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Financial Instruments
 12 Months Ended
Dec. 31, 2021
Financial Instruments

 

36.Financial Instruments
36.1Categories and determination of fair value of financial instruments

 

             
        12.31.2021   12.31.2020
  Note Level Book value Fair value Book value Fair value
Financial assets            
Fair value through profit or loss            
Cash and cash equivalents (a) 5 1 3,472,845 3,472,845 3,222,768 3,222,768
Bonds and securities (b) 6 1  14,571  14,571 751 751
Bonds and securities (b) 6 2   346,487   346,487   299,779   299,779
Accounts receivable - distribution concession (c) 10.1 and 10.2 3 1,433,734 1,433,734 1,149,934 1,149,934
Accounts receivable - generation concession (d) 10.4 3   102,220   102,220  81,202  81,202
Derivatives fair value - forward contracts (e) 12 3 2,907 2,907  23,308  23,308
Fair value in the purchase and sale of power (e) 12 3   855,775   855,775   689,531   689,531
Other temporary investments (f)   1  14,072  14,072  14,910  14,910
Other temporary investments (f)   2 5,913 5,913 7,475 7,475
      6,248,524 6,248,524 5,489,658 5,489,658
Amortized cost            
Collaterals and escrow accounts (a)     182 182 197 197
Collateral and escrow deposits - STN (g) 22.1     142,764   115,643   133,521   113,477
Trade accounts receivable (a) 7   4,515,426 4,515,426 3,819,680 3,819,680
CRC Transferred to the Paraná State Government (h) 8    -  - 1,392,624 1,496,016
Sectorial financial assets (a) 9     767,480   767,480   346,930   346,930
Accounts receivable - concessions - bonus from             
  the grant (i) 10.3     730,851   828,673   671,204   763,070
      6,156,703 6,227,404 6,364,156 6,539,370
Total financial assets      12,405,227  12,475,928  11,853,814  12,029,028
Financial liabilities            
Fair value through profit or loss            
Fair value in the purchase and sale of power (e) 29 3   545,468   545,468   343,406   343,406
        545,468   545,468   343,406   343,406
Amortized cost            
Sectorial financial liabilities (a) 9     293,179   293,179   188,709   188,709
Special Tax Regularization Program - Pert (g)  13.2     421,694   361,080   459,303   377,375
PIS and Cofins to be refunded to consumers (a) 13.2.1   3,326,795 3,326,795 3,927,823 3,927,823
Accounts payable to suppliers (a) 21   2,710,984 2,710,984 2,436,452 2,436,452
Loans and financing (g) 22   3,738,269 3,313,645 3,214,249 2,956,696
Debentures (j) 23   8,240,769 8,240,769 6,837,819 6,837,819
Accounts payable related to concession (k) 27     903,959 1,009,867   731,864   811,329
       19,635,649  19,256,319  17,796,219  17,536,203
Total financial liabilities      20,181,117  19,801,787  18,139,625  17,879,609
Different levels are defined as follows:
Level 1: Obtained from quoted prices (not adjusted) in active markets for identical assets and liabilities;
Level 2: obtained through other variables in addition to quoted prices included in Level 1, which are observable for the assets or liabilities;
Level 3: obtained through assessment techniques which include variables for the assets or liabilities, which however are not based on observable market data. 

Determining fair values

a)Equivalent to their respective carrying values due to their nature and terms of realization.
b)Fair value is calculated based on information made available by the financial agents and the market values of the bonds issued by the Brazilian government
c)The criteria are disclosed in Note 4.4 to these financial statements.
d)The fair values of generation assets approximate their carrying amounts, according to Note 4.4 to these financial statements.
e)The fair values of assets and liabilities are equivalent to their carrying amounts according to Note 4.15 to these financial statements.
f)Investments in other companies, stated at fair value, which is calculated according to the price quotations published in an active market, for assets classified as level 1 and determined in view of the comparative assessment model for assets classified as level 2.
g)The cost of the last issue of Copel’s debentures, CDI + 1.38%, is used as a basic assumption for discount of the expected payment flows.
h)The Company based its calculation on the comparison with a long-term and post-fixed National Treasury Bond (NTN-B) maturing on August 15, 2026, which yields approximately 3.87% p.a. plus the IPCA inflation index.
i)Receivables related to the concession agreement for providing electricity generation services under quota arrangements, having their fair value calculated by expected cash inflows, discounted at the rate established by ANEEL auction notice 12/2015 (9.04%).
j)Calculated from the Unit Price quotation (PU) for December 31, 2021, obtained from the Brazilian Association of Financial and Capital Markets (ANBIMA), net of unamortized financial cost.
k)Actual net discount rate of 8.75% p.a., in line with the Company’s estimated rate for long-term projects.

 

36.2Financial risk management

The Company’s business activities are exposed to the following risks arising from financial instruments:

36.2.1Credit risk

Credit risk is the risk of the Company incurring losses due to a customer or counterparty in a financial instrument, resulting from failure in complying with their contractual obligations.

