20-F 1 elpform20f_2020.htm FORM 20-F

As filed with the Securities and Exchange Commission on April 19, 2021 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 20-F

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

Commission file number: 001-14668

 

COMPANHIA PARANAENSE DE ENERGIA – COPEL

(Exact Name of Registrant as Specified in its Charter)

Energy Company of Paraná

(Translation of Registrant’s Name into English)

The Federative Republic of Brazil

(Jurisdiction of Incorporation or Organization)

 

Rua Coronel Dulcídio, 800

80420-170 Curitiba, Paraná, Brazil

(Address of Principal Executive Offices)

 

Daniel Pimentel Slaviero

+55 41 3331 4011 – ri@copel.com

Rua Coronel Dulcídio, 800, 3rd floor – 80420.170 Curitiba, Paraná, Brazil

(Name, telephone, e-mail and/or facsimile number and address of company contact person)

 

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Each Class

Trading Symbol(s)

Name of Each Exchange on Which Registered

Preferred Class B Shares, without par value* N/A New York Stock Exchange

American Depositary Shares (as evidenced by American Depositary Receipts),

each representing one Preferred Class B Share

ELP

New York Stock Exchange

 

       

 

* Not for trading, but only in connection with the listing of American Depositary Shares on the New York Stock Exchange.

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

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

Indicate the number of outstanding shares of each of the Issuer’s classes of capital or common stock as of December 31, 2020:

1,450,310,800 Common Shares, without par value*

3,267,520 Class A Preferred Shares, without par value*

1,282,975,430 Class B Preferred Shares, without par value*

 

* Does reflect the share split that occurred on March 11, 2021.

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

Yes [X] No [_]

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

Yes [_] No [X]

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

Yes [X] No [_]

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

N/A

 
 
 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and ”emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934. (Check one):

Large accelerated filer [X] Accelerated filer [_]

Non-accelerated filer [_] Emerging growth company [_]

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (§ 15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. [X]

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

U.S. GAAP [_] IFRS [X] Other [_]

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

N/A

 

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Yes [_] No [X]

 
 
 

Table of Contents

Presentation of Financial and Other Information 2
Forward-Looking Statements 3
Item 1. Identity of Directors, Senior Management and Advisers 3
Item 2. Offer Statistics and Expected Timetable 3
Item 3. Key Information 4
  Risk Factors 4
Item 4. Information on the Company 20
  The Company 20
  Business 24
  Concessions 47
  Competition 54
  Environment 55
  Plant, Property and Equipment 56
  The Expropriation Process 57
  The Brazilian Electric Power Industry 58
  Recent Developments 78
Item 4A. Unresolved Staff Comments 79
Item 5. Operating and Financial Review and Prospects 79
  Overview 80
  Critical Accounting Policies 84
  Analysis of Electricity Sales and Cost of Electricity Purchased 90
  Results of Operations for the Years Ended December 31, 2020, 2019 and 2018 91
  Liquidity and Capital Resources 98
Item 6. Directors, Senior Management and Employees 104
  Board of Directors 104
  Board of Executive Officers 107
  Supervisory Board 109
  Audit Committee 110
  Appointment and Evaluation Committee 111
  Investment and Innovation Comittee 112
  Compensation of Directors, Officers, Fiscal Council Members and Audit Committee Members 113
  Employees 114
  Share Ownership 116
Item 7. Major Shareholders and Related Party Transactions 117
  Major Shareholders 117
  Related Party Transactions 118
Item 8. Financial Information 119
  Legal Proceedings 120
  Dividend Payment 121
Item 9. The Offer and Listing 124
Item 10. Additional Information 125
  Memorandum and Articles of Association 125
  Material Contracts 130
  Exchange Controls 131
  Taxation 133
  Documents on Display 139
Item 11. Quantitative and Qualitative Disclosures about Market Risk 139
Item 12. Description of Securities Other than Equity Securities 139
Item 12A. Debt Securities 139
Item 12B. Warrants and Rights 139
Item 12C. Other Securities 139
Item 12D. American Depositary Shares 139
Item 13. Defaults, Dividend Arrearages and Delinquencies 140
Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds 140
Item 15. Control and Procedures 140
 
 
 
Item 16A. Audit Committee Financial Expert 143
Item 16B. Code of Ethics 143
Item 16C. Principal Accountant Fees and Services 143
Item 16D. Exemption from the Listing Standards for Audit Committees 144
Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers 144
Item 16F. Changes in Registrant’s Certifying Accountant 144
Item 16G. Corporate Governance 145
Item 17. Financial Statements 147
Item 18. Financial Statements 147
Item 19. Exhibits 147
Technical Glossary 149
Signatures 155

 

 
 
 

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

In this annual report, we refer to Companhia Paranaense de Energia ‒ Copel, and, unless the context otherwise requires, its consolidated subsidiaries as “Copel”, the “Company”, “we” or “us”.

References to (i) the “real”, “reais” or “R$” are to Brazilian reais (plural) and the Brazilian real (singular) and (ii) “U.S. dollars”, “dollars” or “US$” are to United States dollars. We maintain our books and records in reais. Certain figures included in this annual report have been subject to rounding adjustments.

Our audited consolidated financial statements as of December 31, 2020 and 2019, and for each of the years ended December 31, 2020, 2019 and 2018, are included in this annual report. We prepared our audited consolidated financial statements included in this annual report in accordance with International Financial Reporting Standards, or IFRS, as issued by the International Accounting Standards Board, or IASB.

References in this annual report to the “Common Shares”, “Class A Shares” (or “Class A”) and “Class B Shares” (or “Class B”) are to our common shares, class A preferred shares and class B preferred shares, respectively. References to “American Depositary Shares” or “ADSs” are to American Depositary Shares, each representing one Class B Share. The ADSs are represented by American Depositary Receipts (“ADRs”).

Certain terms are defined the first time they are used in this annual report. As used herein, all references to “GW” and “GWh” are to gigawatts and gigawatt hours, respectively, references to “kW” and “kWh” are to kilowatts and kilowatt hours, respectively, references to “MW” and “MWh” are to megawatts and megawatt hours, respectively, and references to “kV” are to kilovolts. These and other technical terms are defined in the “Technical Glossary” that begins on page 149.

 
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FORWARD-LOOKING STATEMENTS

This annual report contains forward-looking statements. We may also make written or oral forward-looking statements in our annual report to shareholders, in our offering circulars and prospectuses, in press releases and other written materials and in oral statements made by our officers, directors or employees. These statements are not historical facts and are based on management’s current view and estimates of future economic circumstances, industry conditions, company performance and financial results. The words “anticipates”, “believes”, “estimates”, “expects”, “plans” and similar expressions, as they relate to us, are intended to identify forward-looking statements. Statements regarding the declaration or payment of dividends, the implementation of principal operating and financing strategies and capital expenditure plans, the direction of future operations and the factors or trends affecting the financial condition, liquidity or results of operations are examples of forward-looking statements. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to update publicly any of them in light of new information or future events.

Forward-looking statements involve only the current view of management and are subject to a number of inherent risks and uncertainties. There is no guarantee that the expected events, trends or results will actually occur. We caution you that a number of important factors could cause actual results to differ materially from those contained in any forward-looking statement. Such factors include, but are not limited to:

·Brazilian political and economic conditions;
·economic conditions in the State of Paraná;
·technical and operational conditions related to the provision of electricity services;
·lawsuits;
·our ability to obtain financing;
·developments in other emerging market countries;
·changes in, or failure to comply with, governmental regulations;
·competition;
·electricity shortages;
·impacts of the coronavirus (COVID-19) pandemic; and
·other factors discussed below under “Item 3. Key Information―Risk Factors”.

All forward-looking statements are expressly qualified in their entirety by this cautionary statement, and you should not place undue reliance on any forward-looking statement contained in this annual report.

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

 
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Item 3. Key Information

 

Risk Factors

Risks Relating to Our Company and our Operations

We are controlled by the State of Paraná, the policies and priorities of which directly affect our operations and may conflict with the interests of our investors.

We are controlled by the State of Paraná, which holds 58.6 % of our outstanding common voting shares as of the date of this annual report, and whose interests may differ from other shareholders. As a major shareholder, the State of Paraná has the power to control all of our operations, including the power to elect a majority of the members of our Board of Directors and determine the outcome of any action requiring common shareholder approval, including transactions with related parties and corporate reorganizations.

As our operations have an important impact on the commercial and industrial development of the State of Paraná, the State of Paraná may use its status as our controlling shareholder to decide whether we should engage in certain activities and make certain investments aimed, principally, to promote its public policies or social objectives and not necessarily to meet the objective of improving our business and/or operational results. Further, proceedings involving the State of Paraná may affect its controlling shareholder position and, therefore, may impact our capital structure.

We are involved in several lawsuits that could have a material adverse effect on our business if their outcome is unfavorable to us.

We are the defendant in several legal proceedings, mainly relating to civil, administrative, labor and tax claims. The outcome of these proceedings is uncertain and, if determined against us, may result in obligations that could materially affect our results of operations. On December 31, 2020, our provisions for probable (more likely than not) and reasonably estimated losses were R$1,555.7 million. For additional information, see “Item 8. Financial Information–A. Consolidated Financial Information–Legal Proceedings”.

We are subject to limitations regarding the amount and use of public sector financing, which could prevent us from obtaining financing and implementing our investment program.

Our current budget anticipates capital expenditures for expansion, modernization, research, infrastructure and environmental projects of approximately R$1,902.7 million in 2021. As a state-controlled company, we are subject to Brazilian Central Bank Resolution no. 4,589/2017(Resolução nº 4,589/2017 do Banco Central do Brasil), which defines the limit of exposure and the annual global limit of credit to public sector entities to be observed by financial institutions and other institutions authorized to operate by the Brazilian Central Bank. The annual global limit that can be contracted in credit operations, with and without guarantee of the Union, by the bodies and entities of the public sector with the financial institutions and other institutions authorized to operate by the Brazilian Central Bank is defined by the National Monetary Council by means of inclusion of an annex to Brazilian Central Bank Resolution no. 4,589/2017, establishing, until the end of each fiscal year, the limit for the following year. The maximum amounts defined for the 2021 financial year are up to R$9.0 billion for Union guaranteed operations and up to R$11.0 billion for operations without Union guarantee. Although theses limits have recently increased, as a result of these limits, we may have difficulty in obtaining financing from financial institutions and other institutions authorized to operate by the Brazilian Central Bank, which could create difficulties in the implementation of our investment program. Additionally, some of our concession contracts have provisions that limit our permitted level of indebtedness, which could also affect our ability to obtain necessary financing. Furthermore, the requirements and other criteria adopted by financial institutions when approving new financing transactions may be related to certain Brazilian macroeconomic scenarios, as well as to our financial indicators, such as our indebtedness levels and other indicators usually considered by financial institutions in their credit risk assessments. We cannot ensure you that these requirements and criteria will be met. As a result of these regulations and provisions, our capacity to incur debt from certain sources is limited, which could negatively affect the implementation of our investment program.

 
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Failures in our cybersecurity controls or unauthorized disclosure of information, as well as failure to comply with existing data privacy and data security laws may adversely affect our business and reputation. We have suffered cyber-attacks in the past leading to the unavailability of part of our systems. 

We collect, store, process and use various confidential information related to our business and operations. In our ordinary course of business, we also collect and store personal data of our customers in our data centers located at our own premises.

Despite our cybersecurity controls, information technology and infrastructure (solarwinds), in the past we have been and in the future we may be vulnerable to failures whether caused by technical failures, negligence, accident or cyber-attacks. Those failures may result in disclosure or theft of sensitive information, loss of data integrity, misappropriation of funds and disruptions to or interruption in our business operations. For more information on cyber-attacks we suffered, see “Item 4. Information on the Company – Recent Developments.”

We are subject to the Brazilian Federal Law No. 13,709/2018 (Lei Geral de Proteção de Dados Pessoais, or the “LGPD”) that sets forth the legal framework to be observed by companies in the processing of personal data, which entered into effect on September 18, 2020, but its government penalties will only be enforceable from August 1, 2021, pursuant to Law No. 14,010/2020. As a result of any violations of this statute, including any leakage of personal data, beginning in August 2021, we may be subject to penalties, such as (i) a warning, with a deadline for taking corrective measures; (ii) a simple fine of up to 2% of our revenue in Brazil, limited to R$50 million for an infraction; (iii) a daily fine, limited to R$50 million for an infraction; (iv) disclosure of the infraction after duly proven; and (v) elimination of the personal data to which the violation refers. Also, any security incident involving personal data could damage our reputation, which could have an adverse effect on us, our business and our results of operations. Although the government sanctions are not yet in force, civil and criminal legal sanctions can be applied in case of violation of the LGPD’s provisions.

We have engaged an external consulting firm to assist us in adapting our internal controls to the new rules on data protection (especially the LGPD). As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance protective measures or to investigate and remediate any security vulnerabilities that are discovered in the future.

The construction and expansion of our transmission and power generation projects involve significant risks that may have an adverse effect on us

Our activities related to the development of transmission and generation projects depend on the consent of third parties over which we have no control. In addition, project development is subject to environmental, engineering and construction risks that can lead to cost overruns, delays and other impediments to timely complete within a project’s budget. We cannot assure you that we will (i) obtain all required permits and approvals for our projects, (ii) secure private sector partners for any of our projects, or (iii) obtain adequate financing for our projects or that financing will be available on a non-recourse basis to us. If we are unable to complete a project or such project is delayed, this may decrease our expected financial return from the project, which may lead to impairment. As a consequence, our costs may increase or we may fail to achieve the revenues planned in connection with such expansion projects, which may have an adverse effect on our financial condition and results of operations.

We are largely dependent upon the economy of the State of Paraná.

The distribution market for the majority of our sales of electricity is located in the State of Paraná. Although a more competitive market involving possible sales to customers outside Paraná might develop in the future, our business depends and is expected to continue to depend to a very large extent on the economic conditions of Paraná.

The weak economic growth of Brazil in recent years led to the reduction of energy consumption in the State of Paraná and in Brazil as a whole, resulting in leftover energy in the interconnected system, consequently reducing (i) short-term prices and (ii) prices negotiated in the Free Market. At the same time, prices in the regulated market have risen steadily as a result of supply deficiencies on the part of contracted energy by distributors and high prices in the short-term market in previous years. As a result, consumers consistently migrated into the Free Market and, therefore, the distributors’ captive market suffered a reduction since 2018. We cannot assure you that economic conditions in Paraná will be favorable to us in the future.

 
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Further, an increase in electricity prices, combined with poor economic performance in the State of Paraná, would affect the ability of some of our distributions customers to pay amounts owed to us. As of December 31, 2020, our past due receivables with Final Customers were approximately R$643.1 million in the aggregate and our allowance for doubtful accounts related to these receivables was R$212.3 million. See Note 7 to our audited consolidated financial statements.

In addition, in the event of an economic recession combined with high energy prices, the number of our distribution customers connecting illegally to our distribution grid may increase, which would then reduce our revenue from electricity sales to Final Customers. Energy we lose as a result of these illegal connections is considered a commercial loss (non-technical), and we may incur regulatory penalties if our commercial losses exceed certain established regulatory thresholds calculated by ANEEL. If ANEEL determines that we were not efficient in inspecting and controlling the non-technical losses in the distribution grid, the agency may limit the transfer of such losses to the Final Customers.

Disruptions in the operation of, or deterioration of the quality of, our services, or those of our subsidiaries, could have an adverse effect on our business, financial condition and results of operations.

The operation of complex electricity generation, transmission and distribution systems and networks involves various risks, such as operational setbacks and unexpected interruptions, caused by accidents, breakdown or failure of equipment or processes, performance below expected levels of availability and efficiency of assets, or disasters (such as explosions, fires, natural phenomena, landslides, sabotage, vandalism, and similar events). In addition, operational decisions by authorities responsible for the electricity network, environment matters, operations and other issues affecting the electricity generation, transmission or distribution could have an adverse effect on the performance and profitability of the operations of our generation, transmission and distribution systems. If these issues occurred, our insurance may be insufficient to wholly account for the costs and losses that we may incur as a result of the damages caused to our assets, or due to outages.

Further, the revenues that our subsidiaries generate from establishing, operating and maintaining their facilities are related to the availability of equipment and assets, and to the quality of the services (continuity and service in accordance with levels demanded by regulations). Under the related concession contracts, we and our subsidiaries are subject to: (i) a reduction of the distributor revenue as a result of the reduction of the so-called “Portion B” allocation in the revenue calculation formula; (ii) a reduction of the Permitted Annual Revenue - APR (Receita Anual Permitida, or RAP), for the transmission companies; (iii) the effects of the Availability Factor (Fator de Disponibilidade, or FID) and the offtake guarantee levels for the generation facilities; and (iv) the application of penalties and payment of compensation amounts, depending on the scope, severity and duration of non-availability of the services and equipment. Under Brazilian Law, we are strictly liable for direct and indirect damages resulting from the inadequate supply of electricity such as abrupt interruptions arising from the generation, transmission or distribution systems. Therefore, outages or stoppages in our generation, transmission and distribution facilities, or in substations or networks, may cause a material adverse effect on our business, financial situation and results of operations.

We are subject to risks related to social and environmental impacts of our projects.

The construction and operation of our assets may modify the ecosystem, particularly the natural state of the water resources and of the vegetation of the flooded river basin in the case of Hydroelectric Power Plants. Our projects may cause direct and indirect impacts in the local communities, such as housing displacement. Moreover, they may affect the economic outputs of the local communities, lead to the loss of cultural identity or increase the demand for government services. In these eventualities, we may implement specific plans in order to minimize and mitigate those impacts.

 
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Failures in dams under our responsibility may cause serious damages to the affected communities, to our results and to our reputation.

Dams are important infrastructures to our business, and are fundamental components of our Hydroelectric Power Plants for the purposes of diking and storing water, accounting for the majority of our energy generation capacity. However, in any dam, there is an intrinsic risk of ruptures caused by different internal or external factors. Therefore, we are subject to the risk of a dam failure that could have repercussions much greater than just the loss of hydroelectric power generation capacity. A dam failure may result in economic, social, regulatory and environmental damages and potential loss of human life in the communities downstream from the dams, which may have a material adverse effect in the image, business, operational results and financial conditions of the Company.

Our governance, compliance and internal controls may fail to prevent breaches of legal, regulatory, ethical or governance standards.

We are required to comply with a wide range of laws and regulations, including anti-corruption , anti-money laundering and related laws and regulations. Although we have a range of internal policies and controls, we may be subject to breaches of those internal policies and controls and to instances of fraudulent behavior, corrupt practices and dishonesty by our directors, officers, employees, contractors or other agents that we may not timely identify or prevent.

Further, we have a large number contracts with suppliers with wide distribution and outsourcing of the production chains and we are not able to control all possible irregularities or to ensure that our selection processes will be sufficient to avoid situations where our suppliers have problems related to compliance with applicable law, sustainability or outsourcing of the production chain under inadequate safety conditions.

These risks are increased by the fact that our portfolio includes affiliated companies, such as special purpose companies, some of which we do not hold a controlling interest in.

Although we have an integrity program with timely updates and a robust process for investigating complaints, our systems may not be effective in all circumstances. Any failure in our capacity to prevent or detect noncompliance with the applicable governance rules or regulatory obligations may cause damages to our reputation or other material adverse effects to our results of operation or financial condition.

The rules for electricity trading and market conditions may affect the sale prices of electricity.

We perform trading activities through power purchase and sale agreements, mainly in the Free Market, through our generation and trading companies.

Energy trading is affected by changes in the methodology used to calculate energy price in the short-term (Preço de Liquidação de Diferenças, or PLD). PLD is currently determined by the results of optimization models of operation of the interconnected systems used by the ONS (Operador Nacional do Sistema Elétrico) and by CCEE (Câmara de Comercialização de Energia Elétrica). In such determination, there may be data entry errors or errors in the model, which may lead to an unexpected change of the PLD and possible future republications of the PLD. Thus, there is a risk for the commercial business with respect to the alteration of these models, data entry errors and republishing of the PLD, which may cause market uncertainty, reduction of liquidity, and financial losses with unexpected price variation. As of January 1, 2021, the PLD is officially calculated for each submarket on an hourly basis, as proposed by the Standing Committee for Analysis of Methodologies and Programs (Comissão Permanente para Análise de Metodologias e programas Computacionais do Setor Elétrico or CPAMP), in accordance with the implementation schedule defined by MME (Ministério de Minas e Energia) Ordinance No. 301/2019.

Additionally, any change in the energy trading rules related to the increase of restrictions for the entry of new consumers in the Free Market may affect our energy trading business.

Our business could be adversely affected by the performance of our suppliers, contractors or other third parties we do not control.

Suppliers, contractors and other third parties may fail to perform existing contracts and obligations, which may unfavorably impact our operations and financial results.

Further, being a mixed capital publicly-held company, we are legally obliged to engage a bidding process for the acquisition of equipment, materials and services, which may not guarantee the best quality of services, equipment and materials.

We are subject to climate factors and to uncertainties that may adversely impact our operation and results.

Our energy generation, transmission and distribution operations are subject to climatic factors and uncertainties related to severe weather events, mainly cyclones, hurricanes, floods, droughts and fires. These events can affect minimum water storage levels in hydroelectric plant reservoirs and lead to the unavailability of our electricity supply systems, impacting penalties by regulatory bodies, consumer complaints, lawsuits, costs for the restoration of systems, in addition to negatively affecting our results.

 
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Further our wind farms’ operations are subject to climate factors and to uncertainties related to the speed of wind. The authorizations that govern our power generation activities in wind farms set forth certain performance covenants, which require us to generate minimum amounts of energy on annual and four-year bases in accordance with the energy amounts sold in the correspondent auctions. Non-compliance with such covenants may adversely impact our results.

We may acquire other companies in the electric sector or new energy concessions, as we already did in the past, which may increase our financial leverage and adversely affect our consolidated performance.

We constantly prospect for businesses that are related to our corporate purpose and aligned with our strategic plan. To expand our business, we may participate in auctions for the construction and operation of new power generation and transmission ventures, as well as invest in other companies from the energy sector, as we have done in the past. These acquisitions can increase our financial leverage or reduce our profits. In addition, the integration of the new businesses may not result in the synergy we expect in terms of efficiency gains and economies of scale for our operations, which may adversely affect our operational and financial performance.

Labor disputes may disrupt our operations from time to time.

Our employees are represented by unions. Disagreements regarding issues related to divestitures, changes to our business strategy, and reductions in the professional staff may lead to employee reactions. Strikes, work interruptions, or other forms of protests in any of our major suppliers or contractors or at their facilities may undermine our ability to complete relevant projects on time, negatively impacting our results of operations, and affect our ability to achieve long-term strategic goals.

Risks Relating to the Brazilian Electricity Sector and Other Sectors that We Operate

We are uncertain as to the renewal of certain of our generation and transmission concessions.

Under Federal Law No. 12,783/2013, or the 2013 Concession Renewal Law, we may only renew our concessions that were in effect as of 1995 (and, in the case of generation facilities, generation concession contracts entered into prior to 2003) for an additional 30-year period (or an additional 20-year period in the case of thermal plants), if we agree to amend the terms of the concession contract that is up for renewal to reflect certain new terms and conditions imposed by the 2013 Concession Renewal Law, which vary depending on whether the concession is for generation, transmission or distribution. If we do not agree to amend the concession contract to reflect these new conditions, the concession contract cannot be renewed and will be subject to a competitive bidding process upon its expiration, which we might not win. If we do not renew our generation and transmission concessions or if they are renewed under less favorable conditions, our financial condition and results of operations could be materially adversely affected. For more information, see “Item 4. Information on the Company—The Brazilian Electric Power Industry—Concessions”.

The concession agreement of our controlled company Compagas is under discussion with the granting authority

Compagas has entered into a concession agreement with the State of Paraná, as authority, pursuant to which the concession shall expire on July 6, 2024. The purpose of this concession is to provide piped gas distribution services and other related activities, to all segments of the consumer market, either as raw material or for the purpose of power generation or other uses made possible by technological advances.

The gas concession agreement is part of the so called “bifurcated model”, where part of the investments made by the concessionaire is paid by the users of the public service and the remaining part is indemnified by the granting authority, the State of Paraná, at the end of the concession.

On December 7, 2017, the State of Paraná enacted Complementary Law No. 205/2017, setting forth a new interpretation regarding the expiration date of the concession, leading to the understanding that the new expiration date was January 20, 2019. Notwithstanding the new expiration date provided by the state law, this concession has not been subject to neither an extension nor a new bidding process. Pursuant to applicable law, Compagas, as the current concessionaire, may continue to operate the concession until a new concessionaire is appointed.

 
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Further, Complementary Law No. 227/2020, amended Complementary Law No. 205/2017 to revoke the provision on the expiration date of the concession as January 20, 2019.

Although the current Complementary Law 227/2020 ensures the concession expires on July 6, 2024, as originally foreseen in the concession agreement, and with which we agree, there is no guarantee that a future legislative change will change this scenario again, forcing us to to again discuss this issue in court.

In the event of non-extension of the concession, even if Compagas is entitled to compensation for the investments made in the last 10 years prior to the end of the concession, the financial condition and results of operations of our controlled company may be adversely affected. For more information see Note 2.1.1 to our audited consolidated financial statements.

Our operating results depend on prevailing hydrological conditions, which have been volatile recently. The impact of water shortages and resulting measures taken by the government to conserve energy may have a material adverse effect on our business, financial condition and results of operations.

We are dependent on the prevailing hydrological conditions throughout Brazil and in the geographic region in which we operate. According to data from ANEEL, approximately 64.0% of Brazil’s installed capacity currently comes from hydroelectric generation facilities. Hydrological conditions in our region, and Brazil in general, are frequently subject to changes because of non-cyclical deviations in average rainfall.

In previous periods of low rainfall, the Brazilian government reacted to poor hydrological conditions by seeking to reduce the consumption of electricity by Final Customers by several means, from general conservation campaigns to raise public awareness to rationing programs. The effect of conservation campaigns is not very predictable, making it difficult for our distribution business to accurately estimate the volume of energy it needs to purchase for sale to Final Customers. In case of mandatory rationing program, our distribution business would be adversely affected because its revenues are partially based on the volume of electricity it provides through our distribution grid to Final Customers.

With respect to our generation business, in order to compensate for poor hydrological conditions and to maintain adequate water levels in reservoirs, the ONS may order the reduction of generation from Hydroelectric Power Plants, which would be partially compensated by increased generation by Thermoelectric Plants. This mechanism for replacing hydroelectric production with thermoelectric production may not provide all of the energy we need to fulfill our obligations under existing energy supply contracts. To compensate for this deficit, our generation business can be required to purchase energy in the Spot Market, typically at higher prices, and we would not be able to pass on these increased costs. This mechanism impacts all generation companies in Brazil regardless of whether the geographical region in which a specific generator is located is experiencing low rainfall and could have a material adverse effect on our generation business. For more information, see Note 14.1 to our audited consolidated financial statements.

In addition, in an extreme scenario, given the increased presence of thermal generation in the national electric matrix, if a shortage of natural gas were to occur, this would increase the general demand for hydroelectric energy in the market and therefore increase the risk that a rationing program would be instated.

Regarding our energy trading business, the effect of volatility in hydrological conditions is the increase of the variation of energy price, which in turn increases the Spot Market volatility, thus affecting our operating results. Spot price (PLD) is determined by the results of optimization models of operation of the interconnected systems used by the ONS (Operador Nacional do Sistema Elétrico) and by CCEE. The energy average prices in the short term ("spot") are calculated by CCEE every hour and are set for each region.

When there is great availability of hydrological resources, the spot price tends to remain at lower levels, which may not be enough to (i) cover the generation costs of this very same energy (when related to our generation business) and (ii) cover the cost of the power purchase and sale agreement in our energy trading business.

Conversely, if hydrological availability is affected, spot prices tend to increase significantly, in addition to occasionally impacting the GSF, which may adversely impact our costs of energy purchases, as the price set forth in power purchase and sale agreements may not be sufficient.

 
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ANEEL could penalize us for failing to comply with the terms of our concessions or with applicable laws and regulations, and we may not recover the full value of our investment in the event that any of our concessions are terminated.

Our concessions are for terms of 20 to 35 years and may be extended if certain conditions are met. In the event that we fail to comply with any term of our concessions or applicable law or regulation, ANEEL may impose penalties on us, which may include warnings, the imposition of potentially substantial fines and restrictions on our operations, among others. ANEEL may also terminate our concessions prior to the expiration of their terms if we fail to comply with their provisions or if they determine that terminating our concessions would be in the public interest, through a forfeiture or expropriation proceeding. In particular, our renewed distribution concession agreement contains both quality and financial metrics that become more restrictive over time, and that we must meet to ensure that our distribution concession agreement is not terminated. If ANEEL terminates any of our concessions before its expiration, we would not be able to operate the segment(s) of our business that had been authorized by the concession. Furthermore, any compensation that we may receive from the Brazilian government for the unamortized portion of our investment may not be sufficient for us to recover the full value of our investment. The early termination or non-renewal of any of our concessions or the imposition of severe fines or penalties by ANEEL could have a material adverse effect on our financial condition and results of operations. See “Item 4. Information on the Company—The Brazilian Electric Power Industry—Concessions”.

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 legal and regulatory authorities, particularly the MME and ANEEL, which regulate and oversee various aspects of our business and approve our tariffs. Changes to the laws and regulations governing our operations, which have occurred in the past, could adversely affect our financial condition and results of operations.

For example, the tariffs that we charge for sale of electricity to Captive Customers are determined pursuant to a concession agreement with the Brazilian government through ANEEL. The tariff rates we charge our customers are determined pursuant to a concession agreement and in accordance with ANEEL’s regulation. In addition, ANEEL’s decisions relating to our tariffs may be contested by public authorities or by our customers. Administrative and judicial decisions resulting from these challenges may modify ANEEL’s decisions in a manner that is unfavorable to us, which may adversely affect our financial condition and results of operations.

If any further regulations or new laws are passed by the Brazilian government to lower electricity prices, these new laws and regulations could have a material adverse effect on our results of operations.

Certain customers in our distribution concession area may cease to purchase energy from our distribution business.

Our distribution business generates a large portion of its revenues by selling energy that it purchases from generation companies. Large electricity customers within the geographic area of our concession that meet certain regulatory requirements may qualify as free customers (“Free Customers”). A Free Customer in our distribution concession area is entitled to purchase energy directly from generation and energy trading companies rather than through our distribution business, in which case that Free Customer would cease to pay our distribution business for that energy that we previously supplied.

In addition, ANEEL has issued regulations related to micro and mini distributed generation, which has been facilitating the purchase or lease of power generation equipment by customers, especially solar photovoltaic modules, to produce energy for their own consumption. Such regulation is currently under review and its outcome is difficult to predict. If the number of customers with micro and mini distributed generation within the geographic area of our concession increases, our revenues and results of operations could also be adversely affected.

We generate a portion of our operating revenues from Free Customers who may seek other energy suppliers upon the expiration of their contracts with us.

As of December 31, 2020, we had 912 Free Customers, representing approximately 8.0% of our consolidated operating revenues and approximately 14.9% of the total volume of electricity sold by us.

 
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Regarding our energy trading company, as of December 31, 2020, our energy trading company had 877 Free Customers, representing approximately 4.8% of our consolidated operating revenues and approximately 8.6% of the total volume of electricity we sold in 2020.

Copel GeT has 35 Free Custumers on December 31, 2020. Approximately 55.2% of the megawatts-hours sold under contracts to such customers by Copel GeT expired in 2020. These customers represented approximately 6.3% of the total volume of electricity we sold in 2020, and approximately 3.2% of our consolidated operating revenues. Our contracts with Free Customers are typically for periods ranging between two years and five years in our generation business. There can be no assurance that Free Customers will enter into contracts or extend their current contracts to purchase energy from us.

Additionally, it is possible that our large industrial clients could be authorized by ANEEL to generate electric energy for their own consumption or sale to other parties, in which case they may obtain an authorization or concession for the generation of electric power in a given area, which could adversely affect our results of operations.

We may be forced to purchase or sell energy in the Spot Market at higher or lower prices and we may not be entitled to pass on any increased costs or incurred losses to our Final Customers in a timely manner, or at all.

Under the New Industry Model Law, electric energy distributors, including us, must contract, through public bids conducted by ANEEL, 100% of the forecasted electric energy demand for their respective distribution concession areas. The auctions in which the distributors are allowed to purchase energy are held up to seven years prior to the actual delivery of electric energy. We cannot guarantee that our forecasts for energy demand in our distribution concession area will be accurate. If our forecasts fall short of actual electricity demand, or if we are unable to purchase energy through the regulated market due to lack of energy supply in the market, or if a generation company fails to deliver energy that was previously contracted, we may be forced to make up for the shortfall by entering into short-term agreements to purchase electricity in the Spot Market where we may pay significantly more for energy without being able to pass on these increased costs to our Final Customers. In addition, if we underestimate our distribution energy needs, we may be subject to penalties imposed by the CCEE. Moreover, if our forecasts surpass actual demand by more than the allowed margin (105% of actual demand), including where demand is depressed due to government campaigns in response to poor hydrological conditions or due to reduced economic activity, we will not be able to pass on to our Final Customers the cost of the excess energy that we acquire.

We are subject to a counterparty’s credit risk in agreements entered into with Copel Comercialização (Copel Mercado Livre) and in case of default, we may have to sell or purchase energy at a different base price.

Copel Comercialização is subject to a counterparty’s credit risk. When Copel Comercialização sells energy, the counterparties to power purchase agreements may default on their contractual obligations, which may cause Copel Comercialização to sell energy at a different base price. In cases where Copel purchases energy, whether from energy generation projects, in operation or under construction, or even from energy trading, the selling counterparties may also default on the relevant contracts, and, consequently, Copel Comercialização may have to buy energy at a different base price and be subject to regulatory penalties imposed by CCEE due to insufficient contractual guarantees. Even though the Company performs credit analyses in accordance with market standards and requires its counterparties to provide guarantees in connection with the power purchase and sale agreements, we cannot guarantee that our counterparties will not fail to comply with their payment obligation or with their obligation to deliver energy to Copel, as the case may be, which may adversely affect our results.

We are subject to the risk of exchange rate variation if we start to perform energy import business, as well as if we perform business involving natural gas

 

Our subsidiary Copel Comercialização (Copel Mercado Livre) obtained authorization from the Ministry of Mines and Energy to import energy from neighboring countries, Argentina and Uruguay, and if we start doing business in this regard, we will be subject to the risk of exchange rate fluctuation. This subsidiary was also authorized by the National Agency of Petroleum, Natural Gas and Biofuels to operate in the sale of natural gas within Brazil. Although the natural gas business still has an incipient market in Brazil, if we do business in this area, we will be subject to the risk of exchange rate variation, considering that these transactions are carried out in foreign currencies.

 

 
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We are subject to unrealized losses or net gains arising out from the mark-to-market of the purchase and sale of energy contracts, which may expose the Company to the risk of future energy prices

Our subsidiary Copel Comercialização (Copel Mercado Livre) negotiates energy purchase and sale transactions, and part of its agreements are classified as derivative financial instruments measured at fair value through its results. Unrealized net losses or gains resulting from the mark-to-market of these contracts (difference between contracted prices and market prices) are recognized in the results of the fiscal year. This activity may expose the Company to the risk of future energy prices.

Our equipment, facilities and operations are subject to numerous environmental and health regulations, which may become more stringent in the future and may result in increased liabilities and increased capital expenditures.

Our distribution, transmission and generation activities are subject to comprehensive federal, state and local legislation, as well as 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 our failure to comply with their regulations and with requirements established for the maintenance of our environmental licenses. These actions could result in, among other things, the imposition of fines, embargoes and revocation of licenses, which could have a material adverse effect on our financial condition and results of operations. It is also possible that enhanced environmental and health regulations will force us to allocate capital towards compliance, and consequently, divert funds away from planned investments. Such a diversion could have a material adverse effect on our financial condition and results of operations.

