ceronfinal2.htm - Generated by SEC Publisher for SEC Filing

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Banco Nacional de Desenvolvimento
Econômico e Social - BNDES (“BNDES”)
Av. República do Chile, 100
Rio de Janeiro - RJ

August 10, 2017

Dear Sirs:

As per BNDES’s request, and, in accordance with the provisions of Electronic Auction AARH N. 51/2016, Contract OCS no. 028/2017 (“Contract”), dated February 14, 2017, and with the provisions of Article 80 of Law no. 13303/2016, we prepared this summary, in which we present the main findings identified during our accounting due diligence procedures on Centrais Elétricas de Rondônia S/A – CERON.

Our services were limited to the procedures described in item 4.2.3 of Exhibit I to the aforementioned Contract. Accordingly, this summary does not include all matters identified and presented in the due diligence report dated May 5, 2017, and must be read jointly with the whole report in order to provide a comprehensive understanding of the matters identified.

Our works were performed according to the guidelines applicable to advisory services in transactions, as set forth in IBRACON Technical Announcement no. 08/2012. Considering that the scope of our works was not a limited analysis or review performed in accordance with the audit standards, an analysis of internal controls, or any other certification work or other previously agreed proceeding, we do not issue an opinion or any kind of assurance about the Company’s financial statements, about any other information, or about the design or the effectiveness of the Company’s operational and internal controls systems.

Our work was conducted based on information provided by the Company’s management and based on the assumption that the information is true and complete. The information was not subject to tests or verifications, except when expressly defined in the scope of our works.

PricewaterhouseCoopers
Av. Francisco Matarazzo, 1400
Torre Torino - Água Branca
São Paulo - SP – Brazil
Ph: +55 (11) 3674-2000


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Banco Nacional de Desenvolvimento
Econômico e Social - BNDES (“BNDES”)
Av. República do Chile, 100
Rio de Janeiro - RJ

We take no responsibility for the nature, extent, sufficiency, or fitness of the procedures followed by us, whether for the purposes for which this summary was requested or for any other purpose. The sufficiency of the procedures followed by us shall be BNDES’s sole responsibility, as well as any decision related to the proposed transaction. Had we been requested to conduct additional procedures, other issues could have been detected and reported to you.

Sincerely,


		[signed]	[signed]
		PricewaterhouseCoopers	Christian Silva Gambôa
		Corporate Finance & Recovery Ltda.	Accountant CRC 1SP234223/O-4
		CRC 2SP022749/O-7

This document is a true copy of the original signed version delivered to BNDES and in the possession of Eletrobras.

PricewaterhouseCoopers
Av. Francisco Matarazzo, 1400
Torre Torino - Água Branca
São Paulo - SP – Brazil
Ph: +55 (11) 3674-2000


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Summary of the main points of attention (1/2)

The content below presents the main points of attention identified during the accounting due diligence procedures. Accordingly, it does not include all matters identified and discussed in the due diligence report, and, therefore, must be read jointly with the whole report in

order to provide a comprehensive understanding of the matters identified.

1 Financial position

The Company has been ascertaining recurring losses (R$ 835.2 million in 2016 and R$ 560.8 million in 2015), reaching an accumulated loss of R$ 2,617.1 million as of Dec-16 and a net shareholders' equity of R$ 1,295.9 million.

In addition, we identified an adjusted net indebtedness (after our adjustments and reclassifications) as of Dec-16 of R$ 2.6 billion and negative adjusted EBITDA for 2016 of R$ 224.8 million.

According to the management, the main reasons for the Company’s current financial situation are:

Significant value of assets in service not yet included in the “armored” basis [base blindada], resulting in a tariff below the one necessary to cover the operating costs;
Delay in the receipt of subsidies (CCC, CDE, CVA, among others);
High level of client default and technical and operating losses;
Late payment to suppliers and other liabilities (as a consequence of the items above), generating cash unbalance and increase in expenses with financial charges and arrears penalties.

We should stress that the Company’s current financial position, associated with the tariff gap (e.g., significant volume of assets in service not yet included in the “armored” basis), with the investment level during the period of provision of the services, among other factors, may result in additional risks for the Company, mainly in the last fiscal years. We understand that those factors may impair the obtainment of an EBITDA on a recurring and normalized basis, making it more difficult, therefore, to compare the historical periods.

2 Impairment/onerous contract

The concessions of the Eletrobras distribution companies expired in 2015. Although Decree no. 8461, of June 2, 2015, provides for the extension of the electric energy distribution concessions, on June 22, 2016, the 165^thExtraordinary General Shareholders’ Meeting of Eletrobras decided not to extend the concessions of its controlled companies of power distribution.

Accordingly, the Company started to operate as a public utility Company, on a temporary basis, until the earlier of the assumption by a new concessionaire or December 31, 2017.

As a consequence, considering that the Company has power purchase agreements in force for periods going beyond December 31, 2017, a provision for impairment of the fixed assets was registered in 2016, in the amount of R$ 35.2 million, as well as an additional provision for onerous contract in the amount of R$ 191.3 million.

In the management’s view, after conclusion of the privatization process, associated with a program to bring back the company’s financial health, those provisions may be reversed, not necessarily generating a future cash expenditure.


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Summary of the main points of attention (2/2)

order to provide a comprehensive understanding of the matters identified.

3 Lawsuit against all distribution companies

A public civil action was filed by the National Consumers Association –ANDECO against all Electric Energy Concessionaires in the country with respect to prevention and remediation of collective damages against consumers, with a request for preliminary injunction in order for the companies to refrain from charging the claimed losses from the consumers in the electricity bills, including pro rata, as well as the losses sustained due to billing or measurement errors, theft, and fraud in the period from 2010 to 2014. ANDECO also pursues the annulment of all ANEEL Resolutions that allow the collection and inclusion in the bills of sums related to non-technical and technical losses. The value of the matter is R$ 27 billion, but the amount charged from Centrais Elétricas de Rondônia S.A is R$ 2.5 billion.

The plaintiff maintains that, notwithstanding ANEEL’s authorization, the prorated billing of non-technical losses (fraud, theft, measurement and billing errors, and supply without measurement) is groundless and, therefore, the distribution companies must indemnify the regular consumers in twice as much (double indemnification provided for in the law) the amounts charged in the period from 2010 to 2014, according to their respective balance sheets. It also pursues the annulment of all ANEEL Resolutions that allow the collection and inclusion in the bills of sums related to non-technical and technical losses.

This lawsuit was classified by the Company’s lawyer as with risk of possible loss. Due to the relevance of the case, we recommend that you further develop the discussions with the legal area about the potential risks that this matter involves.

4 Tax and labor exposures

It is important to stress that, during our works, we identified several procedures adopted by the Company that may result in questioning and assessments by the labor and social security and the federal, state, and municipal tax authorities. In what respects such procedures, the respective value of the contingencies that may potentially emerge if they are identified and questioned corresponds to R$ 1.4 billion. Please note that there are other non-quantified adjustments.


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Exhibit I – Adjusted EBITDA (1/6)


Quality of earnings - CERON
		FY15	FY16
In R$ thousand		(Audited)	(Audited)
Net revenue		985,921	1,484,833
Net profit (loss)		(560,837)	(835,268)
Add-backs (reversions)		386,443	284,947
Financial results		365,420	250,561
Depreciation/amortization		31,953	34,386
IR and CSLL		(10,929)	-
Reported EBITDA		(174,394)	(550,321)
% on net revenue		(18%)	(37%)
Reclassifications		(24,618)	151,746
1	Reclassification of the new replacement value	(48,532)	(50,910)
2	Reclassification of impairment provisions	23,914	11,331
3	Reclassification of the provision for onerous liabilities	-	191,325
Normalization adjustments		29,019	174,550
4	Normalization of expenses with PCLD	23,570	(7,849)
	Normalization of the revenue from excess demand and
5		5,449	(13,873)
	excess of reactive power
6	Financial impacts due to write-off of CCC credits by ANEEL	NQ	196,273
Tax and labor adjustments		(351)	(735)
7	Tax, labor, and social security impacts	(351)	(735)
Adjusted EBITDA		(170,345)	(224,760)
% on net revenue		(17%)	(15%)
Non-quantified adjustments and other considerations		9,199	(17,997)
8	Potential normalization of provision for contingencies	9,199	(17,997)
9	Potential risk of change in the CVA values	NQ	NQ
10 Costs with new structure/Company’s integration		NQ	NQ
11 Undue charges – Angra 3		-	NQ
12 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis

The table on the left displays the Company’s quality of earnings (EBITDA) analysis for the fiscal years ended on December 31, 2015 (FY15) and December 31, 2016 (FY16).

The adjustments suggested were calculated based on the information provided by the Company's management. Those adjustments were made as a result of our analysis, according to financial and management information prepared by the Company’s management.

The EBITDA corresponds to the net profit subtracted of certain reclassification items, such as net financial results, taxes and social contributions on the earned income (Income Tax (IRPJ) and Social Contribution on Net Profit (CSLL)), depreciation and amortization.

Comments on the adjustments identified are detailed below and in the next pages of this summary.

Reclassification adjustments

1. Reclassification of the new replacement value: This is the monetary restatement of the concession assets basis expected to be paid to the Company after the concession period. Since those sums are not characterized as operating, and considering the current situation of the distribution Company, we understand that they should not be part of the recurring EBITDA analysis for the period.


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Exhibit I – Adjusted EBITDA (2/6)


Quality of earnings - CERON
		FY15	FY16
In R$ thousand		(Audited)	(Audited)
Net revenue		985,921	1,484,833
Net profit (loss)		(560,837)	(835,268)
Add-backs (reversions)		386,443	284,947
Financial results		365,420	250,561
Depreciation/amortization		31,953	34,386
IR and CSLL		(10,929)	-
Reported EBITDA		(174,394)	(550,321)
% on net revenue		(18%)	(37%)
Reclassifications		(24,618)	151,746
1	Reclassification of the new replacement value	(48,532)	(50,910)
2	Reclassification of impairment provisions	23,914	11,331
3	Reclassification of the provision for onerous liabilities	-	191,325
Normalization adjustments		29,019	174,550
4	Normalization of expenses with PCLD	23,570	(7,849)
	Normalization of the revenue from excess demand and
5		5,449	(13,873)
	excess of reactive power
6	Financial impacts due to write-off of CCC credits by ANEEL	NQ	196,273
Tax and labor adjustments		(351)	(735)
7	Tax, labor, and social security impacts	(351)	(735)
Adjusted EBITDA		(170,345)	(224,760)
% on net revenue		(17%)	(15%)
Non-quantified adjustments and other considerations		9,199	(17,997)
8	Potential normalization of provision for contingencies	9,199	(17,997)
9	Potential risk of change in the CVA values	NQ	NQ
10 Costs with new structure/Company’s integration		NQ	NQ
11 Undue charges – Angra 3		-	NQ
12 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis

2.	Reclassification of impairment provisions: We suggest the reversion of the impacts from the recognition and/or reversion of the provision for recoverability of the intangible assets (impairment), considering that those values are purely accounting entries which do not directly impact the Company’s cash flow generation.
3.	Reclassification of the provision for onerous liabilities: We identified that, in 2016, the Company recognized a provision for onerous contracts in the total amount of R$ 191.3m during the evaluation of the recoverability of its concession/intangible assets.
	Since those sums are purely accounting entries, which do not directly impact the Company’s cash generation, we suggest that they be excluded for purposes of analysis of normalized EBITDA.

Normalization adjustments


4.	Normalization of expenses with Allowance for Doubtful
	Accounts (PCLD): We note that the PCLD is automatically and
	systemically calculated, following the criteria established by
	Eletrobras, and that such criteria tends to be more conservative
	than those established by ANEEL. Since those provisions are not of
	a financial nature and their variations are not historically constant,
	we understand that, for purposes of normalized EBITDA, it must be
	considered only the impacts from losses resulting from payments
	from clients that effectively materialized in the period; accordingly,
	we suggest the reversion of the PCLD in the period.
	In R$ thousand	Dec-15	Dec-16
	Net revenue	985,921	1,484,833
	PCLD / Losses result	(86,196)	(51,295)
	Proposed adjustment	23,570	(7,849)
	Losses in the period	(62,626)	(59,144)
	% of losses on net revenue	6%	4%


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Exhibit I – Adjusted EBITDA (3/6)


Quality of earnings - CERON
		FY15	FY16
In R$ thousand		(Audited)	(Audited)
Net revenue		985,921	1,484,833
Net profit (loss)		(560,837)	(835,268)
Add-backs (reversions)		386,443	284,947
Financial results		365,420	250,561
Depreciation/amortization		31,953	34,386
IR and CSLL		(10,929)	-
Reported EBITDA		(174,394)	(550,321)
% on net revenue		(18%)	(37%)
Reclassifications		(24,618)	151,746
1	Reclassification of the new replacement value	(48,532)	(50,910)
2	Reclassification of impairment provisions	23,914	11,331
3	Reclassification of the provision for onerous liabilities	-	191,325
Normalization adjustments		29,019	174,550
4	Normalization of expenses with PCLD	23,570	(7,849)
	Normalization of the revenue from excess demand and
5		5,449	(13,873)
	excess of reactive power
6	Financial impacts due to write-off of CCC credits by ANEEL	NQ	196,273
Tax and labor adjustments		(351)	(735)
7	Tax, labor, and social security impacts	(351)	(735)
Adjusted EBITDA		(170,345)	(224,760)
% on net revenue		(17%)	(15%)
Non-quantified adjustments and other considerations		9,199	(17,997)
8	Potential normalization of provision for contingencies	9,199	(17,997)
9	Potential risk of change in the CVA values	NQ	NQ
10 Costs with new structure/Company’s integration		NQ	NQ
11 Undue charges – Angra 3		-	NQ
12 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis

5.	Normalization of the revenue from excess demand and excess of reactive power: The revenues earned with excess demand and excess of reactive power must be accounted for as “Obligations Related to the Electric Power Utility Service,” which will be amortized starting on the next cycle of tariff review.
	However, the Company recognized those sums as revenues in the fiscal years of 2013-2016 and later, in FY16, reversed 100% of the sums recognized as liabilities until the next cycle of tariff review. This adjustment aims at normalizing the impact of that reversion between the periods.
6.	Financial impacts due to write-off of Fuel Consumption Account (CCC) credits by ANEEL: By means of ANEEL
	Resolution no. 2202, the 2017 approved budget for the CDE/CCC did not consider the renegotiated values for 2014 and 2015 of the distribution companies Amazonas, CERON, Acre, and Boa Vista. The distribution companies filed a request for reconsideration of those amounts, and the expectation is that the balance remains as a write-off until ANEEL reprocesses the CCC account in the period from July 2009 to June 2016. Considering that this is a non- recurring expense (prior periods provision), we are suggesting it be excluded for purposes of EBITDA analysis. Please note that a portion of the adjusted amount should impact the FY15 EBITDA. However, since there was not enough information, it was not
possible	to quantify that impact.

Tax and labor adjustments

7.	Tax, labor, and social security impacts: They refer to potential additional impacts resulting from the matters described in this summary, quantified and not [omissis].


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Exhibit I – Adjusted EBITDA (4/6)


Quality of earnings - CERON
		FY15	FY16
In R$ thousand		(Audited)	(Audited)
Net revenue		985,921	1,484,833
Net profit (loss)		(560,837)	(835,268)
Add-backs (reversions)		386,443	284,947
Financial results		365,420	250,561
Depreciation/amortization		31,953	34,386
IR and CSLL		(10,929)	-
Reported EBITDA		(174,394)	(550,321)
% on net revenue		(18%)	(37%)
Reclassifications		(24,618)	151,746
1	Reclassification of the new replacement value	(48,532)	(50,910)
2	Reclassification of impairment provisions	23,914	11,331
3	Reclassification of the provision for onerous liabilities	-	191,325
Normalization adjustments		29,019	174,550
4	Normalization of expenses with PCLD	23,570	(7,849)
	Normalization of the revenue from excess demand and
5		5,449	(13,873)
	excess of reactive power
6	Financial impacts due to write-off of CCC credits by ANEEL	NQ	196,273
Tax and labor adjustments		(351)	(735)
7	Tax, labor, and social security impacts	(351)	(735)
Adjusted EBITDA		(170,345)	(224,760)
% on net revenue		(17%)	(15%)
Non-quantified adjustments and other considerations		9,199	(17,997)
8	Potential normalization of provision for contingencies	9,199	(17,997)
9	Potential risk of change in the CVA values	NQ	NQ
10 Costs with new structure/Company’s integration		NQ	NQ
11 Undue charges – Angra 3		-	NQ
12 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis


Tax and labor adjustments
7.	Tax, labor, and social security impacts (cont’d):
	Quantified, classified as probable loss by your legal advisors.
	#	Description	31-Dec-15 31-Dec-16
	1	ISS on billable services	109	155
	Total tax exposures		109	155
	4	Irregularities related to work days	242	580
	Total labor exposures		242	580
	Total tax and labor exposures + NQ		351	735

Non-quantified adjustments and other considerations

8.	Potential normalization of provision for contingencies:
	It refers to the reversion of the provisions for contingencies due to their non-financial nature. Accordingly, we understand that, for purposes of the Company’s normalized and recurring EBITDA, the effect from payment of indemnifications materialized in the fiscal years under analysis. We recommend that you discuss with your legal advisors the nature and respective projections of non-materialized losses in the fiscal years.
9.	Potential risk of change in the CVA values: The Account for Compensation of “Portion A” Variations (CVA) records the difference between the costs estimated in the tariff (Portion A) and the costs effectively incurred in the period. We note that the costs incurred by the Company happen before ANEEL’s ratification and that, historically, there are discrepancies between the sums ascertained by the Company and the “armored” basis in the period (ratified by ANEEL).


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Exhibit I – Adjusted EBITDA (5/6)


Quality of earnings - CERON
		FY15	FY16
In R$ thousand		(Audited)	(Audited)
Net revenue		985,921	1,484,833
Net profit (loss)		(560,837)	(835,268)
Add-backs (reversions)		386,443	284,947
Financial results		365,420	250,561
Depreciation/amortization		31,953	34,386
IR and CSLL		(10,929)	-
Reported EBITDA		(174,394)	(550,321)
% on net revenue		(18%)	(37%)
Reclassifications		(24,618)	151,746
1	Reclassification of the new replacement value	(48,532)	(50,910)
2	Reclassification of impairment provisions	23,914	11,331
3	Reclassification of the provision for onerous liabilities	-	191,325
Normalization adjustments		29,019	174,550
4	Normalization of expenses with PCLD	23,570	(7,849)
	Normalization of the revenue from excess demand and
5		5,449	(13,873)
	excess of reactive power
6	Financial impacts due to write-off of CCC credits by ANEEL	NQ	196,273
Tax and labor adjustments		(351)	(735)
7	Tax, labor, and social security impacts	(351)	(735)
Adjusted EBITDA		(170,345)	(224,760)
% on net revenue		(17%)	(15%)
Non-quantified adjustments and other considerations		9,199	(17,997)
8	Potential normalization of provision for contingencies	9,199	(17,997)
9	Potential risk of change in the CVA values	NQ	NQ
10 Costs with new structure/Company’s integration		NQ	NQ
11 Undue charges – Angra 3		-	NQ
12 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis

9.	Potential risk of change in the CVA values (cont'd):
	Considering that the tariffs ratification usually happens in October of each year for the following months, we understand that the cost incurred (and not ratified) related to November and December 2016 may suffer changes over the next fiscal year.
10.	Costs with new structure/Company’s integration: We note that, depending on the changes in the Company’s current structure that are made after the conclusion of the privatization process, as well as on the measures required for the potential integration with an investor, the Company’s EBITDA may change significantly. In addition, possible changes in the compensation of the new management must be considered in the Company’s result. We recommend that this issue be discussed with the “Economic and Legal Assessment” area.
11.	Undue charges – Angra 3: According to ANEEL’s information, the power distribution companies that belong to the interconnected system unduly charged from their consumers in 2016 certain amounts related to the estimated costs of the nuclear power plant Angra 3. We have not had access to the sums to be reimbursed to the Company’s consumers, but we were informed that such reimbursement would be made by means of discount (of approximately 7.66%) in the April 2017 bill.


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Exhibit I – Adjusted EBITDA (6/6)


Quality of earnings - CERON				12. Other potential adjustments: Considering the defined scope
		FY15	FY16	of our works; the limitations in the information provided; the
In R$ thousand		(Audited)	(Audited)	tax, labor, and social security exposures that could not be
Net revenue		985,921	1,484,833	quantified; and possible non-recoverable assets adjustments
Net profit (loss)		(560,837)	(835,268)	(e.g., inventory with low recoverability expectation); other
Add-backs (reversions)		386,443	284,947	potential adjustments may be necessary, in order to better reflect
Financial results		365,420	250,561	the Company’s normalized and recurring EBITDA. In addition,
Depreciation/amortization		31,953	34,386	we recommend that this summary be read jointly with the
IR and CSLL		(10,929)	-	reports of the other due diligence areas (operational, legal, HR,
Reported EBITDA		(174,394)	(550,321)	insurance, and environmental).
% on net revenue		(18%)	(37%)
Reclassifications		(24,618)	151,746
1	Reclassification of the new replacement value	(48,532)	(50,910)
2	Reclassification of impairment provisions	23,914	11,331
3	Reclassification of the provision for onerous liabilities	-	191,325
Normalization adjustments		29,019	174,550
4	Normalization of expenses with PCLD	23,570	(7,849)
	Normalization of the revenue from excess demand and
5		5,449	(13,873)
	excess of reactive power
6	Financial impacts due to write-off of CCC credits by ANEEL	NQ	196,273
Tax and labor adjustments		(351)	(735)
7	Tax, labor, and social security impacts	(351)	(735)
Adjusted EBITDA		(170,345)	(224,760)
% on net revenue		(17%)	(15%)
Non-quantified adjustments and other considerations		9,199	(17,997)
8	Potential normalization of provision for contingencies	9,199	(17,997)
9	Potential risk of change in the CVA values	NQ	NQ
10 Costs with new structure/Company’s integration		NQ	NQ
11 Undue charges – Angra 3		-	NQ
12 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis


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Exhibit II – Net indebtedness (1/5)


Net indebtedness

In R$ thousand		Dec-15	Dec-16
Cash and cash equivalents		25,400	18,706
Securities		30,152	2,039
Loans – short term		(127,651)	(23,324)
Loans – long term		(607,023)	(940,637)
Net financial indebtedness		(679,122)	(943,216)
Collaterals and deposits in court - long term		79,719	127,064
Indemnification right – long term		3,440,587	3,488,797
Financial charges		(8)	(6)
Post-employment benefit – short term		(2,886)	(6,316)
Suppliers - long term		(3,060,507)	(3,421,566)
Payable taxes		(3,955)	(4,260)
Provisions for lawsuits		(134,772)	(172,184)
Indemnification obligations - long term		(142,624)	(152,339)
Other liabilities – long term		(42,199)	(47,439)
Other debt items		133,355	(188,249)
Reported net indebtedness		(545,767)	(1,131,465)
Reclassification between working capital and net indebtedness		(1,109,644)	(1,490,034)
1	CCC amounts to be returned due to overpayment	(6,164)	(125,083)
2	CCC past due and installment payment amounts to be received	131,053	85,173
3	Suppliers with past due credits	(1,220,281)	(1,420,254)
4	Reclassification of related parties	5,669	4,263
5	Other liabilities – short term	(19,921)	(34,133)
Subtotal		(1,109,644)	(1,490,034)
Adjusted net indebtedness		(1,655,411)	(2,621,499)
Other considerations		670,978	794,141
i	Tax, labor, and social security impacts	(274,801)	(367,667)
ii	Financial asset – public utility concessions	900,632	1,120,953
iii	Clients with past due and installment payments	45,147	40,855
iv	Collaterals and deposits in court - long term	NQ	NQ
v	Provision for contingencies	NQ	NQ
vi	CAPEX investments	NQ	NQ
vii	Undue charges – Angra 3	-	NQ
viii Other potential adjustments		NQ	NQ
Source: Audited trial balances and Pw C analysis

The table on the left displays the Company’s net indebtedness, based on the audited financial statements for the years ended on December 31, 2015 (Dec-16) and December 31, 2016 (Dec-16).

We note that the concept of Net Indebtedness is not contemplated in the accounting practices adopted in Brazil, being it rather a contractual definition. For the purpose of our analysis, we considered, in addition to the net financial indebtedness, other items and transactions with financing features, such as: -Indemnification right – long term: CCC receivables, which will be used to pay off the debt with suppliers with past due and coming due credits.

- Suppliers - long term: Balance of suppliers with past due and renegotiated credits, maturing (after the renegotiation) beyond 12 months.

The adjustments suggested and reported were prepared based on management information and reports, accounting trial balances, and enquiries made to the Company’s management. We note that, due to limited information and scope, there may be adjustments that could not be quantified/identified during our analysis.

Reclassifications between working capital and net indebtedness

1.	CCC amounts to be returned due to overpayment: The Company recorded, as per ANEEL’s determination in Decision no. 758/2015, a liability related to CCC amounts received above the limit from 1999 to 2011.


Privatization of the Eletrobras System Distribution Companies	10 agosto 2017
PwC	12

Exhibit II – Net indebtedness (2/5)


Net indebtedness

In R$ thousand		Dec-15	Dec-16
Cash and cash equivalents		25,400	18,706
Securities		30,152	2,039
Loans – short term		(127,651)	(23,324)
Loans – long term		(607,023)	(940,637)
Net financial indebtedness		(679,122)	(943,216)
Collaterals and deposits in court - long term		79,719	127,064
Indemnification right – long term		3,440,587	3,488,797
Financial charges		(8)	(6)
Post-employment benefit – short term		(2,886)	(6,316)
Suppliers - long term		(3,060,507)	(3,421,566)
Payable taxes		(3,955)	(4,260)
Provisions for lawsuits		(134,772)	(172,184)
Indemnification obligations - long term		(142,624)	(152,339)
Other liabilities – long term		(42,199)	(47,439)
Other debt items		133,355	(188,249)
Reported net indebtedness		(545,767)	(1,131,465)
Reclassification between working capital and net indebtedness		(1,109,644)	(1,490,034)
1	CCC amounts to be returned due to overpayment	(6,164)	(125,083)
2	CCC past due and installment payment amounts to be received	131,053	85,173
3	Suppliers with past due credits	(1,220,281)	(1,420,254)
4	Reclassification of related parties	5,669	4,263
5	Other liabilities – short term	(19,921)	(34,133)
Subtotal		(1,109,644)	(1,490,034)
Adjusted net indebtedness		(1,655,411)	(2,621,499)
Other considerations		670,978	794,141
i	Tax, labor, and social security impacts	(274,801)	(367,667)
ii	Financial asset – public utility concessions	900,632	1,120,953
iii	Clients with past due and installment payments	45,147	40,855
iv	Collaterals and deposits in court - long term	NQ	NQ
v	Provision for contingencies	NQ	NQ
vi	CAPEX investments	NQ	NQ
vii	Undue charges – Angra 3	-	NQ
viii Other potential adjustments		NQ	NQ
Source: Audited trial balances and Pw C analysis

2.	CCC past due and installment payment amounts to be received: The Company has CCC receivables that are past due and, in some cases, subject to installment payments. Considering that they are receivables related to prior fiscal years, we are reclassifying them from working capital to Company net indebtedness (which reduces the debt), as these are funds that must be destined to pay off past due liabilities related to fuel acquisition.
3.	Suppliers with past due credits: We suggest the reclassification as net indebtedness of 100% of the suppliers’ past due payable balances, due to their nature of financing.
4.	Reclassification of related parties: It refers to balances receivable from related parties for employee loans (assigned) paid by the Company. In view of their nature, we suggest their reclassification as Company indebtedness.
5.	Other liabilities – short term: We identified certain liabilities classified in the Company’s current liabilities which, in our view, are not characterized as operating working capital, as detailed in the next slide:


In R$ thousand	Dec-15	Dec-16
The balances refer to R&D and PEE classified as other liabilities. We therefore	15,504	23,633
suggest they be reclassified as debt, in view of their nature.
Refers to installment payment to be returned to the CDE fund classified as other
liabilities. We therefore suggest they be reclassified as debt, in view of their nature.	-	6,083
Refers to penalty related to breach of DEC and FEC duration targets verified by	4,417	4,417
Adjustment for reclassification as debt	19,921	34,133
Source: Pw C analysis and discussions w ith management


Privatization of the Eletrobras System Distribution Companies	10 agosto 2017
PwC	13

Exhibit II – Net indebtedness (3/5)


Net indebtedness

In R$ thousand		Dec-15	Dec-16
Cash and cash equivalents		25,400	18,706
Securities		30,152	2,039
Loans – short term		(127,651)	(23,324)
Loans – long term		(607,023)	(940,637)
Net financial indebtedness		(679,122)	(943,216)
Collaterals and deposits in court - long term		79,719	127,064
Indemnification right – long term		3,440,587	3,488,797
Financial charges		(8)	(6)
Post-employment benefit – short term		(2,886)	(6,316)
Suppliers - long term		(3,060,507)	(3,421,566)
Payable taxes		(3,955)	(4,260)
Provisions for lawsuits		(134,772)	(172,184)
Indemnification obligations - long term		(142,624)	(152,339)
Other liabilities – long term		(42,199)	(47,439)
Other debt items		133,355	(188,249)
Reported net indebtedness		(545,767)	(1,131,465)
Reclassification between working capital and net indebtedness		(1,109,644)	(1,490,034)
1	CCC amounts to be returned due to overpayment	(6,164)	(125,083)
2	CCC past due and installment payment amounts to be received	131,053	85,173
3	Suppliers with past due credits	(1,220,281)	(1,420,254)
4	Reclassification of related parties	5,669	4,263
5	Other liabilities – short term	(19,921)	(34,133)
Subtotal		(1,109,644)	(1,490,034)
Adjusted net indebtedness		(1,655,411)	(2,621,499)
Other considerations		670,978	794,141
i	Tax, labor, and social security impacts	(274,801)	(367,667)
ii	Financial asset – public utility concessions	900,632	1,120,953
iii	Clients with past due and installment payments	45,147	40,855
iv	Collaterals and deposits in court - long term	NQ	NQ
v	Provision for contingencies	NQ	NQ
vi	CAPEX investments	NQ	NQ
vii	Undue charges – Angra 3	-	NQ
viii Other potential adjustments		NQ	NQ
Source: Audited trial balances and Pw C analysis

Other considerations:

Tax, labor, and social security impacts: We are considering, for purposes of analysis of the Company’s net indebtedness, the tax, labor, and social security exposures classified as with risk of probable loss (see specific exhibit in this summary). We note that the amount presented here already considers possible fines and interest to be added upon an assessment by the tax authorities.


#	Description	31-Dec-15 31-Dec-16
2	Ancillary obligations in breach of the law	186,379	252,530
6	CVA	797	6,529
7	ISS on billable services	1,216	1,505
Total tax exposures		188,392	260,564
1	Outsourcing of core activity	84,484	104,488
4	Irregularities related to work days	1,729	2,336
5	Employer labor union contribution	196	279
Total labor exposures		86,409	107,103
Total tax and labor exposures + NQ		274,801	367,667

ii.

Financial asset – public utility concessions: It refers to the financial asset indemnifiable in the end of the concession/service period. Depending on how the Company’s sale is structured, the indemnifiable balance may be converted into cash, thus reducing the level of net indebtedness.


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Exhibit II – Net indebtedness (4/5)


Net indebtedness

In R$ thousand		Dec-15	Dec-16
Cash and cash equivalents		25,400	18,706
Securities		30,152	2,039
Loans – short term		(127,651)	(23,324)
Loans – long term		(607,023)	(940,637)
Net financial indebtedness		(679,122)	(943,216)
Collaterals and deposits in court - long term		79,719	127,064
Indemnification right – long term		3,440,587	3,488,797
Financial charges		(8)	(6)
Post-employment benefit – short term		(2,886)	(6,316)
Suppliers - long term		(3,060,507)	(3,421,566)
Payable taxes		(3,955)	(4,260)
Provisions for lawsuits		(134,772)	(172,184)
Indemnification obligations - long term		(142,624)	(152,339)
Other liabilities – long term		(42,199)	(47,439)
Other debt items		133,355	(188,249)
Reported net indebtedness		(545,767)	(1,131,465)
Reclassification between working capital and net indebtedness		(1,109,644)	(1,490,034)
1	CCC amounts to be returned due to overpayment	(6,164)	(125,083)
2	CCC past due and installment payment amounts to be received	131,053	85,173
3	Suppliers with past due credits	(1,220,281)	(1,420,254)
4	Reclassification of related parties	5,669	4,263
5	Other liabilities – short term	(19,921)	(34,133)
Subtotal		(1,109,644)	(1,490,034)
Adjusted net indebtedness		(1,655,411)	(2,621,499)
Other considerations		670,978	794,141
i	Tax, labor, and social security impacts	(274,801)	(367,667)
ii	Financial asset – public utility concessions	900,632	1,120,953
iii	Clients with past due and installment payments	45,147	40,855
iv	Collaterals and deposits in court - long term	NQ	NQ
v	Provision for contingencies	NQ	NQ
vi	CAPEX investments	NQ	NQ
vii	Undue charges – Angra 3	-	NQ
viii Other potential adjustments		NQ	NQ
Source: Audited trial balances and Pw C analysis

iii.

Clients with past due and installment payments: We identified outstanding balances of clients’ past due and installment payments, classified in the current and non-current assets. Although they do not represent a cash item with immediate liquidity, we understand that they are a receivable of the Company, which, therefore, must be included in possible cash flow projections.


In R$ thousand	Dec-15	Dec-16
Clients – current assets	26,010	24,026
Clients – non-current assets	19,137	16,829
Total	45,147	40,855

iv.	Long term collaterals and deposits in court: We note that the deposits in court directly related to a provision for contingency must impact the indebtedness balances in the period. However, since the Company did not provide the ancillary controls, it was not possible to determine if the full amount of the reported balances must be included in the analysis of the Company’s net indebtedness.
v.	Provision for contingencies: We note that this summary does not consider possible changes in the projection of loss of the Company’s lawsuits, resulting from the legal due diligence works.


