management’s view, the scenario in 2015 was favorable for contracting this type of financial instrument, considering the high volatility implicit in dollar options and the fact that there is no initial cost for same.

The total amount contracted was US$ 111,817, with due dates between October 1, 2015 and September 30, 2020. As at December 31, 2017, the total amount contracted was US$ 65,197, considering the options already settled up to date. The exercise prices of the dollar options vary from R$ 4.20 to R$ 4.40 for the put options and from R$ 5.40 to R$ 7.50 for the call options.

These options have been measured at fair value in a recurring manner, as required by IAS 39. The fair value of the options that are part of this operation has been calculated based on the following premises:

 

The following table reconciles the opening and closing balances of the call and put options for the year ended December 31, 2017, as required by IFRS 13:

 

 

The fair value measurement of these financial instruments was recognized as finance income in the statement of profit or loss for the year, and no effects were recognized in other comprehensive income.

 

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c) Sensitivity Analysis

In compliance with IFRS 7, the Group performed sensitivity analyses of the main risks to which their financial instruments (including derivatives) are exposed, mainly comprising variations in exchange and interest rates, as shown below.

If the risk exposure is considered an asset, the risk to be taken into account is a reduction in the pegged indexes, resulting in a negative impact on the results of the Group. Similarly, if the risk exposure is considered a liability, the risk is of an increase in the pegged indexes and the consequent negative effect on the results. The Group therefore quantify the risks in terms of the net exposure of the variables (dollar, euro, CDI, IGP-M, IPCA, TJLP and SELIC), as shown below:

 

c.1) Exchange rate variation

Considering the level of net exchange rate exposure at December 31, 2017 is maintained, the simulation of the effects by type of financial instrument for three different scenarios would be:

 

 

 

(a) The exchange rates considered as of December 31, 2017 were R$ 3.31 per US$ 1.00 and R$ 3.97 per € 1.00.

(b)  As per the exchange curves obtained from information made available by B3 S.A., with the exchange rate being considered at R$ 3.46 and R$ 4.24, and exchange depreciation at 4.52% and 6.85%, for the US$ and €, respectively.

(c) As required by CVM Instruction 475/2008, the percentage increases in the ratios applied refer to the information made available by the B3 S.A..

(d) Owing to the characteristics of this derivative (zero-cost collar), the notional amount is presented in US$.

Except for the zero cost collar, based on the net exchange exposure in US$ and euro being an asset, the risk is a drop in the dollar and euro and, therefore, the local exchange rate is appreciated by 25% and 50% in relation to the probable exchange rate.

 

c.2) Interest rate variation

Assuming that (i) the scenario of net exposure of the financial instruments indexed to variable interest rates at December 31, 2017 is maintained, and (ii) the respective accumulated annual indexes for 2017 remain stable (CDI 6.89% p.a.; IGP-M -0.52% p.a.; TJLP 7.00% p.a.; IPCA 2.76% p.a. and SELIC 9.70% p.a.), the effects on the Company’s 2017 financial statements would be a net finance cost of R$ 764,150 (CDI R$ 669,661, TJLP R$276,141 and income of SELIC R$ 36,609, IGPM R$298 and IPCA R$ 141,152). In the event of fluctuations in the indexes in accordance with the three scenarios described below, the effect on net finance cost would as follows:

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(a) The CDI, IGP-M, TJLP, IPCA and SELIC indexes considered of 6.81%, 3.47%, 6.75%, 3.87% and 6.86%, respectively, were obtained from information available in the market.

(b) In compliance with CVM Instruction 475/08, the percentage of raise/drop of indexes were applied to Scenario I indexes.

 

d) Liquidity analysis

The Company manages liquidity risk by continuously monitoring forecast and actual cash flows, and by matching the maturity profiles of its financial liabilities. The table below sets out details of the contractual maturities of the financial liabilities at December 31, 2017, taking into account principal and future interest, and is based on the undiscounted cash flow, considering the earliest date on which the Group have to settle their respective obligations.

 

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The balances disclosed in the "Transactions resulting from business combination" lines refer to the complementary amounts related to the acquisition of RGE Sul, which was provisionally recorded at December 31, 2016, according to note 14.3.

 

36.1        Issue of debentures

In January 2018, subsidiaries issued simple non-convertible debentures with the following conditions and details:

 

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36.2        RGE and RGE Sul concession grouping

In March 2018, we requested ANEEL an application of requesting the grouping of the concessions of distributors RGE Sul and RGE in a single concession agreement, being RGE Sul the incorporating company and RGE the incorporated company. The implementation of the grouping of the concessions shall depend on ANEEL’s authorization, as well as on the deliberation and approval by the competent bodies of RGE Sul and RGE.

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Following is the information relating to CPFL Energia's unconsolidated condensed financial statements presented above:

a.     Cash and cash equivalents:

 

 

 

Amounts invested in an Investment funds, involving investments subject to floating rates tied to the CDI in federal government bonds, CDBs, secured debentures of major financial institutions, with daily liquidity, low credit risk and interest equivalent, on average, to 101% of CDI.

 

b.    Dividends and interest on equity:

 

 

(*) At December 31, 2017 the companies were group in Companhia Jaguari de Energia (note 14.4.2).

 

c.     Other receivables:

 

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