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35. Financial Instruments

12 Months Ended

Dec. 31, 2018

35.1 Categories and determination of fair value of financial instruments


				12.31.2018	12.31.2017
	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	1,948,409	1,948,409	1,040,075	1,040,075
Bonds and securities (b)	6	1	696	696	687	687
Bonds and securities (b)	6	2	343,600	343,600	218,976	218,976
Accounts receivable related to the distribution concession (c)	10.1 e 10.2	3	1,105,282	1,105,282	987,874	987,874
Accounts receivable related to the transmission concession (c)	10.4	1	-	-	99,969	99,969
Accounts receivable related to the concession compensation (d)	10.6	3	65,811	65,811	68,859	68,859
Other temporary investments (e)		1	11,557	11,557	8,958	8,958
Other temporary investments (e)		2	7,954	7,954	9,769	9,769
			3,483,309	3,483,309	2,435,167	2,435,167
Amortized cost
Pledges and restricted deposits linked (a)		1	203	203	59,372	59,372
Collaterals and escrow accounts STN (f)	22.1	2	89,555	76,524	75,665	57,188
Trade accounts receivable (a)	7	1	3,107,006	3,107,006	2,994,322	2,994,322
CRC Transferred to the State Government of Paraná (g)	8	2	1,445,042	1,546,469	1,516,362	1,620,212
Sectorial financial assets (a)	9	1	678,819	678,819	343,218	343,218
Accounts receivable related to the transmission concession (c)	10.4	1	-	-	1,397,430	1,397,430
Accounts receivable related to the concession - RBSE (c)	10.5	1	753,826	753,826	1,418,370	1,418,370
Accounts receivable related to the concession - bonus from the grant (h)	10.3	2	625,772	714,880	606,479	694,463
State of Paraná - Government Programs (a)	15.1	1	-	-	130,417	130,417
			6,700,223	6,877,727	8,541,635	8,714,992
Total financial assets			10,183,532	10,361,036	10,976,802	11,150,159
Financial liabilities
Amortized cost
Sectorial financial liabilities (a)	9	1	96,531	96,531	283,519	283,519
Ordinary financing of taxes with the federal tax authorities (f)	13.3	2	86,632	84,383	148,845	142,702
Special Tax Regularization Program - Pert (f)	13.3	2	518,442	469,304	533,671	431,036
Suppliers (a)	21	1	1,469,199	1,469,199	1,727,046	1,727,046
Loans and financing (f)	22	2	4,047,307	4,012,621	3,759,505	3,569,856
Debentures (i)	23	1	7,518,131	7,518,133	6,070,978	6,070,978
Payable related to concession (j)	27	3	584,163	687,869	554,954	645,904
Total financial liabilities			14,320,405	14,338,040	13,078,518	12,871,041
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.

The financial instruments classification changes, as of the adoption of IFRS 9, on 01.01.2018, is described in Note 4.17.1

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.
d)	The fair values of generation assets approximate their carrying amounts, according to Note 4.4.
e)	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 last borrowing taken out by the Company is used as a basic assumption, namely TJLP plus spread of 1.94% p.a., for discount of the expected payment flows.
g)	The Company based its calculation on the comparison with a long-term and post-fixed National Treasury Bond (NTN-B) maturing on August 15, 2024, which yields approximately 4.29% p.a. plus the IPCA inflation index.
h)	Receivables related to the concession agreement for providing electricity generation services under quota arrangements at their fair value calculated by expected cash inflows discounted at the rate established in ANEEL auction notice 12/2015 (9.04%).
i)	Calculated from the Unit Price quotation (PU) for December 31, 2018, obtained from the Brazilian Association of Financial and Capital Markets (ANBIMA), net of unamortized financial cost.
j)	Actual net discount rate of 8.13% 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 financial instrument counterparty, resulting from failure in complying with contractual obligations.