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

We are strictly liable under Brazilian law for damages resulting from the inadequate provision of electricity distribution services. In addition, our distribution, transmission and generation utilities may be held liable for damages caused to others as a result of interruptions or disturbances arising from the Brazilian generation, transmission or distribution systems, whenever these interruptions or disturbances are not attributed to an identifiable member of the National Electric System Operator, the Operador Nacional do Sistema Elétrico (“ONS”). We cannot assure you that our insurance policies will fully cover damages resulting from inadequate rendering of electricity services, which may have an adverse effect on us.

We are the controlling shareholders of a company that operates a gas distribution business (Compagas) and we are consequently exposed to risks inherent to this sector.

We control a business in the gas distribution sector, which is operated by Companhia Paranaense de Gas – Compagas. This company is entitled to exclusive rights with respect to the supply of piped gas in the State of Paraná. The clients of this business are Thermoelectric Plants, cogeneration plants, gas stations, other companies and residences.

Businesses in the gas distribution sector are subject to a broad set of risks inherent to its operation, including among the main ones:

• Regulatory instability,

• Shortage of natural gas,

• Depending on a single supplier in Brazil,

• Capacity of financing expansion,

• Operational failures and accidents in distribution,

• Performance of outsourced service providers,

• Alternative energy sources,

• Quality in service.

 
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As a result of these uncertainties, there is no guarantee that the purposes of our gas distribution business will be achieved, which may have an adverse effect on our results of operations and our business.

We are still the controlling shareholders of a company that operates a telecommunications business (Copel Telecomunicações S.A.) and we are consequently exposed to the risks inherent to this sector.

We control a business in the telecommunications sector under an authorization granted by the National Telecommunications Agency (Agência Nacional de Telecomunicações – “ANATEL”). This business provides telecommunications services through the use of fiber optics. It also provides a number of telecommunications services to other companies of the Copel group.

On November 9, 2020, Copel Telecom's divestment auction was held at B3 S.A. – Brasil , Bolsa, Balcão. The winning bid was R$ 2.4 billion (equity value). On January 14, 2021, a Share Purchase Agreement for the sale of 100% of Copel Telecom was entered into with Bordeaux Multi-Strategic Investment Fund – Bordeaux Fundo de Investimentos em Participações Multiestratégia, the winning bidder of the auction. Certain conditions precedent, such as approval by ANATEL and the Administrative Council for Economic Defense (Conselho Administrativo de Defesa Econômica – “CADE”) have not yet been concluded. Thus, the process of divestment in the control of the subsidiary Copel Telecomunicações SA is still ongoing, and, if the conditions precedent are not completed, the transaction may not close. Failure to complete such sale may force us to keep the operations in the telecommunications sector longer than expected. 

Businesses in the telecommunications sector are subject to a broad set of risks inherent to its operation, such as:

• Regulatory instability,

• Increase in competition,

• Technological changes,

• Capacity of financing our expansion,

• Failures in technological systems and information security,

• Performance of outsourced service providers,

• Exchange rate fluctuations,

• Variation in operating costs,

• Operational failures,

• Quality in service.

If it is not possible to implement our proposal to divest control of Copel Telecomunicações S.A., we will need to reevaluate our strategy in the telecommunications sector

Considering that the process of potential divestment in the control of the subsidiary Copel Telecomunicações SA is in progress, as approved by the Board of Directors, this process may not be materialized, judicial decisions or restrictions imposed by regulatory bodies or other governmental entities or other unknown factors. Failure to complete such sale may force us to reevaluate our divestment strategy in the telecommunications sector.

 
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We cannot assure the speed of our innovation capacity and our responses in view of the changes the energy sector has been going through as a result of technology advances.

The electric energy sector has been going through changes driven by (i) the decentralization of the power generation systems; (ii) advances in energy storage technologies; (iii) dissemination of digital technologies that improve the efficiency of energy generation, transmission and consumption; (iv) increase of renewable energy sources, such as wind and solar energy; and (v) a tendency of reducing carbon footprints in the energy system, as part of the global efforts to mitigate the effects of climate change. These changes present many challenges and we may not be able to keep up with the effects of the increasing adoption of digital technologies in the electric energy sector and the significant potential of new technology solutions (both with respect to the improvement of processes and services provided to consumers and with respect to the development of new products that may lead to higher productivity gains, more affordable prices, higher competition and the creation of new markets). Investments in research and development may contribute to mitigate the risks related to the transformations of the energy sector and create new opportunities.

Risks Relating to Brazil

The Brazilian Government has significant influence over the Brazilian economy. Brazilian economic and political conditions— and investor perception of these conditions— have a direct impact on our operation.

Historically, the country’s political situation has influenced the performance of the Brazilian economy, and political crises have affected the confidence of investors and the general public, which resulted in economic deceleration, the downgrading of credit ratings of the Brazilian government and Brazilian issuers, and heightened volatility in the securities issued abroad by Brazilian companies.

Additionally, the Brazilian government has exercised, and continues to exercise, significant influence over the Brazilian economy and often changes monetary, credit, exchange and other policies to influence Brazil’s economy. Our business, financial condition, results of operations and prospects may be adversely affected by changes in government policies, as well as other factors including, without limitation:

• exchange rate movements and volatility;

• inflation and changes in interest rates;

• exchange control policies;

• fiscal policy and changes in tax laws;

• other political, diplomatic, social and economic developments that may affect Brazil or the international markets;

• controls on capital flows; and/or

• limits on foreign trade.

In the last few years, Brazil faced adverse fiscal developments and political instability. Brazilian GDP decreased by 4.1% in 2020, grew by 1.1% in 2019 and grew by 1.3% in 2018. Unemployment rate was 13.5% in 2020, 11.9% in 2019 and 11.6% in 2018. Inflation, as reported by the consumer price index (IPCA), was 4.52% in 2020, 4.31% in 2019 and 3.75% in 2018. The Brazilian Central Bank’s base interest rate (SELIC) was 2.0% on December 31, 2020, 4.5% on December 31, 2019 and 6.5% on December 31, 2018. Future economic, social and political developments in Brazil may impair our business, financial condition or results of operations, or cause the market value of our securities to decline.

Changes in, or uncertainties regarding the implementation of, the policies above, might generate or contribute to uncertainties in the Brazilian economy. This would increase the volatility of the domestic capital market and the value of Brazilian securities traded abroad, and adversely affect our business, results of operations and financial condition.

 
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Moreover, taking into account the Brazilian presidential system of government, and the considerable influence of the executive power, it is not possible to predict whether the present government or any successive governments will have an adverse effect on the Brazilian economy, and consequently on our business.

The effects of the COVID-19 pandemic of the coronavirus may have a material adverse impact on our operations and results

In December 2019, the outbreak of the Coronavirus Disease 2019 (COVID-19), spread throughout the world, being declared by the World Health Organization (WHO) as the COVID-19 outbreak pandemic, in March 2020. The impact on the global economy and financial markets has been significant and the overall consequences are still uncertain.

As a result, ANEEL, the Federal and the State Governments, particularly the State of Paraná, enacted a number of measures and regulations in response to the COVID-19 outbreak pandemic, aiming at protecting certain consumers, such as low income consumers and essential services and activities, while preserving public electricity distribution services during the COVID-19 outbreak pandemic.

With regards to the captive distribution market, Copel may experience in the short term (i) a significant reduction in revenue and collection from energy supply chains, (ii) defaults of large high voltage customers, and (iii) defaults of commercial class clients. In the medium term, Copel negative impacts may extend to other customer classes, especially residential ones.

A possible increase in payment defaults by residential consumers, coupled with the decrease in collection and the standstill of several commercial and industrial activities, resulting from social isolation measures, can adversely affect the financial and economic results involving the activities of the electricity sector, mainly the electricity distributors. Eventually, with the decrease in energy consumption, the Company may be in a position above the permitted regulatory limit for over contracting electricity.

Copel has followed the load projections issued by official bodies in the electricity sector strongly impacted by the drop in consumption in the commercial and industrial segments. This fall has caused notifications by energy buyers, under the perspective and allegation of unforeseeable circumstances and force majeure generated by the COVID-19 outbreak pandemic, requiring a reduction in the amounts of energy contracts and/or installments of defaulted bills.

Adverse impacts of the COVID-19 outbreak pandemic can also be felt on the implementation of generation and transmission projects, or on the availability of existing assets resulting from local actions, preventing access to facilities or problems with suppliers in the sector, also affected by the COVID-19 outbreak pandemic .

To the extent the government does not adopt a joint solution for the energy sector as a means to control or remove risk for the sector as a whole, the Company may suffer, among other impacts, cash damages, decreases in its profitability and the impossibility of performing certain operational activities.

We have established a Contingency Committee in light of the COVID-19 outbreak pandemic with the objective of monitoring and mitigating current and futures impacts and consequences in our activities. The Contingency Committee has four main focus objectives: (i) people’s safety, (ii) continuation of essential activities of the Company, (iii) monitoring guidelines and requirements of regulatory bodies, and (iv) preservation of adequate financial conditions to support the crisis. The Company has also continuously been (A) monitoring the impacts of the COVID-19 pandemic on (i) its contracts, (ii) suppliers and (ii) the liquidity of the energy market and its short-term pricing, as well as (B) involved and negotiating with the relevant authorities for the implementation of guidelines that guarantee the maintenance of the economic and financial sustainability of Brazil’s electricity power generation, transmission, commercialization and distribution chain.

 
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Fluctuations in currency exchange rates and the devaluation of the real may adversely affect our net income and cash flow.

The Brazilian currency has been devalued periodically in the past in relation to the U.S. dollar and other foreign currencies. At the end of 2018, the exchange rate between the real and the U.S. Dollar was of R$3.87 per US$1.00. As of December 31, 2019, the exchange rate between the real and the U.S. Dollar was of R$4.03 per US$1.00, depreciating 4.0% against the U.S. Dollar. As of December 31, 2020, the real vs. U.S. dollar exchange rate recorded was R$5.19 to US$1.00, depreciating 28.8% against the U.S. Dollar, compared to the exchange rate recorded on December 31, 2019. Depreciation of the real increases the cost of servicing our foreign currency-denominated debt and the cost of purchasing electricity from the Itaipu – a hydroelectric facility, one of our major suppliers, which adjusts its electricity prices based in part on its U.S. dollar costs. Indeed, depreciation generally curtails access to international capital markets and may prompt government intervention. It also reduces the U.S. dollar value of our dividends and the U.S. dollar equivalent of the market price of our common shares and the ADSs.

Inflation and governmental measures to curb inflation may contribute to economic uncertainty in Brazil, and could reduce our margins and the market price of the Class B Shares and ADSs.

Brazil has in the past experienced extremely high rates of inflation. More recently, Brazil’s annual rates of inflation, measured in accordance with the variation of the Índice Geral de Preços - Disponibilidade Interna (“IGP-DI”) index, were 8.26% for the three-month period ended March 31, 2021, 23.7% in the year 2020, 7.7% in the year 2019, 7.1% in the year 2018 and (0.4)% in 2017. The Brazilian government has in the past taken measures to combat inflation, such as raising the basic Selic interest rate to elevated levels, and public speculation about possible future government actions has had significant negative effects on the Brazilian economy. Although our concession contracts provide for annual adjustments based on inflation indexes, if Brazil experiences substantial inflation in the future, and the Brazilian government adopts inflation control policies similar to those adopted in the past, our costs may increase faster than our revenues, our operating and net margins may decrease and, if investor confidence lags, the price of the Class B Shares and ADSs may fall. Inflationary pressures may also curtail our ability to access foreign financial markets and could lead to further government intervention in the economy, including the introduction of government policies that may adversely affect the overall performance of the Brazilian economy.

Allegations of political corruption against the Brazilian government and the Brazilian legislative branch could create economic and political instability.

Currently, several former and current members of the Brazilian executive and legislative branches of government are being investigated as a result of allegations of unethical and illegal conduct identified by the Operation Car Wash (Operação Lava-Jato) being conducted by the Office of the Brazilian Federal Prosecutor, and a number of politicians and businessmen have been arrested. The potential outcome of these investigations is unknown, but they have already had an adverse impact on the image and reputation of the investigated companies, in addition to adversely impacting general market perception of the Brazilian economy, including our business, financial condition and results of operations, as well as the trading price of our common shares and ADSs. Moreover, the conclusion of these proceedings or further allegations of illicit conduct could have additional adverse effects on the Brazilian economy. We cannot predict whether such allegations will lead to further instability or whether new allegations against key Brazilian government officials will arise in the future. In addition, we cannot predict the outcome of any such allegations and their effect on the Brazilian economy.

Changes in Brazilian tax policies may have an adverse effect on us and our shareholders.

The Brazilian government has in the past changed its tax policies in ways that affect the electricity sector, and it may do so again in the future. These changes include increases in the tax rates affecting energy companies and, occasionally, the collection of temporary taxes related to specific governmental purposes. If we are unable to adjust our tariffs accordingly, we may be adversely affected.

Considering the Brazilian Government's intention to replace Contributions to PIS / PASEP and Cofins with Contribution on Goods and Services (Contribuição sobre Bens e Serviços) – CBS (Bill No. 3887/2020), we formalized a group of work to assess the impacts and risks that this change may have on our results. Taking into account the market in which we operate, with regulated tariffs and bilateral contracts, which are expected to rebalance prices in the event of new taxes, our working group concluded that the impacts for us will likely be low. However, for the final consumers of our distribution concession area, we estimate that the impacts will be medium, in view of the possible tariff increase due to the increase in the rate of the new tax.

 
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There are also bills under discussion at the National Congress of Brazil that may change the way in which taxes are collected in Brazil, including the collection of income tax on dividends, which may adversely affect our shareholders.

Negative developments in other national economies, especially those in developing countries, may negatively impact foreign investment in Brazil and the country’s economic growth.

International investors generally consider Brazil to be an emerging market. Historically, adverse developments in the economies of emerging markets have resulted in investors’ perception of greater risk from investments in such markets. Such perceptions regarding emerging market countries have significantly affected the market value of securities of Brazilian issuers. Furthermore, although economic conditions are different in each country, investors’ reactions to developments in one country can impact the prices of securities in other countries, including those in Brazil, and this may diminish investors’ interest in securities of Brazilian issuers, including ours.

Risks Relating to the Class B Shares and ADSs

ADSs holders may not have all the rights of our shareholders, and may be unable to exercise voting rights or preemptive rights relating to the shares underlying their ADSs.

Holders of the Class B Shares, and thus of the ADSs may not have the same rights that are attributed to our shareholders by Brazilian law or our bylaws, and the rights of ADS holders may be subject to certain limitations provided in the deposit agreement or by the securities intermediaries through which ADS holders hold their securities.

Although ADS holders are permitted to vote at shareholders’ meetings, there are procedural steps involved in the process that create practical limitations on the ability of ADS holders to vote. In accordance with the Deposit Agreement, we will provide the notice to the Depositary, which will in turn, as soon as practicable thereafter, mail to holders of ADSs the notice of such meeting and a statement as to the manner in which instructions may be given by holders. To exercise their voting rights, ADS holders must then instruct the Depositary how to vote their shares. Because of this extra procedural step involving the Depositary, the process for exercising voting rights will take longer for ADS holders than for direct holders of Class B Shares. ADSs for which the Depositary does not receive timely voting instructions will not be voted.
The holders of the Class B Shares may have fewer and less well-defined rights to protect your interests in connection with actions taken by our Board of Directors or the holders of Common Shares than under the laws of the United States and certain other jurisdictions outside Brazil. Although Brazilian law imposes restrictions on insider trading and price manipulation, the Brazilian securities markets are not as highly supervised as the United States securities markets or markets in certain other jurisdictions outside Brazil.
The ability of ADS holders to exercise preemptive rights is not assured, particularly if the applicable law in the holder’s jurisdiction (for example, the Securities Act in the United States) requires that either a registration statement be effective or an exemption from registration be available with respect to those rights, as is in the case in the United States. We are not obligated to extend the offer of preemptive rights to holders of ADSs, to file a registration statement in the United States, and we cannot assure you that we will file any such registration statement. Accordingly, you may receive only the net proceeds from the sale of your preemptive rights by the Depositary or, if the preemptive rights cannot be sold, they will be allowed to lapse. If you are unable to participate in rights offerings, your holdings may also be diluted.
ADS holders may not receive dividend payments if we incur net losses or our net profit does not reach certain levels. Under Brazilian Corporate Law and our by-laws, we must pay our shareholders a mandatory distribution equal to at least 25% of our adjusted net profit for the preceding fiscal year, with holders of preferred shares having priority of payment. According to our bylaws, Class A Shares and Class B Shares are entitled to receive annual, non-cumulative minimum dividends, which dividend per share shall be at least 10% higher than the dividends per share paid to the holders of the Common Shares. Class A Shares have a dividend priority over the Class B Shares to receive a minimum dividend equal to 10% of the total share capital represented by the Class A Shares outstanding at the end of the fiscal year in respect of which the dividends have been declared, and Class B Shares have a dividend priority over the Common Shares. In the event that we are unable to declare dividends, our management may nevertheless decide to defer payment of dividends or, in limited circumstances, not to declare dividends at all. We cannot make dividend payments from our legal reserve and capital reserve accounts.
 
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Sales of a substantial number of shares, or the perception that such sales might take place, could adversely affect the prevailing market price of our shares or ADSs.

As a consequence of the issuance of new shares, sales of shares by existing share investors, or the perception that such a sale might occur, the market price of our shares and, by extension, of the ADSs may decrease significantly.

Future equity issuances may dilute the holdings of current holders of our shares or ADSs and could materially affect the market price for those securities.

We may in the future decide to offer additional equity to raise capital or for other purposes. Any such future equity offering could reduce the proportionate ownership and interests of holders of our shares and ADSs, as well as our earnings and net equity value per share or ADS. Any offering of shares and ADSs by us or our main shareholders, or a perception that any such offering is imminent, could have an adverse effect on the market price of these securities.

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

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

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

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

If you exchange your ADSs for Class B Shares, you risk increased taxes and the inability to remit foreign currency abroad.

Brazilian law requires that parties obtain a registration before the Brazilian Central Bank in order to be allowed to remit foreign currencies, including U.S. dollars, abroad. For the ADSs, the Brazilian custodian for the Class B Shares has obtained the necessary certificate from the Brazilian Central Bank for the payment of dividends or other cash distributions relating to the preferred shares or upon the disposition of the preferred shares. If you exchange your ADSs for the underlying Class B Shares, however, you must obtain your own certificate of registration or register in accordance with Brazilian Central Bank and CVM rules in order to obtain and remit U.S. dollars abroad upon the disposition of the Class B Shares or distributions relating to the preferred shares. If you do not obtain a certificate of registration, you may not be able to remit U.S. dollars or other currencies abroad and may be subject to less favorable tax treatment on gains with respect to the preferred shares. Pursuant to Brazilian Central Bank rules, obtaining this registration requires exchange transactions, which are subject to taxes in Brazil. For more information, see “Item 10. Additional Information—Taxation—Brazilian Tax Considerations—Other Brazilian Taxes”. If you attempt to obtain your own registration, you may incur expenses or suffer delays in the application process, which could delay your ability to receive dividends or distributions relating to the preferred shares or the return of your capital in a timely manner. The custodian’s registration before the Brazilian Central Bank and any certificate of foreign capital registration you obtain may be affected by future legislative changes. Additional restrictions may be imposed in the future on the disposition of the underlying Class B Shares or the repatriation of the proceeds from disposition.

 
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The Brazilian government may impose exchange controls and restrictions on remittances abroad which may adversely affect your ability to convert funds in reais into other currencies and to remit other currencies abroad.

In the past, the Brazilian government has imposed restrictions on the remittance to foreign investors of the proceeds of their investments in Brazil and the conversion of Brazilian currency into foreign currencies. The Brazilian government could again choose to impose this type of restriction if, among other things, there is deterioration in Brazilian foreign currency reserves or a shift in Brazil’s exchange rate policy. Reintroduction of these restrictions would hinder or prevent your ability to convert dividends, distributions or the proceeds from any sale of Class B Shares, as the case may be, from reais into U.S. dollars or other currencies and to remit those funds abroad. We cannot assure you that the Brazilian government will not take similar measures in the future.

The relative volatility and illiquidity of the Brazilian securities markets may impair your ability to sell the Class B Shares underlying the ADSs.

The Brazilian securities markets are substantially smaller, less liquid, more concentrated and more volatile than major securities markets in the United States and certain other jurisdictions outside Brazil, and are not as highly regulated or supervised as some of these other markets. The illiquidity and relatively small market capitalization of the Brazilian equity markets may cause the market price of securities of Brazilian companies, including our ADSs and Class B Shares, to fluctuate in both the domestic and international markets, and may substantially limit your ability to sell the Class B Shares underlying your ADSs at a price and time at which you wish to do so.

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

Law No. 10,833 of December 29, 2003, provides that the disposition of assets located in Brazil by a non-resident to either a Brazilian resident or a non-resident is subject to taxation in Brazil, regardless of whether the disposition occurs outside or within Brazil. This provision results in the imposition of income tax on the gains arising from a disposition of our common or preferred shares by a nonresident of Brazil to another non-resident of Brazil. There is no judicial guidance as to the application of Law No. 10,833 and, accordingly, we are unable to predict whether Brazilian courts may decide that it applies to dispositions of our ADS between nonresidents of Brazil. However, in the event that the disposition of assets is interpreted to include a disposition of our ADS, this tax law would accordingly result in the imposition of withholding taxes on the disposition of our ADS by a non-resident of Brazil to another non-resident of Brazil.

There is no guarantee that the Conversion Offers will be successful.

As described in “Item 4. Information on the Company – Recent Developments”, on March 22, 2021, Copel offered to the holders of Class B Shares, including Class B Shares represented by ADSs, the ability to convert five Class B Shares into one unit, consisting of four Class B Shares and one common share of Copel. The conversion of shares and formation of Units will only occur if there is a minimum adhesion of approximately 60% (sixty percent) of the shares issued and outstanding. We cannot assure you that the Coversion Offers (as defined below) will be successful or, if successful, how the conversion will impact the pricing and liquidity of our shares.   

 
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Item 4. Information on the Company

 

The Company

We engage in the generation, transmission, distribution and sale of electricity mainly in the Brazilian State of Paraná, pursuant to concessions granted by ANEEL, the Brazilian regulatory agency for the electricity sector. We also provide telecommunications and other services. While our activities are more concentrated in the Brazilian State of Paraná, we also operate in 10 different Brazilian states through our generation and transmission businesses.

As of December 31, 2020, we generated electricity from nineteen (19) hydroelectric plants, twenty five (25) wind plants and one (1) Thermoelectric Plant, for a total installed capacity of 5,742.0 MW, of which, approximately 99.7% is derived from renewable sources. Including the installed capacity of generation companies in which we have an equity interest, our total installed capacity is 6,397.8 MW. Our electric power business is subject to comprehensive regulation by ANEEL.

We hold concessions to distribute electricity in 394 of the 399 municipalities in the State of Paraná and in the municipality of Porto União in the State of Santa Catarina. As of December 31, 2020, we owned and operated 3,135 km of transmission lines and 202,085 km of distribution lines, constituting one of the largest distribution networks in Brazil. Of the electricity volume we supplied in 2020 to our Final Customers:

·37.0% was to industrial customers;
·27.1% was to residential customers;
·19.2% was to commercial customers; and
·16.7% was to rural and other customers.

Key elements of our business strategy include the following:

·bringing together sustainable growth, profitability, adequate indebtedness levels and allocation of profits;
·preparing the Company to go from consumer to client;
·seeking profitable opportunities related to new businesses and services in the energy sector;
·managing an integrated and strategic energy portfolio, including strategic partnerships and maximizing synergies and profitability;
·divesting from non-strategic assets;
·maintaining discipline in allocating capital and technical rigor in planning and implementing projects;
·achieving the same efficiency standards as the best companies from the energy sector, promoting innovation, investment in technology and optimization of the workforce;
·ensuring and raising levels of corporate sustainability, environmental, governance, risk management and compliance;
·developing and implementing a culture based on meritocracy and consequence management towards building high performance teams;
·seeking greater protagonism in our interaction with regulators and institutions;
·consolidating a culture focused on safety, health and quality of life.
 
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Our revenues for each of the last three (3) financial years by activity are described in “Item 5. Operating and Financial Review and Prospects —Results of operations for the years ended December 31, 2020, 2019 and 2018”.

Historical Background

We were formed in 1954 by the State of Paraná to engage in the generation, transmission and distribution of electricity, as part of a plan to bring the electric energy sector under state control. We acquired the principal private power companies located in the State of Paraná in the early 1970s. From 1970 to 1977, we significantly expanded our transmission and distribution grid and worked to increase the connectivity of our network to networks in other Brazilian states. In 1979, a change in state law permitted us to extend our generating activities to include production from sources other than hydroelectric and thermal power plants.

Currently, we are the largest energy company in the State of Paraná. We are a corporation incorporated and existing under the laws of Brazil, with the legal name Companhia Paranaense de Energia – Copel. Our head offices are located at Rua Coronel Dulcídio, 800, CEP 80420-170 Curitiba, Paraná, Brazil. Our telephone number at the head office is +55 (41) 3331-4011. Our website is www.copel.com and any filings we make electronically with the SEC will be available to the public over the Internet at the SEC’s website. The commercial name of each of our businesses is provided as follows.

Relationship with the State of Paraná

The State of Paraná owns 58.6% of our Common Shares and, consequently, has the ability to control the election of the majority of the members of our Board of Directors, members of our Supervisory Board, the appointment of senior management and our direction, future operations and business strategy.

Corporate Structure

Prior to 2001, we operated as a single corporation engaged in the generation, transmission and distribution of electricity and in certain related activities. In compliance with the new regulatory regime, we transferred our operations to four wholly-owned subsidiaries (one each for generation, transmission, distribution and telecommunications) and our investments in other companies to a fifth wholly-owned subsidiary. This corporate restructuring was completed in July 2001.

In 2007, to comply with energy sector legislation, we divided the assets of our transmission business (“Copel Transmissão S.A.”) between our distribution business (“Copel Distribuição S.A.”) and our generation business, (“Copel Geração S.A.”). As a result, we changed the name of the latter entity to Copel Geração e Transmissão S.A.

In 2013, the Company was restructured in order to enhance the efficiency of our corporate structure and reduce our operating costs.

On January 28, 2016, our board of directors approved the amendment of the bylaws of Copel Participações S.A., in order to change its corporate purpose and denomination to Copel Comercialização S.A. The corporate purpose of this company is the sale of energy and rendering of related services. The restructuring that created Copel Comercialização S.A. (Copel Mercado Livre) is aimed at strengthening Copel’s positioning in the energy trading market and to improve its efficiency, allowing for greater agility and flexibility in the sale of energy.

In September 2017, in order to optimize the management of operating activities, the Company carried out an organizational restructuring of its wholly-owned subsidiary Copel Renováveis S.A., whose activities were absorbed by Copel Geração e Transmissão S.A,

On August 30, 2018, Copel GeT signed a Share Exchange Agreement with Eletrosul with respect to the joint ventures Costa Oeste Transmissora de Energia S.A. (51% - Copel GeT and 49% - Eletrosul), Marumbi Transmissora de Energia S.A. (80% - Copel GeT and 20%- Eletrosul) and Transmissora Sul Brasileira de Energia S.A. (20% - Copel GeT and 80% - Eletrosul). Under this agreement, Copel GeT started holding share of interest of 100% in the joint ventures Costa Oeste and Marumbi, in addition Eletrosul started to hold share of interest of 100% in Transmissora Sul Brasileira. The business combinations occurred on August 31, 2018, date of transfer of the shares.

 
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In March 2019, Copel GeT signed a purchase and sale agreement with Centrais Elétricas Brasileiras S.A. and Fundação Eletrosul de Previdência e Assistencial Social - Elos to transfer 100% of the shares issued by SPE Uirapuru Transmissora de Energia SA. In June 2019, Copel GeT took over control of the company.

On October 18, 2019, Copel GeT, through a consortium with its subsidiary Cutia Empreendimentos Eólicos, participated in the A-6 new energy generation auction, having sold 14.4 average MW of the Jandaíra Wind Complex. The Jandaíra Wind Complex, which has 90.1 MW of installed capacity and 47.6 average MW of assured power, will be built in the northeastern state of Rio Grande do Norte, a region where Copel has other wind generation assets.

In order to renew the concession of HPP Gov. Bento Munhoz (or HPP Foz do Areia) for another 30 years, Copel incorporated the special purpose company F.D.A. Geração de Energia Elétrica S.A. (“FDA”) and, on March 03, 2020, requested the Ministry of Mines and Energy to apply Federal Decree no. 9,271/2018 (as amended by Federal Decree no. 10,135/2019), which conditions the renewal to the sale of the concession's corporate control in up to 18 months before the end of the current concession. On the same date, FDA signed with ANEEL the Brazilian Electricity Regulatory Agency, the Concession Contract that transfers the concession of the HPP Foz do Areia from Copel GeT to FDA, for the exploration of the plant until the end of the current concession, on September 17, 2023.

On November 9, 2020, Copel Telecom's divestment auction was held at B3 S.A. - Brasil, Bolsa, Balcão. The winning bid was R$ 2.4 billion (equity value). On January 14, 2021, a Share Purchase Agreement for 100% of Copel Telecom was entered into with Bordeaux Multi-Strategic Investment Fund – Bordeaux Fundo de Investimentos em Participações Multiestratégia, the winning bidder of the auction. We estimate that the transaction will close between the second or third quarter of 2021.

Copel currently has five wholly-owned subsidiaries, which are Copel Geração e Transmissão S.A., Copel Distribuição S.A., Copel Telecom, Copel Comercialização S.A. (Copel Mercado Livre) and Copel Serviços S.A.

Copel also holds 100% shareholding stake in several Special Purpose Companies (SPC).

The current organization of the group is as described as follows. All of our subsidiaries are incorporated in the Federative Republic of Brazil and subject to the Brazilian law.

 
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BUSINESS

In the past, our generation and distribution businesses were integrated, and we sold most of the electricity we generated to the customers of our distribution business. This changed as a result of the implementation of the New Industry Model Law, enacted in 2004. Today, open auctions on the regulated market are still one of the primary channels by which our distribution business purchases energy to resell to Captive Customers and one of the channels by which our generation business generates revenues. Our generation business only sells energy to our distribution business through auctions in the regulated market. Moreover, our distribution business, like other certain Brazilian distribution companies, is also required to purchase energy from Itaipu, in an amount determined by the Brazilian government based on our proportionate share in the Brazilian electricity market. For more information, see “Item 4. Information on the Company—The Brazilian Electric Power Industry”.

The following table shows the total electricity we (i) generated through entities in which we hold a 100.0% shareholding stake and the 51.0% and 30.0% of energy generated by Mauá and Baixo Iguaçu Hydroelectric Plants respectively (corresponding to the interest we hold in each of these assets) and (ii) purchased in the last five years, broken down by the total amount of electricity generated and purchased by Copel Geração e Transmissão and our wind farm generation facilities described below (“Wind Farms”) and the total amount of electricity purchased by Copel Distribuição and Copel Comercialização (Copel Mercado Livre).

 

Year ended December 31,

 

2020

2019

2018

2017

2016

  (GWh)
Copel Geração e Transmissão(1)          
Electricity generated(2) 10,115 17,199 18,029 19,583 25,319
Electricity purchased from Copel Comercialização 487 155 180 627 -
Electricity purchased from others 147 141 141 428 141
Electricity received from the Interconnected System 5,878 445 142 425 2
Total electricity generated and purchased by Copel Geração e Transmissão 16,627 17,940 18,492 21,063 25,462
Wind Farms(1) (3)          
Electricity generated(2) 2,116 1,909 1,067 989 1,175
Electricity purchased from others 39 61 - - -
Total electricity generated and purchased by Wind Farms 2,145 1,970 1,067 989 1,175
Copel Distribuição          
Electricity purchased from Itaipu(4) 5,498 5,533 5,727 5,934 5,958
Electricity purchased from Auction – CCEAR – affiliates 154 153 92 87 157
Electricity purchased from Auction – CCEAR – other 11,579 12,361 10,691 9,860 13,387
Electricity purchased from Mechanism for Compensation of Surpluses and Deficits of New Energy (MCSD-EN)) 785 - - - -
Electricity purchased from Spot Market – CCEE 536 23 34 215 -
Electricity purchased from others 7,571 8,093 9,208 9,994 10,361
Total electricity purchased by Copel Distribuição(5) 26,162 26,139 25,751 26,090 29,863
Copel Comercialização          
Electricity purchased from Copel Geração e Transmissão 7,275 5,125 2,422 27 -
Electricity purchased from others 5,077 3,330 4,101 2,644 59
Electricity purchased from Spot Market – CCEE 97 34 2    
Total electricity purchased by Copel Comercialização 12,449 8,489 6,525 2,671 59
Total electricity generated and purchased by Copel Geração e Transmissão, Copel Distribuição, Wind Farms and Copel Comercialização 57,383 54,538 51,835 50,813 56,559

 

(1) In 2018, Copel adopted the criteria set forth by the CCEE to determine the energy flows in sale and purchase transactions. The energy amounts reflected in this table, even with respect to past years, were calculated in accordance with the criteria adopted by the CCEE.

(2) Includes the electrical losses of wiring and interconnecting station and technical losses by delivering energy to the Interconnected System.

(3) Electricity generated and purchased by our wind farm generation facilities which were under the supervision of Copel Renováveis until 2015. In December 2015, Copel Geração e Transmissão became responsible for the operation of these facilities.

(4) Distribution companies operating under concessions in the Midwest, South and Southeast regions of Brazil purchase electricity generated by Itaipu.

 
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The following table shows the total electricity we sold to Free Customers, Captive Customers, distributors, energy traders and other utilities service providers in the south of Brazil through the Interconnected Transmission System in the last five years.

 

Year ended December 31,

 

2020

2019

2018

2017

2016

  (GWh)
Copel Geração e Transmissão(1)          
Electricity delivered to Free Customers 3,364 4,146 3,960 3,860 3,600
Electricity delivered to Bilateral Agreements (Copel Comercialização) 7,238 5,123 2,969 27 -
Electricity delivered to Bilateral Agreements 2,786 3,724 5,826 8,477 7,908
Electricity delivered under auction – CCEAR – affiliates(2) 123 122 92 86 157
Electricity delivered under auction – CCEAR – other(2 2,221 2,215 876 838 3,154
Electricity delivered to Spot Market – CCEE(2) (203) (594) 213 1,246 (252)
Electricity delivered to the Interconnected System 939 3,203 4,556 6,529 10,895
Total electricity delivered by Copel Geração e Transmissão 16,627 17,940 18,492 21,063 25,462
Wind Farms(1) (3)          
Electricity delivered under auction – CCEAR – affiliates 31 31 - - -
Electricity delivered to Bilateral Agreements (Copel Com) 37

-

-

-

-

Electricity delivered under auction – CCEAR – other 1,291 1,288 840 840 842
Electricity delivered under auction – CER – other 917 914 334 357 358
Total electricity delivered by Wind Farms 2,276 2,233 1,174 1,197 1,200
Copel Distribuição          
Electricity delivered to Captive Customers 19,180 19,784 19,594 19,743 22,328
Electricity delivered to distributors in the State of Paraná 76 164 279 521 614
Spot Market – CCEE(4) 3,787 3,143 2,401 2,510 3,611
Total electricity delivered by Copel Distribuição 23,043 23,091 22,274 22,774 26,553
Copel Comercialização          
Electricity delivered to Free Customers 4,620 2,715 2,096 771 58
Electricity delivered to Bilateral Agreements (Copel GeT) 516 216 180 628 -
Electricity delivered to Bilateral Agreements 6,984 5,506 4,223 1,254 -
Electricity delivered to Spot Market – CCEE 329 52 26 18 1
Total electricity delivered by Copel Comercialização 12,449 8,489 6,525 2,671 59
Subtotal 54,395 49,930 48,465 47,705 53,274
Losses by Copel Distribuição and Wind Farms5) 3,211 2,808 3,370  3,108 3,285
Total electricity delivered by Copel Geração e Transmissão, Copel Renováveis, Copel Distribuição and Copel Comercialização, including losses 57,606 52,738 51,835 50,813 56,559

 

(1) In 2018, Copel adopted the criteria set forth by the CCEE to determine the energy flows in sale and purchase transactions. The energy amounts reflected in this table, even with respect to past years, were calculated in accordance with the criteria adopted by the CCEE. (2) Amounts indicated as less than zero (negative numbers) refer to the consolidated purchase of electricity from the Spot Market along the year.

