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Financial Instruments | 12 Months Ended
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Dec. 31, 2022
Financial Instruments |
Financial Instruments |
34. | Financial Instruments
| 34.1 | Categories and determination of fair value of financial instruments
Schedule of fair value of financial instruments |  |  |  |  |  |
|  |  |  | 12.31.2022 |  | 12.31.2021
| 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 | 2,678,457 | 2,678,457 | 3,472,845 | 3,472,845
Bonds and securities (b) | 6 | 1 | - | - | 14,571 | 14,571
Bonds and securities (b) | 6 | 2 | 431,056 | 431,056 | 346,487 | 346,487
Accounts receivable - distribution concession (c) | 9.1 and 9.2 | 3 | 1,442,819 | 1,442,819 | 1,433,734 | 1,433,734
Accounts receivable - generation concession (c) | 9.4 | 3 | 68,642 | 68,642 | 102,220 | 102,220
Derivatives fair value - forward contracts (d) | 11 | 3 | - | - | 2,907 | 2,907
Fair value in the purchase and sale of power (d) | 11 | 3 | 1,081,758 | 1,081,758 | 855,775 | 855,775
Other temporary investments (e) |  | 1 | 15,372 | 15,372 | 14,072 | 14,072
Other temporary investments (e) |  | 2 | 10,247 | 10,247 | 5,913 | 5,913
|  |  | 5,728,351 | 5,728,351 | 6,248,524 | 6,248,524
Amortized cost |  |  |  |  |  |
Collaterals and escrow accounts (a) |  |  | 157 | 157 | 182 | 182
Collateral and escrow deposits - STN |  |  | - | - | 142,764 | 115,643
Trade accounts receivable (a) | 7 |  | 3,451,869 | 3,451,869 | 4,515,426 | 4,515,426
Sectorial financial assets (a) | 8 |  | 381,398 | 381,398 | 767,480 | 767,480
Accounts receivable - concessions - bonus from |  |  |  |  |  |
the grant (g) | 9.3 |  | 766,832 | 866,653 | 730,851 | 828,673
|  |  | 4,600,256 | 4,700,077 | 6,156,703 | 6,227,404
Fair value through other comprehensive income |  |  |  |  |  |
Certified Emission Reductions - CERs (j) | 29.4 |  | 10,295 | 10,295 | - | -
|  |  | 10,295 | 10,295 | - | -
Total financial assets |  |  | 10,338,902 | 10,438,723 | 12,405,227 | 12,475,928
Financial liabilities |  |  |  |  |  |
Fair value through profit or loss |  |  |  |  |  |
Fair value in the purchase and sale of power (d) | 27 | 3 | 738,703 | 738,703 | 545,468 | 545,468
|  |  | 738,703 | 738,703 | 545,468 | 545,468
Amortized cost |  |  |  |  |  |
Sectorial financial liabilities (a) | 8 |  | 483,255 | 483,255 | 293,179 | 293,179
ICMS installment payment (f) | 12.2.4 |  | 48,320 | 43,419 | - | -
Special Tax Regularization Program - Pert (f) | 12.2 |  | 404,075 | 340,025 | 421,694 | 361,080
PIS and Cofins to be refunded to consumers (a) | 12.2.1 |  | 1,995,158 | 1,995,158 | 3,326,795 | 3,326,795
Accounts payable to suppliers (a) | 19 |  | 2,215,470 | 2,215,470 | 2,710,984 | 2,710,984
Loans and financing (f) | 20 |  | 4,694,957 | 4,171,789 | 3,738,269 | 3,313,645
Debentures (h) | 21 |  | 7,887,077 | 7,688,396 | 8,240,769 | 8,240,769
Accounts payable related to concession (i) | 25 |  | 937,542 | 1,051,710 | 903,959 | 1,009,867
|  |  | 18,665,854 | 17,989,222 | 19,635,649 | 19,256,319
Total financial liabilities |  |  | 19,404,557 | 18,727,925 | 20,181,117 | 19,801,787
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 book 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) | Financial assets with fair values ​​similar to book values ​​(Note 4.4).
| d) | The fair values of assets and liabilities are equivalent to their book values (Note 4.15).
| e) | 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.