     
Exposure to credit risk 12.31.2021 12.31.2020
Cash and cash equivalents (a) 3,472,845 3,222,768
Bonds and securities (a) 361,058 300,530
Pledges and restricted deposits linked (a) 142,946 133,718
Trade accounts receivable (b) 4,515,426 3,819,680
CRC Transferred to the Paraná State Government (c)   - 1,392,624
Sectorial financial assets (d) 767,480 346,930
Accounts receivable - distribution concession (e) 1,433,734 1,149,934
Accounts receivable - concessions - Bonus from the grant (f) 730,851 671,204
Accounts receivable - generation concessions (g) 102,220   81,202
Other temporary investments (h)   19,985   22,385
    11,546,545   11,140,975
a)The Company manages the credit risk of its assets in accordance with the Management’s policy of investing virtually all of its funds in federal banking institutions. As a result of legal and/or regulatory requirements, in exceptional circumstances the Company may invest funds in prime private banks.
b)The risk arises from the possibility that the Company might incur losses resulting from difficulties to receive its billings to customers. This risk is directly related to internal and external factors to Copel. To mitigate this type of risk, the Company manages its accounts receivable, detecting the classes of consumers most likely to default, implementing specific collection policies and suspending the supply and/or recording of energy and the provision of service, as established in contract and regulatory standards.
c)There is no risk considering that the balance was settled in 2021.
d)Management considers the risk of this credit to be reduced, since the agreements signed guarantee the unconditional right to receive cash at the end of the concession to be paid by the Concession Grantor, corresponding to the costs not recovered through the tariff.
e)Management considers the risk of this credit to be reduced, since the agreements signed guarantee the unconditional right to receive cash at the end of the concession to be paid by the Concession Grantor, referring to investments in infrastructure not recovered through the tariff.
f)Management considers the risk of such credit to be low, as the contract for the sale of energy by quotas guarantees the receipt of an Annual Generation Revenue - RAG, which includes the annual amortization of this amount during the concession term.
g)For the generation concession assets, ANEEL published Normative Resolution 596/2013, which deals with the definition of criteria for calculating the New replacement value (Valor novo de reposição – VNR), for the purposes of indemnification. In July 2021, Normative Resolution No. 942/2021 was published, regulating the calculation of these amounts through the presentation of appraisal reports to be prepared by accredited companies. Management’s expectation of indemnification for these assets supports recoverability of the balances recorded.
h)This risk arises from the possibility that the Company might incur losses resulting from the volatility on the stock market. This type of risk involves external factors and has been managed through periodic assessment of the variations occurred in the market.

 

36.2.2Liquidity risk

The Company’s liquidity risk consists of the possibility of having insufficient funds, cash or other financial assets, to settle obligations on their scheduled maturity dates.

The Company manages liquidity risk relying on a set of methodologies, procedures and instruments applied to secure ongoing control over financial processes to ensure proper management of risks.

Investments are financed by incurring medium and long-term debt with financial institutions and capital markets.

Short, medium and long-term business projections are made and submitted to Management bodies for evaluation. The budget for the next fiscal year is annually approved.

Medium and long-term business projections cover monthly periods over the next five years. Short-term projections consider daily periods covering only the next 90 days.

The Company permanently monitors the volume of funds to be settled by controlling cash flows to reduce funding costs, the risk involved in the renewal of loan agreements and compliance with the financial investment policy, while concurrently keeping minimum cash levels.

The following table shows the expected undiscounted settlement amounts in each time range. Projections were based on financial indicators linked to the related financial instruments and forecast according to average market expectations as disclosed in the Central Bank of Brazil’s Focus Report, which provides the average expectations of market analysts for these indicators for the current year and for the next 3 years. As from 2026, 2025 indicators are repeated on an unaltered basis throughout the forecast period.

 

               
               
    Less than 1 to 3 3 months 1 to 5 Over  
   Interest (a)   1 month    months   to 1 year    years   5 years   Total  
12.31.2021              
Loans and financing Note 22  37,039  97,025   729,794  2,047,981   2,234,468  5,146,307
Debentures Note 23  65,956  56,696   2,727,331  6,362,806   2,029,487   11,242,276
Accounts payable related  Rate of return +            
  to concession IGP-M and IPCA   8,948  17,904  82,977  500,875   2,431,666  3,042,370
Accounts payable to suppliers -   2,355,760   236,941  51,322   66,961 -  2,710,984
PIS and Cofins to be refunded              
  to consumers - -  - -  3,363,440 -  3,363,440
Special Tax Regularization Program - Pert  Selic   4,375 8,829  41,411  258,120   232,257  544,992
Sectorial financial liabilities Selic  11,736  23,760   112,857  182,395 -  330,748
Lease liability Note 28   5,444  10,919  48,886  119,212   207,099  391,560
      2,489,258   452,074   3,794,578   12,901,790   7,134,977   26,772,677
(a) Effective interest rate - weighted average.

