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35 Financial Instruments | 12 Months Ended
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Dec. 31, 2019
Financial Instruments [Abstract] |
Financial Instruments | 35 Financial Instruments 35.1 Categories and determination of fair value of financial instruments
| Note | Level | 12.31.2019 | 12.31.2018
| Book value | Fair value | Book value | Fair value
Financial assets |  |  |  |  |  |
Fair value through profit or loss |  |  |  |  |  |
Cash and cash equivalents (a) | 5 | 1 | 2,941,727 | 2,941,727 | 1,948,409 | 1,948,409
Bonds and securities (b) | 6 | 1 | 2,429 | 2,429 | 696 | 696
Bonds and securities (b) | 6 | 2 | 279,652 | 279,652 | 343,600 | 343,600
Accounts receivable - distribution concession (c) | 10.1 and 10.2 | 3 | 1,161,203 | 1,161,203 | 1,105,282 | 1,105,282
Accounts receivable - generation concession (d) | 10.5 | 3 | 69,182 | 69,182 | 65,811 | 65,811
Fair value in the purchase and sale of power in the active market (e) | 12 | 3 | 460,635 | 460,635 | 14,793 | 14,793
Other temporary investments (f) |  | 1 | 15,566 | 15,566 | 11,557 | 11,557
Other temporary investments (f) |  | 2 | 12,168 | 12,168 | 7,954 | 7,954
|  |  | 4,942,562 | 4,942,562 | 3,498,102 | 3,498,102
Amortized cost |  |  |  |  |  |
Collaterals and escrow accounts (a) |  |  | 147 | 147 | 203 | 203
Collateral and escrow deposits - STN (g) | 21.1 |  | 98,433 | 102,733 | 89,555 | 76,524
Trade accounts receivable (a) | 7 |  | 3,182,567 | 3,182,567 | 3,107,006 | 3,107,006
CRC Transferred to the Paraná State Government (h) | 8 |  | 1,350,685 | 1,479,683 | 1,445,042 | 1,546,469
Sectorial financial assets (a) | 9 |  | 473,989 | 473,989 | 678,819 | 678,819
Accounts receivable - concessions - RBSE (c) | 10.4 |  | 739,269 | 739,269 | 753,826 | 753,826
Accounts receivable - concessions - bonus from the grant (i) | 10.3 |  | 647,984 | 738,483 | 625,772 | 714,880
|  |  | 6,493,074 | 6,716,871 | 6,700,223 | 6,877,727
Total financial assets |  |  | 11,435,636 | 11,659,433 | 10,198,325 | 10,375,829
Financial liabilities |  |  |  |  |  |
Fair value in the purchase and sale of power (e) | 28 | 3 | 251,973 | 251,973 | 11,007 | 11,007
Derivatives fair value - forward contracts | 28 | 3 | 1,203 | 1,203 | - | -
|  |  | 253,176 | 253,176 | 11,007 | 11,007
Amortized cost |  |  |  |  |  |
Sectorial financial liabilities (a) | 9 |  | 102,284 | 102,284 | 96,531 | 96,531
Ordinary financing of taxes with the federal tax authorities (g) | 13.2 |  | 18,063 | 18,001 | 86,632 | 84,383
Special Tax Regularization Program - Pert (g) | 13.2 |  | 497,207 | 446,448 | 518,442 | 469,304
Accounts payable to suppliers (a) | 20 |  | 1,873,193 | 1,873,193 | 1,469,199 | 1,469,199
Loans and financing (g) | 21 |  | 3,168,710 | 3,204,188 | 4,047,307 | 4,012,621
Debentures (J) | 22 |  | 8,540,366 | 8,540,366 | 7,518,131 | 7,518,133
Accounts payable related to concession (k) | 26 |  | 612,587 | 694,742 | 584,163 | 687,869
Lease liabilities (a) | 27 |  | 96,604 | 96,604 | - | -
|  |  | 14,909,014 | 14,975,826 | 14,320,405 | 14,338,040
Total financial liabilities |  |  | 15,162,190 | 15,229,002 | 14,331,412 | 14,349,047
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 value 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 the financial statements. d) The fair values of generation assets approximate their carrying amounts, according to Note 4.4 of these Financial Statements. e) The fair values of assets and liabilities are equivalent to their carrying amounts according to Note 4.15 of 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 borrowing taken out by the Company is used as a basic assumption, 120.0% of CDI, 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 2.97% 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, 2019, obtained from the Brazilian Association of Financial and Capital Markets (ANBIMA), net of unamortized financial cost. k) Actual net discount rate of 8.16% p.a., in line with the Company's estimated rate for long-term projects. 35.2 Financial risk management The Company's business activities are exposed to the following risks arising from financial instruments: 35.2.1 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