| f) | The cost of the highest value of the last funding carried out by the Company, CDI + spread of 1.22%, is used as a basic assumption for the discount of the expected payment flows.
| g) | 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%).
| h) | Calculated according to the quotation of the last trade in the secondary market through the average price of the Unit Price - PU on December 31, 2022, obtained from the Brazilian Association of Financial and Capital Market Entities - Anbima.
| i) | The actual pre-tax discount rate of 8.65% p.a. was used, compatible with the rate estimated by the Company for long-term projects.
| j) | Financial assets with fair values ​​similar to book values ​​(Note 4.2).
| 34.2 | Financial risk management
The Company's business activities are exposed to the following risks arising from financial instruments:
| 34.2.1 | Credit 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.
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 | 12.31.2022 | 12.31.2021
Cash and cash equivalents (a) | 2,678,457 | 3,472,845
Bonds and securities (a) | 431,056 | 361,058
Pledges and restricted deposits linked (a) | 157 | 142,946
Trade accounts receivable (b) | 3,451,869 | 4,515,426
Sectorial financial assets (c) | 381,398 | 767,480
Accounts receivable - distribution concession (c) | 1,442,819 | 1,433,734
Accounts receivable - concessions - bonus from the grant (d) | 766,832 | 730,851
Accounts receivable - generation concessions (e) | 68,642 | 102,220
Other temporary investments (f) | 25,619 | 19,985
| 9,246,849 | 11,546,545
| 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) | Risk of losses resulting from difficulties to receive amounts billed to customers related to internal and external factors. 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) | 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 Granting Authority, corresponding to the costs and investments not recovered through the tariff.
| d) | 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.
| e) | 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. In August 2022, Copel filed with Aneel the assessment reports related to the residual values, with a base date of July 2015, for the HPP Governador Parigot de Souza - GPS and HPP Mourão - MOU, which are awaiting inspection and subsequent validation by the regulatory agency. Management's expectation of indemnification for these assets supports recoverability of the balances recorded.
| f) | Risk arising from the possibility of the Company incurring losses due to stock market volatility. This type of risk involves external factors and is being managed through periodic assessments of the variations in the market.
| 34.2.2 | Liquidity risk
The liquidity risk of the Company 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 by 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 Focus Report, which provides the average expectations of market analysts for these indicators for the current year and for the next 3 years. From 2027 on, the 2026 indicators are repeated throughout the forecast period.
Schedule of liquidity risk |  |  |  |  |  |  |
|  | Less than | 1 to 3 | 3 months | 1 to 5 | Over |
| Interest (a) | 1 month | months | to 1 year | years | 5 years | Total
12.31.2022 |  |  |  |  |  |  |
Loans and financing | Note 20 | 39,138 | 176,621 | 474,493 | 3,593,649 | 2,481,487 | 6,765,388
Debentures | Note 21 | 95,407 | 42,366 | 1,928,303 | 6,695,007 | 2,333,033 | 11,094,116
Accounts payable related | Rate of return + |  |  |  |  |  |
to concession | IGP-M and IPCA | 9,674 | 19,371 | 87,865 | 508,869 | 2,258,292 | 2,884,071
Accounts payable to suppliers | - | 1,919,501 | 206,735 | 23,031 | 66,203 | - | 2,215,470
PIS and Cofins to be refunded |  |  |  |  |  |  |
to consumers | Note 12.2.1 | - | - | 387,721 | 1,365,327 | 357,912 | 2,110,960
Special Tax Regularization Program - Pert | Selic | 4,776 | 9,665 | 45,279 | 282,820 | 170,426 | 512,966
ICMS installment payment | Selic | 874 | 1,767 | 8,259 | 46,722 | - | 57,622
Sectorial financial liabilities | Selic | 36,543 | 74,240 | 353,022 | 59,037 | - | 522,842
Lease liability | Note 26 | 8,146 | 15,893 | 67,566 | 174,725 | 364,729 | 631,059
|  | 2,114,059 | 546,658 | 3,375,539 | 12,792,359 | 7,965,879 | 26,794,494
(a) | Effective interest rate - weighted average.
