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35 Financial Instruments

12 Months Ended

Dec. 31, 2020

35	Financial Instruments

35.1	Categories and determination of fair value of financial instruments

				12.31.2020	12.31.2019	Restated
	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	3,222,768	3,222,768	2,941,727	2,941,727
Bonds and securities (b)	6	1	751	751	2,429	2,429
Bonds and securities (b)	6	2	299,779	299,779	279,652	279,652
Accounts receivable - distribution concession (c)	10.1 and 10.2	3	1,149,934	1,149,934	1,161,203	1,161,203
Accounts receivable - generation concession (d)	10.4	3	81,202	81,202	69,182	69,182
Derivatives fair value - forward contracts (e)	12	3	23,308	23,308	-	-
Fair value in the purchase and sale of power (e)	12	3	689,531	689,531	460,635	460,635
Other temporary investments (f)		1	14,910	14,910	15,566	15,566
Other temporary investments (f)		2	7,475	7,475	12,168	12,168
			5,489,658	5,489,658	4,942,562	4,942,562
Amortized cost
Collaterals and escrow accounts (a)			197	197	147	147
Collateral and escrow deposits - STN (g)	21.1		133,521	113,477	98,433	94,671
Trade accounts receivable (a)	7		3,819,680	3,819,680	3,182,567	3,182,567
CRC Transferred to the Paraná State Government (h)	8		1,392,624	1,496,016	1,350,685	1,488,456
Sectorial financial assets (a)	9		346,930	346,930	473,989	473,989
Accounts receivable - concessions - bonus from
the grant (i)	10.3		671,204	763,070	647,984	738,483
			6,364,156	6,539,370	5,753,805	5,978,313
Total financial assets			11,853,814	12,029,028	10,696,367	10,920,875
Financial liabilities
Fair value through profit or loss
Fair value in the purchase and sale of power (e)	28	3	343,406	343,406	251,973	251,973
Derivatives fair value - forward contracts (e)	28	3	-	-	1,203	1,203
			343,406	343,406	253,176	253,176
Amortized cost
Sectorial financial liabilities (a)	9		188,709	188,709	102,284	102,284
Ordinary financing of taxes with the federal tax authorities (g)	13.2		-	-	18,063	18,001
Special Tax Regularization Program - Pert (g)	13.2		459,303	377,375	497,207	439,519
PIS and Cofins to be refunded to consumers (a)	13.2.1		3,927,823	3,927,823	-	-
Accounts payable to suppliers (a)	20		2,436,452	2,436,452	1,873,193	1,873,193
Loans and financing (g)	21		3,214,249	2,956,696	3,168,710	3,110,104
Debentures (j)	22		6,837,819	6,837,819	8,540,366	8,540,366
Accounts payable related to concession (k)	26		731,864	811,329	612,587	690,326
			17,796,219	17,536,203	14,812,410	14,773,793
Total financial liabilities			18,139,625	17,879,609	15,065,586	15,026,969
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 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 IPCA + Spread de 4.8165%, 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 3.09% 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, 2020, obtained from the Brazilian Association of Financial and Capital Markets (ANBIMA), net of unamortized financial cost.

k)	Actual net discount rate of 8.64% 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	12.31.2020	12.31.2019 Restated
Cash and cash equivalents (a)	3,222,768	2,941,727
Bonds and securities (a)	300,530	282,081
Pledges and restricted deposits linked (a)	133,718	98,580
Trade accounts receivable (b)	3,819,680	3,182,567
CRC Transferred to the Paraná State Government (c)	1,392,624	1,350,685
Sectorial financial assets (d)	346,930	473,989
Accounts receivable - distribution concession (e)	1,149,934	1,161,203
Accounts receivable - concessions - Bonus from the grant (f)	671,204	647,984
Accounts receivable - generation concessions (g)	81,202	69,182
Other temporary investments (h)	22,385	27,734
	11,140,975	10,235,732

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.

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)	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 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.

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.

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.