Privatization of the Eletrobras System Distribution Companies	10 agosto 2017
PwC	15

Exhibit II – Net indebtedness (5/5)


Net indebtedness

In R$ thousand		Dec-15	Dec-16
Cash and cash equivalents		25,400	18,706
Securities		30,152	2,039
Loans – short term		(127,651)	(23,324)
Loans – long term		(607,023)	(940,637)
Net financial indebtedness		(679,122)	(943,216)
Collaterals and deposits in court - long term		79,719	127,064
Indemnification right – long term		3,440,587	3,488,797
Financial charges		(8)	(6)
Post-employment benefit – short term		(2,886)	(6,316)
Suppliers - long term		(3,060,507)	(3,421,566)
Payable taxes		(3,955)	(4,260)
Provisions for lawsuits		(134,772)	(172,184)
Indemnification obligations - long term		(142,624)	(152,339)
Other liabilities – long term		(42,199)	(47,439)
Other debt items		133,355	(188,249)
Reported net indebtedness		(545,767)	(1,131,465)
Reclassification between working capital and net indebtedness		(1,109,644)	(1,490,034)
1	CCC amounts to be returned due to overpayment	(6,164)	(125,083)
2	CCC past due and installment payment amounts to be received	131,053	85,173
3	Suppliers with past due credits	(1,220,281)	(1,420,254)
4	Reclassification of related parties	5,669	4,263
5	Other liabilities – short term	(19,921)	(34,133)
Subtotal		(1,109,644)	(1,490,034)
Adjusted net indebtedness		(1,655,411)	(2,621,499)
Other considerations		670,978	794,141
i	Tax, labor, and social security impacts	(274,801)	(367,667)
ii	Financial asset – public utility concessions	900,632	1,120,953
iii	Clients with past due and installment payments	45,147	40,855
iv	Collaterals and deposits in court - long term	NQ	NQ
v	Provision for contingencies	NQ	NQ
vi	CAPEX investments	NQ	NQ
vii	Undue charges – Angra 3	-	NQ
viii Other potential adjustments		NQ	NQ
Source: Audited trial balances and Pw C analysis

vi.	CAPEX investments: As mentioned before, the Company has been operating as a public utility Company, which has resulted in a reduction in CAPEX investments, maintaining only those that are essentially necessary to continue with the operational activities and the levels of quality required by the regulatory agencies. We recommend that the you consider the impacts estimated by the result of the technical and operational due diligence.
vii.	Undue charges – Angra 3: According to ANEEL’s information, the power distribution companies that belong to the interconnected system unduly charged from their consumers in 2016 certain amounts related to the estimated costs of the nuclear power plant Angra 3. We have not had access to the sums to be reimbursed to the Company’s consumers, but we were informed that such reimbursement would be made by means of discount (of approximately 4.74%) in the April 2017 bill.
viii.	Other potential adjustments: Considering the defined scope of our works; the limitations in the information provided; the tax, labor, and social security exposures that could not be quantified; and possible non-recoverable assets adjustments (e.g., inventory with low recoverability expectation); other potential adjustments may be necessary, in order to better reflect the Company’s net and recurring indebtedness. In
addition,	we recommend that this summary be read jointly with
the	reports of the other due diligence areas (operational, legal,
HR,	insurance, and environmental).


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Exhibit III – Net working capital (1/3)


Net working capital

In R$ thousand	Dec-15	Dec-16
Clients – short term	273,511	248,349
Short term electricity	71,817	-
Taxes and social contributions – short term	24,952	27,665
Indemnification right – short term	148,748	253,308
Inventory	18,948	16,864
Financial assets	134,435	54,523
Other assets – short term	44,091	22,210
Suppliers - short term	(1,227,024)	(1,456,393)
Taxes and contributions	(59,680)	(69,418)
Indemnification obligations - short term	(6,164)	(125,083)
Regulatory liabilities - short term	(294,428)	(74,898)
Industry charges - short term	(20,113)	(21,459)
Estimated obligations	(12,631)	(17,167)
Other liabilities – short term	(36,837)	(46,199)
Reported net working capital	(940,375)	(1,187,698)
Reclassification between working capital and net indebtedness	1,109,644	1,490,034
CCC amounts to be returned due to overpayment	6,164	125,083
CCC past due and installment payment amounts to be received	(131,053)	(85,173)
Suppliers with past due credits	1,220,281	1,420,254
Reclassification of related parties	(5,669)	(4,263)
Other liabilities – short term	19,921	34,133
Subtotal	1,109,644	1,490,034
Adjustments proposed by the due diligence	(33,579)	(34,906)
1 Inventory with low recoverability expectation	(363)	(1,617)
2 Clients with past due and installment payments	(26,010)	(24,026)
3 Other assets – short term	(7,206)	(9,264)
Subtotal	(33,579)	(34,906)
Adjusted net working capital	135,690	267,429
Other considerations	NQ	NQ
Source: Audited trial balances and Pw C analysis

We present in the table on the left the Company’s net working capital as of December 31, 2015 (Dec-15) and 2016 (Dec-16), prepared based on the audited financial statements.

The adjustments suggested and reported were prepared based on management information and reports, audited accounting trial balances, and enquiries made to the Company’s management. We note that, due to limited information and scope, there may be adjustments that could not be quantified/identified during our analysis.

Reclassifications between working capital and net indebtedness

For further details, see the preceding exhibit of this summary, “net indebtedness.”

Adjustments proposed by the due diligence

Inventory with low recoverability expectation: Items destined to sale (scraps) and lent materials, which are not classified as operating working capital.

Clients with past due and installment payments: We identified outstanding balances of clients’ past due and installment payments, classified in the current assets, which we suggest be excluded for purposes of analysis of the Company’s working capital. As mentioned before, although they do not represent a cash item with immediate liquidity, we understand that they are a receivable of the Company, which, therefore, must be included in possible cash flow projections.


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Exhibit III – Net working capital (2/3)


Net working capital

In R$ thousand	Dec-15	Dec-16
Clients – short term	273,511	248,349
Short term electricity	71,817	-
Taxes and social contributions – short term	24,952	27,665
Indemnification right – short term	148,748	253,308
Inventory	18,948	16,864
Financial assets	134,435	54,523
Other assets – short term	44,091	22,210
Suppliers - short term	(1,227,024)	(1,456,393)
Taxes and contributions	(59,680)	(69,418)
Indemnification obligations - short term	(6,164)	(125,083)
Regulatory liabilities - short term	(294,428)	(74,898)
Industry charges - short term	(20,113)	(21,459)
Estimated obligations	(12,631)	(17,167)
Other liabilities – short term	(36,837)	(46,199)
Reported net working capital	(940,375)	(1,187,698)
Reclassification between working capital and net indebtedness	1,109,644	1,490,034
Adjustments proposed by the due diligence	(33,579)	(34,906)
1 Inventory with low recoverability expectation	(363)	(1,617)
2 Clients with past due and installment payments	(26,010)	(24,026)
3 Other assets – short term	(7,206)	(9,264)
Subtotal	(33,579)	(34,906)
Adjusted net working capital	135,690	267,429

3.	Other assets – short term: We identified certain assets classified in the Company’s current assets which, in our view, are not characterized as operating working capital, as detailed below:


In R$ thousand	Dec-15	Dec-16
Goods to be written-off or scrapped	(4,138)	(5,487)
Scraps available for sale	(443)	(492)

Client’s financial difficulty. We suggest writing off this sum from	(2,625)	(3,285)
the WC.
Adjustment for WC write-off	(7,206)	(9,264)
Source: Pw C analysis and discussions w ith management


Other considerations		NQ	NQ
i	Risk of writing-off of CCC indemnification right	NQ	NQ
ii	Potential risk of change in the CVA values	NQ	NQ
iii Tax, labor, and social security exposures		NQ	NQ
iv Other potential adjustments		NQ	NQ
Source: Audited trial balances and Pw C analysis


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Exhibit III – Net working capital (3/3)


Net working capital			Other considerations

In R$ thousand	Dec-15	Dec-16	i.	Risk of writing-off of CCC indemnification right: We were
Clients – short term	273,511	248,349		informed that ANEEL is in the process of inspecting the CCC
Short term electricity	71,817	-		account reprocessing. As a result, we understand that there may
Taxes and social contributions – short term	24,952	27,665		be variations in the CCC receivables account (positive or negative)
Indemnification right – short term	148,748	253,308		when that process is concluded.
Inventory	18,948	16,864
Financial assets	134,435	54,523	ii.	Potential risk of change in the CVA values: The Account for
Other assets – short term	44,091	22,210		Compensation of “Portion A” Variations (CVA) records the
Suppliers - short term	(1,227,024)	(1,456,393)
Taxes and contributions	(59,680)	(69,418)		difference between the costs estimated in the tariff (Portion A) and
Indemnification obligations - short term	(6,164)	(125,083)		the costs effectively incurred, creating a payable or receivable
Regulatory liabilities - short term	(294,428)	(74,898)		balance (and, consequently, an expense or a revenue) for the
Industry charges - short term	(20,113)	(21,459)		Company. Such amounts to be paid/received are ratified each year
Estimated obligations	(12,631)	(17,167)
Other liabilities – short term	(36,837)	(46,199)		by ANEEL. We found that, historically, the amounts ascertained
Reported net working capital	(940,375)	(1,187,698)		by the Company may significantly differ from those ratified by
Reclassification between working capital and net indebtedness	1,109,644	1,490,034		ANEEL, mainly with respect to the financial items, which are not
Adjustments proposed by the due diligence	(33,579)	(34,906)		controlled by the Company. Considering that the ratification
1 Inventory with low recoverability expectation	(363)	(1,617)		process happens close to the end of the fiscal year (between
2 Clients with past due and installment payments	(26,010)	(24,026)
3 Other assets – short term	(7,206)	(9,264)		September and October), we understand that there are no material
Subtotal	(33,579)	(34,906)		discrepancies for the balances accounted for in Dec-15 and Dec-16.
Adjusted net working capital	135,690	267,429		On the other hand, those differences may become significant over
Other considerations	NQ	NQ		the months.
i Risk of writing-off of CCC indemnification right	NQ	NQ	iii.	Tax, labor, and social security exposures: It refers to the
ii Potential risk of change in the CVA values	NQ	NQ
iii Tax, labor, and social security exposures	NQ	NQ		impact on the net working capital of adjustment #7 presented in
iv Other potential adjustments	NQ	NQ		the quality of the results. We understand that any changes in the
Source: Audited trial balances and Pw C analysis				tax, labor, and social security procedures may also impact the
				Company’s net working capital.

iv.

Other potential adjustments: See adjustment viii of the preceding exhibit.


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Exhibit IV – Balance Sheet


Assets
	Dec-15	Dec-16
In R$ thousand	Audited	Audited
Cash and cash equivalents	25,400	18,706
Securities - TVM	30,152	2,039
Clients – short term	273,511	248,349
Short term electricity	71,817	-
Taxes and social contributions – short term	24,952	27,665
Indemnification right – short term	148,748	253,308
Inventory	18,948	16,864
Ongoing services	4,900	10,621
Financial assets	134,435	54,523
Other assets – short term	44,091	22,210
Current assets	776,954	654,285
Clients – long term	19,137	16,829
Taxes and social contributions – long term	7,628	6,534
Collaterals and deposits in court - long term	79,719	127,064
Indemnification right – long term	3,440,587	3,488,797
Financial asset – public utility concessions	900,632	1,120,953
Other assets – long term	2,447	2,447
Investments	1,806	1,806
Intangible assets	60,544	27,336
Fixed assets	32,735	28,044
Non-current assets	4,545,235	4,819,810
Total assets	5,322,189	5,474,095


Liabilities
	Dec-15	Dec-16
In R$ thousand	Audited	Audited
Suppliers - short term	1,227,024	1,456,393
Loans – short term	127,651	23,324
Taxes and contributions	59,680	69,418
Indemnification obligations - short term	6,164	125,083
Financial charges	8	6
Post-employment benefit – short term	2,886	6,316
Regulatory liabilities - short term	294,428	74,898
Industry charges - short term	20,113	21,459
Estimated obligations	12,631	17,167
Onerous concession - short term	-	191,325
Other liabilities – short term	36,837	46,199
Current liabilities	1,787,422	2,031,588
Suppliers - long term	3,060,507	3,421,566
Loans – long term	607,023	940,637
Payable taxes	3,955	4,260
Advance for future capital increase (AFAC)	245	-
Provisions for lawsuits	134,772	172,184
Indemnification obligations - long term	142,624	152,339
Other liabilities – long term	42,199	47,439
Non-current liabilities	3,991,325	4,738,425
Capital stock	1,325,124	1,325,369
Other comprehensive results	213	(4,124)
Accumulated losses	(1,781,895)	(2,617,163)
Net equity	(456,558)	(1,295,918)
Total liabilities	5,322,189	5,474,095
Source: Audited trial balances


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*Exhibit V* – *Income Statement*



Income Statement

In R$ thousand	FY15	FY16
Net Revenue	985,921	1,484,833
Operating Cost	(1,048,754)	(1,577,006)
Cost of Electricity	(756,659)	(1,030,744)
Electricity bought for resale	(721,434)	(989,185)
Charges for use of transmission grid	(16,949)	(17,613)
Alternative Pow er Sources Incentive Program (Pro	(18,276)	(23,946)
Operations Cost	(157,363)	(347,036)
Labor, materials, and third parties services	(120,764)	(119,804)
Depreciation and amortization	(31,953)	(34,386)
Other	(4,646)	(192,846)
Construction Cost	(134,733)	(199,227)
Gross Profit	(62,833)	(92,173)
Operating Expenses/Revenues	(192,046)	(492,534)
Results from Electricity Service	(254,879)	(584,707)
Financial results	(365,421)	(250,561)
Results before equity stakes	(620,299)	(835,268)
New Replacement Value - NRV	48,532	-
IR and CSLL	10,929	-
Net profit (loss)	(560,837)	(835,268)
Source: Audited trial balances and audited financial statements


Privatization of the Eletrobras System Distribution Companies	10 agosto 2017
PwC	21

Exhibit VI – Quantified tax, labor, and social security exposures


Tax exposure

Item	Description	Exposure	Risk assessment *
1	PIS and COFINS on CCC reimbursement	677,168	Possible
2	Ancillary obligations in breach of the law	252,530	Probable
3	Non-technical energy losses	130,286	Possible
4	ICMS on CDE and Low Income subsidies	108,802	Possible
5	Write-off of PIS and COFINS credit on tariffs	64,137	Remote
6	CVA	6,529	Probable
7	ISS on sharing of infrastructure and services	3,832	Probable/Possible
Total of quantified tax exposure		1,243,284
Source: Pw C analyses
(*) Risk assessment for exposures reported in accordance w ith Loeser e Portela Advogados

Labor and social security exposure


Item	Description	Exposure	Risk assessment *
1	Outsourcing of core activity	104,488	Probable
2	PLR disqualification	32,386	Possible
3	Medical and dental care	20,037	Possible
4	Irregularities related to work days	2,336	Probable
5	Employer labor union contribution	279	Probable
6	Reimbursement of undergraduate and graduate courses	214	Possible
Total labor and social security exposure		159,740
Source: Pw C analyses
(*) Risk assessment for exposures reported in accordance w ith Loeser e Portela Advogados


Privatization of the Eletrobras System Distribution Companies	10 agosto 2017
PwC	22

Exhibit VII – Tax credit on tax loss, CSL negative basis, and temporary adjustments

The Company has not recognized in its accounting records the IRPJ and CSL deferred credit on the tax losses and on the social contribution negative basis, or on the temporary adjustments.
It is important to note that the balances of tax losses and CSL negative basis may be offset with future profits up to the limit of 30% of the taxable profit of each year (without a limit in time).
We should stress that the Company cannot use the balances of tax losses and CSL negative basis if (i) between the date of determination and offsetting there has been both a change in its corporate control and (ii) of its field of activity.
It is important to note that the tax losses and CSL negative basis balances are not reduced by the contingencies presented in this summary.


In R$ thousand	IRPJ	CSL
Tax Loss/CSL Negative Basis	2,848,693	2,848,693
IRPJ 25%	712,173	-
CSL 9%	-	256,382
Total	712,173	256,382
Source: ECF and Calculation Records


Privatization of the Eletrobras System Distribution Companies	10 agosto 2017
PwC	23

Belo Horizonte, November 1, 2017.

Gentlemen,

In furtherance of the service provision agreement, this paper is part of the services retained for Eletrobras Distribuição Rondônia privatization, ITEM 3 – “SERVICE A” (Financial & Economic Evaluation), under the BNDES Agreement.

This Report encompasses the purpose, scope, procedures and methodology used, as well as the market and operating assumptions for Valuation of Distributor and the execution of the new Concession Contract¹.

Discounted Cash Flow was the methodology used. Assumptions were adhered to, based on information delivered by the Distributors and BNDES, and on general market conditions.

The signed copies of this agreement are kept by the Contracting party.

Best regards,

Alexandre Moreira Galvão

Legal Representative & Stockholding Director

¹Statutory Law 12.783 dated January 11, 2013, Article 8, Paragraph 1 A: “When the service provider is a legal entity directly or indirectly controlled by the government, the Union will be entitled to hold such bidding procedure as described in the head section of this article, combined with the service-providing legal entity control transfer, and granting the utility contract to the new controlling shareholder for a 30-year period.” t Ceres )nteligência Financeira


TABLE L)ST


Table 1 – Other Revenue Sharing (%)	29
Table 2 – Unrecoverable Revenue per Consumption Class	31
Table 3 – Unrecoverable Revenue Limits – Neutrality of Charges	31
Table 4 - Summary of Applicable Methodologies	39
Table 5 - End 2017 Threshold for Operating Management	42
Table 6 – Assets History – Eletrobras Distribuição Alagoas 2012 to 2016	48
Table 7 - Liabilities History - Eletrobras Distribuição Alagoas 2012 to 2016	49
Table 8 - Income Statement History - Eletrobras Distribuição Alagoas 2012 to 2016	50
Table 9 - Financial Indicators 2012 to 2016	51
Table 10 – Summary of Macroeconomic Indexes	53
Table 11 – Geometric Mean of 2007-2016 Consumptions	56
Table 12 – Geometric Mean of Consumptions 2017-2047	60
Table 13 – Network Forecasting per Voltage Level 1 of 3	64
Table 14 - Network Forecasting per Voltage Level 2 of 3	64
Table 15 - Network Forecasting per Voltage Level 3 of 3	64
Table 16 – Deployment and Renewal	66
Table 17 – Private References	67
Table 18 – VMU/VNR Ratio in 2022	67
Table 19 - Investment in Replacement	68
Table 20 - Proportion of Investment Reference Companies	68
Table 21 – Distribution Investment in Maintenance prior to Tax Revision	69
Table 22 – Maintenance	69
Table 23 – Personnel Expenses Forecasting 1 of 3	75
Table 24 - Personnel Expenses Forecasting 2 of 3	76
Table 25 - Personnel Expenses Forecasting 3 of 3	76
Table 26 - Material Expenses Forecasting 1 of 3	77
Table 27 - Material Expenses Forecasting 2 of 3	77
Table 28 - Material Expenses Forecasting 3 of 3	78
Table 29 – Service Expenses Forecasting 1 of 3	79
Table 30 - Service Expenses Forecasting 2 of 3	79
Table 31 - Service Expenses Forecasting 3 of 3	79
Table 32 – Other Expenses Forecasting 1 of 3	81
Table 33 - Other Expenses Forecasting 2 of 3	81
Table 34 - Other Expenses Forecasting 3 of 3	82

Table 35 –PMSO Expense (R$ ‘000) and Network Extension (Km) of the Distributors Evaluated and


Benchmark	82
Table 36 - Estimated Upper and Lower Efficiency Limits - Ceron	83
Table 37 – Efficiency Limits of Evaluated and Private Distributors	83
Table 38 – Average of Reference Limits for the Evaluated Distributor Limits Forecasting	83
Table 39 – Payroll Realized Dec /16 (in R$ ‘000)	86
Table 40 - Voluntary Dismissal Plan (PDV) Forecasting	86

Table 41 – Offsetting History of the Evaluated Distributor and its Benchmarks and Forecasting of the Evaluated


Distributor		90
Ceres )nteligência Financeira		x


Table 42 – Offsetting History of the Evaluated Distributor up to the Benchmark Group Average	90
Table 43 – Offsetting Evolution of the Evaluated Distributor and Comparison with the Target 1 of 3	91
Table 44– Offsetting Evolution of the Evaluated Distributor and Comparison with the Target 2 of 3	91
Table 45 – Offsetting Evolution of the Evaluated Distributor and Comparison with the Target 3 of 3	91
Table 46 - Financings (1 of 4)	93
Table 47 - Financings (2 of 4)	94
Table 48 - Financings (3 of 4)	95
Table 49 - Financings (4 of 4)	96
Table 50 - RGR fund financing premises	97
Table 51 – RGR Releases	97
Table 52 – Net Debt Balance	98
Table 53 - Due Diligence Contingencies	99
Table 54 - Power Purchase Agreements	100
Table 55 – Definition of Other Revenues	102
Table 56 – Details on Other Revenues in the Trial Balance Sheet (in R$ ‘000)	103
Table 57 – Initial and Final Rate of Fully Depreciated Assets over the VNR	114
Table 58 - Regulatory Remuneration Base 4CRTP (R$ ‘000) – Ceron	115
Table 59 – Operation of Assets (R$ ‘000) 3CRTP to 4CRTP – CEAL	116
Table 60 - ANEEL Adjustments 3CRTP – Incremental Base – CEAL	116
Table 61 - ANEEL 3CRTP Adjustments – Incremental Base – Cemar (Benchmark)	117
Table 62 - ANEEL 3CRTP Adjustments - Incremental Base – Celpa (Benchmark)	117
Table 63 - NEEL Adjustment Average, Benchmarks Group 3CRTP - Incremental Base	117
Table 64 - ANEEL 3CRTP Adjustments - Incremental Base – Eletroacre	118
Table 65 - ANEEL 3CRTP Adjustments - Armored Base – Amazonas Energia	118
Table 66 - ANEEL 3CRTP Adjustments - Armored Base – Ceron	119
Table 67 - ANEEL 3CRTP Adjustments - Armored Base – Eletrobras Roraima	119
Table 68 - ANEEL Adjustment Average, Group Evaluated Distributors 3CRTP - Armored Base	119
Table 69 – Balance of the Ceron Fixed Assets in Progress in Jun/17	121
Table 70 – Indemnification Forecasting	122
Table 71 – Tax Loss Balances and CSL Negative Base	122
Table 72 – Special Obligations Forecasting (in R$ ‘000)	124
Table 73 – History of Special Obligations and Recurrence (in R$ ‘000)	124

Table 74 - Weight Values of Indicators of Quality of Concession Holders with more than 60 thousand Consumption


Units	126
Table 75 – DEC and FEC Global Limits from 2018 to 2022, including	129
Table 76 - DEC Indicator - Realized/Forecasted x ANEEL Limits 1 of 3	130
Table 77 - DEC Indicator - Realized/Forecasted x ANEEL Limits 2 of 3	130
Table 78 - DEC Indicator - Realized/Forecasted x ANEEL Limits 3 of 3	130
Table 79 – DEC Indicator - Forecasted/Realized X ANEEL Limit 2015-2047	131
Table 80 - Realized DEC Variation Rate and Potential per Period	131
Table 81 – Benchmark Evaluation Premises	131
Table 82 – DEC Benchmark Curve	132
Table 83 - FEC Indicator - Realized/Forecasted x ANEEL Limits 1 of 3	132
Table 84 - FEC Indicator - Realized/Forecasted x ANEEL Limits 2 of 3	132
Table 85 - FEC Indicator - Realized/Forecasted x ANEEL Limits 3 of 3	132

Ceres )nteligência Financeira	y


Table 86 - FEC Indicator - Forecasted/Realized X ANEEL Limit 2015-2047	133
Table 87 - Realized and Potential FEC Variation Rate per Period	133
Table 88 – Benchmark Evaluation Premises	134
Table 89 - FEC Benchmark Curve	134
Table 90 – FER Indicator - Realized/Forecasted x ANEEL Limit 1 of 3	135
Table 91 - FER Indicator - Realized/Forecasted x ANEEL Limit 2 of 3	135
Table 92 - FER Indicator - Realized/Forecasted x ANEEL Limit 3 of 3	136
Table 93 - FER Indicator - Forecasted/Realized X ANEEL Limit 2015-2047	136
Table 94 – Realized and Potential FER Variation Rate per Period	136
Table 95 - FER Realized Benchmark	137
Table 96 - FER Realized Benchmark Group	137
Table 97 - IASC Indicator – Realized/Forecasted x Target 1 of 3	138
Table 98 - IASC Indicator – Realized/Forecasted x Target 2 of 3	138
Table 99 IASC Indicator – Realized/Forecasted x Target 3 of 3	139
Table 100 - IASC Indicator - Forecasted/Realized X ANEEL Limit 2015-2047	139
Table 101 – Realized and Potential IASC Variation Rate per Period	139
Table 102 - IASC Realized Benchmark	140
Table 103 - IASC Realized Benchmark Group	140
Table 104 - INS Indicator - Realized/Forecast x Target 1 of 3	141
Table 105 - INS Indicator - Realized/Forecast x Target 2 of 3	141
Table 106 - INS Indicator - Realized/Forecast x Target 3 of 3	142
Table 107 - INS Indicator - Forecast/Realized X ANEEL Limit 2015-2047	142
Table 108 – Realized and Potential Variation Rate of INS per Period	142
Table 109 - INS Realized Benchmark	143
Table 110 – Group of Benchmark of INS Realized	143
Table 111 - IAb Indicator – Realized/Forecast x Target 1 of 3	144
Table 112 - IAb Indicator – Realized/Forecast x Target 2 of 3	144
Table 113 - IAb Indicator – Realized/Forecast x Target 3 of 3	145
Table 114 - IAb Indicator - Forecast/Realized X ANEEL Limit 2015-2047	145
Table 115 – Realized and Potential Variation Rate of IAb per Period	145
Table 116 – Benchmark of IAb Realized	146
Table 117 – Group of Benchmark of IAb Realized	146
Table 118 - ICO Indicator – Realized/Forecast x Target 1 of 3	148
Table 119 - ICO Indicator – Realized/Forecast x Target 2 of 3	148
Table 120 - ICO Indicator – Realized/Forecast x Target 3 of 3	148
Table 121 - ICO Indicator - Forecast/Realized X ANEEL Limit 2015-2047	148
Table 122 –Realized and Potential ICO Variation Rate per Period	149
Table 123 – Benchmark of ICO Realized	149
Table 124 – Group of Benchmark of ICO Realized	149
Table 125 – Evolution and Impact of the X Factor Components	152
Table 126 – Calculation of Regulatory WACC	153
Table 127 – Calculation of the Cost of equity (Ke)	154
Table 128 – Financial Structure of the Companies	155
Table 129 - Enterprise Value and Company Debt	156
Table 130 – Weighted Cost of Debt used for the composition of Kd	156

Ceres )nteligência Financeira	z


Table 131 - CDI Bradesco Forecast	156
Table 132 – Calculation of Kd Cost	156
Table 133 – Calculation of the Weighted Average Cost of Capital (WACC)	157
Table 134 – Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2016-2027 (%)	159
Table 135 - Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2028-2037 (%)	159
Table 136 - Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2038-2047 (%)	160
Table 137 - Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2048-2052 (%)	160
Table 138 – Distribution of Total Invoicing and Not Received (in R$ '000)	160
Table 139 - Targets ANEEL per Regulatory Cycle	161
Table 140 – Level of Technical Loss and Loss in the Basic Grid.	163
Table 141 – Forecast Regulatory Losses 1 of 3	165
Table 142 – Forecast Regulatory losses 2 of 3	165
Table 143 – Forecast Regulatory losses 3 of 3	165
Table 144 – Annual Loss Decrease Rate Definition: Benchmark Company CEMAR	166
Table 145 – Starting Point and Target of Non-Technical Losses	166
Table 146 – Forecast Real Losses 1 of 3	166
Table 147 – Forecast Real Losses 2 of 3	166
Table 148 – Forecast Real Losses 3 of 3	167
Table 149 – Initial Balances of the Working Capital	168
Table 150 – Parameters of forecast NCG	169
Table 151 – Benchmark operating due dates North Region	169
Table 152 – Balances with special treatment	170
Table 153 – Settlement of Long-Term Balances	170
Table 154 - Sectorial Charges	171
Table 155 - Transmission Costs	172
Table 156 - Benchmark Revenue and Annual Revenue	172
Table 157 - CVA	173
Table 158 – Solvency Indicator	174
Table 159 – Evolved Gross Income	175
Table 160 – Default	176
Table 161 - Operating Costs and Expenses	177
Table 162 – Costs versus EBITDA	177
Figure 163 – Evolved Costs with Power Purchase	178
Figure 164 – Evolved Transmission Costs	179
Table 165 – PMSO Expenses	180
Table 166 – Analysis of Net Revenue, Costs and Gross Margin	182
Table 167 – Evolved EBITDA, Gross Profit and Expenses	183
Table 168 – Summary Financial Indicators 2017 to 2026 (1 of 3)	184
Table 169 – Summary Financial Indicators 2027 to 2036 (2 of 3)	184
Table 170 – Summary Financial Indicators 2037 to 2047 (3 of 3)	184
Table 171 – Forecast DRE Eletrobras Distribuição Rondônia	185
Table 172 – Forecast Indirect Cash Flow Eletrobras Distribuição Rondônia	186
Table 173 – Forecast Cash Flow to Firm Eletrobras Distribuição Rondônia	187
Table 174 - Results from Appraisal Eletrobras Distribuição Rondônia	188
Table 175 – Valuation Components	188

Ceres )nteligência Financeira	{


Table 176 – Adjusted Enterprise Value	189
Table 177 – Forecast Cash and Gross Debt Balance	189
Table 178 - WACC and BRRL Sensitivity – Enterprise Value	190
Table 179 - WACC and BRRL Sensitivity – Valuation	190
Table 180 – Data from Eletrobras Distribuição Rondônia for appraisal by multiples (R$’000)	191
Table 181 - Multiples Companies Privatized from 1997 to 2000	193
Table 182 - Enterprise Value from the Multiples of Companies Privatized from 1997 to 2000 (R$’000)	193
Table 183 - Multiples Publicly Held Companies	195
Table 184 - Enterprise Value from the Multiples of Publicly Held Companies (R$’000)	195
Table 185 - Multiples CELGD	196
Table 186 - Enterprise Value from Multiples of CELG D (R$’000)	197
Table 187 - Multiples from Share Transfer	199
Table 188 - Enterprise Value of Multiples from Share Transfer (R$’000)	199
Table 189 - Date of Privatization of Comparable Companies	200
Table 190 - Multiples Privatizations from 1997 to 2000	201
Table 191 - Multiples Foreign Transactions	202
Table 192 - Enterprise Value Foreign Transactions	203
Table 193 – Median of Multiples (1 of 2)	204
Table 194 - Median of Multiples (2 of 2)	204
Table 195 - Enterprise Value from the Median of Multiples (R$’000)	205
Table 196 – Market Discount Rates	207
Table 197 – VMU/VNR Ratio 2022 - Machinery and Equipment	208
Table 198 – Grouped Personnel (PMSO) and Realized Accounts 2012-2016 1 of 2	211
Table 199 – Grouped Personnel (PMSO) and Realized Accounts 2012-2016 2 of 2	211
Table 200 – Grouped Materials (PMSO) and Realized Accounts 2012-2016	212
Table 201 – Grouped Service (PMSO) and Realized Accounts 2012-2016 1 of 2	214
Table 202 – Grouped Service (PMSO) and Realized Accounts 2012-2016 2 of 2	215
Table 203 – Grouped Others (PMSO) and Realized Accounts 2012-2016 1 of 3	216
Table 204 – Grouped Others (PMSO) and Realized Accounts 2012-2016 2 of 3	217
Table 205 – Grouped Others (PMSO) and Realized Accounts 2012-2016 3 of 3	218
Table 206 – Re-rating of Asset Balances	219



Table 207 - Re-rating of Liabilities ^BalancesF)GURE L)ST	220

Figure 1 – Owners’ Equity Cost (Ke) Breakdown	35
Figure 2 - Gross Margin and EBITDA Margin 2012 to 2016	52
Figure 3 – Indebtedness Index and Historical Composition 2012 to 2016	52
Figure 4 – Consumption History per Class	56
Figure 5 – Composition of the Power Consumption Comparison	56
Figure 6 - 2047 Total Power Consumption Composition	60
Figure 7 – Power Consumption Forecasting	60
Figure 8 – Consumption Units Forecasting	61
Figure 9 – Voltage Level Percentages	62


Ceres )nteligência Financeira	sr

Introduction

Purpose

The purpose of this paper is to issue a Financial & Economic Evaluation Report on Eletrobras Dis-tribuição Rondônia and on the execution of a new Concession Contract, in order to shore up the accurate dimensioning and provide technical support in the business deals of the Company.

The purpose of the financial evaluation, besides the main point of determining the business Valuation, is to present scenarios, existing synergies for the business, and value possibilities that may be perceived by the market, as well as associated liabilities. From the company’s viewpoint, the discounted cash flow method reckons in numbers and at present value the whole dimension of the business, on a realistic basis, and taking into account potential points of exploitation of the concession contract, in view of the current structure.

Added hereto are the sensitivity analysis and the risk analysis, in addition to other valuable methods, such as comparative evaluation by multiples or similar transactions, aiming at reaching the clearest perception of the business value interval and possible structures that could make the transaction more efficient, both for the buyer and the seller.

Disclaimers

The job described in this paper was developed according to information obtained from sources appointed by Eletrobras Distribuição Rondônia and data delivered by ANEEL.

This evaluation does not take into account the penalties for electricity over-contract by the enterprise at issue, because it was assumed that the new utility company could afford settling its positions at market prices. Ceres hereby highlights that sudden changes in macroeconomic indicators and electricity prices may have some bearing on the values pointed out herein.

Please note that this paper does not contain a Compensation Basis added by the enterprise’s current PP&E positions. The accounting entries covering the current PP&E positions may be found in section “Comments on Current Assets” for invertors’ information.