 

As disclosed in Notes 22.5 and 23.3, the Company has loans and financing agreements and debentures with covenants that if breached may have their payment accelerated.

36.2.3Market risk

Market risk is the risk that the fair value or the future cash flows of a financial instrument shall oscillate due to changes in market prices, such as currency rates, interest rates and stock price. The purpose of managing this risk is to control exposures within acceptable limits, while optimizing return.

a)Foreign currency risk (US Dollar)

This risk comprises the possibility of losses due to fluctuations in foreign exchange rates, which may reduce assets or increase liabilities denominated in foreign currencies.

The Company’s foreign currency indebtedness is not significant, and it is not exposed to foreign exchange derivatives. The Company monitors all relevant foreign exchange rates.

The effect of the exchange rate variation resulting from the power purchase agreement with Eletrobras (Itaipu) is transferred to customers in Copel DIS’s next tariff adjustment.

The exchange rate risk posed by the purchase of gas arises from the possibility of Compagas reporting losses on the fluctuations in foreign exchange rates, increasing the amount in Reais of the accounts payable related to the gas acquired from Petrobras. This risk is mitigated by the monitoring and transfer of the price fluctuation through tariff, when possible. The Company monitors these fluctuations on an ongoing basis.

Sensitivity analysis of foreign currency risk

The Company has developed a sensitivity analysis in order to measure the impact of the devaluation of the US dollar on its loans and financing subject to currency risk.

The valuation of the financial instruments considers the possible effects on profit and loss and equity of the risks evaluated by the Company’s Management on the reporting date for the financial instruments, as recommended by IFRS 7 - Financial Instruments: Disclosure. Based on the equity position and the notional value of the financial instruments outstanding at the date of these financial statements, it is estimated that these effects will approximate the amounts stated in the above table in the column for the forecast probable scenario, since the assumptions used by the Company are similar to those previously described.

The baseline scenario takes into account the existing balances on the date of these financial statements and the probable scenario assumes a variation in the foreign exchange rate - prevailing at the end of the period (R$/US$5.50) based on the median market expectation for 2022 according to the Focus Report of February 18, 2022, issued by the Central Bank of Brazil, with the exception of the amounts related to the STN, which for the probable scenario considered the balances effectively realized, since the operation was settled on March 10, 2022. Additionally, the Company continues to monitor scenarios 1 and 2, which consider a deterioration of 25% and 50%, respectively, in the main risk factor of the financial instrument in relation to the level used in the probable scenario, as a result of extraordinary events that may affect the economic scenario.

 

           
           
.   Baseline  Projected scenarios
Foreign exchange risk Risk 12.31.2021 Probable   Scenario 1 Scenario 2
.          
Financial assets          
Collaterals and escrow accounts - STN USD depreciation 142,764 (14,967)  (a)   (a) 
.   142,764 (14,967)    
Financial liabilities          
Loans and financing - STN USD appreciation   (150,572)  13,425  (a)   (a) 
Suppliers          
Eletrobras (Itaipu) USD appreciation   (304,215) 4,388  (70,568)   (145,525)
Acquisition of gas USD appreciation  (60,121) 867  (13,946)  (28,759)
           
      (514,908)  18,680  (84,514)   (174,284)

(a) Projected scenarios not evaluated. Probable value reflects the settlement value of the transaction, which took place on March 10, 2022.

 

b)Foreign exchange risk - euro

This risk arises from the possibility of loss due to fluctuations in exchange rates affecting fair value of Non-Deliverable Forward (NDF) transactions. These derivatives were contracted considering that in the supply contracts for wind turbines of companies in the Jandaíra wind complex, controlled by Copel GeT, disbursement installments in Euro are foreseen. Sporadic gains and losses are recognized in the Company’s statement of income.

Based on the notional amount of €2.200 outstanding at the date of these financial statements, the fair value was estimated by the difference between the amounts contracted under the respective terms and the forward currency quotations (B3 reference rates), discounted to present value at the fixed rate. The net asset balance recorded is shown in Note 12.

Sensitivity analysis of operations with derivative financial instruments

The Company developed a sensitivity analysis in order to measure the impact from exposure to fluctuation in exchange rate to Euro (€).

For the base scenario, the accounting balances recorded on the date of these financial statements were considered and for the probable scenario, the balances effectively carried out.

 

           
  Exchange Baseline  Projected scenarios
   rate variation 12.31.2021 Probable   Scenario 1 Scenario 2
           
Gains (losses) on operations with derivative financial instruments  Increase   2,907 996  (a)   (a) 
         
    Decrease   2,907 996  (a)   (a) 
(a) Projected scenarios not evaluated. Probable value reflects the settlement value of the transaction, which took place on March 10, 2022.

 

c)Interest rate and monetary variation risk

This risk comprises the possibility of losses due to fluctuations in interest rates or other indicators, which may reduce financial income or increase the financial expenses related to the assets and liabilities raised in the market.

The Company has not entered into derivative contracts to cover this risk but has been continuously monitoring interest rates and market indexes in order to observe any need for contracting.