Exposure to credit risk | 12.31.2019 | 12.31.2018
Cash and cash equivalents (a) | 2,941,727 | 1,948,409
Bonds and securities (a) | 282,081 | 344,296
Pledges and restricted deposits linked (a) | 98,580 | 89,758
Trade accounts receivable (b) | 3,182,567 | 3,107,006
CRC Transferred to the Paraná State Government (c) | 1,350,685 | 1,445,042
Sectorial financial assets (d) | 473,989 | 678,819
Accounts receivable - distribution concession (e) | 1,161,203 | 1,105,282
Accounts receivable - concessions - RBSE (f) | 739,269 | 753,826
Accounts receivable - concessions - Bonus from the grant (g) | 647,984 | 625,772
Accounts receivable - generation concessions (h) | 69,182 | 65,811
Other temporary investments (i) | 27,734 | 19,511
| 10,975,001 | 10,183,532
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 defaulting consumers, 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 believes this credit risk is low because repayments are secured by resources from dividends. 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 credit risk reduced to the balance of RBSE assets, even in light of the injunctions that temporarily reduced the RAP to be received, as described in Note 10.4. g) 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. h) 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. Management's expectation of indemnification for these assets supports recoverability of the balances recorded, as described in Note 10.5. i) 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. 35.2.2 Liquidity 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 2024, 2023 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
12.31.2019 |  |  |  |  |  |  |
Loans and financing | Note 21 | 31,783 | 115,995 | 308,094 | 2,063,354 | 1,666,502 | 4,185,728
Debentures | Note 22 | 391,329 | 61,304 | 1,049,225 | 7,256,323 | 1,655,253 | 10,413,434
Accounts payable related | Rate of return + |  |  |  |  |  |
to concession | IGP-M and IPCA | 6,099 | 12,198 | 56,222 | 336,027 | 1,389,334 | 1,799,880
Accounts payable to suppliers | - | 1,313,913 | 291,700 | 127,030 | 140,550 | - | 1,873,193
Ordinary financing of taxes |  |  |  |  |  |  |
with the federal tax authorities | Selic | 6,037 | 12,117 | - | - | - | 18,154
Special Tax Regularization Program - Pert | Selic | 4,122 | 8,282 | 37,820 | 219,788 | 335,681 | 605,693
Sectorial financial liabilities | Selic | - | - | - | 108,367 | - | 108,367
Lease liabilities | Note 27 | 3,485 | 6,980 | 31,793 | 73,515 | 11,226 | 126,999
|  | 1,756,769 | 508,576 | 1,610,184 | 10,197,923 | 5,057,996 | 19,131,448
(a) Effective interest rate - weighted average.
As disclosed in Notes 21.5 and 22.3, the Company have loans and financing agreements and debentures with covenants that if breached may have their payment accelerated. 35.2.3 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 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 Compagás 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 baseline scenario takes into account the existing balances in each account as of December 31, 2019 and the probable scenario assumes a variation in the foreign exchange rate - prevailing at the end of the period (R$/US$ 4.60) based on the median market expectation for 2020 reported in the Central Bank's Focus report of April 9, 2020. For the scenarios 1 and 2, deteriorations of 25% and 50%, respectively, were considered for the main risk factor for the financial instrument compared to the rate used in the probable scenario.