Ceres )nteligência Financeira

Methodology

Evaluating a distributor is based on the set of regulations making up the tariff review base applicable to inter-cycle tariffs and tariff readjustments, as well as on the economic pillar of effective forecasts, especially about costs incurred and capital invested. The set of regulations gives direction to the Required Revenue, which is the criterion to set the tariffs used by the distributors. Such tariffs arise from tariff reviews, decomposed from Installment A (non-manageable costs) and Installment B (manageable costs).

Tariff reviews are based on “tariff moderateness” and “continued award to efficiency” principles, with the different complexity/size areas being taken into consideration.

Costs and expenses, taxes, working capital, provision for indemnities and contingencies, and real disbursements supplement the economic flow, to be dimensioned in forecast and at present value, for business analysis.

Please find below some directives forming the tariff review base, dimensioned at the Tariff Level and specified in PRORET (Portuguese acronym standing for “Tariff Regulation Procedures”). The cash flow and the capital cost definition methods used in this evaluation are detailed below. As a final point, find our comments on this paper’s directives for specific approaches and risk analysis.

Ceres )nteligência Financeira

PRORET (Tariff Level)

General Procedures

Electricity distribution public service utility companies (hereinafter referred to as “distributors”) tariff level in Brazil is regulated by ANEEL as stipulated in PRORET documentation. This section summarizes the main methodological elements of the Tariff Review Process according to PRORET Submodule 2.1 (version 2.2 effective as of 6/27/2016) and the Tariff Readjustment Process according to PRORET Submodule 3.1 (version 1.4 effective as of 3/28/2016).

This paper contains a description of the forecast methods per element of Installment A and Installment B, while this section is dedicated to tariff calculation methodological indication.

Tariff Review

The Required Revenue calculated in the distributors’ tariff level definition comprises the sum of two installments, namely Installment A and Installment B.

44 L 82# E 82$

Where: ·

· ·

44 means Required Revenue;

82# means Value of Installment A, which comprises the costs related to the electricity genera- _82$and means transmission Value of Installment business, including B, which own comprises generation typical and costs industry-related of distribution charges; and customer management.

Installment A is obtained by the sum of the following elements:

82# L %' E %6 E '5


Where: ·	82# means Value of Installment A;
· ·	^%'%6 means means cost cost of of connection electricity acquisition to and use and of distribution/transmission own generation;	systems;
·	'5 means industry-related charges defined in specific law;

Value of Installment B is calculated in the tariff review process, according to distributor’s review schedule


(every five years), in line with the following equation:
82$ L :%#1/ E %##; H :s F 2à F /+3; F 14
Where: ·	82$ means Value of Installment B;
· ·	%## %#1/ means means Annual Administration, Cost of Assets; Operation & Maintenance Cost;

Ceres )nteligência Financeira		sv


		·	_/+32à means means 2× in Market the Quality X Factor Adjustment Improvement (Submodule Factor, Incentive 2. calculated 5); Mechanisms with the same calculated calculation with the methodology same calculation as ele-
		·
		·	methodology14 means Other as element Revenue, Q in calculated the X Factor according (Submodule to Submodule 2.5); 2.7;

Administration, Operation & Maintenance Costs are comprised of the following elements:

%#1/ L %1 E 4+


Where: ·		%#1/ means Administration, Operation & Maintenance Cost;
· ·		^%14+ means Other operating Unrecoverable costs Revenue;

The Annual Cost of Assets is calculated by the sum of the following elements:

%## L 4% E 344 E %#+/+

Where: ·

· · ·

%## means Annual Cost of Assets;

^4%₃₄₄means means Yield Statutory on Capital, Reintegration including Quota; income taxes and contributions; %#+/+ means Annual Cost of Property & Equipment;

Yield on Capital is calculated through the following equation:

4% L :$44H F 4)4; HNêÔÖÖ E4)4 HNåÚå E4%È¾

ÛÝé


Where: ·		4% means Yield on Capital;
· ·		^$44H4)4 means means the Statutory debt balance Net Yield of the Base, Global according Reversal to Submodule Reserve; 2.3;
· · ·		_NN_åÚå^êÔÖÖmeans ÛÝé means RGR Real capital Capital cost, Weighted weighted Average per destination Cost before (PLPT Taxes, and according non-PLPT), to Submodule according 2.4; to Submodule4%È¾ means 2.4; Yield on Investments obtained from Special Liability funds.

Yield on Investments obtained from Special Liability funds is calculated through the following equation:

%#1/

4% _LN_sFPF NÙ Hr,wH2 H ~~_È¾~~H1'5

È¾ ~~%#1/ E %## F 4%~~ Õ


Where: ·	_N4% means È¾ means Owners’ Yield on Equity Investments Cost (nominal); obtained from Special Liability funds;
· ·	NÙ ã means Yield on risk-free Assets (nominal);
· ·	^P₂means means Income Owners’ Taxes Equity and Share Contributions; in Total Equity;
· ·	_%##%#1/ means means Annual Administration, Cost of Assets; Operation & Maintenance Cost;
·	1'5Õ means Gross Special Liabilities;

Ceres )nteligência Financeira		sw

The Statutory Reintegration Quota corresponds to the installment that takes into account depreciation and amortization of investments made, and recomposes the assets assigned to the service provision over their lifespan. It is calculated through the following equation:

344 L $44> H Ü

Where:

· 344 $44>means Statutory Reintegration Quota;·· means Statutory Gross Yield Base;

Ü means Facilities depreciation average rate, calculated based on Table XVI in the Annex to the Electricity Market Equity Control Manual (MCPSE) approved by REN 367/2009 – ANEEL.

Annual Cost of Property & Equipment refers to short-term recoverable investments, such as investments in hardware, software, vehicles and office building infrastructure.

%#+/+ L %#. E %#8 E %#+


Where: ·		%#+/+ means Annual Cost of Property & Equipment;
· ·		_%#8%#. means means Annual Annual Cost Cost of of Rents; Vehicles;
·		%#+ means Annual Cost of Computer Systems;

Annual Cost of Rents is calculated through the following equation:

_Hds _ENÐº¼¼ %#. L $#4º ₈₇_tÛÝé h

Where: ·

· ·

%#. means Annual Cost of Rents;

$#4º means the statutory annuity base amount regarding investments in office building infra- structure,87 means as the per lifespan, Submodule as defined 2.3; in Table XVI of the Annex to the Electricity Market Equity Control Manual (MCPSE).

Annual Cost of Vehicles is calculated through the following equation:

_Hds _ENÐº¼¼ %#8 L $#4Ï ₈₇_tÛÝé h

Where: ·

· ·

%#8 means Annual Cost of Vehicles;

$#4Ï means the statutory annuity base amount regarding investments in vehicles, as per Sub- module87 means 2.3; the lifespan, as defined in Table XVI of the Annex to the Electricity Market Equity Control Manual (MCPSE).


Annual Cost of Computer Systems is calculated through the following equation:
%#+ L $#4Â H^d₈₇^s	_EN^Ðº¼¼t ^ÛÝéh
Where:
Ceres )nteligência Financeira		sx

Annual Tariff Readjustment

Every year where there is no Ordinary Tariff Review, the adjustment formulas contained in Submodule 3.1 in PRORET are to apply. In such years, VPB is not calculated, but adjusted for money value at IGP-M and also considering the X Factor.

In its turn, Installment A is calculated by taking into account the conditions on the Former Reference Date (DRA) and the Reference Market, as follows:

1.	For electricity bought: “Electricity Bought” amount valued at “Average Price of Transfer” consid- ered in the former year’s readjustment or review;
2.	For connection to distribution/transmission systems and for TUSDg-T and TUSDg-ONS ele- ments: values considered in the former year’s readjustment or review;
3.	For use of distribution/transmission systems: amounts of power demand retained in the refer- ence period and associated electricity, valued at the respective tariffs considered in the former year’s readjustment or review; and
4.	For the other items in Installment A: values resulting from applying the relevant tariff elements, in force on the Former Reference Date (DRA), to the Reference Market, so as to assure eco- nomic neutrality of industry-related charges.

Value of Installment A, given the current juncture on the in-processing readjustment date (DRP), and the Reference Market, is calculated from different tariffs according to the electricity source, i.e., own generation, PROINFA, Itaipú and other agreements and contracts.

Value of Installment B, given the current juncture on the Former Reference Date (DRA), and the Refer-

ence Market, is calculated as follows:

82$4 L4#4 F82#4


Where: ·		_4#82$4 means Installment B in current juncture on DRA;
· ·		82#₄means means Annual Installment Revenue A in on current DRA juncture or “Reference on DRA; Revenue”;

Value of Installment B, given the current juncture on the in-processing readjustment date (DRP), is


calculated as follows:
82$5 L 82$4 H :+)2/ F :;

Where: ·	^82$82$⁵means Installment B in current juncture on DRP;
· ·	_+)2/means means Installment General Price B in Index current by juncture Getúlio Vargas on DRA; Foundation (FGV);

Ceres )nteligência Financeira		sz

Operating Costs

Abstract

At this stage, we calculated items related to the tariff level cost elements. The operating costs calculated for the distributor take into account the own costs and the other distributors’ costs. The other distributors are included in the calculation to form the efficient cost target of the distributor under evaluation. The Statutory Operating Costs are forecasted from two angles:

1.	Statutory Cost from Nov/2017 to Nov/2023 equivalent to such value as specified in Technical Note 149/2017 SRM/SGT/SRD/SFF/ANEEL;
2.	Statutory Cost calculation from Nov/2023 through such methodologies as described in Submod- ules 2.2 and 2.2-A of PRORET, considering the information obtained from RT 2013, SAMP, BDGD and Financial Statements as the reference values.

Accordingly, the operating costs calculation as of 2013 adhered to the following brief plan of work:

1.	Collect data from ANEEL documents;
	a.	PRORET submodule 2.2
	b.	PRORET submodule 2.2-A
	c.	APPROVAL RESOLUTION # 1.858 DATED FEBRUARY 27, 2015;
	d.	Technical Note 409/2013-SRE/ANEEL;
2.	Market Data Collection from SAMP (Economic Regulation Market Information Monitoring Sys- tem);
3.	Data Collection of distributor’s structure from BDGD (Distributor’s Geographic Database);
4.	Data Collection from the two most-recent annual Financial Statements available;
5.	Updating Factor Calculation based on the methodology of Module 2.2, V2.0, PRORET;
6.	Efficient Costs Interval Calculation;
7.	Operating Costs Target Definition;
8.	Operating Costs Revenue Calculation;
9.	Report containing all the calculations made and results obtained upon the application of the proposed methodology;

Please find below a detailed description of such stages.

Database

Inputs

The Operating Costs calculation required:


1. Information about Cycle 3 Installment B review and parameters, applicable to Distributor;
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2.	Submodules 2.2 and 2.2-A of PRORET;
3.	Statutory PMSO, effective from Nov/2017 to Nov/2023, according to Technical Note 149/2017- SRM/SGT/SRD/SFF/ANEEL and Technical Note no. 293/2017-SGT/ANEEL;
4.	Data on underground network, air distribution network, high voltage network, consumer-units, weighted market, non-technical losses, discontinued consumer/hour, regarding the next tariff review;
5.	Access to SAMP;
6.	Data from BDGD.

Operating Costs Revenue Calculation

Inputs

Additional revenue in connection with operating costs from Nov/2017 to Nov/2023 corresponds to the amount entered in the last column of the table in Item 43 of Technical Note 149/2017 SRM/SGT/SRD/SFF/ANEEL. As specified in TN 149, the additional revenue amounts are adjusted at IPCA from the 2016 tariff process through the 2017 tariff process date; after that period, Installment B is adjusted at IGP-M and the X Factor.

Data required for Operating Costs Revenue calculation as of 2023 were taken from the technical note of the most recent tariff review of Distributor:

1.	Value of operating costs approved in the most recent tariff review, adjusted;
2.	Value of Installment B in the most recent tariff review;
3.	X Factor’s T Element in the most recent tariff review;
4.	Installment B revenue in the test-year; (it is calculated based on the distribution tariffs arising from the tariff opening of the most recent readjustment, applied to the market in the test-year);
5.	Number of years in the utility company’s tariff cycle.


Calculation Methodology %1ºç _L%1ËØé ^F_82$82$^ËØé:_s:^s_F^F₆:s^F;_Ç?56ËØé ;^{Ç?5 ;}. 82$ºç
ËØé	ËØé

Where:

%1 operating costs revenue in the test-year;

%1ºç value of operating costs approved in the most recent tariff review, adjusted;

ËØé

: value of Installment B in the most recent tariff review;

82$ËØé 6

X Factor’s T Element defined in the most recent tariff review;

82$ test-year;

Installment B revenue in the

ºç

N: number of years in the utility company’s tariff cycle.

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Results

Based on such calculations, we tried to identify the magnitude relating to the statutory operating costs in Installment B formation in the most recent review;

Operating Costs Target Calculation

Inputs

1.	Result of operating costs revenue calculation;
2.	Efficient statutory operating costs ceiling;
3.	Efficient statutory operating costs floor;
4.	Real Average OpEx (for average OpEx calculation, the average value of real operating costs, in the two consecutive years nearest the tariff review, considering the most recent information available, with money value adjustment at IPCA, through the tariff review date, was taken into account).

Calculation Methodology _%1

ØÙ Lmin:max:%1ºç ;.+;;.5;

Where:
%1
: Efficient statutory operating costs value;
.5 ØÙ
: Efficient statutory operating costs ceiling;
: Efficient statutory operating costs floor;
.+

and

%1 L min Ln^¿_¨%1ØÙ Fsn;w%M
%1ºç


and		%1çÔåÚØç L %1ºç :s G %1;^Ç
_%1%1:Where:_çÔåÚØçstatutory : operating operating costs costs target annual adjusted fluctuation; to annual fluctuation ceiling;
and
		%12çÔåÚØç _Ls.t. 1LAT^ÔéÚ_tE %1çÔåÚØç

Where:

%12

: statutory operating costs target with sharing;

1LAT çÔåÚØç:

real operating costs average;

ÔéÚ

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Results

The efficient operating cost value was defined by comparing the operating costs revenue at the time of the review with the efficient operating costs interval for the utility company at issue.

Efficient Costs Interval

Inputs

1.	Efficiency reference (76% as per PRORET);
2.	OpEx (Annex II in PRORET);
3.	Statutory operating costs ceiling;
4.	Statutory operating costs floor;
5.	Efficiency interval ceiling calculated for the company;
6.	Efficiency interval floor calculated for the company;
7.	Updating factor.

Calculation Methodology

_.5L _{Ù .}^àà^æèã.1LAT .+ L ^{Ù .}_ààÜáÙ ~~åØÙ~~ .1LAT

~~åØÙ~~

.5: Where: Statutory operating costs ceiling;

_à^.+à_æèãStatutory : Efficiency operating interval costs ceiling floor; calculated for the company;

^à1LAT:^ÜáÙ: Efficiency Efficiency Company’s interval reference; real operating floor calculated cost used for the to calculate company; efficiency;

Ù: Updating factor.

Results

The efficient cost intervals were used to calculate the Operating Costs Target.

Updating Factor

Inputs

1.	Product weight in “t” and “t+1”;
2.	Input weight in “t” and “t+1”;
3.	Company’s scale factor in “t” and “t+1”;
4.	Products in “t” and “t+1”.

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Calculation Methodology

1LATØÙ ^L_Q^sLÍ_Ý@5^àRÝ UÜ E îM

1LAT Where: U ^ØÙ: the efficient cost estimated for the utility company;

_I_:Q R_Ý^Ü: : weight weight company’s total products; assigned assigned product to to the product “j”; input; “j”;

î: company’s “scale factor”.

Ù _L^1LAT~~1LAT~~^ØÙç>5~~_ØÙ~~ç _.^+2%#+2%#^ç>5ç

Where:

1LAT_ØÙ

_ØÙ^ç>5ç : efficient cost estimated on the tariff review base date;

1LAT efficient cost estimated on the efficiency calculation base date;

: IPCA index number in the month preceding the tariff review base date;

+2%#^ç>5+2%#^ç

: IPCA index number in the month preceding the efficiency calculation base date.

Results

The Updating Factor was used to calculate the efficient cost intervals.

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The X Factor Calculation

The X Factor is mainly aimed at assuring that the balance between efficient revenues and expenses, set at the time of the tariff review, is maintained during the tariff cycle.

The approach adopted by ANEEL to calculate the X Factor aims to define it from potential productivity gains compatible with the market growth level, the number of consumer-units, and the service quality, in addition to fostering a transition of efficient operating costs.

In order to meet that purpose, the X Factor is comprised of three elements, namely:

(=?PKN L 2× E3 E6

Whe _{: P}r e: oductivity gains from distribution; Q: Technical and commercial quality of the service delivered to consumers;

T: Operating costs trajectory:

The Pd and T elements are defined ex ante, i.e., at the time of the tariff review. The T element calculation rule is described in Submodule 2.2 – Operating Costs. The Q element is specified per tariff repositioning ex post with technical and commercial quality data for the two previous years, available in April each year.

Productivity gains from distribution (Pd)

Inputs

1.	Total productivity of factors;
2.	Electricity variation invoiced by the utility company between the last two cycles;
3.	Growth of electricity invoiced by the market between the last two cycles;
4.	Variation of the utility company’s consumer-units between the last two cycles;
5.	Variation in the number of consumer-units in the market between the last two cycles.

Methodology

2 :E; L26(Er.svHk /9D:E; F $$$$$$$$$oFr.rvH: 7%:E; F $$$$$$;

PTF: Average productivity of the distribution segment at s.wu% p.a.; f f

MWhi: Market average annual variation of utility company òió from the former tari review through the MWh : Distributorsï market average annual variation at v.xw% p.a.; current tari review; UC:i;: Average annual variation of in the number of consumer units invoiced by the utility company òió f f

_{UCi: Average annual variation in the number of consumer}units at u.u{% p.a.; from the former tari review through the current tari review;

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Results

With the X Factor’s Pd Element, the review may comprise the potential productivity gains arising from electricity distribution, estimated from the ratio between market growth and increased costs of that business.

Please note that in the evaluation such factor will be set at zero between the agreement execution date and the first subsequent ordinary tariff review, as highlighted in the draft²agreement.

Technical and commercial quality of service delivered to consumers (Q)

The technical and commercial quality (the Q element) incentive mechanism is specified every tariff readjustment ex post with the technical and commercial quality data for the last two years, available in April each year.

Operating costs trajectory (T)

The X Factor’s T Element is aimed at setting a trajectory in the statutory operating costs definition. Essentially, it is a transition between different methodologies to set the efficient operating costs. The operating costs calculation methodology is described in section “Operating Costs”.

Inputs

1.	Operating Costs Revenue;
2.	Operating Costs Target;
3.	Current tariff review Installment B value;

Calculation Methodology

%1 L%1 _Ek%1çÔåÚØç F %1ºço

ã ºç

6ã L Ls F ^¿7-_¨~~^%1~~%1~~^çÔåÚØç~~_ãM^H~~_82$~~%1 _ã

Where:

²Draft Agreement, Official Letter 113/2017-DR/ANEEL, 05/03/17, from Romeu Donizete Rufino, Procedure 48510.000502/2017-00, Clause 19 – Transient Provisions, Section 3, Item I: “The value of the X Factor’s Pd Element shall be set at 0 (zero)”.

tx Ceres )nteligência Financeira

_{: operating costs revenue in the test}year;

%1ã: statutory operating costs value to be taken into account in the current tari review;

%1ºç f

%1 : operating costs target adjusted to annual fluctuation ceiling; N: number of years in the utility companyïs tari cycle; f_{review )nstament B value.}6 : the X factorïs operating costs òtrajectoryó element for the current review; 82$ã: current tari

Results

The result of the abovementioned calculations is the X Factor’s operating cost “trajectory” element. The T element was used to deduct or add part of the operating costs from or to the tariffs, gradually, over the Distributor’s review cycle.

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Other Revenue Calculation

Other Revenue calculation to be taken into account in the tariff readjustment is based on Submodule 2.7, V2.1, in PRORET. By definition, “Other Revenue” is classified in two groups, namely: (1) Revenue inherent to electricity distribution service; and (2) Revenue from other business segments. Each type of Other Revenue account has a revenue sharing ratio defined by PRORET, which is used to calculate the Other Revenue value to be discounted from Installment B in the tariff review process, with a view to encourage the service provision efficiency.

82$ L :%#1/ E %##; H :s F 2à F/+3;F 14

CAOM Administration, Operation & Maintenance Cost; CAA: Annual Cost of Assets;

M)Q: Quality )mprovement )ncentive Mechanism; and 2 : Market Adjustment Factor; OR: Other Revenue.

Revenue inherent to electricity distribution service

Non-tariff revenue related to electricity supply, invoiced with billable services. The sharing of such revenue was 60% (of gross revenue) assigned to consumers of the distribution service and 40% to the utility company, with a view to encourage the service provision efficiency.

Revenue from other business segments

Revenue from activities of an economic nature that is accessory to the concession contract or permit agreement, performed for its own account and risk.

Proper Accessory Activities: regulated activity delivered by the distributor only and subject to inspections.

The sharing of revenue from proper accessory activities was 60% (of gross revenue) assigned to consumers of the distribution service and 40% to the utility company, with a view to encourage the service provision efficiency. Such amount was discounted from Installment B, variable Other Revenue (OR).

Complementary Accessory Activities: non-regulated activity, the delivery of which is related to the distribution service fruition, and which may be delivered either by the distributor or by third parties, subject to the consumer code rules and antitrust laws.

The sharing of revenue from complementary accessory activities was 60% (of gross revenue) assigned to consumers of the distribution service and 40% to the utility company, with a view to encourage the

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Discounted Cash Flow

Introduction

The technique used for evaluation is based on the Discounted Cash Flow methodology, which is supported on the hypothesis that the value of a project depends on its capacity to generate wealth in the future. Revenues, costs, expenses, investments and other working capital requirements are estimated, in addition to all the items that affect the enterprise’s cash fluctuation, for a given period of time.

Seeing as the generated cash flow values occur in different time spans, these must be summed and compared in a current equivalence. Thus, the net balances reckoned per period are taken to present value at a discount rate reflecting the risks inherent to the business, added by the risk-averse investors opportunity cost, i.e., an attractiveness rate reflecting the business capital providers opportunity cost.

Such rate is given by value parameters generally offered by government bonds, incorporates the specific risk of the business, and is calculated based on CAPM (Capital Asset Pricing Model). By that model, the project owners’ equity (Ke) cost is calculated.

To calculate the project values, the owners’ equity cost (Ke) is weighted with the third-parties’ equity cost (Kd), in proportion to the capital structure used in the project, resulting in the enterprise’s WACC (Weighted Average Cost of Capital).

There are different versions of the Discounted Cash Flow methodology, and this paper adheres to the Free Cash Flow to Firm (FCFF) approach.

Free Cash Flow to Firm – FCFF

The Free Cash Flow to Firm approach uses the weighted average capital cost (WACC) to discount at present value the free cash flow to firm. Hence, all resources available for dividend distribution or reinvestment are taken into account, but amortization flows and third-party debt interests paid are not considered, the yield on which is implied in estimated WACC rate. The firm flow is recommended for the evaluation at issue because it foresees the likelihood of permanent leverage over the concession contract period.

Capital Asset Pricing Model – CAPM

Introduction

The owners’ equity cost (Ke) calculation is primarily based on the business risk analysis, added by the economy’s risk-free yield rate, generally given by the yield offered by government bonds.

At first, companies of the industry serve as the basis, measuring the price fluctuation of their shares in the money market, against the economy oscillations, mirrored on some market index, for instance.

One of such measures is by Beta, which represents a multiplier in relation to the return fluctuations of companies in a given segment in relation to the market and is equivalent to the risk of the segment analyzed. Primarily, we take a weighted average of such measure for the industry, excluding the indebtedness weight. That indicator represents an average and time relation between the returns on the shares selected in relation to the economy, which was highlighted here by the S&P500 returns fluctuation, an index that captures a good deal of transactions in the US market. Therefore, compared are the fluctuations of the prices in dollars of the shares in the public companies that operate in the same industry as the enterprise analyzed, with the S&P500 index fluctuations.

The purpose of this process is to obtain the additional risks of the business at issue in relation to the economy. Therefore, the result of the return expected and required on the business would be a risk free yield rate, in line with the rates offered by the government, added by the economy rate in general, plus the profits or minus the losses of the business, in comparison with the economy as a whole. Hence, a single rate synthesizes the yield required by a business, contemplating all the risks inherent in their fluctuations of income and cash, and adds the gains on zero risk investments, given in traditional short-term investments offered by the government.

Whereas we used indexes present in the US and global economy, calculated in dollars, considering the purpose of accuracy of inter-industry risk levels, therefore, utilization and supplementation in calculating the risks present in Brazilian interest rates in relation to the global market are necessary.

For risk-free and government rates, we used the 10-year US treasury bonds, marked to market continuously (Constant Maturity Bond). Thus, the risk elements present in the Brazilian interest rate, as the uv Ceres )nteligência Financeira

country risk premium, regarding the credit risk in the Brazilian Economy against the global market, and the exchange risk, showing the uncertainties about the R$ fluctuation against the USD, must be included. Both of them are already included in SELIC interest rate or government bonds with future maturities, the reason for such inclusions, for they represent the risk-free opportunity cost in Brazil.

For the country risk premiums, we used the difference between FRA for Exchange Coupon, contracts traded in BM&F-BOVESPA, and the Risk Free Rate calculated through the Treasury Bonds.

In order to calculate the exchange risk premium, we used the real difference between the DI – 1-day contracts, FRA for Exchange Coupon, denominated in Forward Premium, both the agreements traded in BM&F-BOVESPA, and which translate the expected price fluctuations between the Brazilian interest rates in the future market against Brazilian external fund-raising in USD. Hence, it is impossible to obtain, from its quotation, the exchange premium, after the adjustments for inflation between the countries (IPCA minus CPI forecast).

In brief, the evaluation uses the Discounted Cash Flow methodology, which is supported on the hypothesis that the value of a project depends on its capacity to generate wealth in the future. Seeing as the value to be produced will occur in different time spans, all of them must be brought to present value at a discount rate reflecting the risks inherent to the estimated flow, i.e., an attractiveness rate reflecting the opportunity cost of several business capital providers, the business risk included. Such discount rate is calculated based on CAPM (Capital Asset Pricing Model). Such model allows calculating the owners’ equity cost (Ke), to be associated with the third-parties’ equity cost (Kd), defining the WACC – Weighted Average Cost of Capital.

Please find below the Ke formation detailing:

Figure 1 – Owners’ Equity Cost (Ke) Breakdown


- -Ø - Cost of Equity	Source: Ceres Inteligência Financeira
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Beta

That indicator represents an average and time relation between the returns on the shares selected in relation to the economy, which is usually highlighted by the S&P500 returns fluctuation, an index that captures a good deal of transactions in the US market.

The leveraged Beta of each company is obtained by tilting the linear regression between the historical logarithmic returns of these assets and the market index. Then, the unleveraged Beta is obtained for each company by adjusting their Debt to Equity (D/E) ratios. Finally, the unleveraged betas of each company are weighted by their Enterprise Value, thus achieving the unleveraged Beta for the resulting Beta, unleveraged, for the industry, which is then re-leveraged in order to consider the fraction of systemic risk corresponding to the relevant company indebtedness effect.

Market Risk Premium

The Market Risk Premium represents the yield expected by the market, taking into account the additional risk in relation to the risk-free rate that practiced therein. The Market Risk Premium is calculated based on the difference between the returns on the S&P500 Index and the perpetual 10-year US Treasury Bonds (Constant Coupon Bond), marked to market annually, considering a long-term window of time. That is, to estimate the Market Risk Premium, the difference between the return on the S&P500, adjusted for dividends and the return on Treasury Bonds, was taken into account.

For the calculation of the return on T-Bonds, the constant maturity bonds, i.e. 10-year-maturity marked-to-market perpetual bonds, are taken into account, assuming the repurchase of the bond at the end of each year. Thus, this return is composed of two components: the yield hired for the year in which the bond was held by the investor and the paper price fluctuation to market due to the changes in the interest rate offered at the end of the year.

Country Risk

As previously mentioned, the CAPM model structuring based on the rates practiced in foreign markets, especially those found in the US market, is more advisable due to the diversity of business segments found in their stock market indices, which explain more comprehensively the relative risks between segments and companies in an economy. However, for application in the countries of origin, it is necessary to adjust the country-specific credit risks, since the US risk-free rate is used, based on T-Bonds, debt securities issued by the United States. The measurement of this risk spread, which applies to developing economies, including Brazil, is denominated country risk. The option recommended in this paper, for a better adjustment, is obtaining the spread between interpolated FRA and T-Bonds, which more directly reflect the country risk present in the interest curve.

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Exchange Risk

To estimate the foreign exchange risk premium, the forward premium was obtained by the breakdown of domestic interest rates and the FRA, which already includes the country risk. The foreign exchange coupon and FRA contracts indicate the expected interest rates in US dollars, measuring the DI-1 day rate fluctuation against the exchange rate fluctuation, and are good indicators of the external interest rates evidenced in the negotiations of Brazilian bonds with sovereign risk, issued abroad.

The Real Exchange Rate is calculated based on the difference between the Interbank Deposit (ID) and the Forward Rate Agreement (FRA) rates. It should be noted that this indicator is calculated in real terms, discounting the forecasted inflation in Brazil (IPCA) and the forecasted inflation in the USA (CPI).

The data of the rates and their respective maturities were interpolated using the Cubic Spline methodology to obtain the related risk curve.

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Capital Structure and Discount Rate Breakdown

Owners’ Equity Cost (Ke)

For the risk-free rate, the yield of the 10-year Treasury Bonds was considered. The data of the rates and their respective maturities were collected and then interpolated by using the Cubic Spline methodology to obtain the curve.

In order to estimate the Market Risk Premium, the difference between the return on the S&P500, adjusted for dividends, and the return on Treasury Bonds, was taken into account. For the calculation of the return on T-Bonds, the constant maturity bonds, i.e. 10-year-maturity marked-to-market perpetual bonds, are taken into account, assuming the repurchase of the bond at the end of each year. Thus, this return is composed of two components: the yield hired for the year in which the bond was held by the investor and the paper price fluctuation to market due to the changes in the interest rate offered at the end of the year. Thus, the Market Risk Premium was obtained, considering a time window, geometric mean and the long-term (10-year) bond with a coupon.

The Real Exchange Premium is calculated based on the difference between the Interbank Deposit (ID) and the Forward Rate Agreement (FRA) rates. It should be noted that this indicator, to be calculated in real terms, is discounted by the difference between inflation in Brazil (IPCA) and inflation in the USA (CPI).

The FRA and ID databases were collected in the Trading System of BM&FBovespa. Then, the data were interpolated by the Cubic Spline method, to obtain the rate curves.

In addition to FRA and ID, the Consumer Price Index (CPI) and the Extended Consumer Price Index (IPCA) forecasts are also necessary for the composition of the Foreign Exchange Risk. While the IPCA forecast was obtained in the Market Expectation System of the Focus Bulletin, made available by the

Banco Central (Bacen).

Table 4 - Summary of Applicable Methodologies

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Third-party capital cost (Kd)

The third party capital cost is obtained through the weighted average of the gross debt (2011-2016) of the companies used to calculate Beta, weighted at the Debt/Net Debt ratio, of the same companies, on their respective reference dates. Next, the Cost of Debt / Net Debt ratio is multiplied by the IDC forecast of the target year. As a final point, inflation and taxes are discounted to reach the tax-free real Kd.

Weighted Average Cost of Capital – WACC

The WACC rate is obtained by weighting the owners’ equity cost and the third-party equity cost and their respective sharing in the company’s capital structure, considering the tax benefit of the debt for third-party equity. The capital structure used was the same as used by ANEEL in PRORET, Submodule 2.4.

Risk Analysis and Sensitivity Analysis

With the purpose of analyzing possible impacts on the valuation, we analyze the sensitivity of relevant variables for the forecast model, with a view to checking the impact on the Net Present Value (VPL). Herein, the sensitivity analysis was conducted in view of the impacts on the evaluation, from fluctuations falling on the Yield Base and on the weighted average cost of capital.

Critical Points and Adaptations

This paper further analyzes critical points of the business and suggested adaptations that may add value to the companies. We also studied some possibilities for this transaction that would minimize risks and maximize the return for investors.

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Synergies

Costs and investments synergies and optimizations were identified, so as to obtain post-privatization potential business value benchmarks. We also appraised possible gains that could be reversed to the seller, depending on the sale structure.

Special Treatments and Specific Risks

The distributors being analyzed are within the electric power distribution service provision norm as Designated Distributors, pursuant to the terms and conditions of Article 9, Statutory Law 12.783, dated Jan-uary 11, 2013, and Ordinance 338 dated July 26, 2016, issued by the Department of Mines & Energies (MME).

Accordingly, several terms and conditions were agreed to for operation under supervision of the regulatory agency.

“ReA No. 748/2016 imposes on such distributors the pre-privatization Temporary Distribution Service Provision Plan for 2017, entailing loan transfer to meet the targets set and accommodate the operating costs, inter alia, according to Annex IV – Commitment, attached to said ReA, as follows: ‘The Designated Distributor Officers, regarding the distribution utility service provision (hereinafter referred to as the ‘Officers’), who are signatories to this agreement, in order to be entitled to the transfers of funds set forth in Paragraph 4, Article 9, Statutory Law 12.783 dated January 11, 2013, commit to abide by the provisions of Ordinance MME-388/2016 and see to continuity and suitability of the service delivered, particularly regarding the following parameters, which have been followed up by ANEEL as a priority:

I – industry compliance;

II	– the assignment’s electric power loss threshold;
III	– the assignment’s Operating Costs threshold;
IV	– the assignment’s threshold of discontinuity equivalent duration per consumer unit (DEC);
V	– the assignment’s threshold of discontinuity equivalent frequency per consumer unit (FEC);
VI	– quality of information provided to ANEEL;
VII	– meeting the inspection requirements issued by ANEEL.

The signatories hereto, on behalf of the Officers, hereby commit to send to ANEEL the Tempo-

Forecast of ‘Light to Everyone’ and RGR Flow earmarked to expiration

We forecasted the amounts payable and receivable by means of CDE funds for ‘Luz para Todos’ Program (PLPT – Portuguese acronym for “’Light for All’ Program”) through expiration scheduled for De-cember 2018⁷. We did not make PLPT forecasts for subsequent years at scheduled expiration because such forecasts would depend on determinations foreign to the distributors.