As disclosed in Notes 20.4 and 21.3, the Company has loans and financing agreements and debentures with covenants that if breached may have their payment accelerated.
| 34.2.3 | Market 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 effect of the exchange rate variation resulting from the power purchase agreement with 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 to measure the impact of the devaluation of the US dollar on its financial liabilities 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. For the baseline scenario, the accounting balances recorded on the date of these financial statements were considered and for the probable scenario, the Company considers the balance updated with the exchange rate variation - prevailing at the end of the period (R$/US$5.25) based on the median market expectation for 2023 according to the Central Bank of Brazil Focus Report. 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, because of extraordinary events that may affect the economic scenario.
Schedule of sensitivity analysis of foreign currency risk |  |  |  |  |
. |  | Baseline | Projected scenarios
Foreign exchange risk | Risk | 12.31.2022 | Probable | Scenario 1 | Scenario 2
. |  |  |  |  |
Financial liabilities |  |  |  |  |
Suppliers |  |  |  |  |
Itaipu | USD appreciation | (284,930) | (1,764) | (73,437) | (145,111)
Acquisition of gas | USD appreciation | (93,696) | (580) | (24,149) | (47,718)
|  | (378,626) | (2,344) | (97,586) | (192,829)
| b) | 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 financial expenses related to the assets and liabilities raised in the market. The Company has not entered derivative contracts to cover this risk but has been continuously monitoring interest rates and market indexes to observe any need for contracting. Sensitivity analysis of interest rate and monetary variation risk The Company has developed a sensitivity analysis 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. For the baseline scenario, the accounting balances recorded on the date of these financial statements were considered and for the probable scenario, the Company considers the balances updated with the variation of the indicators (CDI/Selic - 12.50%, IPCA - 5.78%, IGP-M - 4.60% and TJLP - 7.05%) estimated as market average projections for 2023 according to the Central Bank of Brazil Focus Report, except 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, because of extraordinary events that may affect the economic scenario.
Schedule of gains (losses) on operations with derivative financial instruments |  |  |  |  |
. |  | Baseline | Projected scenarios
Interest rate risk and monetary variation | Risk | 12.31.2022 | Probable | Scenario 1 | Scenario 2
. |  |  |  |  |
Financial assets |  |  |  |  |
Bonds and securities | Low CDI/SELIC | 431,056 | 53,883 | 40,433 | 26,942
Collaterals and escrow accounts | Low CDI/SELIC | 157 | 19 | 14 | 10
Sectorial financial assets | Low Selic | 381,398 | 47,675 | 35,756 | 23,837
Accounts receivable - concessions | Low IPCA | 2,209,651 | 127,718 | 95,788 | 63,859
Accounts receivable - generation concessions | Undefined (a) | 68,642 | - | - | -
|  | 3,090,904 | 229,295 | 171,991 | 114,648
Financial liabilities |  |  |  |  |
Loans and financing |  |  |  |  |
Banco do Brasil | High CDI | (751,673) | (93,959) | (117,449) | (140,939)
Banco Itaú | High CDI | (1,037,946) | (129,743) | (162,179) | (194,615)
BNDES | High TJLP | (1,712,943) | (120,787) | (150,983) | (181,180)
BNDES | High IPCA | (389,801) | (22,530) | (28,163) | (33,796)
Banco do Nordeste | High IPCA | (718,835) | (41,549) | (51,936) | (62,323)
Banco do Brasil - BNDES Transfer | High TJLP | (60,720) | (4,282) | (5,352) | (6,422)
Other | No risk | (23,039) | - | - | -
Debentures | High CDI/SELIC | (4,953,884) | (619,235) | (774,044) | (928,853)
Debentures | High IPCA | (2,841,725) | (164,252) | (205,315) | (246,378)
Debentures | High TJLP | (91,468) | (6,450) | (8,062) | (9,675)
Sectorial financial liabilities | High Selic | (483,255) | (60,407) | (75,509) | (90,610)
ICMS installment payment | High Selic | (48,320) | (6,040) | (7,550) | (9,060)
Special Tax Regularization Program - Pert | High Selic | (404,075) | (50,509) | (63,137) | (75,764)
Accounts payable related to concession | High IGP-M | (874,187) | (40,213) | (50,266) | (60,319)
Accounts payable related to concession | High IPCA | (63,355) | (3,662) | (4,577) | (5,493)
. |  | (14,455,226) | (1,363,618) | (1,704,522) | (2,045,427)
(a) | Risk assessment still requires ruling by the Concession grantor.