(3) Electricity generated and purchased by our wind farm generation facilities which were under the supervision of Copel Renováveis until 2015. In December 2015, Copel Geração e Transmissão became responsible for the operation of these facilities.(4) Includes the MCSD and MVE.(5) Includes Technical, Non-technical and Basic network losses of Copel Distribuição and losses related to the Wind Farms.

 

 
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Generation

 

As of December 31, 2020, considering only the entities in which we hold a 100.0% shareholding stake and 51.0% and 30.0% of the energy generated by Mauá and Baixo Iguaçu Hydroelectric Plants, respectively (corresponding to the interest we hold in each of these assets), we operated and sold energy through nineteen (19) hydroelectric plants, twenty five (25) wind plants and one (1) Thermoelectric Plant, with a total installed capacity of 5,742 MW. Our assured energy totaled an average of 2,571 MW in 2020. Our generation varies yearly as a result of hydrological conditions and other factors. We generated 12,665GWh in 2020, 19,812 GWh in 2019, 19,935 GWh in 2018, 21,469 GWh in 2017 and 27,944 GWh in 2016.

Considering the installed capacity of all of the generation companies in which we have an interest (equity or otherwise), our total installed capacity as of December 31, 2020, was 6,399.6 MW.

The generation of electrical energy at our power plants is supervised, coordinated and operated by our Generation and Transmission Operation Center in the city of Curitiba. This operation center is responsible for coordinating the operations related to major part of our total installed capacity, including some of the plants in which we hold only partial ownership interests.

Hydroelectric Generation Facilities

 

The following table sets forth certain information related to our main hydroelectric plants in operation during 2020:

Plant

Installed capacity

Assured energy (1)

Placed in service

Concession expires

  (MW) (GWh/yr)    
Foz do Areia 1,676.0 5,299.39 1980 September, 2023
Segredo 1,260.0  5,081.54 1992 November, 2029
Salto Caxias 1,240.0 5,319.59 1999 May, 2030
Capivari Cachoeira(2) 260.0 957.46 1970 January, 2046
Mauá 185.2(3) 885.43 2012 July, 2042
Baixo Iguaçu 105,06(4) 454.13 2019 October, 2049
Colíder 300 1,564.43 2019 January, 2046
Others 102.7 513.86 N/A N/A

 

(1) Values used to determine volumes committed for sale.

(2) On January 5, 2016, Copel Geração e Transmissão executed a concession agreement with ANEEL so that it will continue to operate this plant under an operation and maintenance regime until 2046.

(3) Corresponds to 51.0% of the installed capacity of the plant (363.1 MW), corresponding to the interest we hold in this plant, as we operate this plant through a consortium.

(4) Corresponds to 30.0% of the installed capacity of the plant (350.2 MW), corresponding to the interest we hold in this plant, as we operate this plant through a consortium.

 

Governador Bento Munhoz da Rocha Netto (“Foz do Areia” Plant). The Foz do Areia Hydroelectric Power Plant is located on the Iguaçu River, approximately 350 kilometers southwest of the city of Curitiba.

 

Copel Geração e Transmissão SA (“Copel GeT”) held the concession for the exploration rights of the Governador Bento Munhoz da Rocha Netto Hydroelectric Power Plant (“UHE GBM”), in accordance with the Concession Agreement No. 045/1999, with the term of such concession until September, 2023. On the occasion of the termination of such concession, it is the Brazilian government’s responsibility to launch a new competitive bidding process for UHE GBM 's exploration rights, with wide competition between agents in the sector. Decree 9.271/18 allows the Brazilian government to grant a new concession contract for a period of up to 30 years to the winning legal entity of the privatization bidding of a public electricity generation service concessionaire under the control of the States.

 
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The Company carried out studies to analyze the feasibility of becoming the winner in the future bidding process, and in the administrators’ assessment, the appetite of foreign investors represents a high risk for Copel, which may not be sufficiently competitive in the event of more efficient agents, or with lower financial cost for investments.

In this context, Copel GeT incorporated FDA and requested ANEEL for the transfer of the public electricity generation service for the plant in question. The transfer of the concession rights of UHE GBM to FDA took place under the terms of ANEEL Authorization Resolution No. 8,578, of February 11, 2020 and the Concession Contract for Generation of Electricity destined to the Public Service between FDA No. 002/2020.

On March 3, 2020, for the purposes of the provisions of Article 1st §2nd, item II of Decree No. 9.271/2018 (as amended by Decree No. 10.135/2019), Companhia Paranaense de Energia - Copel and Copel Geração e Transmissão S.A. filed a petition with the Ministry of Mines and Energy, through which they expressed their intention to privatize, by means of the sale of FDA’s control, associated with obtaining a Concession Agreement for 30 (thirty) years, counted as from its signing date, for the Governador Bento Munhoz da Rocha Netto Hydroelectric Plant. The petition provided that the privatization bidding, by means of the sale of FDA’s control, will be effected only after the acknowledgement and evaluation of the conditions involved in obtaining the concession rights, especially those related to the payment of the concession rights, in addition to the respective procedures and governance therefore.

In relation to the new concession agreement, the Ministry of Mines and Energy is responsible for defining the physical guarantee of energy, which should be included in the concession contract, as per §2º of art. 2 of Decree No. 5.163/2004.

On February 4, 2021, the Ministry of Mines and Energy published Directive (Portaria) No. 516/2021, which sets the physical guarantee of UHE GBM at 596.0 MWm (assured energy at 5,220.96 GWh/yr). The value is conditioned to the execution of the new concession agreement to be entered into by the company resulting from the privatization process, according to Decree No. 9,271/2018. The original value defined by the Ministry of Mines and Energy was 593.8 MWm (assured energy of 5,201.69 GWh/yr), however the value was revised after the approval of new parameters resulting from the modernization process of Generating Units 1, 2, and 4, approved by ANEEL through Order No. 3,245/2020. After reviewing the calculation of the physical guarantee of UHE GBM, the defined value is 596.0 MWm (assured energy at 5,220.96 GWh/yr).

 

Governador Ney Aminthas de Barros Braga (“Segredo” Plant). The Segredo Hydroelectric Power Plant is located on the Iguaçu River, approximately 370 kilometers southwest of the city of Curitiba.

Governador José Richa (“Salto Caxias” Plant). The Salto Caxias Hydroelectric Power Plant is located on the Iguaçu River, approximately 600 kilometers southwest of the city of Curitiba.

Governador Pedro Viriato Parigot de Souza (“Capivari Cachoeira” Plant). The Capivari Cachoeira Hydroelectric Power Plant is the largest underground hydroelectric plant in Southern Brazil. The reservoir is located on the Capivari River, approximately 50 kilometers north of the city of Curitiba, and the power station is located on the Cachoeira River, approximately 15 kilometers from the reservoir.

Our former concession agreement for the Capivari Cachoeira Plant expired on July 7, 2015. Although Copel Geração e Transmissão did not elect to renew the original concession pursuant the 2013 Concession Renewal Law, it participated in the new competitive bidding process and won. On January 5, 2016, Copel GeT executed a concession agreement with ANEEL, allowing it to continue to operate this plant under an operation and maintenance regime until January 5, 2046. We paid a total of R$574.8 million as the signing bonus for this concession and we received an annual generation revenue (AGR) of R$144.1 million from January 5, 2016 to December 31, 2016. This AGR is subject to an annual tariff adjustment. In July 2017, the AGR was adjusted to R$114.1 million for the period from July 2017 to June 2018 pursuant to the ANEEL Resolution No. 2,265/2017, and in 2018 the AGR was adjusted to R$119.2 million for the period from July 2018 to June 2019 pursuant ANEEL Resolution No. 2,421/2018. In 2019 the AGR was adjusted to R$123,7 million for the period from July 2019 to June 2020 pursuant ANEEL Resolution No. 2,587/2019. In 2020 the AGR was adjusted to R$127.9 million for the period from July 2020 to June 2021 pursuant to ANEEL Resolution No. 2,746/2020.

The Capivari Cachoeira Plant has 260.0MW of installed capacity and assured energy of 957.5 GWh/year. Since January 1, 2017, 70.0% of the energy generated by this plant has been allocated in quotas to the regulated market. Copel GeT will no longer bear the hydrological risk for the energy allocated in quotas under the MRE associated with the Capivari Cachoeira Plant.

 
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Mauá. The Jayme Canet Júnior Hydroelectric Power Plant (Mauá Plant) is located on the Tibagi River, in the State of Paraná. It was constructed between 2008 and 2012 by Consórcio Energético Cruzeiro do Sul, in which we hold a 51.0% interest and CGT Eletrosul holds the remaining 49.0%. The facility is located approximately 250 kilometers from Curitiba, in the Municipality of Telêmaco Borba.

Colíder Hydroelectric Power Plant has an installed capacity of 300.0 MW and it is located on the Teles Pires River, in the State of Mato Grosso, between the municipalities of Nova Canaã do Norte and Itaúba, with the municipalities of Colíder and Cláudia are also affected by the reservoir. The construction of the plant began in 2011 and the work was totally concluded in 2019. The first Generating Unit entered commercial operation on March 9, 2019 and the last unit started operating on December 21, 2019.

Baixo Iguaçu Hydroelectric Power Plant has an installed capacity of 350.2 MW and it is located on the Iguaçu River, in the municipalities of Capanema, Capitão Leonidas Marques, Planalto, Realeza and Nova Prata do Iguaçu, State of Paraná. Baixo Iguaçu HPP is the last large energy project planned for the main Iguaçu and it is located around 30 km downstream from Governador José Richa HPP - the Salto Caxias Hydroelectric Power Plant, which is 100.0% owned by Copel. It was constructed by a consortium in which Copel GeT holds a 30% interest and Geração Céu Azul S.A. holds the remaining 70.0%. This power plant became fully operational on April 10, 2019. In addition to our generation facilities, we have ownership interests in several other hydroelectric generation companies as detailed below.

Between 2004 and 2010, we were required by law to retain a majority of the voting shares of any company in which we obtained an ownership interest. Starting in 2010, it became possible for us to hold non-controlling interests in companies.

The following table sets forth information regarding the hydroelectric generation plants in which we had a partial equity interest as of December 31, 2020:

Plant

 

Installed

capacity

 

Assured

energy

 

Placed in service

 

Our ownership

 

Concession

Expires

    (MW)   (GWh/yr)       (%)    
Elejor Facility
(Santa Clara, Santa Clara I, Fundão and Fundão I)
  246.5   1,211.3   July, 2005
June, 2006
  70.0   May, 2037(1)
December, 2032
Dona Francisca   125.0   664.1   February, 2001   23.0   August, 2033
SHP Arturo Andreoli
(Foz do Chopim)
  29.1   179.2   October, 2001   35.8   April, 2030
UHE Baixo Iguaçu   350.2   1,514.4   April, 2019   30.0   August, 2047

___________________

(1) Elejor Facility adhered on January 14, 2015, with the renegotiation of the hydrological risks, which caused the expiration date to be extended from 2036 to 2037.

Elejor Facility. The Elejor Facility consists of the Santa Clara and Fundão Hydroelectric Power Plants, both of which are located on the Jordão River in the State of Paraná. The aggregate total installed capacity of the units is 246.5 MW, which includes two smaller hydroelectric generation units installed in the same location. Elejor signed a concession agreement with a term of 35 years for the Santa Clara and Fundão plants in October 2001. As of December 31, 2020, we own 70.0% of the common shares of Elejor, and Paineira Participações owns the remaining 30.0 %.

Elejor is required to make monthly payments to the Brazilian government for the use of hydroelectric resources, which in 2001 totaled R$19.0 million. This amount is adjusted on an annual basis by the IGP-M Index.

We had a power purchase agreement with Elejor, which provides that we will purchase all of the energy produced by the Santa Clara and Fundão facilities at a set rate until April 2019, to be adjusted annually in accordance with the IGP-M Index. This agreement was terminated, there was no renewal and Elejor is selling the energy in the Free Market. In 2020, Elejor’s net revenues and loss were R$194.8 million and R$29.4 million, respectively, while in 2019 its net revenues and net profits were R$218.4 million and R$26.1 million, respectively.

 
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Dona Francisca. We own 23.03 % of the common shares of Dona Francisca Energética S.A. (“DFESA”). The other shareholders are Gerdau S.A. with a 51.82% interest, Celesc S.A. with a 23.03% interest and Statkraft S.A. with a 2.12% interest. DFESA Hydroelectric Power Plant is located on the Jacuí River in the State of Rio Grande do Sul. The plant began full operations in 2001. In April 2015, we signed a new ten year power purchase agreement with DFESA, valued at R$17.0 million annually, under which Copel purchases 23.03% of DFESA’s assured energy (proportional to Copel’s stake).

In 2020, DFESA’s net revenues and net profits were R$70.3million and R$42.0million, respectively, while in 2019 its net revenues and net profits were R$70.7 million and R$42.8 million, respectively.

SHP Arturo Andreoli (“Foz do Chopim” Hydroelectric Plant). The Foz do Chopim Hydroelectric Plant is located on the Chopim River in the State of Paraná. We own 35.8% of the common shares of Foz do Chopim Energética Ltda., the entity that owns the Foz do Chopim Hydroelectric Plant. Silea Participações Ltda. owns the remaining 64.2%. The operation and maintenance of Foz do Chopim Hydroelectric Plant is performed by Copel Geração e Transmissão S.A. Energy supply agreements were executed at an Average Tariff of R$220.07/MWh. Foz do Chopim Energética Ltda. also had the authorization to operate Bela Vista SHP, a hydroelectric power plant that is located on the same river and has similar capacity, which was transferred to Bela Vista Geração de Energia S.A. (“Bela Vista Geração”), through the ANEEL’s Authorizing Resolution no. 7.802/2019. In 2020, Foz do Chopim’s net revenues and net profits were R$55.7million and R$26.9million, respectively, while in 2019 its net revenues and net profits were R$56.9 million and R$38.9 million, respectively.

Wind Farm Generation Facilities

Since 2013 we have been expanding our energy generation capacity and diversifying our energy matrix through the development of renewable energy sources, like the construction and acquisition of wind farms in the State of Rio Grande do Norte. The following table sets forth certain information relating to our wind farm plants in operation as of December 31, 2020:

Plant

Installed capacity

Assured Power

Placed in Service

Concession Expires

  (MW) (Average MW)    
São Bento Energia(1) 94.0 46.3    
Boa Vista 14.0 6.3 February, 2015 April, 2046
Olho d'Água 30.0 15.3 February, 2015 May, 2046
São Bento do Norte 30.0 14.6 February, 2015 May, 2046
Farol 20.0 10.1 February, 2015 April, 2046
Palmas 2.5 0.4 November, 1999  September, 2029
Copel Brisa Potiguar Wind Complex (2) 183.6 98.4    
Asa Branca I 27.0 14.2 August, 2015 April, 2046
Asa Branca II 27.0 14.3 September, 2015 May, 2046
Asa Branca III 27.0 14.5 September, 2015 May, 2046
Eurus IV 27.0 14.7 August, 2015 April, 2046
Santa Maria 29.7 15.7 April, 2015 May, 2047
Santa Helena 29.7 16.0 May, 2015 April, 2047
Ventos de Santo Uriel 16.2 9.0 May, 2015 April, 2047
Voltália São Miguel do Gostoso I(3) 108.0 57.1    
Carnaúbas 27.0 13.1 June, 2017 April, 2047
Reduto 27.0 14.4 June, 2017 April, 2047
Santo Cristo 27.0 15.3 June, 2017 April, 2047
 
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São João 27.0 14.3 June, 2017 March, 2047
Cutia Empreendimentos Eólicos(4) 312.9 130.1    
Dreen Cutia 23.1 9.6 December, 2018 January, 2042
Dreen Guajiru 21.0 8.3 December, 2018 January, 2042
Esperança do Nordeste 27.3 9.1 December, 2018 May, 2050
GE Jangada 27.3 10.3 December, 2018 January, 2042
GE Maria Helena 27.3 12.0 December, 2018 January, 2042
GE Paraíso dos Ventos do Nordeste 27.3 10.6 January, 2019 May, 2050
Potiguar 27.3 11.5 December, 2018 May, 2050
Bento Miguel        
São Bento do Norte I 23.1 10.1 January, 2019 August, 2050
São Bento do Norte II 23.1 10.8 January, 2019 August, 2050
São Bento do Norte III 23.1 10.2 April, 2019 August, 2050
São Miguel I 21.0 9.3 February, 2019 August, 2050
São Miguel II 21.0 9.1 February, 2019 August, 2050
São Miguel III 21.0 9.2 February, 2019 August, 2050
         

___________________

(1) Pursuant to Directive (Portaria) No. 360 of September 30, 2020, the projects that are part of the São Bento Energia wind complex had their physical guarantees altered as of January 1, 2021, as follows: Boa Vista (from 6.3 MW to 5.2MW), Olho d'Água (from 15.3 MW to 12.8MW), São Bento do Norte (from 14.6MW to 11.3MW) and Farol (from 10.1MW to 8.8MW).

(2) Pursuant to Directive (Portaria) No. 360 of September 30, 2020, certain the projects that are part of the Copel Brisa Potiguar wind complex had their physical guarantees altered as of January 1, 2021, as follows: Asa Branca I (from 14.2MW to 12.1MW), Asa Branca II (from 14.3 MW to 11.9MW), Asa Branca III (from 14.5MW to 12.3MW) and Eurus IV (from 14.7MW to 12.4MW).

(3) Copel has a 49.0% interest in Voltália São Miguel do Gostoso .

(4) In January 2019, São Bento do Norte I, II and III began their commercial operations with 100% of their installed capacity, while the São Miguel I,II and III began their operation with 100% of their installed capacity in February 2019.

São Bento Energia. On February 25, 2015, the four wind farms (Boa Vista, Olho d’Água, São Bento do Norte and Farol) which are part of the São Bento Wind Farm Complex, located in the State of Rio Grande do Norte, began operations. With an installed capacity of 94 MW and assured energy of 46.3 average-MW. In August 2010, 43.7 average-MW of the energy generated at a weighted average price of R$134.40/MWh (annually adjusted by IPCA index) was sold to fifteen distribution concessionaires in ANEEL public auctions. The energy generated by these wind farms is sold through 20-year term contracts.

Copel Brisa Potiguar Wind Complex. On September 15, 2015, Copel concluded the installation of the Brisa Potiguar Wind Complex with an installed capacity 183.6 MW and assured energy of 98,4 average-MW. An assured energy of 57.7 average-MW (from Asa Branca I, Asa Branca II, Asa Branca III and Eurus IV wind farms) was committed under contract to electric power distributors in the alternative energy auction in August 2010 at a weighted average price of R$135.40/MWh (adjusted annually by IPCA inflation index) and an average of 40.7 MW (from WPPs Santa Helena, Santa Maria and Ventos de Santo Uriel) was committed under contract in the 6th Reserve Energy Auction held in August 2011 at a weighted average price of R$101.98/MWh (annually adjusted by the IPCA inflation index). The energy to be generated was sold through 20-year term contracts with payments beginning in April 2015.

Voltália São Miguel do Gostoso I. In June 2014, we negotiated with Voltalia Energia do Brasil Ltda. (Voltalia) the acquisition of a 49.0% interest in the São Miguel do Gostoso I Wind Farm Complex, in the State of Rio Grande do Norte. The São Miguel do Gostoso wind farm complex has 108.0 MW of installed capacity and assured energy of 57.1 average-MW, and its energy was sold in the 4th Reserve Energy Auction at an average price of R$98.92/MWh through 20-year term contracts. In April 2015, we concluded the construction of this wind farm complex and ANEEL, in July and August 2015, classified it as ready for commercial operation. This wind farm complex began production in June 2017 after completion of the necessary transmission lines.

Cutia. Cutia Empreendimentos Eólicos, which is Copel’s largest wind farm business, is divided into two large complexes totaling 312.9 MW of installed capacity: (a) Cutia Complex, composed of seven wind farms (Guajiru, Jangada, Potiguar, Cutia, Maria Helena, Esperança do Nordeste and Paraíso dos Ventos do Nordeste), with a total installed capacity of 180.6 MW, 71.4 average MW of physical guarantee and located in the State of Rio Grande do Norte; and (b) Bento Miguel Complex, composed of six wind farms (São Bento do Norte I, São Bento do Norte II, São Bento do Norte III, São Miguel I, São Miguel II and São Miguel III) with 132.3 MW of total installed capacity, 58.7 average MW of physical guarantee and located in the State of Rio Grande do Norte, in the same region of other wind farm complexes that belong to us. On October 31, 2014, at the 6th Reserve Energy Auction, we sold 71.2 average MW from the Cutia Complex for R$144.00/MWh (maximum auction price). In addition, at the 20th New Energy Auction (A-5), held on November 28, 2014, we sold 54.8 average MW from the six Bento Miguel wind farms for R$136.97/MWh, through Availability Agreements with a 20-year term.

 
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In December 2018, the wind farms of Cutia, Guajiru and Esperança do Nordeste, all part of the Cutia Complex, began their operations with 100% of their installed capacity. The parks of Jangada, Maria Helena and Potiguar, also part of the Cutia Complex, began their commercial operations in December 2018 with 85%, 54% and 77% of their installed capacity, respectively. On September 20, 2019, according to ANEEL Order No. 2,593 / 2019, the last three Generating Units of the Maria Helena Wind Power Plant were released. With this, the Cutia Wind Complex became fully operational in 2019.

In January 2019, São Bento do Norte I, São Bento do Norte II began their operations, while in February 2019, São Miguel I, São Miguel II e São Miguel III began theirs. In April 2019, São Bento do Norte III began their operations. With this, the Bento Miguel Complex became fully operational.

Thermoelectric Generation Facilities

The following table sets forth certain information about our Thermoelectric Plants in operation as of December 31, 2020:

Plant

Installed

capacity

Assured

energy

Placed in service

Our ownership

Concession/ authorization
expires

  (MW) (GWh/yr)   (%)  
TPP Araucária 484.2 2,604.5(1) September, 2002 81.2 (2) December, 2029
TPP Figueira 20.0 90.5 April, 1963 100.0 March, 2019(3)

___________________

(1) The annual assured energy of thermal plants such as Araucária varies depending on the price of natural gas, according to criteria established by the MME.

(2) Held 20,3% by Copel and 60,9% by Copel GeT.

(3) We are currently waiting for the granting authority to amend our concession agreement with respect to TPP Figueira, extending the concession of the Thermoelectric Plant for another 20 years, pursuant to the Concession Extension Law of 2013

Araucária. We have an 81.2 % interest in UEG Araucária Ltda., which owns the Araucária Thermoelectric Plant, a natural gas thermoelectric power plant, located in the state of Paraná. The Araucária Thermoelectric Plant has 484.2 MW of installed capacity, does not have Availability Agreements currently in force and operates under a business model in which revenue depends on the plant’s operation. When produced, energy will be sold in the Spot Market as directed by the ONS.

As of November 2019, the plant may also have the possibility of being activated in the form of an assignment of energy credits, in accordance with the agreement signed with Petróleo Brasileiro S.A. - Petrobrás and in accordance with Normative Resolution No. 614/2014 from ANEEL. Based on this agreement, in force until December 31, 2020, the plant may be dispatched outside of out-of-merit-order, and the UTE Araucária gas supplier will inform, weekly, if it will activate the plant. In this scenario, the order will not be at the price of the CVU approved by ANEEL, but at a price agreed between the parties, considering, among other factors, market opportunities and margins considered adequate for the plant's operation, thus enabling recovery fixed cost for the order period.

A gas supply agreement was signed between Petróleo Brasileiro S.A - Petrobras and UEG Araucária Ltda - UEGA. The agreement is valid from January 01th to December 31th, 2021 and it provides for the delivery of up to 2,150,000 cubic meters of natural gas per day, without take-or-pay clauses. As a result, TPP Araucária will remain available to the National Interconnected System - SIN and can therefore be dispatched at the discretion of ONS. However, UEG Araucária signed an amendment to the Transfer of Energy Credits agreement with Petróleo Brasileiro S.A. - Petrobras, in accordance with ANEEL's Normative Resolution No. 614/2014, for the same duration as the gas supply agreement. The amendment will allow the plant to be dispatched out-of-merit-order, and the gas supplier will inform TPP Araucária weekly whether it will activate the plant. In this context, dispatch will not be charged at the CVU approved by ANEEL but at the value agreed by the parties, taking into account, among other factors, market opportunities and margins considered adequate for the operation of the plant, thus enabling the recovery of the fixed cost related to the dispatch period. With an installed capacity of 484.2 MW, the combined cycle power plant is one of the most efficient in Brazil.

 
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TPP Araucária was activated on March 8, 2020, according to the schedule for the operational week of ONS. The dispatch order is part of the exceptional measures adopted at the meeting of March 4, 2020 by the Electric Sector Monitoring Committee (“CMSE”) for the recovery of hydroelectric reservoirs in the southern region of the country. The plant's remuneration, therefore, will be based on the Variable Cost per Unit - CVU approved by ANEEL, in the amount of R$681.79/MWh.

Figueira. The Figueira plant is located in the city of Figueira, in the northeast of the state of Paraná (where the main coal basin of Paraná is located). This plant is currently in a modernization process, which consists of replacing the old equipment for new equipment. This process aims to make this plant more efficient, reduce emissions of gases and particles resulting from the burning of coal and comply with applicable environmental legislation.

After the modernization, the plant will have the installed capacity of 20.0 MW with only one Generating Unit and the physical guarantee of 17.7 MW, so that it is in compliance with Normative Resolution No. 801/2017, which defines a minimum efficiency of 25% for installations with installed capacity up to 50.0 MW.

Expansion and Maintenance of Generating Capacity

We expect to spend R$429.8 million in 2021 to expand and maintain our generation capacity, including participation in new businesses, of which R$270.2 million will be invested in Jandaíra wind farm, R$35.6 million will be invested in Figueira Thermal Power Plant and R$22.0 million will be invested in the Cutia wind farm. The remaining amount will be spent on equipment maintenance, the modernization of the HPP Foz do Areia, SHP Bela Vista, Brisa Potiguar and São Bento Wind Farm Complex and other projects.

Hydroelectric Power Plant Projects

We have interests in several hydroelectric generation projects. The following table sets forth information regarding our major hydroelectric generation projects under construction.

Facility

Installed capacity

Estimated

assured energy (1)

Budgeted completion cost

Beginning of operation

Our ownership

Status

  (MW) (GWh/year) (R$million)   (%)  
SHP Bela Vista 29 145 200 January, 2024 100.0 Concession granted

___________________

(1) Values used to determine volumes committed for sale.

Bela Vista. In August 2018, we participated in the A-6 auction as a member of the Consórcio Bela Vista Geração and sold 14.7 MW of the SHP Bela Vista, at a price of R$195.70 / MWh. With an estimated investment of R$200.0 million, the Bela Vista SHP has 29 MW of installed capacity and 16.6 MW of assured power and is under construction in the Chopim river, in the São João and Verê Municipalities, located in the southwest of the State of Paraná. The energy sales agreement will be in force as of January 1, 2024, for a 30-year term and will be subject to an annual readjustment by the IPCA. The construction of this facility began in the first semester of 2019.

 
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Wind Farm Projects

The following table sets forth information regarding our wind farm projects, all of which currently refer to the Jandaíra wind farm (Complexo Eólico Jandaíra). In October 2019, Copel GeT and its subsidiary Cutia wind farm (Cutia Empreendimentos Eólicos) joined the Auction ANEEL A-6 for new energy generation and sold an average of 14.4 MW from the Jandaíra wind farm for R$98.00 MW/h. We expect to invest R$411.6 million in this new wind farm, which has an installed capacity equivalent to 90.1 MW and a physical guarantee equivalent to 47.6 MW. The Jandaíra wind farm will be built in the state of Rio Grande do Norte, and, as other wind farm assets of Copel are located in the same region, we believe that this project may benefit from operational synergies related to our projects that are already operating.

The amount of energy sold in October 2019 corresponds to 30% of the project’s physical guarantee. Pursuant to the power purchase agreement executed in connection with the above, such amount of energy shall be supplied as from January 1, 2025, this agreement will be in force for 20 years and prices will be adjusted pursuant to the IPCA index. Any additional energy generated by the Jandaíra wind farm will be negotiated in the Free Market.

Wind Farm

Installed capacity

Estimated Assured Power

Budgeted completion cost

Beginning of commercial operation(1)

Our ownership

Concession

expires

  (MW) (Average MW) (R$million)   (%)  
Jandaíra 90.1 47.6 411.6 May, 2022 100.0 April 2055
Jandaíra I 10,4 5.3 - - 100 April 2055
Jandaíra II 24,3 13.5 - - 100 April 2055
Jandaíra III 27.7 14.6 - - 100 April 2055
Jandaíra IV 27.7 14.2 - - 100 April 2055

___________________

(1)The beginning of commercial operation of each wind farm will occur as of May 2022, in a staggered manner. On January 1, 2025, the beginning of supply of the regulated environment contracts will take place.

 

Development Projects

We are involved in various initiatives to study the technical, economic and environmental feasibility of certain hydroelectric, wind, solar photovoltaic and thermoelectric generation projects. The following table sets forth information regarding our proposed generation projects that are considered feasible under a technical, economic, social, environmental and land-related perspective pursuant to the above-mentioned studies.


Proposed Projects(1)

Estimated Installed Capacity

Estimated Assured Energy

Our Ownership
  (MW) (GWh/yr)

(%)

HPP São Jerônimo 330.0 1,560.2 41.2
WPP Complexo Alto Oriente 62.4 262.2 100.0
HPP Salto Grande 49.0 221.3 100.0
SHP Salto Alemã 29.8 160.8 19.0
TOTAL 471.2 2,204.5 -

___________________

(1)Do not include other proposed projects of Copel whose technical, economic, social, environmental and land-related feasibility is still under analysis.

Copel is also a member of Consortium Geração Luz Paranaense – CGLP, which was granted with exploration rights related to the following projects: (i) SHP Foz do Curucaca, (ii) SHP Salto Alemã, (iii) SHP Alto Chopim and (iv) SHP Rancho Grande. After obtaining the applicable authorization from ANEEL and evaluating the hydraulic potential of each project, the consortium decided to carry out the studies only with respect to SHP Salto Alemã and SHP Foz do Curucaca and to return the exploration rights for SHP Alto Chopim and SHP Rancho Grande projects to ANEEL. The basic designs of SHP Salto Alemã and of SHP Foz do Curucaca had already been approved by ANEEL and the environmental studies related to this project were registered in the competent entity (IAT – Instituto Água e Terra do Paraná or “IAT”) for analysis.

 
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Since 2018, COPEL has held the rights of the HPP Salto Grande, located in the Chopim River in the state of Paraná. The environmental studies related to this project were registered with IAT for analysis in February 2020 and the basic design was approved by ANEEL in November 2020.

Taking into account that four energy auctions are planned in 2021, we intend to bid for concessions to construct and operate new hydroelectric and solar photovoltaic plants or wind farms in power auctions in the regulated market for new generation projects. We are studying the feasibility of our participation in the hydroelectric, wind farms and solar photovoltaic projects planned to be listed in the auctions of 2021 or sell the energy in the unregulated electricity market (Free Market). We will also conduct studies of new hydroelectric power plants. For instance, we have partnered with BE - Empresa de Estudos Energéticos S.A., Minas PCH S.A. and SILEA Participações Ltda. to develop studies in the lower region of the Chopim River, which may lead to the development of another four (4) hydroelectric projects. We are also conducting studies related to future government auctions for wind farms, solar photovoltaic and hydropower plants, small hydroelectric plants and thermoelectric power plants in which we may eventually participate. Other renewable energy projects under study or development include the use of municipal solid waste in power generation, and thermosolar energy. For instance, since 2017, Copel has conducted solarimetric measurements in two solarimetric stations located in areas leased by Copel Brisa Potiguar. The development of solar energy projects in such areas is still under analysis and the corresponding studies are expected to be concluded as to be able to submit such projects to energy auctions in 2021.

We are also developing studies for the implementation / acquisition of projects related to Generation Distribution, Biomass (sugar cane and forest residues), Biogas and Natural Gas. In addition to energy generation projects, investment opportunities in new energy transmission assets whose concession will be auctioned by the Brazilian government or existing assets that have synergy with our current portfolio are also being studied.

Transmission and Distribution

General

Electricity is transferred from power plants to customers through transmission and distribution systems. Transmission is the bulk transfer of electricity from generating facilities to the distribution system by means of the Interconnected Transmission System, in tension greater than or equal to 230 kV. Distribution is the transfer of electricity to Final Customers, in tension lesser or equal to 138 kV.

The following table sets forth certain information concerning our transmission and distribution grids on the dates presented.

 

As of December 31,

 

2020

2019

2018

2017

2016

Transmission lines (km):          
230 kV and 500 kV 3,127.6 3,127.6 3,025.4 2,691. 8 2,514.0
138 kV 7.2 7.2 7.2 7.2 7.2
69 kV(1) - - - - -
Distribution lines (km):          
230 kV(2) - - - - 165.5
138 kV 6,547 6,506.7 6,264.8 5,935.0 5,970.3
69 kV 755 755.6 751.2 866.4 695.4
34.5 kV 86,489 85,734.5 85,185.2 84,639.2 84,071.3
13.8 kV 108,384 106,955.7 106,172.4 105,510.6 104,556.0
Transformer capacity (MVA):          
Transmission and distribution substations (69 kV – 500 kV)(3) 23,918.2 23,860.2 22,825.1 22,849.3 22,535.4
Generation (step up) substations 6,691.0 6,691.0 6,355.0 6,335.0 6,335.0
Distribution substations (34.5 kV) 1,594.2 1,545.8 1,502.3 1,537.9 1,488.5
Distribution transformers 14,180.8 13,800.9 13,404.6 12,956.9 12,548.2
Total energy losses(4) (5) 7.8% 7.0% 8.3% 7.8% 8.1%
 
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___________________

(1) As approved by ANEEL in 2008, these 69 kV transmission lines held by Copel Distribuição were transferred to Copel Geração e Transmissão, since they were part of our transmission business segment.

(2) Due to improvements to registration and control systems used by Copel Distribuição to classify and register its transmission lines, lines were classified pursuant to its insulation voltage, and not according to its structure and isolate components. Consequently, all lines previously registered by Copel Distribuição were reclassified and there are no lines classified as 230 kV anymore.

(3) This figure includes transformers with primary tensions of 69 kV and 138 kV which belong to Copel Distribuição but are implemented in 230 kV and 525 kV substations, which belong to Copel Geração e Transmissão.

(4) Percentage of losses on the energy injected in the distributor (technical and non-technical losses on injected energy). Does not consider losses in the basic network.

(5) We note that percentages measured until 2016 and reported in previous reports of the Company reflected the amounts of physical losses (Technical), commercial losses (Non-Technical) and losses on the basic network (allocation of agreements on the gravity center of the submarket) of Copel Distribuição, as well as the losses related to the allocation of agreements of Copel GeT. Those percentages were calculated taking into account the total of power purchased and sale agreements entered into by both Copel Distribuição and Copel GeT. For a better representation and comparison of the percentage of losses, we considered the percentage obtained by dividing the total amount of technical and non-technical losses by the energy injected into the network of Copel Distribuição. This percentage may be compared to other companies and has a more accurate physical meaning as it utilizes the database of measured data and not information taken from agreements of the period being analyzed.

 

Transmission

Our transmission system consists of all our assets of 230 kV and greater and a small portion of our 69 kV and 138 kV assets, which are used to transmit the electricity we generate and the energy we receive from other sources. In addition to using our transmission lines to provide energy to customers in the State of Paraná, we also transmit energy through the Interconnected Transmission System. Two companies owned by the Brazilian government, Companhia de Geração e Transmissão de Energia Elétrica do Sul do Brasil – CGT Eletrosul and Furnas, also maintain significant transmission systems in the State of Paraná. Furnas is responsible for the transmission of electricity from Itaipu, while CGT Eletrosul’s transmission system links the states in the south of Brazil. Copel, like all other companies that own transmission facilities, is required to allow third party access to its transmission facilities in exchange for compensation at a level set by ANEEL.