As a final point, the total investment in replenishment will be distributed over the years 2018 to 2022 based on the Technical & Operating Due Diligence outcome; for the other years, the necessary replenishments, consistent with the private market⁸within their area of operation.

⁷Presidency of the Republic, Chief of Staff, Legal Team, Decree No. 8.387 dated December 30, 2014. ⁸CEMAR, COELCE, COELBA, CELPE.

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Economic & Financial Evaluation

General Assumptions for the Financial Model

For the financial model, it was necessary to adopt some assumptions to analyze the distributors. The model was developed with monthly periodicity; the following general assumptions were defined: Base Date used for the evaluation as of March 1, 2018, with analysis period from March 1, 2018 to February 28, 2048 (30 years of Concession contract). However, the tables, charts, and results shown in the Report start in January 2017 and end in December 2047, because, by considering only two months in 2048, the analyses would not be comparable with the other years.

The discount rate used is based on the dynamic rate methodology, consisting in the monthly calculation of the WACC – Weighted Average Cost of Capital, to be applied. The reporting currency is the official currency, i.e., the values are impacted by inflation over the analysis period. Deflator used to bring the forecasted cash flow to present value is IPCA.

For regulatory assumptions, we assumed that Ordinary Tariff Reviews have a 5-year periodicity, being considered in the month of November and as of the year 2023 as reference (5 years after the contract is signed with the new utility company, which is to take place in 2018). Besides, this evaluation considers an Extraordinary Tariff Review in 2019, basically encompassing the BRR reevaluation.

Finally, the results obtained in the evaluation are based on Nominal Cash Flow to Firm.

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Summary of Business and Existing Structures

Features of the Business

Eletrobras Distribuição Rondônia - Centrais Elétricas de Rondônia S.A. - CERON, is a mixed economy company, indirectly managed by the Federal Government and belonging to the Eletrobras group, which operates in the distribution of electricity in the state of Rondônia.

Originally, Eletrobras Distribuição Rondônia is successor of the old SAALFT- Serviço de Abastecimento de Água Luz e Força of the Federal Territory of Rondônia, established under the form of Joint Stock Company, created by Law No. 5.523, of November 4, 1968, under the shareholding control of the then Government of the Federal Territory of Rondônia and was installed on December 1, 1969, meeting only two municipalities of Rondônia, Porto Velho, the Capital and Guajará Mirim, through isolated nuclei of thermoelectric generation, by Diesel oil, with installed power of 2.893 KW.

In 1997, a new milestone was established and the Company goes through jointly management between the Government of the State of Rondônia, which owns 51% of the shares and ELETROBRAS, with 48.7%, enabling this Company to participate in management on the Boards of Directors, Tax Board and also on the Executive Board. Also in 1997, the federalization of CERON occurs, according to State Law No. 740. The State approves the transfer of the shareholding control of CERON to ELETROBRAS. The shareholding structure was distributed as follows: 79.91% - ELETROBRAS, 20.0% - Government of the State and 0.09% - other shareholders.

In 1998, CERON underwent further changes in its shareholding structure as a result of the sale to ELETROBRAS, which now owns 99.96% of the company's capital stock, being 0.04% to others. In June 2008, the company centralized its management along with five other electricity distributors under the control of the Eletrobras Distribution Board, in which the company now controls 100% of the capital stock, and is presented to its customers and society with the name of Eletrobras Distribuição Rondônia.

The Company's concession covers a geographical area of 237,576 square kilometers covering 52 municipalities and 154 locations for a population of approximately 1.6 million inhabitants and 512,949 customers. The headquarters of Eletrobras Distribuição Rondônia is located in Porto Velho, at Avenida Imigrantes, 4137, Industrial District.

The operational processes related to the business are managed by the 17 departments and 58 commercial offices, with a total of 757 employees and 1,614 outsourced employees. The departments' management develops their actions based on plans from the projects and initiatives emanating from the Strategic Planning. The distribution assets have 50 substations, installed capacity of 982 MVA, 1,262 km of transmission lines and 41,869 km of distribution networks with 61,064 transformer units.

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Demand Forecasting

Demand Forecasting per Class

The consumption of electric power in Brazil may be divided into eight different classes, which are: Residential, Commercial, Industrial, Rural, Government, Public Lighting, Public Service, and Own Consumption. In order to understand the possible heterogeneities among the groups, the Residential, Commercial, Industrial, and Rural sectors were analyzed in separate. Government, Public Lighting, Public Service, and Own Consumption were all grouped in a single class entitled ‘Other’. This decision was based on the similar consumption behavior between them and to reduce the effect of volatility incurred in low-consumption classes.

Distributor’s History

To project the demand for power of the next thirty years, ending in February/2048, it is necessary to carry out a historical analysis that demonstrates the evolution of power consumption and its distribution between the classes. As observed in Table 10 – Geometric Mean of 2007-2016 Consumptions, all sectors present an evolution in power consumption¹⁹. The segments presented similar growths, something near 6.70% p.a. Exception is made to the industrial sector that obtained an expansion below the others, 2,98% p.a. It is also worthwhile noting the composition of power consumption, i.e., how the total power consumption is distributed between the classes. Analyzing Figure 3 – Power Consumption Composition Comparison, it possible to note that no substantial changes occurred in terms of power consumption distribution. The residential sector was responsible for 35.39% of the total consumption, against 39.86% in 2016, for the industrial sector, one has in 2007 16.66% against 13.46% in 2016, commercial 22.86% in 2007 and 21.72% in 2016, rural 9.47% in 2007 and 10.77% in 2016 and Other that went from 15.42% in 2007 and ended the year with 14.19%.


¹⁹Source: Distributor’s statement of invoicing
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Regression Analysis and Results

As mentioned in the section above, five models were performed to project the demand for power, with one model to each one of the classes, which are Residential, Commercial, Industrial, Rural, and Other. The methodologies and results will be subject to individual analyses. The behavior of the overall power consumption for the next thirty years.

Residential

A linear model of regression estimated by MQO²⁰was adopted to project the demand by the residential class. The dependent variable in the model is the variation of residential power consumption per capita²¹. A trend line and Brazil’s annual GDP were used as explicative variables. The power consumption per capita was used, for this variable indirectly incorporates the population variation, eliminating the addition of another explicative variable in the model. The trend line defined as

HP L log :P;

, t ranges from (1,T) where T is the sample size, aims at eliminating the non-stationarity of the set. The GDP variable was introduced to capture the elasticity of power consumption based on income. The model was estimated without intercepto. The definition of the model is presented below: log _F?L:P E_;s;GL»HP:PEs; E¼LE>:P Es; ?L:P pL population cL Residential power consumption cpL Consumption Per Capita ltL Trend Line pibL GDP Brazil

In which ± and ² are the coefficients of the model.


Coeffi ievt		Value
±		ì.ììóõï
²		ì.ðôìòì

With the forecasted coefficients, the forecast GDP²²and the forecast population²³were used to estimate the demand for power until 2048. It was necessary to implement an exponential smoothing in the model so that the sequence of variations of residential consumption did not diverge. The adopted premise assumed that when achieving a consumption target per capita, in the case of consumption per capita in

²⁰Least Squares: Linear regression model that estimates the straight line, minimizing the squared difference between the

estimated and the observed value;

²¹The demographic data have been obtained from IBGE; ²²Bacen Expectations; ²³IBGE Population Forecast;

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Other

The model created to project the Other class of power consumption was based on the premise that there is a relationship of linear dependence between this class and the Residential consumption class The model may be defined as ^follows:. K:P; L=:P; ?.N:P; c. oL Consumption Other c. rL Residential Consumption Where ± t is the proportion that Other represents of the residential consumption in time t.

For such, it was necessary to estimate an auxiliary model capable of defining the parameters ± to each time t. An equation was created with parameters (µ) = 97.98%, based on the history of these proportions, and a target ² values was also defined to soften ± (t). This value was based on the proportion found in the State of São Paulo in 2015 between Other and Residential, case in which ²=30%. Another parameter, »=4.6145, was defined with the linear optimization to maximize the correlation between the proportion set forth in time. The model was defined as presented below:

=:PEs; L=:P; :Q^:ã max:=:PEs; FÚ,r;;;

The values ± were forecast for time t as a whole, replacing them in the aforementioned equation and using the residential consumption forecasting already made, to obtain the forecasting for the class entitled Other.

Total

This section presents the forecast graphs of the overall power consumption, in addition to a general chart of the growth per class.

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Network Extension (Km)

Common Analyses to Distributors

The network extension project was based on the history of extension of low, medium, and high voltage networks between years 2001 and 2016³⁰. The network extension set forth by the Decennial Plans and PDDs of distributors was added to such history, of which the forecasted network extension was extracted for years 2017 to 2021 for low and medium voltages, 2017 and 2018 for the “Luz Para Todos Program” (Light for All) and high voltage for years 2017 to 2026.

Its history of expansion after the Decennial Plans and PDDs takes into account both the historical and forecast investments to each distributor.

Three groups have been segregated: (i) low and medium voltage, (ii) high voltage, and (iii) “Luz Para Todos Program”. This division was necessary to determine the fundamental differences existing in each group.

The forecasting of group (i) Low and Medium Voltage is set to begin in 2022. A proxy (average of investment/average of growth) of dependency was created between the degree of investment and the network expansion. With the degree of investment forecast by Ceres, it was possible to estimate from 2022 the network mileage values.

The same methodology applied to the Low and Medium Voltages was applied to the High Voltage segment. The Decennial Plan already projects the expansion of the network mileage for years 2017-2026. For years 2027-2048, a causal relation was applied between the investment and the network expansion. The investments forecast for the high voltage Market served as an input to obtain the network expansion of that class.

Regarding “Luz Para Todos Program” (PLPT), the data used refer to the Decennial Plans and, therefore, based on the current condition of the legislation that determines the end of the program in 2018, no forecast was made for the coming years.

³⁰The extension of the network built under Luz Para Todos Program in included in the 2001-2006 history, in low and medium voltage

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Investment Forecasting

Deployment and Renewal

The CERON 2017 Distribution Development Plan (PDD 2017), the 2017 Decennial Plan, the 2017 Plan on the Provisional Electric Power Distribution Services (Provisional Plan), the information of the Due Diligence of service B, in its “Product 7 – Technical-Operational Report of CERON”, annex II, in addition to indications of CERON’s technical team, obtained in the meetings organized by CERES, were used to define CERON’s investment needs.

Investments were subdivided into High Voltage Expansion, Medium Voltage/Low Voltage Expansion, Improvement, Renewal (Maintenance), Luz para Todos, and Infrastructure and Support. From 2017 to 2022, the values obtained in the Due Diligence of service B, in its “Product 7 – Technical-Operational Report of CERON”, annex II, were considered as a whole and added to the expenses with Renewal (Maintenance) in 2017 of the Provisional Plan.

Only 10% of the expenses with Luz para Todos Program were considered for years 2017 and 2018, since the other 90% were subsidized with CDE resources and have been allocated as Special Obligations. In addition, approximately R$ 173 million of the investments in Expansion of High Voltage and R$ 58 million of the investments in Expansion of Medium Voltage of 2018 were also considered as Special Obligations, since their origin are of subrogation.

As of 2023, investments with High Voltage Expansion, Medium Voltage/Low Voltage Expansion, and Renewal (Maintenance) continued being forecasted according to the premises described below.

High Voltage Expansion: The values informed in the 2017 PDD were corrected for the base date De-cember 2016 and fully considered until 2026. For the other years in the forecast, the estimated investment is equivalent to the average expenses between 2018 and 2026.

MT/BT Expansion: For CERON, the PDD 2017 presented a forecast of investments in the MT/BT network. These values informed in the PDD 2017 were corrected for the base date December 2016 and considered in full up to 2026. For the other forecast years, the estimated investment equals the average of expenses between years 2018 and 2016

Improvement: Based on information supplied by CERON’s technical team, it has been defined that, in 2023, the amount corresponds to the average of the amounts spent between 2018 and 2022 with De-cember 2016 as a base, without variations due to the continuous structure of this account.

Renewal (Maintenance): As of 2023, expenses with maintenance will be equivalent to the asset depreciation value. The reference of depreciation of ANEEL’s Normative Resolution no. 674/2015 for the current assets was used to define this value, in addition to the depreciation of new investments of the company, calculated based on the average depreciation of the assets of the Equity Control Report.

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PMSO Estimate

Common Analyses to Distributors

PMSO Forecasting Method

The analysis of Personnel, Material, Third-party Services, and Other Expenses (PMSO, of the Portu-guese “Pessoal, Material, Serviços de terceiros e Outras despesas”) may be divided into two parts: characterization of the analytical bases and the effective forecasting of such bases according to the types of expenses observed in such accounts

The First Part, known as the Characterization of Analytical Accounts, underwent 5 Phases: Phase 1 – Grouping of analytical accounts; Phase 2 – Analysis of the account nature as fixed and variable; Phase 3 – Identification of atypical values³³; Phase 4 – Evaluation of the best correlation to variable accounts;

Phase 5 – Identification of regulatory accounts (considered as recurring by ANEEL and compensated thereby).

Phase 1 begins with the monetary adjustment of the analytical accounts evaluated. These accounts are included in the sampling period between January 2012 and December 2016, and were adjusted for the base date of December 2016 for it is the most current of the period.

After such first monetary adjustment, the accounts of expenses were grouped in each PMSO group, in accordance with the similarity of type of expense and respective taxable events.

Phase 2 consists of the analysis of the fixed and variable accounts. The PMSO groups were evaluated considering as fixed account the account whose participation in the expenditure in the past 3 periods³⁴was within the lower and upper limits of the expense grouping sample, where:

Upper limit fix/var = 60%*(1-((standard sample deviation)/(sample minimum)) and

Lower limit fix/var = 60%*(1-(standard sample deviation)/(sample maximum)).

³³Values with behavior different from the usual of the account, either too high or too low in relation to the average, values at non-recurring levels ³⁴To accounts completely fixed in value, each 1 out of 5 years of the period would represent 20% of the total expenditure. Thus, the last 3 years would represent 60% of the value in the 5 years evaluated

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Initially, accounts above or below such limits are considered variable. Then, an evaluation is carried out in relation to the nature of the expense (if having characteristics of fixed or variable) and the degree of variation in the recent period³⁵.

Fixed accounts, when forecast, are calculated as the average of expenses in the sampling period, excepting outliers.

Variable accounts, when forecast, are transformed into indicators and range according to the forecasts³⁶of Consumption Units and Consumed MWh, also excluding atypical values.

Phase 3 evaluates which periods in a sample may consist of atypical values and, therefore, unlikely to occur in the forecast scenario. A period entry is considered as an outlier when its value is beyond the established limits of normality of the sample, where:

Upper limit out = (sample average) + (standard sample deviation);

Lower limit out = (sample average) - (standard sample deviation).

After such initial characterization, the nature of the expense and the levels verified in the past 3 years are evaluated in order to identity structural breaches to the expense level to define if the prior samples must be kept or eliminated in the evaluation.

Phase 4 evaluates what are the most correlated variables with the PMSO account groups. More correlated groups are used as an indicator to estimate the account value. The two variables with the greatest correlation with the PMSO accounts were Network Extension (Km)³⁷and Consumption in MWh.

The formation of the indicator in the PMSO group expenses considered as variable occur as shown below:

Finally, Phase 5 consists of the classification of the accounts composing the groups of each PMSO block, pursuant to the characterization defined by ANEEL for regulatory PMSO. Thus, each account composing the analytical PMSO has a classification as Effective PMSO (total), Regulatory PMSO and PMSO Other (effective PMSO – regulatory PMSO).

³⁵Expenses with low variation would tend to be fixed

³⁶More detail on the forecasting of Consumption Units and Consumption in MWh are provided in the chapter of Demand and Consumption Forecasting ³⁷Includes the extension of low, medium, and high voltage network ³⁸Excluding those atypical ³⁹The parameters considered are consumption units and consumption in MWh for the same period of time of the expense, excluding periods considered as atypical by the company

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The Second Part includes the Forecasting of the Effective and Regulatory PMSO Groups, and may be divided into four Phases:

Phase 1 – Expense Forecasting for 2017;

Phase 2 – Operating Costs Variation Rate;

Phase 3 – Identification and Treatment of Accounts with Behavior Linked to Improvements of the Distributor;

Phase 4 – Concession Period Forecasting – 2018 to 2047.

Phase 1, Expense Forecasting for 2017, will consider a variation of the expense based on the history of the company, observing the fixed and variable natures of the expenses composing the PMSO.

Fixed and variable expenses are calculated as detailed in the First Part, Phase 2, in accordance with the provisions of this chapter. Variable expenses are transformed into indicators having as denominator the parameter of best correlation that has been analyzed, based on R$/Parameter, multiplied by the forecasting⁴⁰of Network Extension (Km) or MWh Extension.

Phase 2, Operating Costs Variation Rate and Target, is subdivided into three steps: 1 – Definition of the Operating Cost Benchmarks; 2 – Definition of Variation Rate and Target between 2018 and 2022; 3 – Definition of Variation Rate and Target between 2023 and 2027.

Step 1 of definition of Operating Cost Benchmarks initially took into account the groups determined by ANEEL, which have been adjusted per region. For the distributors of the Northern region, the benchmarks that have been considered consisted of the following private distributors: Celpa and Celtins. These were grouped with Ceron, Eletrobrás Roraima, Eletroacre and Amazonas Energia.

For the Northeastern region, the following were considered: Celpe, Cemar, Coelce, Energisa Paraíba and Energisa Sergipe, Coelba and Cosern; these were grouped with Cepisa and Ceal.


⁴⁰Detailed in the chapter on Consumption and Demand Forecasting
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In Step 2 of Definition of the Variation Rate between 2018 and 2022, ANEEL’s DEA data base of calculation of efficient costs was used for the 4CRTP. The PMSO expense of each company with the extension of the network is parameterized.

Based on these indicators, it is possible to calculate the average of the group of each distributor according to the region. Distributors whose initial indicator is greater than that verified by the group average shall have their cost adjusted in terms of indicator in the next rate adjustment, in 2023.

Distributors whose initial indicator is below that verified in the group average shall have as their target the indicator level between 2023 and 2027 lower than the group average.

Step 3 of Definition of the Variation Rate between 2023 and 2027 consists of the calculation of the average indicator of the private benchmarks of the groups. For the Northeastern region, the private distributors considered were: Celpe, Cemar, Coelce, Energisa Paraíba, and Energisa Sergipe. For the Northern region, the private distributors were: Celpa and Celtins.

When achieving the R$/Consumption unit indicator of the cycle target, distributors stabilize the operating cost indicators parameterized by consumption unit.

Phase 3 of Identification and Treatment of Accounts with Behavior Linked to Improvements of the Distributor consists of the identification of considered accounts that influence the effective PMSO cost, but that range in accordance with the operating improvements of the distributor⁴¹. Each company had a set of adjustments treated in their specific section.

Phase 4 consists of the estimate of the PMSO expense levels of distributors during the period of concession. With the targets between 2018 and 2022 and from 2023 to 2027, distributors will achieve the operating cost benchmarks by the end of 2027. From that year, the indicator of R$ PMSO/Consumption Unit is stabilized, and the absolute PMSO value ranges in effective terms by means of the variation of consumption units.

Efficient Costs Interval

The upper and lower limits of the efficiency interval⁴²calculated to each distributor were estimated. The values considered to these forecasts were based on those found in “Annex I – Efficiency Intervals” of submodule 2.2 V2 of PRORET. These limits have the trend of being aligned with their respective benchmarks in two occasions during the concession; the first ending in 2022 and the second ending in 2027.

⁴¹Examples: ANEEL fines are reduced according to the curve of improvement of indicators of quality

⁴²Greater detail on the PRORET methodology about this subject may be found in chapter “Methodology”, Item PRORET (Rate Level), Sub-item “Operating Costs”, Topic “Efficient Cost Interval”, or PRORET submodule 2.2 V2

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The first occasion calculates the simple average of each one of these limits to distributors according to their regional groups, consisting of:

Northeast: Ceal, Cepisa, Celpe, Cemar, Coelba, Coelce, Cosern, Energisa Paraíba, and Energisa Ser-gipe;

North: Amazonas Energia, Eletrobras Roraima, Ceron, Eletroacre, Celpa, and Celtins.

Distributors with upper or lower limit at level worse than that of the group average achieve the group average by 2022.

At the second occasion, the average of private distributors of these regional groups is calculated, consisting of:

Northeast Private Benchmark: Celpe, Cemar, Coelce, Energisa Paraíba, and Energisa Sergipe;

North Private Benchmark: Celpa, Celtins.

It should be noted that, since Technical Note 149/2017-SRM/SGT/SRD/SFF/ANEEL defines the operating costs in force from 2017 to 2023, the efficient costs intervals defined in this section will only have an impact to the rate after the Rate Review of 2023.

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Voluntary Dismissal Plan (“PDV”)

Common Analyses to Distributors

The adjustment of personnel involves the decision between terminating the labor agreement with the collaborator versus offering him/her a voluntary dismissal against financial compensation. The values of each option are evaluated by the employee and by the company, and each will choose what is best when making the decision.

The evaluation begins with the definition of the public eligible to the PDV, considering only collaborators with at least 20 years⁴⁴of effective labor link with the company. This public represents approximately one-third⁴⁵of the total personnel of the evaluated distributors.

Labor link with the company means employees in the following categories⁴⁶:

· ·

Employees in full-time positions; Assigned employees⁴⁷;

Employees under license or with labor agreement suspended; Officer⁴⁸.

In this sense, the following employees are not included in the base containing employees eligible to the PDV:

Employees requested from other agencies and branches⁴⁹;
Employees without link with the government;
Board members;
Young apprentice;
Interns.

The payroll independent of enrollment on December 31, 2016, was evaluated to each distributor. Such evaluation resulted a termination value that is compared to the value if the employee applies to the PDV.

⁴⁴PID – Eletrobras Companies Dismissal Stimulation Plan – Commission of Mines and Energy – Chamber of Deputies –07/02/2013 ⁴⁵PID Eletrobras calculated 36.4% of total eligible personnel ⁴⁶The categories are those presented in the due diligence of Human Resources performed by Service B, in “Product 8: Report on Distributor’s Human Resources Evaluation” of each distributor ⁴⁷According to Decree no. 4.050, dated April 12, 2001, which governs Article 93 of Act no. 8.112, dated 12/11/1990, these employees are part of the personnel of the conceding agency (the evaluated distributor is the conceding institution in such case) ⁴⁸Applicable only to officers with more than 20 years of career in the distributor and part of the effective personnel, not including officers required by other government agencies and branches or without link to the government, among others ⁴⁹According to Decree no. 4.050, dated April 12, 2001, which governs Article 93 of Act no. 8.112, dated 12/11/1990, these employees are part of the personnel of the conceding agency (the evaluated distributor is the receiving institution in such case)

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The PDV expense is entered as a nonrecurring item that occurs in two occasions, in its phase 1 on June 1, 2018, and in its phase 2 on June 2, 2019. Employees who leave the company reduce the PMSO personnel account. Such reduction may occur in two ways, either by means of reduction of the work position without the addition of a new employee and/or replacement with a new employee with a more competitive cost, which will return to the PMSO Personnel account.

The termination value is calculated based on the sum of the following accounts: base salary, additions⁵⁰, overtime, prior notice, FGTS fine, vacation, and 13^thsalary, in which:

13^thsalary has the same value of the Dec/2016 base salary;
Additions and overtime refer to values received by the employees in December 2016;
Prior notice is the sum of the monthly base salary, extraordinary compensation for length of

work⁵¹;

· FGTS is calculated with the multiplication of the monthly salary by 8%, by the number of months that the individual worked at the company until the base date of December 31, 2016. The fine of FGTS represent 50% of this value;· Vacation has total value per employee of half plus 1+(1/3) of a base salary related to December 2016. This value is divided by half because at this point of the period, half of the individuals have already used their vacation benefit.

The PDV is calculated as approximately 18 times the sum of the Base Salary, Additions, and Overtime of the collaborators in December 2016. This choice represents the value with which approximately one-third⁵²of individuals eligible to the PDV see it as financially interesting when compared to the involuntary dismissal.

Considering such eligible collaborators, those in two specific situations join the Plan:

1 – Individuals whose PDV is equal to or higher than the involuntary contractual termination value;

2 – Individuals whose PDV is greater than twice the sum of the base salary, additions, and overtime is greater than or equal to the termination value.

The individuals in situation 1 join and receive the PDV originally offered, the individuals in situation 2 joint and receive the PDV plus two times the sum of the base salary, additions, and overtime.

⁵⁰Premium for hazardous, dangerous and hardship

⁵¹At every one year, 3 days of bonus are received as compensation, up to a maximum of 60 days or two months of compensation. Added to the prior notice compensated with maximum of 30 days, the total of receipts may totalize 90 days ⁵²PID – Eletrobras Dismissal Benefit Plan – Commission of Mines and Energy – Chamber of Deputies – 07/02/2013. Eletrobras estimated that the number of dismissals would represent 47% of the public eligible to its 2013 PID

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Offsetting for the Transgression of the Continuity Limits

Common Analyses to Distributors

ANEEL establishes limits for the continuity indicators. When surpassing these limits, a distributor shall financially offset the consumer. The compensation is automatic and shall be paid within up to 2 months after the month of calculation of the indicator (month of interruption)⁵³.

Four individual continuity indicators are evaluated:

Individual interruption duration per consumption unit (DIC): Interval of time, in the period of de- termination, that the electric power distribution was discontinued in each consumption unit or point of connection;
Individual interruption frequency per consumption unit (FIC): Number of interruptions occurred in the period of determination, in each consumption unit or point of connection;
Maximum duration of continuous interruption per consumption unit or point of connection (DMIC): Maximum period of continuous interruption of electric power, in each consumption unit or point of connection;
Individual interruption duration occurred on critical day per consumption unit or point of connec- tion (DICRI): Corresponding to the duration of each interruption occurred on a critical day, to each consumption unit or point of connection.

Such continuity of supply is evaluated by ANEEL by means of subdivisions of the distributors, known as Electrical Sets. Each set⁵⁴is associated with limits to the indicators. The limits of the DIC and FIC indicators are defined for monthly, quarterly, and annual periods. The DMIC indicator limit is defined for monthly periods. The DICRI indicator limit is defined to each interruption on critical day⁵⁵.

The forecasting of these indicators may be divided into three parts: estimate on the amount of fines for 2017, history of adjustment of fines in terms of unit cost, and high level of unit cost.

The estimate of the amount of compensations for 2017 was made based on the Offsetting Indicators Base of ANEEL and of the SAMP consumption units, owned by ANEEL, for years 2014 to 2016.

After Ë$ ÈÙÙæØççÜáÚ 6458?645: the following indicator was created to each distributor, in separate: ~~_{# ¼âáæèàãçÜâá ÎáÜçæ 6458?645:}~~. This indicator represents to each distributor the sum of total offsetting

⁵³	ANEEL
⁵⁴	The Sets may have differentiated coverage, with sets covering part of a municipalities and sets covering multiple

municipalities

⁵⁵Regulation in Module 8 of te PRODIST Distribution Procedures

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occurred between 2014 and 2016, divided by the sum of the consumption units of the distributor between 2014 and 2016.

Following that, the average indicator of each distributor between 2014 and 2016 is multiplied by the forecast of the number of consumption units for 2017⁵⁶, achieving the offsetting value in 2017.

To calculate the history of adjustment of the fines in terms of unit costs, the evaluated companies were grouped in regional benchmarks:

Northeastern distributors: Cepisa and Ceal were grouped with Celpe, Cemar, Cosern, Energisa Paraíba and Energisa Sergipe;
Northern distributors: Amazonas Energia, Ceron, Eletroacre and Eletrobras Roraima were grouped with Celpa and Energisa Tocantins.

To each regional group, private distributors »ËÅ 645: »ØáÖÛàÔåÞ ÈÙÙæØççÜáÚ benchmark, with the determination of the average of benchmark indicators⁵⁷~~_{# 645: »ØáÖÛàÔåÞ ¼âáæèàãçÜâá ÎáÜçæ}~~, i.e., the Northeastern region considered Celpe, Cemar, Cosern, Energisa Paraíba and Energisa Sergipe; and the Northern region considered Celpa and Energisa Tocantins.

The evaluated distributors, whose offsetting per consumption unit were better than those verified in the benchmarks, maintained their (best) indicator throughout the period of concession. The evaluated distributors, whose indicators were worse than the benchmarks, improved their indicators until they reached the benchmark indicator level.

At last, the final level of unit cost of distributors is achieved in 5 years, until the first ordinary rate review after the beginning of the concession, in which distributors achieve the offsetting average per consumption unit of the benchmark groups.

These unit cost values, multiplied by the forecasted consumption units, generate to each year an offsetting value to be incurred by the evaluated distributors. These values are divided homogeneously to each month of each respective year in the evaluation.

The treatments of such offsetting occur with the definition of two documents:

⁵⁶The forecasting of consumption units is treated in Chapter “Economic-Financial Evaluation”, Item “Demand Forecasting”, Subitem “Consumption Unit Forecasting” ⁵⁷The average verified in 2016 was used for the benchmark distributors in detriment of the 2014-2016 average, due to data missing in relation to the benchmarks for the periods before 2016

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1 – Normative Resolution no. 748, dated November 29, 2016⁵⁸, which establishes the terms and conditions for the provision of the public service of electric power by Designated Distributor;

2 – Official Letter no. 113/2017-DR/ANEEL, Brasília, dated May 3, 2017, case: 48510.000502/2017-00, which determines the submittal of a draft of the new model of Agreement for the Concession of Public Service of Electric Power Distribution⁵⁹.

The treatment given in relation to Document 1, in its Chapter I (Revenue), in its Article 5 established that: “The Designated Distributor will be authorized to assign the resources from offsetting for violation of the limits of quality related to the continuity of the service and the voltage level in permanent regimen as per items 2.13 of section 8.1 and 5.11 of section 8.2 of PRODIST’ Module 8 for investments in the area of concession. ”

These offset values are included in entry Obligations Linked to the Electric Power Service (Special Obligations), during the period of designation for the provision of the electric power public service, i.e., between 01/01/17 and 02/28/18.

In relation to Document 2, in its Clause Nineteen (Transitory Provisions), Subclause One, we have: “DISTRIBUTOR may allocate the resources from offsetting for violation of the limits of quality, related to the continuity of the services and the sampling measurements of the voltage level in permanent regime, for the investments in the area of concession, until the end of the fifth calendar year after the date of execution of the concession agreement. ”

I.e., between 03/01/2018 and 02/28/2023, the distributor may allocate such offsetting to make investments, according to the criteria below:

Paragraph one: “DISTRIBUTOR must continue calculating the offset values from the date of execution of the agreement, according to the regulation, for the purposes of follow-up and in- spection by ANEEL”;
Paragraph Two: From the second calendar year following the execution of the agreement, in case the calculated values of the offsets are below the values of the calculated offsetting for the previous calendar year, such difference will be considered as a remunerable investment by DISTRIBUTOR upon the rate review, with the remaining value being included in entry Obliga- tions Linked to the Electric Power Public Service (Special Obligations) ”;
Paragraph Three: “From the second calendar year after the execution of the agreement, in case the calculated values of the offsetting is greater than the values of calculated offsetting for the


⁵⁸ANEEL
⁵⁹As resolved by ANEEL Management in the 15^thOrdinary Public Meeting, held on May 2, 2017


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Figure 10 – Offsetting Evolution of the Evaluated Distributor and Comparison with the Target

R$/UC Avaliada; R$/UC Avaliada;

R$/UC Avaliada


‘$/UC AÀaliada; íð; íô,óô		‘$/UC AÀaliada; îì; íñ,íð


		‘$/UC Bev hua k; îõ; íí,îñ
		‘$/UC Bev hua k	‘$/UC AÀaliada

Source: ANEEL – Offsetting Indicators and SAMP, Ceres Inteligência Financeira

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Other Revenues Forecasting

The revenues that have not been linked to the operational indicators will remain fixed and shall be corrected by the IGP-M during the period. The initial base date of these revenues was defined by the average of the entry in the past three years. Revenues related to operational indicators were forecast from the calculation of the average value in R$ per Consumption Units (“UC”) or Mega Watt hour (MWh), and based on the curve of the indicators, the factor is corrected based on the IGP-M. The definition of the factor was based on the average of the value of revenue in the past three years, over the average of the past three years of the operational indicator values.

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Regulatory Remuneration Base Flow

Regulatory Remuneration Base Calculation

To estimate the Regulatory Remuneration Base to be validated in 4CRTP by ANEEL, the additions, write-off, and adjustments of the regulatory agencies have been evaluated for the following lines:

(1) Fixed Assets in Use (New Replacement Value); (2) Maximum Usage Index; (3) Gross Special Operations; (4) Fully Depreciated Assets;

(5)	Gross Remuneration Base = (1)-(2)-(3)-(4);
(6)	Accumulated Depreciation;
(7)	Net AIS (Market Value in Use);
(8)	Depreciated Usage Index;
(9)	Remuneration Base Value (VBR);
(10)	Stockroom in Operation;
(11)	Deferred Charges;
(12)	Net Special Obligations;
(13)	Real Property and Easements;
(14)	Total Net Remuneration Base = (1)-(6)-(8)+(10)+(11)-(12)+(13);
(15)	RGR PLPT Balance;
(16)	RGR Balance Other Investments;
(17)	Depreciation Rate;
(18)	Regulatory Reintegration Quota = (5)*(17);
(19)	Effective WACC before Taxes;
(20)	RGR PLPT Rate;

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(21) RGR Rate Other Investments;

(22) Remuneration of Capital (RC) = (15)*(20)+(16)*(21)+[(14)-(15)-(16)]*(19).

Common Analyses to Distributors

Composition of the 4CRTP Regulatory Remuneration Base

The composition of the Regulatory Remuneration Base considered in the evaluation may be divided into two parts: Initial Base and ANEEL Adjustments⁶¹.