Exposure to credit risk	12.31.2018	12.31.2017
Cash and cash equivalents (a)	1,948,409	1,040,075
Bonds and securities (a)	344,296	219,663
Pledges and restricted deposits linked (a)	89,758	135,037
Trade accounts receivable (b)	3,107,006	2,994,322
CRC Transferred to the State Government of Paraná (c)	1,445,042	1,516,362
Sectorial financial assets (d)	678,819	343,218
Accounts receivable related to the concession (e)	1,859,108	3,903,643
Accounts receivable related to the concession - Bonus from the grant (f)	625,772	606,479
Accounts receivable related to the concession compensation (g)	65,811	68,859
State of Paraná - Government Programs	-	130,417
Loans - related parties	-	38,169
Other temporary investments (h)	19,511	18,727
	10,183,532	11,014,971

a)	The Company’s Management manages the credit risk of its assets in accordance with the Group'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 closely related to internal and external factors of 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 the agreement.
c)	Management believes this credit risk is low because repayments are secured by funds from dividends.

d)	Management believes this risk is low because these contracts assure an unconditional right to be paid in cash by the concession Grantor at the end of the concession period for any infrastructure investments not recovered through tariffs.
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.
	Management also 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 10.5.
f)	Management considers the risk of this credit to be low, as the contract for the sale of energy by quota guarantees the receipt of an Annual Generation Revenue - RAG guaranteed which includes the annual amortization of this amount during the concession term.
g)	For the generation concession assets, ANEEL published Normative Resolution No. 596/2013, which deals with the definition of criteria for calculating the VNR, for the purposes of indemnification. Management's expectation regarding the indemnification of these assets indicates the recoverability of the balances recorded, as described in Note 10.6.

h)	The 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 the following year. As from 2022, 2021 indicators are repeated on an unaltered basis throughout the forecast period.


	Interest (a)	Less than	1 to 3	3 months		Over	Total
		1 month	months	to 1 year	1 to 5 years	5 years	liabilities
12.31.2018
Loans and financing	Note 22	213,934	178,471	990,005	2,051,613	1,846,702	5,280,725
Debentures	Note 23	74,834	62,755	2,473,208	6,317,116	550,901	9,478,814
Payable related to concession	Rate of return +
use of public property	IGP-M and IPCA	5,924	11,825	53,605	312,422	1,347,527	1,731,303
Suppliers	-	1,058,074	211,709	145,317	28,986	25,113	1,469,199
Ordinary financing of taxes
with the federal tax authorities	Selic	5,796	11,660	53,634	18,293	-	89,383
Special Tax Regularization Program - Pert	Selic	3,916	7,889	36,498	223,421	440,857	712,581
Sectorial financial liabilities	Selic	-	-	-	106,796	-	106,796
		1,362,478	484,309	3,752,267	9,058,647	4,211,100	18,868,801
(a) Effective interest rate - weighted average.

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

As at December 31, 2018, the Company recorded negative net working capital of R$ 17,268 (R$ 408,080 in 2017). Management has been monitoring the liquidity and taking actions to balance the short-term financial capacity, preserving the Company's investment programs, as well as seeking debt repayment extension.

35.2.3 Market risk

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

a) Foreign currency risk (US Dollar)

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

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

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

The exchange rate risk posed by the purchase of gas arises from the possibility of Compagas reporting losses on the fluctuations in foreign exchange rates, increasing the amount in Reais of the accounts payable related to the gas acquired from Petrobras. This risk is mitigated by the monitoring and transfer of the price fluctuation through tariff, when possible. Compagás 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 U.S. dollar on its borrowings subject to currency risk.