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
12.31.2020
Loans and financing	Note 21	29,274	197,056	669,153	1,570,564	1,868,504	4,334,551
Debentures	Note 22	335,121	47,686	1,723,107	4,953,679	1,020,581	8,080,174
Accounts payable related	Rate of return +
to concession	IGP-M and IPCA	7,220	14,444	68,504	429,573	1,570,984	2,090,725
Accounts payable to suppliers	-	2,034,872	309,329	26,248	66,003	-	2,436,452
PIS and Cofins to be refunded
to consumers	-	-	-	121,838	3,805,985	-	3,927,823
Special Tax Regularization Program - Pert	Selic	4,220	8,456	38,426	225,206	270,982	547,290
Sectorial financial liabilities	Selic	15,752	31,585	143,906	-	-	191,243
		2,426,459	608,556	2,791,182	11,051,010	4,731,051	21,608,258
(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 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 held as of December 31, 2020, 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$/US$ 5.15) based on the median market expectation for 2021 according to the Focus Report issued by the Central Bank of Brazil. 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 - Dec.2020
Foreign exchange risk	Risk	12.31.2020	Probable	Scenario 1	Scenario 2
.
Financial assets
Collaterals and escrow accounts - STN	USD depreciation	133,521	(1,200)	(34,280)	(67,360)
.		133,521	(1,200)	(34,280)	(67,360)
Financial liabilities
Loans and financing - STN	USD appreciation	(140,337)	1,261	(33,508)	(68,277)
Suppliers
Eletrobras (Itaipu)	USD appreciation	(288,640)	2,594	(68,918)	(140,429)
Acquisition of gas	USD appreciation	(38,574)	347	(9,210)	(18,767)

		(467,551)	4,202	(111,636)	(227,473)

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 15,5 million euros outstanding as of December 30, 2020, 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 active balance, recorded as of December 30, 2020, is shown in Note 12. The liability balance, as of December 31, 2019, is presented 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 (€).

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 future currency quotations (B3 reference rates on February 26, 2021) were considered and adjusted to present value by the pre-tax rate at same date. Additionally, the Company continues to monitor scenarios 1 and 2, which consider the 25% and 50% rise or fall in future quotes applied on the probable scenario, as a result of extraordinary events that may affect the economic scenario.

	Exchange	Baseline	Projected scenarios
	rate variation	12.31.2020	Probable	Scenario 1	Scenario 2

Gains (losses) on operations with derivative financial instruments	Increase	23,308	29,230	56,504	83,186

	Decrease	23,308	29,230	3,140	(23,541)

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 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 baseline scenario takes into account the existing balances in each account as of December 31, 2019 2020 on the date of these financial statements and the probable scenario assumes balances reflecting varying indicators CDI/Selic – 4.00%, IPCA – 3.98%, IGP-DI – 6.85%, IGP-M - 8,98% and TJLP – 4.98%, estimated as market average projections for 2021 according to the Focus Report issued by the Central Bank of Brazil, 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, as a result of extraordinary events that may affect the economic scenario.

.		Baseline	Projected scenarios - Dec.2020
Interest rate risk and monetary variation	Risk	12.31.2020	Probable	Scenario 1	Scenario 2
Financial assets
Bonds and securities	Low CDI/SELIC	300,530	12,023	9,014	6,011
Collaterals and escrow accounts	Low CDI/SELIC	197	8	6	4
CRC Transferred to the Paraná State Government	Low IGP-DI	1,392,624	95,395	71,546	47,697
Sectorial financial assets	Low Selic	346,930	13,877	10,408	6,939
Accounts receivable - concessions	Low IPCA	1,821,138	72,481	54,361	36,241
Accounts receivable - generation concessions	Undefined (a)	81,202	-	-	-
		3,942,621	193,784	145,335	96,892
Financial liabilities
Loans and financing
Banco do Brasil	High CDI	(640,177)	(25,607)	(32,009)	(38,411)
BNDES	High TJLP	(2,027,581)	(100,974)	(126,217)	(151,460)
BNDES	High IPCA	(273,379)	(10,880)	(13,601)	(16,321)
Banco do Brasil - BNDES Transfer	High TJLP	(83,936)	(4,180)	(5,225)	(6,270)
Caixa Econômica Federal	High TJLP	(165)	(8)	(10)	(12)
Other	No risk	(48,674)	-	-	-
Debentures	High CDI/SELIC	(5,174,803)	(206,992)	(258,740)	(310,488)
Debentures	High IPCA	(1,550,339)	(61,703)	(77,129)	(92,555)
Debentures	High TJLP	(112,677)	(5,611)	(7,014)	(8,417)
Sectorial financial liabilities	High Selic	(188,709)	(7,548)	(9,435)	(11,323)
Special Tax Regularization Program - Pert	High Selic	(459,303)	(18,372)	(22,965)	(27,558)
Accounts payable related to concession	High IGP-M	(678,436)	(60,924)	(76,154)	(91,385)
Accounts payable related to concession	High IPCA	(53,428)	(2,126)	(2,658)	(3,190)
.		(11,291,607)	(504,925)	(631,157)	(757,390)
(a) Risk assessment still requires ruling by the Granting Authority.