The Initial Base refers to the values that will compose the Regulatory Remuneration Base in the 4^thCycle of Periodical Rate Review (4CRTP). These values were determined by independent companies that conduct the Investment Evaluation (Incremental Base Review) and Armored Base of distributors between 3CRTP and 4CRTP, achieving a composition of part of the lines composing the Regulatory Remuneration Base of the 4CRTP to each distributor. This Initial Base takes into account the Complete Evaluation Report of Distributors.

Thus, the Complete Evaluation Reports, which include the Incremental Base Review and the Armored Base Review and that were considered in the evaluation of each distributor are:

Eletrobras Distribuição Rondônia: SETAPE – Report: “EDAC Executive Summary – Complete Base –Evaluation of the Electricity Assets of Acre – Eletrobras Distribuição Rondônia”, reference February 28, 2017;

Eletrobras Distribuição Alagoas: Levin – Complete Evaluation Report “Companhia Energética de Ala-goas – CEAL Project no. 2715-17745”, reference February 28, 2017;

Eletrobras Distribuição Amazonas: Levin – Complete Evaluation Report “Eletrobras Amazonas Energia – Project Levin no. 3174-17752”, reference February 28, 2017;

Eletrobras Distribuição Piauí: Levin - Complete Evaluation Report “Cepisa Eletrobras Distribuição Piauí Project Levin no. 3082-18367”, reference February 28, 2017;

Eletrobras Distribuição Rondônia: Deloitte – Equity Evaluation Report “Centrais Elétricas de Rondônia – Ceron”, reference February 28, 2017;


⁶¹Performed by ANEEL inspection
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Eletrobras Distribuição Roraima: Levin – Complete Evaluation Report: “Eletrobras Distribuição Roraima Project no. 3012-17862” reference February 28, 2017.

Complete Evaluation of distributions shall hereinafter mean the aforementioned reports, related to the respective distributors.

During the evaluation procedure, the Distributors had two review reports of the Regulatory Remuneration Base. One to be presented to ANEEL, except atypical situations, with the Asset Evaluation Report, which reviews the Incremental Base of a CRTP to the other, considering money adjustments, additions, and write-off.

The second, the Complete Evaluation Report, considers this same Asset Evaluation Base and also reviews the Armored Base of 3CRTP, adjusted to the 4CRTP. This report was made and used in this work due to the important value of the assets of the distributors with potential to make part of their Armored Bases. However, it should be noted that the reviews on the Armored Base may have a smaller expectation of being accepted for they regard to specific cases when compared to the evaluations of the Incremental Base between CRTPs⁶².

The position of the Complete Evaluation Report, which has been considered in this work, includes the money adjustments of the 3CRTP Base, the additions and write-off between the 3CRTP and 4CRTP, and the review of the 3CRTP Armored Base, adjusted to the 4CRTP. The additions, write-off, and review of the Armored Base were included in its pertinent items by the evaluator of the Complete Report.

The evaluation of the Complete Report includes⁶³from item (1) Fixed Assets in Use (New Replacement Value) to (14) Total Net Remuneration Base = (1)-(6)-(8)+(10)+(11)-(12)+(13) and all were used in the composition of the initial Regulatory Remuneration Base of 4CRTP⁶⁴.

Items (15) RGR PLPT Balance and (16) RGR Balance Other Investments were subject to money adjustment by the IPCA between the values obtained in 3CRTP and 4CRTP.

Finally, the other percentage items: (17) and (19) to (21) were maintained constant in relation to what has been verified in 3CRTP and subtotals (5), (7), (9), (14), (18) and (22) had their calculation logics.

⁶²To balance such smaller change of acceptance by the regulatory agency, the difference of the Reviewed Armored Base and the “Common” Armored Base (Armored Base of the Asset Evaluation Report) is set aside, which is greater than that applied to the Incremental Base, as detailed in the topics below ⁶³These same lines are also included for the Asset Evaluation Report that reviews the Incremental Base ⁶⁴Item 1 was adjusted by ANEEL’s disallowance rate, which implied the variation of the original values used in the Regulatory Remuneration Base of the economic-financial evaluation. The disallowance was applied in separate over the Incremental Base and the Armored Base

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ANEEL Adjustment on the Incremental and Armored Bases

ANEEL inspects the Incremental Base of assets and the Reviewed Armored Base⁶⁵between periodical rate cycles. This advent implies that the assets presented and/or reviewed may be considered as inapplicable and thus discarded by the regulatory agency. Thus, the incremental Base between the 3CRTP and 4CRTP and the Armored Base Review of this same period were applied percentages of Incremental Base Adjustments and Armored Base Adjustments, respectively.

The average adjustment (disallowance) of the group of distributors evaluated in the 3CRTP per region was applied over the Incremental Base that forms the Initial Base of 4CRTP⁶⁶, or for cases in which the average adjustment is worse than that verified by the company, the adjustment of the distributor was maintained

The average adjustments (disallowance) of the group of distributors evaluated in the 3CRT per region were applied over the Reviewed Armored that forms the Initial Base of the 4CRTP. Such adjustment is applied once to each distributor in its Initial Base, i.e., it is not applied in the following years, differently to the Incremental Base. For the Reviewed Armored Base⁶⁷, Northern companies were attributed a disallowance of 5.73% and Northeastern companies had disallowance of 5.01%.

From 2018 to 2048⁶⁸, the average adjustment of the benchmark private distributors⁶⁹is applied per region, obtained from the 3CRTP Incremental Base. A disallowance of 2.09% was considered to Northeastern, and of 2.83% to Northern companies.

Disallowances are considered as effective, i.e., they are not presented again in the future and considered as assets by ANEEL. This occurs due to two main reasons:

Difficulty to present the proof of the investment at the degree demanded by the regulatory agency;
Management faults that could generate investments in assets not acknowledged in the Regulatory

Remuneration Base, which makes part of the invested assets to be set aside.

The evaluated distributors, with the entry of a new concession holder, will seek and gradually achieve the adjustment level by ANEEL of the benchmark private distributors of their regions, which will cause in the average that their asset disallowances are reduced when compared to the period prior to the private concession holder.

⁶⁵In the specific cases in which they are reviewed and presented again, as occurring to the Evaluated Distributors ⁶⁶Provided by the investment evaluators between 3CRTP and 4CRTP

⁶⁷Armored Base of the Complete Report less Armored Base of the Incremental Report ⁶⁸From the period of a new concession

⁶⁹Benchmark distributors compared to those evaluated in the Northern region: Celpa and Cemar; Northeastern region: Celpe, Energisa Paraíba and Energisa Sergipe. Energisa Tocantins (Celtins) was discarded due to the atypical value (above 1.5 of standard deviation over the average of indicators) of ANEEL adjustment for the period considered when compared to the other private distributors

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Finally, the application of the disallowance of the Remuneration Base presented by the distributors is levied upon item (1) Fixed Assets in Use (New Replacement Value) and consequently affects the items connected thereto. This will make the values considered in the evaluation to be different of the asset evaluation report in the magnitude of the disallowance applied to each distributor.

Regulatory Remuneration Base Components Forecasting

Inflation adjustments, additions, and write-off of assets shall occur for the years after the Initial Base of 4CRTP, which are considered in the evaluation until the final period of the concession.

Money Adjustments

The money adjustments of the Regulatory Remuneration Base may be subdivided into four detailed subgroups, as follows:

Items Monetarily Adjusted Directly; Items Consisting of Formulas; Percentage Items; Other Items.

It should also be noted that the values of the rates to which such adjustments occur may be found in section “Economic-Financial Evaluation”, in chapter “Macroeconomic Forecasting”.

The items of the Regulatory Remuneration Base are monetarily adjusted⁷⁰by the IPCA⁷¹: (1) Fixed Assets in Use (New Replacement Value); (3) Special Gross Obligations; (10) Stockroom in Operation; (11) Deferred Asset; (13) Real Properties and Easements;

⁷⁰The IPCA is applied directly to the value observed from the Initial Base, also considering their increments and write-off throughout the evaluation period ⁷¹National Price Index to the Broad Consumer – IBGE, according to PRORET Submodule 2.3 V5, review 2.0, with date of effectiveness on 11/23/2015 and after, according to Normative Review no. 686/2015, dated 11/23/2015

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(15) RGR PLPT Balance;

(16) RGR Balance Other Investments.

(5)	Gross Remuneration Base = (1)-(2)-(3)-(4);
(7)	Net AIS (Market Value in Use);
(9)	Remuneration Base Value (VBR);
(14)	Total Net Remuneration Base = (1)-(6)-(8)+(10)+(11)-(12)+(13);
(18)	Regulatory Reintegration Quota = (5)*(17);
(22)	Remuneration of Capital (RC) = (15)(20)+(16)(21)+[(14)-(15)-(16)]*(19).

The percentage items are not monetarily adjusted by any index. These items are: (17) Depreciation Rate; (19) Effective WACC before Taxes; (20) RGR PLPT Rate; (21) RGR Rate Other Investments.

Finally, items net of their depreciations, depreciations, and complete usage rates are treated specifically and have their money adjustments obtained indirectly.

Item (2) Complete Usage Rate is obtained by multiplying item (1) Fixed Assets in Use (New Replacement Value)⁷²by the ratio of the values of the Initial Base between item (2) over item (1).

Item (4) Fully Depreciated Assets is obtained by multiplying item (1) Fixed Assets in Use (New Replacement Value)⁷³by the ratio between the Accumulated Fully Depreciated Assets over the Accumulated VNR, both items of the ratio are in the same monetary date.

⁷²Monetarily adjusted by the IPCA as highlighted above ⁷³Monetarily adjusted by the IPCA as highlighted above

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On its turn, the (6) Accumulated Depreciation is found by multiplying item (1) Fixed Assets in Use (New Replacement Value) by the ratio between the accumulated depreciation and the Accumulated VNR, with both last items being in the same monetary date.

Item (8) Depreciated Usage Rate is also monetarily adjusted indirectly, multiplying item (2) Complete Usage Rate⁷⁴by the subtraction of one by the ratio between the Depreciation of the Accumulated Usage Rate over the Accumulated Gross Usage Rate, with both items of the ratio being in the same monetary date.

Finally, item (12) Net Special Obligations⁷⁵is obtained by multiplying item (3) Special Gross Obligations by one less the ratio between the Depreciation of the Accumulated Special Obligation over the Accumulated Gross Special Obligation, with both items of the ratio being in the same monetary date.

Increments and Composition of the Regulatory Remuneration Base Lines

The assets will have increments throughout the period of concession, which are net of write-off, and that are contemplated in the economic-financial evaluation of distributors.

The items of the Regulatory Remuneration Base are affected differently by these increments and may be divided into five groups:

Items with Direct Increments; Items Consisting of Formulas; Percentage Items; Items without Increments; Other Items.

Part of the items of the Regulatory Remuneration Base are incremented directly, as detailed below: (1) Fixed Assets in Use (New Replacement Value); (3) Special Gross Obligations; (10) Stockroom in Operation; (13) Real Properties and Easements;

⁷⁴Monetarily adjusted by the IPCA as highlighted above ⁷⁵Monetarily adjusted by the IPCA as highlighted above

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Items (1), (10) and (13) have their increment values of the Regulatory Remuneration Base detailed in section “Economic-Financial Evaluation” of this document, in section “Investment Forecasting” and, on its turn item (3), is detailed in chapter “Special Obligations”.

Items consisting of formulas, i.e., using the lines of the Regulatory Remuneration Base to be calculated, are monetarily updated indirectly, using the calculations over the items over which the accounts are realized, already with their respective increments. The composition of the formulas of these items is the same according to the provisions established by the regulatory agency⁷⁶, these items being:

(5)	Gross Remuneration Base = (1)-(2)-(3)-(4);
(7)	Net AIS (Market Value in Use);
(9)	Remuneration Base Value (VBR);
(14)	Total Net Remuneration Base = (1)-(6)-(8)+(10)+(11)-(12)+(13);
(18)	Regulatory Reintegration Quota = (5)*(17);
(22)	Remuneration of Capital (RC) = (15)(20)+(16)(21)+[(14)-(15)-(16)]*(19).

Percentage items are not affected by increments. Their percentages are established by regulation and the values verified in the 3CRTP of each evaluated distributor are kept constant. These items are:

(17) Depreciation Rate;

(19) Effective WACC before Taxes; (20) RGR PLPT Rate; (21) RGR Rate Other Investments.

These percentages are maintained unaltered throughout the entire valuation period.

Part of the items of the Regulatory Remuneration Base do not have increments, being only adjusted monetarily by the IPCA, considering the 3CRTP values allocated to each distributor.

(11) Deferred Asset;

(15) RGR PLPT Balance;


⁷⁶ANEEL PRORET Submodule 2.3, V2.0, of Normative Resolution no. 686/2015, dated 11/23/2015
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(16) RGR Balance Other Investments.

At last, the other items of the Regulatory Remuneration Base have particularities related to their composition and their increments, which are not related to the groups above.

Item (2) Complete Usage Rate is obtained by multiplying item (1) Fixed Assets in Use (New Replacement Value)⁷⁷of the period for the ratio of the values of the Initial Base between item (2) over item (1).

Item (4) Fully Depreciated Assets is detailed in the topic below “Fully Depreciated Assets”, of this same Chapter “Regulatory Remuneration Base Flow”.

Item (6) Accumulated Depreciation is calculated from the sum of the depreciation of the Initial Base, summed to the depreciation of the Incremental Base throughout the period of concession. Greater detail of the depreciation may be found in Chapter “Investment Forecasting” of this same section.

Item (8) Depreciated Usage Rate is calculated from the multiplication of item (2) Complete Usage Rate by one less the ratio between the Depreciation of the Accumulated Usage Rate over the Accumulated Gross Usage Rate, considering the components of the ratio in the same monetary date.

Finally, item (12) Net Special Obligations is obtained with the multiplication of item (3) Special Gross Obligations, by one less the ratio between the Depreciation of the Accumulated Special Obligation and the Special Gross Obligation, considering the components of the ratio in the same monetary date.


⁷⁷Monetarily adjusted by the IPCA as highlighted above
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Considerations on Assets in Course

It should be noted that this work does not incorporate the Fixed Assets positions in course of the enterprise to the Remuneration Base.

The evaluation reports of the Remuneration Base did not perform any treatment regarding the items of Fixed Assets in Course, due to the fact that this type of asset is not part of the scope of contract. In addition, the accounting position from the audited Financial Statements of the evaluated Distributor does not allow the acknowledgement of relevant particularities for the amounts in course to be considered.

Thus, based on the reports of the evaluators of the Remuneration Base and the audited Financial Statements, the following information cannot be extracted:

what are the assets in operation not unitized;
which amounts represent works in progress;
which values refer to improvements or expansions interrupted;
the New Replacement Value (VNR) of Fixed Assets in course;
the depreciation rate to be applied and the moment in which its application begun;
the usage rate of the assets for the cases in which the asset is already in use, and
the source of financing of these assets in course.

These restrictions impede the estimate of the effective impact that the Fixed Assets in Course may generated to the Initial Remuneration Base and, consequently, to the respective tax impact.

Since the minimum set of premises to include these assets in course in the Remuneration Base was not met, it is not possible to obtain reasonable consistency regarding to

eligibility for provision;
physical-accounting conciliation;
sources of financing, and
other parameters of the reevaluation procedure (such as the VNR calculation, depreciation, usage rate, and write-off evaluations).

Thus, the effects of Fixed Assets in Course to the Remuneration Base were not included in this economic-financial evaluation document. The investor shall then analyze the criterion of adoption of the parameters to be considered.

Finally, for Eletrobras Distribuição Rondônia, it is highlighted the Equity Evaluation Report “Centrais Elétricas de Rondônia – CERON”, performed by Deloitte, which brings the balance for this Fixed Asset in Progress, as observed in the table below.

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Special Obligations

Common Analyses to Distributors

The Special Obligations consist of resources related to: financial participation of the consumer, budget appropriation of the Government, federal, state, and municipal charges, and charges of special credits related to the investments applied to the enterprises linked to the concession.

The Special Obligations were calculated in two periods: The first for Dec/16, which used the position of Dec/16 made available by the evaluated distributors. The second from 2017, which excluded from the analytical bases of Special Obligations all nonrecurring items.

Bases with different levels of detail were provided, some distributors had specific treatments to define the recurring items. “Luz para Todos” Program (PLPT)⁸⁴is considered as a recurring item during its period of effectiveness for which distributors have expense forecasting (until 2019).

For the other Special Obligations, recurring items have been considered as those that in the past 5 years presented at least three variations of value, or that in the past three years had at least two years with variation of value.


⁸⁴Detailed in the Investments chapter

Indicators of Quality

Analysis of Indicators of Quality

The levels of the indicators of quality achieved by the evaluated distributors throughout the concession period (03/01/2018 to 02/28/2048) were estimated, the targets established by ANEEL in the same period were forecasted.

Seven indicators were evaluated:

DEC (Equivalent Duration of Interruption per Consumption Unit); FEC (Equivalent Frequency of Interruption per Consumption Unit); FER (Equivalent Frequency of Complaint); IASC (ANEEL Rating of Consumer Satisfaction); IAb (Telephone Support Abandonment Rate); ICO (Indicator of Busy Calls of Telephone Support).

These indicators affect the Component of Quality of Service Q of Factor X and may influence the values of Installment B of distributors, in accordance with the coverage or not of the regulatory targets established by ANEEL. The levels of coverage or not of each distributor are compared with the results obtained by the distributors of a same group⁸⁵. A distributor may be between the 25% best or worst companies to whether achieve or not the target, or between the other 75% that whether achieve or not the levels established by ANEEL.

Summing all indicators, the addition or reduction value of Installment B may be of 2%, depending on the level of coverage of ANEEL targets by the distributor in each indicator, also compared to the other distributors of its group.

The equations and parameters for the classes of each indicator were used in accordance with ANEEL’s PRORET 2.5 V2.0.

The weights equivalent to each indicator are presented below:


⁸⁵Groups are defined by size of company, as per Submodule 2.5 V2.0 of ANEEL’s PRORET
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calendar year, such difference shall be invested doubled in the concession and included in entry Obligations Linked to the Electric Power Public Service (Special Obligations).”

DEC and FEC

Common Analyses to Distributors

Forecasting of Indicators Performed by the Companies

The indicator of DEC (Equivalent Duration of Interruption per Consumption Unit) consists of the time in which a Consumption Unit (UC) remained without electric power for a certain period and the indicator of FEC (Equivalent Frequency of Interruption per Consumption Unit) consists of the number of times that an UV had no electricity for a given period.

The analyses⁸⁹may be divided into three parts: Starting Point, Indicator Variation Rate and ANEEL Limit.

The starting point consists of the DEC and FEC estimates for 2017 and is the result of data obtained for 2016⁹⁰and adjusted according to ANEEL’s target of reduction for 2017⁹¹of DECi and FECi⁹². Based on the history of variation of distributors, the assumption is that distributors seek and achieve the DECi reduction percentage for the DEC as a whole, and, similarly, achieve the FECi percentage for the FEC as a whole.

The rate of variation of the indicator is based on the rate of variation realized by the private benchmark⁹³. The DEC and FEC levels of the evaluated company in 2015 are evaluated and compared with the history of the private company, identifying 1993 and 2015 the most recent period in which the company had a rate near that of the evaluated company.

With the evaluation of this period of similarity of indicators, the extension of the period from this point to 2015 is evaluated, followed by the calculation of the annual geometric mean of variation of the indicator of the private company. Such indicator is initially applied in the distributors evaluated between 2018 and 2022, including both.

⁸⁹DEC and FEC Analyses are carried out in separate but have common constructive logical structure ⁹⁰Annual DEC and FEC of the case of collective indicators of continuity of ANEEL

⁹¹Procedure 48500.004245/2016-77, Vote, Table 1 – Limit for the end of 2017 for operational management. Variation % between the Determined DECi and its Limit for 2017 and the Determined FECi and its Limit for 2017 ⁹²Internal DEC and Internal FEC, indicators that accompany the interruptions occurred in the distribution system of internal origin ⁹³Companies with geographic proximity to the evaluated distributors

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The assumed premise is that the privatization will cause the evaluated company to present internal changes that will impact the improvement of the indicator, aligned with the improvement verified by other distributors, also private.

Between 2023 and 2027, the speed in which distributors adjust⁹⁴to achieve the limits established by ANEEL⁹⁵for 2027. This is possible due to the maturity that the new concession holder gains throughout the period in the management of the company, which enables a degree of improvement that is faster than that verified in the recent period by the benchmark private distributors. Subsequently, the speeds adjust to the speed verified by the private distributors.

The evolution of the indicators occurs until the distributor achieves the DEC and FEC levels of the benchmark distributors for 2015 and remain constant until the end of the concession, on February 28, 2048.

At last, it should be noted that although achieving the global regulatory DEC and FEC levels, the distributor may offset consumer in case of violation of the individual limits. Such offsetting is treated in section “Offsetting for the Transgression of the Continuity Limits”.

Forecasting of Limits Established by ANEEL

The definitions of the limits established by ANEEL are based on those established between 2014 and 2016 by ANEEL to each distributor. To 2017, the limit used was that established by no. 88/2017-SRM/SGT/SRD/ ANEEL, dated May 24, 2017, case: 48500.002667/2017-99, until November to Eletro-acre, Amazonas Energia, Ceron and Eletrobras Roraima, and until September to Cepisa and Ceal, for it consists of the limit established to distributors for the year.

The subsequent months used the limits established in Technical Note no. 149/2017-SEM/SGT/SRD/SFF/ANEEL, dated September 8, 2017, procedure 48500.002667/2017-99, thus achieving a weighted limit for 2017 between both technical notes.

Years from 2018 to 2023⁹⁶considered the provisions of Technical Note no. 149/2017-SEM/SGT/SRD/SFF/ANEEL, dated September 8, 2017, procedure 48500.002667/2017-99, related to the definitions of regulatory DEC and FEC limits for the designated distributors, which are: Eletroacre, Ceal, Amazonas Energia, Cepisa, Ceron and Eletrobras Roraima⁹⁷.

⁹⁴Approximate speed of that verified by the private companies, to be presented in the specific analysis to each distributor ⁹⁵Estimate by Ceres as exposed below ⁹⁶Until the month of the ordinary rate review. To facilitate the view, the values are presented with annual references where 2022 will represent the indicator until the month of review ⁹⁷The limit includes Boa Vista (Capital) and CERR (Countryside), with the global limits of each one, for DEC, are of 29.75 and 99.84, respectively, while for FEC are of 54.65 and 68.65

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Benchmark Group) and so successively until the indicator achieves the IASC targets defined by ANEEL for the distributors evaluated for the years as of 2017.

The IASC target used is the minimum value of 70¹¹⁰from 2017 and sustained until the end of the concession. When achieving the targets of the period, the distributors stabilize their efforts of improvement of the indicator. In the long term, companies tend to have indicators equal to the targets estimated to ANEEL. This makes companies tend to achieve the other 75% of the distributors that achieve the IASC targets.

Specific Analyses of Distributor

Ceron achieves the IASC ANEEL limits throughout the entire period of concession, which makes the distributor to be part of the 75% that achieves the target.


Table 97 - IASC Indicator – Realized/Forecasted x Target 1 of 3

Data	îìíñ	îìíò	îìíó	îìíô	îìíõ	îìîì	îìîí	îìîî	îìîï	îìîð	îìîñ
‘ealized	ñî.íñ	òì.óò	òì.óð	òò.ôñ	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì
ANEEL Liuit	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì
”%	îò%	íï%	íï%	ñ%	ì%	ì%	ì%	ì%	ì%	ì%	ì%
Source: ANEEL, Ceres Inteligência Financeira
Table 98 - IASC Indicator – Realized/Forecasted x Target 2 of 3

Data	îìîò	îìîó	îìîô	îìîõ	îìïì	îìïí	îìïî	îìïï	îìïð	îìïñ	îìïò
‘ealized	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì
ANEEL Liuit	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì	óì.ìì
”%	ì%	ì%	ì%	ì%	ì%	ì%	ì%	ì%	ì%	ì%	ì%
Source: ANEEL, Ceres Inteligência Financeira


¹¹⁰PRORET ANEEL Submodule 2.5A
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IAb

Analyses Common to the Distributors

The IAb (Indicator of Telephone Service Abandonment) consists of the list of calls abandoned by the calls received less abandoned.

The IAb base of the distributors evaluated was reviewed and they noticed that the indicators improved from 2010 and 2016, reaching in 2016 the minimum levels required by ANEEL of 4%¹¹². Therefore, they deemed that in 2017 the distributors evaluated have kept the levels of indicator in 2016.

The IAb targets of ANEEL have been perpetuated from 2017 to 2047. The companies have kept the levels established by ANEEL and become part of the group of remaining distributors – 75% - that reached the target in the period.

Specific Analyses of the Distributor

Ceron achieves the IAb ANEEL limits throughout the entire period of concession, which makes the distributor to be part of the 75% that achieves the target.


Table 111 - IAb Indicator – Realized/Forecast x Target 1 of 3

Data	îìíñ	îìíò	îìíó	îìíô	îìíõ	îìîì	îìîí	îìîî îìîï	îìîð	îìîñ
‘ealized	í.ïô	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò í.óò	í.óò	í.óò
ANEEL Liuit	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì ð.ìì	ð.ìì	ð.ìì
”%	òò%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò% ñò%	ñò%	ñò%
Source: ANEEL, Ceres Inteligência Financeira
Table 112 - IAb Indicator – Realized/Forecast x Target 2 of 3


‘ealized	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò	í.óò
ANEEL Liuit	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì	ð.ìì
”%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò%	ñò%
Source: ANEEL, Ceres Inteligência Financeira


¹¹²PRORET ANEEL Submodule 2.5A
Ceres )nteligência Financeira		svv

ICO

Analyses Common to the Distributors

The ICO (Busy Call Indicator of Telephone Service) refers to the list of busy calls over offered.

Its analysis can be divided into three main parts: Starting Point, Indicator Variation Rate and Target.

The starting point consists of the ICO estimates for 2017, which derives from indicator data of each distributor obtained from 2010 to 2016¹¹³. The average is calculated by excluding the missing data¹¹⁴from 2010 to 2016.

The indicator variation rate from 2018 to 2022 is calculated based on the variation of indicators obtained by the groups of benchmark of the outsourced distributors¹¹⁵. By using the indicators from 2010 to 2016 of each benchmark, the simple indicator average is calculated for each group established. The joint geometric average is applied per group from 2012 to 2016¹¹⁶, in which we have (Indicator 2017)*(1+Variation Rate of the Group of Benchmarks 2012-2016) and so on until the indicator reaches the targets defined by ANEEL of the distributors evaluated for the years starting in 2017 of ICO.

Between 2023 and 2027 the distributor speed is adjusted¹¹⁷to reach the target established by ANEEL¹¹⁸for 2027. This is possible thanks to the maturity that the new concessionaire acquires during the period in the company management, which allows them an improvement rate faster than that verified in the recent period by the benchmark of the outsourced distributors. Subsequently, the speeds are adjusted to the speed verified by the outsourced distributors.

The ICO target used is the maximum amount of 2%¹¹⁹from 2015, which is kept to the concession end. While reaching the targets of the period, the distributors stabilized their improvement efforts of the indicator. In the long run, the companies tend to show indicators equal to the targets estimated for ANEEL. This leads the companies to reach the remaining 75% of distributors that reach the ICO targets.

Specific Analyses of the Distributor

Ceron achieves the ICO ANEEL limits from 2027 and keep reaching them throughout the entire period of concession, which makes the distributor to be part of the 75% that achieves the target from that point.

¹¹³ICO base of Distribution Indicators of ANEEL

¹¹⁴The year of 2016 and other points along the historical series present missing data, reason which the average reference checked in the period was used ¹¹⁵Companies geographically located near the distributors evaluated ¹¹⁶The interval with longer historic period was used, without missing data among the benchmark outsourced ¹¹⁷Speed near that checked by the outsourced companies will be presented in the specific analysis for each distributor

¹¹⁸Estimated by Ceres as it will be addressed below ¹¹⁹PRORET ANEEL Submodule 2.5A

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The PTF values, Annual average variation of the distributor market and Annual average variation of the number of consuming units were maintained during concession, starting May/15, date on which they became valid.

The valuesDMWh(i) andDUC(i) were calculated according to the forecast of demand and specific consuming units per consumption class of each distributor evaluated and are discussed in the chapter of Demand Forecast of this document.

Finally, we outline that according to the official letter no. 113/2017-DR/ANEEL¹²¹in its “Clause Nineteen – Transitory Provisions”, Subclause Three, the value of Pd component will be defined as zero¹²²between the agreement execution ate and the first subsequent ordinary tariff revision.

Q Factor

The Q Component of the Factor by portions technical and commercial quality according to the following equation:

= 0.70.

36echnical

+ 0.30.

3%KIm N?E= l.

The technical component is composed by the indicators DEC (Equivalent Duration of Interruption per Consuming Unit) and FEC (Equivalent Frequency of Interruption per Consuming Unit).

The commercial component is composed by the indicators of FER (Equivalent Frequency of Complaint), IASC (ANEEL Index of Consumer’s Satisfaction), INS (Telephone Service Level Indicator), IAb (Telephone Service Abandonment Indicator) and ICO (Busy Call Indicator of Telephone Service).

These commercial and technical indicators are discussed in further details in the chapter “Quality Indicators” and take into account, among others, the provisions of the Technical Note 149/2017-SEM/SGT/SRD/SFF/ANEEL, of September 8, 2017, case 48500.002667/2017-99.

Considerations about the T Factor

The description and dates used for this component are discussed in the chapter that addresses Operating Costs and PMSO (Personnel, Materials, Services of Outsources and Others). We outline that during evaluation, between the agreement execution and the first ordinary subsequent tariff revision, its value was deemed zero¹²³, as provided in the Technical Note no. 88/2017-SEM/SGT/SRD/ANEEL¹²⁴.


¹²¹On May 3, 2017, case 48510.000502/2017-00
¹²²Also provided in the Technical Note 149/2017-SEM/SGT/SRD/SFF/ANEEL on September 8, 2017, case
48500.002667/2017-99
¹²³Also provided in the Technical Note 149/2017-SEM/SGT/SRD/SFF/ANEEL on September 8, 2017, case
48500.002667/2017-99
¹²⁴On May 24, 2017, case 48500.002667/2017-99


Ceres )nteligência Financeira	sws

Loss Forecast

The electrical distribution system losses are divided into two categories: Basic Network losses and Distribution Network losses. It its turn, the Distribution Network losses are divided into Technical Losses and Non-Technical Losses.

The Basic Network loss consists of the energy loss in the physical processes occurring between generation to the distribution system. Such loss costs are divided equally between the generator and distributor, with each company assuming 50% of the Basic Network loss. The Technical Loss consists of the energy loss inherent to the electric power transport, voltage transformation and energy measurement. They can be deemed as the consumption of equipment employed in the energy distribution. The Non-Technical Losses correspond to the difference between total losses and technical losses. The remaining losses are associated to the distribution system (e.g; energy robbery, measurement error, invoicing error, etc.). These are losses related to the commercial management of the distributors.

The model is forecast in loss percentage in the energy invoiced (deemed equivalent to the energy injected in the forecasts of this work) for the Technical Losses and in the Basic Network and loss percentage in the low voltage market for the Non-Technical Losses, as established by the submodule 2.6 of PRORET.

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Technical Loss and Loss in the Basic Grid

The regulatory loss consists in the amounts of efficient loss defined as a target for the distributor in the tariff review period. It has been assumed that the real Loss in the Basic Grid and the Technical Loss will be equal to the calculated regulatory ones. The Technical Loss was calculated by ANEEL¹²⁸in the last tariff review cycle in 2013, and considered the physical characteristics of the distribution system and the distributors´ equipment. The real Loss in the Basic Grid is calculated monthly by CCEE¹²⁹and the regulatory amount is provided by the average of the measurements in the last 12 months and the amount from the last tariff adjustment in 2016 was used. As the amounts of Technical Loss and Loss in the Basic Grid are not related to the distributor´s activity and its distributed power administration, but to physical processes and the characteristics of the used equipment, it was defined that for both indicators, the regulatory and the real amounts will remain constant and equal along the period.

Table 140 – Level of Technical Loss and Loss in the Basic Grid.

% Loss/ Ivje ted PoÁeŒ


		Te hvi al Loss	Loss iv the Basi GŒid
		íí.íñ%	î.ðò%

Source: Ceres Inteligência Financeira based on data from CCEE and ANEEL

¹²⁸Data obtained from SAMP, disclosure source defined by submodule 2.6 of PRORET ¹²⁹Data available in SPARTA, file from the last tariff adjustment (2016)

Ceres )nteligência Financeira

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Amount of Installment “A” (VPA1), considering the effective conditions on the DRP and the Benchmark Market, is calculated by considering the Off-Balance Sheet Account of Variation of Amounts for Items of Installment A (CVA), which is adjusted by SELIC and includes the electric power related to the Isolated Systems: the average cost of power traded in the Regulated Contracting Territory (ACR), Transmission Costs and sectorial charges, with the amounts of the tables below.

Solvency Indicators

Draft of the new template for Agreement for Public Service Concession of Electric Power Distribution, issued on May 3, 2017 by Aneel and under the liability of the CEO, Romeu Donizete Rufino, sets forth, in its attachment II, the efficiency parameters in the economic and financial management, as follows:

Compliance with the Efficiency Criterion in relation to the Economic-Financial Management shall depend upon compliance with the following inequalities:

(I)	LAJIDA ≥ 0 (until the end of 2020 and maintained in 2021, 2022 and 2023);
(II)	[LAJIDA (-) QRR] ≥ 0 (until the end of 2021 and maintained in 2022 and 2023);
(III)	{Net Debt / [LAJIDA (-) QRR]} ≤ 1 / (0,8 * SELIC) (until the end of 2022); and
(IV)	{Net Debt / [LAJIDA (-) QRR]} ≤ 1 / (1,11 * SELIC) (until the end of 2023).

The first set of analyzed data corresponds to the amounts realized throughout 2019, since inequalities are verified as of the year following the agreement effective period. In such case, non-compliance with one of the conditions provided above, for two following years, as of 2019, shall lead to terminated concession, as exposed in clause eighteen of the agreement.