The baseline scenario takes into account the existing balances in each account as of December 31, 2018 and the probable scenario assumes a variation in the foreign exchange rate – prevailing at the end of the period (R$/USD 3.70) based on the median market expectation for 2019 reported in the Central Bank’s Focus report of February 8, 2019. 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.2019
Foreign exchange risk	Risk	12.31.2018	Probable	Scenario 1	Scenario 2
.
Financial assets
Collaterals and escrow accounts - STN	USD depreciation	89,555	(4,040)	(25,419)	(46,798)
.		89,555	(4,040)	(25,419)	(46,798)
Financial liabilities
Loans and financing - STN	USD appreciation	(104,751)	4,726	(20,281)	(45,287)
Suppliers
Eletrobras (Itaipu)	USD appreciation	(145,098)	6,546	(28,092)	(62,731)
Acquisition of gas	USD appreciation	(66,808)	3,014	(12,935)	(28,883)
		(316,657)	14,286	(61,308)	(136,901)

In addition to the sensitivity analysis required by CVM Resolution No. 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, 2018, 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) 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 engaged in transactions with derivatives to cover this risk, but it has continually monitored interest rates and market indicators, in order to assess the potential need for such transactions.

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, 2018 while the ‘probable’ scenario assumes balances reflecting varying indicators as follows: CDI/Selic - 6.50%, IPCA - 3.87%, IGP-DI - 4.04%, IGP-M - 3.90% and TLP - 6.50%, estimated as market average projections for 2019 according to the Focus Report issued by the Central Bank of Brazil as of February 8, 2019, except TLP 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.2019
Interest rate risk and monetary variation	Risk	12.31.2018	Probable	Scenario 1	Scenario 2
Financial assets
Bonds and securities	Low CDI/SELIC	344,296	24,100	18,075	12,052
Collaterals and escrow accounts	Low CDI/SELIC	203	13	10	7
CRC transferred to the State Government of Paraná	Low IGP-DI	1,445,042	58,380	43,785	29,190
Sectorial financial assets	Low Selic	678,819	44,123	33,092	22,062
Accounts receivable related to the concession	Low IPCA	2,484,880	96,165	72,124	48,082
Accounts receivable related to the concession compensation	Undefined (a)	65,811	-	-	-
		5,019,051	222,781	167,086	111,393
Financial liabilities
Loans and financing
Banco do Brasil	High CDI	(838,657)	(54,513)	(68,141)	(81,769)
BNDES	High TJLP	(2,137,966)	(138,968)	(173,710)	(208,452)
BNDES	High IPCA	(11,992)	(464)	(580)	(696)
Promissory notes	High CDI	(571,822)	(37,168)	(46,461)	(55,753)
Banco do Brasil - Distribution of Funds from BNDES	High TJLP	(107,324)	(6,976)	(8,720)	(10,464)
Caixa Econômica Federal	High TJLP	(496)	(32)	(40)	(48)
Other	No risk	(274,299)	-	-	-
Debentures	High CDI/SELIC	(6,535,759)	(424,824)	(531,030)	(637,237)
Debentures	High IPCA	(845,156)	(32,708)	(40,884)	(49,061)
Debentures	High TJLP	(137,216)	(8,919)	(11,149)	(13,378)
Suppliers - renegotiation of gas	High IGP-M	(28,670)	(1,118)	(1,398)	(1,677)
Sectorial financial liabilities	High Selic	(96,531)	(6,275)	(7,843)	(9,412)
Ordinary financing of taxes with the federal tax authorities	High Selic	(86,632)	(5,631)	(7,039)	(8,447)
Special Tax Regularization Program - Pert	High Selic	(518,442)	(33,699)	(42,123)	(50,548)
Payable related to concession	High IGP-M	(536,131)	(20,909)	(26,136)	(31,364)
Payable related to concession	High IPCA	(48,032)	(1,859)	(2,324)	(2,788)
.		(12,775,125)	(774,063)	(967,578)	(1,161,094)
(a) Risk assessment still requires ruling by the Granting Authority.

In addition to the sensitivity analysis required by CVM Resolution No. 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 9 - Financial Instruments: Disclosures. Based on the equity position and the notional value of the financial instruments held as of December 31, 2018, 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 hydrological conditions that are unpredictable, 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 2018-2022 Energy Operation Plan.