Sensitivity analysis of interest rate and monetary variation risk

The Company has developed a sensitivity analysis in order to measure the impact of variable interest rates and monetary variations on its financial assets and liabilities subject to these risks.

The valuation of the financial instruments considers the possible effects on profit and loss and equity of the risks evaluated by the Company’s Management on the reporting date for the financial instruments, as recommended by IFRS 7 - Financial Instruments: Disclosure. Based on the equity position and the notional value of the financial instruments outstanding at the date of these financial statements, it is estimated that these effects will approximate the amounts stated in the above table in the column for the forecast probable scenario, since the assumptions used by the Company are similar to those previously described.

The baseline scenario takes into account the existing balances on the date of these financial statements and the probable scenario assumes balances reflecting varying indicators (CDI/Selic - 12.25%, IPCA - 5.56%, IGP-DI - 8.09%, IGP-M - 8.12% and TJLP - 6.55%) estimated as market average projections for 2022 according to the Focus Report of February 18, 2022, issued by the Central Bank of Brazil, except IGP-DI and TJLP that considers the Company’s internal projection. Additionally, the Company continues to monitor scenarios 1 and 2, which consider a deterioration of 25% and 50%, respectively, in the main risk factor of the financial instrument in relation to the level used in the probable scenario, as a result of extraordinary events that may affect the economic scenario.

 

           
.   Baseline  Projected scenarios
Interest rate risk and monetary variation Risk 12.31.2021 Probable   Scenario 1 Scenario 2
.          
Financial assets          
Bonds and securities Low CDI/SELIC   361,058  41,522  31,159  20,760
Collaterals and escrow accounts Low CDI/SELIC   182   21   15   11
Sectorial financial assets Low Selic   767,480  94,016  70,512  47,008
Accounts receivable - concessions Low IPCA   2,164,585 120,351  90,263  60,175
Accounts receivable - generation concessions Undefined (a)   102,220  -  -  -
      3,395,525 255,910 191,949 127,954
Financial liabilities          
Loans and financing          
  Banco do Brasil High CDI  (641,207) (78,548) (98,185)   (117,822)
  BNDES High TJLP  (1,864,177)   (122,023)   (152,529)   (183,035)
  BNDES High IPCA  (348,305) (19,366) (24,207) (29,049)
  Banco do Nordeste High IPCA  (626,043) (76,690) (95,863)   (115,035)
  Banco do Brasil - BNDES Transfer High TJLP   (72,109)   (4,720)   (5,900)   (7,080)
  Other No risk   (35,856)  -  -  -
Debentures High CDI/SELIC  (5,627,350)   (689,350)   (861,688)   (1,034,026)
Debentures High IPCA  (2,513,179)   (139,733)   (174,666)   (209,599)
Debentures High TJLP  (100,240)   (6,561)   (8,202)   (9,842)
Sectorial financial liabilities High Selic  (293,179) (35,914) (44,893) (53,872)
Special Tax Regularization Program - Pert  High Selic  (421,694) (51,658) (64,572) (77,486)
Accounts payable related to concession High IGP-M  (844,599) (68,581) (85,727)   (102,872)
Accounts payable related to concession High IPCA   (59,360)   (3,300)   (4,125)   (4,951)
.     (13,447,298)   (1,296,444)   (1,620,557)   (1,944,669)
(a) Risk assessment still requires ruling by the Concession grantor.

 

36.2.4Electricity shortage risk

Approximately 64% of installed capacity in Brazil currently comes from hydroelectric generation, as informed by the Generation Information Bank of ANEEL, which makes Brazil and the geographic region in which we operate subject to unpredictable hydrological conditions, due to non-cyclical deviations of mean precipitation. Unsatisfactory hydrological conditions may cause, among other things, the implementation of comprehensive programs of electricity savings, such as rationalization or even a mandatory reduction of consumption, which is the case of rationing.

From September 2020, the National Interconnected System has been presenting the worst record of Affluent Natural Energies in the aggregate of its uses. The Ministry of Mines and Energy and other sector bodies are working to mitigate the risks of rationing, with emphasis on a high thermoelectric dispatch outside the order of cost merit, as well as the relaxation of restrictions on the system’s hydroelectric operation. Additionally, considering the strong wind generation in the Northeast and the generation of biomass in the Southeast, it is estimated that the risk of energy shortages in 2021 and 2022 will be minimized, according to official information published so far.

In order to mitigate the risk of meeting instant demand, the MME is managing large energy consumers in order to migrate their consumption from periods of greater demand. Which, in general, means moving production into the early morning hours. This guarantees the service to consumers with greater economy, since the operation in periods of high demand is very expensive.

The Electric Sector Monitoring Committee (CMSE) has maintained the energy deficit risk indicators within the safety margin in short-term projections, with the authorization of a reduced dispatch of thermal generation outside the order of merit of cost by ONS, which for in turn, it has dispatched the amounts necessary for a safe operation to the National Interconnected System.