¹³⁴Technical Record No. 380/2016-SGT/ANEEL
Ceres )nteligência Financeira		syu

Final Considerations

The fair value of the business for the Enterprise Value indicates R$ 1,524,512,239.58 to Eletrobras Distribuição Rondônia and granting of new Concession Agreement. However, the debts, liabilities with suppliers and contingencies cause the company’s Valuation to be negative at R$ 1,636,209,285.18.

Such assertion assumes that the company sale and granting of new concession would only take effect if proper conditions are structured for such investor, such as transferring existing liabilities to the current shareholder.

The Non-Recoverable Revenues, the Losses, the X Factor, the PMSO and more strongly the Power Purchase for Ceron generate current amounts which decrease the business value. Although, considering the R$ 968,555,620.00 in taxes recoverable, there is great condition to reduce such companies’ costs, business governance and management are evolved, either as to productivity, quality, continuity, among other Indicators, yet, in view of the estimated track record, such transaction shall not be sufficient to neutralize all existing liabilities at Ceron.

Analysis by multiples showed that the appraised company has an indicated amount lower than that of the compared private companies, resulting from the forecast conditions, from the regulatory expectation and from the need for forceful changes in its indicators,

Ceres )nteligência Financeira

trx

To:

Banco Nacional de Desenvolvimento Econômico e Social (Brazilian Development Bank - "BNDES") Av. República do Chile nº 100 Rio de Janeiro - RJ

Attention: Mrs. Lidiane Delesderrier Gonçalves - Manager of Contract OCS 028/2017 September 18, 2017 Dear,

Pursuant to service contract OCS 028/201 7 (“the Contract") signed February 14, 2017 by BNDES and Consortium Mais Energia B (“the Consortium”), this report presents the result of our analysis related to the Privatization of Eletrobras System Distributors.

The result of our work is detailed in this document titled “Product 10: Final Valuation Report” (“the Report”) and provides a financial valuation as of September 18, 2017, of Centrais Elétricas de Rondônia S.A.

As contemplated under the Contract, the sole purpose of the Report is to provide a valuation of Centrais Elétricas de Rondônia S.A. to BNDES, the institution responsible under Decree 8.893 for the privatization process of the Eletrobras System Distributors.

If the Report is shared with third parties, it must be provided in full so that the applicable disclaimers and limitations are effectively communicated.

Sincerely,


	Summary
1.	Introduction		9
1.1.		Context	9
1.2.		Purpose	9
1.3.		Summary of the premises	10
1.4.		Valuation	11
2.	History and Characteristics of the Concession		12
2.1.		Brief History	12
2.2.		Description of the Operating Area	13
2.3.		Socioeconomics	13
2.4.		Transportation Infrastructure	14
2.5.		Climate	17
2.6.		Geoelectric Characteristics	19
3.	Market and Consumption Unit Forecasts		24
3.1.		Market and Consumption Units (UC) History	24
3.2.		Market Forecast Methodology	26
3.3.		Market Forecast Results	33
3.4.		Consumption Unit Forecast Methodology	40
3.5.		UC Forecast Results	42
4.	Methodologies, Premises, and Results of Readjustment and Reviews		43
4.1.		Overview	43
4.1.1.		Regulation by incentives	43
4.1.2.		Recent changes to the contractual and tariff rules of the electric power distribution.	47
4.2.		Methodologies, Premises and Results for the Definition of Portion A	64
4.2.1.		Purchase of Power and Tariff Flags	64
4.2.2.		Charges	65
4.2.3.		Transport Costs	67
4.2.4.		Financial	67
4.2.5.		Technical Losses (“PT”)	68
4.2.6.		Non-Technical Losses (“PNT”)	74
4.2.7.		Default	89
4.3.		Methodology for definition of Portion B	90
4.3.1.		Regulatory WACC	92
4.3.2.		Operational costs and Factor Xt	94
4.3.3.		Xpd and Xq Factor	108
4.3.4.		Demand Surplus, Reactive Excess and Other Revenues	113
4.3.5.		DEC and FEC Indicators	115
4.3.6.		Compensations	126
4.3.7.		Long-Term Investment	130
4.3.8.		Remuneration Base	136

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4.3.9. Tariff Transactions		151
5.	Analysis of the supplier	155
5.1.	Historical Financial Statements	155
6.	Valuation	161
6.1.	Methodology	161
6.2.	Discount Rate	161
6.3.	Assumptions	163
6.4.	Valuation by Multiples	171
6.5.	Conclusion	175
6.6.	Sensitivity	183
7.	References	184
ANNEX I – Extent of Responsibility		185
APPENDIX A – Socioeconomic Characterization of the Concession Area of Ceron		186
APPENDIX B – Methodologies of Market Projection		189
APPENDIX C - Selection of Models for Market Projections		193
APPENDIX D – Alternative Models Not Selected		195
APPENDIX E – Models of the Assessed DEC and FEC Indicators		198
APPENDIX F – Concepts and Methods of BRR Assessment		199
APPENDIX G – Company’s Debt Overview		202



	Figures

Figure 1 - Macroeconomic Assumptions		11
Figure 2 – State of Rondônia (capital highlighted)		13
Figure 3 – Federal and State Highways of Rondônia		17
Figure 4 – Total rainfall for Brazil		18
Figure 5 – Average temperatures observed to the Brazilian states		19
Figure 6 – National Interconnected System		21
Figure 7 – Regional representation based on connection to Basic Network		22
Figure 8 – Map of the State with the distribution of the substations		23
Figure 9 – GDP real growth forecasts (% p.a.) of external sources		30
Figure 10 – Schematic drawing for the total forecast of Consumption Unit		40
Figure 11 – Price cap functioning		44
Figure 12 – Yardstick Competition Functioning		45
Figure 13– Example of Periodicity of Periodical Tariff Reviews and Tariff Readjustments		45
Figure 14 – Timeline with changes to the PRORET.		49
Figure 15– Timeline with recent rulings related to the renewal of the concessions.		52
Figure 16 – Trajectory of reduction		79
Figure 17 - Periodicity of Forecast of Regulatory Non-Technical Losses Targets		83
Figure 18 - Dynamics of the Regulatory PNT Target Forecast		85
Figure 19 – Example of a model for calculation of components X Factor quality indicator		111
Figure 20 – Historical Financial Indicators		155
Figure 21 – Summarized Income Statements		156
Figure 22 – Summarized Balance Sheet		156
Figure 23 - Balance Sheet		157
Figure 24 – Result Statements of the Year		157
Figure 25 – Quality of Results		158
Figure 26 – Working Capital		159

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Figure 27 – Net Debt	159
Figure 28 – Due Diligence Financial Indicators	160
Figure 29 - Rolling WACC	163
Figure 30 – Working Capital	170
Figure 31 - EV / Net Revenues Multiples	172
Figure 32 - EV / EBITDA Multiples	173
Figure 33 - EV / BRR Multiples	173
Figure 34 - EV/ Consumer Units Multiples (R$ thousand/Number of clients)	174
Figure 35 - EV/ Distributed Energy Multiples (R$ thousands/MWh)	174



Graphs

Graph 1– Density of Total Highways (km/km²)	15
Graph 2 – Percentage of Existing and Planned Roads in 2015	15
Graph 3 – Competitiveness of generation sources	20
Graph 4 – Voltage level share in the total market (%) - Ceron Forecasts	28
Graph 5 – State GDP share in Brazil’s GDP (%) of Ceron	32
Graph 6 – Forecasted Market of Ceron in each Decade per Class of Consumption	39
Graph 7 – Forecasted Market of Ceron until 2046 per class of consumption	40
Graph 8 – Ceron UC’s Forecasts	42
Graph 9 - Average Loss per Segment of Ceron and Comparable	71
Graph 10 – Forecast of regulatory technical losses of Ceron	74
Graph 11 – Comparison between Real and Regulatory Non-Technical Losses on the Low Voltage Market	75
Graph 12 – Forecast of Verified and regulatory PNT Ceron (Invoiced)	86
Graph 13 – Example of heterogeneity curve	101
Graph 14 – Efficiency curve Ceron	104
Graph 15 – Forecast of Other Regulatory Revenues – Ceron (R$ Million)	114
Graph 16 – Forecast of Annual Demand Surplus and Reactive Excess Revenues – Ceron (R$ Million)	115
Graph 17– Verified Indicator and Limits of DEC for Ceron	116
Graph 18– Verified Indicator and Limits of FEC	117
Graph 19– History of Compensations for Violation of the Individual Indicators of Ceron	117
Graph 20 - DEC Forecast for Ceron	124
Graph 21 - FEC Forecast for Ceron	125
Graph 22 – Forecasted Compensation Ceron	130
Graph23 - Forecast for electric and non-electric investments Ceron	135
Graph 24 - Long-Term Investments Plan of Ceron per Type of Works/Systems	135
Graph 25 – Tariff Transactions (%)	154



Tables

Table 1 – Valuation	11
Table 2 – Highway Indicators to Rondônia	16
Table 3 – Climate characteristic of the state of Rondônia	18
Table 4 – Evolution of the Number of Consumers per Voltage Level	24
Table 5 – Market Evolution per Voltage Level	25
Table 6 – Mid-Market Evolution per Voltage Level	25
Table 7 – Evolution of the Average Consumption per Tariff Class	26
Table 8 – Variables used in the market forecasts per class of Ceron	29
Table 9 – State GDP share in Brazil’s GDP (%)	31
Table 10 – Average GDP growth rates (%)	32
Table 11 – Forecasted Market of Ceron in each Decade per Class of Consumption	39
Table 12 – Summary of UC’s Forecasts for Ceron	42
Table 13- Values Factor T and Xpd	58
Table 14 - Values of Regulatory Losses	58

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Table 15 - DEC and FEC Global Limits in TN No. 088/2017	59
Table 16 - Variation of the amounts destined to PMSO per Distributor	62
Table 17 - Variation of the DEC limits per Distributor	63
Table 18 - Variation of the FEC limits per Distributor	63
Table 19 - Amount of Losses in the Distribution System of the Company	69
Table 20 - Amount of Technical Losses per Segment of Transformation and Grid	69
Table 21 - Technical Losses, Target per Voltage Segment	72
Table 22 - Amount of Technical Losses per Segment of Transformation and Grid	73

Table 23 – Socioeconomic Variables for the Composition of the Complexity Factor to Fight Non-Technical Losses 76


Table 24 - Models Selected for the Composition of the Complexity Factor to Fight Non-Technical Losses	76
Table 25 - Result of the Complexity Factors of each Econometric Model to Companies of Grupo Eletrobras	77
Table 26 - Average Complexity Index of the Companies of Grupo Eletrobras	77
Table 27 - Summary of Definition of the Starting Point	81
Table 28 - Example of Forecast of the Regulatory Non-Technical Losses	82
Table 29 - Comparison of Verified Loss Invoiced with Regulatory Loss Invoiced	84
Table 30 - Complexity Index of Fighting Non-Technical Losses of the most Complex Companies of Group 1	84
Table 31 - Forecast Regulatory PNT 2023 to 2027	86
Table 32 - Forecast Regulatory PNT 2028 to 2032	87
Table 33 - Forecast Regulatory PNT 2033 to 2037	87
Table 34 – Forecast Regulatory PNT 2038 to 2042	88
Table 35 – Forecast Regulatory PNT 2043 to 2047	88
Table 36 – Operational Costs Efficiency Parameters in 4CRTP	96
Table 37 – Confidence intervals of the efficiency estimations	97
Table 38 – Cluster Composition	101
Table 39 – Composition of the clusters and efficiency - Ceron	103
Table 40 – Forecast of Regulatory PMSO Ceron	104
Table 41 – Grid forecast modeling results	107
Table 42 – Operational Costs and Component T of Ceron	108
Table 43 – Technical and commercial indicators of component Q of Factor X	110
Table 44 – Commercial indicators in 2016 - Ceron	112
Table45 – Results for Factor X and its components Ceron	113
Table 46 – Verified/ Forecasted Verified and Approved/ Verified Limit of DEC for Ceron	124
Table 47 - Verified/ Forecasted Verified and Approved/ Verified Limit of FEC for Ceron	125
Table 48 – Compensation Regression Table	129
Table 49- Forecast of Quinquennial Investments 2018-2022	131
Table 50 - Investments in HV Expansion works 2018-2022	132
Table 51 - Mean, Standard deviation and Limits for HV Expansion works	132
Table 52 - Investments in HV Expansion work (outliers excluded)	132
Table 53 - Investments in HV Expansion works 2023-2027	133
Table 54 - Forecast of Investments for the Quinquennium of Ceron	134
Table 55 – Proportions of the Groups of Assets in BAR	140
Table 56 - Calculation of the AIS Considered in the BRR Model in Feb/17	143
Table 57 – Difference between the Initial and the Final Additional AIS (VOC) of the 3rd RTP	143
Table 58 – Values of BRR Considered Starting Point in the Frozen BRR in Feb/17	144
Table 59 – Investments between 2018 and December 2022 per Registration Unit: Impact on the Average
depreciation rate of the Assets	148
Table 60 – Assumptions for Index and Rate Forecast	149
Table 61 – TJLP Forecast	149
Table 62 – Forecast of Regulatory Reintegration Quota in RTPs	150
Table 63 – Forecast for Equity Remuneration without Special obligations in RTPs	150
Table 64 – Forecast for Equity Remuneration of the Special obligations in RTPs	151
Table 65 – Forecast of the Annual Fixed or Portable Facilities Cost in RTPs	151
Table 66 – Estimations for Required Revenues, VPA and VPB for Ceron (rated R$ million)	153
Table 67 - Unlevered Beta of comparable companies	162
Table 68 - Transaction Multiples	171
Table 69 – Distributed Energy Projections	175
Table 70 - Net Revenues Projections	176
Table 71 - Operating Costs Projections	177

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Table 72 - Gross profit Projections		178
Table 73 - Operating Expenses Projections		178
Table 74 - EBITDA Projections		180
Table 75 - Net Income Projections		180
Table 76 - Cash Flow Projections		181
Table 77 – Terminal Value		182
Table 78 – Valuation Results		182
Table 79 – Financial Covenants		182
Table 80 – Sensitivity Analysis		183
Table 81 – Demographic Information, Education Level, and Unemployment Rates		186
Table 82 – Information on Access to Services		187
Table 83 – Information on Income		187
Table 84 – Violence Information		188
Table 85 – Family of Exponential Models		191
Table 86 – Statistical Indicators		194
Table 87 – Residential Class: Ceron		195
Table 88 – Industrial Class: Ceron		195
Table 89 – Commercial Class: Ceron		196
Table 90 – Rural Class: Ceron		196
Table 91 – Public Entities: Ceron		197
Table 92 – Utilities: Ceron		197



Charts

Chart 1 – Socioeconomic characterization of the state of Rondônia		14
Chart 2 – Summary chart with the forecast model for Residential Consumption of Ceron		33
Chart 3 – Summary chart with the forecast model for Industrial Consumption of Ceron		34
Chart 4 – Summary chart with the forecast model for Commercial Consumption of Ceron		34
Chart 5 – Summary chart with the forecast model for Rural Consumption of Ceron		35
Chart 6 – Summary of the forecast model for the Consumption of Public Service o Ceron		36
Chart 7 – Summary of the forecast model for the Consumption of Public Lighting of Ceron		36
Chart 8 – Summary of the forecast model for the Consumption of Public Service of Ceron		37
Chart	9 – Summary chart with the forecast model for Own Consumption of Ceron	38
Chart 10 – Example of the need of investments in HV Expansion for the period between 2023-2027		132


Equations
Equation 1 - Box Cox Transformation		27
Equation 2 - Domiciliary Density Calculation		41
Equation 3 – Kt Coverage		41
Equation 4 – Residential UC’s Forecast		41
Equation 5 – Average Consumption Series		42
Equation 6 - UC’s Forecast		42
Equation 7 - Formula for the Maximum Cap Price and Periodical Readjustment		43
Equation 8 - Formulation for Tariff Readjustment Rate		46
Equation 9 - Formulation for the Complexity Factor of Fight Non-Technical Loss of Company A		77
Equation 10 - Calculation of Targets of Non-Technical Losses		78
Equation 11 - Global Target		78
Equation 12 – Value of Non-recoverable revenues for companies, which have not undergone 4CRTP yet		89
Equation 13 – Value of Non-recoverable revenues for companies that have undergone 4CRTP		90
Equation 14 – Calculation of Portion B in adjustment processes		91
Equation 15 – Calculation of Portion B in review processes		91
Equation 16 – Operational Cost Tariff Coverage		98
Equation 17 – Value of the Efficient operational costs		99
Equation 18 – Annual Variation of the Regulatory Operational Costs		99

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Equation 19 – Target of Efficient operational costs	99
Equation 20 – Target of shared Efficient operational costs	99
Equation 21 – Standardization of variables	100
Equation 22 – Euclidean Distance	100
Equation 23 – Efficiency Indicator	102
Equation 24 – Value of the Efficient operational costs	105
Equation 25 – Update Factor	105
Equation 26 – Operational Cost in Tariff review	107
Equation 27 – Component T of Factor X	107
Equation 28 – Component Pd of X Factor	108
Equation 29 – Component Q of Factor X	110
Equation 30 – Determination of Heterogeneity	119
Equation 31 - Limit Equation	121
Equation 32 – Simplified Limit Equation	121
Equation 33 – Linear Regression Equations for DEC	122
Equation 34 – Linear Regression Equations for FEC	122
Equation 35 - Calculation of the average EUSD	126
Equation 36 - Calculation of the Compensation in Force	127
Equation 37 - Forecasted Compensation	129
Equation 38 – Regulatory Reintegration Quota	136
Equation 39 – Gross BRR	137
Equation 40 – Capital Remuneration	137
Equation 41 – Net Regulatory Remuneration Base	138
Equation 42 – Special Obligations Capital Remuneration	138
Equation 43 – Regulatory Annuity Base (BAR)	139
Equation 44 – Annual Rental Cost (CAL)	140
Equation 45 – Annual vehicle Cost (CAV)	140
Equation 46 – Annual Cost of Information Systems (CAI)	141
Equation 47 - Stationary Series	189
Equation 48 - Seasonal Series	189
Equation 49 - Box & Jenkins Methodology Models	190
Equation 50 – ETS Model	190
Equation 51 - Dynamic Model	192

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1. Introduction
1.1. Context

Centrais Elétricas de Rondônia S.A. – CERON (“CERON”, the “Distributor”, or the “Company”) is a quasi-public company headquartered in Porto Velho, the capital of the State of Rondônia. It is a federal utility concession holder responsible for the sale and distribution of electricity in the State of Rondônia. The Company, which was previously controlled by the State Government, is currently controlled by Centrais Elétricas Brasileiras S.A. - Eletrobras, who holds 100% of its shares.

According to Article 2 of Decree 8.893, the Development Bank (BNDES) is responsible for the supervision and execution of the privatization process of the electric distributorship concession holders.

In this context, the Consortium has prepared the financial valuation of the Company’s shares with a base date of December 31, 2016, using a Discounted Cash Flow (“DCF”) methodology. The financial valuation assumes the scenario of renewal of the concession for electric power distribution. Therefore, the result of this work represents the Company’s value in the event of concession renewal.

1.2. Purpose

The purpose of this report is to provide BNDES, the leader of the project, with information regarding the company’s Fair Value, making clear all assumptions used for calculations of portions A and B, as well as the methodologies used in the financial model.

With this purpose, the following analyses were carried out:· Research and analysis or market information;

· Projections for the energy market, energy demand and regulatory elements;· Analysis of the historical financial statements;· Meetings, conference calls, and discussions with the directors and technical teams of the Company;· Field visits;· financial statements projections (Income Statements and Cash Flow Statements) based on information provided by the Company, market analyses, and due diligence studies;· Financial valuation based on Discounted Cash Flow methodology;· Calculation and projection of the discount rate based on the Weighted Average Cost of Capital (WACC) methodology, used for calculating the present value of projected· cash flows; Calculation and projection of regulatory WACC.

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1.3.Summary of the premises

Methodology

The valuation of the Company was performed using the Discounted Cash Flow method, based on the projected profits, utilizing Free Cash Flow to the Firm (FCFF).

Discount rate

The methodology used to estimate the discount rate was the Weighted Average Cost of Capital (WACC), considering a rolling capital structure (Rolling WACC).

Base date

The base date used for this valuation is December 31,2016.

Projection period

The cash flows were estimated for the period between January 1, 2017 and February 29, 2048 (end of the concession period) assuming operational shutdown of the Company at the end of the concession period. Only the cash flows projected for the period between March, 2018, and February, 2048, were considered in calculating the Net Present Value of the Company.

Currency

The projections are expressed in nominal Reais (R$) considering inflation effects.

Macroeconomic assumptions

The macroeconomic assumptions used in the financial model are presented below. It is important to highlight that the GDP premise was used in the projection of the number of consumers by market class as detailed in Chapter 4 of this report.

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2. History and Characteristics of the Concession

This chapter will detail relevant characteristics of Ceron, providing information regarding its background, socioeconomics, transportation infrastructure, climate, level of connectedness to the SIN and standards of the electric power distribution grids.

2.1.Brief History

This history of Rondônia started in the early 17th century with the arrival of the first Portuguese colonizers. However, only in the next century, with the discovery of gold in Goiás and Mato Grosso, did interest in the region intensify. With the creation of the state of Acre, the construction of Madeira-Mamoré railroad, and the telegraphic connection established by Cândido Rondon in the early 20th century, the colonization of the region was accelerated until, in 1943, the region became the Território Federal de Guaporé (in 1956 renamed Território de Rondônia), with its capital in Porto Velho and created out of partitions from the states of Mato Grosso and Amazonas [1].

The first thermoelectric plant in Rondônia was opened in 1940 by President Getúlio Vargas. After the creation of Território Federal de Guaporé, the plant became known as SAALFT - Serviço de Abastecimento de Água, Luz e Força do Território, and served only two cities: Porto Velho, the Capital, and Guajará Mirim. This thermoelectric plant was diesel-oil powered and had capacity of 2,893 KW.

The accelerated growth of the region in fact only occurred in 1960’s and 1970’s. The policy of fiscal incentives and the intensive investments of the federal government, such as the directed colonization projects, stimulated migration, mostly from the Center-South of the country. With the growth of the region, the development of sanitation and electric power infrastructure was required. Thus, in 1968, the services of SAALFT were divided and CAERD (Companhia de Águas e Esgotos de Rondônia) and Ceron (Centrais Elétricas de Rondônia) were created [2].

In that same year, in 1968, Centrais Elétricas de Rondônia S.A., under the abbreviation Ceron, was tasked with the purpose of developing the electric power services, and performing transmission and distribution services in the territory of Rondônia.

After almost 30 years, in 1997, a new benchmark was established and Ceron fell under a shared management between the Government of the State of Rondônia (instituted as a State in

1982) and Eletrobras. The State became holder of 51% of the company’s shares, while Eletrobras was entitled to 48.7% of the shares. Also in 1997, the supplier was made a federal company, according to the State Law no. 740/97. The State approved the transfer of the controlling interest from Ceron to Eletrobras. The share were distributed as follows: 79.91% - Eletrobras, 20.0% -State of Rondônia, and 0.09% - other shareholders. [3] In 1998, Ceron went through new changes to its shareholder composition due to the sale of shares to Eletrobras, which acquired 100% of the shares of the company.

Finally, in July 2016, the Eletrobras group decided not to renew the contracts of electric power suppliers in the North and Northeast regions, including Ceron. On August 3, 2016, through Ordinance No. 423/2016, the Ministry of Mines and Energy (MME) designated Ceron responsible

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same value from January to December of the respective year has been applied. As of

January/2015, the market share of the Federative Unit’s GDP was forecasted using the trend of past values, in the periods with greater potential growth of the market share, and the values were kept as constant market share as of January/2030, converging with the growth of the national GDP. Such forecast of the market share in the forecast of the total monthly GDP was applied at real values of 2000, obtaining the effective monthly total GDP for the Federative Units used.

Table 9 presents the market share of each State GDP between 2002 and 2014. In all States forming one of the areas of concession of the 6 companies, except for Alagoas, there is an increase of its economic relevance in a period of 12 years. This context results from a gradual, non-uniform trend of deconcentration of the economic activities of the South and Southeast regions to the other regions of Brazil. This trend occurs due to several reasons, such as, for instance: dislocation from the modern and exporting agricultural front to the States of Northeast and North regions, faster growth of the population in these States, expansion of the service services (especially tourism), increase to the weight of the traditional industry – seeking more competitive costs – and the commercial segment – which follows the general trend of the regional economy –, among others.


Table 9 – State GDP share in Brazil’s GDP (%)


UF	2002	2003	2004	2005	2006	2007	2008	2009	2010	2011	2012	2013	2014	(2002-2014)
Brazil	100	100	100	100	100	100	100	100	100	100	100	100	100	-
Rondonia	0.5	0.55	0.56	0.58	0.54	0.53	0.56	0.59	0.62	0.63	0.63	0.58	0.59	0.09
Acre	0.2	0.2	0.19	0.2	0.19	0.2	0.21	0.22	0.21	0.2	0.21	0.22	0.23	0.03
Amazonas	1.48	1.51	1.59	1.57	1.66	1.6	1.55	1.52	1.57	1.62	1.5	1.56	15	0.02
Roraima	0.16	0.15	0.14	0.15	0.16	0.15	0.16	0.17	0.17	0.17	0.16	0.17	0.17	0.01
Para	1.78	1.76	1.9	1.87	1.91	1.91	1.96	1.85	2.13	2.26	2.22	2.27	2.16	0.38
Amapa	0.21	0.2	0.2	0.2	0.22	0.22	0.22	0.22	0.21	0.22	0.23	0.24	0.23	0.02
Tocantins	0.36	0.38	0.37	0.36	0.36	0.37	0.39	0.41	0.42	0.42	0.43	0.45	0.45	0.09
Maranhao	1.07	1.14	1.13	1.16	1.23	1.13	1.22	1.23	1.19	1.19	1.26	1.27	1.33	0.26
Piauf	0.48	0.49	0.48	0.49	0.55	0.5	0.52	0.57	0.57	0.59	0.59	0.59	0.65	0.17
Ceara	1.93	1.9	1.88	1.89	1.93	1.87	1.94	2.02	2.04	2.05	2.01	2.05	2.18	0.25
Rio Grande do Norte	0.91	0.87	0.88	0.92	0.95	0.97	0.93	0.93	0.93	0.94	0.96	0.97	0.93	0.02
Para fb a	0.86	0.86	0.8	0.81	0.86	0.84	0.86	0.91	0.86	0.85	0.88	0.87	0.92	0.06
Pernambuco	2.42	2.26	2.3	2.31	2.3	2.3	2.26	2.39	2.5	2.52	2.66	2.65	2.68	0.26
Alagoas	0.77	0.73	0.72	0.71	0.72	0.73	0.72	0.73	0.7	0.72	0.72	0.7	0.71	-0.06
Sergipe	0.69	0.68	0.68	0.66	0.68	0.67	0.69	0.65	0.68	0.67	0.68	0.66	0 05	-0.04
Bahia	3.95	3.91	3.98	4.07	3.96	4.02	3.91	4.14	3.97	3.81	3.79	3.84	3.87	-0.08
Minas Gerais	8.33	8.39	8.78	8.68	8.83	8.84	8.96	8.62	9.04	9.14	9.19	9.15	8.94	0.61
Espirito Santo	1.82	1.83	2.03	2.17	2.22	2.23	2.32	2.08	2.2	2.42	2.43	2.2	2.23	0.41
Rio de Janeiro	12.38	11.8	12.32	12.43	12.44	11.9	12.16	11.75	11.58	11.72	11.94	11.78	11.61	-0.77
Sao Paulo	34.85	34.43	33.35	34.23	34.22	34.4	33.52	33.82	33.32	32.83	32.38	32.17	32.15	-2.7
Parana	5.93	6.41	6.31	5.87	5.71	6.07	5.97	5.9	5.8	5.88	5.93	6.25	6.02	0.09
Santa Catarina	3.66	3.73	3.76	3.76	3.78	3.81	3.91	3.87	3.96	3.98	3.98	4.02	4.2	0.54
Rio Grande do Sul	6.64	6.95	6.7	6.28	6.13	6.18	6.12	6.13	6.21	6.06	5.97	6.23	6.19	-0.45
Mato Grosso do Sul	1.1	1.27	1.19	1.09	1.11	1.11	1.16	1.19	1.22	1.26	1.29	1.3	1.37	0.27
Mato Grosso	1.29	1.55	1.71	1.58	1.27	1.4	1.58	1.58	1.46	1.58	1.65	1.67	1.75	0.46
Goias	2.59	2.65	2.61	2.48	2.55	2.63	2.65	2.79	2.75	2.77	2.88	2.84	2.86	0.27
Distrito Federal	3.62	3.4	3.43	3.49	_ 3.51	3.43	3.55	3.73	3.71	3.53	3.41	3.3	3.42	-0.2
Source: IBGE

Considering the long term time window of our forecasts, we assume that this trend of deconcentration of the economic activity will be maintained in the following years to all analyzed States. Thus, we have forecasted, from the historical series, a gradual expansion of the GDP share of these States until 2030. The GDP growth of each States grows more than the national average in this phase of convergence and will subsequently accompany the median expansion of the

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at any time, whenever an event causes substantial economic-financial instability. The RTE may be requested in cases of creation, change or extinction of taxes or charges, after the execution of the concession agreements, and whenever the impact over the activities of the companies is relevant, and duly proven, to the economic-financial equilibrium.

e) Manageable and non-manageable part

Non-manageable costs correspond to expenses that do not depend on the control of the concessionaire, being directly transferred to the consumer. These items form a relevant part of Portion A, component of the revenue of the concessionaire of distribution that includes costs and sectoral charges, in addition to costs of inputs and upstream segments of the activities of the regulated company, such as costs of power generated or transmitted to the electric power distribution companies. On their turn, manageable costs represent the part related to the effective activity of the electric power distribution concessionaire, in which the company may establish strategies of management. The so-called Portion B is composed, for instance, by the operational costs, capital and depreciation costs, and non-recoverable revenues.

There are also costs that present a relative degree of management by the concessionaire. This is the case, for instance, of non-technical losses (“PNT”), whose amount depends on both the efficiency of the commercial activities and routines of the concessionaire and on the socioeconomic, institutional, and cultural environment of the geographic area in which the company acts.

Although they affect the purchase of power, allocated in Portion A, technical and nontechnical losses receive regulatory treatment aiming at allowing gains of efficiency in the procedures. The purchase of power may also receive regulatory treatment and respect restriction in order to foment an efficient acquisition and modicity to the end consumer (captive).

An example of this regulatory treatment are the controls related to the purchase of power by related party and the obligations of acquisition of power in auctions in the regulated environment. Therefore, the separation of the manageable and non-manageable costs, in the so-called Parts A and B, is a conceptual simplification that may be changed in accordance with the evolution of the regulation.

4.1.2. Recent changes to the contractual and tariff rules of the electric power distribution.

The implementation of the regime of regulation by incentives in the activity of electric power distribution has been done throughout almost two decades, conditioned by changes to the concession/permit agreements and by public policies. Its evolution and transformation were also marked by the processes of discussions, in inquiries and public hearings, of the regulations that treat the different tariff and contractual aspects. Currently, these rules are described in Technical Notes elaborated by ANEEL, which describe in detail the methods, premises, and results applicable to the different components of the tariffs and the tariff operation procedures.

These regulatory rules are consolidated in the Tariff Regulation Procedures (“PRORET”), which have normative character and consolidate the regulation of tariff processes. The PRORET

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structure was approved by Normative Resolution no. 435/2011, organized in 12 modules, which on their turn are subdivided into submodules.

Regarding the distribution of electric power, there is a set of tariff procedures that include specificities to each contractual situation, as detailed below:

I.	To Distributors that renew their concession agreements under the terms of Decree no. 8.461/2015, signed contractual amendments with new economic clauses, or signed contractual amendments for the complete adhesion to the new concession model¹⁴, the new tariff rules presented in Normative Resolution no. 761/2017 and in the PRORET list indicated with the letter A in its original number shall be valid¹⁵.
II.	To companies that hold permits and distribution concessionaires that have not renewed their concession agreement or signed amendments still have valid the PRORET without the indication of letter A.
III.	For the set of Distributors owned by the Government, responsible for the provision of distribution services in concessions that have not been extended (so-called Designated Distributors), specific rules shall be applied as per Normative Resolution no. 748/2016 and Homologation Resolution no. 2.184/2016¹⁶.

Figure 14 presents a timeline with the indications of all Normative Resolutions (REN), Homologation Resolutions (REH), Technical Notes (NT), and Public Hearings (AP) that changed or proposed changes to the PRORET as of April 2015.

¹⁴	In the terms of the Reporting Judge’s Vote announced in the 30th Ordinary Public Meeting in 2016.
¹⁵	Submodules 2.1A, 2.2A, 2.5A, 2.7A, 3.1A, 3.2A, 3.3A, 3.4A, 4.2A and 4.4A.
¹⁶	Both resolutions replace Technical Note No. 331/2016, setting forth definitely the additional conditions to be

applied to the Designated distributors (public administration body or entity responsible for the decision of the Granting Authority on the provision of public service for electric power distribution because of non-extension of given concession according to Law No. 12.783/2013), with the purpose to assure the continuity of the provision of public service for electric power distribution until a new concessionaire to be granted by means of a bid takes over..

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	contractual amendment, will be subtracted from Portion B only in the second review after the 3rd RTP.
	b.	To companies that will undergo their first review after the 3rd RTP, the revenues registered as UD and ER in special obligations until the date of contractual amendment will be subtracted from Portion B.
	c.	To all companies, the invoiced values of UD and ER between the date of contractual change and the date of the tariff procedure will be used as reducers of Portion B.
	d.	The invoiced values will be updated according to the IPCA.
iii.	The RI’s are no longer calculated in two parts and now consider exclusively the regulatory percentages of default. In addition, the financial revenues now compose the basis of calculation of the RI’s.
iv.	In the first tariff review after the execution of the contractual change, the calculation of the Factor X will no longer consider the average growth of the market and consumers of the tariff cycle, being determined on an annually basis.
v.	The values of other revenues (OR) to be subtracted from Portion B will be calculated in the twelve months prior to the month of reference for the review, and will be updated by the IPCA.