| 34.2.4 | Electricity shortage risk
Most of the installed capacity in Brazil currently comes from hydroelectric generation, 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. Between September 2020 and August 2021, the National Interconnected System - SIN presented the worst record of Affluent Natural Energies in the aggregate of its uses. The Brazilian Ministry of Mines and Energy and other sector bodies worked to maximize the thermoelectric dispatch out of the cost merit order, as well as the easing of restrictions on the system's hydroelectric operation. Additionally, considering the strong wind generation in the Northeast, biomass generation in the Southeast and the rainy season with affluent natural energies that raised the reservoirs to comfortable values, it is estimated that the risk of energy shortages in 2023 and 2024 is minimized. The energy supply guarantee criteria are currently established by the National Energy Policy Council - CNPE through Resolution 29/2019. With reason, the responsible bodies keep the energy deficit risk indicators within the safety margin in all subsystems.
| 34.2.5 | Risk of Generation Scaling Factor - GSF impacts
The Energy Reallocation Mechanism - MRE 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 assured energy (GF) 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 guarantee. 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 hydroelectric projects participating in the MRE. 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 Regulated Contracting Environment - 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 HPP Mauá, HPP Baixo Iguaçu, HPP Colíder and SHP Cavernoso II. For the distribution segment, the effects of the GSF are perceived in the costs associated with quotas of Itaipu, of Angra, of the plants whose concessions were renewed in accordance with Law 12,783/2013 and the plants that renegotiated the hydrological risk in the ACR, in accordance with Law 13,203/2015. This is a financial risk, since there is guarantee of neutrality of expenses with energy purchases through a tariff transfer. It should be noted that, at least conjuncturally, the GSF risks are greatly reduced due to the improvement in the hydrological scenario in 2022 concomitant with the low load growth.
| 34.2.6 | Risk 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, with regard to the deadline for requesting the extension of concessions. According to the mentioned law, the concession operator should request extension of concession at least 36 months before the end date of the contract or act of granting for hydroelectric power plants and electric power transmission enterprises, and 24 months before the end date of the contract or act of granting for thermoelectric plants. The Granting Authority 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 2018, Decree No. 9.271/2018 was published, amended by Decrees No. 10.135/2019, No. 10.893/2021 and No. 11.307/2022, 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 12 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. Some of the generation projects of Copel had their concession period extended due to the effects of the GSF renegotiation, which established the compensation through an extension of the concession period of the plants contemplated by Law No. 13,203/2015, resulting in the approval of the extension period of the concession of these plants through of Ratifying Resolutions No. 2,919/2021 and No. 2,932/2021. For HPP Governador Bento Munhoz da Rocha Netto - 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 the subsidiary F.D.A. Geração de Energia Elétrica S.A. with the purpose of divesting the control of this concessionaire and, thus, allow a new concession grant for 30 years, as provided for in Decree No. 9.271/2018. The process of transforming Copel into a “Corporation” is underway, as described in Note 1, which will allow the Company to maintain 100% interest in the plant. 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 TPP Figueira concession, which expired in March 2019, the Company awaits the conclusion of the process, which is in progress at Aneel and MME. The plant went through a modernization process that provided direct benefits such as improved energy efficiency and reduced emissions of pollutants in the atmosphere, compared to the old plant. The plant was released for commercial operation on December 7, 2022, through Order No. 3,502/2022. According to the Law No. 14,052/2020, the Company may express its intention to extend the concession of the HPP Apucaraninha until January 2024, and the HPP Guaricana and HPP Chaminé 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 Granting Authority. Regarding the transmission segment, the only Copel GeT concession to expire in the next ten years is the Concession Contract No. 75/2001, referring to Transmission Line Bateias-Jaguariaíva 230 kV, which will expire on August 17, 2031. Additionally, regarding the extension of transmission concession contracts, on December 29, 2022 Decree No. 11,314 was published, determining that the extension of transmission concessions may be carried out only when the bidding process is unfeasible or results in damage to the public interest and will be carried out without the advance indemnity of the assets linked to the provision of the service, conditioned to the acceptance by the concessionaire in relation to the revenue and other conditions of the amendment to be prepared by Aneel.