Although dam storage levels are not ideal, from the standpoint of regulatory agencies, when combined with other variables, they are sufficient to keep the risk of deficit within the safety margin established by the National Energy Policy Council - CNPE (maximum risk of 5%) in all subsystems.

35.2.5 Risk of 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, of the need for a centralized operation associated with a centrally calculated optimum 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 - 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 Cavernoso II Thermoelectric Plants.

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. 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

Decree 9,187 of November 1, 2017 regulates the extension of the thermoelectric power generation concessions set forth in Law 12,783/2013. Currently, there are two bills in progress that intend to reduce the deadline to file for intention to extend from 60 to 36 months and to terminate the possibility of extending the physical guarantee quotas regime established by said law.

By 2023, two generation plants will have their concessions overdue: the Usina Termelétrica de Figueira – UTE Figueira (20 MW) in March 2019 and the Governor Bento Munhoz hydroelectric power plant at Rocha Netto-GBM plant (1676 MW), in September 2023.

Regarding the HPP Figueira concession, the Company awaits a manifestation of the Concession Grantor regarding the request for extension of this Concession, required in March 2017. 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.

Regarding the HPP GBM, the Company did not express an interest in extending this concession. Under Law 12,783/2013, the option for extension is conditioned to a change in the plant operation regime, which may occur within 60 months before its final term. Internal studies indicated that the extension through change of the anticipated operation regime is economically and financially disadvantageous in relation to the exploration of the plant in the present regime until its final term. The plant must be tendered by the Concession Grantor and the Company may participate in the auction, if it meets the qualification conditions.

According to the law, the Company may express its intention to extend the concession of the São Jorge HPP in 2019, 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, the concession of the São Jorge HPP may, at its final term, be granted to the Company in the condition of registration, and the other concessions, at their final term, shall be tendered by the Concession Grantor.

Copel GeT does not have any transmission concession ending in the next ten years.

35.2.7 Risk of non-renewal of concessions - distribution of electricity

On December 9, 2015, pursuant to the Concession Agreement Amendment No. 46/1999 of Copel DIS, the concession was extended, provided that quality and efficiency parameters for provision of distribution services are met, measured by indicators that consider duration and frequency of service interruptions (DECi and FECi) and efficiency in the Company’s economic and financial management.

The fifth amendment to the concession agreement imposes indexes of economic and financial efficiency and quality. Failure to comply with the indexes for two consecutive years or any limits at the end of the first five years will result in the termination of the concession (clause 18, sub clause 1), observing the agreement terms, specifically the right to full defense and reconsideration.

Non-compliance with the global electricity supply quality indicators (DEC and FEC) for two consecutive years or three times in five years, depending on ANEEL’s regulation, may limit the payment of dividends or interest on capital (clause 2, sub clause 8), while the breach of the economic and financial sustainability indicators may require a capital contribution from the controlling shareholders (clause 13, sub clause 4).

From the sixth year following the signing of the agreement, the breach of quality criteria for three consecutive years or of economic and financial management criteria for two consecutive years will result in the opening of an expiration process (clause 12, sub clause 14), causing the end of the concession.

The following table sets forth the minimum parameters of economic and financial sustainability defined for Copel DIS in the first five years of the renewal:


			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 ^(d)	661.4	12.54	8.74	10.41	6.79
2018	EBITDA (-) QRR ≥ 0 ^{(e) (f)}		11.23	8.24	10,29 (c)	6,20 (c)
2019	{Net Debt / [EBITDA (-) QRR]} ≤ 1 / (0.8 * SELIC) ^{(e) (g)}		10.12	7.74	-	-
2020	{Net Debt / [EBITDA (-) QRR]} ≤ 1 / (1.11 * SELIC) ^{(e) (g)}		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) Preliminary data.
(d) Regulatory EBTIDA adjusted for non-recurring events (PDV, post-employment benefit, provisions and reversals) according to clause six, of the Fifth Amendment to the Concession Agreement.
(e) QRR: Regulatory Reintegration Quota or Regulatory Depreciation Expense. This is the value defined in the most recent Periodical Tariff Review (RTP), plus IPCA between the month preceding the RTP and the month preceding the twelve-month period of the economic and financial sustainability measurement.
(f) Data will be disclosed in Copel DIS's Regulatory Financial Statements.
(g) Selic: limited to 12.87% p.y.