Although dam storage levels are not ideal, from the standpoint of the bodies responsible for planning the operation of the system, when combined with other variables, such as affluent flows, wind and solar generation, they are sufficient to keep the risk of deficit within the safety margin established by the National Energy Policy Council (CNPE) in all subsystems (maximum risk of 5%).

36.2.5Risk of GSF impacts

The Energy Reallocation Mechanism (Mecanismo de Realocação de Energia - MRE, in Portuguese) is a system of redistribution of electric power generated, characteristic of the Brazilian electric sector, which has its existence by the understanding, at the time, that there is a need for a centralized operation associated with a centrally calculated optimal price known as PLD. Since generators have no control over their production, each plant receives a certain amount of virtual energy which can be compromised through contracts. This value, which enables the registration of bilateral contracts, is known as Physical Guarantee (Garantia Física - GF, in Portuguese) and is also calculated centrally. Unlike PLD, which is calculated on a weekly basis, GF, as required by Law, is recalculated every five years, with a limit of increase or decrease, restricted to 5% by revision or 10% in the concession period.

The contracts need to have an energy physical guarantee basis. This is done, especially, through the allocation of power generated received from the MRE or purchase. The GSF is the ratio of the entire hydroelectric generation of the MRE participants to the GF sum of all the MRE plants. Basically, the GSF is used to calculate how much each plant will receive from generation to back up its GF. Thus, knowing the GSF of a given month the company will be able to know if it will need to back up its contracts through purchases.

Whenever GSF multiplied by GF is less than the sum of contracts, the company will need to buy the difference in the spot market. However, whenever GSF multiplied by GF is greater than the total contracts, the company will receive the difference to the PLD.

The low inflows that have been recorded since 2014, as well as problems with delays in the expansion of the transmission system have resulted in low GSF values, resulting in heavy losses for the companies holding MRE participating hydroelectric projects.

For plants with contracts in the Free Contracting Environment - ACL, the main way to manage the low GSF risk is not to compromise the entire GF with contracts, as well as the timely repurchase of intra-annual energy approaches currently adopted by the Company.

For the contracts in the ACR, Law 13,203/2015 allowed the generators to contract insurance for electricity demand (load), by means of payment of a risk premium. Copel adopted this approach to protect contracts related to energy generated by the Mauá, Baixo Iguaçu and Colíder Thermoelectric Plants and Cavernoso II Small HPP.

For the distribution segment, the effects of the GSF are perceived in the costs associated with quotas of Itaipu, of Angra and the plants whose concessions were renewed in accordance with Law 12,783/2013, as well as in the costs of the contracts for power availability with thermoelectric plants. This is a financial risk, since there is guarantee of neutrality of expenses with energy purchases through a tariff transfer.

36.2.6Risk of non-renewal of concessions - generation and transmission

The extension of energy generation and transmission concessions, achieved by Law No. 9,074/1995, is regulated by Law No. 12,783/2013, which was amended by Law No. 14,052/2020, regarding the deadline for requesting an extension of concessions.

According to the new law, the concession operator should request extension of concession at least 36 months before the final contract date or after granting of concessions to hydroelectric power generation and electric power transmission and distribution plants, and of up to 24 months for thermoelectric plants. The Concession Grantor may advance effects of extension by up to 60 months counted as of contract or grant date and may also define initial tariff or revenue, which includes the definition of the tariff or initial revenues for the generation and transmission ventures (RAG - Annual Generation Revenue and RAP - Permitted Annual Revenue, respectively).

Concessions for hydroelectric power generation and electric power transmission may be extended, at the discretion of the granting authority, only once, for a period of up to 30 years. Thermoelectric power generation concessions have an extension term limited to 20 years.

In 2019, Decree No. 10,135/2019 was published, which regulated the granting of concession contracts in the electricity sector associated with privatization through sale of control by holder of a public service concession for electricity generation, having as one of the conditioning factors the alteration of the exploration regime to Independent Power Producer (IPP). According to the Decree, the manifestation of sale of the concession must take place within up to 42 months from the date of the related formal agreement, and any sale must take place within up to 18 months from the concession end date. If sale of control of the venture does not occur within the specified period, the plant must be subject to auction by the granting authority and the same concessionaire can participate in the auction, if it meets the qualification conditions.

Compensation was established through the extension of the concession period of the plants contemplated by Law No. 13,203/2015, ratification of the period of extension of the concession of these plants through Ratification Resolutions No. 2919/2021 and No. 2932/2021 (Note 1-b).

For HPP Governador Bento Munhoz da Rocha Netto - HPP GBM (1,676 MW), whose concession will end in 2024, the Company has not expressed any interest in extending the concession, as internal studies have shown that the extension through early change of the exploration regime would be economically and financially disadvantageous in relation to exploration of the plant under the current regime until concession end. On March 3, 2020, Copel GeT transferred the concession of HPP GBM to subsidiary F.D.A. Geração de Energia Elétrica S.A. with the purpose of, if the studies carried out by Copel GeT point to the advantage of the operation, divesting the control of this concessionaire and, thus, allow a new concession grant for 30 years.