. |  | Baseline | Projected scenarios - Dec.2020
Foreign exchange risk | Risk | 12.31.2019 | Probable | Scenario 1 | Scenario 2
Financial assets |  |  |  |  |
Collaterals and escrow accounts - STN | USD depreciation | 98,433 | 13,903 | (14,181) | (42,265)
. |  | 98,433 | 13,903 | (14,181) | (42,265)
Financial liabilities |  |  |  |  |
Loans and financing - STN | USD appreciation | (108,983) | (15,393) | (46,487) | (77,581)
Suppliers |  |  |  |  |
Eletrobras (Itaipu) | USD appreciation | (222,431) | (31,416) | (94,878) | (158,340)
Acquisition of gas | USD appreciation | (79,174) | (11,183) | (33,772) | (56,361)
|  | (410,588) | (57,992) | (175,137) | (292,282)
In addition to the sensitivity analysis required by CVM Resolution 475/2008, the Company evaluates its financial instruments considering 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 held as of December 31, 2019, 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. 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, whose gains and losses are recognized in the Company's statement of income. Based on the notional amount of 22 million euros outstanding as of December 31, 2019, 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 as of the same date. The liability balance, recorded as of December 31, 2019, is shown in Note 28. 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 (€). The sensitivity analyses were prepared in accordance with CVM Instruction 475/08, considering, for scenarios 1 and 2, 25% and 50% increase or decrease in exchange rates, applied to the forward rate as of December 31, 2019. The results obtained are shown below
| Exchange rate variation | Baseline | Projected scenarios
|  | 12.31.2019 | Scenario 1 | Scenario 2
Gains (losses) on operations with derivative financial instruments | Increase | (1,203) | 23,777 | 48,757
| Decrease | (1,203) | (26,183) | (51,163)
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 financial expenses or increase the financial expenses related to the assets and liabilities raised in the market. 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. 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 baseline scenario takes into account the existing balances in each account as of December 31, 2019 while the probable scenario assumes balances reflecting varying indicators (CDI/Selic: 3.25%, IPCA: 2.52%, IGP-DI: 4.93%, IGP-M: 4.83% and TJLP: 5.20%) estimated as market average projections for 2020 according to the Focus Report issued by the Central Bank of Brazil as of April 9, 2020, except TJLP that considers the Company's internal projection. For the scenarios 1 and 2, deteriorations of 25% and 50%, respectively, were considered for the main risk factor for the financial instrument compared to the rate used in the probable scenario.
. |  | Baseline | Projected scenarios - Dec.2020
Interest rate risk and monetary variation | Risk | 12.31.2019 | Probable | Scenario 1 | Scenario 2
Financial assets |  |  |  |  |
Bonds and securities | Low CDI/SELIC | 282,081 | 9,168 | 6,876 | 4,584
Collaterals and escrow accounts | Low CDI/SELIC | 147 | 5 | 4 | 2
CRC Transferred to the Paraná State Government | Low IGP-DI | 1,350,685 | 66,589 | 49,942 | 33,294
Sectorial financial assets | Low Selic | 473,989 | 15,405 | 11,553 | 7,702
Accounts receivable - concessions | Low IPCA | 2,548,456 | 64,221 | 48,166 | 32,111
Accounts receivable - generation concessions | Undefined (a) | 69,182 | - | - | -
|  | 4,724,540 | 155,387 | 116,540 | 77,693
Financial liabilities |  |  |  |  |
Loans and financing |  |  |  |  |
Banco do Brasil | High CDI | (679,976) | (22,099) | (27,624) | (33,149)
BNDES | High TJLP | (2,198,064) | (114,299) | (142,874) | (171,449)
BNDES | High IPCA | (8,288) | (209) | (261) | (313)
Banco do Brasil - BNDES Transfer | High TJLP | (95,807) | (4,982) | (6,227) | (7,473)
Caixa Econômica Federal | High TJLP | (331) | (17) | (22) | (26)
Other | No risk | (77,261) | - | - | -
Debentures | High CDI/SELIC | (6,464,603) | (210,100) | (262,624) | (315,149)
Debentures | High IPCA | (1,950,591) | (49,155) | (61,444) | (73,732)
Debentures | High TJLP | (125,172) | (6,509) | (8,136) | (9,763)
Sectorial financial liabilities | High Selic | (102,284) | (3,324) | (4,155) | (4,986)
Ordinary financing of taxes with the federal tax authorities | High Selic | (18,063) | (587) | (734) | (881)
Special Tax Regularization Program - Pert | High Selic | (497,207) | (16,159) | (20,199) | (24,239)
Accounts payable related to concession | High IGP-M | (563,756) | (27,793) | (34,741) | (41,690)
Accounts payable related to concession | High IPCA | (48,831) | (1,231) | (1,538) | (1,846)
. |  | (12,830,234) | (456,464) | (570,580) | (684,697)
(a) Risk assessment still requires ruling by the Granting Authority.