Currently, we carry out the operation and maintenance of 3,524 km of transmission lines, forty one (41) substations in the State of Paraná and two (2) substations in the State of São Paulo. In addition, we have partnerships with other companies to operate 4,028 km of transmission lines and seven (7) substations through special purpose companies (SPCs).

The table below sets forth information regarding our transmission assets in operation:

Subsidiary / SPC

Transmission Lines

TL Extension

(km)4

Number of Substations

Concession Expiration Date

Our Ownership

APR ¹
(R$million)

COPEL GeT Main Transmission Concession(1) 2,026 34 December, 2042 100.0% 505.4
COPEL GeT TL Bateias - Jaguariaiva 137 - August, 2031 100.0% 11.6
COPEL GeT TL Bateias - Pilarzinho 32 - March, 2038 100.0% 1.1
COPEL GeT TL Foz - Cascavel Oeste 116 - November, 2039 100.0% 12.7
COPEL GeT Cerquilho III Substation - 1 October, 2040 100.0% 5.2
COPEL GeT

TL Londrina – Figueira

Foz do Chopim – Salto Osório

102 - August, 2042 100.0% 6.2
COPEL GeT

TL Assis – Paraguaçu Paulista

Paraguaçu Paulista II Substation

83 1 February, 2043 100.0% 9.7
COPEL GeT

Curitiba Norte Substation

TL Bateias – Curitiba Norte

31 1 January, 2044 100.0% 10.2
COPEL GeT

Realeza Sul Substation

TL Foz do Chopim- Realeza Sul

52 1 September, 2044 100.0% 8.0
 
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COPEL GeT TL Assis – Londrina 122 - September, 2044 100.0% 20.8
COPEL GeT TL Araraquara II – Taubaté 334 - October, 2040 100.0% 32.0
COPEL GeT

TL Baixo Iguaçu – Realeza

TL Curitiba Centro – Uberaba

TL Curitiba Leste - Blumenau

188 3 April, 2046 100% 119.1
Uirapuru (Copel GeT – 100%)(2) TL Ivaiporã - Londrina 120 - March, 2035 100% 37.1
Costa Oeste (Copel GeT – 100%) LT Cascavel Oeste - Cascavel Norte
TL Cascavel Norte -  Umuarama Sul
152 1 January, 2042 100% 12.8
Marumbi   (Copel GeT – 100%) TL Curitiba – Curitiba Leste 29 1 May, 2042 100% 19.9
Subtotal Copel GeT 3,524 43     811.7
Caiuá Transmissora TL Guaíra - Umuarama Sul
TL Cascavel Norte - Cascavel Oeste
Santa Quitéria Substation / Cascavel Norte Substation
142 2 May, 2042 49.0%(3) 11.8
Integração Maranhense LT Açailandia-Miranda II 365 - May, 2042 49.0%(3) 17.8
Matrinchã TL Paranaíta - Ribeirãozinho 1,005 3 May, 2042 49.0%(3) 97.7
Guaraciaba TL Ribeirãozinho - Marimbondo 600 1 May, 2042 49.0%(3) 48.4
Paranaíba TL Barreiras II - Pirapora II 953 - May, 2043 24.5%(3) 35.4
Cantareira TL Estreito – Fernão Dias 342 - September, 2044 49.0%(3) 52.2
Mata de Santa Genebra TL Araraquara II - Atatiba
TL Bateias - Atatiba
621 1 May, 2044 50.1%(3) 124.6
Subtotal SPCs   4,028 7     388.0
Total   7,552 50     1,199.7

___________________ 

(1) Our main transmission concessions encompasses several transmission lines.

(2) In March 2019, Copel GeT signed a purchase and sale agreement with Centrais Elétricas Brasileiras SA and Fundação Eletrosul de Previdência e Assistencial Social - Elos to transfer 100% of shares issued by SPE Uirapuru Transmissora de Energia S.A.. In June, 2019 Copel GeT took over the stake control of the company.

(3) Refers to the equity interest held by Copel Geração e Transmissão.

(4) Considers double circuits as a single extension.

Expansion and Maintenance of Transmission Facilities

The construction of new transmission facilities of 230 kV and higher must be awarded in a bidding process or otherwise authorized by ANEEL. We are permitted by ANEEL to make minor improvements to some of the existing 230 kV and 500 kV facilities.

In November 2013, SPC Mata de Santa Genebra Transmissora, a strategic partnership between Copel (50.1%) and Furnas (49.9%), won the right to build and operate 847 km of transmission lines and three substations in the States of Paraná and São Paulo. The construction schedule of the Mata de Santa Genebra project was affected by successive vandalism events, which resulted in the collapse of towers and theft of aluminum cables in transmission lines already installed and commissioned, in different sections of the project. On November 11, 2020, the LT 440 kV Fernão Dias / Taubaté, the last asset of the SPC Mata de Santa Genebra project, began its commercial operation. With the completion of these steps, the SPC Mata de Santa Genebra became fully operational. The project an APR of R$ 248.7 million, of which R$ 124.6 million are related to COPEL's stake.

In November 2015, Copel GeT won ANEEL’s public auction No. 005/2015 for the construction and operation of 188 km of transmission lines in the States of Paraná and Santa Catarina, and three (3) substations in the State of Paraná, with a total capacity of 900 MVA. With an APR of R$119.1 million, the corresponding concession agreement was signed in April 2016, and, the remaining facility which was still under construction, the transmission line Curitiba Leste - Blumenau, become operational in April 1, 2021. This facility had an auction APR of R$ 24.9 million and in current values, it has an APR of R$ 38.6 million, approved for 2020-2021 tariff adjustment cycle.

 
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Distribution

Our distribution system consists of a widespread network of overhead lines and substations with voltages up to 138 kV assets. Higher Voltage electricity is supplied to bigger industrial and commercial customers and lower voltage electricity is supplied to residential, small industrial, and commercial customers in addition to other customers. As of December 31, 2020, we provided electricity in a geographic area encompassing approximately 97% of the State of Paraná and served 4.8 million customers.

Our distribution grid includes 202,085 km of distribution lines, 446,549 distribution transformers and 230 distribution substations of 34.5 kV, 36substations of 69 kV and 112 substations of 138 kV. During 2020, 122,612 new captive customers were connected to our network, including customers connected through the rural and urban electrification programs. We are continuing to implement compact grid design distribution lines in urban areas with large concentration of trees in the vicinity of the distribution grid.

We have five (5) captive customers that are directly supplied with energy at a high voltage (69 kV and above) through connections to our distribution lines. The volume of energy commercialized for these customers was 25.272MWh in 2020.

We are also responsible for expanding the 138 kV and 69 kV distribution grid within our concession area to meet any future demand growth.

On October 16, 2019 Copel Distribuição launched a program to modernize its distribution grid called “Transformation Program” (Programa Transformação). The Transformation Program is comprised of three projects: “Total Reliability” (Confiabilidade Total), “Three-phase Paraná” (Paraná Trifásico) and “Smart Grid Copel”. The goal is to improve infrastructure, particularly in rural areas, in order to enhance quality of energy supply and reduce supply restoration period in case of power outages. With investments of up to R$2.9 billion until 2025, which shall compose the Regulatory Remuneration Base, the Transformation Program involves the construction of approximately twenty-five 25,000 kilometers of power grids, 15,000 new automated power connections and the setting up of smart grid technology in the State of Paraná. The Smart Grid Project deals with the implementation of a communication network for distribution automation equipment and for smart meters. In addition, computer systems for efficient management of this communication network are included in this project.

Performance of the Distribution System

Total losses are commonly divided into a technical and non-technical component. Technical losses are inherent to the transportation of electricity and consist mainly of power dissipation in the line network. Non-technical (or commercial) losses are caused by actions external to the power system (for instance, electricity theft). Since total losses are comprised of both technical and non-technical parcels, the latter is easily calculated as the difference between total losses and the estimated technical losses inherent to the system.

Total losses in our distribution system are segmented between (i) losses in the basic network (tension equal to or greater than 230kV), which are external to our distribution grid and have a technical cause, and (ii) losses in the distribution network (internal to our distribution grid), which are usually caused by both technical and non-technical reasons.

Losses in the basic network are calculated monthly by the CCEE as the difference between the total generation and the energy effectively delivered to the distribution networks. The total losses from our distribution grid are calculated as the difference between the energy allocated to the system and the energy supplied to the customers.

Our total energy distribution losses (including transmission system, technical and commercial losses) totaled 9.4% of the total energy amount available in 2020, being (i) 1.6% related to losses in the basic network, (ii) 6.0% of technical losses and (iii) 1.8% of non-technical losses.

 
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ANEEL grants the transfer of all energy losses to the final consumers when the real losses are less than regulatory losses. The calculation is made within the regulatory period, that is different from a civil year, and thereby we will know the result just in the next tariff adjustment, in June 2021. But our simulation indicates that in the civil year, from January through December 2021, we will have all losses transferred to the final consumers.

Furthermore, ANEEL requires distributors to observe certain standards for “energy supply continuity”, namely (i) duration of outages per customer per year or DEC – Duração Equivalente de Interrupção por Unidade Consumidora and (ii) frequency of outages per customer per year or FEC – Frequência Equivalente de Interrupção por Unidade Consumidora. Information regarding the duration and frequency of outages for our customers is set forth in the following chart for the years indicated.

   

Quality of supply indicator

2020

2019

2018

2017

2016

DEC – Duration of outages per customer per year

(in hours)

7h50min 09h07min 10h19min 10h28min 10h49min
FEC – Frequency of outages per customer per year (number of outages) 5.61 6.02 6.22 6.83 7.23

We comply with the quality indicators defined by ANEEL for 2020, which penalizes power outages in excess of an average number of hours per customer, in each case calculated on an annual basis. These limits vary depending on the geographic region, and the average limit established by ANEEL for our distribution company was 9 hours and 47 minutes of outages per customer per year, and a total of 7.38 outages per customer per year. Failure to comply with these predetermined standards with a Final Customer results in a reduction of the amount we can charge such Final Customer in future periods.

In addition, quality target indicators are taken into consideration by ANEEL during distribution concession renewal proceedings, and also influence ANEEL’s calculation of our tariff adjustments. For more information, see “–Concessions–Distribution Concessions” and “–The Brazilian Electric Power Industry–Distribution Tariffs”.

Purchases for the captive market

The following table contains information concerning volume, cost and Average Tariff for the main sources of the electricity we purchased for the captive market in the last three years.

Source

2020

2019

2018

Itaipu      
Volume (GWh) 5,498 5,533 5,726  
Cost (R$millions) 1,766.1 1,317 1,272.2
Average Tariff (R$/MWh) 327.09 238 222.18
Angra      
Volume (GWh) 968 979 1,009
Cost (R$millions) 269 248 250.3
Average Tariff (R$/MWh) 277.73 253 248.07
CCGF      
Volume (GWh) 6,136 6,274 6,520
Cost (R$millions) 673 642 593.0
Average Tariff (R$/MWh) 109.68 102.32 90.95
Auctions in the regulated market      
Volume (GWh)(1) 11,733 12,515 10,783
Cost (R$millions)(2) 2,207 2,257 2,080.8
Average Tariff (R$/MWh) 188.08 180.34 192.97

___________________

(1) These numbers do not include assignments related to MCSD-EN and MVE.

(2) These numbers do not include short-term energy purchased through the CCEE.

 
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Itaipu

We purchased 5,498 GWh of electricity from Itaipu in 2020, which constituted 9.8%% of our total available electricity in 2020 and 22.1% of Copel Distribuição’s total available electricity in 2020. Our purchases represented approximately 7.2% of Itaipu’s total production. Distribution companies operating under concessions in the midwest, south and southeast regions of Brazil are required by law to purchase Brazil’s portion of the energy generated by Itaipu in a proportion that correlates with the volume of electricity that they provide to customers. The rates at which these companies are required to purchase Itaipu’s energy are fixed to cover Itaipu’s operating expenses and payments of principal and interest on Itaipu’s U.S. dollar-denominated borrowings, as well as the cost of transmitting the power to their concession areas. These rates are denominated in U.S. dollars, and have been set for 2021 at US$ 28.07 per kW per month.

In 2020, we paid an Average Tariff of R$ 327.09/MWh for energy from Itaipu, compared to R$237.94/MWh in 2019. These figures do not include the transmission tariff that distribution companies must pay for the transmission of energy from Itaipu.

ANGRA

Because Eletronuclear renewed the generation concession of Angra under the 2013 Concession Renewal Law, the energy generated by Angra is no longer sold in auctions in the regulated market. Rather, under the 2013 Concession Renewal Law, this energy is sold to distributors in accordance with the quota system established by said law. For more information, see “Item 4. Information on the Company—The Brazilian Electric Power Industry”. As a result, Copel Distribuição was legally required to purchase 968 GWh from Angra in 2020, 979GWh from Angra in 2019 and 1,009 GWh in 2018.

Assured Power Quota Contract – CCGF

Under the 2013 Concession Renewal Law, certain generation concessionaires renewed their concession contracts, and therefore these concessionaires no longer sell the energy produced by these generation facilities at auctions in the regulated market. Rather, this energy is sold to distribution companies in accordance with the quota system established by the 2013 Concession Renewal Law. For more information, see “Item 4. Information on the Company—The Brazilian Electric Power Industry”. Copel Distribuição is obligated to purchase energy from these generation concessionaires that have renewed generation concessions under this quota system. Copel Distribução was legally required to purchase 6,136 GWh in CCGF contracts in 2020, 6,274 GWh in CCGF contracts in 2019 and 6,520 GWh in CCGF contracts in 2018.

Auctions in the Regulated Market

In 2020, we purchased 11,733 GWh of thermoelectric and hydroelectric energy through auctions in the regulated market. This energy represents 47.3% of the total electricity purchased by the Copel Distribuição. For more information on the regulated market and the Free Market, see “Item 4. Information on the Company—The Brazilian Electric Power Industry”.

 
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Sales to Captive Customers

During 2020, we supplied approximately 97% of the energy distributed directly to Captive Customers in the State of Paraná. Our concession area includes nearly 4.8 million customers located in the State of Paraná and in one municipality in the State of Santa Catarina, located in the south of the State of Paraná. During 2020, the total power consumption of our Captive Customers was 19,180 GWh, a 3.1% decrease as compared to 19,784 GWh during 2019.

 

Year ended December 31,

Categories of purchaser

2020

2019

2018

2017

2016

  (GWh)
Industrial customers 2,314 2,648 2,935 3,254 5,753
Residential 7,910 7,499 7,238 7,126 6,932
Commercial 4,172 4,730 4,652 4,651 5,059
Rural 2,451 2,361 2,288 2,257 2,180
Other(1) 2,333 2,546 2,481 2,455 2,404
Total(2) 19,180 19,784 19,594 19,743 22,327

___________________

(1) Includes public services such as street lighting, electricity supply for municipalities and other governmental agencies, as well as our own consumption.

(2) Total GWh does not include our energy losses.

 

Sales to Free Customers

 

We operate in the ACL through our wholly owned subsidiaries Copel Geração e Transmissão and Copel Comercialização (Copel Mercado Livre). As of December 31, 2020, we had 912 Free Customers (of which 877 were customers of our energy trading company and 35 of Copel GeT), representing approximately 8.0% of our consolidated operating revenue and approximately 14.9% of the total quantity of electricity sold by us. During 2020, the total power consumption of our Free Customers was 7,988GWh, a 16.4% increase as compared to 6,860 GWh during 2019.

 

Year ended December 31,

Categories of purchaser

2020

2019

2018

2017

2016

  (GWh)
Industrial customers 7,308 6,352 5,728 4,435 3,821
Commercial 680 508 327 196 2
Total 7,988 6,860 6,055 4,631 3,823

 

The following table sets forth the number of our Final Customers, considering both Captive and Free Customers, in each category as of December 31, 2020.

Category

Number of Final Customers

Industrial 71,904
Residential 3,944,556
Commercial 413,599
Rural 347,592
Other(1) 60,072
Total 4,837,723

___________________

(1) Includes street lighting, as well as electricity for municipalities and other governmental agencies, public services and own consumption.

 
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Industrial and commercial customers accounted for approximately 10.2% and 17.9%, respectively, of our total revenues from sales to Final Customers of Captive Market during 2020. In 2020, 32.5%of our total revenues from energy sales were from to residential customers.

Tariffs

Retail Tariffs. We classify our customers in two groups (“Group A Customers” and “Group B Customers”), based on the voltage level at which electricity is supplied to them and on whether they are considered as industrial, commercial, residential or rural customers. Each customer falls within a certain tariff level defined by law and based on the customer’s classification, although some flexibility is available according to the nature of each customer’s demand. Under Brazilian regulation, low voltage customers such as residential customers (other than Low-income Residential Customers, as defined as follows) pay the highest tariff rates, followed by 13.8 kV and 34.5 kV voltage customers (usually commercial customers), and 69 kV and 138 kV voltage customers (usually industrial customers).

Group A Customers receive electricity at 2.3 kV or higher and the tariffs applied to them are based on the actual voltage level at which energy is supplied and the time of day the energy is supplied. Tariffs are comprised of two components: a “capacity charge” and an “energy charge”. The capacity charge, expressed in reais per kW, is based on the higher of (i) contracted firm capacity and (ii) power capacity actually used. The energy charge, expressed in reais per MWh, is based on the amount of electricity actually consumed as evidenced by our metering.

Group B Customers receive electricity at less than 2.3 kV, and the tariffs applied to them are comprised solely of an energy charge and are based on the classification of the customer.

ANEEL restates our tariffs annually, usually in June. For more information about the distribution tariff adjustments that have been made by ANEEL in recent years, see “Item 5. Operating and Financial Review and Prospects—Overview—Rates and Prices”.

The following table sets forth the Average Tariffs for each category of Final Customer in effect in 2020, 2019 and 2018.

Tariffs

2020

2019

2018

  (R$/MWh)
Industrial 487.41 488.78 767.87
Residential 498.82 504.36 505.08
Commercial 574.57 574.41 527.31
Rural 489.57 466.9 345.80
Other customers 356.03 364.49 375.99
All Final Customers 537.81 534.32 514.94

 

Low-income Residential Customers. Under Brazilian law, we are required to provide low level rates to certain low-income residential customers (“Low-income Residential Customers”). In December 2020, we served approximately 331,061 low-income residential customers. For servicing these customers, in 2020 we received an approximately R$101.8 million contribution from the Brazilian government, which was approved by ANEEL.

The following table sets forth the current minimum discount rates approved by ANEEL for each category of Low-income Residential Customer.

Consumption

Discount from base tariff

Up to 30 kWh per month 65%
From 31 to 100 kWh per month 40%
From 101 to 220 kWh per month 10%

 

Special Customers. A customer of our distribution business that consumes at least 500 kW (a “Special Customer”) may choose its energy supplier if that supplier derives its energy from alternative sources, such as small hydroelectric plants, wind plants or biomass plants. A Special Customer that chooses to purchase energy from a supplier other than Copel Geração e Transmissão continues to use our distribution grid and pay our distribution tariff. However, as an incentive for Special Customers to purchase from alternative sources, we are required to reduce the tariff paid by Special Customers by 50%. This discount is subsidized by the Brazilian government, and therefore does not impact the revenues of our distribution business.

 
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Transmission Tariffs. A transmission concessionaire is entitled to annual revenues based on the transmission network it owns and operates. These revenues are annually readjusted according to criteria stipulated in the concession contract. We are directly a party to twelve (12) transmission concession contracts, eleven (11) of which are in the operational stage and one (1) of which includes a transmission line that is still under construction. Not all of the transmission concession contracts employ the same revenue model. 1.5% of our transmission revenues are updated on an annual basis by the IGP-M and the other 98.5% are subject to the tariff review process.

The first periodic revision related to our Main Transmission Concession scheduled for 2005 was only carried out in 2007, at which point ANEEL reduced the tariffs by 15.08%. This adjustment was applied retroactively to July 2005, and was passed on to our Final Customers until June 2009. In addition, in July 2010 pursuant to a second periodic revision of our principal concession, ANEEL granted provisional approval of a reduction in our transmission tariff by 22.88%, applied to the revenues of new installations in the Interconnected Transmission System, and applied retroactively from July 1, 2009 onward. In June 2011, ANEEL reviewed the figures of the second periodic revision and reduced the annual revenues by 19.94%. The remainder of our annual revenues was subject to adjustment by IGP-M or IPCA, as applicable.

By late 2012, Copel decided to anticipate the extension of its main transmission concession agreement (corresponding to 78% of our transmission lines then in operation) that would expire in 2015, pursuant to the new rules of the 2013 Concession Renewal Law. In December 2012, Copel executed the Third Addendum to the Concession Agreement 060/2001, extending this transmission concession agreement until December 31, 2042. In order to adjust these assets’ annual permitted revenue to the new rules of 2013 Concession Renewal Law, ANEEL reduced the transmission tariffs we charged by 61.9%.

Of all our transmission concessions in operational stage, our main transmission concession (which involves our main transmission facilities) accounted for about 71% of our gross transmission revenues in 2019. In addition, we have ten (10) concession agreements for transmission lines and substations in operation and one (1) partially in operation, which correspond to an aggregate of 29% of our transmission revenues. The amount of revenues we are entitled to receive pursuant to one (1) of these contracts is updated on an annual basis by the IGP-M and is not subject to the tariff review process, but, pursuant to the terms set forth in this agreement, our revenues were reduced by 50% starting in June 2018. Other ten (10) agreements revenues are subject to the tariff review process and adjustments by the IPCA.

In relation to our main concession agreement, on April 22, 2016, Ordinance No. 120/2016 of the Ministry of Mines and Energy determined that the amounts ratified by ANEEL related to the non-depreciated transmission assets existing on May 31, 2000 (Existing Basic Network System “RBSE”) should be incorporated to the Regulatory Remuneration Base, and that their cost of capital should be added to APR. The Ordinance also determined that the cost of capital would be composed of compensation and depreciation installments, plus related taxes, and recognized as of the 2017 tariff revision process, with adjustments and revisions in accordance with contractual conditions.

Also pursuant to the above mentioned Ordinance, the cost of capital not incorporated between the concessions’ extensions and the 2017 tariff revision process should be restated at the real cost of own capital of the transmission segment defined by ANEEL (10.4%) and, after the tariff revision process, it should be remunerated at the Weighted Average Cost of Capital (WACC) of 6.6%, also defined by that agency.

On May 9, 2017, ANEEL approved the result of the inspection of the appraisal report of the transmission assets existing on May 31, 2000 (RBSE and Other Transmission Facilities - RPC) related to our main transmission concession agreement. The Agency recognized the amount of R$667.6 million as the net value of the assets for the purposes of indemnification as of December 31, 2012. As of December 31, 2017, the net value of those assets for the purposes of indemnification amounted to R$1,418.4 million.

 
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On June 27, 2017, ANEEL approved the Annual Permitted Revenue (Receita Anual Permitida, or APR) of the transmission assets of Copel GeT for the 2017/2018 cycle, including the commencement of receipt of the RBSE indemnification of our main transmission concession agreement.

In 2017(i) our main transmission concession agreement was adjusted by the IPCA and by the portion related the commencement of receipt of the RBSE indemnification (average increase of 151.3%) (ii) one of our transmission concession agreements was adjusted by the IPCA and improvements to the system were approved by ANEEL (average increase of 3.7%), (iii) six transmission concession agreements were adjusted by the IPCA (3.6%), (iv) one transmission concession agreement was adjusted by the IGP-M (1.6%), and (v) one transmission agreement became operational in August 2017, adding R$18.9 million of annual permitted revenues. As a result, the annual permitted revenues for the 2017/2018 cycle for our transmission assets reflected an increase of 121.2% over our annual permitted revenues for the 2016/2017 cycle.

In June 2018, ANEEL approved the APR for the 2018/2019 cycle, considering (i) an adjustment of relevant amounts by the IGP-M and IPCA indexes, and (ii) the expansion of our transmission system with strengthening works and revenues from other works classified as improvement measures.

Compared to our total APR for the 2017/2018 cycle, the APR of our main concession for the 2018/2019 cycle was reduced by 8.1%, as a result of the correction of a prior calculation made by ANEEL, which take into account certain financial and economic portions of unamortized and unrepaired assets related to the RBSE when determining the assets of the Regulatory Remuneration Base in the prior cycle.

The APR of concession No. 075/2001 was reduced by approximately 30.5%, as a result of a 50% reduction of the APR starting at the 16th anniversary of commercial operation, which occurred during the 2018/2019 cycle. Two of our concession agreements (022/2012 and 002/2013) were subject to a periodic review, which resulted in a lower APR in connection with increasing revenues related to strengthening works.

In June 2019, ANEEL approved the APR for the 2019/2020 cycle, considering (i) an adjustment of relevant amounts by the IGP-M and IPCA indexes, and (ii) the expansion of our transmission system with strengthening works and revenues from other works classified as improvement measures.

In 2020, in the scope of the tariff review process for the contracts extended under Law No. 12,783/2013, holders of assets belonging to RBSE had their review ratified in June 2020 despite originally being scheduled for 2018, due to a two-year delay and the retroactive effects of REN 880/2020 on the 2018 tariff year. For Copel, this process was ratified through Homologation Resolution No. 2,715/2020 for concession agreement No. 060/2001, granted to Copel GeT. During review process, by ANEEL’s deliberation it was decided that as of the 2020/2021 cycle, the renumeration portion of the RBSE would be calculated by the cost of equity (“KE”) as provided for in Ordinance MME No. 120/2016. The value not received during the three previous cycles (2017-2020) will be incorporated into the next three cycles (2020-2023) by the means of an Adjustment Installment (Parcela de Ajuste).

Additionally, by means of Homologation Resolution No. 2,725/2020, ANEEL established the readjustment of RAPs for electric energy transmission assets for the 2020-2021 cycle, effective from July 1, 2020 until June 30, 2021. According to the aforementioned resolution, Copel GeT’s transmission asset RAPs for the 2020-2021 cycle were R$777.2 million, of which R$703.4 million correspond to the revenue of operational assets. Considering the homologated RAPs for the Special Purpose Companies (Sociedades de Propósito Específicos) in which Copel GeT has equity ownership, the total consolidated value for Copel GeT is R$1,146.0 million. Along with beginning of commercial operations of Mata de Santa Genebra assets in its totality in 2020, GeT’s total consolidated value is R$1,161.2 million.

The table below shows our APR (R$ million) for the last four cycles of transmission lines over which we hold a 100% ownership:

 
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Contract

 

Transmission Line /

Substation

 

Jul. 2020 Jun.2021

 

Jul. 2019

Jun. 2020

 

Jul. 2018

Jun. 2019

 

Jul.2017

Jun.2018

            APR (R$ million)
                     
060/2001   Main Transmission Concession(1)   505.4   469.5   450.4   482.7
075/2001   Bateias – Jaguariaiva   11.6   10.9   13.5   19.4
006/2008   Bateias – Pilarzinho   1.1   1.1   1.1   1.0
027/2009   Foz do Iguaçu - Cascavel Oeste   12.7   12.5   11.9   11.6
015/2010   Cerquilho III   5.2   5.1   4.8   4.7
022/2012   Foz do Chopim – Salto Osório   6.2   6.1   5.8   5.8
002/2013  

Assis-Paraguaçu Paulista II

SE Paraguaçu Paulista II

  9.7   8.2   7.9   7.7
005/2014   Bateias – Curitiba Norte   10.2   9.9   9.5   8.7
021/2014   Foz do Chopim - Realeza(2)   8.0   7.8   7.5   7.3
022/2014   Assis – Londrina(3)   20.8   20.4   19.5   18.9
010/2010   Araraquara 2 – Taubaté(4)   32.0   31.4   30.0   -
006/2016  

Baixo Iguaçu – Realeza

Curitiba Centro - Uberaba

  80.5   79.0   -   -
002/2005   Uirapuru(5)   37.1   32.4   -   -
001/2012   Costa Oeste(6)   13.7   12.5   9.1   -
008/2012   Marumbi(6)   19.9   19.5   18.1   -
Total       774.1   661.9   561.9   567.8

___________________

(1) Our main transmission concessions encompass several transmission lines.

(2) This transmission line became operational in January 2017.

(3) This transmission line became operational in August 2017.

(4) This transmission line became operational in July 2018.

(5) In June 2019, Copel Geração e Transmissão S.A. became the owner of 100% of the project.

(6) In August 2018, Copel Geração e Transmissão S.A. became the owner of 100% of the project.

 

Other Businesses

Telecommunications

Copel Telecomunicações S.A. Pursuant to an authorization from the Brazilian National Telecommunication Agency (Agência Nacional de Telecomunicações – “ANATEL”), we provide telecommunication services within the States of Paraná and Santa Catarina. We have been offering these services since August 1998 through the use of our fiber optics network (totaling 36.2 thousand km of fiber optic cables by the end of 2020). In addition, we have been involved in an educational project aimed at providing broadband internet access to public elementary and middle schools in the State of Paraná.

COPEL currently serves 399 municipalities in the State of Paraná. All of these municipalities are connected to COPEL’s optical backbone.

In addition to the high transmission capacity in its backbone, Copel Telecom serves 85municipalities in the State of Paraná, with GPON (Gigabit-Capable Passive Optical Networks) access technology, providing several network services with symmetry rates, in different types of Fts services.

We provide services to most of the major Brazilian telecommunication companies that operate in the State of Paraná. In total, we have corporate clients that include supermarkets, universities, banks, internet service providers and television networks in addition to retail clients. We also provide a number of different telecommunication services to our subsidiaries.

On November 9, 2020, Copel Telecom's divestment auction was held at B3 S.A. - Brasil, Bolsa, Balcão. The winning bid was R$ 2.4 billion (equity value). On January 14, 2021, a Share Purchase Agreement for 100% of Copel Telecom was entered into with Bordeaux Multi-Strategic Investment Fund – Bordeaux Fundo de Investimentos em Participações Multiestratégia, the winning bidder of the auction. We estimate that the transaction will close between the second or third quarter of 2021.

 
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Sercomtel. Sercomtel S.A. (“Sercomtel”) holds a concession to provide fixed telephony services and an authorization to provide mobile services in the municipalities of Londrina and Tamarana, located in the State of Paraná. In addition, Sercomtel has two (2) other authorizations from ANATEL that allow it to provide fixed telephony and broadband internet services in all other municipalities of the State of Paraná. Currently, Sercomtel operates with its own network in fifteen (15) municipalities of the State of Paraná, providing voice services and fixed broadband. Pursuant to a commercial agreement between COPEL and Sercomtel in force since March 2012, Sercomtel can provide voice services over Copel Telecom’s network in one hundred and eighty three (183) cities within the State of Paraná, including Curitiba. .

In addition to the telecommunications business, Sercomtel S.A. – Telecomunicações currently holds the following equity interest: (i) 100% of the capital stock of Sercomtel Participações S.A., a company whose purpose is to provide added value services, design, deploy and maintain internet service providers, operate a service center for users of telecommunications services, offer integrated IT solutions, among other activities. In September 2017, pursuant to Decision (Acórdão) no. 366, ANATEL determined that Sercomtel was not in compliance with certain financial indicators set forth by the agency in connection with the concessions granted to Sercomtel and required for the company’s operations to continue. As a consequence, ANATEL brought an administrative proceeding against Sercomtel to assess whether the concession and the authorizations granted to this company should be terminated. In March 2019, ANATEL decided to suspend the above mentioned proceeding, so that Sercomtel could present to the agency alternative plans for meeting the relevant regulatory indicators. ANATEL published a bidding notice proposal in September 2019 with respect to the licenses held by Sercomtel. ANATEL’s proposal is subject to review by the Federal Audit Court (Tribunal de Contas da União). No bidding process has been carried out by ANATEL, as of the date hereof. If a bidding process is indeed carried out by ANATEL, Sercomtel’s licenses could be forfeited and terminated.

Sercomtel had losses in previous years and faced financial difficulties in carrying out its operations. Given the accumulated losses and the uncertainties regarding its operational viability, we carried out in 2013 the write-off of this investment in our financial statements.

In June 2019, the municipal legislature of Londrina approved the sale of the stake held by the Londrina City Hall as the controlling shareholder of Sercomtel (Municipal Law No 12.871, dated June 12, 2019). In November 2019, the City Hall published the bidding notice for the privatization process of Sercomtel, which provided for the assignment of the City Hall’s preemptive right to subscribe shares in a future capital increase of Sercomtel. This process would result in the dilution of the stake held by the City Hall and Copel in Sercomtel. However, given that no bidders attended the February 5, 2020 auction, a new date was scheduled for July 9, 2020.

On August 18, 2020, Sercomtel’s privatization auction was held at B3 S.A. - Brasil, Bolsa, Balcão.

The winner of the auction pledged to make an investment of R$130 million in Sercomtel, in order to meet Anatel's minimum indicators and end the process of forfeiture of its concession and forfeiture of its authorization grants.

On December 23, 2020, the operation was closed, and Copel received R$1.5 million for its share.

Gas

Gas Distribution

We are engaged in the distribution of natural gas through Companhia Paranaense de Gás (“Compagas”), the company that holds the exclusive rights to supply piped gas in the State of Paraná. Compagas operates the gas distribution grid in the State of Paraná under a concession agreement with a term of 30 years, with expiry on July 6, 2024. Such date has always been announced and considered for assessment of the balances of the prior-year financial statements. The concession agreement may be extended for an equal 30-year period upon request of the concessionaire.

On December 7, 2017, however, the State of Paraná published Supplementary Law 205, introducing a new interpretation of the expiry of the concession, which should have occurred on January 20, 2019. Notwithstanding the new expiration date provided by the state law, this concession has not been subject to neither an extension nor a new bidding process. Pursuant to applicable law, Compagas, as the current concessionaire, may continue to operate the concession until a new concessionaire is appointed.

 
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In addition, the management of Compagas, we and other shareholders are challenging the effects of the aforesaid law, understanding that it conflicts with the provisions of the concession agreement currently in force. Compagas filed a lawsuit challenging the anticipating of the expiration date of such concession and was granted with a provisional remedy on October 30, 2018, which granted a preliminary injunction in our favor to recognize the validity of clause 1.1 of the Concession Agreement, which establishes a contractual term of 30 years as of July 6, 1994, ending on July 6, 2024. We await a decision in the judicial process.

Furthermore, Supplementary Law No. 227/2020 was published on December 4, 2020, which amended Supplementary Law No. 205/2017, revoking its article 15, which provided for the end of the concession term on January 20, 2019. Despite the revocation, the lawsuit remains in progress to have the validity of clause 1.1 of the Concession Agreement judicially declared. Compagas covered 842 kilometers in 2020, increase of 1.1% compared to 833 kilometers covered in 2019. Compagas’s net revenues were R$524.2 million, a decrease of 30.7%, compared to 2019 (R$756.6 million), and its net income was R$59.6 million, a decrease of R$126.4 million or 68% compared to 2019. Compagas’ customers include industries, gas stations, other businesses and residences and Araucária Thermoelectric plan. Compagas is focusing its business strategy on increasing the volume of gas it distributes to customers by marketing the benefits of substituting oil and other fuels by gas as a mean of achieving greater energy efficiency. Compagas’ customer base increased 4.4%, to 49,335 customers in 2020 from 47,238 in 2019.

Compagas registered an decrease of 35.6% in the average daily volume of natural gas distributed to Final Customers, to 881,745 cubic meters per day in 2020 (not including the volume of gas supplied to Araucária Thermoelectric Plant) compared to 1,368,915 cubic meters per day in 2019 (not including the volume of gas supplied to Araucária Thermoelectric Plant). In addition, Compagas makes its distribution grid available to transport natural gas to Araucária TPP. The volume of natural gas supplied from Petrobras and distributed by Compagas to Araucária TPP, was 676,113 cubic meters per day in 2020, compared to 68,050 cubic meters per day in 2019.

As of December 31, 2020, we held a controlling stake (51%) of the capital stock of Compagas and consolidated this equity interest in our financial statements. The minority shareholders of Compagas are Petrobras, through its subsidiary Gaspetro, and Mitsui Gás, each of which owns 24.5% of the capital stock of Compagas.