With respect to HPP São Jorge, whose concession ends in 2026, Copel did not express interest in the renewal and intends, at the end of the concession, to request ANEEL to convert the granting of concession into granting of registration.

Regarding the Figueira HPP concession, expired in March 2019, the Company awaits the conclusion of the related ANEEL and MME procedural steps to execute any amendment to the Concession Agreement. The plant is undergoing a modernization process and will have as direct benefits the improvement in energy efficiency and the reduction of pollutant emissions in the atmosphere, in comparison with the old plant.

According to the new law, the Company may express its intention to extend the concession of the Apucaraninha HPP until January 2024, and the Guaricana and Chaminé HPPs until July and August, 2025, respectively. If the Company does not express an interest in the extension of the current regime at its final term, be granted to the Company in the condition of registration, and the other concessions, at their final term, must be returned to the Concession Grantor.

Copel GeT has no transmission concession to expire in the next ten years.

36.2.7Risk on non-renewal of concessions – distributions of electricity

The fifth amendment to Copel DIS’s concession contract No. 46/1999 imposes economic and financial efficiency covenants and indicators that consider the duration and frequency of service interruptions (DECi and FECi). Failure to comply with the conditions will result in termination of the concession (clause eighteen, subclause one), with due regard for the provisions of the contract, particularly the right to full defense and adversary system.

On November 17, 2020, Aneel approved Normative Resolution 896, which establishes the indicators and procedures for monitoring efficiency in relation to the continuity of supply and the economic-financial management of public electricity distribution service concessions from the year 2021.

Indicators and penalties

       
       
Year Indicator Criteria Penalties
Until 2020 Economic - financial efficiency and quality 2 consecutive years or at the end of the 5-year period (2020) Concession termination
Quality Indicators 2 consecutive years or 3 times in 5 years Limitation of dividend and interest on equity distribution
Economic - financial efficiency in the base year Capital Increase (a)
Limitation of dividend and interest on equity distribution
Restrictive regime for contracts with related parties
From the 6th year of (2021) Economic - financial efficiency 2 consecutive years Concession termination
Quality Indicators 3 consecutive years
(a) Within 180 days from the end of each fiscal year, in the totality of the insufficiency that occurs to reach the Minimum Economic and Financial Sustainability Parameter.

 

Targets for Copel Distribuição in 2021

 

The criterion of efficiency in relation to economic-financial management will not be complied when what is determined in the table below is not achieved, or even when the EBITDA is lower than the QRR. The calculation of results occurs at the end of each year, when the results are disclosed in the Regulatory Financial Statements.

             
      Quality - limits Quality (Performed)
Year Economic and Financial Management Realized DECi FECi  DECi  FECi 
2021 {Net Debt / [EBITDA (-) QRR ≥ 0]} ≤ 1 / (1,11 * Selic)  -   9.29   6.84   7.20   4.76

 

             
Net Debt Gross Debt deducted from Financial Assets, with the exception of Financial Assets and Financial Liabilities in administrative or judicial discussion. The accounts that make up the Gross Debt and Financial Assets are defined in the attachment to Resolution No 896/20.
QRR Regulatory Reinstatement Share or Regulatory Depreciation Expense. This value will be the one defined in the last Periodic Tariff Review, updated by the variation of the Regulatory Portion B and calculated on a pro rata basis.
Recurring EBITDA: Recurring: refers to Earnings Before Interest (Financial Result), Taxes (Income Taxes), Depreciation and Amortization.

 

 

Targets for Copel Distribuição from 2016 to 2020

             
             
      Quality - limits (a) Quality (Performed)
Year Economic and Financial Management Realized DECi (b)  FECi (b)  DECi  FECi 
             
2016       13.61 9.24   10.80   7.14
2017  EBTIDA ≥ 0 (c)    661,391   12.54 8.74   10.41   6.79
2018  EBTIDA (-) QRR ≥ 0 (d)    550,675   11.23 8.24   10.29   6.20
2019  {Net Debt / [EBTIDA (-) QRR]} ≤ 1 / (0.8 * SELIC) (d)    822,386   10.12 7.74 9.10   6.00
2020  {Net Debt / [EBTIDA (-) QRR]} ≤ 1 / (1.11 * SELIC) (e)    1,624,821 9.83 7.24 7.81   5.55
(a) According to Aneel’s Technical Note No. 0335/2015.
(b) DECi - Equivalent Time of Interruption Caused by Internal Source per Consumer Unit; and FECi - Equivalent Frequency of Interruption Caused by Internal Source per Consumer Unit.
(c) Regulatory EBTIDA adjusted for non-recurring events (Voluntary retirement program, post-employment benefit, provisions and reversals) according to sub-clause six, of the Fifth Amendment to the Concession Agreement.
(d) QRR: Regulatory Reintegration Quota or Regulatory Depreciation Expense. This is the value defined in the most recent Periodical Tariff Review (RTP), plus General Market Price Index (IGPM) variation between the month preceding the RTP and the month preceding the twelve-month period of the economic and financial sustainability measurement.
(e) Selic: limited to 12.87% p.a.