The rules of tariff readjustment presented in Module 3 had the following changes:

i.	If the first tariff process after the execution of contractual change is a tariff readjustment, known as DR1 in the A version of the PRORET, there will be the need to remove the RI components from Portion B and to transfer them to Portion A, in addition to isolating OR, UD, and ER, which will be determined according to what has been effectively realized. The ONS values shall be transferred from Portion A to Portion B.
ii.	In the tariff readjustments, Portion B shall be effectively calculated and not only obtained as a residue of the calculation of Required Revenue.
iii.	The value of Portion B considering the conditions in force and the Reference Market (VPB0DR1) will be obtained from the multiplication of this market for the economic value in force (homologated in the last procedure), equivalent to the tariff component of Thread B (TUSD Thread B) in force. This value will be updated by the difference between IPCA and Factor X and multiplied by a correction factor (Factor DR1), necessary for the application of the adjustments indicated in (i). Finally, the values of OR, UD, and ER will be expurgated, and added the values with ONS.
iv.	In the subsequent tariff processes, the procedure will be quite similar in practical terms, with the calculation of Factor Pbi-1, which reintroduces the values of OR, UD, and ER in Portion B, which will be adjusted by the inflation (IPCA) and Factor X. Following that, the observed values of these components in the period of reference are excluded from Portion B.

In Module 4, the neutralities are calculated to all components of Portion A (including other financial components, financial components of neutrality, and financial component of CVA balance to compensate), not only to sectorial charges, as it is the case of the rules in force. The

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concept of neutrality remains unchanged, such as the difference between the invoiced values and the values included in the tariff processes, neutralizing the differences derived from market changes¹⁷. The proposed methodologies of calculation differentiate items with tariff coverage of fixed nature, when the expense is not changed with the market variation (sectorial charges, connection charges, and Itaipu), and variably, in the opposite case (costs with power, charges with the use of transmission/distribution, and non-recoverable revenues).

The specific case of the neutrality of non-recoverable revenues will be calculated only from the second tariff procedure after the execution of the contractual amendment, since until then there is not a component of tariff coverage for this item. All new items to which there is no calculation of neutrality shall take into account the date of execution of the agreement or contractual amendment. Therefore, for the first tariff procedure after the execution of the agreement or publication of the PRORET, whatever occurs last, the neutrality of Portion A will be calculated only from the next month of signature of the contractual amendment or renewal of the concession agreement, limited to the period of reference, i.e., the last 12 months.

Finally, the part of non-recoverable revenues was inserted in submodules 7.1 and 7.2, in the function of TUSD Losses cost. The update of submodule 3.2 impacts directly to Module 7, due to the calculation of losses in the other facilities of transmission of shared use (DITc), which is in the tariff component of losses in the basic network.

b) Additional Conditions for the Designated Distributors

In its 165th Special Meeting, the shareholders of Eletrobras decided not to approve the extension of the concessions of Ceal, Cepisa, Eletroacre, Ceron, Boa Vista Energia, and Amazonas Energia. In addition, Companhia de Eletricidade do Amapá (CEA) did not have its concession extended for it did not gather the requirements of compliance. By means of several directives, the Ministry of Mines and Energy designated Amazonas Energia, Eletroacre, Ceron, Cepisa, Ceal, Boa Vista Energia and CEA as responsible for the provision of the public service of distribution of electric power until the end of 2017 or until the assumption of a new concessionaire, whatever occurs first.

Figure 15 illustrates the timeline with recent rulings related to the renewal of the concessions of the distributors of Grupo Eletrobras.

¹⁷In this section we are describing the changed made to the PRORETs from Normative Resolution no. 276/2017, including changes to the treatment of the neutralities of charges. The modelling of the items composing Portion A in the financial model is detailed in section 3.2.

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Such resolution also establishes that the resources of RGR will be used to assure the minimum conditions of sustainability of the service, as per Directive no. 388/2016-MME, with deadlines, grace periods and fees as indicated in REN no. 748/2016, and the contracted obligations will be assumed by the new concessionaire.

In addition, REN asserts that there are major investments to be made, which will reduce expenses of CCC and, therefore, classified as subrogation of the fund’s resources. ANEEL shall homologate prudent investments considered in the elaboration of the basic project, calculate the amount to be subrogated, and inspect the application. The agency or entity of the federal public administration shall assign to the contracted company for the implementation of the distribution lines, on an irrevocable basis, the credits of reimbursement of CCC.

Finally, the resolution establishes an exceptional regime of regulatory sanctions, prioritizing the character exclusively orientational and/or determinant, without the imposition of penalties.

c) Public Hearing no. 094/2016

In May 2017, ANEEL published, after receiving contributions in Public Hearing no. 094/2016: (i) Technical Note no. 182/2017, with guidelines for the elaboration of a new agreement for the concession of the public service of electric power, as per §1-A of Article 8 of Act no. 12.783/2013; and (ii) a new Contractual Draft.

According to Technical Note no. 182/2017, dated May 2, 2017, ANEEL received Official Letter no. 242/2016-SE, of the Ministry of Mines and Energy (MME) requesting the elaboration of a draft of a concession agreement, observing a few guidelines that aim at expediting the realization and to increase competitiveness of bidding procedures of transfer of corporate control, associated with grants of new concessions. MME emphasized four guidelines:

I.	Adoption of clauses that allow the conversion of pecuniary compensations into investment obligations to the first five years of new concessions, aiming at allowing the recovery of the concessions;
II.	Adoption of trajectories of regulatory parameters of efficiency, providing the new controller with term to readjust the values adopted by the companies;
III.	Adoption of a tariff calendar with interstice of five years at every tariff review, but that allows the performance of two tariff reviews in the first five years of the agreement, allowing exceptionally, the acknowledgment in shorter investment terms;
IV.	The possibility of the calendar set forth in the item above being chosen by the winner of the bidding, with the first review occurring prior to the third tariff process after the execution of the agreement and the second review shall be carried out in the fifth tariff procedure after such signature.

According to the result of public hearing no. 094/2016 – presented in Technical Note no. 182/2017 -, transitory provisions were considered about the use of compensations due to violations of the limits of quality related to the continuity of the service and the voltage level to investment, as reproduced below.

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“CLAUSE NINETEEN – TRANSITORY PROVISIONS

Subclause One - DISTRIBUTOR may use the resources of compensations due to violation of the limits of quality, related to the continuity of the service and sampling measurements of the voltage level in a permanent regime, for the realization of investments in the area of concession, until the end of the fifth calendar year after the date of execution of the concession agreement.

Paragraph One – From the date of execution of the agreement, the compensation values shall remain being calculated by DISTRIBUTOR, as per the regulation, for the purposes of follow-up and inspection by ANEEL.

Paragraph Two – From the second calendar year following the execution of the agreement, in case the calculated values of the compensations are below the values of the compensations calculated for the previous calendar year, such difference shall be considered as a remunerable investment by DISTRIBUTOR upon its tariff review, with the remaining value being accounted in entry Obligations Linked to the Public Service of Electric Power (Special Obligations).

Paragraph Three – From the second calendar year following the execution of the agreement, in case the calculated values of compensations are higher than the compensations calculated for the previous calendar year, such different will be invested twice in the concession and accounted in entry Obligations Linked to the Public Service of

Electric Power (Special Obligations). ”

According to the Draft, as of 2020, the non-fulfillment of the global, annual limits of the indicators of continuity per determined period will cause economic-financial limitations, as established in Subclause Eight.

“Subclause Eight – As of 2020, the non-fulfillment of the annual limits of collective indicators of continuity for two years in a row or three times in five years may, as per the ANEEL regulation, imply limitation of dividends or payments of interest over its own capital, until the regulatory parameters are restored, observing the provisions of Item I of Subclause One of Clause Seven. ”

From the sixth calendar year, the non-fulfillment of the regulatory goals may imply the filing of an expiry proceeding of the concession as indicated in Subclause Thirteen, as reproduced below, applicable to the criteria related to the continuity of supply.

“Subclause Thirteen – For the period from the sixth calendar year following the execution of this agreement, the default of the concessionaire resulting from the non-fulfillment of the criteria of efficiency in relation to the continuity of the supply will imply

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service. According to ANEEL, this context consists of an atypical situation, incompatible with the type of application to which the methodology of the Factor X has been designed. Due to this reason, an adequateness of its calculation is seen as possible.

In addition, the new Draft considered that the inspection performed by ANEEL will not apply penalties in the first two years of the new contracts, as a form of mitigating the effects of the technical or commercial problems inherited from the prior situation, as set forth in Subclause Five.

“Subclause Five – Until the twenty-fifth month following the month of execution of the concession agreement, the inspection of ANEEL will have an orientative and/or determinative character, without the application of penalties, except in case of non-fulfillment of determinations by Aneel Management. ”

To meet the request by the MME regarding a tariff calendar that allows an additional tariff review in the first five years of the agreement, aiming acknowledgment in shorter term of investments, the Draft presents the transitory provisions in its Clause Nineteen.

“Subclause Two – In the period between the date of execution of the agreement and the first subsequent ordinary tariff review, a tariff review may occur upon request of the Concessionaire, observing the following criteria: I – The tariff review in lieu of an annual tariff readjustment, to which the same date of processing shall be maintained.

II – The request for review shall be formally presented to ANEEL within at least one (1) years prior to its conduction.

III – The tariff review will occur based on the rules set forth in this agreement and in the regulations in force, except those items set forth in Subclause Three.

IV – In the period of review, the Concessionaire may request the complete evaluation of the Regulatory Remuneration Base.

V – The review shall occur until the third tariff procedure after the execution of the agreement. ”

The Draft also defines the values and specific formulas of calculation for the period between the date of execution of the agreement and the first subsequent tariff review, as set forth in Subclause Three.

“Subclause Three – In the period between the date of execution of the agreement and the first subsequent ordinary tariff review, the values and formula of calculation for the

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Factor X will be used, as well as Operational Costs and Regulatory Losses, different from those set forth by Clause Six, observing the following criteria: I – The value of component Pd of Factor X will be defined as zero (0).

II – The regulatory Operational Costs will be defined considered a degree of efficiency of []% over the average of effective costs observed in the last three (3) years prior to the tariff processing.

III – Regulatory, non-technical losses will be defined in the percentage of []% over the average of the real percentages observed in the last three (3) years prior to the tariff processing.

Sole Paragraph – The tariff effects resulting from the treatment described in this Subclause will be perceived from the first tariff calculation following the execution of the agreement, always with prospective effects. ”

Subclause Four establishes the rules on the debt related to the loan existing with the RGR fund, occurred in the period of designation.

“Subclause Four – DISTRIBUTOR undertakes to settle the debt related to the loan existing with the RGR Fund occurred in the period of designation, in the following conditions: I – The interest rate to be used for the loan will be of 111% of the SELIC rate;

II	– The amortization of principal and the payment of interest will have a grace period of
12	months from the assumption of the concession by the new concessionaire, considering

that, once the grace period expires, the amortization of the loan will occur in 36 monthly, equal parts. ”

d) Public Hearing no. 032 /2017

On May 4, 2017, ANEEL placed in public hearing Technical Note no. 088/2017, aiming at gathering subsidies to improve the calculation of the regulatory parameters and indicators of quality of services that will serve as the basis for the next tariff review procedures of the Distributors controlled by Eletrobras. The Technical Note establishes the regulatory parameters for the tariff procedures of the Designated Distributors, defined under the terms of Normative Resolution no. 748/2016 and limits to the DEC and FEC collective indicators of continuity.

The proposal is that the value of the T component of Factor X is equal zero (0)to all tariff processes homologated until the first tariff review process after the execution of the Concession Agreement, while to the value of the Xpd component the recommendation is to maintain the Pd component in force until the first tariff process after the execution of the Concession Agreement, when it will assume zero value (see Table 13).

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Considering the regulatory possibility of review of the payment conditions, favoring the bidding procedure and the assumption of a new concessionaire, committed with the tariff modicity and with the quality of the service, the tariff impact was simulated considered interest of 5% p.a. and a deadline of 30 years for payment. The monthly values of RGR are defined by REH 2199/2017-ANEEL and the values are reviewed by ANEEL on a quarterly basis based on the quarterly results of distributors. According to ANEEL, the payment of the loan would begin in the sixth year of contractual effectiveness and would extend until its expiration (25 years to pay). Considering that the que loan will now be acknowledged in the tariff, there will be neutrality for the new concessionaire in terms of payment of the amounts involved.

f) Technical Note no. 247/2017

In view of Technical Note no. 351/2017, the Ministry of Mines and Energy proposed changes to the draft of the Agreement for the Concession of Public Service of Electric Power Distribution by means of Technical Note no. 247/2017. The main proposed changes related to (i) the acknowledgment in Portion A of the revenue necessary for the payment of RGR loans; (ii) definition, as an extraordinary review, of the tariff procedure that the new controller may request in the interstice of five years of the new concession, basically to consider the volume of investments in the base of assets; and (iii) clarifications on the systematic of flexibilization of the regulatory parameters of operational costs and non-technical losses until the first periodical tariff review.

The proposed changes to the Draft of Agreement mentioned in Technical Note no.

247/2017 are presented below, whose contributions were received until 09/06/2017.

“CLAUSE SIX – TARIFFS APPLICABLE IN THE PROVISION OF THE SERVICE

Portion A – Sectorial Charges: part of the revenue of the DISTRIBUTOR, destined to the observance of the obligations associated with the Electric Power Services Inspection Fee – “TFSEE”; with the Financial Compensation for the Use of Water Resources –“CFURH” for the purposes of generation of electric power, when applicable; with the System Services Fee – “ESS”; with the Energetic Development Account – “CDE”; with

Research and Development – R&D; with the Energetic Efficiency Program – “PEE”; with the Reserve Power Fee – “EER”; payments of loans of the Global Reversion Reserve –

“RGR”, made in accordance with Article 4, § 4, item VI, of Act no. 5.655, dated May 20,

1971, and the other public policies for the electric sector, defined in the supervening legislation;

CLAUSE NINETEEN – TRANSITORY PROVISIONS

Subclause Two – In the period between the date of execution of the agreement and the first subsequent ordinary tariff review, an extraordinary tariff review may occur upon request of the Concessionaire, observing the following criteria:

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Subclause Three – In the period between the date of execution of the agreement and the first subsequent ordinary tariff review, values and formula of calculation for the Factor X will be used, as well as to Operational Costs and Regulatory Losses other than those set forth in Clause Six, observing the following criteria: I – The value of component Pd of Factor X will be defined as zero (0).

II – The regulatory Operational Costs in the first tariff procedure after the execution of the concession agreement will be defined as a percentage of []% over the value of the operational costs of the previous tariff procedure, updated according to the rule of readjustment of Portion B. Between the second tariff procedure and the tariff procedure immediately before the first ordinary tariff, the operational costs will be defined by applying the rule of readjustment of Portion B.

III – Regulatory, non-technical losses will be defined in the percentage of []% over the low voltage invoiced market.

Paragraph One – The tariff effects resulting from the treatment described in this Subclause will be perceived from the first tariff calculation following the execution of the agreement, always with prospective effects.

Paragraph Two – The transitory percentages of items II and III are those resulting from the bidding procedure of the concession of electric power distribution associated with the transfer of control of the legal entity providing the service, under the terms of Art. 8 of Act no. 12.783/2013 and its regulations.

Paragraph Three – The rules set forth in Clause Six shall be applied in the first ordinary tariff review, not considering any effects resulting from the transitory percentages of items II and III.

Subclause Four – DISTRIBUTOR shall settle the loans with the RGR Fund as per Directive MME no. 388, dated July 26, 2016, adjusted as per Art. 4, § 5, of Act no. 5.655, dated May 20, 1971.

Paragraph One – The payments shall be made between the first ordinary tariff review and the final deadline of this agreement.

Paragraph Two – DISTRIBUTOR will be entitled to tariff acknowledgment of []% of loans paid, according to the definition of the bidding procedure of the concession of electric power distribution, associated with the transfer of control of the legal entity providing the service, under the terms of Art. 8 of Act no. 12.783/2013 and its regulations.

”

g) Technical Note no. 149/2017

On September 8, 2017, ANEEL reopened Public Hearing no. 032/2017, by means of Technical Note no. 149/2017. In it, the Regulator exposed its proposal of flexibilization of a few regulatory parameters – non-technical losses, operational costs and Factor X – and the limits to the DEC and FEC collective continuity indicators until the first ordinary tariff review of the new controller of the designated companies, to be contracted by means of bidding procedure. The

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03/01/2018. An adjustment (IRT) will occur in this year, on the date of anniversary of the old agreements;· An extraordinary review¹⁸will occur in 2019, on the date of anniversary of the old agreements. In such review, the tariff coverage related to the Annual Cost of Assets

(“CAA”), composed by the Remuneration of Capital, Regulatory Reintegration

Quota, and Annual Cost of Movable and Immovable Facilities will be reevaluated.

No review shall be performed to metrics of PNT, OPEX, Default, Factor X etc.;

· There will be usual IRT’s between 2020 and 2022;

· In 2023, there will be a complete RTP corresponding to the 5-year period after the execution of agreement, in which the regulatory parameters will be once again established (such as PNT, OPEX, Default, Factor X, etc.).

· After 2023, there will be both IRT and RTP in the interstice of 5 years until 2048.

The new agreement will be adapted to the tariff rules of REN no. 761/2017.

4.2. Methodologies, Premises and Results for the Definition of Portion A

Portion A is the tariff revenue component through which consumers compensate the Distributor for the costs considered as non-manageable, such as: purchase of power, sectorial charges, power transport costs, financial charges, technical losses, non-technical losses, and default.

Since these costs are considered as non-manageable, they are directly transferred to the tariffs (pass-through) according to the rules established by the Regulator, as detailed below.

The pass-through condition above is true for the cases in which the Distributor is within a regulatory interval of limits of losses and supercontracting.

4.2.1. Purchase of Power and Tariff Flags

For the definition of the amount of required power, for the purposes of regulatory purchase of power, the volumes of energy were calculated for the provision and supply. The power for provision includes the total forecasted market, excluding volumes to free market, distribution, and supply.

The Methodologies and results obtained for the total and free market forecast were presented above. The forecasts of the volumes for distribution and provision followed the estimated behavior for the total market of the concessionaire.

Using the forecasts of regulatory losses, the total losses were estimated – technical, nontechnical, and basic network. In relation to the losses of the basic network, the percentages presented in the SPARTA spreadsheet of 2016 were maintained. The required power is obtained from the sum of supply, provision, and regulatory losses.

¹⁸In this extraordinary review, the frozen asset base will be opened.

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The system of flags, applied by the concessionaires connected to the National Interconnected System – SIN, has three tariff flags (green, yellow and red) which indicate if the power costs more or less, based on the conditions of generation of electricity. For the economic-financial evaluation, the same favorable scenario of generation was considered by ANEEL in the tariff procedures, i.e., a green flag scenario.

4.2.2.Charges

The sectorial charges are all created by laws approved by the National Congress to allow the implementation of public policies in the Brazilian energetic sector. Its values are included in resolutions or decisions by the National Agency for Electric Power (ANEEL) and are paid by distributors through the electricity bill. Each charge has pre-defined objectives. The charges described below are applicable to the electric sector.

Energetic Development Account (CDE)

CDE was created by Law No. 10.438/2002 with the objective of, among other purposes, promoting the universalization of the electric power sector in the entire national territory, funding discounts to the tariffs granted to the low income rural and residential classes, assuring the competitiveness of the energy produced from wind source, small hydroelectric power plants, biomass, natural gas, and mineral coal.

The National Treasury may provide contributions of resources to the CDE accounts, aiming the modicity of tariffs. The CDE cost is prorated by all consumers served by the National Interconnected System (SIN). The quota value is calculated by ANEEL.

Electric Power Services Inspection Fee (TFSEE)

The TFSEE was created with the purpose of funding the operation of ANEEL in the exercises of both activities of inspection and economic regulation.

The Fee is paid by all consumers of electric power, levied upon the activity of the agents of distribution, generation, and transmission of electric power.

Program of Incentive to Alternative Sources of Electric Power – “PROINFA”

PROINFA was created by Act no. 10.438/2002 and regulated by Decree no. 5.025/2004 with the purpose to fund the ANEEL operation in the exercises of both activities of inspection and economic regulation.

Prorating of costs and of electric power contracted by the program, taking into account the Annual Plan elaborated by Centrais Elétricas Brasileiras S/A (ELETROBRAS) and the electric power market verified, both captive and free. The Act conceded exempted to consumptions of the Low Income residential subclass.

Financial Compensation for the Use of Water Resources (“CFURH”)

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The CFURH is set forth in the Federal Constitution of 1988, with the objective of providing financial compensation to the Government, state and municipalities, for the use of water and productive lands necessary for the installation of plants for the generation of power.

System Services Charges (“ESS”)

The ESS was created with the objective of increasing the reliability and safety of the offer of power in the country. The cost is calculated on a monthly basis by the Chamber of Commercialization of Electric Power and is paid by all consumers, captive and free, to the generation agents. It considers the dispatch of thermoelectric plants by order of merit, by energetic safety, operational restrictions, and ancillary services.

National System Operator (“ONS”)

The contribution to the ONS was created with the objective of financing the operation of the National Electric System Operator, which coordinates and controls the operation of generators and transmitters of electric power in the National Interconnected System (SIN). The value is defined on an annually basis by the ONS and approved by ANEEL.

Research and Development and Energetic Efficiency (“P&D/EE”)

The P&D/EE was created with the purpose of stimulating scientific and technological researches related to electric power and the sustainable use of the resources necessary to create it.

Reserve Power Charge (“EER”)

The ERR was created with the purpose of covering costs resulting from the contracting of reserve power, including administrative, financial, and tax costs.

The prorating among the end users of electric power of the National Interconnected System (SIN), including free consumers and self-producers only in the part of the energy resulting from the interconnection to the SIN, is defined on a monthly basis by the Chamber of Commercialization of Electric Power (CCEE), according to the formula set forth by ANEEL resolution.

As mentioned above, the effect of Portion A is that of pass-through, i.e., costs with sectorial charges, one of the components of Portion A, will be transferred to the consumer by the tariff, thus neutral from the point of view of the economic-financial evaluation, presenting only a temporal effect, since the adjustment caused by the difference between markets of reference is subject to inflation adjustment and adjusted in the next readjustment, however, for the effects of this evaluation, such temporal effect caused by the difference between the inflation adjustment rate (SELIC) and the discount rate (WACC), was not considered by virtue of its low representativeness.

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4.2.3.Transport Costs

Costs with the transport of power are those related to the transport of power from the generation units to the distribution systems, regulated by Resolutions 1917 and 1918, dated 06/03/2015 and Submodule 3.3 of the PRORET, being composed by the following items:

a)	Use of the transmission facilities classified as Basic Network, Basic Network at Borders, or Other Transmission Facilities (DIT) of shared use;
b)	Use of the distribution facilities;
c)	Connection to DIT of exclusive use;
d)	Connections to the distribution networks;
e)	Transport of power from Itaipu to the point of connection to the Basic Network;
f)	Use of Basic Network by the Itaipu plant; and
g)	Use of the transmission system by the generation centers connected at the voltage level of 88kV or 138kV.

Both the use of the transmission systems and distribution system for the purposes of tariff procedures are calculated considering the amount of contracted demand for the period of reference, valued by the respective economic tariffs in force on the date of the tariff procedure.

4.2.4.Financial

Portion A includes costs that are transferred to the tariffs of the regulated market, but the calculation of the tariff occurs from a forecast for these costs, and the effective costs then do be different in relation to the forecast.

The invoicing of the distributor, as a recovery of Portion A, may be higher or lower than the effective costs of Portion A, and the differences verified will be accounted in entry CVA

(“Compensation of Variation of Values of Items of Portion A”) to a posterior encounter of accounts.

It also occurs with the cost of the thermoelectric generation contracted, which may be higher or lower than that estimated in accordance with the intensity of use of the thermal plants, which on its turn depend on the volume of rainfall, a situations especially difficult to forecast. If, at the time of the calculation of the annual readjustment, CVA has a surplus, that means that the distributor has collected, via tariff, more money has been collected that what has been effectively applied in non-manageable costs. The balance will be corrected by the SELIC rate and the financial component corresponding to CVA will be negative in the calculation of the tariff of the

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next year to compensate the surplus, thus charging against the consumer less than the economic tariff.

As mentioned above, once the components of Portion A were considered neutral, i.e., values related to financial charges for the purposes of this economic-financial evaluation were not considered.

4.2.5. Technical Losses (“PT”)

The electric system is divided into generation, transmission, and distribution of electric power. Distributors receive the power from the supplying agents (transmitters, generators, or other distributors), delivering it to the end consumers, either residential, commercial, rural, industrial, or pertaining to the other classes. The power measured by the Distributors in the consumption units will always be smaller than the power received from the supplying agents. This different is known as loss of power and is segregated according to its origin.

The National Agency for Electric Power - ANEEL – shall refine, at every tariff review, a regulatory referential of losses that takes into account the performance of the concessionaire. Losses may be segmented by losses in the Basic Network, external to the distribution system of the concessionaire and with origin specifically technical, and losses in the distribution, which may have either technical or non-technical nature.

a) Concept and Characterization of the Historical Technical Losses of the Distributor

Technical Losses (PT) are those inherent to the transport of electric power in the network, related to the transformation of electric power into thermal power in the conductors (joule effect), losses in the transformer cores, dielectric losses, etc. They may be understood as the consumption of the equipment responsible for the distribution of power. It is worthwhile noting that the degrees are defined by ANEEL upon the RTP, and kept constant by a tariff cycle.

The most recent verification of the company’s technical losses, segmented by the transformation and grid components, was done by ANEEL by means of Technical Note No. 0237/2013-SRD/ANEEL dated November 20, 2013, process No.: 48500.002315/2013-18 Subject: Analysis of the contributions of Public Hearing no. 099/2013, related to the evaluation of the losses in the distribution system, associated with the 3rd Cycle of Periodical Tariff Review of Centrais Elétricas de Rondônia S/A – Ceron. The outcome of the verification resulted in the values established as per Table 19 and Table 20.

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The trajectory of reduction will be the result of the comparison between the goal and the starting point, both considering the non-technical losses of the measured market. As a general rule, the definition of the trajectory will observe the limits of annual reduction defined in equations (I) and (II). In case the trajectory calculated for the concessionaire surpasses the maximum annual rate of reduction defined by the equation, the limit of the reduction shall prevail.

iii. Definition of the Starting Point

The starting point of non-technical losses is a referential value for the tariff year immediately before the year of the tariff review. In the definition of the starting point of nontechnical losses, the percentage of non-technical losses of the measured market is used. The definition of the starting point will be given by:

a)	Group 1: Maximum 7.50%; Minimum (Goal 3, Measured CRTP, Average of the last
	4	years);
b)	Group 2: Maximum 2.50%; Minimum (Goal 3, Measured CRTP, Average of the last
	4	years).

The exceptions of the general rule are applied in the following cases:

1.	When the company has already been adopting low levels of non-technical losses,
	below	7.50% to companies of Group 1 and below 2.50% to companies of Group 2,
	then	the average of non-technical losses adopted over the measured market in the
	last	four (4) calendar years shall be considered;
2.	Companies with low probability of comparison shall be subject to a complementary
	analysis	and a diagnostics analysis that take into account the degree of effort of the
	Distributor	to combat losses;
3.	Concessionaires whose goals to be established by the methodology are greater than
	the	starting point established by the goal of 3CRTP and not included in the item
	above.	Then:
	a.	In case the goal obtained with the non-technical losses of the company of 3CRTP is greater than the goal established with the most recent loss, the goal obtained with the most recent loss will be used as the starting point, without trajectory of reduction;
	b.	In case the goal obtained with the non-technical losses of the company of 3CRTP is greater than the starting point, but smaller than the goal established with the most recent loss, the goal obtained with the non-technical losses of 3CRTP shall be used as the starting point, without trajectory of reduction;
	c.	In case the goal obtained with the non-technical losses of the company of 3CRTP is smaller than the starting point, the starting point shall be defined according

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Table 28 - Example of Forecast of the Regulatory Non-Technical Losses

1 - Calculation of the Start Point before the flexibility analysis


Description	Non Technical Losses (% BT)
1. 3^rdCycle Goal (Invoiced)	7.87%
2. Difference between measured and invoiced (average of the 4 last years)	0.61%
3. 3^rdCycle Goal (Measured) [1. + 2.]	8.48%
4. Historical Average (Measured)	20.05%
5. Start Point [ = maximum (7.5% and Minimum (3 and 4) ]	8.48%
2 - Calculation of the goal based on the
Benchmarks
Description	Model C	Model G	Model K
Benchmark Company	ELETROPAULO	ESE	ELETROPAULO
6. Benchmark Loss (PNT/BT)	9.38%	4.74%	9.38%
7. ESCELSA Loss (PNT/BT)	18.93%	18.93%	18.93%
8. Comparison Probability	72.64%	55.94%	59.97%
9. Goal based on each Benchmark [ 7. X 5. + ( 1.- 7.) x 6. ]	11.99%	10.99%	13.20%
10. Average goal of the Benchmarks [average(8) ]		12.06%
3 - Calculation of the Start and Arrival Point after the flexibility analysis
Description	Model C	Model G	Model K
Benchmark Company	ELETROPAULO	ESE	ELETROPAULO
11. Benchmark Loss (PNT/BT)	9.38%	4.74%	9.38%
12. ESCELSA Loss (PNT/BT) - Reference 3^rdCycle Losses	21.95%	21.95%	21.95%
13. Comparison Probability	72.64%	55.94%	59.97%
14. Goal based on each Benchmark [7.x5.+(1.-7.)x6.]	12.81%	12.32%	14.41%
15. Average goal of the Benchmarks [average(8) ]		13.18%
16. Start Point [ = maximum (5. and 10.)		12.06%
17. Arrival Point = start point)(10 and 16)		12.06%
4 - Definition of the Regulatory
Goal			2017	2018
Description	Start Point	2016
PNT/BT Path (start point to the goal)	12.06%	12.06%	12.06%	12.06%
Reduction Pace (p.a.)		0.00%	0.00%	0.00%
Reduction Limit (p.a.)		0.00%	0.00%	0.00%
Regulatory PNT/BT Reference (measured)	12.06%	12.06%	12.06%	12.06%
Difference between measured and invoiced	0.61%	0.61%	0.61%	0.61%
Regulatory Reference PNT/BT (invoiced)	11.45%	11.45%	11.45%	11.45%
Regulatory Reference PT/Einj	7.14%	7.14%	7.14%	7.14%

Source: Example Escelsa based on the data from Technical Note no. 243/2016-SGT/ANEEL.

c) Premises for Forecasting Regulatory Non-Technical Losses

The forecasts of Regulatory Non-Technical Losses to the designated companies were made based on the successive application, until 2047, of the mechanisms of definition of goals, starting points, and trajectories detailed in Technical Note no. 106/2015. The models considered for the forecast of the trajectory of goals of losses were estimated based on data defined at the time.

Review cycles of 5 years were considered for the forecasting of regulatory Non-Technical Losses of goals, according to the calendar shown by Figure 17 (observing the goals established by Homologation Resolution no. 2.184/2016, applicable to distributors AME, Boa Vista, and CEA). The Regulatory Non-Technical Losses of the last review cycle (3CRTP) were considered for years 2017 to 2023. This level is updated upon the 1st RTP of the new concessionaire (2023).

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*Extraordinary Tariff Review. Parameters of Non-Technical Losses are not estimated.

Figure 17 - Periodicity of Forecast of Regulatory Non-Technical Losses Targets

Source: Own Elaboration

To define the goals, it is considered that the difference between measured and invoiced (median of the last 4 years) of the companies is constant and equal to the most recent data informed.

d) Assumptions for Forecasting Real Non-Technical Losses

During the regime of Provisional Provision, in force in 2017 and possibility in the beginning of 2018, it has been considered that the economic, financial, and technical-managerial difficulties will limit the last-longing gains of efficiency in the combat to Non-Technical Losses. Therefore, it has been defined that to the 6 companies from the Eletrobras Group, the current degree of real PNT (related to 2016) shall remain in force until the beginning of the new administration in 2018.

After 2019, it is considered as the beginning of a new phase in the combat to Non-Technical Losses, with successive gains of efficiency and efficacy of these activities. To identity the trajectory of real Non-Technical Losses, the analyzed companies were divided into 3 groups.

The first group includes companies AME and CERON, whose difference between the invoiced and the regulatory Non-Technical Loss verified is greater than 30%. For this first group, there is a forecast of reduction of the Non-Technical Losses verified stronger than the others in the first 5 years, due to the high incentive to combat that such differences motivate to the new administration. This additional reduction is forecasted based on the calculated fall by the equation that relates the speed of reduction and the degree of losses of Technical Note no. 106/2015. In addition to this reduction in the first 5 years, forecasts were also made based on the use of the

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The calculation of the value of Portion B is different between the processes of tariff review and adjustment. In the tariff adjustment process, the methodology from sub-module 3.1A of PRORET is followed.

First, the Value of Portion B in the test year (12 months prior to the tariff adjustment) –also called VPB0 component -, is calculated as the quotient of the division of the Value of Portion B from the reference market (both from the previous tariff process) multiplied by the value from the reference market of the current process.

Then, VPB0 is adjusted to recompose the elements, which are excluded from the previous process: Other Revenues, Demand Surplus and Reactive Excess. In the first tariff adjustment of the analyzed concessionaires (2017), an adjustment factor calculated by ANEEL according to Public Hearing No. 58/2016 (DR1 Factor) is used. For the other years, the so-called Pbi-1 Factor is estimated annually based on the data from the previous tariff process (t-1).

After this adjustment, VPB0 is updated by IPCA and adjusted by the X Factor. Finally, Other Regulatory Revenues (OR)¹⁹and revenues from com Demand Surplus (UD) and Reactive Excess (ER)²⁰, are excluded. The following formula summarizes the exposed above.

Equation 14 – Calculation of Portion B in adjustment processes

In addition, in the first tariff process (2017), the value of the ONS charge is added to Portion B.

In the tariff review processes, Portion B is calculated according to the following equation.

All components of the equation will be discussed along this report in specific sections.