Gas Exploration

In the 12th bidding round of National Petroleum Agency (Agência Nacional do Petróleo “ANP”), held at the end of 2013, the consortium formed by us (30%), Bayar Participações (30%), Tucumann Engenharia (10%) and Petra Energia (30%), the latter acting as operating company, won the right to explore, research, develop and produce oil and natural gas in four blocks located in the central southern region of the State of Paraná, in a 11,327 km² area. The minimum investment in the first phase of the research is approximately R$78.1 million for a 4-year term. We and our partners have signed the concession contracts for 2 blocks in May 2014. However, because of a public civil action, the first phase of exploration for these two blocks was halted and the signing of the other two concession contracts was prohibited. On June 7th, 2017, a court decision held that all the bidding round and the agreements related thereto should be deemed null and void. Moreover, the Government of the State of Paraná enacted Law No. 19,878 (July 3, 2019), forbidding the exploration of shale gas through the drilling / fracking method.

As a result of the above-mentioned events, our consortium requested ANP to release it from its contractual obligations, with no liabilities and with reimbursement of the signing bonuses, reimbursement of all costs incurred in connection with guarantees and release of such guarantees for the four blocks. Even though this request was submitted to ANP on September 6th, 2017, it is still subject to analysis. All the activities for the four blocks were interrupted due to the suspension of the effects of the12th bidding round of ANP because of an injunction granted in connection with the above mentioned public civil action, which awaits a decision from the Federal Court of Appeals of the 4th Region. For this reason, in October 2018, the consortium approved the establishment of an institutional arbitration procedure with the ANP for the four blocks awarded in the 12th bidding round of ANP, asking for the refund of the contributions made. Arbitral proceedings have already been initiated.

 
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Gas Natural Power Plants

On January 14, 2020, Copel and Shell Brasil Petróleo formed the "Copel Energia a Gás Natural" Consortium with the objective of developing feasibility studies for natural gas power plants in the state of Paraná. The consortium hired a consulting firm to provide specialized technical services to carry out studies to identify the best location for the implementation of natural gas thermoelectric projects in the State. The study is ongoing.

CONCESSIONS

 

We operate under concessions granted by the Brazilian government for our generation, transmission and distribution businesses. Under Brazilian law, concessions are subject to competitive bidding processes at the end of their respective terms.

2013 Concession Renewal Law

Until 2013, the Brazilian rules governing generation concessions gave concessionaires the right to renew for additional 20 year concession contracts that were entered into prior to December 11, 2003. For transmission and distribution concessions granted after 1995, concessionaires had the right to renew these contracts for an additional 30-year period.

On September 11, 2012, the Brazilian government enacted the Provisional Measure No. 579, subsequently converted into the 2013 Concession Renewal Law, which significantly changed the conditions under which concessionaires are able to renew concession contracts. Under the 2013 Concession Renewal Law, generation, transmission and distribution concessionaires may renew the concessions that were in effect as of 1995 (and, in the case of generation facilities, generation concession contracts entered into prior to 2003) for an additional period of 30 years (or an additional 20-year period in the case thermal plants), provided that the concessionaire agrees to amend the concession contract to reflect a series of new conditions that aim to ensure that services are provided in a continuous and efficient fashion and subject to low tariffs. Under the 2013 Concession Renewal Law, concessionaires must decide 60 months before the end of each concession term (or 24 months with respect to thermal plant concessions that it is 24 months) whether to amend and renew a concession contract or to terminate each concession contract at the end of its respective term.

For concessionaires of generation facilities existing at that time, the 2013 Concession Renewal Law changed the scope of the concession contracts at the moment they were renewed. Previously, a generation concessionaire had the right to sell the energy generated by the facilities subject to its concession for profit. In contrast, generation concessions renewed pursuant to the 2013 Concession Renewal Law do not grant concessionaires the right to sell the energy generated by these facilities. Instead, these concessions only cover the operation and maintenance of the generation facilities, subject to quality standards determined by Brazilian authorities. The energy generated by these facilities are allocated by the Brazilian government in quotas to the regulated market, for purchase by distribution concessionaires. For new generation facilities (i.e., generation facilities operated after the 2013 Concession Renewal Law), on the other hand, the concessionaire still has the right to sell the energy produced by the generation facility.

In addition to changing the scope of generation concessions, the 2013 Concession Renewal Law establishes a new tariff regime that significantly affects the treatment of amounts to be invested by concessionaires to improve and maintain generation plants. To this effect, several regulations were issued by MME and ANEEL to regulate the compensation due to concessionaires as a result of their investments to improve and maintain generation plants.

The 2013 Concession Renewal Law affects transmission and distribution concessions differently. The principal change is that amounts invested in modernization projects, structural reforms, equipment and contingencies are subject to prior ANEEL approval. However, the 2013 Concession Renewal Law does not affect the manner in which distribution and transmission concessionaires may recover amounts invested in transmission infrastructure.

With respect to the transmission agreements, the conditions for renewal set forth in the 2013 Concession Renewal Law are the acceptance of a fixed income as determined by ANEEL and compliance with quality standards set forth in applicable regulation. With respect to distribution agreements, the conditions are set forth in the amendment to the concession agreement and are related to compliance with quality standards, economic-financial sustainability indicators and corporate governance as set forth in the amendment to the concession agreement according to the parameters provided in the 2013 Concession Renewal Law.

 
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The 2013 Concession Renewal Law applies to all generation, transmission and distribution contracts that were in effect as of 1995 (and, in the case of generation concessions, entered into prior to 2003), regardless of whether a contract grants to the concessionaire the right to renew a concession on its original terms. For example, several of our concession contracts contain provisions allowing us to renew these concessions for a period of 20 years. Under the 2013 Concession Renewal Law, in order to renew these contracts, we nonetheless would be required to accept the application of the conditions imposed by the 2013 Concession Renewal Law to the contract, and the concession contract would then be renewed for 30 years, rather than 20 years. If we choose to renew a concession contract that contains a renewal provision, we would be indemnified by the Brazilian government using funds from the RGR Fund (see Energy Sector Regulatory Charges) in an amount equal to the portion of our investments related to the concession that have not yet been amortized or depreciated, as calculated by ANEEL.

If a concessionaire decides not to accept the new tariff regime with respect to a concession contract and therefore decides not to renew the contract, the concession will terminate at the end of its original term, and the Brazilian government will conduct a new competitive bidding process for the concession. The original concessionaire may participate in the new competitive bidding process.

In the case of hydroelectric generation concessions with an installed capacity of more than 5,000 kW, upon the expiration of their original term and provided that the concessionaire does not request the extension of such term, the granting authority may submit the concession to a new bidding process. In the case of concessions for hydroelectric generation units with an installed capacity of 5,000 kW or less, upon the expiration of their original term, the concessions may be granted to the current concessionaire in the form of registration, for an indefinite term.

Generation Concessions

Of the nineteen (19) hydroelectric plants we operated in 2020, fourteen (14) were operated under the generation concession contracts that were in force prior to the 2013 Concession Renewal Law, and five (5) were operated in accordance with the 2013 Concession Renewal Law (Capivari Cachoeira HPP, Chopim I HPP, Marumbi HPP, Baixo Iguaçu HPP and Colíder HPP). In 2013, 12 of the 13 hydro and thermoelectric generation concessions operated by the Company in 2013 (exception made only to Rio dos Patos HPP) were extended pursuant to the old regime and could be renewed again under the 2013 Concession Renewal Law.

However, at the time the 2013 Concession Renewal Law was enacted, the Company elected not to renew the following generation concessions: Rio dos Patos (2014), Mourão I (2015), Chopim I (2015) and Capivari Cachoeira (2015), all of which had remaining terms of 60 months or less. Please see below for further information on each of these concessions.

Foz do Areia HPP. Copel Geração e Transmissão did not elect to renew the original concession pursuant the 2013 Concession Renewal Law for the Foz do Areia HPP (Governador Bento Munhoz da Rocha Netto). However, in order to obtain a new concession for the Foz do Areia HPP for another 30 years, Copel GeT transferred the ownership of this HPP to its subsidiary, the SPC F.D.A. Geração de Energia Elétrica S.A (F.D.A) on March 3, 2020, and, on the same date, requested a new concession from the Ministry of Mines and Energy pursuant to Federal Decree no. 9,271/2018 (as amended by Federal Decree no. 10,135/2019), which conditions that, to obtain a new concession, the sale of the concession's corporate control (F.D.A) must occur. On the same date, F.D.A. signed with ANEEL the Concession Contract that transfers the concession of the HPP Foz do Areia from Copel GeT to the F.D.A., for the exploration of the plant until the end of the current concession, on September 17, 2023.

Rio dos Patos HPP. The concession of Rio dos Patos HPP was terminated and not submitted to a further bidding process due to the lack operational conditions.

Mourão I and Capivari Cachoeira HPP. The granting authority submitted the concessions for HPP Capivari Cachoeira and Mourão I to new bidding processes, pursuant to which new agreements should be in force for a 30-year period. Copel GeT was the winner in the bidding process related to HPP Capivari Cachoeira. With respect to Capivari Cachoeira, although Copel GeT did not elect to renew the original concession for the Capivari Cachoeira HPP, it participated in the new competitive bidding process and won. On January 5, 2016, Copel GeT executed a concession agreement with ANEEL so that it will continue to operate this plant under an operation and maintenance regime until 2046. We paid a total amount of R$574.8 million as signing bonus for this concession agreement. 100.0% of the energy generated by this plant in 2016 was allocated in quotas to the regulated market, and reduced to 70.0% on January 1, 2017. Copel GeT can sell remaining amount of energy generated by this plant on the Free Market or Spot Market.

 
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Chopin I HPP. As the installed capacity of Chopin I HPP also does not exceed 5,000 kW, the concession regime of this plant has been changed to a registration in favor of the Company, valid for an indefinite term. In addition, pursuant to the same statute, we may notify the granting authority of its intention to extend: (i) in 2020, the concession of Apucaraninha HPP; and (ii) in 2021, the concessions of Guaricana and Chaminé HPPs. In the event we do not request the extension of these concessions, they will be subject to new bidding processes conducted by the granting authority.

Figueira TPP. Our concession for the Figueira TPP expired on March 26, 2019. We had filed an extension request with respect to this plant on May 24, 2017, but we are still waiting for the granting authority to amnd our concession agreement, extending its term for an additional 20-year period in accordance with the 2013 Concession Renewal Law. This plant has an installed capacity equivalent to 20 MW and subject to a modernization process.

With respect to the concessions granted between 2011 and 2017 with no renewal right attached, we acquired the right to renew only one of the hydroelectric plants (HPP Cavernoso II) for a 30-year period, as a result of an amendment to the 2013 Concession Renewal Law by Law No. 13,360, of November 17, 2016.

In accordance with the 2013 Concession Renewal Law, Copel could have flagged to the granting authority by 2019 its intention to renew the concession of HPP São Jorge. However, Copel elected not to renew such concession and, consequently, it will be able to operate such HPP until December 2024 and request the conversion of this operating regime into a registration regime, as the installed capacity does not exceed 5,000 kW.

Concessions for generation projects granted after December 11, 2003 were not affected by the 2013 Concession Renewal Law and are non-renewable, meaning that upon expiration of their 35-year term, the concession will be granted subject to a new competitive bidding process. In 2019, we had three (3) hydroelectric plants operating in this condition (HPP Mauá, HPP Colíder and HPP Baixo Iguaçu).

In September 2020, the GSF Law was passed, which established new conditions for the renegotiation of hydrological risk of electricity generation, amending Article 2 of Law No. 13,203/2015, among other measures. This procedure was regulated through Normative Resolution No. 895/2020, in which ANEEL established the methodology for calculating compensation to the owners of hydroelectric plants participating in the MRE. It also regulated the repatriation of hydrological risk to equate the issue of GSF and open debts in CCEE to allow for the return of normalcy and greater liquidity in the short-term electricity market, in exchange for the extension of the terms of grants given to hydroelectric plants to up to seven years.

On March 2, 2021, CCEE released the calculations of the renegotiation of the hydrological risk and the results, which total approximately R$ 1,366.3 million for the 15 eligible plants of the Company, were sent to Aneel to be submitted to the approval analysis. To date, the Company has not yet adhered to the renegotiation of the hydrological risk, as the Management is awaiting approval by Aneel of the approximately 510 days of average extension of the granting of its plants to assess the possible adherence to the terms of the renegotiation and waiver of future questions or lawsuits in relation to the hydrological risks in question. More information is detailed as described in notes 1-b to our audited consolidated financial statements.

 

The following tables sets forth information relating to the actual terms as well as the renewals of our main generation hydroelectric, thermoelectric and wind farm plants and all of which we hold a direct ownership interest in:

Hydroelectric Plants

Initial concession date

First expiration date

Extension Date

Final expiration date

Foz do Areia (1) May, 1973 May, 2003 January, 2001 September, 2023
Apucaraninha October, 1975 October, 2005 April, 2003 October, 2025
Guaricana August, 1976 August, 2006 August, 2005 August, 2026
Chaminé August, 1976 August, 2006 August, 2005 August, 2026
 
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Segredo November, 1979 November, 2009 September, 2009 November, 2029
Derivação do Rio Jordão November, 1979 November, 2009 September, 2009 November, 2029
Salto Caxias May, 1980 May, 2010 September, 2009 May, 2030
Mauá (2) June, 2007 July, 2042 Not extendable July, 2042
Colíder(3) January, 2011 January, 2046 Not extendable January, 2046
Cavernoso II February, 2011 February, 2046 Not extendable February, 2046
Baixo Iguaçu(4) August, 2012 August, 2047 Not extendable October, 2049
SHP Bela Vista (5) May, 2007 January, 2041 Extendable January, 2071

___________________

(1) In March 3, 2020, the concession of Foz do Areia was transferred from Copel GeT to FDA pursuant to ANEEL Authorizing Resolution no. 8.578/2020. Copel GeT owns 100% of FDA Geração de Energia S.A.

(2) Mauá was constructed by Consórcio Energético Cruzeiro do Sul, of which Copel owns 51.0% and Eletrosul owns the remaining 49.0%.

(3) The commercial operations of generation units 1, 2 and 3 of Colíder’s began in March 2019, May 2019 and December 2019, respectively.

(4) Baixo Iguaçu was constructed by Consórcio Empreendedor Baixo Iguaçu, of which Copel owns 30% and Geração Céu Azul the remaining 70%. The commercial operations of generation units 1, 2 and 3 of Baixo Iguaçu’s began in February 2019, Feburary 2019 and April 2019, respectively.

(5) The consortium CBVG, formed by Copel GeT and Foz do Chopim Energética Ltda., won ANEEL Auction No. 003/2018 for SHP Bela Vista. In April 2019, the authorization to operate SHP Bela Vista was transferred from Foz do Chopim Energética Ltda. to Bela Vista Geração de Energia S.A through the ANEEL’s Authorizing Resolution no. 7.802/2019. In December 2019, Copel GeT became the owner of 100% of Bela Vista Geração de Energia. This power plant is still under construction. .

 

Thermoelectric Plants

Initial concession date

First expiration date

Extension date

Final expiration date

Figueira March 1969 March 1999 June 1999 March 2019

 

Wind Plants

Initial concession date

First expiration date

Asa Branca I April, 2011 April, 2046
Asa Branca II May, 2011 May, 2046
Asa Branca III May, 2011 May, 2046
Nova Eurus IV April, 2011 April, 2046
Santa Maria May, 2012 May, 2047
Santa Helena April, 2012 April, 2047
Ventos de Santo Uriel April, 2012 April, 2047
Boa Vista April, 2011 April, 2046
Farol April, 2011 April, 2046
Olho D'Água June, 2011 June, 2046
São Bento do Norte May, 2011 May, 2046
Cutia(1) January, 2012 January, 2042
Guariju(1) January, 2012 January, 2042
Jangada(1) January, 2012 January, 2042
Maria Helena(1) January, 2012 January, 2042
Palmas September, 1999 September, 2029
Potiguar(1) May, 2015 May, 2050
Esperança do Nordeste(1) May, 2015 May, 2050
Paraíso dos Ventos do Nordeste(1) May, 2015 May, 2050
São Bento do Norte I(1) August, 2015 August, 2050
São Bento do Norte II(1) August, 2015 August, 2050
São Bento do Norte III(1) August, 2015 August, 2050
São Miguel I(1) August, 2015 August, 2050
São Miguel II(1) August, 2015 August, 2050
São Miguel III(1) August, 2015 August, 2050
Jandaíra I(2) April, 2020 April, 2055
Jandaíra II(2) April, 2020 April, 2055
Jandaíra III(2) April, 2020 April, 2055
Jandaíra IV(2) April, 2020 April, 2055

(1) Wind plants located at Copel’s Cutia wind farm complex.

(2) The consortium formed by Copel GeT and Cutia Empreendimentos Eólicos S.A.., won ANEEL Auction no. 004/2019 for Jandaíra Wind Complex (I, II, III and IV) and granting process is still ongoing.

 
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The following table sets forth information relating to the terms of our generation hydroelectric plant, whose concession agreement has been executed under the terms and conditions of the 2013 Concession Renewal Law:

Hydroelectric Plants

Initial concession date

First expiration date

Extension Date

Final expiration date

Capivari Cachoeira (Gov Parigot de Souza) January, 2016 January, 2046 Not subject to extension January, 2046

 

The following table sets forth information relating to the terms of our generation hydroelectric plants which, once respective original concession period expires, will no longer be subject to a concession regime but rather to a registration proceeding with the ANEEL:

Hydroelectric Plants(1)

Initial concession date

Concession expiration date

Final expiration date

Chopim I March, 1964 July, 2015 Indefinitely
São Jorge December, 1974 December, 2024 -
Cavernoso January, 1981 January, 2031 -
Melissa May, 2002 Indefinitely -
Pitangui May, 2002 Indefinitely -
Salto do Vau May, 2002 Indefinitely -
Marumbi March, 1956 May, 2018 Indefinitely

 

(1) Upon the expiration of concessions or authorizations for hydroelectric energy generation with installed capacity equal to or less than 5,000 KW, the relevant projects are subject to a registration regime in accordance with Brazilian Federal Law No. 9,074/1995, as amended by Brazilian Federal Law No. 13,360/2016. The operation of hydroelectric and thermoelectric plans with installed capacity of up to 5,000 KW are not subject to any concession, permission or authorization and require solely the registration with the granting authority.

 

We also have ownership interests in eleven (11) other generation projects. The following table sets forth information relating to the terms of the concessions of the generation facilities in which we had such partial ownership interest as of December 31, 2020.

Generation Facility

Company

Initial concession date

Expiration date

Extension

HPP Dona Francisca Dona Francisca Energética SA ‒ DFESA July, 1979 August, 2033 Possible
HPP Santa Clara Centrais Elétricas do Rio Jordão S.A. - ELEJOR October, 2001 May, 2037 Possible
HPP Fundão Centrais Elétricas do Rio Jordão S.A. - ELEJOR October, 2001 May, 2037 Possible
SHP Santa Clara I Centrais Elétricas do Rio Jordão S.A. - ELEJOR December, 2002 December, 2032 Possible
SHP Fundão I Centrais Elétricas do Rio Jordão S.A. - ELEJOR December, 2002 December, 2032 Possible
TPP Araucária UEG Araucária Ltda. December, 1999 December, 2029 Possible
HPP Arturo Andreoli Foz do Chopim Energética April, 2000 April, 2030 Possible
WPP Carnaúbas São Miguel do Gostoso I April, 2012 April, 2047 Not possible
WPP Reduto São Miguel do Gostoso I April, 2012 April, 2047 Not possible
WPP Santo Cristo São Miguel do Gostoso I April, 2012 April, 2047 Not possible
WPP São João São Miguel do Gostoso I March, 2012 March, 2047 Not possible
 
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Transmission Concessions

Pursuant to the 2013 Concession Renewal Law and the terms of our transmission concessions, we have the right to request 30-year extensions of the concessions from ANEEL, provided that such request is delivered within 60 months prior to the expiration of the contract. Our principal transmission concession, from which 72% of our transmission revenues in 2020 derived, has been renewed pursuant to the 2013 Concession Renewal Law, and will therefore now expire in December 2042.

In addition, in 2020, an aggregate of 28% of our transmission revenues derived from eleven (11) other concession contracts for transmission lines and substations that are currently in operation and whose terms and extensions are set forth in the next table. In accordance with the 2013 Concession Renewal Law, each of these contracts can be extended for an additional 30-year period.

We intend to continue requesting extensions for all of our transmission concessions.

The following table sets forth certain information relating to the terms and extension terms of our main transmission concessions (all of which we hold a direct ownership interest), including the concession contracts for transmission lines and substations both in operation or under construction:

Transmission

Facility

Initial concession

Date

First expiration

Date

Possibility of extension

Expected (or final) expiration date

Main transmission concession July, 2001 July, 2015 Extended December, 2042
Bateias – Jaguariaíva August, 2001 August, 2031 Possible August, 2061
Bateias – Pilarzinho March, 2008 March, 2038 Possible March, 2068
Foz do Iguaçu – Cascavel Oeste November, 2009 November, 2039 Possible November, 2069
Substation Cerquilho III October, 2010 October, 2040 Possible October, 2070
Araraquara 2 – Taubaté October, 2010 October, 2040 Possible October, 2070
Foz do Chopim - Salto Osorio August, 2012 August, 2042 Possible August, 2072
Assis – Paraguaçu Paulista II February, 2013 February, 2043 Possible February, 2073
Bateias – Curitiba Norte January, 2014 January, 2044 Possible January, 2074
Realeza Sul – Foz do Chopim September, 2014 September, 2044 Possible September, 2074
Assis - Londrina September, 2014 September, 2044 Possible September, 2074
Curitiba Leste – Blumenau(1) April, 2016 April, 2046 Possible April, 2076

 

(1) Facility under construction.

We have ownership interests in ten (10) other transmission projects, through special purpose companies. The following table sets forth information relating to the terms of the concessions of the transmission facilities in which we had such partial ownership interest as of December 31, 2020:

 
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Transmission Facility

Special Purpose Company (SPC)

Initial concession date

First Expiration date

Possibility of Extension

Expected (or final) expiration date

Cascavel Oeste – Umuarama Costa Oeste Transmissora de Energia S.A January, 2012 January, 2042 Possible January, 2072
Umuarama - Guaira Caiuá Transmissora de Energia S.A May, 2012 May, 2042 Possible May, 2072
Açailândia
Miranda II
Integração Maranhense Transmissora de Energia S.A. May, 2012 May, 2042 Possible May, 2072

Curitiba -

Curitiba Leste

Marumbi Transmissora de Energia S.A. May, 2012 May, 2042 Possible May, 2072

Paranaíta –

Ribeirãozinho

Matrinchã Transmissora de Energia S.A. May, 2012 May, 2042 Possible May, 2072
Ribeirãozinho – Marimbondo II Guaraciaba Transmissora de Energia S.A May, 2012 May, 2042 Possible May, 2072
Barreiras II – Pirapora II Paranaíba Transmissora de Energia S.A May, 2013 May, 2043 Possible May, 2073
Itatiba – Bateias Mata de Santa Genebra Transmissora S.A May, 2014 May, 2044 Possible May, 2074
Estreito – Fernão Dias Cantareira Transmissora de Energia S.A. September, 2014 September, 2044 Possible September, 2074
Ivaiporã – Londrina Uirapuru Transmissora de Energia S.A. March, 2005 March, 2035 Possible March 2065

 

Distribution Concessions

We originally operated our distribution business pursuant to a concession contract that was signed on June 24, 1999 (retroactive to July 7, 1995), and was set to expire on July 7, 2015. Under the 2013 Concession Renewal Law, we had the right to renew this concession for an additional 30-year period by accepting an amendment to the concession contract. Notwithstanding the changes introduced by the 2013 Concession Renewal Law, we concluded that the renewal of our distribution concession in accordance with the 2013 Concession Renewal Law would not materially affect our results of operations. Accordingly, after a careful evaluation of the conditions imposed by the Brazilian government for the extension of our distribution concession, we decided to request the renewal of this contract and our renewal request was approved by the MME on November 11, 2015. On December 9, 2015, we have executed the fifth amendment to the public Electricity Distribution Service Concession Agreement No. 46/1999 of Copel Distribuição S.A.

This amendment imposes efficiency conditions to Copel Distribuição that are measured through two different metrics: quality of the service and economic-financial sustainability of the company. Failure to comply with any of these metrics (i) for two consecutive years within the first four years of this renewed concession or (ii) in the fifth year of this concession, may, in each case, result in the termination of our distribution concession. From January 1, 2021 on, failure to comply with the quality indicator for three consecutive years or the economic-financial sustainability indicator for two consecutive years may also result in the termination of the distribution concession.

Additionally, non-compliance with quality indicator targets for two consecutive years or three times in five years may lead to restrictions in the payment of dividends and interest on equity to the controlling shareholders of Copel Distribuição, while non-compliance with the economic-financial sustainability indicators may require capital contributions from Copel Distribuição controlling shareholders.

The table below presents the economic and financial and quality indicators established for the first five (5) years after the execution of this amendment.

Economic and Financial Indicators

Quality Indicators (1)

Year

DECi(2)

FECi(2)

2016 N/A

13.61

9.24

2017 EBITDA(3) ≥ 0 12.54 8.74
2018 [EBITDA (-) QRR (4)] ≥ 0 11.23 8.24
2019 {Net Debt(5)/[EBITDA(3) (-) QRR(4)]} ≤ 1/(0.8*SELIC(6)) 10.12 7.74
2020 {Net Debt(5)/[EBITDA(3) (-) QRR(4)]} ≤ 1/(0.8*SELIC(6) 1/(1.11*SELIC(6)) 9.83 7.24
       

___________________

(1) According to ANEEL’s Technical Note No. 0335/2015.

(2) DECi – Duration of outages per customer per year (in hours); and FECi – Frequency of outages per customer per year (number of outages).

(3) Earnings before interest, tax depreciation and amortization, as calculated according to ANEEL regulations.

(4) QRR: Regulatory Reintegration Quota or Regulatory Depreciation Expense. This is the value defined in the most recent Periodic Tariff Review (RTP), plus the General Market Price inflation index (IGP-M) between the month preceding the Periodic Tariff Review and the month preceding the twelve-month period of the economic and financial sustainability measurement.

(5) As calculated according to ANEEL regulations.

(6) Selic base rate: limited to 12.87% per year.

We have complied with the quality indicators for 2019 both with respect to DECi totaling 9.10 in 2019) and FECi (totaling 6.0 in 2019).

 
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COMPETITION

We have concessions to distribute electricity in substantially all of the State of Paraná, and we do not face competition from the four utilities that have been granted concessions for the remainder of the state. As a result of legislation passed in 2004, however, other suppliers are able to offer electricity to our existing Free Customers at prices lower than those we currently charge. However, when a Captive Customer becomes a Free Customer, it is still required to pay to use our distribution grid. The reduction in net revenue of our distribution business is therefore compensated with a reduction in our costs for energy that we would otherwise acquire to sell to these customers.

Furthermore, under certain circumstances, Free Customers may be entitled to connect directly to the Interconnected Transmission System rather than our distribution grid. Unlike a Free Customer’s choice of another energy supplier, in which case that customer must still use our distribution grid and thus pay us the appropriate tariff, our distribution business ceases to collect tariffs from a customer that connects directly to the Interconnected Transmission System. The migration of customers from the distribution grid to the transmission network therefore results in the loss of revenues for our distribution business.

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.

Free Customers are limited to, as from January 1, 2021, with demand of at least 1.5 MW; after January 1, 2022, customers with demand of at least 1.0 MW at any voltage; and, after January 1, 2023, with demand of at least 500 kW at any voltage.

Special customers are costumers with demand of at least 500 kW that opt to be supplied energy by means of alternative sources, such as wind power projects, small hydroelectric power plants, biomass projects, solar plants and others.

As of December 31, 2020, we had 912 Free Customers (of which of 877 were customers of our energy trading company and 35 of Copel GeT), representing approximately 8.0% of our consolidated operating revenue and approximately 14.9% of the total quantity of electricity sold by us.

Copel GeT has 35 Free Costumers as of December 31, 2020. Approximately 55.2% of the megawatts-hours sold under contracts to such customers by Copel GeT expired in 2020. These customers represented approximately 6.3% of the total volume of electricity we sold in 2020, and approximately 3.2% of our consolidated operating revenues.

In the generation business, any producer may be granted a concession to build or manage thermoelectric and small hydroelectric generating facilities in the State of Paraná. Brazilian law provides for competitive bidding for generation concessions for hydroelectric facilities and, since 2017, this requirement applies only to facilities with capacity higher than 50 MW.

In the transmission business, Brazilian law provides for competitive bidding for transmission concessions for facilities with a voltage of 230 kV or greater that will form part of the Interconnected Transmission System.

Brazilian law requires that all of our generation, transmission and distribution concessions be subject to a competitive bidding process upon their expiration. We may face significant competition from third parties in bidding for renewal of such concessions or for any new concessions. The loss of certain concessions could adversely affect our results of operations

 
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ENVIRONMENT

Our construction and operation activities for the generation, transmission and distribution of electric energy, distribution of natural gas and our telecommunications operations are subject to federal, state and municipal environmental regulations.

All of our activities follow our Sustainability Policy, which integrates corporate planning and sustainability management in order to optimize our financial, social and environmental performance. Also, our activities follow our Climate Change Policy, which establishes guidelines for the mitigation of greenhouse gas emission and changes in our business, evaluating risks and opportunities related to climate change.

We request and renew our environmental licenses in accordance with the environmental regulation issued by applicable federal, state and municipal level authorities. We are in compliance with all material environmental regulations and our more recent (post-1986) generation, transmission and distribution projects are in compliance with federal, state and municipal regulations.

Being a signatory to the Global Compact since 2000, we are committed to sustainability. As a founding member of the Brazilian Global Compact Network Committee, created in 2003, we support the movement to disseminate the principles of the Global Compact in promoting effective and consistent articulations between governments, companies and social organizations in favor of social, environmental and economic challenges for sustainability, as well as raising awareness among other Brazilian companies to engage and adopt corporate citizenship as a standard for managing their businesses.

We adopt best market practices to guide and evaluate our performance, and compare practices with global and local references: B3 Corporate Sustainability Index - ISE, Ethos Indicators for Sustainable and Responsible Business Models, and other evaluations and classifications related to ESG (Environmental, Social and Governance) matters.

Through an annual report, we reinforce our commitment to sustainable development and are accountable for our performance related to economic, social, environmental and governance aspects (Integrated Report Copel). This report follows the international guidelines of the Standards model of the Global Reporting Initiative (GRI), and the International Integrated Reporting Initiative (IIRC), and is submitted to independent assurance, to ensure the reliability of the information disclosed.

 
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PLANT, PROPERTY AND EQUIPMENT

Our principal properties consist of the generation and telecommunications facilities described in “Business”. Of the net book value of our total property, plant and equipment as of December 31, 2020 (including construction in progress), generation facilities represented 64.4%, wind farms represented 30.1%, telecommunications represented 0.5%, Elejor represented 3.7%, and Araucária Thermoelectric Plant represented 1.3%. We believe that our facilities generally are adequate for our present needs and suitable for their intended purposes.

In addition, the infrastructure used by the transmission and distribution business is classified as accounts receivable related to the concession, contract assets and intangible assets as described in Notes 4.4, 4.5 and 4.9 to our audited consolidated financial statements.

 
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THE EXPROPRIATION PROCESS

Although we receive concessions from the Brazilian government to construct hydroelectric facilities, we do not receive title to the land on which the facilities are to be located. In order for us to construct, the land must be expropriated. The land required for the implementation of a hydroelectric facility may only be expropriated pursuant to specific legislation, after proving its public interest. We generally negotiate with communities and individual owners occupying the land so as to resettle such communities in other areas and to compensate individual owners. Our policy of resettlement and compensation generally has resulted in the settlement of expropriation disputes, with friendly settlements for most of them. As of December 31, 2020, we estimated our liability related to the settlement of such disputes to be approximately R$ 133.9 million. This amount is in addition to amounts for land expropriation included in each of our hydroelectric facility budgets. 

 
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The Brazilian eLECTRIC Power Industry

General

In February 2021, according to Ordinance No. 002/2021, MME approved the Decennial Energy Plan - PDE 2030, which projects that the installed capacity of electricity generation in Brazil will be 196 in GW in 2030 (not including distributed generation and self-production). It is projected in the 2021 PDE that 87% of this total will be renewable (54% is projected to be hydroelectric and 29% will be alternative sources of energy, such as wind, biomass and small hydroelectric plants), 11% will be thermoelectric, 4% will be solar, and 2% will be nuclear.

As of 2020, approximately 30% of the installed power generating capacity of Brazil is currently owned by Eletrobras (including its wholly-owned subsidiary Eletronuclear and its 50% participation interest in Itaipu). Through its subsidiaries, Eletrobras is also responsible for approximately 44% of the installed transmission capacity equal or above 230 kV within Brazil. In addition, some Brazilian states control entities involved in the generation, transmission and distribution of electricity. They include Companhia Energética de Minas Gerais – CEMIG and us, among others.

Principal Regulatory Authorities

Ministry of Mines and Energy – MME

The MME is the primary regulatory institution of the power industry and acts as the Brazilian governmental authority empowered with policymaking, regulatory and supervisory powers.

National Energy Policy Council – CNPE

The National Energy Policy Council (Conselho Nacional de Política Energética - “CNPE”), created in August 1997, provides advice to the President of the Republic of Brazil regarding the development and creation of a national energy policy. The CNPE is chaired by the MME and is composed of ten ministers of the Brazilian government and five members designated by the President of CNPE. The CNPE was created in order to optimize the use of energy resources in Brazil and ensure the national supply of electricity.

National Electric Energy Agency – ANEEL

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

National Electric System Operator – ONS

The ONS (Operador Nacional do Sistema Elétrico) is a non-profit private entity comprised of electric utilities engaged in the generation, transmission and distribution of electric energy, in addition to other private participants such as importers, exporters and Free Customers. The primary role of the ONS is to coordinate and regulate the generation and transmission operations in the Interconnected Transmission System, subject to the ANEEL’s regulation and supervision. The objectives and principal responsibilities of the ONS include, among others, operational planning for the generation industry, organizing the use of the domestic Interconnected Transmission System and international interconnections, ensuring that industry participants have access to the transmission network in a non-discriminatory manner, assisting in the expansion of the electric energy system, proposing plans to the MME for extensions of the Interconnected Transmission System, and formulating regulations regarding the operation of the transmission system for ANEEL’s approval.

 
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Electric Energy Trading Chamber – CCEE

The CCEE (Câmara de Comercialização de Energia Elétrica) is a non-profit private entity subject to authorization, inspection and regulation by ANEEL. The CCEE is responsible for, among other things, (i) registering all energy purchase agreements in the regulated market, Contratos de Comercialização de Energia no Ambiente Regulado (“CCEAR”) and in the Free Market, (ii) accounting for and clearing short-term transactions and (iii) managing funds generated by some of the regulatory charges. The CCEE is composed of holders of concessions, permissions and authorizations in the electricity industry and Free Customers, and its board of directors is composed of five members, out of which four are appointed by these agents and one by the MME, who is the chairman of the board of directors.

Energy Sector Monitoring Committee – CMSE

The CMSE (Comitê de Monitoramento do Setor Elétrico) was created by the New Industry Model Law to monitor service conditions and to recommend preventative measures to ensure energy supply adequacy, including demand-side action and contracting of energy reserves.

Energy Research Company – EPE

In August 2004, the Brazilian government created the Energy Research Company (Empresa de Pesquisa Energética - “EPE”), a federal public company responsible for conducting strategic studies and research in the energy sector, including the industries of electric power, petroleum, natural gas, coal and renewable energy sources. The studies and research conducted by the EPE subsidize the formulation of energy policy by the MME.

Eletrobras

Eletrobras serves as a holding company for the following federally-owned energy companies: Companhia Hidro Elétrica do São Francisco – CHESF, Furnas Centrais Elétricas S.A., CGT Eletrosul, Centrais Elétricas do Norte do Brasil S.A. – Eletronorte, Companhia de Geração Térmica de Energia Elétrica – CGTEE and Eletrobras Termonuclear S.A. Eletronuclear, Centro de Pesquisas de Energia Elétrica – Cepel and Itaipu Binacional. Eletrobras manages the commercialization of energy from Itaipu and from alternative energy sources, under the Program for incentive to alternative energy sources (Programa de Incentivo às Fontes Alternativas de Energia – “Proinfa”).