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 No. 10,484/2014 and Decree No. 5,163/2004, which determine that distributors must purchase the volume required to serve 100% of their market.

The contracting of the total output available in the market is verified by observing the period comprising the calendar year, and 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, among which we can highlight:

• Normative Resolution No. 700/2016, which regulated the recognition of involuntary overcontracting arising from the reallocation of assured power quota of plants renewed pursuant Law 12,783/2013;

• Normative Resolution No. 693/2015, which regulated the New Energy and Decrease Clearing Facility (“Mecanismo de Compensação de Sobras e Déficits - MCSD-EN”), for the contracts arising from new generation projects, which permits reallocation of energy between distributors and generators;

• Normative Resolution No. 711/2016, which established criteria and conditions for bilateral agreements between distributors and generators, under the modalities of temporary total or partial reduction in the contracted power, permanent partial reduction, and also of contractual termination.

• Decree 9,143/2017 was published, which, among other measures, changes Decree 5,163/2014, recognizing: i) the involuntary contractual exposures arising from the migration of special consumers to the free market, provided that the evaluation of the maximum effort by distributors is considered by ANEEL; and ii) the contractual right to the reduction of existing power auctions, by the amounts related to the migration of special consumers to the free market. Eligible contracts are those arising from power auctions held after June 2016, pursuant to Normative Resolution No. 726/2016;

• Normative Resolution No. 824/2018, which established criteria for the processing of the Mechanism for Sale of Energy Surplus.

In relation to the contracting of 2018, preliminary, still in 2017, and throughout 2018, Copel Distribuição's indicators often indicated overcontracting scenarios. During this period, the monitoring of indicators of contracting levels prevailed, and mitigating actions were required.

All tools available were used to manage the power contracting by distributors, seeking to meet the requirement of endeavoring to adjust its contracting level to regulatory limits. In this context, we can highlight the following actions by the Company:

a) It reported surpluses of New Energy and Free Power Exchanges, under the Mechanism for Compensation of Power Surpluses and Deficits (MCSD), related to exceeding amounts of energy of physical guarantee quotas and of which the contracting by special consumers has been cancelled (disengaged);

b) It fully returned under the MCSD mechanism, the maximum variation of 4% in the contracted amounts of existing electricity;

c) It fully returned, under the monthly MCSD mechanism, the available amounts of energy existing in Distributor's portfolio, related to the disengaging of potentially free consumers; and

d) It established agreements with generators for the reduction of contracts, entering into bilateral agreements in accordance with Normative Resolution No. 711/2016;

According to the most up-to-date market data, Copel Distribuição closed 2018 year within the regulatory limits of 100% to 105% contracting, thus ensuring the neutrality of the costs associated with the energy purchase.

35.2.10 Gas shortage risk

This risk involves potential periods of shortage of natural gas supply to meet the Company’s gas distribution and thermal generation business requirements.

Long periods of gas shortage could result in losses due to lower revenues by subsidiaries Compagas and UEG Araucária.

The natural gas supply contract between Brazil and Bolivia is effective for twenty years, ending in 2019. Due to the non-use of all contracted natural gas in recent years, the Ministry of Mines and Energy considers the extension of the term of this contract by two years in its Ten Year Planning. In the event of non-renewal of this contract, currently centralized in Petrobras, direct consumers or state distributors must directly negotiate the fuel supply with producers, importers or suppliers of natural gas.