| 34.2.7 | Risk on non-renewal of concessions – distributions of electricity
The fifth amendment to Copel DIS 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 No. 896, consolidated by Normative Resolution No. 948/2021, 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. According to Aneel Technical Note No. 068/2021 and Authorizing Resolution No. 10,231/2021, as of 2022 the quality targets will become the indicators DEC (System Average Interruption Duration Index) and FEC (Customer Average Interruption Duration Index). Indicators and penalties
Indicators and penalties |  |  |
Year | Indicator | Criteria | Penalties
From 2021 | Economic - financial efficiency | in the base year | Capital Increase (a)
Limitation on distribution of dividends and interest on capital
Restrictive regime for contracts with related parties
2 consecutive years | Concession termination
Quality Indicators | in the base year | Results plan
2 consecutive years | Limitation on distribution of dividends and interest on capital
3 consecutive years | Concession termination
(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 set for Copel Distribuição as of 2021
Schedule of targets set |  |  |  |  |  |
|  |  | Quality - limits | Quality - performed
Year | Economic and Financial Management | Realized | DECi | FECi | DECi | FECi
2021 | {Net Debt / [EBITDA (-) QRR ≥ 0]} ≤ 1 / (1,11 * Selic) | Achieved | 9.29 | 6.84 | 7.20 | 4.76
Year | Economic and Financial Management | Realized | DEC | FEC | DEC | FEC
2022 | {Net Debt / [EBITDA (-) QRR ≥ 0]} ≤ 1 / (1,11 * Selic) | - | 9.19 | 6.80 | 7.98 | 5.29
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 VIII to Aneel Resolution No 948/2021.
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: Earnings Before Interest (Financial Result), Taxes (Income Taxes), Depreciation and Amortization.
The Company monitors concession indicators in order to anticipate actions that ensure efficiency gains and compliance with regulatory requirements and the result is disclosed in the Regulatory Financial Statements.
| 34.2.8 | Risk of non-extension of the gas distribution concession
Upon termination of the concession by the end of the contractual term, the assets linked to the gas distribution services will revert to the Granting Authority, the State of Paraná, and the Company will be compensated for the assets related to the concession that have not yet been amortized, evaluated at their book value monetarily restated up to that date.
| 34.2.9 | Risk 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 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. plus the amounts of involuntary overcontracting recognized by the regulator. Copel DIS estimates that it will end the year with a contracting level of 111.4%, however, it considers that it has sufficient amounts of "involuntary over-contracting" to accommodate the estimated contracting for the year. Thus, there is no risk of penalization for over-contracting.
| 34.2.10 | Gas shortage risk
The natural gas market in Paraná, made up of Compagas consumers (non-thermoelectric market) and the Araucária Thermoelectric Power Plant (UEG Araucária), is supplied by contracts with Petrobras that use the transport infrastructure of the Brazil-Bolivia gas pipeline (Gasbol). Compagas signed a 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 not contracted for 2022, as well as part of the estimated demand between 2023 and 2025. UEG Araucária, meanwhile, negotiates and signs short-term natural gas contracts as a result of its merchant operation regime. In the current situation of the natural gas sector in Brazil, the Novo Mercado de Gás program, coordinated by the Ministry of Mines and Energy, aims to open the natural gas market to make it dynamic, competitive, integrated with the electrical and industrial sectors. The supply of natural gas is growing and coming from diverse sources, and the great challenge for the sector still focuses on enabling new producers and traders to access infrastructure and the consumer market, currently served mostly by Petrobras. Finally, the new gas law, Law No. 14.134/2021, represents another important step in opening up the Brazilian gas market, in order to make it more competitive and with greater potential for expansion. A possible shortage in the supply of gas could result in losses for Copel due to a reduction in revenue from the natural gas distribution service by Compagas or penalties for non-compliance with the obligations contained in the concession contract. Furthermore, in this scenario, UEG Araucária would probably be kept out of operation. However, the Company considers this risk to be low in view of the situation of the Novo Mercado de Gás and the enactment of Law No. 14,134/2021.
| 34.2.11 | Risk of non-performance of wind farms
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 assured energy 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 27.