Historical Background of Industry Legislation

The Brazilian constitution provides that the development, use and sale of electric energy may be undertaken directly by the Brazilian government or indirectly through the granting of concessions, permissions or authorizations. Historically, the Brazilian electric energy industry has been dominated by generation, transmission and distribution concessionaires controlled by the federal or state governments. Since 1995, the Brazilian government has taken a number of measures to reform the Brazilian electric energy industry. in general, these measures were aimed at increasing the role of private investment and eliminating foreign investment restrictions in order to increase overall competition and productivity in the industry.

The following is a summary of the principal developments in the regulatory and legal framework of the Brazilian electricity sector:

·In 1995, (i) the Brazilian constitution was amended to authorize foreign investment in power generation; (ii) the Concessions Law was enacted, requiring that all concessions for energy-related services be granted through public bidding processes, providing for the creation of independent producers and Free Customers and granting electricity suppliers and Free Customers open access to all distribution and transmission systems; and (iii) a portion of the controlling interests held by Eletrobras and various Brazilian states in generation and distribution companies were sold to private investors.
·In 1998, the Power Industry Law was enacted, providing for, among other things, the creation of the ONS and the appointment of National Bank for Economic and Social Development, or Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”), a development bank wholly owned by the Brazilian government, as the financing agent of the power industry, especially to support new generation projects.
 
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·In 2001, Brazil faced a serious energy crisis that lasted through February 2002. During this period, the Brazilian government implemented an energy-rationing program in the most adversely affected regions, namely the southeast, central-west and northeast regions of Brazil. In April 2002, the Brazilian government for the first time implemented the extraordinary tariff adjustment to compensate the electricity suppliers for financial losses incurred as a result of the rationing period.
·In 2004, the Brazilian government enacted the New Industry Model Law (Law No. 10,848), in an effort to further restructure the power industry with the ultimate goal of providing customers with a stable supply of electricity at reasonable prices. The New Industry Model Law introduced material changes to the regulation of the electric energy industry, in order to (i) provide incentives to private and public entities to build and maintain generation capacity, and (ii) ensure the supply of electricity in Brazil at low tariffs through a competitive electricity public bidding process. The key elements of the New Industry Model Law include:
oEnsuring the existence of two markets: (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 Customers and energy-trading companies), called the Free Market, that permits a certain degree of competition vis-à-vis the regulated market.
oRestrictions on certain distribution activities, including requiring distributors to focus on their core business of distribution activities in order to promote more efficient and reliable services to Captive Customers.
oElimination of self-dealing by providing an incentive for distributors to purchase electricity at the lowest available prices rather than buying electricity from related parties.
oUpholding contracts executed prior to the New Industry Model Law, in order to provide regulatory stability for transactions carried out before its enactment.
·In 2004, Decree No. 5,163 was enacted to governor the purchase and sale of electricity in the regulated market and the Free Market, as well as the granting of authorizations and concessions for electricity generation projects. This decree includes, among other items, rules relating to auction procedures, the form of power purchase agreements and the mechanism for passing costs through to Final Customers. Among other matters, this decree:
oprovides for the guidelines under which electricity-purchasing agents must contract their electricity demand. Electricity-selling agents must show that the energy to be sold comes from existing or planned power generation facilities. Agents that do not comply with such requirements are subject to penalties imposed by ANEEL.
orequires electricity distribution companies to contract for 100% of their energy needs primarily through public auctions. In addition to these auctions, distribution companies can purchase limited amounts (up to 10% of their demand) from: (i) generation companies that are connected directly to a distribution company (except for hydroelectric power plants with capacity higher than 30 MW and certain thermoelectric power plants) (ii) electricity generation projects participating in the initial phase of the Proinfa Program, (iii) the Itaipu Power Plant and (iv) quotas from those generation concession contracts extended or subject to a new competitive bidding process in accordance with the 2013 Concession Renewal Law.
oprovides that the MME shall establish the total amount of energy that will be contracted in the regulated market, including the number and the type of generation projects that will be auctioned each year.
 
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orequires all electricity generation, distribution and trading companies, independent producers and Free Customers to notify MME, by August 1st of each year, of their estimated electricity demand or estimated electricity generation, as the case may be, for each of the subsequent five years. In advance of each electricity auction, each distribution company is also required to inform MME of the amount of electricity that it intends to contract in the auction. In addition, distribution companies are required to specify the portion of the contracted amount they intend to use to supply potentially Free Customers.
·In 2012, the Brazilian government enacted two Provisional Measures that brought important changes to the Brazilian electricity regulatory framework: (i) Provisional Measure No. 577, dated as of August 29, 2012 (converted into Law No. 12,767 dated as of December 27, 2012); and (ii) Provisional Measure No. 579, dated September 11, 2012 (converted into the 2013 Concession Renewal Law). Provisional Measure No. 577 established the obligation of the granting authority to render electricity services in the event of termination of an electricity concession, as well as new rules related to the intervention by the granting authority in electricity concessions to ensure adequate performance of Utility services. The 2013 Concession Renewal Law established new rules that changed concessionaires’ ability to renew concession contracts. Under this Law, generation and distribution concessionaires may renew their concession contracts that were in effect as of 1995 and transmission concessionaires may renew their concession contracts that were in effect prior to and as of 1995 for an additional period of 30 years, provided that the concessionaires agree to amend the concession contracts to reflect a new tariff regime to be established by ANEEL. See “—Concessions”.
·In 2013, the 2013 Concession Renewal Law was enacted. This statute changed the nature of the concession agreements for generation facilities existing at the time. Prior to 2013, a generation concessionaire had the right to sell the energy generated by the facilities subject to its concession for profit. In contrast, generation concessions for existing generation facilities (including those renewed pursuant to the 2013 Concession Renewal Law) could no longer grant concessionaires the right to sell the energy generated by these facilities. Instead, these concessions started to cover the operation and maintenance of the generation facilities. The energy generated by these facilities was then allocated by the Brazilian government in quotas to the regulated market, for purchase by distribution concessionaires. In case of generation facilities created after the 2013 Concession Renewal Law, the concessionaire has the right to sell the energy produced by the facility. For further information, see “—Concessions—2013 Concession Renewal Law.”
·In 2015, the Brazilian government enacted Provisional Measure No. 688, dated as of August 18, 2015, converted into Federal Law No. 13,203, dated as of December 8, 2015, to revise the allocation of the hydrological risks borne by hydroelectric power plants that share hydrological risks under Energy Reallocation Mechanism. In 2014 and 2015, given poor hydrological conditions, the MRE participants generated less electricity than their assured energies, which was confirmed by a significant decrease of the Generating Scaling Factor (“GSF”), a measurement of the proportion between the electricity generated by the MRE participants and their respective assured energy. These generation deficits resulted in losses for the MRE participants given their exposure to hydrological risks. As a consequence, Federal Law No. 13,203 established an optional mechanism that allows each generation plant to transfer these risks to Final Customers upon payment of a risk premium to the Brazilian government, as well as certain temporary extensions of generation concessions to compensate for losses in 2015. We decided to opt-in with respect to all of Copel GeT´s and Elejor´s eligible Energy Agreements under this new hydrological risk allocation mechanism, which represented approximately 16% of Copel GeT´s total assured energy.
·In 2016, the Brazilian government enacted Provisional Measure No. 735, dated as of June 22, 2016, converted into Federal Law No. 13,360, dated as of November 17, 2016, which changed several federal laws mainly to: (i) revise certain rules related to regulatory charges (CDE, CCC and RGE) and appoint CCEE as the new manager of such charges in lieu of Eletrobras; (ii) facilitate the privatization of generation, transmission and distribution companies, (iii) change certain requirements of the generation concession and authorization regimes; (iv) change rules related to the MRE; (v) allow distribution companies to sell energy excess in the Free Market; (vi) extension of terms for commencement of the supply under energy auctions in the regulated market; and (vii) transfer back from MME to ANEEL the authority to decide about generation and transmission companies’ requests for extension of their facilities construction schedules.
 
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·In July 2017, the MME released the Public Consultation No. 033/2017, named “Proposal for improvement of the legal framework of the electricity sector”. This public consultation marks an important step to guide the MME in preparation of specific legislative proposals capable of providing measures of economic rationalization and modernization of the electricity sector.
·In August 2017, Decree No. 9,143/2017 changed the frequency of the auctions for new energy and authorized the distribution companies to negotiate contracts for the sale of energy in the Free Market to Free Consumers and other agents (generators, marketers, and self-producers), provided that these contracts are linked to excess in energy contracted in auctions.
·In January 2018, Decree No 9,271/2018 regulated the granting of a new energy concession in the event of privatization of an energy generation concession holder that provides public services, in accordance with Law No 9.074, dated July 7, 1995. Pursuant to this decree, the Brazilian government may grant a new concession contract for a period of up to 30 years to the entity that results from a bidding process for the privatization of a concessionaire previously controlled directly or indirectly by a federal, state or municipal governmental entity. This decree determined that the concessionaire shall request a new concession contract during the remaining period of its concession (up to 60 months counted from the end of the concession) This decree was amended in November 2019 pursuant to Decree No 10,135 in order to reduce the deadline for the concessionaire to request the granting of a new agreement, from 60 months to 42 months counted from the end of the concession and required the privatization process to be concluded no later than 18 months prior to the termination of the prior concession.
·During 2018, the Brazilian government concluded the privatization of Eletrobras’ distribution companies Companhia Energética do Piauí - Cepisa, Companhia Energética de Rondônia S.A. - Ceron, Companhia de Eletricidade do Acre - Eletroacre, Boa Vista Energia S.A. - Boa Vista Energia, Companhia Energética de Alagoas - Ceal and Amazonas Distribuidora de Energia S.A. - Amazonas Distribuidora.
·In June 2019, the National Energy Policy Council (Conselho Nacional de Política Energética – CNPE) launched a program pursuant to its Resolution No. 16 to boost the natural gas market and foster competition by promoting free competition and using Thermoelectric Plants as a vehicle for creating demand for the better use of natural gas from the Pre-Salt layer.
·In December 2019, MME published the Ordinance No. 465/2019, determining that MME will gradually decrease, over the next years, the power limits to contract electric power by consumers served at any voltage, allowing them to purchase energy from conventional sources, considering the following schedule: (i) from January 1, 2021: consumers with demand equal to or greater than 1,500 kW; (ii) from January 1, 2022: consumers with demand equal to or greater than 1,000 kW; and (iii) January 1, 2023: consumers with demand of 500 kW or more. Furthermore, by January 31, 2022, ANEEL and CCEE shall present studies on the regulatory measures necessary to allow the opening of the Free Market for consumers with electric load below 500 kW.
·In January 2020, the ONS implemented the Short Term Hydrothermal Dispatch Model (Modelo de Despacho Hidrotérmico de Curtíssimo Prazo - DESSEM), in order to optimize the operations of National Interconnected System (Sistema Interligado Nacional – SIN), and to reduce the difference between the planned dispatch and the one that is actually carried out by taking into account factors related to the electric grid, the operation of hydroelectric power plants, Thermoelectric Plants and other sector components. The execution of DESSEM meets the schedule set forth in Ordinance MME nº 301, dated July 31, 2019.
·In September 2020, Law No. 14,052 (the “GSF Law”) was passed, which established new conditions for the renegotiation of hydrological risk of electricity generation, amending Article 2 of Law No. 13,203/2015, among other measures. This procedure was regulated through Normative Resolution No. 895/2020, in which ANEEL established the methodology for calculating compensation to the owners of hydroelectric plants participating in the MRE. It also regulated the repatriation of hydrological risk to equate the issue of GSF and open debts in CCEE to allow for the return of normalcy and greater liquidity in the short-term electricity market, in exchange for the extension of the terms of grants given to hydroelectric plants to up to seven years.
 
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·In December 2020, through Normative Resolution No. 905/2020, ANEEL consolidated the rules for Electric Energy Transmission Services in the National Electric System, effective January 1, 2021.
·In January 2021, the CCEE adopted an hourly pricing model for the accounting and settlement of the short-term market. Thus, since January 1, 2021, the PLD is officially calculated for each submarket on an hourly basis, per the implementation schedule defined by MME Directive 301/2019.
·Additionally, 2020 was atypical due to the COVID-19 pandemic, which required the introduction of various legal and regulatory measures, as highlighted below:
oIn March 2020, Decree No. 6 officially declared a state of emergency in Brazil, effective until December 31, 2020. On the same date, Decree no. 10,282 was released (complemented by Decree No. 10,288/2020), which regulated Law No. 13,979/2020 and dealt with the new COVID-19 measures, including directives regarding the operation of public services and essential activities, specifically the electricity sector and electricity generation, transmission and distribution. By means of Decree No. 117/2020, the MME also established a Crisis Committee within the Ministory’s scope to articulate, coordinate, monitor, guide and supervise the measures and actions taken against COVID-19 for the duration of the public health crisis. In line with the guidelines established by this decree, ANEEL issued Decree No. 6,335/2020, the Office of Monitoring the Electrical Situation (Gabinete de Monitoramento da Situação Elétrica), with the objective of identifying the effects of the COVID-19 pandemic on the electrical energy market and monitoring the economic-financial situation in relation to supply and demand, as well as coordinating studies of proposals to preserve equilibrium between different entities within the sector.
oIn March 2020, to ensure the continuity of electricity distribution services, ANEEL issued Normative Resolution No. 878/2020, solidifying the Agency's first measures in order to guarantee the supply of electricity to certain consumer units that have lost the ability to remain compliant as a result of the COVID-19 pandemic. This especially concerns consumer units related to the supply of energy to services and activities considered essential, as defined by Federal Decrees No. 10,282/2020 and No. 10,288/2020.
oOn April 8, 2020, the Brazilian government issued Provisional Measure No. 950, which specified temporary emergency measures for the electricity sector to cope with the state of emergency by establishing an exemption in energy tariffs funded by the CDE for low-income consumers for up to 220 kWh/month, for the period of April 1 to June 30, 2020. For this purpose, resources were provisioned by means of a credit operation aimed at providing financial relief to electricity distributors. On the same date, ANEEL published Order No. 986, authorizing the CCEE to transfer the surplus financial resources available in the reserve fund for future relief to the sector's agents, based on consumption, with the aim of reinforcing the sector's liquidity in the midst of the COVID-19 pandemic.
oOn May 18, 2020, Decree No. 10,350 was issued by the Brazilian government, which regulated Provisional Measure No. 950/2020 and provided for the creation of the COVID-19 Fund. This fund was to receive resources to cover potential deficits or anticipate distributors' revenues and regulate the use of tariffs by the CDE for the purpose of payments and receipts of amounts to cover or defer costs arising from the COVID-19 pandemic. Through Resolution No. 885/2020, ANEEL established criteria and procedures for the management of the COVID-19 Fund. The value of the resources of the COVID-19 Fund given to concessionaires were made operational by the CCEE throughout 2020, considering, for this purpose, the existence of a positive balance in the fund.
 
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oIn May 2020, by means of Order No. 1,511/2020, ANEEL, suspended the systematic application of the system for activating the Tariff Flags (Bandeiras Tarifárias), under exceptional and temporary circumstances, as provided for in Submodule 6.8 of the Procedures for Tariff Regulation. This added a “green flag” through December 31, 2020 in accordance with the time period stipulated in Federal Decree No. 10,350/2020 to cover the electric sector’s costs with resources from the COVID-19 Fund. This was in effect until November 30, 2020, when it was revoked by ANEEL with the same-day issuance of Order No. 3,364/2020.
oFinally, in September 2020, Provisional Measure No. 998/2020 was issued, due to important changes in the electricity sector rules to mitigate the effects on the consumer due to aid granted to companies as a result of the COVID-19 pandemic, such as transferring 30% of the funds that concessionaires are required to invest in research and development and energy efficiency programs between 2021 and 2025. Notwithstanding these points, this measure also sought to address the withdrawal of incentives for renewable sources, removing the discount on the tariffs for the use of the transmission (TUST) and distribution (TUSD) systems for projects such as small hydroelectric plants and plants based on solar sources, wind power, biomass and qualified cogeneration. These incentives are only being maintained for projects that apply for the concession within twelve months of September 1, 2020 and the start of operations of all its Generating Units within 48 months from the date of concession. In addition, Provisional Measure No. 998 contemplated several other changes in the regulation of the sector, such as the reallocation of resources to reduce energy tariffs for consumers in northern Brazil. Regarding the measure’s effectiveness, it is important to highlight that after being approved by the House of Representatives on December 17, 2020 and by the Federal Senate on February 4, 2021, being sanctioned in March 2021 by the President of the Republic, through Law 14.120, of March 1, 2021.

Potential New Regulatory Framework

The following potential changes to the Brazilian regulatory framework may have a direct impact in our operations, as our business is subject to comprehensive regulation by various Brazilian legal and regulatory bodies, especially the MME (which proposes sector policies) and ANEEL (which regulates, supervises and inspects various aspects of our business, including our tariff rates).

·In February 2018, the MME published on its website a report of the public hearing, reflecting the final proposal for improvements to the energy regulatory framework, which were especially motivated by technological, social and environmental matters, as well as difficulties arising from the current business models. Among the discussed topics, the following stand out:
oTermination of the quota system applicable to hydropower plants (HPP) concessions that have been extended or granted through competitive biddings, in accordance with Federal Law No. 12,783/2013, and allocation of part of the economic benefit of grants to the CDEin order to reduce what is charged to the population;
oLowering the minimum thresholds for accessing the Free Market;
oApproach between the short-term price formation and the operating cost of the system;
oWhether energy and ballast (currently combined for commercialization purposes) should be segregated;
oEffects of the migration of consumers to the Free Market;
oMarket for environmental attributes;
oAttraction of foreign capital for investments in the Brazilian energy sector;
 
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oMore efficient tariff discounts;
oAllocation of resources from the global reversion reserve to the transmission segment;
oGuidelines for the use of research and development resources;
oModernization of the regulated market; and
oReduction of judicial disputes regarding the hydrological risk.
·In May 2018, most of the improvements proposed by the MME with respect to the regulatory framework applicable to the energy sector were included in Bill No. 1,917/2015 of the House of Representatives, known as the bill for the energy bill portability (Projeto de Lei da Portabilidade da Conta de Luz). This bill is still subject to analysis in the House of Representatives and, if approved, will depend on further approval by the Senate and the President of Brazil.
·Also, there are initiatives in order to promote the modernization of the energy sector. Ordinance MME No. 187/2019 established a working group in order to develop proposals for the modernization of the energy sector, which released a report in October, 2019 with measures that should be adopted or studied, including topics such as (i) opening of the consumer market; (ii) pricing mechanism for the short-market; (iii) expansion of the Free Market accommodating new technologies and new business models; (iv) Energy Reallocation Mechanism; (v) cost and risk allocation; (vi) introduction of new technologies; and (vii) sustainable distribution services. This working group has been appointed for a 2-year term, which may be extended for 1 additional year.
·In November 2019, the Brazilian government submitted to Brazilian Congress Bill No. 5,877, which, among other matters, address the privatization of Centrais Elétricas Brasileiras S.A. - Eletrobras. Such bill determines the privatization of Eletrobras pursuant to a capital increase and public offering of new common shares (that entitle their holders to voting rights), resulting in the dilution of the stake held by the Brazilian government in Eletrobras (the “Eletrobras Privatization”). In February 2021, Provisional Measure No. 1,031/2021 on the Eletrobras Privatization was issued.
·In November 2019, ANEEL submitted a proposed amendment to Resolution No. 482/2012 to a public hearing. This resolution refers to the distribution of micro and mini energy generation. The update of such rules was required in 2015 by Resolution 687/2015 and suggests improvements to the credit compensation system in view of changes to distributed generation in recent years.
·In December 2019, CNPE approved its Resolution No. 29, pursuant to which (i) it reviewed the general criteria adopted with respect to supply guarantee in studies on offer expansion, planning of the SIN operations, and calculations of energy physical guarantees and power of a generation project. However, MME shall determine the specific thresholds for such criteria, which is used in the calculation of physical guarantees and plans for expansion.
·In 2020, due to the COVID-19 pandemic, discussions beginning in 2017 between the MME and the electric sector with regards to proposals for the industry’s improvement of the legal and regulatory framework were interrupted. This meant limited progress on measures such as PL No. 1.917/2015 and PLS No. 232/2016, which address issues such as the commercial model of the electric sector, the portability of electricity bills and concessions for electric energy generation. The COVID-19 pandemic also allowed for compromise within Special Commission of the House of Representatives, established in August 2019, regarding the Brazilian Electric Energy Code, which aims to consolidate electricity legislation that is currently scattered between ordinances issued by various government agencies.

These potential changes to the regulatory framework applicable to the Brazilian Energy Sector may impact our operations in the coming years.

 
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Concessions

The companies or consortia that wish to build or operate facilities for generation, transmission or distribution of electricity in Brazil must participate in a competitive bidding process or must apply to the MME or to ANEEL for a concession, permission or authorization, as the case may be. Concessions grant rights to generate, transmit or distribute electricity in a specific concession area for a specified period. This period is 35 years for generation concessions granted after 2003, and 30 years for new transmission or distribution concessions. In accordance with the 2013 Concession Renewal Law, generation and distribution concessionaires may renew their concession contracts that were in effect as of 1995 and transmission concessionaires may renew their concession contracts that were in effect prior to and as of 1995 for an additional period of 30 years, provided that the concessionaires agree to amend the concession contracts to reflect certain new terms and conditions established by the law. The 2013 Concession Renewal Law does not impact generation concessions granted after 2003, as they are non-renewable.

The Concessions Law establishes, among others, the conditions that the concessionaire must comply with when providing electricity services, customers’ rights and the respective rights and obligations of the concessionaire and the granting authority. In addition to the Concessions Law, the concessionaire must also comply with the general regulations governing the electricity sector. The main provisions of the Concessions Law and related ANEEL regulations are summarized as follows:

Adequate service. The concessionaire must render adequate service to all customers in its concession and must maintain certain standards with respect to regularity, continuity, efficiency, safety and accessibility.

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

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

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

Intervention by the granting authority. The granting authority may intervene in the concession, through ANEEL, to ensure the adequate performance of services, as well as the full compliance with applicable contractual and regulatory provisions. Once ANEEL determines the intervention, limited to one year, but extendable for additional two years, it must designate a third party to manage the concession. Within 30 days of the determination of the intervention, the granting authority’s representative must commence an administrative proceeding in which the concessionaire is entitled to contest the intervention. The administrative proceeding must be completed within 1 year. The shareholders of the concessionaire under intervention must submit to ANEEL, within 60 days of the determination of the intervention, a recovery and correction plan. If ANEEL approves such plan, the intervention is terminated. In the event ANEEL does not approve the plan, the granting authority may: (i) declare forfeiture of the concession; (ii) determine the spin-off, incorporation, merger or transformation of the concessionaire, incorporation of a subsidiary or assignment of quotas/shares to a third party; (iii) determine the change of control of the concessionaire; (iv) determine a capital increase of the concessionaire; or (v) determine the incorporation of a special purpose company.

Termination of the concession. The termination of the concession agreement may occur by means of expropriation and/or forfeiture. Expropriation is the early termination of a concession for reasons related to the public interest. An expropriation must be specifically approved by law or decree. Forfeiture must be declared by the granting authority after ANEEL or the MME has made a final administrative ruling that the concessionaire, among other things, (i) has failed to render adequate service or comply with an applicable law or regulation, (ii) no longer has the technical, financial or economic capacity to provide adequate service, or (iii) has not complied with penalties assessed by the granting authority. The concessionaire may contest any expropriation or forfeiture in the courts.

A concession agreement may also be terminated (i) through the mutual agreement of the parties, (ii) upon the bankruptcy or dissolution of the concessionaire, or (iii) following a final, non-appealable judicial decision rendered in a proceeding filed by the concessionaire.

When a concession agreement is terminated, all assets, rights and privileges that are materially related to the rendering of electricity services revert to the Brazilian government. Following termination, the concessionaire is entitled to indemnification for its investments in assets that have not been fully amortized or depreciated, after deduction of any amounts due by the concessionaire related to fines and damages.

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

Penalties. ANEEL regulations govern the imposition of sanctions against electricity sector participants and determine the appropriate penalties based on the nature and importance of the breach (including warnings, fines, temporary suspension from the right to participate in bidding procedures for new concessions, licenses or authorizations and forfeiture). For each infraction, the fines can be up to 2% of the revenue (net of value-added tax and services tax) of the concessionaire in the 12-month period preceding any penalty notice. Some infractions that may result in fines relate to the failure to request ANEEL’s approval to, among other things: (i) execute certain contracts between related parties; (ii) sell or assign the assets related to services rendered as well as impose any encumbrance (including any security, bond, guaranty, pledge and mortgage) on these or any other assets related to the concession or the revenues from electricity services; (iii) effect a change in the controlling interest of the holder of the authorization or concession; and (iv) make certain changes to the bylaws. In the case of contracts executed between related parties that are submitted for ANEEL’s approval, ANEEL may seek to impose restrictions on the terms and conditions of these contracts and, in extreme circumstances, require that the contract be rescinded.

Parallel Environment for the Trading of Electric Energy

Under the New Industry Model Law, the purchase and sale of electricity is carried out in two different segments: (i) the regulated market, which contemplates that distribution companies will purchase by public auction all the electricity they need to supply their customers; and (ii) the Free Market, which provides for the purchase of electricity by non-regulated entities (such as the Free Customers and energy traders).

However, the electricity arising from the following is subject to specific rules different from the rules applicable to the regulated market and to the Free Market: (i) low capacity generation projects located near consumption points (such as certain co-generation plants and small hydroelectric power plants), (ii) plants qualified under the Proinfa Program, an initiative established by the Brazilian government to create incentives for the development of alternative energy sources, such as wind power projects, small hydroelectric power plants and biomass projects, (iii) Itaipu, (iv) Angra 1 and 2 as from 2013 and (v) those generation concession contracts extended or subject to a new bidding process in accordance with the 2013 Concession Renewal Law.

The electricity generated by Itaipu will continue to be sold by Eletrobras to the distribution concessionaires operating in the South, Southeast and Midwest portions of the Interconnected Transmission System. The rates at which Itaipu-generated electricity 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 real/U.S. dollar exchange rate. Changes in the price of Itaipu-generated electricity are, however, subject to the Parcel A cost recovery mechanism discussed as follows under “–Distribution Tariffs”.

Beginning January 2013, the energy generated by nuclear plants Angra 1 and 2 started to be sold by Eletronuclear to the distribution concessionaires at a rate calculated by ANEEL.

The New Industry Model Law does not affect Bilateral Agreements entered into before 2004.

The Regulated Market

In the regulated market, distribution companies must purchase their expected electricity requirements for their Captive Customers in the regulated market through a public auction process. The auction process is administered by ANEEL, either directly or through the CCEE, under certain guidelines provided by the MME.

 
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Electricity purchases are generally made through three types of Bilateral Agreements: (i) Energy Agreements (Contratos de Quantidade de Energia), (ii) Availability Agreements (Contratos de Disponibilidade de Energia) and (iii) allocation of energy quotas, as defined by the ANEEL. 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 case, the generator would be required to purchase electricity elsewhere in order to comply with its supply commitments. Under an Availability Agreement, a generator commits to making 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. With respect to the third method (introduced by the 2013 Concession Renewal Law), the plants that have had their concession renewed under the 2013 Concession Renewal Law lost the right to sell their energy, and from now on will only receive compensation under the energy quota system as a result of the operation and maintenance of such facilities. As a result, energy generated by these generation concessionaires are passed on to distributors at a lower cost through quotas that match the size of the markets served.

With respect to the generation plants with expired concessions, which are subject to a new competitive bidding process, the winner of the competitive bidding process may be required to allocate up to 100% of the energy generated by this plant in quotas to the regulated Market depending on the criteria adopted in the relevant auction process.

The estimate of demand from distributors is the principal factor in determining how much electricity the system as a whole will contract. A distributor is obligated to contract all of its projected electricity needs. A deviation in actual demand from projected demand could result in penalties to distributors. In the event of under-contracting, the distributor is penalized directly in an amount that increases as the difference between the amounts of energy contracted for and actual demand increases. An under-contracting distributor must also pay to meet its demand by purchasing energy in the Spot Market.

In the event of over-contracting, where the contracted volume falls between 100% and 105% of actual demand, the distributor is not penalized and the additional costs are compensated customers’ tariffs. Where the contracted volume is over 105% of actual demand, the distributor must sell energy in the Spot Market. If the contract price proves lower than the current Spot Market price, the distributor sells its excess energy for a profit. On the other hand, if the contract price is higher than the Spot Market price, the distributor sells its excess energy at a loss. The Federal Law No. 13,360, dated November 17, 2016, also permitted the sale of excess energy by distribution companies in the Free Market. Resolutions No. 833, dated December 4, 2018 and 904, dated December 8, 2020, have recently provided additional rules on the methodology to be adopted by distribution companies with respect to the Mechanism of Surplus Sales (Mecanismo de Venda de Excedentes, or MVE).

With respect to the granting of new concessions, regulations provide that bids for new hydroelectric generation facilities may include, among other things, the minimum percentage of electricity to be supplied in auctions in the regulated market. Concessions for new generation projects, such as Mauá and Colíder in our case, are non-renewable, meaning that upon expiration, the concessionaire must again complete a competitive bidding process.

The Free Market

The Free Market covers transactions between generation concessionaires, Independent Power Producers – IPPs, self-generators, energy traders, exporters and importers of electric energy and Free Customers. The Free Market also covers bilateral agreements between generators and distributors signed under the old model, until they expire. Upon expiration, such contracts must be executed under the New Industry Model Law guidelines.

A consumer that is eligible to choose its supplier may only do so upon the expiration of its contract with the local distributor and with advance notice or, in the case of a contract with no expiration date, upon 15 days’ notice in advance of the date on which the distributor must provide MME with its estimated electricity demand for the year. In the latter case, the contract will only be terminated in the following year. Once a consumer has chosen the Free Market, it may only return to the regulated system with five years prior notice to its regional distributor, provided that the distributor may reduce such term at its discretion. This extended period of notice seeks to assure that, if necessary, the distributor can buy additional energy in auctions on the regulated market without imposing extra costs on the captive market.

Private generators may sell electricity directly to Free Customers. State-owned generators may sell electricity directly to Free Customers but are obligated to do so only through private auctions carried out by the state-owned generators exclusively to Free Customers or by the Free Customers.

 
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As mentioned above, recently, Federal Law No. 13,360, dated November 17, 2016, also permitted the sale of excess energy by distribution companies in the Free Market, but the effectiveness of the rule is still subject to further regulation by ANEEL.

Focusing on the future of the electricity sector, the Ministry of Mines and Energy launched Public Consultation No. 33/2017 with the purpose of obtaining the view of different participants around improvements in the business model of the sector. Issues such as the expansion of the Free Market and removal of barriers to the entry of its participants, hourly energy price, adequate allocation of risks, security of supply and socio-environmental sustainability were discussed. Further regulation is expected for the years to come with bills being discussed in the Brazilian Congress in order to implement reforms in the power sector. For more information see “–Potential New Regulatory Framework”.

Regulation under the New Industry Model Law and further rules enacted

A July 2004 decree governs the purchase and sale of electricity in the regulated market and the Free Market, as well as the granting of authorizations and concessions for electricity generation projects. This decree includes, among other items, regulations relating to auction procedures, the form of power purchase agreements and the mechanism for passing costs through to Final Customers.

These regulations establish the guidelines under which electricity-purchasing agents must contract their electricity demand. Electricity-selling agents must show that the energy to be sold comes from existing or planned power generation facilities. Agents that do not comply with such requirements are subject to penalties imposed by ANEEL.

These regulations also require electricity distribution companies to contract for 100% of their energy needs primarily through public auctions. In addition to these auctions, distribution companies can purchase limited amounts (up to 10% of their demand) from: (i) generation companies that are connected directly to the distribution company (except for hydroelectric power plants with capacity higher than 30 MW and certain thermoelectric power plants) (ii) electricity generation projects participating in the initial phase of the Proinfa Program, (iii) the Itaipu Power Plant and (iv) quotas from those generation concession contracts extended or subject to a new competitive bidding process in accordance with the 2013 Concession Renewal Law.

The MME establishes the total amount of energy that will be contracted in the regulated market, the number and the type of generation projects that will be auctioned each year.

All electricity generation, distribution and trading companies, independent producers and Free Customers are required to notify MME, by August 1st of each year of their estimated electricity demand or estimated electricity generation, as the case may be, for each of the subsequent five years. In advance of each electricity auction, each distribution company is also required to inform MME of the amount of electricity that it intends to contract in the auction. In addition, distribution companies are required to specify the portion of the contracted amount they intend to use to supply potentially Free Customers.

Auctions in the Regulated Market

Electricity auctions for new generation projects are held from the third to the seventh year before the initial delivery date of electricity. Electricity auctions for existing generation projects are held (i) from the first to the fifth year before the initial delivery date, and (ii) up to four months before the initial delivery date (“Adjustment Auctions”).

New and existing power generators may participate in the Reserve Energy Auctions as long as these generators increase the power system capacity or if they did not achieve commercial operation by January 2008. Invitations to bid in the auctions are prepared by ANEEL in accordance with guidelines established by the MME, including the requirement that the lowest bid wins the auction. Each generation company that participates in the auction executes a contract for the purchase and sale of electricity with each distribution company, in proportion to the distribution companies’ respective estimated demand for electricity, except for the market adjustment and Reserve Energy Auctions.

 
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The contracts for new generation projects have a term between 15 and 35 years, and the contracts for existing generation projects have a term between 1 and 15 years. Contracts arising from market Adjustment Auctions are limited to a two-year term. The reserve energy contracts are limited to a 35-year term.

The quantity of energy contracted from existing generation facilities may be reduced for three reasons: (i) to compensate for Captive Customers that become Free Customers; (ii) to compensate for market deviations from the estimated market projections (up to 4% per year of the annual contracted amount, beginning two years after the initial electricity demand is estimated); and (iii) to adjust the quantity of contracted energy in bilateral agreements entered into prior to the enactment of the New Industry Model Law.

With regard to (i) above, the reduction in net revenue caused when a Captive Customer becomes a Free Customer is partially compensated by the increased amounts that Free Customers are required to pay to use our distribution system. However, a Free Customer may disconnect from our distribution grid (and therefore cease to pay us a distribution tariff) if it chooses to connect directly to the Interconnected Transmission System or if it generates energy for self-consumption and transports this energy without using our distribution grid. Because a Free Customer that connects directly to the Interconnected Transmission System no longer pays us a distribution tariff, we might not be able to fully recover this loss in revenues.

Since 2004, CCEE has conducted thirty (30) auctions for new generation projects, twenty two (22) auctions for energy from existing power generation facilities, ten (10) auctions for reserve energy in order to increase energy supply security, three (3) auctions from alternative energy sources and seventeen (17) auctions for market adjustments. No later than August 1 of each year, the generators and distributors provide their estimated electricity generation or estimated electricity demand for the five subsequent years. Based on this information, MME establishes the total amount of electricity to be traded in the auction and determines which generation companies will participate in the auction. The auction is carried out electronically in two phases.

After the completion of the auction (except in the case of Reserve Energy Auction), generators and distributors execute the CCEAR, in which the parties establish the price and amount of the energy contracted in the auction. The price is adjusted annually based on price variations published by the IPCA. The distributors grant financial guarantees to the generators (mainly receivables from the distribution service) to secure their payment obligations under the CCEAR.

Also, after completion of the Reserve Energy Auction, the generation concessionaire and the CCEE execute the Contrato de Energia de Reserva, in which the parties establish the price and amount of the energy contracted for in the auction. The distributors, Free Customers and self-producing customers then execute the Contrato de Uso da Energia de Reserva (“CONUER”) with CCEE, in order to provide for the terms of the use of the reserve energy. The reserve energy customers grant financial guarantees to CCEE to secure their payment obligations under CONUER.