 

36.2.8Risk of non-extension of the gas distribution concession

In the event of termination of the concession at the end of the contractual term, Compagas will be entitled to compensation for investments made in the last 10 years prior to the end of the concession at their depreciated replacement value, according to the contractual clause.

36.2.9Risk of overcontracting and undercontracting of electricity

Under the current regulatory model, the agreement for purchase of electric power by distributors is regulated by Law 10,484/2014 and Decree 5,163/2004, which determine that the purchase of energy must be in the volume necessary to serve 100% of the distributor’s market.

The difference between the costs remunerated by the tariff and those actually incurred in the power purchases are fully passed on to captive consumers, as long as the distributor presents a contracting level between 100% and 105% of its market. However, if distributors determine contracting levels lower or higher than the regulatory limits, there is the assurance of neutrality if it is identified that such violation derives from extraordinary and unforeseen events that are not manageable by the buyer.

In the last years, the distribution segment has been exposed to a general overcontracting scenario, as most companies determined contracting levels higher than 105%. Considering that several factors that have contributed to this situation are extraordinary and unavoidable by the distributors, such as the involuntary allocation of physical guarantee quotas and the broad migration of consumers to the free market and more recently, from 2020, the effects on the market of the governmental measures of social isolation implemented in the fight against the pandemic of the coronavirus Sars-CoV-2 (Covid-19), which caused a significant retraction in the market of distribution concessionaires, ANEEL and MME implemented a series of measures aiming at the mitigation of overcontracting.

In relation 2021, the scenarios of supply and demand indicate the occurrence of overcontracting in relation to the contracted portion above the regulatory limits in the calendar year. However, the distributor will continue to exercise continuous vigilance in relation to its contracting levels and occurrences of involuntary events beyond its management, such as the migration of consumers to the free market and load reduction.

36.2.10Gas shortage risk

The natural gas market in Paraná covers Compagas consumers (non-thermoelectric market) and the Araucária Thermoelectric Plant (UEG Araucária). This market is currently supplied by contracts with Petrobras, which uses the transport infrastructure of the Brazil-Bolivia gas pipeline (Gasbol). As a result of the public call in 2021, Compagas signed a new contract with Petrobras for the supply of natural gas, effective from 2022 to 2025, which will make it possible to meet the demand that was uncontracted for 2022, as well as part of the estimated demand between 2023 and 2025. On the other hand, UEG Araucária negotiates and enters into short-term natural gas contracts as it does not have electricity generated under contract in the regulated environment.

In the current situation of the natural gas sector in Brazil, the New Gas Market program is coordinated by the Ministry of Mines and Energy together with the Civil House of the Presidency of the Republic, the Ministry of Economy, the Administrative Council for Economic Defense, the National Petroleum Agency and the Energy Research Company - EPE, whose purpose is to open the natural gas market in order to make it dynamic, competitive, integrated with the electric and industrial sector. This program is advancing, but still requires improvement of the sector’s regulation.

In the current natural gas market, there is already a growing supply of natural gas and diversified sources, having as alternatives the import of gas from Bolivia, import of liquefied natural gas (LNG), use of natural gas explored in onshore basins and greater use of natural gas from the pre-salt layer, which has large volumes to be explored. The biggest challenge of the sector still is enabling new producers and traders to access the infrastructure and the consumer market, currently mostly served by Petrobras.

Regarding the transport network, changes in regulation allow new shippers to access the gas pipelines, through public calls carried out by TBG (Gasbol transporter) with the purpose of offering the contracting of capacity in the gas pipeline. In addition, it is important to highlight the periodic updating of the Indicative Gas Pipeline Plan (PIG) coordinated by the EPE, which provides a vision of better structuring of the natural gas transport sector and adequate planning to meet current and future demands, even if for these latter significant investments are required.

Additionally, the new gas law, Law No. 14,134/2021, which replaces Law No. 11,909/2009, was signed, representing another important step in opening the Brazilian gas market, in order to make it more competitive and with greater potential expansion, in view of the fact that brings agility to the authorization, implantation and expansion of new ventures, as well as the possibility of third party access to existing infrastructures.

A possible shortage in gas supply could result in losses to Copel due to a reduction in revenue from the natural gas distribution service provided by Compagas, as well as any penalty resulting from non-compliance with the obligations contained in the concession contract. In addition, in this scenario, UEG Araucária would probably be kept out of operation. However, this risk is considered low in view of the situation of the New Gas Market and the Law No. 14,134/2021.

36.2.11Risk of non-performance of windfarms

The power generation purchase and sale contracts for wind power are subject to performance clauses, which provide for a minimum annual and four-year generation of the physical guarantee committed in the auction. Ventures are subject to climatic factors associated with wind velocity uncertainties. Non-compliance with what is stated in the agreement may jeopardize future revenues of the Company. The balance recorded in liabilities referring to the non-performance is demonstrated in note 29.