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. In the first quarter of 2020, the reservoirs in the Northeast and North recovered their levels, which practically reduces the risk of rationing in these subsystems to zero. As the system is interconnected, the South and Southeast/Midwest subsystems, despite being at lower storage levels, results in having a low risk of energy shortage since they can make use of the energy stored in the other two subsystems.

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 2020-2024 Energy Operation Plan - PEN 2020.

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, in Portuguese) (maximum risk of 5%) in all subsystems.

35.2.5

Risk 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, 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

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 of September 8, 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.

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, 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 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 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 October 2022, and the Guaricana and Chaminé HPPs until August, 2023. 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	Concession termination
		end of the 5-year period (2020)
	Quality Indicators	2 consecutive years or	Limitation of dividend and interest on equity distribution
		3 times in 5 years
	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 6^th 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 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)	822,386	10.12	7.74	9,10	6,00
2020	{Net Debt / [EBITDA (-) QRR]} ≤ 1 / (1.11 * SELIC) ^(e)		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.y.

35.2.8

Risk of non-extension of the gas distribution concession

In the event of termination of the concession at the end of the contractual term, 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.

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, in 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 to the contracting of, 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 and load reduction by the Covid-19 pandemic, it is considered that the Company maintains the guarantee of neutrality preserved, since this factors are 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, at the moment, 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 2023 and will make a new 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, 2020, the consolidated balance recorded in liabilities referring to the non-performance is demonstrated in note 28.

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, 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$ 6,065,065 for purchase contracts and R$ 6,634,477 for electricity sales contracts open on December 31, 2020 , the fair value was estimated using the prices defined internally by the Company in the last week of December 2020, 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, 2020, adjusted for credit risk and additional project risk.

The balances referring to these outstanding transactions as of December 31, 2020 are shown below.

	Assets	Liabilities	Net
Current	51,359	(35,298)	16,061
Noncurrent	638,172	(308,108)	330,064
	689,531	(343,406)	346,125

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 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	12.31.2020	Probable	Scenario 1	Scenario 2
Unrealized gains (losses) on purchase and sale of energy	Increase	346,125	332,741	356,496	380,117
Unrealized gains (losses) on purchase and sale of energy	Decrease	346,125	332,741	309,255	285,635

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, 2020, the ratio attained is shown below:


	12.31.2020	12.31.2019
Loans and financing	3,188,531	3,142,383
Debentures	6,757,481	8,429,710
(-) Cash and cash equivalents	(3,222,768)	(2,941,727)
(-) Bonds and securities (current)	(1,465)	(3,112)
(-) Bonds and securities (noncurrent) - debt contract guarantees	(175,901)	(121,617)
(-) Collaterals and escrow accounts STN	(133,521)	(98,433)
Adjusted net debt	6,412,357	8,407,204
Net income	3,834,172	2,062,869
Equity in earnings of investees	(193,547)	(106,757)
Deferred IRPJ and CSLL	24,896	205,771
Provision for IRPJ and CSLL	1,260,469	433,555
Financial expenses (income), net	(866,271)	488,486
Depreciation and amortization	1,009,913	1,093,836
Adjusted ebitda	5,069,632	4,177,760
Adjusted net debt/Adjusted ebitda	1.26	2.01

35.3.1

The debt to equity ratio is shown below:


Indebtedness	12.31.2020	12.31.2019
Loans and financing	3,214,249	3,168,710
Debentures	6,837,819	8,540,366
(-) Cash and cash equivalents	3,222,768	2,941,727
(-) Bonds and securities	300,530	282,081
Net debt	6,528,770	8,485,268
Equity	20,250,518	17,598,212
Debit to equity ratio	0.32	0.48