In addition to the sensitivity analysis required by CVM Resolution 475/2008, the Company evaluates its financial instruments considering 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 Based on the equity position and the notional value of the financial instruments held as of December 31, 2019, 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. 35.2.4 Electricity 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. Since 2014, the reservoirs of the Southeast/Midwest, North and Northeast Brazilian regions have been subject to adverse climate situations, leading agencies responsible for this industry to adopt water resources optimization measures to guarantee fully meeting electricity demand. The Electric Sector Monitoring Committee (CMSE) has maintained the energy deficit risk indicators within the safety margin in short-term projections. The same position is adopted by ONS regarding the risk of deficit in the medium term, as stated in the 2019-2023 Energy Operation Plan - PEN 2019. Although dam storage levels are not ideal, from the standpoint of regulatory agencies, when combined with other variables, such as a slower consumption growth, they are sufficient to keep the risk of deficit within the safety margin established by the National Energy Policy Council (Conselho Nacional de Política Energética - CNPE) (maximum risk of 5%) in all subsystems. 35.2.5 Risk of GSF impacts The Energy Reallocation Mechanism (Mecanismo de Realocação de Energia - 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 Physical Guarantee (Garantia Física - 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 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, approach 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, Santa Clara, Fundão, 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. 35.2.6 Risk of non-renewal of concessions - generation and transmission Currently, the extension of energy generation and transmission concessions, achieved by Law No. 9,074/1995, is regulated by Law No. 12,783/2013. 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. The concession operator should request extension of concession at least 60 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. However, 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, changing 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. Copel has 2 plants whose concession ends in the next 5 years. For HPP Governador Bento Munhoz da Rocha Netto (HPP GBM) (1,676 MW), whose concession will end in 2023, 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 divesting the control of this concessionaire and, thus, allow a new concession grant for 30 years (Note 40.2). With respect to HPP São Jorge, whose concession ends in 2024, 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 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 law, the Company may express its intention to extend the concession of the Apucaraninha HPP in 2020, and the Guaricana and Chaminé HPPs in 2021. 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 does not have any transmission concession ending in the next ten years. 35.2.7 Risk 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. 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) | Extinction of the dividend |
Quality Indicators | 2 consecutive years or 3 times | Distribution limitation concession and interest on equity |
Economic - financial efficiency | In 5 years in the base year | Capital Increase (a) |
From the 6th year of (2021) | Economic and 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 defined for Copel Distribuição in the first five years after extension of the concession agreement
|  |  | 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 | EBITDA = 0 (c) | 661,391 | 12.54 | 8.74 | 10.41 | 6.79
2018 | EBITDA (-) QRR = 0 (d) | 550,675 | 11.23 | 8.24 | 10.29 | 6.20
2019 | {Net Debt / [EBITDA (-) QRR]} ≤ 1 / (0.8 * SELIC) (e) |  | 10.12 | 7.74 | 9,10(f) | 6,00(f)
2020 | {Net Debt / [EBITDA (-) QRR]} ≤ 1 / (1.11 * SELIC) (e) |  | 9.83 | 7.24 | - | -
(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.y.