36.2.12Risk related to price of power purchase and sale transactions

The Company operates in the electricity purchase and sale market with the objective of achieving results with variations in the price of electricity, respecting the risk limits pre-established by Management. This activity, therefore, exposes the Company to the risk of future electricity prices.

Future electricity purchase and sale transactions are recognized at fair value through profit or loss, based on the difference between the contracted price and the market price of operations on the balance sheet date.

Based on the notional amounts of R$7,530,281 (R$6,065,065 in 2020) for electricity purchase contracts and R$7,881,880 (R$6,634,477 in 2020) for electricity sales contracts, outstanding at the date of these financial statements, the fair value was estimated using the prices defined internally by the Company, which represented the best estimate of the future market price. The discount rate used is based on the NTN-B rate of return disclosed by ANBIMA, adjusted for credit risk and additional project risk.

The balances referring to these outstanding transactions at the date of these financial statements are stated below.

 

       
       
  Assets  Liabilities Net
Current   112,057   (106,889) 5,168
Noncurrent   743,718   (438,579)   305,139
    855,775   (545,468)   310,307

 

Sensitivity analysis on the power purchase and sale transactions

The Company developed a sensitivity analysis in order to measure the impact of changes in future prices. For the base scenario, the accounting balances recorded on the date of these financial statements were considered and for the probable scenario, the balances updated with the market price curve and NTN-B rate of December 31, 2021 were considered. Additionally, the Company continues to monitor scenarios 1 and 2, which consider the 25% and 50% rise or fall applied to future prices considered in the probable scenario, as a result of extraordinary events that may affect the economic scenario.

 

           
  Price Baseline  Projected scenarios
  variation 12.31.2021 Probable   Scenario 1 Scenario 2
           
Unrealized gains (losses) on purchase and sale of energy  Increase  310,307 299,404 347,905 396,407
         
    Decrease  310,307 299,404 250,900 202,398

 

36.2.13Counterparty risk in the energy market

Since free energy market still does not have a counterparty acting as guarantor of all agreements (clearing house), there is a bilateral risk of default. Thus, the Company is exposed to the risk of failure in the supply of energy contracted by the seller. In the event of such failure, the Company must buy energy at the spot market price, being further subject to regulatory penalties and loss of amounts paid.

The Company follows a policy that establishes limits for possible operations with each counterparty, after analyzing its credit worthiness, maturity and history.

In addition, even if our policy is more restrictive and the counterparties present good financial condition, the Company is exposed to systemic events in which the default of one agent ends up affecting other energy trading companies in a "domino effect" until reaching the Company’s counterparties.

36.3Capital management

The Company seeks to keep a strong capital base to maintain the trust of investors, creditors and market and ensure the future development of the business. Management also strives to maintain a balance between the highest possible returns with more adequate levels of borrowings and the advantages and the assurance afforded by a healthy capital position. Thus, it maximizes the return for all stakeholders in its operations, optimizing the balance of debts and equity.

The Company monitors capital by using an index represented by adjusted net debt divided by adjusted EBITDA (Earnings before interest, taxes, depreciation and amortization), for the last twelve months. The corporate limit established in the debt indentures provides for maintenance of ratio below 3.5 while any expectation of failing to meet this target will prompt Management to take steps to correct its course by the end of each reporting period.

As of December 31, 2021 and 2020, the ratio attained is shown below:

 

     
     
  12.31.2021 12.31.2020
Loans and financing 3,678,444 3,188,531
Debentures  8,147,617 6,757,481
(-) Cash and cash equivalents   (3,472,845)   (3,222,768)
(-) Bonds and securities (current) (16,121)   (1,465)
(-) Bonds and securities (noncurrent) - debt contract guarantees   (237,183)   (175,901)
(-) Collaterals and escrow accounts STN   (142,764)   (133,521)
Adjusted net debt 7,957,148 6,412,357
Net income from continuing operations 3,859,045 3,834,172
Equity in earnings of investees   (366,314)   (193,547)
Deferred IRPJ and CSLL 790,406  24,896
Provision for IRPJ and CSLL 469,226 1,260,469
Financial expenses (income), net 327,361   (866,271)
Depreciation and amortization 1,082,539 1,009,913
Ebitda from discontinued operations 1,872,381 259,560
Adjusted ebitda 8,034,644 5,329,192
Adjusted net debt/Adjusted ebitda   0.99   1.20

 

 

36.3.1Debt to equity ratio:
     
Indebtedness 12.31.2021 12.31.2020
Loans and financing  3,738,269  3,168,710
Debentures  8,240,769  8,540,366
(-) Cash and cash equivalents  3,472,845  3,222,768
(-) Bonds and securities  361,058  300,530
Net debt  8,145,135  8,185,778
Equity 22,175,235 20,250,518
Debt to equity ratio 0.37 0.40