The 2013 Concession Renewal Law established that generation concessions entered into prior to 2003 that were not renewed would be subject to a new competitive bidding process and that the energy generated by these facilities will be allocated by the Brazilian government in quotas to the regulated market, for purchase by distribution concessionaires. On November 25, 2015, ANEEL carried out a competitive bidding process for the grant of new 30-year concessions of 29 hydroelectric plants in accordance with the 2013 Concession Renewal Law. Until December 31, 2016, 100% of the electricity generated by such 29 hydroelectric plants must be destined to the regulated market and, as of January 1, 2017, the percentage was reduced to 70%. On September 27, 2017, the ANEEL carried another competitive bidding process for the grant of new 30-year concessions of 4 hydroelectric plants in accordance with the 2013 Concession Renewal Law. In this auction, the percentage destined to the regulate market was 70% since the beginning of the concession.

The Annual Reference Value

Brazilian regulation establishes a mechanism (“Annual Reference Value”) that limits the costs that can be passed through to Final Customers.

The regulation establishes certain limitations on the ability of distribution companies to pass-through costs to customers, such as no pass-through of costs for electricity purchases that exceed 105% of actual demand.

 
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The MME establishes the maximum acquisition price for electricity generated by existing projects. If distributors do not comply with the obligation to fully contract their demand, the pass-through of costs from energy acquired in the short-term market is the lower of the Spot Market price and the Annual Reference Value.

Electric Energy Trading Convention

The Electric Energy Trading Convention (Convenção de Comercialização de Energia Elétrica) regulates the organization and functioning of the CCEE and defines, among other things, (i) the rights and obligations of CCEE participants, (ii) the penalties to be imposed on defaulting agents, (iii) the means of dispute resolution, (iv) trading rules in the regulated and Free Markets, and (v) the accounting and clearing process for short-term transactions.

Restricted Activities of Distributors

Distributors in the Interconnected Transmission System are not permitted to (i) engage in activities related to the generation or transmission of electric energy, (ii) hold, directly or indirectly, any interest in any other company, corporation or strategic agreement, or (iii) engage in activities that are unrelated to their respective concessions, except for those permitted by law or the relevant concession agreement. According to Law No. 13,360/2016, distributors are allowed to sell energy to Free Customers. This possibility is regulated by ANEEL through REH No. 904/2020, with the application of the MVE.

Elimination of Self-Dealing

Since the purchase of electricity for Captive Customers is now performed through auctions in the regulated market, “self-dealing” (under which distributors were permitted to meet up to 30% of their energy needs using energy that was either self-produced or acquired from affiliated companies) is no longer permitted.

Challenges to the Constitutionality of the New Industry Model Law

The New Industry Model Law is currently being challenged on constitutional grounds before the Brazilian Supreme Court. The Brazilian government moved to dismiss the actions, arguing that the constitutional challenges were moot because they related to a provisional measure that had already been converted into law. To date, the Supreme Court has not reached a final decision and we do not know when such a decision may be reached. While the Supreme Court is reviewing the law, its provisions have remained in effect. Regardless of the Supreme Court’s final decision, certain portions of the New Industry Model Law relating to restrictions on distributors performing activities unrelated to the distribution of electricity, including sales of energy by distributors to Free Customers and the elimination of self-dealing, are expected to remain in full force and effect.

Tariffs for the Use of the Distribution and Transmission Systems

ANEEL regulates access to the distribution and transmission systems and establishes tariffs for the use of these systems. The tariffs are (i) network usage charges, which are charges for the use of the proprietary local grid of distribution companies (“TUSD”) and (ii) for the use of the transmission system, which is the Interconnected Transmission System and its ancillary facilities (“TUST”).

TUSD

Users of a distribution grid pay the distribution concessionaire a tariff known as the TUSD (Tarifa de Uso dos Sistemas Elétricos de Distribuição). The TUSD is divided into two parts: one related to the contracted power in R$/kW and another related to the regulatory charges in R$/kWh. The amount paid by the users of a distribution grid is calculated by multiplying the maximum contracted power for each of the customer’s points of connection to the concessionaire’s distribution grid, by the tariff in R$/kW, plus the product of the power consumption by the tariff in R$/kWh, per month.

In relation to the Captive Customers, the TUSD is part of the supply tariff that is calculated based on the voltage used by each customer.

 
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TUST

The TUST (Tarifa de Uso do Sistema de Transmissão) is paid by distribution companies, generators and Free Customers to transmission companies for the use of the Interconnected Transmission System (electrical transmission system with a voltage equal or higher than 230 kV). This tariff is revised annually according to (i) the location of the user of the Interconnected Transmission System and (ii) the annual revenues that a transmission company is permitted to collect for the use of its assets in the Interconnected Transmission System. The ONS, an entity that represents all transmission companies that own assets in the Interconnected Transmission System, coordinates the payment of transmission tariffs to these transmission companies. Users of the Interconnected Transmission System sign contracts with the ONS, which allows them to use the transmission grid in return for paying TUST.

Distribution Tariffs

Distribution tariff rates to Final Customers are subject to review by ANEEL, which has the authority to adjust and review these tariffs in response to changes in energy purchase costs and market conditions. When adjusting distribution tariffs, ANEEL divides the costs of distribution companies into (i) costs that are beyond the control of the distributor, (“Parcel A costs”), and (ii) costs that are under control of distributors (“Parcel B costs”). ANEEL’s tariff adjustment formula treats these two categories differently.

Parcel A costs include, among others, the following:

·costs of electricity purchased by the concessionaire to attend Captive Customers, in accordance to the regulatory model in force;
·charges for the connection to and use of the transmission and distribution grids; and
·energy sector regulatory charges.

Parcel B costs include, among others, the following:

·a component designed to pay the distributor for the investments made by the distributor on the concession assets;
·depreciation costs; and
·a component designed to compensate the distributor for its operating and maintenance costs.

Each distribution company’s concession agreement provides annual readjustments. In general, Parcel A costs are fully passed through to customers. Parcel B costs, however, are adjusted for inflation in accordance with the IPCA Index, minus the X factor.

Electricity distribution concessionaires are also entitled to periodic tariff revisions (revisão periódica) every four or five years. In these processes, Parcel B is recalculated, taking into account incentives for efficiency, quality improvement and reasonable tariff. These revisions are aimed at (i) assuring necessary revenues to cover efficient Parcel B operational costs and adequate compensation for investments deemed essential for services provided within the scope of each such company’s concession and (ii) determining the “X factor”. The fifth amendment to our concession agreement, which establishes the renewal of our concession agreement, determines the Periodic Tariff Review every five years.

The X factor for each distribution company is calculated based on the following components:

·P, based on the concessionaire’s productivity, which is calculated through the productivity of the distribution segment (PTF), determined by the relation between the variation of the billed market and the operating and capital costs, plus the average growth of the billed market and the consumer units of the concessionaire itself;
 
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·T, based on the trajectory of the concessionaire’s operating costs, measured as the difference between the cost benchmarks established by ANEEL and the concessionaire’s actual operating costs; and
·Q, based on quality target indicators that measure the interruption of energy supply to Final Customers, and other quality indicators.

In addition, a distribution concessionaire may request an Extraordinary Tariff Review of its tariffs in case of evident economic-financial imbalance, according to the admissibility criteria established through the Tariff Regulation Procedures (PRORET), sub-module 2.9. Extraordinary tariff adjustments were granted (i) in June 1999 to compensate for increased costs of electricity purchased from Itaipu as a result of the devaluation of the real against the dollar; (ii) in 2000 to compensate for the increase in Social Security Financing Contribution (Contribuição para o Financiamento da Seguridade Social - COFINS) from 2% to 3%; (iii) in December 2001 to compensate for losses caused by the Rationing Program; (iv) in January 2013, due to the enactment of 2013 Concession Renewal Law; (v) in March 2015, to compensate the costs related to the quotas of the CDE and increased costs with the purchase of energy, and (vi) in March 2017, to compensate the amount unduly included in the tariffs for captive consumers in 2016, referring to the Angra III plant.

Since October 2004, on the date of a subsequent tariff adjustment or tariff revision, whichever occurs earlier, distribution companies have been required to execute separate contracts for the connection and use of the distribution grid and for the sale of electricity to their potentially Free Customers.

Tariff Flags (Bandeiras Tarifárias)

Effective as of January 1, 2015, a new system has been introduced by the ANEEL to permit distribution concessionaires to pass on to their Final Customer certain variable cost increases attributable to changes in hydrological conditions in Brazil, prior to the formal tariffs periodic revisions made by ANEEL.

In accordance with this model, a green, yellow or red flag, as determined by ANEEL, is included in invoices sent to Final Customers, reflecting nationwide hydrological conditions (except for the State of Roraima). If a green flag is added to Final Customers’ invoices due to satisfactory hydrological conditions, no additional charges are added. On the other hand, if these invoices contain yellow or red flags, this indicates that distribution concessionaires are facing higher variable costs from the acquisition of electricity and will pass these costs on to Final Customers.

Incentives

In 2000, a Federal decree created the Thermoelectric Priority Program, (Programa Prioritário de Termoeletricidade, or “PPT”), for the purposes of diversifying the Brazilian energy matrix and decreasing Brazil’s strong dependence on hydroelectric plants. The incentives granted to the Thermoelectric Plants included in the PPT were: (i) guarantee of gas supply for 20 years, as per a MME regulation, (ii) assurance that the costs related to the acquisition of the electric energy produced by Thermoelectric Plants will be passed on to customers through tariffs up to the normative value established by ANEEL, and (iii) guarantee of access to a special BNDES financing program for the electric energy industry.

In 2002, the Brazilian government established the Proinfa Program to encourage the generation of alternative energy sources. Under the Proinfa Program, Eletrobras would purchase the energy generated by alternative sources for a period of 20 years. In its initial phase, the Proinfa Program was limited to a total contracted capacity of 3,300 MW. In its second phase, which should start after the 3,300 MW cap has been reached, the Proinfa Program intends to purchase up to 10% of Brazil’s annual electric energy consumption from alternative sources. The first phase of the Proinfa program commenced in 2004 and it so far has supported the construction of 131 alternative energy plants which is expected to reach the production of 11.2 million MWh. According to a decision of ANEEL, the total investment to the Proinfa Program in 2021 will be R$4.0billion.

 
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Energy Sector Regulatory Charges

EER

The Encargo de Energia de Reserva (“EER”) is a regulatory charge designed to raise funds for energy reserves that have been contracted through CCEE and which are deposited in the Reserve Energy Account (Conta de Energia de Reserva – CONER). These energy reserves, which are mandatory, were created in order to attempt to ensure a sufficient supply of energy in the Interconnected Transmission System. The EER shall be collected from Final Customers of the Interconnected Transmission System. Beginning in 2010, this charge has been collected on a monthly basis.

RGR Fund

In certain circumstances, electric energy companies are compensated for certain assets used in connection with a concession if the concession is revoked or is not renewed. In 1971, the Brazilian Congress created a reserve fund designed to provide these compensatory payments (“RGR Fund”). In February 1999, ANEEL established a fee requiring public-industry electric companies to make monthly contributions to the RGR Fund at an annual rate equal to 2.5% of the company’s fixed assets in service, not to exceed 3% of total operating revenues in any year. Since the enactment of the 2013 Concession Renewal Law, the RGR Fund has been used to fund the compensations arising from the termination of non-renewed concessions. The 2013 Concession Renewal Law also allowed the funds from the RGR Fund to be transferred to the CDE.

According to 2013 Concession Renewal Law, as from January 1, 2013, the concession contracts from concessionaires of (i) distribution; (ii) transmission which competitive bidding process occurred after September 12, 2012; and (iii) transmission and generation which had their concession contract renewed or had their underlying facilities subject to a new competitive bidding process are no longer obliged to pay the annual RGR fee.

UBP

Some hydroelectric generation enterprises (except small hydroelectric power plants) are required to make contributions for using a public asset, Uso de Bem Público (“UBP”) according to the rules of the corresponding public bidding process for the granting of concessions. Eletrobras receives the UBP payments in a specific account. See Note 26 to our audited consolidated financial statements.

ESS

The costs related to maintaining system reliability and stability when Thermoelectric Plants generate energy to meet demand in the National Connection System (SIN) are called System Service Charges, or Encargos de Serviços de Sistema (ESS). These amounts are paid by each entity that purchases energy in the Spot Market (CCEE), proportional to each such entity’s consumption.

ESS is expressed in R$/MWh and paid only to Thermoelectric Plants that generate energy in response to requests by the Electricity System National Operator (ONS).

CDE

In 2002, the Brazilian government instituted the Electric Energy Development Account, Conta de Desenvolvimento Energético (“CDE”). The CDE is funded by (i) annual payments made by concessionaires for the use of public assets, (ii) penalties imposed by ANEEL, (iii) the annual fees paid by agents offering electric energy to Final Customers, by means of an additional charge added to the tariffs for the use of the transmission and distribution grids and (iv) transfer of resources from the Federal General Budget. The CDE was originally created, amongst others, to promote the availability of electric energy services to all of Brazil and the competitiveness of the energy produced by alternative sources.

Currently, CDE aims to fund several public policies in the Brazilian electricity sector, such as: universalization of the electricity service throughout the national territory; granting of tariff discounts to various users of the service (low income; rural; Irrigating; public water, sewage and sanitation services; incentive energy generation and consumption, etc.); low tariff on isolated electricity systems (Fuel Consumption Account - CCC); competitiveness of electricity generation from the national coal source; among others. The CDE is managed by CCEE since May, 2017, pursuant to Federal Law No. 13,360/2016. This charge had been substantially reduced by the 2013 Concession Renewal Law (approximately 75% compared to its December 31, 2011 amount) in an attempt to reduce the cost of electricity paid by Final Customers. The 2013 Concession Renewal Law also allowed the funds from the RGR Fund to be transferred to the CDE, provided that the Federal Treasury would also contribute with the CDE and permit the funds deposited in the CDE to be used in support of the electricity generation program in non-integrated electric grids (sistemas elétricos isolados) as well as to partially offset the increased costs borne by distribution concessionaires for the purchase of energy in the Spot Market as a result of the non-renewal of generation concessions due to the 2013 Concession Renewal Law.

 
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On March 7, 2014, the Brazilian government also permitted the transfer to distribution concessionaires of funds deposited in the CDE to cover their respective costs arising from involuntary exposure to the Spot Market in January 2014 as a result of poor hydrological conditions in 2013 and 2014, which mandated the acquisition of thermoelectric energy at higher prices in the Spot Market, costs which distribution concessionaires were not able to pass on to Final Customers through regular Retail Tariffs prior to annual readjustments or formal tariffs periodic revisions made by ANEEL.

Distribution concessionaires will be able to pass on to its Final Customer a CDE charge, to the extent necessary to repay their respective financing obligations contracted by the CCEE through the ACR Account. See “—Regulated Market Account–ACR Account.”

On February 27, 2015, ANEEL approved a significant increase of the CDE fee charged to cover all of these additional costs supported by the CDE. ABRACE, an association of Free Customers filed lawsuits to contest the increase of the CDE fee. Since July 2015, the Free Customers associated with ABRACE benefit from an injunction suspending the increase of the CDE fee. Associations of distributors of energy (ABRADEE, with whom Copel Distribuição is associated) also obtained injunctions suspending its obligation to withhold such CDE fees while ABRACE´s and other consumers’ injunction remains in force.

Federal Law No. 13,360/2016 established that the Brazilian government must prepare a plan for a structural reduction of the CDE charge until December 31, 2017, and it also provided that the revenues, expenses and beneficiaries of the CDE must be published monthly by CCEE, among other changes. As a result, Decree nº 9,642/2018 was published, which determined the gradual reduction, in 5 years, of discounts granted to consumer units classified as Rural and Public Service of Water, Sewage and Sanitation, in Groups A (high voltage) and B (low voltage).

Regulated Market Account – ACR Account.

On April 2014, the Brazilian government created the Regulated Market Account, Conta no Ambiente de Contratação Regulada – Conta-ACR (“ACR Account”), to assist distribution concessionaires to cover their respective costs for the acquisition of thermoelectric energy for the period from February 2014 to December 2014, incurred as a result of poor hydrological conditions. Distributors incurred higher costs as a result of adverse hydrological conditions because they were required to buy thermoelectric energy at higher prices in the Spot Market, and were unable to pass all these costs on to Final Customers prior to a formal tariff periodic revision made by ANEEL. To fund the ACR Account, the Brazilian government authorized the CCEE to enter into credit agreements with certain Brazilian financial institutions. An aggregate of R$21.7 billion, composed of nine tranches, was deposited in the ACR Account. Distribution concessionaires have been repaying this loan since 2015 by charging its Final Customers with additional CDE amounts on a monthly basis. At first, the amount deposited in the ACR Account should be repaid by 2020. However, in March 2019, ANEEL authorized CCEE to negotiate with the creditor financial institutions and seek early termination of the corresponding loans, which occurred in September 2019.

Itaipu Transmission Fee

The Itaipu Hydroelectric Plant has an exclusive transmission grid and is not part of the Interconnected Transmission System. Companies that are entitled to receive electricity from Itaipu pay a transmission fee in an amount equal to their proportional share of the Itaipu generated electricity.

Use of Water Resources Tax

Holders of concessions and authorizations that allow for the exploitation of water resources must pay a total tax of 7.00% of the value of the energy they generate, which for the purposes of this calculation is based on a rate set by ANEEL. Beginning on January 1, 2021, ANEEL set this rate at R$76.00/MWh. The proceeds of this tax are shared among the states and municipalities where the plant or the plant’s reservoir is located, as well as with certain federal agencies.

 
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ANEEL Inspection Fee (TFSEE)

The ANEEL Inspection Fee is an annual fee due by the holders of concessions, permissions or authorizations equal to an ANEEL determined percentage of their revenues. The ANEEL Inspection Fee requires these holders to pay up to 0.4% of their annual revenue to ANEEL in 12 monthly installments.

Default on the Payment of Regulatory Charges

The failure to pay required contributions to the RGR Fund, Proinfa Program or CDE or to make certain payments, such as those due from the purchase of electric energy in the regulated market or from Itaipu, will prevent the defaulting party from receiving adjustments or reviews of their tariffs (except for an extraordinary review) and will also prevent the defaulting party from receiving funds from the RGR Fund or CDE. We comply with payment obligations related to Regulatory Charges.

Energy Reallocation Mechanism

The Energy Reallocation Mechanism (Mecanismo de Realocação de Energia, or MRE) attempts to mitigate the risks borne by hydroelectric generators due to variations in river flows (hydrological risk).

Under Brazilian law, each hydroelectric plant is assigned a determined amount of “assured energy”, according to an energy supply risk criterion defined by MME, based on historical river flow records. The assured energy also represents the maximum energy that can be sold by the generator, which is set forth in each concession agreement, irrespective of the volume of electricity actually generated by the facility.

The MRE tries to guarantee that all participating plants receive the revenue corresponding to their assured energy, irrespective of the volume of electricity generated by them. In other words, the MRE effectively reallocates the electricity, transferring the surplus from those who have produced in excess of their assured energy to those that have produced less than their assured energy. The relocation, which occurs in the Interconnected Transmission System, is determined by the ONS, considering the nationwide electricity demand and hydrological conditions, regardless of the power purchase agreement of each individual generator. The volume of electricity actually generated by the plant, whether more or less than their assigned assured energy quotient, is priced pursuant to a tariff known as the “Energy Optimization Tariff”, designed to cover only the variable operation and maintenance costs of the plant, so that generators are largely unaffected by the actual dispatch of their plants.

Each hydroelectric plant which has its concession contract renewed in accordance to 2013 Concession Renewal Law will no longer participate in the MRE, and the hydrological risk from those plants will be borne by the distribution concessionaires under the National Interconnected Power Grid. For the generation plants with expired concessions, which were subject to a new competitive bidding process under the 2013 Concession Renewal Law, 30% of the generated energy available for the generation concessionaire to sell in the market is also subject to the MRE hydrological risk allocation mechanism. This risk does not impact our distribution business, since we are allowed to increase the tariffs of our distribution customers to compensate any costs arising from this hydrological risk.

Research and Development

The companies holding concessions and permissions for distribution of electricity must invest a minimum of 0.50% of their annual net operational revenues in research and development and 0.50% in energy efficiency programs. Beginning on January 1, 2023, these percentages will become 0.75% and 0.25%, respectively.

A company holding concessions and authorizations for generation and transmission of electricity must invest a minimum of 1% of its annual net operational revenues in research and development. A company that generates electricity exclusively from small hydroelectric power plants, cogeneration or alternative energy projects is not subject to this requirement.

The amount to be invested in research and development must be distributed as follows:

 
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·40% to the company research and development projects, under the supervision of ANEEL;
·40% to the Ministry of Sciences and Technology, to be invested in national research and development projects; and
·20% to the MME, to defray EPE.

In March 2021, Law 14,120/2021 and ANEEL Resolution 929/2021 changed the allocation of research and development resources.

The amount not yet committed to the research and development program until September 2020 will be transferred to CDE as a way to promote tariff moderateness. In the same way, until December 2025, a minimum of 70% of the percentages defined by law must continue to be invested in research and development programs while the difference will be transferred to CDE.

·These measures do not impact the amounts to be invested by the concessionaires, but rather their destination.

Environmental Regulations

The Brazilian Federal Constitution includes environmental matters among the ones that are subject to concurrent legislative competence, meaning that the Brazilian government enacts general rules, which are supplemented by rules passed by states; municipalities, in turn, enact local rules or supplement federal and/or state legislation.

In 1981, the National Environmental Policy was enacted in Brazil (Federal Law No. 6,938/1981). The Federal Environmental Crimes Act (Federal Law No. 9,605/1998), which took effect in 1998, establishes a general framework of liability for environmental crimes. Federal laws and statutes have established the National System for Management of Water Resources and the National Council of Water Resources to address the major environmental issues facing the hydroelectric sector and users of water resources. In 2000, the Brazilian government created an independent agency, the National Water Agency, to regulate and supervise the use of water resources. In 2008, the Federal Decree No. 6,514/2008 was enacted to prescribe the administrative liability due for environmental infractions.

The Brazilian Forestry Code (Federal Law No. 12,651/2012) and related regulations establish rules regarding the maintenance of areas affected by hydroelectric plant reservoirs. These regulations may result in increased maintenance, reforestation and expropriation costs to energy industry concessionaires. We have been developing conservation measures in our power plants, as established in the Brazilian Forestry Code, since their construction.

Under Brazilian environmental Law, one single action that causes risk to the environment can trigger three types of liability: civil, administrative and criminal.

Thus, a violator of an environmental law may be subject to administrative and criminal sanctions and, in case environmental damage occurs, will have an obligation to repair and provide compensation to the affected party. Administrative sanctions may apply to both the company and the individual representatives of the company concomitantly and may include substantial fines of up to BRL 50 million and the suspension of activities. Criminal sanctions may also apply to both company and the individual representatives and include sanctions such as fines for the company and, for individuals including for directors and employees of companies that commit environmental crimes, possible imprisonment.

Our energy generation, distribution and transmission facilities are subject to prior environmental licensing procedures, which may include the preparation of environmental impact assessments before such facilities are constructed, as well as proposing and implementing mitigation and compensation actions for the identified impacts. As a condition for the regularity of these procedures, we must also request authorization from certain regulatory entities, such as Brazilian Institute of National Historic and Artistic Heritage (Instituto do Patrimônio Histórico e Artístico Nacional – IPHAN), an oversight body that is in charge of the protection and preservation of Brazilian cultural heritage (archeological, material and immaterial). Once the respective environmental licenses are obtained, their maintenance is still subject to compliance with certain requirements.

 
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recent developments

Unitization

On March 11, 2021, acting at an Extraordinary Shareholders’ Meeting, the shareholders of Copel approved the Unitization (as defined below) and amendments to Copel’s bylaws to facilitate the Unitization, including the opening of the period for the Conversion Offers (as defined below) and the terms and conditions of the Conversion Offers. With the Units Program (as defined below), we seek to improve the liquidity of the trading market for our securities by establishing units, each consisting of four Class B Shares and one Common Share (“Units”). The steps to establish the Units, taken as a whole, are referred to as the “Unitization”.

Our bylaws were amended at the shareholders meeting of March 11, 2021 to provide for certain changes in our corporate governance necessary to permit our shares or the Units to be listed in the B3 listing segment known as Level 2. These amendments had previously been approved by the Board of Directors at its meeting on January 20, 2021. The effectiveness of these amendments is conditional on the completion of a public offering by the State of shares or Units owned by it and the listing of Copel on Level 2. When they take effect, these amendments will, among other things, (1) provide for a mandatory tender offer to all shareholders upon specified events, including a change of control, removal from the Level 2 with the exception of a removal for the purpose of Copel’s being listed in Novo Mercado, a special listing segment of B3 listing segment, or termination of registration as a public company under Brazilian law, and (2) provide voting rights for the holders of Preferred Shares (Class A Shares and Class B Shares) on matters involving the transformation, merger or spin-off of Copel.

On March 17, 2021, our Board of Directors approved the 1st Share Conversion and Share Depositary Receipt Formation Program (the “Units Program”).

The Unitization includes the following steps, among others:

·From March 22, 2021 to April 20, 2021, of one Common Share and four Class B Shares will be permitted to convert those shares into one Unit (“Standard Conversion Offer”).
·For a concurrent period:
oA holder of five Class A Shares will be permitted to convert all of them into Class B Shares, subsequently one into a Common Share and those shares to one Unit (the “Class A Share Conversion Offer”).
oA holder of five Class B Shares will be permitted to convert one of those shares into a Common Share and then to one Unit (the “Class B Share Conversion Offer”).
oProvided that the number of Copel’s Preferred Shares (including Class A Shares) is bellow 2/3 of the total amount of shares, a holder of five Common Shares will be permitted to convert four of those shares into four Class B Shares and then to one Unit (the “Common Share Conversion Offer,” and together with the Standard Conversion Offer, Class A Share Conversion Offer and Class B Share Offer, the “Conversion Offers”).
·The Conversion Offers will be conditioned on the aggregate number of Units issuable as a result of the Conversion Offers (taken together) attaining 229.172.878 Units (the “Minimum Participation Condition”), calculated so as to represent approximately 60% of the shares in the free float (excluding shares owned by the State). There is no minimum participation condition that applies separately to any of the Conversion Offer.
·The Deposit Agreement governing the Class B ADSs, and the Deposit Agreement governing the American Depositary Shares, each representing one Common Share (the “Common ADSs”), will each be amended to provide that, effective upon completion of the Conversion Offers, there will be a single Deposit Agreement, and each American Depositary Share will represent one Unit (“Unit ADSs”).

 

If the Conversion Offers are consummated, Unit ADSs will trade on the NYSE, and Class B ADSs will no longer trade on the NYSE. A holder of Class B ADSs or Common ADSs will be able to cancel its ADSs and take delivery of the underlying shares, and it will then be able to hold those shares or tender them into the applicable Brazilian Conversion Offer. Any shares that are not converted will remain outstanding. If a holder has a number of Class B ADSs or Common ADSs that is not an integral multiple of five, the Depositary will sell the excess shares necessary to reduce that number to an integral multiple of five and distribute the cash proceeds to that holder.

 
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Share Split

On March 11, 2021, acting at an Extraordinary Shareholders’Meeting, the shareholders of Copel approved the splitting of our shares, pursuant the Brazilian Corporate Law, in the proportion of one share to ten shares, so that for each one share issued by the Company, nine new shares of the same class and type would be credited (the "Share Split"). The shares were traded ex-Share Split as of March 12, 2021 (inclusive), and the shares resulting from the Share Split were credited to the shareholders on March 16, 2021. Considering that the Share Split was carried out in such a way that each share we issued was split into ten shares of the same type and class, there was no surplus resulting from fractions of shares.

The Share Split did not affect our capital stock, which remains at R$10,800,000,000.00 as of March 12, 2021 or impacted any rights of holders of Copel shares. After the Share Split, our capital stock is represented by 2,736,553,750 shares with no par value, of which 1,450,310,800 Common Shares and 1,286,242,950 Preferred Shares and, of these, 3,267,520 are Class A Shares and 1,282,975,430 are Class B Shares. Our management took the necessary measures to implement the Share Split of the ADRs.

Cyber-attacks

On February 1, 2021, a number of our servers suffered cyber-attacks leading to the unavailability of part of our systems. Our systems (Solarwinds) detected the attacks and we immediately followed the security protocols, including suspending the operation of our computerized environment to protect the integrity of the information. Immediately after the event, the Company implemented the Business Crisis Management and Contingency Plan – Cyber-Attack (the “Contingency Cyber Plan”), containing immediate actions to be taken within the scope of a crisis management, and formed an internal Committee to monitor the actions planned. During the assessment of the incident, it was found that the cyber-attack did not have a significant impact on the revenue performance of our business for the year ended December 31, 2020, although it resulted in a small delay in billing in the first days of February 2021 arising from preventive measures to identify the extent of the incident. The incremental expense incurred as a result of the cyber incident was not material, and no provision to be recognized as of December 31, 2020 was identified. It was also found that there was no evidence of destruction, loss, alteration, communication and dissemination of personal data, which rules out any implications for the LGPD.

Although there is no indication that the accuracy and integrity of any financial information and personal data have been affected as a result of the cyber attack incident, we have performed extensive procedures to validate the accuracy and integrity of the information and no access was identified to the computing environment that concentrates our Enterprise Resource Planning (ERP) and billing systems, including in folders and/or files with sensitive personal data. Among the actions set in the Contingency Cyber Plan is the implementation and improvement of policies and internal controls, contributing to the improvement of our information security environment. The competent authorities have been informed about the incident. For more information on our cybersecurity controls, see “Item 3. Key Information―Risk Factors.”

Item 4A. Unresolved Staff Comments

None.

Item 5. Operating and Financial Review and Prospects

The information presented in this section should be read together with our audited consolidated financial statements for the years ended December 31, 2020, 2019 and 2018 that have been prepared in accordance with IFRS as issued by the IASB. For more information see “Presentation of Financial and Other Information” and Note 3 to our audited consolidated financial statements for the year ended December 31, 2020.

The information presented in this section focuses on material events and uncertainties known to our management that could result in reported financial information not being indicative of future operating results or future financial condition, including a quantitative and qualitative description of the reasons underlying material changes. The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ significantly from those discussed in the forward-looking statements for several reasons, including, without limitation, the risks described in “Forward-Looking Statements” and “Item 3. Key Information―Risk Factors.

 
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OVERVIEW

Brazilian Economic Conditions

All of our operations are in Brazil, and we are affected by general Brazilian economic conditions. In particular, the general performance of the Brazilian economy affects demand for electricity, and inflation affects our costs and our margins. The Brazilian economic environment faced periods of instability in recent years, impacting the performance of the Brazilian GDP growth rates, with an increase of 2.3% in 2013 and 0.1% in 2014 and a decrease of 3.8% in 2015. The growth rate was equally negative in 2016, with a decrease of 3.3%. The economic environment showed signs of recovery in 2017, with an increase of 1.0% in growth rate. In 2018 and 2019, the economic environment continued to recover, with an increase of 1.3% and 1.1%, respectively, in growth rate. In 2020, the growth rate decreased by 4.1%.

The following table shows selected economic data for the periods indicated:

 

Year ended December 31,

 

2020

2019

2018

Inflation (IPCA) 4.52% 4.31% 3.75%
Inflation (IGP-DI) 23.7% 7.70% 7.10%
Appreciation (depreciation) of the real vs. U.S. dollar (28.8)% (4.0%) (17.13)%
Period-end exchange rate – US$1.00(1) 5.1967 4.0307 3.8748
Average exchange rate – US$1.00 5.1558 3.9461 3.6558
Change in real GDP (4.1)% 1.1 1.3%
Average interbank interest rates(2) 2.77% 4.40% 6.40%

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(1) The real/U.S. dollar exchange rate at December 31, 2020 was R$5.19 per US$1.00.

(2) Calculated in accordance with Central Clearing and Custody House, or Central de Custódia e Liquidação Financeira de Títulos (“CETIP”), methodology (based on nominal rates).

Sources: FGV ‒ Fundação Getúlio Vargas, the Brazilian Central Bank, the Brazilian Geography and Statistics Institute IBGE and CETIP.

Rates and Prices

Our operational results are significantly affected by changes in the prices at which our generation business sells energy, and by the prices at which our distribution business buys and resells energy.

Our generation business sells energy at unregulated prices in the regulated market, in the Free Market and in the Spot Market. Our generation business allocates the amount of energy that it sells in each of these markets seeking to maximize returns, based on factors such as: (i) the requirements of its concession contracts, many of which set a minimum percentage of energy generated in a particular concession that must be sold in the regulated market; (ii) the volume of energy that we plan to sell to Free Customers for a given year; and (iii) the outlook of the short-term, medium-term and long-term for energy prices generally. Although sales in the Free Market and the Spot Market are not directly regulated, they are influenced by energy regulatory policy. The prices at which our generation business sells energy are not regulated.

Our distribution business purchases enough energy to meet 100% of the demand we forecast for our Final Customers in auctions at unregulated prices in the regulated market. Our distribution business resells that energy to Final Customers at regulated tariffs that take into consideration the price at which the energy was purchased. If our forecasts fall short of the actual electricity demand of our Final Customers, we may be forced to make up for the shortfall by entering into short-term agreements to purchase electricity in the Spot Market. If our forecasts exceed the actual demand of our Final Customers, our distribution business sells the excess energy in the Spot Market. The margins in our distribution business tend to be relatively stable due to the regulated nature of the distribution business, while the margins in our generation business are typically larger but less stable, since they are not substantially market regulated.

Sales to Final Customers (which include sales by our distribution business to Captive Customers, sales by our generation business and sales by our trading business to Free Customers) represented approximately 50.7%of the volume of electricity we made available in 2020, and accounted for 68.7%of our energy sales revenues. Almost all of such sales were to Captive Customers. For more information, see “Item 4. Information on the Company—The Brazilian Electric Power Industry—Distribution Tariffs”. In general, if our costs for energy increase, the tariff process permits us to recover these costs from our customers through higher rates in future periods. However, if we do not receive tariff increases to cover our costs, if the recovery of these costs is delayed, or if our Board of Directors elects to reduce the tariff increase awarded by ANEEL, our profits and cash flows may be adversely affected.

 
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ANEEL modifies our Retail Tariffs annually, generally in June. Since January 2013, the adjustments have been as follows.

·In January 2013, due to the enactment of 2013 Concession Renewal Law, we were subject to an extraordinary revision that has been approved by ANEEL. The average impact of this extraordinary review in the tariffs we charge our customers was a decrease of 19.28%.
·In June 2013, ANEEL approved the annual revision of our Retail Tariffs, increasing them by an average of 13.08%, of which 11.40% related to the tariff increase and 1.68% referred to an increase in recovery of deferred regulatory accounts (CVA). After giving effect to the recovery of Parcel A costs, the average effect of this tariff readjustment on our Captive Customers was an increase of 14.61%. However, Copel Distribuição requested a partial deferral of this adjustment, which was authorized by ANEEL and approved on July 9, 2013. The amount of R$255.9 million was therefore deferred, and included as a financial component in the 2014 annual revision. This deferral reduced the average effect of the tariff adjustment to 9.55%.
·In June 2014, ANEEL approved the annual adjustment of our Retail Tariffs, increasing them by an average of 35.38%, of which 25.05% related to the tariff increase and 10.34% related to an increase in recovery of deferred regulatory accounts (CVA). After giving effect to the recovery of Parcel A costs, the average effect of this tariff adjustment on our Captive Customers was an increase of 39.71%. However, Copel Distribuição requested a partial deferral of this adjustment, which was authorized by ANEEL and approved on July 22, 2014. The amount of R$898.3 million was therefore deferred and included as a financial component in the 2015 annual readjustment. This deferral reduced the average effect of the tariff revision to 24.86%.
·In March 2015, ANEEL approved an extraordinary revision due to a series of events that significantly impacted the distribution concessionaires’ costs, which were not originally foreseen in the 2014 Retail Tariff increase, such as the increase of Itaipu tariffs (46.14%) and higher prices to purchase energy in recent energy auctions. Copel Distribuição’s Average Tariff revision approved by ANEEL was 36.79% starting from March 2, 2015. Of this total, 22.14% related to CDE charges that have been passed to customers and 14.65% relates to (i) Itaipu’s tariff increase and (ii) the higher prices paid by us to purchase energy in recent energy auctions that have been passed to customers.
·In June 2015, ANEEL authorized the annual revision of Copel Distribuição’s tariff to Final Customers, increasing them by an average of 15.32%, of which (i) 20.58% related to the inclusion of the financial components, which will be recovered in the 12 months subsequent to the adjustment (including the amount of R$935.3 million corresponding to the deferrals in 2013 and 2014), (ii) 0.34% related to the restatement of Portion B, (iii) (3.25)% related to the adjustment of Portion A, and (iv) (2.35)% reflected the removal of the financial components from the previous process. The adjustment was fully applied to Copel Distribuição’s tariffs as of June 24, 2015.
·In June 2016, ANEEL approved the fourth periodic review of our Retail Tariffs, decreasing them by 12.87%, of which: (1.73)% related to the inclusion of financial components; 4.48% due to the update of Portion B; (2.57)% related to the update of Portion A; and (13.05)% reflecting the removal of the financial components of the previous tariff process.
·In March 2017, ANEEL approved an extraordinary tariff revision to correct the amount unduly included in the tariffs for captive consumers in 2016. The return corresponded to the energy that was to be generated by the Angra III power plant; however, the plant was not yet in commercial operation. The refund of the amount charged the most was made in a single installment during the month of April 2017, and, as of May 2017, the tariffs were adjusted to disregard the amount that was being charged. The decision, of extraordinary character, affected 90 distributors of electric power of the country. Copel’s retail tariff was reduced by an average of 11.8% during April 2017, and in May 2017, the tariff was close to its previous value, retaining an average discount of 1.27% until June 2017.
 