(f) DECi / FECi in 2019: preliminary data
35.2.8 Risk of non-extension of the gas distribution concession As presented in Note 2.1.1, the expiration date of the gas distribution concession of the subsidiary Compagás is under discussion with the concession grantor. In the event of non-extension of the concession, Compagás 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. 35.2.9 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'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. Since 2016, 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, ANEEL and MME implemented a series of measures aiming at the mitigation of overcontracting. In relation to the contracting of 2019, the scenarios of supply and demand indicate the occurrence of over contracting 105.8% by Copel DIS. Nevertheless, considering that this situation arises mainly from the migration of consumers to the free market, it is considered that the distributor maintains the guarantee of neutrality preserved, since this factor is subject to the recognition of involuntary over contracting. 35.2.10 Gas shortage risk The natural gas market in Paraná is composed of Compagás' consumers (non-thermal market) and the Araucária Thermoelectric Plant (UEG Araucária). This market is supplied by contracts with Petrobras that uses the transportation infrastructure of the Brazil-Bolivia gas pipeline (Gasbol). Compagás has a contract for the supply of natural gas from Bolivia until December 2021, and is making a public bidding for the supply of natural gas as from January 2022. UEG Araucária, on the other hand, negotiates short-term natural gas contracts for not having electricity generated contracted 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, with an improved regulation. Within the scope of the New Gas Market, the offer of natural gas already demonstrates growth and diversification, having as alternatives the import of gas from Bolivia, import of liquefied natural gas (LNG) that has a large world offer, use of natural gas from onshore basins and greater use of natural gas from the pre-salt which has large volumes to be extracted. In relation to the transportation network, the changes in regulation to allow access to new agents, the public call of TBG (Gasbol transporter) that establishes a new capacity contracting regime in the gas pipeline and the Gas Pipeline Indicative Plan (PIG) coordinated by EPE, give a vision of better structuring of the sector and adequate planning to meet current and future demands, even though investments are needed for the latter. 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 Compagás, 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. 35.2.11 Risk 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. At December 31, 2019, the consolidated balance of the provision recorded in liabilities referring to the non-performance is R$ 65,790 (R$ 83,525, at December 31, 2018), which may be offset by higher future production, measured within the annual and/or four-yearly contractual cycle. 35.2.12 Risk 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, determined by the difference between the contracted price and the future market price estimated by the Company. On December 31, 2019, based on the notional amounts of R$ 4,448,602 (R$ 222,928 on 12.31.2018) for purchase contracts and R$ 4,089,801 (R$ 95,382 on 12.31.2018) for electricity sales contracts, the fair value was estimated using the prices defined internally by the Company in the last week of December 2019, 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 January 2, 2020, adjusted for credit risk and additional project risk. The balances referring to these outstanding transactions as of December 31, 2019 are shown below. The variation in relation to the net balance of R$ 3,786, on December 31, 2018, results from the increase in the level of contracting in the free energy market
| Assets | Liabilities | Net
Current | 13,540 | (7,152) | 6,388
Noncurrent | 447,095 | (244,821) | 202,274
| 460,635 | (251,973) | 208,662
Sensitivity analysis on the power purchase and sale transactions The main risk factor is the exposure to variation of energy market prices. The variation of the discount rate does not have a relevant impact on the fair value determined. The sensitivity analyses were prepared in accordance with CVM Instruction 475/08. For the probable scenario, the balances were updated with the market price curve, the credit risk rate and the NTN-B rate on April 7, 2020. For scenarios 1 and 2, the increase or decrease of 25% and 50% in future prices, applied to market prices of December 31, 2019. The results obtained are as follows:
| Price | Baseline | Projected scenarios |  |
| variation | 12.31.2019 | Probable | Scenario 1 | Scenario 2
Gains (losses) on purchase and sale of energy in active market | Increase | 208,662 | 192,103 | 270,953 | 349,803
| Decrease | 208,662 | 192,103 | 113,253 | 34,402
35.2.13 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 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. 35.3 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 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, 2019, the ratio attained is shown below
| 31.12.2019 | 31.12.2018
Loans and financing | 3,142,383 | 4,047,307
Debentures | 8,429,710 | 7,518,131
(-) Cash and cash equivalents | (2,941,727) | (1,948,409)
(-) Bonds and securities (current) | (3,112) | (124,862)
(-) Bonds and securities (noncurrent) | (121,617) | (112,604)
(-) Collaterals and escrow accounts STN | (98,433) | (89,555)
Adjusted net debt | 8,407,204 | 9,290,008
Net Income | 2,062,869 | 1,444,004
Equity in earnings of investees | (106,757) | (135,888)
Deferred IRPJ and CSLL | 205,771 | (68,072)
Provision for IRPJ and CSLL | 433,555 | 580,065
Financial expenses (income), net | 488,486 | 438,050
Depreciation and amortization | 1,093,836 | 749,179
Adjusted ebitda | 4,177,760 | 3,007,338
Adjusted net debt / Adjusted ebitda | 2.01 | 3.09
35.3.1 The equity to debt ratio is shown below:
Indebtedness | 12.31.2019 | 12.31.2018
Loans and financing | 3,168,710 | 4,047,307
Debentures | 8,540,366 | 7,518,131
(-) Cash and cash equivalents | 2,941,727 | 1,948,409
(-) Bonds and securities | 282,081 | 344,296
Net debt | 8,485,268 | 9,272,733
Equity | 17,598,212 | 16,336,214
Equity indebtedness | 0.48 | 0.57

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