On the other hand, the volume of natural gas produced in the pre-salt has increased. The Brazilian’s current net output is 67 million m³/day and with growing trend.

In addition to the gas from Bolivia and from the pre-salt, there is the alternative of importing the Liquified Natural Gas (LNG). Currently, Petrobras has tree regasification stations with total capacity of 41 million m³/day.

There are also projects of new regasification stations in all Brazilian regions, with stations located in the South region of Brazil capable of serving the consumption of this region of the country without the need for large investments in transport infrastructure and reducing the level of capacity utilization of the Gasbol Sul line, which would increase the supply of natural gas in Paraná.

In the international market, the natural gas price has remained stable, indicating a balance between supply and demand.

In this scenario, the natural gas shortage risk can be considered low.

35.2.11 Risk of non-performance of wind farms

The power generation authorization 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, and non-compliance with what is stated in the agreement may jeopardize future revenues of the Company.

35.2.12 Risk related to price of power purchase and sale transactions in the active market

The Company operates in the market for the purchase and sale of energy in the active market (NE nº 4.15), with the objective of achieving results with changes in energy prices, subject to the risk limits established by Management. This activity, therefore, exposes the Company to the risk of future energy price.

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

Based on the notional value of R$ 222,928 for purchase contracts and R$ 95,382 for contracts for the sale of electricity, outstanding on December 31 of 2018, the fair value was estimated using the prices defined by the Company in the last week of December 2018, which represented the best estimate of the future market price. The discount rate uses the return rate of the NTN-B disclosed by ANBIMA as of December 31, 2018, adjusted by a credit risk rate.

The balances relating to these outstanding transactions at December 31, 2018 are presented below.


	12.31.2018
	Assets	Liabilities	Net
Current	10,748	(6,991)	3,757
Noncurrent	4,045	(4,016)	29
	14,793	(11,007)	3,786

Sensitivity analysis on the power purchase and sale transactions in the active market

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, especially in view of the short-term for the settlement of contracts.

The sensitivity analyses were prepared in accordance with CVM Instruction 475/08, considering, for scenarios 1 and 2, the increase or decrease of 25% and 50% in future prices, applied to market prices of December 31, 2018. The results obtained are as follows:


	Price	Baseline	Projected scenarios
	variation	31.12.2018	Scenario 1	Scenario 2

Gains (losses) on purchase and sale of energy in active market	Elevation	3,786	31,356	58,926

	Reduction	3,786	(23,784)	(51,354)

35.3 Capital management

The Company seeks to maintain 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 goal established in the strategic planning 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, 2018, the ratio attained is shown below:


	12.31.2018	12.31.2017
Loans and financing	4,047,307	3,759,505
Debentures	7,518,131	6,070,978
(-) Cash and cash equivalents	(1,948,409)	(1,040,075)
(-) Bonds and securities (current)	(124,862)	(1,341)
(-) Bonds and securities (noncurrent)	(119,574)	(112,604)
(-) Collaterals and escrow accounts STN	(89,555)	(75,665)
Adjusted net debt	9,283,038	8,600,798
Net income	1,444,004	1,118,255
Equity in earnings of investees	(135,888)	(101,739)
Deferred IRPJ and CSLL	(68,072)	(105,257)
Provision for IRPJ and CSLL	580,065	379,943
Financial expenses (income), net	438,050	748,440
Depreciation and amortization	749,179	731,599
Adjusted ebitda	3,007,338	2,771,241
Adjusted net debt / Adjusted ebitda	3.09	3.10

35.3.1 The equity to debt ratio is shown below:


Indebtedness	12.31.2018	12.31.2017
Loans and financing	4,047,307	3,759,505
Debentures	7,518,131	6,070,978
(-) Cash and cash equivalents	1,948,409	1,040,075
(-) Bonds and securities (current)	124,862	1,341
Net debt	9,492,167	8,789,067
Equity	16,336,214	15,510,503
Equity indebtedness	0.58	0.57