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·In June 2017, ANEEL approved the annual revision of our Retail Tariffs, increasing them by an average of 3.13%, of which 3.86% related to the tariff increase and (0.73)% related to the inclusion of financial components. After the removal of the financial components of the previous tariff process, the average effect of this tariff adjustment on our Customers was an increase of 5.85%.
·In June 2018, ANEEL approved the annual revision of our Retail Tariffs, increasing them by an average of 14.32%, of which 7.80% related to the tariff increase and 6.52% related to the inclusion of financial components. After the removal of the financial components of the previous tariff process, the average effect of this tariff adjustment on our Customers was an increase of 15.99%.
·In June 2019, ANEEL approved the annual readjustment of our Tariffs, increasing them on average by 8.57%, with -1.96% related to the variation in economic revenue and 10.54% related to the inclusion of financial components. After removing the financial components from the previous tariff process, the average effect of the tariff adjustment on our consumers was an increase by 3.41%.
·In June 2020, ANEEL approved the annual readjustment of our supply tariffs, which represented a tariff repositioning index of 15.84%, comprised of a variation of 8.68% in the economic components and 7.16% in the financial components. After removing the effect of the financial variables from the previous tariff process, the average effect perceived by the customers would be 5.39%. However, in an aim to reduce the impact on electric bills due to the financial consequences of the COVID-19 pandemic, ANEEL created the COVID-19 Fund, a loan operation between various banks contracted by the CCEE in order to dilute tariff increases in the next five years. Thus, Copel Distribution asked that the effects the COVID-19 Fund be applied to our annual tariff readjustment in the amount of R$536 million, equivalent to the accumulated total of the Compensation Account for the Variation of Items of Parcel A (CVA), considered a negative financial component, ultimately reducing the effect on the consumer. With the removal of the previous year’s financial components, the final average effect perceived by the consumer was 0.41%.

Purchase and Resale of Energy

Our distribution business purchases energy from generation companies and resells this energy to Final Customers at regulated rates. For more information, see “Item 4. Information on the Company— Business—Generation” and “Item 4. Information on the Company—Business—Purchases for the captive market”. Our major long-term contracts or purchase obligations are described as follows.

·We purchase energy from Itaipu at prices that are determined based on the Itaipu project’s costs, including servicing its U.S. dollar-denominated debt. In 2020, our electricity purchases from Itaipu amounted to R$1,766.0 million;
·Our distribution business is required to purchase a large portion of its energy needs from the regulated market. For more information, see “Item 4. Information on the Company—The Brazilian Electric Power—Industry—Concessions—Auctions in the Regulated Market”.

Under current legislation, the amount that our distribution business charges Final Customers is composed of two fees: a fee for the actual energy consumed and a fee for the use of our distribution grid. Since the regulated rates at which our distribution business sells energy to Final Customers are substantially the same as the rates at which it purchases energy (after accounting for deductions and the cost of energy purchased for resale), our distribution business does not generate operating profit from the sale of electricity to Final Customers. Rather, our distribution business generates operating profit principally by collecting tariffs for the use of our distribution grid.

 
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Impact of the CRC Account

One of our most significant assets consists of the obligations of the State of Paraná under an agreement that was last amended in October 2017. These obligations derive from amounts we were entitled to recover under a prior regulatory regime, and as a result they are referred to as the recoverable rate deficit account or “CRC Account” (Conta de Resultados a Compensar). The balance is adjusted for IGP-DI, plus interest at 6.65% per year, and is payable in monthly installments until April 2025. If the State of Paraná fails to make payments on a timely basis, we may apply dividends we owe to the State of Paraná in its capacity as our shareholder against amounts it owes us under the CRC Account agreement.

In June 2016, as per the request of the Paraná State Government, our Board of Directors approved an amendment to the CRC Agreement, contingent upon the approval of the Brazilian Department of Treasury, comprising: (i) a grace period from April 2016 to December 2016, in which no principal and interest amounts were paid under the CRC Agreement; and (ii) a grace period from January 2017 to December 2017, in which amounts corresponding exclusively to the interest were paid monthly, but no principal amounts were paid. All other provisions of the CRC Agreement were maintained as they were, including the maintenance of the current correction and interest rates, thus not affecting the global net present value of such agreement.

The Company and the State of Paraná formalized the above-mentioned amendment on October 31, 2017, after the consent from the Brazilian Department of Treasury. The State of Paraná complied with the agreed terms of such amendment and made monthly interest payments until December 2018. As of December 31, 2020, the outstanding balance of the CRC Account was R$1,392.6 million.

As of January 1, 2021, there were 52 monthly installments left. For additional information, see Note 8 to our audited consolidated financial statements.

Special Obligations

The contributions received from the Brazilian government and our customers exclusively for investment in our generation assets, transmission and distribution grid are named as special obligations. We record the amount of these contributions on our statement of financial position as a reduction of our intangible and financial assets, under the caption “special obligations”, and, upon the conclusion or termination of the operating concession granted to us, the amount of these contributions is offset against intangible and financial assets. The amount we recorded as special obligations as of December 31, 2020 was R$2,750.1 million as a reduction of intangible assets and R$29.8million as a reduction of contract assets.


 
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CRITICAL ACCOUNTING POLICIES

In preparing our financial statements, we make estimates concerning a variety of matters as referred to in Note 3.4 to our audited consolidated financial statements. Some of these matters are highly uncertain, and our estimates involve judgments we make based on the information available to us. We have discussed in “Overview” above certain accounting policies relating to regulatory matters. In the discussion below, we have identified several other matters for which our financial information would be materially affected if either (i) we reasonably used different estimates or (ii) in the future we change our estimates in response to changes that are reasonably likely to occur.

The discussion below addresse only those estimates that we consider    most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate. There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation. Please see Note 3.4 to our audited consolidated financial statements included herein for a more detailed discussion of the application of these and other accounting policies.

Basis of consolidation

 

Investments in joint ventures and associations are recognized in the consolidated financial statements based on the equity method and the financial statements of the subsidiaries are included in the consolidated financial statements as from the date they start to be controlled by us until the date such control ceases. Noncontrolling interests are presented in equity, separately from the equity attributable to our shareholders. When required, for calculation of equity in earnings, the investees' financial statements are adjusted to align their policies with our accounting policies.

The analysis of the acquisition of new equity interests is done on a case-by-case basis to determine whether the transaction represents a business combination or an asset purchase and the values ​​of the business combination are recorded using estimates mainly in the definition of the fair value of the acquired equity interest. Transactions between companies under common control do not constitute a business combination. There was no relevant business combination this year.

Financial Instruments

 

Financial instruments are recognized immediately when the obligation or right arises, at fair value, unless it is a trade receivable without a significant financing component, plus, for an item not measured at fair value through profit or loss, any directly attributable transaction costs. Fair values are determined based on market prices for financial instruments with active market, and by the present value method of expected cash flows, for those that have no quotation available in the market. Please see Notes 4.2 and 35 to our audited consolidated financial statements for more detail about our financial instruments.

Net Sectorial Financial Assets and Liabilities

The amendment to our distribution concession agreement, executed on 2014, provides that, in the event of termination of the concession for any reason, the residual values of Portion A items and other financial components not recovered or returned through tariff are incorporated in the calculation of compensation or deducted from unamortized assets indemnity values. Therefore, we recognize sectorial financial assets and liabilities, considering that the contract protects the concessionaire's right or obligation with the Granting Authority regarding these assets and liabilities.

The balances of the net sectorial financial assets and liabilities, evaluated based on the Company's estimates, comprise: a) Portion A Variation Compensation Account - CVA, which records the variation between estimated and actual energy purchase and transmission costs and sector charges, and b) financial items, which correspond to energy over-contracting, neutrality of charges and other rights and obligations included in the tariff. The final values, included in the tariff, are defined by Aneel. During the year this group of accounts had an impact due to the effects of the Covid Account, as presented in Notes 1 (a) and 9 of our consolidated financial statements.

 
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Accounting for Concession Arrangements – Accounts receivable related to the concession, Contract Assets, Intangible Assets and Accounts payable related to the concession

       We account for our concession contracts segregated in: Accounts receivable related to the concession, Contract Assets and Intangible Assets, as presented in Notes 4.4, 4.5 and 4.9 to our audited consolidated financial statements. In addition, accounts payable related to the concession are recorded, as presented in Note 4.6 to our audited consolidated financial statements. Estimates and judgments in the valuation of these items are relevant and may cause significant impacts, in view of the representativeness of these balances in our consolidated financial statements.

Concession of electric power distribution

The portion that we recognize as a financial asset refers to the indemnification provided for in the concession agreement for public electricity distribution services that guarantees the unconditional right to receive cash at the end of the concession, to be paid by the granting authority. This indemnification aims to reimburse the Company for investments made in infrastructure, without recovery, through the tariff. We calculate the cash flows linked to these assets considering the value of the tariff base called the Regulatory Remuneration Base - BRR, defined by the granting authority, using the methodology of replacement cost of the assets that are part of the distribution infrastructure linked to the concession.

The portion that we recognize as contract asset represents the contractual right of the concessionaire related to the works under construction to meet the needs of the distribution concession, accounted for at cost plus financial charges, when applicable. When these assets are put into operation, we transfer to the intangible asset the amount equivalent to what will be remunerated by the user through payment of the fee for the use of the services, and for the receivables linked to the concession, the amount equivalent to the residual portion of the assets not amortized which will be reverted to the granting authority through indemnification at the end of the concession.

The portion that we recognize as an intangible asset comprises the right to exploit the infrastructure, built or acquired under the concession regime for the public electric power service, and to charge users for the public service rendered. We record at acquisition cost, including borrowing costs, less accumulated amortization and impairment losses, when applicable. The amortization of this intangible asset reflects the pattern in which we expect the future economic benefits of the asset to be consumed, with amortization expected during the concession term.

Concession of electric power transmission

The portion that we recognize as a contract asset represents the balance of the public electricity transmission service contracts signed with the granting authority to build, operate and maintain the high voltage lines and substations of the generation centers up to the distribution points. During the term of the agreement, we receive, subject to performance, a remuneration denominated Annual Revenue Allowance (RAP) that amortizes the investments made in the construction of the infrastructure and covers the costs of operation and maintenance incurred. After the start of the commercial operation and to the extent that the operation and maintenance service - O&M is provided, the portion of RAP referring to O&M revenue is recognized in profit or loss at fair value, on a monthly basis, and billed together with the revenue part recognized in the construction phase, referring to the remuneration of the built-up assets. This amount billed after complying with the O&M performance is reclassified to the financial asset under Customers until its effective receipt. The revenue in the construction phase is estimated at fair value based on the budgeted cost of the work and used by management as a parameter for bidding on the concession auction. Fair value revenue comprises the budgeted cost for the entire construction period plus the construction margin, which represents sufficient profit to cover the costs of managing and monitoring the work. The remuneration rate of each concession is determined by the projection of the expected cost, of the profit margin on the cost in the construction phase and also of the projection of the RAP to be received in the operational stage, already net of the variable consideration estimate (PV) and the RAP part of the O&M performance. This fair value valuation technique using the income approach discounts cash flow for the entire concession period, determining at initial recognition the implied rate that zeroes the flow over time. This remuneration rate is fixed at the initial period and does not change during the performance of the contract and represents the market rate in effect at the time under the conditions of the negotiation between parties.

The assets arising from the construction of the transmission infrastructure are formed by the recognition of the construction revenue and its financial remuneration. We recognize gains and losses due to efficiency or inefficiency in the construction of the infrastructure and due to periodic tariff review (RTP), when incurred, directly in the statement of income for the year. Upon expiration of the concession, if there is a remaining balance not yet received related to the construction of the infrastructure, it will be received directly from the granting authority, as provided in the concession agreement, as compensation for the investments made and not recovered through RAP.

 
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We have not recognized intangible assets for energy transmission concession contracts.

Concession of electric power generation

We recognize as a financial asset the concession agreement for quota generation that provides for the payment of a bonus for the grant, considering that this bonus represents an unconditional right to receive cash, guaranteed by the granting authority during the term of the concession and without risk of demand. The remuneration of this financial asset is based on the weighted average cost of capital (WACC).

We also recognize as financial assets the electricity generation concession contracts that contain clauses for indemnification of the infrastructure not depreciated, amortized and / or received during the term of the concession. At the end of each reporting period, we evaluate the recoverability of the asset, remeasuring its cash flow based on our best estimate.

In intangible assets, we record the onerous concession contract for the generation of electric energy, which corresponds to the acquisition of the right to exploit the hydroelectric power generation potential whose contract provides for payments to the Brazilian government as Use of Public Property - UBP. During the construction of the project, we recognize the amount at the present value of the future cash outflows during the period of validity of the concession agreement. On the date of commencement of the commercial operation of the enterprise, the amount presented is fixed and amortized during the concession period.

We also recognize as an intangible asset the asset constituted by the Generation Scaling Factor (GSF), derived from the excess amount between the amount recovered from the cost and the MRE (GSF) adjustment factor, subtracted from the total cost of the risk premium to be amortized over the period of energy supply in the regulated environment. The amount was transformed by ANEEL into an extension of the grant period, which we amortized on a straight-line basis as from January 1, 2016 until the end of the new concession term.

We did not recognize a contract asset for the power generation concession contracts

Distribution of piped gas

The portion that we recognize as a financial asset is the one that will be indemnified by the granting authority corresponding to the investments made in the ten years prior to the end of the concession provided for in the agreement and which, in Management's opinion, guarantees the unconditional right to receive cash at the end of the concession. We use the indemnification premise based on the replacement cost of the concession assets.

The portion that we recognize as a contract asset comprises the works in progress for the distribution of piped gas which will be transferred to the intangible asset upon its entry into operation and to the extent that the right (authorization) to receive the users is received and the portion that we recognize as an intangible asset corresponds to the users' right to charge for the gas supply. We initially valued this asset at acquisition cost, including interest and other capitalized financial charges. We apply the linear depreciation method based on the estimated useful life of each asset, considering the standard of economic benefit generated by the intangible assets.

Accounts payable related to the concession

We record the amounts set forth in the concession agreement in connection with the right to explore hydraulic power generation potential (onerous concession), whose agreement is signed as Use of Public Property agreements. The obligation is recognized on the date of signature of the concession agreement corresponding to the present value of future cash payments for the concession and, from the on, we remeasure the liability using the effective interest rate and reduced by contractual payments.

Inventories (including property, plant and equipment and contract assets)

 

We recognize materials and supplies in inventory, classified under current assets, and those assigned for investments, classified under property, plant and equipment, and contract assets, at their average acquisition cost and the amounts do not exceed their net realizable value. We have no impairment recorded in the inventory.

 
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Property, Plant and Equipment

 

We have adopted the deemed cost methodology to determine the fair value of Copel Geração e Transmissão’s property, plant and equipment, specifically for the generation business as of the date of transition of our financial statements to IFRS (January 1, 2009). These assets are depreciated according to the linear method based on annual rates set forth and reviewed periodically by ANEEL, which are used and accepted by the market as representative of the economic useful life of the assets related to concession’s infrastructure, limited to the term of said concession, when applicable. The estimated useful life, the residual amounts, and depreciation are reviewed as of each reporting date, and the effect of any changes in estimates is recorded prospectively, which may have a material impact.to our consolidated financial statements, considering the representativeness of the balance of Property, Plant and Equipment in the total assets of the Company. The assumptions and estimates of impairment of these assets are dealt with in the next item.

Impairment of Assets

Financial assets

Our provisions for losses on financial assets are based on assumptions about default risk, existing market conditions and future estimates at the end of each year.

We estimate the expected credit losses in amounts deemed sufficient to cover potential losses on the realization of customer receivables and others whose recovery is considered unlikely. We account for the balance of expected credit losses based on the credit risk analysis, taking into account specific payment history criteria, recovery actions for credit recovery and the relevance of the amount due in the receivables portfolio. See Notes 4.10.1 and 7.3 to our consolidated financial statements for further details. During this year, this account had impacts due to the coronavirus pandemic, as described in note 1 (a) of our consolidated financial statements.

Non-financial assets

Non-financial assets, primarily property, plants and equipment assets, comprise a significant amount of our total assets. We evaluate our long-lived assets and make judgments and estimates concerning the carrying value of these assets, including the amounts to be capitalized, the depreciation/ amortization rates and useful lives of these long-lived assets. The carrying values of these assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of future revenues and costs related to the assets subject to review. These forecasts require assumptions about the demand for our products and services, future market conditions and regulatory developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Please see Notes 4.10.2 and 17.5 to our audited consolidated financial statements for more detail.

Provisions

Our subsidiaries and we are party to certain legal proceedings in Brazil arising in the normal course of business regarding tax, labor, civil and environmental claims.

Provisions are recognized when, and only when: (i) the Company has a present obligation (legal or constructive) resulting from a past event, (ii) it is probable (i.e., more likely than not) that an outflow of resources embodying economic benefits will be required to settle the obligation, and (iii) a reliable estimate can be made of the amount to settle the obligation. By their nature, risks will only be resolved when a future event or events occur or fail to occur. Typically, such events will occur a number of years in the future. The evaluation of these risks is performed by our internal and external legal counsel. Accounting for risks requires significant judgment by management concerning the estimated probabilities, including classification as probable or possible losses and ranges of exposure to potential liability. Management’s assessment of our exposure to risks could change as new developments occur or more information becomes available. The outcome of the risks could vary significantly and could materially impact our consolidated results of operations, cash flows and financial position. For more information, see Note 29 to our audited consolidated financial statements.

 
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Revenue Recognition

Revenue from contracts with customers is measured based on the consideration that we expect to receive in a contract with the customer, net of any variable consideration. We recognize revenues when we transfer control of the product or service to the customer and when it is probable to receive the consideration considering the client's ability and intention to pay the consideration when due. We record unbilled revenue, by estimate, when there is no information on the effective revenue incurred.

Interest income is recognized on a straight-line basis and based on time and the effective interest rate on outstanding principal amounts, when it is probable that future economic benefits will flow to us and its amount can be reliably measured.

Revenue related to construction services for infrastructure in the power transmission and distribution services, and gas distribution, are recognized using the percentage of completion method.

Significant changes in the assumptions used for valuing revenue may have a material impact on the Company's results. Additional information is contained in Notes 4.12 and 4.13 to our audited consolidated financial statements.

Construction revenues and costs

We recognize construction revenues and construction costs for construction activities we perform in connection with our distribution and transmission concessions. Our distribution business outsources power distribution infrastructure construction and recognize construction costs and revenues in roughly the same amounts. In contrast, since our transmission business performs much of our transmission infrastructure construction, we recognize construction revenue in amounts that exceed construction costs, resulting in a margin that is calculated based on a methodology that takes into account business risk. Changes in the assumptions to define the construction margin may cause impacts to the consolidated financial statements.

Power purchase and sale transactions in the Spot Market (Electric Energy Trading Chamber - CCEE

We record power purchase and sale transactions in CCEE on the accrual basis of accounting, based on data released by CCEE, which are calculated by the product of the Differences Settlement Prices - PLD multiplied by the energy surplus declared with CCEE, or, when such information is not available in a timely manner, by an estimate prepared by our Management.

Derivative Financial Instruments

We negotiate energy purchase and sale operations and part of our contracts are classified as derivative financial instruments measured at fair value through profit or loss. We recognize in the income for the period unrealized net gains or losses arising from the mark-to-market of these contracts, based on the difference between contracted and market prices.

In addition, we enter into non-deliverable forward contracts, which aim exclusively at providing hedge against exchange rate risks associated with cash flows from capital contributions to subsidiaries, when they reflect foreign-currency denominated purchases of projected equipment. They are measured at their fair value, with changes recorded in the statement of income for the year. The fair value is calculated based on the information of each contracted operation and the respective market information on the closing dates of the financial statements.

Changes in the energy futures price curve and and foreign currency, as well changes in the assumptions for calculating the fair value of these derivatives may have a material impact to the Company’s results. For more information, see Notes 35.2.3 (b) and 35.2.12 to our audited consolidated financial statements.

Taxes

We record Income Tax and Social Contribution and other taxes recoverable and other tax obligations based on applicable law, as described in Note 4.16 to our audited consolidated financial statements.

 
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       We recognize deferred tax assets and liabilities based on the differences between the financial statement carrying amounts and the tax basis of assets and liabilities using prevailing rates. We regularly review our deferred tax assets for recoverability based on its profitability history and the expectation of generating future taxable profits, based on its internal projections prepared for reasonable periods for its business. If we are unable to generate sufficient future taxable income, or if there is a material change in the actual effective tax rates or time period within which the underlying temporary differences become taxable or deductible, we could be required to derecognize all or a significant portion of our deferred tax assets resulting in a substantial increase in our effective tax rate and a material adverse impact on our operating results. Additional information is contained in Notes 4.16.2 and 13.1 to our consolidated financial statements.

Post-employment benefits

We sponsor a (i) defined-benefit pension plan and a (ii) variable contribution pension plan covering substantially all of our employees. We have also established a health care plan for current and retired employees. We determine our obligations for these plans based on calculations performed by independent actuaries using assumptions that we provide about interest rates, investment returns, rates of inflation, mortality rates and future employment levels (see the assumptions and other information about de actuarial valuation in Note 23.5 of our consolidated financial statements). These assumptions directly affect our post-employment benefits liability and any changes may have a significant impact, considering the relevance of the Post-employment benefits amounts in the Company's liabilities.

Leases

We recognize leases at present value as a right-of-use asset and lease liability and, from the initial registration, we record the amortization of the asset and interest on the liability for separately in profit or loss. We use judgments in adopting exemptions from recognition provided for short-term leases (lease term of up to 12 months) and leases of low value assets, so that we record these contracts as operating costs or operating expenses on a straight-line basis during the term of the contract. To estimate the interest rate, we consider the cost of the last fundraising carried out via debentures, disregarding incentivized or subsidized funding. For more information, see Notes 4.18 and 27 to our consolidated financial statements.

 
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ANALYSIS OF ELECTRICITY SALES AND COST OF ELECTRICITY PURCHASED

The following table sets forth the volume and Average Rate components of electricity sales and purchases for the years ended December 31, 2020, 2019 and 2018:

 

Year ended December 31,

 

2020

2019

2018

Electricity Sales      
Sales to Final Customers      
Average price (R$/MWh):(1)      
Industrial customers(2) 233.19 284.03 292.71
Residential customers 744.34 789.75 745.77
Commercial customers 686.18 743.25 711.64
Rural customers 474.13 465.30 408.71
Other customers(3) 557.91 582.91 551.84
All customers(2) 512.52 561.27 537.51
Volume (GWh):      
Industrial customers(2) 9,623 9,000 8,641
Residential customers 7,910 7,499 7,238
Commercial customers 4,852 5,238 4,979
Rural customers 2,451 2,361 2,288
Other customers(3) 2,333 2,546 2,481
All customers(2) 27,169 26,644 25,627
Total revenues from sales to Final Customers (millions of R$) 13,925 14,954 13,775
Sales to distributors(4)      
Average price (R$/MWh)(1) 258,34 213,57 241,62
Volume (GWh) (5) 16,765 15,456 12,979
Total revenues (millions of R$) 4,331   3,301 3,136
Electricity Purchases      
Purchases from Itaipu      
Average cost (R$/MWh)(6) 321.23 237.4 222.18
Volume (GWh) 5,498 5,533 5,726
Percentage of total Itaipu production purchased 9.2 8.7 7.1
Total cost (millions of R$)(7) 1,766.1 1,316.5 1,272.2
Purchases from Angra      
Average cost (R$/MWh) 277,69 253,58 248.07
Volume (GWh) 0,968 0,978 1,009
Total cost (millions of R$)(7) 268.8 248.0 250.3
Purchases from CCGF      
Average cost (R$/MWh) 109.18 102.28 90.92
Volume (GWh) 6,136 6,274 6,520
Total cost (millions of R$)(7) 669.9 641.7 592.8
Purchases from others(4)      
Average cost (R$/MWh) 213.77 185.27 237.41
Volume (GWh) 19,295 21,045 17,884
Total cost (millions of R$)(7) 4,125 3,899 4,246

___________________

(1) Average prices or costs have been computed by dividing (i) the corresponding revenues or expenses by (ii) MWh of electricity sold or purchased.

(2) Includes Free Customers outside Paraná.

(3) Includes public services such as street lighting, as well as the supply of electricity to government agencies, and our own consumption.

(4) Energy traded between Copel’s subsidiaries not included.

(5) Energy Reallocation Mechanism not included.

(6) Our purchases of electricity generated by Itaipu are stated in reais and paid for on the basis of a capacity charge expressed in U.S. dollars per kW plus a “wheeling” (or transportation) charge expressed in reais per kWh.

(7) See “Item 4. Information on the Company—Business—Generation” and “Item 4. Information on the Company—Business— Purchases for the captive market” for an explanation of our expenses relating to electricity purchases.

 
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RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

The following table summarizes our results of operations for the years ended December 31, 2020, 2019 and 2018.

Our consolidated financial statements present our revenue at net value    and our operating costs of sales and services provided by function. However, in accordance with IFRS, Note 31 and 32 of our audited consolidated financial statements presents this information according to the nature of the revenue, operating cost or expense. For ease of understanding, the analysis below reflects the information presented by nature.

We highlight that, with the Copel Telecom divestment process approved during the year 2020, we classified the results of this subsidiary as discontinued operations and, for comparability, we restated the balances for 2019 and 2018. Additional information on the divestment process and about the amounts considered as a discontinued operation can be found in Note 40 to our consolidated financial statements.

Besides, in 2020, the economy and our business were affected by COVID-19. Therefore, there was a reduction in electric energy demand in the regulated market, which was affected more intensely in the industrial and commercial consumption classes in the Distribution Company. However, the residential class registered a growth of 5.5% in   the year, mainly influenced by measures of social distancing and isolation.

The effects of the pandemic impacted the expected credit losses at Copel, especially in the first semester, due to imposed restrictions, such as the prohibition to cut the energy supply from those defaulter customers. On the other hand, in the second semester, there were lower impacts, due to less restrictions, the recovery of economic activity and the possibility of cutting the energy supply from non-paying customers.

Economic effects of the pandemic on the assumptions of the Company's relevant non-financial assets were individually assessed and concluded, by Management, that it was necessary to adjust the impairment value for some assets. The most significant adjustment occurred at UEG Araucária, considering that its cash flow estimates are affected by the decrease in energy demand in the country, whereas on the other projects there were impairment reversals.

But, despite of the impacts of energy consumption, credit losses and impairmnets, the results of our operation were not materially affected. Further information in Notes 1(a) of our consolidated financial statements,

 

 

Year ended December 31,

 

2020

2019 restated

2018 restated

  (R$ million)
Net Operating Revenues:      
Electricity sales to Final Customers: 9,524.9 10,481.7 10,104.0
Residential 3,098.9 3,336.4 3,175.3
Industrial 970.6 1,276.1 1,419.2
Commercial, services and other activities 1,701.2 2,179.5 2,136.1
Rural 613.4 631.5 572.3
Other classes 3,140.7 3,058.2 2,801.1
Electricity sales to distributors 4,331.0 3,301.3 3,136.2
Use of main distribution and transmission grid 8,780.6 8,271.0 6,867.3
Residential 2,788.7 2,585.9 2,222.6
Industrial 1,273.3 1,280.2 1,110.1
Commercial, services and other activities 1,628.1 1,713.6 1,407.2
       
 
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Rural 548.7 467.0 362.8
Other classes 582.3 597.9 511.5
Free consumers 1,164.0 1,052.5 795.1
Concessionaires and generators 61.7 62.4 80.3
 Operating and maintenance income - O&M and interest income 733.7 511.4 377.7
Construction revenues 1,414.1 1,132.9 1,097.3
Revenues from telecommunications - - -    
Distribution of piped gas 679.3 1,003.8 753.2
Sectorial financial assets and liabilities result 746.1 25.1 985.3
Other operating revenues 406.5 438.9 199.8
Fair value of assets from the indemnity for the concession 57.3 36.6 47.5
(-) Revenue deductions (7,306.5) (8,822.1) (8,640.3)
  18,633.2 15,869.2 14,550.5
Cost of sales and services provided:      
Electricity purchased for resale (6,829.5) (6,105.3) (6,361.2)
Charge of main distribution and transmission grid (1,525.6) (1,249.3) (1,176.8)
Personnel and management (1,601.9) (1,325.4) (1,357.8)
Pension and healthcare plans (228.6) (238.3) (243.8)
Material and supplies (72.7) (80.2) (80.0)
Materials and supplies for power electricity (404.5) (49.4) (19.7)
Natural gas and supplies for gas business (354.7) (585.2) (412.6)
Third-party services (558.0) (526.0) (481.1)
Depreciation and amortization (1,009.9) (950.7) (696.3)
Accruals and provisions (237.3) (260.1) (281.1)
Construction cost (1,417.5) (1,091.4) (1,052.2)
Other costs and expenses (333.3) (212.5) (272.6)
  (14,573.5) (12,673.7) (12,435.1)
Equity in earnings of associates and joint ventures 193.5 106.8 135.9
Financial results 866.3 (455.4) (413.1)
Profit before income tax and social contribution 5,119.5 2,846.9 1,838.0
Income tax and social contribution on profit (1,285.4) (675.6) (471.2)
Net income from continuing operations 3,834.2 2,171.3 1,366.9
Net income (loss) from discontinued operations 75.6 (108.4) 77.1
Net income for the year 3,909.7 2,062.9 1,444.0
Net income attributable to controlling shareholders 3,904.2 1,989.9 1,407.1
Net income attributable to non-controlling interest 5.5 72.9 36.9
Other comprehensive income (179.2) 123.2 38.4
Comprehensive income 3,730.6 1,939.7 1,405.6
Comprehensive income attributable to controlling shareholders 3,725.2 1,862.5 1,368.5
Comprehensive income attributable to non-controlling interest 5.3 77.2 37.0

 

Results of Operations for 2020 Compared with 2019

Operating Revenues

Our consolidated net operating revenues increased by 17.4% or R$2,764.0 million in 2020 compared to 2019. This result reflected, mainly, an increase of R$1,029.7 million in electricity sales to distributors and of R$721.0 million in sectorial financial assets and liabilities, partially offset by a decrease of R$956.8 million in electricity sales to Final Customers. In addition, there was an increase in the amount of recovery of Pis/Pasep and Cofins on ICMS, recorded within the revenue deductions. Below are the main reasons for variations in revenue accounts:

 
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Electricity Sales to Final Customers. Our revenues from electricity sales to Final Customers decreased by 9.1%, or R$956.8 million, , mainly due to a decrease of the average price per kilowatt hour sold to the final customers by Copel Distribuição and the effects of the economic downturn caused by the coronavirus pandemic, as follows:

·The revenue from electricity sold to residential customers decreased R$237.5 million in 2020 compared to 2019, also considering a reduction of 5.75% on the average price (R$/MWh) of the electricity sold during the same period, despite the increased volume compared to 2019.
·The revenue from electricity sold to industrial customers decreased by 23.9%, or R$305.5 million, in 2020 compared to 2019, considering a reduction of 17.9% on the average price (R$/MWh)) and a decrease in volume (GWh) of electricity sold during the same period.
·The revenue from electricity sold to commercial customers decreased by 21.9%, or R$478.3 million, in 2020 compared to 2019, considering a reduction of 7.7% on the average price (R$/MWh) and a decrease in volume (GWh) of electricity sold during the same period.
·The revenue from electricity sold to rural customers decreased by 2.9%, or R$18.1 million, in 2020 compared to 2019. This decrease is mainly due to the reduction of consumers compared to 2019 and agribusiness performance in the State of Paraná during the COVID-19 pandemic.

Electricity Sales to Distributors. Our revenues from electricity sales to distributors increased by 31.2%, or R$1,029.7 million. This increase was mainly due to the increase in our revenues from energy sold through bilateral contracts by Copel Mercado Livre and contracts in the regulated environment, reflection of the TPP Araucária dispatch, which had not operated in 2019.

Use of main distribution and transmission grid. Our revenues from the use of main distribution and transmission grid increased by 6.2%, or R$509.6 million, mainly due the positive result of the periodic tariff review of the transmission contract 060/2001, the increase in remuneration on transmission assets, due to the growth of the IGPM / IPCA indexers, the growth in the grid market and the tariff readjustment of Copel Distribuição which corresponded to the Average Tariff effect being 1.13% for consumers connected in high voltage and 0.05% for consumers connected in low voltage. Besides that, there was an increase of 2.6% on the number of consumers compared to 2019.

Construction revenues. Our revenues from construction increased by 24.8%, or R$281.2 million, mainly due an intensification of construction efforts and improvement of the infrastructure of the distribution businesses.

Fair value of assets from the indemnity for the concession. The fair value of the assets from the indemnity for the concession increased by 56.6%, or R$20.7 million, mainly due to higher variation in the distribution concession agreement’s assets fair value.

Distribution of Piped Gas. Revenues from the distribution of piped gas decreased by 32.3%, or R$324.5 million, considering the impacts by the reduction in gas volume due to the Covid-19 pandemic, mainly in the industrial, commercial and vehicular segments.

Sectorial Financial Assets and Liabilities.. Increased by 2,877.4%, or R$721.0 million due to the higher value of net assets constituted in 2020, mainly due to the purchasing energy and charges for use of the network costs being higher than those considered in the calculation of the electricity tariff approved by Aneel for the annual tariff cycle ending in June 2021.

Other Operating Revenues. Other operating revenues decreased by 7.4%, or R$32.4 million, mainly reflecting the recognition of the fair value of the portfolio of energy purchase and sale contracts of Copel Mercado Livre referring to the variation of the contracted price in relation to the market price in an amount lower than that recorded in 2019.

Cost of sales and services provided

Our consolidated costs of sales and services provided increased by 15.0% or R$1,899.8 million. The main factors leading to such increase in our cost of sales and services provided are as follows:

 
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·Electricity Purchased for Resale. Our purchased energy costs for resale increased by 11.8%, or R$724.2 million, mainly due to an increase in the purchase of Energy in the Regulated Environment – CCEAR of energy from Itaipu Binacional by Copel Distribuição and from bilateral contracts to face the higher volume of energy sold on the free market in the period by Copel Mercado Livre.
·Charge of Main Distribution and Transmission Grid. Expenses we incurred for our use of the main distribution and transmission grid increased 22.1%, or R$276.3 million mainly as a result of the increase in tariffs and charges for transmission infrastructure made available from 2020, in addition to the effect of the variation in costs related to dispatching thermal plants, with an impact on system service fees – ESS and increase in charges for the use of the system and in the reserve energy charge - EER, partially offset by the reduction in Itaipu's transportation charges.
·Personnel and administrative expenses increased by 20.8%, or R$276.5 million, reflecting the increase in provision for performance and profit sharing and the salary readjustment in October 2020, higher than in 2019, partially offset by the reduction in the number of employees and cost reduction policy.