| 34.2.12 | Risk related to price of power purchase and sale transactions
The Company operates in the electricity purchase and sale market to achieve 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 by the volatility of future electricity prices. Future electricity purchase and sale transactions are recognized at fair value through profit or loss, according to Note 4.15.1, based on the difference between the contracted price and the market price of operations on the balance sheet date. The table below shows the notional values of the electricity commercialization contracts on the date of these financial statements, which have an average maturity of 139 months for purchase contracts and 25 months for sales contracts:
Targets for Copel Distribuion from 2016 to 2020 |  |
. | Purchase | Sale
2023 | 606,571 | 645,966
2024 | 752,615 | 810,145
2025 | 742,114 | 794,957
2026 | 738,024 | 734,063
2027 | 673,274 | 620,858
2028 to 2040 | 4,130,827 | 4,577,941
| 7,643,425 | 8,183,930
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 on December 31, 2022, without inflation, 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.
Schedule of deadline for manifestation |  |  |
| Assets | Liabilities | Net
Current | 288,419 | (244,064) | 44,355
Noncurrent | 793,339 | (494,639) | 298,700
| 1,081,758 | (738,703) | 343,055
Sensitivity analysis of energy purchase and sale operations The Company developed a sensitivity analysis 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 Company considers the balances updated with the market price curve and NTN-B rate on December 31, 2022. 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, because of extraordinary events that may affect the economic scenario.
Schedule of sensitivity analysis on the power purchase and sale transactions in the active market |  |  |  |  |
| Price | Baseline | Projected scenarios
| variation | 12.31.2022 | Probable | Scenario 1 | Scenario 2
Unrealized gains (losses) on energy purchase and sale operations | Increase | 343,055 | 343,055 | 369,579 | 396,104
| Decrease | 343,055 | 343,055 | 316,528 | 290,003
| 34.2.13 | Counterparty 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 buyer/seller. In the event of such failure, the Company is obliged to sell/acquire 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.
| 34.3 | Capital 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 consolidated net debt divided by adjusted consolidated EBITDA (Earnings before interest, taxes, depreciation and amortization), for the last twelve months. The corporate limit established in the debt deeds provides for the annual maintenance of the index below 3.5, and the eventual expectation of non-compliance of that indicator gives rise to actions by the Management to correct the course of the calculations until the end of each year. As of December 31, 2022 and 2021, the ratio attained is shown below:
Schedule of capital monitored by index |  |
| 12.31.2022 | 12.31.2021
Loans and financing | 4,650,363 | 3,678,444
Debentures | 7,803,855 | 8,147,617
(-) Cash and cash equivalents | (2,678,457) | (3,472,845)
(-) Bonds and securities (current) | (93) | (16,121)
(-) Bonds and securities (noncurrent) - debt contract guarantees | (290,602) | (237,183)
(-) Collaterals and escrow accounts STN | - | (142,764)
Adjusted net debt | 9,485,066 | 7,957,148
Net income from continuing operations | 1,149,321 | 3,859,045
Equity in earnings of investees | (478,577) | (366,314)
Deferred IRPJ and CSLL | (628,389) | 790,406
Provision for IRPJ and CSLL | 429,267 | 469,226
Financial expenses (income), net | 1,966,037 | 327,361
Depreciation and amortization | 1,300,982 | 1,082,539
Hydrological Risk Renegotiation - GSF | - | (1,570,543)
Provision for allocation of PIS and Cofins credits | 810,563 | -
(-/+) Impairment | 84,387 | (134,854)
Ebitda from discontinued operations | - | 1,872,381
Adjusted ebitda | 4,633,591 | 6,329,247
Adjusted net debt/Adjusted ebitda | 2.05 | 1.26
| 34.3.1 | Debt to equity ratio:
Debt to equity ratio |  |
Indebtedness | 12.31.2022 | 12.31.2021
Loans and financing | 4,694,957 | 3,738,269
Debentures | 7,887,077 | 8,240,769
(-) Cash and cash equivalents | (2,678,457) | (3,472,845)
(-) Bonds and securities | (431,056) | (361,058)
Net debt | 9,472,521 | 8,145,135
Equity | 21,131,225 | 22,175,235
Debt to equity ratio | 0.45 | 0.37

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