Equation 15 Calculation of Portion B in review processes

82$ = :%#1/ + %##; × :s 2à /+3; 14 7&, '4

Where:

CAOM: Regulatory Operational Costs; CAA: Annual Cost of Assets; Pm: equivalent to component Pd of Factor X;

¹⁹It can be noted that it is about percentage of regulatory share of the Other Revenues, which varies according to the nature of the revenues (for the bigger part of them, it is 60%).

²⁰Such revenues are net from taxes, of the regulatory percentage of 3.5% of the revenues, related to demand surplus in the transmission grid, and the irrecoverable revenues, applying the regulatory percentage associated with the industrial consumption class.

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tariff reviews and were considered to compose the PMSO data to be forecasted within this analysis.

The approach used by ANEEL for the calculation of the efficient operational costs in the periodic tariff review seeks defining the efficient cost level for the performance of the processes, according to the conditions provided in the concession contracts and the regulation, assuring adequate service provision and that the assets will keep their service capacity unchanged throughout their service life. In the definition of the efficient operational costs, the costs of the distributors, the efficient cost level and the characteristics of the concession area will be observed.

ANEEL uses the non-parametric model called DEA (Data Envelopment Analysis), whose purpose is to define a production/variable cost boarder as a way to identify the level of efficiency of the companies. The model considers PMSO, with the adjustments mentioned above, as production input. The values are also adjusted by salary indexes, for companies, which work in regions where labor cost is cheaper, not to have competitive advantage, and thus, masking their efficiency score.

The products considered in 4CRTP were: Grid (underground grid, air-borne distribution grid and high voltage grid), consumers, average market (weighted by voltage level), NonTechnical Losses and quality (interrupted consumer hour). Using a sample of 61 companies for the period from 2011 to 2013, ANEEL obtained the efficiency scores in the DEA model as presented in Table 36.

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Table 36 – Operational Costs Efficiency Parameters in 4CRTP


DISTRIBUTOR	EFFICIENCY	DISTRIBUTOR	EFFICIENCY
JAGUARI	100%	BRAGANTINA	69%
CSPE	100%:	CELG	69%
CELTINS	100%	CEMIG	69%
RGE	100%	CHESP	68%
COELCE	100%	NACIONAL	68%
PIRATININGA	100%	CFLO	67%
NOVA PALM A	100%	ENERSUL	67%
MUXFELDT	100%	SULGIPE	66%
COELBA	96%	COPEL	64%
CPFL PAULISTA	95%	COOPERALIANÇA	63%
ELEKTRO	94%	CELESC	62%
ELETROPAULO	93%	ESE	60%
COSERN	92%	CEPISA	59%
MOCOCA	91%	DEMEI	58%
CPEE	88%	COCEL	57%
CEMAR	87%	CELPA	56%
CELPE	86%	IGUAÇU	56%
EMG	83%	CEB	53%
AESSUL	83%	ENF	53%
BANDEIRANTE	82%	HIDROPAN	52%
EPB	82%	ELETROACRE	52%
SANTA MARIA	81%	ELETROCAR	52%
JOAO CESA	80%	CERON	51%
LIGHT	78%	URUSSANGA	45%
SANTA CRUZ	77%	CEAL	44%
CEMAT	77%	FORCEL	43%
CAIUA	74%	DME-PC	42%
E3C	73%	CEEE	42%
ESCELSA	72%	AME	31%
AMPLA	70%	BOA VISTA	23%
EDEVF	70%

Source: Sub-module 2.2 A, PRORET

Using the bootstrap²¹method, ANEEL made a sensitivity analysis of the efficiency scores and generated the confidence intervals for the concessionaires, as it can be observed in Table 37.

²¹The main idea of the method consists in generating random sub-samples from a sample of verified observations and thus, expanding the observation database. From this resampling, it is possible to derive estimations of parameters of the population, which has given raise of the original sample.

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Table 37 – Confidence intervals of the efficiency estimations


			Upper
DISTRIBUTOR	Lower Limit	Downtown	Limit
JAGUARI	94%	100%	100%
CSPE	94%	100%	100%
CELTINS	96%	100%	100%
RGE	95%	100%	100%
COELCE	94%	100%	100%
PIRATININGA	94%	100%	100%
NOVA PALMA	92%	100%	100%
MUXFELDT	86%	100%	100%
COELBA	88%	96%	100%
CPFL PAULISTA	90%	95%	99%
ELEKTRO	88%	94%	97%
ELETROPAULO	88%	93%	99%
COSERN	85%	92%	100%
MOCOCA	85%	91%	96%
CPEE	82%	88%	94%
CEMAR	81%	87%	94%
CELPE	77%	86%	90%
EMG	78%	83%	90%
AES SUL	78%	83%	89%
BANDEIRANTE	77%	82%	85%
EPB	76%	82%	86%
SANTA MARIA	77%	81%	85%
JOAO CESA	63%	80%	87%
LIGHT	74%	78%	83%
SANTA CRUZ	72%	77%	82%
CEMAT	72%	77%	85%
CAIUA	70%	74%	76%
EBO	68%	73%	79%
ESCELSA	68%	72%	76%
AMPLA	64%	70%	72%
EDEVP	66%	70%	73%
BRAGANTINA	65%	69%	71%
CELG	65%	69%	74%
CEMIG	65%	69%	73%
CHESP	64%	68%	76%
NACIONAL	64%	68%	70%
CFLO	63%	67%	70%
ENERSUL	63%	67%	70%
SULGIPE	62%	66%	70%
COPEL	60%	64%	68%
COOPERALIANÇA	59%	63%	68%
CELESC	58%	62%	65%
ESE	55%	60%	63%
CEPISA	55%	59%	62%
DEMEI	53%	58%	61%
COCEL	53%	57%	60%
CELPA	52%	56%	58%
IGUAÇU	52%	56%	60%
CEB	50%	53%	56%
ENF	50%	53%	56%
HIDROPAN	46%	52%	57%
ELETROACRE	49%	52%	55%
ELETROCAR	48%	52%	55%
CERON	47%	51%	54%
URUSSANGA	38%	45%	50%
CEAL	39%	44%	45%
FORCEL	35%	43%	49%
DME-PC	39%	42%	44%
CEEE	40%	42%	44%
AME	29%	31%	34%
BOA VISTA	22%	23%	24%

Source: Sub-module 2.2 A, PRORET

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Table45 – Results for Factor X and its components Ceron

Source: Own Elaboration

4.3.4.Demand Surplus, Reactive Excess and Other Revenues

Sub-module 2.7A of PRORET classified Other revenues in three categories: (i) activities inherent to the electric power distribution service; (ii) complementary activities; and (iii) atypical activities.

The revenues inherent to the electric power distribution service are additional to the power supply, but are still part of the essence of the electric power distribution concession, for which the expenses incurred while providing the services are already contemplated in the revenues of the regulated service. In this category, the revenues obtained from connection charges and chargeable services as included; as well as the revenues determined for Demand Surplus and Reactive Excess; the purpose of their collection is to incentive optimized use of the grid and efficient consumption of power, without effective service compensation by the concessionaire.

The complementary activities are those, whose expenses are not clearly identified and are already covered by the revenues coming from the regulated activity. In this sub-group, the revenues from share of infrastructure and communication systems (PLC) are allocated.

The atypical activities are those, on which administration and management criteria are imposed, which enable full distinction of the cost and income accounting. They are composed of revenues coming from provision of services to third parties (operation and maintenance, consulting, communication and engineering) and charge for the agreement collection in the energy bills.

From the most recent information about Other revenues supplied by the analyzed concessionaires, it was adopted as assumption that they will evolve according to the growth of IGP-M, as it is about the price index used by ANEEL for financial update of the regulatory values of Other revenues. This indicates maintenance of the current levels of other revenues, without additional efforts for their expansion. Such case reflects a reduction of the incentives for generation of other revenues, once there was reduction of the period, in which it is possible gain

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b) Methodology for Definition of the Group Limits of the Service Quality Indicators

For the definition of the limits of the group continuity indicators (DEC and FEC) of the Distributor, ANEEL stipulated the following procedures: (i) desegregation of the operation area of each concessionaire in groups of consumption units (geoelectric groups); (ii) characterization of each group of the country by means of 7 (seven) attributes describing the service quality; (iii) application of the dynamic grouping method (clustering) for the identification of the similar groups; (iv) definition of the regulatory limits of the continuity indicators based on the performance of the groups considered similar (benchmarking by means of position measurement); (v) application of a linear decrease trajectory within 8 years²⁹for definition of the annual limits of each group from their target values in force; (vi) application of specific treatment for groups with give characteristics – those with high degrees of heterogeneity, high share of the supply in the interruptions and/or high annual target drop rates-.

The group of consumption unit (analysis unit for definition of group limits) is defined as the range area of a Distribution Substation (SED) owned by the Distributor, with High Voltage (HV) primary and Medium Voltage (MV) secondary. The criteria for creation, aggregation and division of the groups are set by ANEEL in Section 8.2, Module 8 of PRODIST.

For purposes of determination of the quality targets, the groups are characterized by means of attributes with high correlation (theoretically) with the DEC and FEC indicators. The 7 (seven) attributes currently used are:· PC_VRAMà Percentage of area with remaining vegetation high or medium (%);· PLUVà Average Annual Pluviometric Precipitation (mm);· PC_NUC_ADà Percentage of Consumption units (UC) in High Density Areas (%);· PC_ERMT_3Fà Percentage of Medium Voltage (MV) grids, three-phase (%);· CM_NUC_RESà Average Consumption per UC of the Residential Class (given in MWh);· NUC_INDà Number of UC in the Industrial Class (exclusive for DEC);· NUC_COMà Number of UC in the Commercial Class (exclusive for FEC).

ANEEL takes these attributes from the Geographic Database of the Distributor (BDGD) sent annually by each Distributor, in addition to using other databases³⁰.

The methodology approved by the Agency uses the dynamic clustering method to identify similarity between the groups in these attributes. It is worth pointing out that this method is applied only between airborne groups, while the underground groups form a single cluster.

In the clustering process, each group, in given time of analysis, is considered the reference group and then, the groups, which are the most similar to it, are established. The distance measure

²⁹As clarified in Technical Note No. 0028/2010-SRD/ANEEL, the transition period was set considering the characteristics of each system and the required performance variation, adopting the average period of two tariff reviews, namely, eight years.

³⁰Native vegetation data taken from Project for Preservation and Sustainable Use of the Brazilian Biological Diversity

Probio (2008), and the precipitation data is from the CPTEC site (from 1999 to 2012).

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used to evaluate the degree of similarity between the groups is the Euclidean one. Considering that this measure is sensitive to the scale differences existing between the attributes used in the comparison, the standardization called Score Z is done first - calculated by subtracting the average and dividing by the standard deviation for each attribute.

Once the Euclidean distances are calculated, it is necessary to determine the heterogeneity of each reference group in relation to the other groups by means of Equation 30.

Equation 30 – Determination of Heterogeneity
^jA
H_i= ^Max^@^{Dist i}
3 k

Where:

I: Reference group index;

Index of the group candidate for comparison to group i;

D†st j; ^h: g Euclidian distance of group i for group u of

ˆ:

Maximum reference distance, where k is the number attributes.

For the definition of the clustering of similar groups, 20% is considered maximum allowed heterogeneity; however, it is also restricted to the comparison to a minimum and maximum quantity of comparable groups, namely:· Minimum comparable groups: 50 (heterogeneity is higher than 20%).

· Maximum comparable groups: 100 (heterogeneity is lower than 20%).

The groups, which form clusters with 50 members (lowest clustering allowed) are called heterogeneous. For these groups, the norm provides performing a particular analysis to define the o limit, once there are few comparable groups.

Once the similar groups are defined, their performance is compared in between. For this purpose, the similar groups are ordered in increasing order according to the average of the grouped values of the DEC and FEC indicators from the last 3 years.

The regulatory target is set by using a position measure, namely:· Interconnected airborne sets: set placed in the 2nd decile.

· Underground or isolated airborne groups: a group placed in the median.

The limit trajectory is linear and decreasing –

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From the regressions, the indicators are estimated year by year, starting from the assumption that the independent variable is the result for the previous year, obtaining possible decrease every year until 2025. The models estimated and used for the definition of the forecast of the quality indicators for Ceron are presented in Appendix E.

Finally, the third moment is the forecast of the indicators from 2026 to 2047 and for this purpose, the calculated historical indicators were ordered in increasing order (2003 to 2016) of the comparable companies. The final target for the analysis period (2047) is defined by the measurement of the position of the 1st decile (or percentile 10) of the indicators of the comparable companies³². Once this level was found, a reduction trajectory was outlined, considering the indicator from 2025 as starting point and the value of the 1st decile applied in 2047 as end point. The value obtained in 2047 is considered for 2048, as it is expected to close the concession in the latter year.

d) Assumptions for Forecast of the Regulatory Limits of DEC and FEC

For the forecasts of these regulatory targets, the method in force in 4CRTP was used, mainly grounded on the method of group clustering by similarity and the measurement of the position for the definition of the regulatory target. The database of attributes of each group in the country in 2016 was used to perform dynamic clustering.

For the calculation, the following assumption were necessary: (i) progress in the interconnections of isolated systems to SIN was foreseen from 2019 to 2021 for the Distributors Eletroacre, Ceron and Boa Vista, influencing their regulatory target; (ii) the contribution of each group to the formation of the global indicators (DEC and FEC) in 2016 was used as weighing criterion for opening the forecasted indicators at company level defined according to the methodology presented in the previous section; and (iii) only the indicators of the Distributors from the Eletrobras group would present annual reduction rate, while the indicators of the other groups would remain constant.

For calculation of the trajectories of the DEC and FEC limits forecasted from 2023 to 2048, it shall be considered that: (i) RTP will occur in 2023, 2028, 2033, 2038 and 2043; (ii) the value for 2048 will be equal to that obtained in 2047, as it is expected to close the concession in the latter year; and (iii) all limit values are weighed by the number of consumption units related to the average from the 1st quarter 2017, according to NT No. 088/2017 SRD-ANEEL.

e) Results for the Forecasts of the Verified and Regulatory Indicators

Based on the used assumptions and methodologies, the results for the forecast of the verified indicators and the regulatory service quality limits of the distributor – DEC and FEC –until 2048 are presented. Graph 20 and Table 46 present the forecasts for DEC and Graph 21 and Table 47, those of FEC.

³²The first decile and the cut-off point, i.e., the target is defined as the accomplished performance of 10% better.

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by 2048. The same is verified for the FEC forecasts, where the value is lower than the regulatory in 2022 and remains in decrease trajectory by 2048.

4.3.6.Compensations

Among the penalties provided in the legislation for violation of the quality standards in the electric power supply, the compensation for violation of the individual service continuity indicators is the most expressive.

The methodology for the calculation of this compensation was prepared about eight years ago, as provided in Technical Note No. 092/2009 – SRD/ANEEL, and it comprehends the followings stages: (i) building the database of the individual indicators observed in the groups of consumption units for 2007 and 2008 – data from 36 Distributors, which served 65% of the consumers in the country at that time –; (ii) production of histograms for 42 DEC and FEC ranges according to the verified individual indicators segregated by connection voltage (HV, MV and LV) and localization (urban or non-urban); (iii) definition of percentile 90 as position measurement of the individual limit for each range; and (iv) application of a trend line to correct possible inconsistencies related to the limits of each range; (v) setting the DICRI limit as the DMIC value from the last DEC range; and (vi) multiplication of the monthly values by 2 and 4 for calculation of the quarterly and the annual limits, respectively. By means of this method, the limit tables of the individual indicators presented on Module 8 of PRODIST were built.

To what refers to the compensations paid to the consumer for the violation of the individual limit, the calculation is made using the quotient of the calculated value in relation to the limits (percentage of limit excess), multiplied by the value of the Distribution System Use Charge (EUSD) and increased by a constant, which depends on the voltage level of the consumer’s connection.

EUSD is used as a base for the calculation of the individual compensations. EUSD is calculated using the product of the use tariff³³(TUSD) by the respective verified consumption variable or contracted demand, according to Equation 35.

Equation 35 - Calculation of the average EUSD

EUSDaverage = TUSD x Consumo (KWh)

Where:

EUSDaverage: Arithmetic mean of the Distribution System Use Charges (EUSD); TUSD: Distribution System Use Tariffs.

Equation 36 presents the general rule for the calculation of the compensations by indicator.

³³Related to the voltage level and the tariff sub-group.

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4.3.8.Remuneration Base

Within the tariff review process, the definition of the Regulatory Remuneration Base (BRR) is a fundamental input for the calculation of the capital remuneration and the regulatory reintegration quota. BRR consists in the group of assets held by the service provider appreciated according to given methodology.

a) Methodology Adopted by ANEEL

For electric power distribution concessionaires in Brazil, ANEEL uses the DORC (Depreciated Optimized Replacement Cost) method to evaluate the assets of higher representativeness in the BRR value and CCV (Current Cost Valuation) for the valuation of the assets with lower representativeness. Furthermore, the Rolling Forward method is applied with the purpose to provide its movement in time. These methods are described in Appendix F.

In the Periodic Tariff Review (RTP), the construction of BRR considers two elements. The first is obtained by the BRR amount of the previous RTP (called Frozen asset base), deducting the depreciation and the write-off made in the period between the RTP’s, financially updated by the IPCA index. The second, called additional base, is calculated by means of the additions made in the period between the RTP’s, valued at market prices through an asset re-evaluation process.

BRR is composed of the values of the followings items: fixed assets in service (evaluated and depreciated); warehouse in operation; deferred assets; and special obligations (or without lien). For the purposes of validation of the physical registration and the re-evaluation, the Fixed Assets in Service (AIS) are divided in the following groups: intangible; land; reservoirs, dams and water networks; buildings, civil works and improvements; machines and equipment; vehicles; and furniture and utensils.

For the valuation of the electric power distribution assets, DORC or CCV are considered depending on the asset group. The groups of machines and equipment; buildings, civil works and improvements are evaluated by DORC, while the groups of land and easement are evaluated by CCV, i.e., from the accounting values corrected by the IPCA index.

In the composition of Portion B, the Regulatory Reintegration Quota (QRR) and the Capital Remuneration (RC) are considered. QRR results from the multiplication of the gross BRR by the regulatory depreciation, according to Equation 38

Equation 38 – Regulatory Reintegration Quota

QRR BRRb

Where:

QRR = Regulatory reintegration quota.

BRRb = gross BRR.

= average depreciation rate of the fixed assets in Service.

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Replacement Value⁴²). Conversion of VOC (Original Accounting Value⁴³) into VNR is done by the relation of AIS (VNR) / AIS (VOC) of the company in the 3rd RTP, which resulted in 0.95. AIS (VNR) is the approved value of AIS in the 3rd RTP of the company. AIS (VOC) comes from worksheet “Calculation Report - Capital Cost -Factor X” (made available by ANEEL in AP No. 040/2010) adding the VOC informed by the company for the Additional BRR of the 3rd RTP to the value of AIS.

· 100% Depreciated assets: application of an average growth rate determined from the evolution of the monthly accounting balance of the assets, which have been 100% depreciated, considering the average depreciation rate of each asset and the residual value in the database informed by the concessionaire.

· Accrued depreciation: updates the previous accrued depreciation by IPCA, adds the monthly depreciation and takes the write-off depreciation out. o Monthly Depreciation: Gross BRR multiplied by the average depreciation rate. o Write-off Depreciation: application of the average write-off depreciation percentage verified in the Evaluation report prepared by American Appraisal on the value of write-offs in the forecasted month.

· Average Depreciation Rate: the depreciation rate drops from the average level verified in Feb/17, considering the increase of the average service life of the assets. o In Feb/17 the weighted average between the depreciation rate of each asset and its weight in the residual AIS (AIS deducting 100% depreciated assets) verified in the Evaluation report prepared by Deloitte was considered, resulting in 3.22%. o After Feb/17, the rate drops from the average level of 3.22%, because the assets are becoming 100% depreciated (or are written off). The purpose is to estimate which the expected level at the end of the forecast is (2048). For this purpose, we used accounting data made available by the concessionaire in Sep/16 again, projecting the residual AIS year by year. Then, we calculated the average depreciation rates of the assets, weighting the depreciation rates of each asset by its weight in the residual AIS. Once the rate expected in 2048, 2.56%, was obtained, we interpolated the values between Feb/17 and Dec/2048.

· Operation warehouse: proportion of the Operation warehouse account in relation to the gross BRR of the Evaluation report prepared by Deloitte applied to the gross BRR of the forecasted month.

· Depreciated Use Index (R$): segregation of the percentage of assets, which are not land, in the amount of Full IA, using the proportion of the amount of assets in IA of BRR of the 3rd RTP, which are not land.

⁴²Equivalent to the appreciation by DORC for ANEEL. ⁴³Equivalent to the appreciation by CCV for ANEEL.

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o In the proportion of the land use index, the annual depreciation rate is not applied. o The annual depreciation rate is applied to the proportion of the use index of the other assets.

· Net special obligations: update of the net special obligation accumulated by the previous month by IPCA, deduction of the Special obligations write-offs from the current month and depreciation of the result.

· Deferred Assets: if any, they evolve with IPCA.· Land and Easement: evolves with IPCA.

· RGR Balance (PLpT): initially, the RGR Balance (PLpT) balance was financially updated by IPCA and the depreciation from the period between the 3rd RTP and Feb/17 was deducted. In the subsequent months, the forecast was made by updating the balance until the precious month by IPCA and depreciation of the result.

· RGR Balance (Other Investments): initially, the RGR Balance (Other Investments) was financially updated by IPCA and the depreciation from the period between the 3rd RTP and Feb/17 was deducted. In the subsequent months, the forecast was made by updating the balance until the precious month by IPCA and depreciation of the result.

The transaction of the Additional BRR (new investments) was made by means of addition of assets forecasted for the period after Feb/17, deducted from the write-offs related to these assets. The forecast of the Additional BRR account was made as described below:· New Assets (Investments): addition of assets from the current month added to the update (IPCA) of the amount accumulated until the previous month, deducting the write-offs of assets, which entered in operation after the base date Feb/17. The forecast was made using the investments presented in section 4.3.7, deducted at 5%.

Lower percentage of deductions was considered in the forecast period considering that the additional efforts for asset management and modernization of the asset and unification controls will increase the consistency of the information and reduce the differences, which generated these regulatory deductions.

· Asset Write-offs: o By Feb/27: null, considering the reduced probability of the assets to be written off in the first 10 years. o Between Mar/27 and Feb/32: 1/3 multiplied by the Write-off/AIS ratio of the Frozen asset BRR. o Between Mar/32 and Feb/42: 2/3 multiplied by the Write-off/AIS ratio of the Frozen asset BRR. o From Mar/42 on: full ratio of Write-off/AIS of the Frozen asset BRR.

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	Gross special obligations: additions of special obligations and update by IPCA. The compensation amounts for indicator violation, forecasted between 2019 and 2023,
	were	added to this account following the provisions in Sub-Clause One of Clause
	Nineteen, which stipulates Transitory Provisions in Technical Note No. 182/2017.
	100% Depreciated assets: it was considered null by Feb/32, given the insignificant proportion of assets, which become 100% depreciated in the period. After this date, scaling was done as follows:
	o	Between Mar/32 and Feb/37: 1/3 multiplied by the average proportion of the 100% Depreciated Assets/AIS ratio of companies of the North and the North- East Regions in the 3rd CRTP. The following were companies considered: Celtins, Energisa Borborema, Celpe and Cemar.
	o	Between Mar/37 and Feb/42: 2/3 multiplied by the average proportion of the 100% Depreciated Assets/AIS ratio of companies of the North and the North- East Regions in the 3rd CRTP.
	o	From Mar/42 on: average proportion of the 100% Depreciated Assets/AIS ratio of companies of the North and the North-East Regions in the 3rd CRTP.
		It was considered that in 25 years, the companies from the Eletrobras Group will be with level of 100% depreciated assets similar to that of the compared
	Full Use companies Index (R$): in the multiplication North and the of AIS North-East (new assets) Regions. from each month by the Use Index/AIS ratio verified in BRR in the Evaluation report prepared by Deloitte.
	Accrued depreciation: update of the accrued depreciation prior to IPCA and addition of the monthly depreciation.
	Average depreciation rate: the weight of the investments made available in the Quinquennium Investment Plan (PIQ) from 2018 to 2022, presented in Front 5 Report was considered per group of assets and their respective depreciation rates.
	The segregation of each investment per registration unit of the asset base was done according to the big items (ex: substation busbars, power transformers, reclosers, conductors, etc.), when possible. Thus, the average depreciation rate coming from the investments provided in PIQ was obtained, which resulted in 3.22% of the AIS, as it can be observed in Table 59. This rate was kept constant along the 30 years of concession.

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(c)	the new operational cost for 2017 was obtained by the sum of (a) and (b).
(d)	the share of (c) in VPB for 2017 was applied to VPBo for 2018, obtaining an estimation of the operational costs coverage for 2018;
(e)	the IPCA accumulated in one year was applied, reducing the Factor X, to (c). The difference between this value and (d) was applied to VPB for 2018.

In 2019, there will be extraordinary review. For its implementation, the tariff coverage of the Annual Asset Cost (CAA, composed of the sum of the equity remuneration, regulatory reintegration quota and annuity of the fixed and portable facilities) was estimated using a mechanism similar to that for the calculation of the operational cost tariff coverage. This value was excluded from VPB and the CAA forecast for 2019 was added. The forecast already includes the closed and the additional base reports.

It shall also be pointed out that for the period between 2017 and 2022, the regulatory limits for Non-Technical Losses were made flexible, being replaced by the average between the verified Non-Technical Losses and the regulatory losses observed in 2016. This procedure was not adopted for AmE and Boa Vista Energia, because their technical losses were made flexible by the Approval of Resolution No. 2.184/2016.

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Table 66 – Estimations for Required Revenues, VPA and VPB for Ceron (rated R$ million)


	RA1	VPA	VPB
Regulatory Year	Reference Period	Required Revenue	Value of Portion A	Value of Portion B
2017	Nov/16 - Oct/17	R$1,454.85	R$1,095.97	R$358.88
2018	Nov/17 - Oct/18	R$1,572.82	R$1,177.63	R$395.18
2019	Nov/18 - Oct/19	R$1,753.76	R$1,256.13	R$497.62
2020	Nov/18 - Oct/20	R$1,876.28	R$1,338.12	R$538.16
2021	Nov/20 - Oct/21	R$2,000.71	R$1,422.34	R$578.37
2022	Nov/21 - Oct/22	R$2,132.94	R$1,510.19	R$622.76
2023	Nov/22 - Oct/23	R$2,188.11	R$1,491.53	R$696.58
2024	Nov/23 - Oct/24	R$2,298.59	R$1,577.71	R$720.88
2025	Nov/24 - Oct/25	R$2,414.58	R$1,669.83	R$744.75
2026	Nov/25 - Oct/26	R$2,534.71	R$1,766.44	R$768.27
2027	Nov/26 - Oct/27	R$2,655.65	R$1,868.08	R$787.56
2028	Nov/27 - Oct/28	R$2,763.46	R$1,963.10	R$800.36
2029	Nov/28 - Oct/29	R$2,916.51	R$2,073.03	R$843.48
2030	Nov/29 - Oct/30	R$3,076.24	R$2,188.09	R$888.15
2031	Nov/30 - Oct/31	R$3,241.75	R$2,307.55	R$934.20
2032	Nov/31 - Oct/32	R$3,416.45	R$2,433.84	R$982.61
2033	Nov/32 - Oct/33	R$3,564.61	R$2,554.25	R$1,010.36
2034	Nov/33 - Oct/34	R$3,758.73	R$2,694.57	R$1,064.15
2035	Nov/34 - Oct/35	R$3,964.35	R$2,843.49	R$1,120.86
2036	Nov/35 - Oct/36	R$4,181.80	R$3,001.14	R$1,180.66
2037	Nov/36 - Oct/37	R$4,411.78	R$3,168.06	R$1,243.72
2038	Nov/37 - Oct/38	R$4,451.51	R$3,326.15	R$1,125.36
2039	Nov/38 - Oct/39	R$4,705.49	R$3,511.80	R$1,193.69
2040	Nov/39 - Oct/40	R$4,975.25	R$3,708.97	R$1,266.28
2041	Nov/40 - Oct/41	R$5,261.31	R$3,917.88	R$1,343.43
2042	Nov/41 - Oct/42	R$5,564.72	R$4,139.29	R$1,425.43
2043	Nov/42 - Oct/43	R$5,819.34	R$4,350.91	R$1,468.43
2044	Nov/43 - Oct/44	R$6,148.99	R$4,597.67	R$1,551.32
2045	Nov/44 - Oct/45	R$6,499.21	R$4,860.08	R$1,639.14
2046	Nov/45 - Oct/46	R$6,870.71	R$5,138.50	R$1,732.22
2047	Nov/46 - Oct/47	R$7,264.94	R$5,434.02	R$1,830.92
		Source: Own Elaboration

Adopting the hypothesis that the financial components will be neutral along the period, the tariff transactions are obtained by direct comparison of the required revenues to the revenues observed in the reference period.

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5. Analysis of the supplier

The corporate purpose of the company is to design, construct, and explore the utility of electric power distribution to the end consumers, as well as the services that may be granted thereto or authorized by any title of right and activities associated to the utility of energy, and also to provide technical services of its specialty and to execute the other acts required to the achievement of its purpose, being such activities regulated and inspected by Brazilian Electricity Regulatory Agency – ANEEL, an entity related to the Ministry of Mines and Energy – MME.

On October 15, 2012, the suppliers of Eletrobras whose concessions expired in 2015, were entitled to manifest the interest in the extension of the concession for an additional period of 30 years, which they did within the term set forth. On July 22, 2016, the 165th Extraordinary General Meeting of Centrais Elétricas Brasileiras S.A. – Eletrobras, resolved for the non extension of the concessions of the controlled Energy Distributor of Eletrobras Group.

The ordinance of the Ministry of Mines and Energy no. 422, of August 3, 2016, designated the Company as Responsible for the Provision of the Utility of Electric Power Distribution, aims at guaranteeing the continuity of the service in the Concession area of the State of Rondônia until the designation of the new concessionaire, or until December 31, 2017, whichever occurs first, in the areas corresponding to the Cities in the State of the Supplier.

The financial valuation of the Supplier considers as an assumption that a new concession contract will be entered into with the granting authority on 03/01/2018. At the closing of the year on Dec/2016, the Company registered losses in its operations, related to the period of 2016, in the amount of R$ 835,268, increasing the accumulated losses to R$ 2,617,163. It also presented excess of current liability on current assets in the amount of R$ 1,377,303.

5.1.Historical Financial Statements

The period considered in the retrospective analyses of the Company’s financial statements corresponds to the interval between 2014 and 2016. The following indicators were based on the historical audited financial statements of the Company:

Figure 20 – Historical Financial Indicators

Three indicators were analyzed in order to measure the Company’s leverage levels and its capacity to honor the short term obligations: the total financial debt to total of assets, the long-term debt to total assets, and the current ratio.

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Ceron presented low and stable indexes of indebtedness over the last years. However, the current liquidity ratio has been low over the analyzed period, having dropped in 2016.

In relation to the company’s operational performance, the growth rates of the net operational revenue and of the operational costs and expenses were analyzed. On net revenues, it was observed an average annual growth rate (“CAGR”) of 6.48% in the analyzed period, followed by a CAGR of 41.25% on costs and 120.44% on expenses. The observed dynamics in the evolution of revenues and expenditures of the company directly impacted the profitability indicators presented and discussed as follows.

The gross margin of Ceron dropped significantly over the last three years, from 39.6% in 2014 to a negative mark of -6.2% in 2016. The same dynamics of reduction was observed in EBITDA margin and net margin, which dropped from 34.5% and 24.0% in 2014 to -36.9% and -56.3% in 2016, respectively.

We present below the items of the historical audited financial statements of the company taken as base for the analysis of the selected indicators.

Figure 21 – Summarized Income Statements

Figure 22 – Summarized Balance Sheet

We present below the Historical Audited Financial Statements (DFs) of the Supplier. Additionally, the analyses performed in the accounting due diligence conducted in line with the economical-financial assessment process are provided, as well as financial indicators related to the end of the year of 2016.

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6. Valuation
6.1.Methodology

Valuation of the company was performed using the Discounted Cash Flow method, based on projected profits.

This method estimates the value of a company or business based on the net present value of the projected cash flows for that company or business. The projections consider the cash inflows and outflows, including investments required for the maintenance and/or expansion of the Company, treating the business as a going concern. These projections are related to the business plan developed by the administration of the Company, the prospects of the electric sector in Brazil, as well as macroeconomic considerations. The final valuation under the DCF method reflect the value of tangible and intangible assets and liabilities that contribute for the future free cash flows of the Company.

The Free Cash Flow to the Firm (FCFF) approach was adopted, where the cash flows from operational and investment activities are considered, but not debt or financing activities. The net present value of the projected FCFF was calculated using a discount rate equivalent to the

Company’s weighted average cost of capital, resulting in a total operational value of the company (“Enterprise Value”, or “EV”). The Company’s Net Debt is subtracted from the EV as are the non-operational assets and liabilities, resulting in a valuation of 100% of the company’s shares (“Equity Value”).

6.2. Discount Rate

The discount rate was calculated using the weighted average cost of capital (WACC) methodology. This methodology considers the cost of equity and the cost of debt, weighted by the

Company’s leverage raio taxes according to the equation below:

9#%% = -@ T [s 6] _T& _'+ -A _T' ~~& + ' + &~~

Where:

WACC = Weighted Average Cost of Capital:

Kd = Cost of debt;

Ke = Cost of equity

D = Debt weight;

E = Equity weight; and

T = Income tax rate.

The cost of the debt was calculated based on the SELIC projections, provided by Boletim Focus – BACEN, presented in section 10.3. The spread over SELIC observed for the Brazilian electricity distributors average cost of debt was added to the SELIC projections.

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the Contract Draft made public by Aneel that establishes a concession period of 30 years (from March 1,2018 to February 29, 2048).

The Cash Flows projections therefore considered the period from January 1, 2017 to February 29, 2048. However, the business value is based only on the Cash Flows projected for the period from March 1, 2018 to February 29, 2048, as decided by BNDES and the Consortium. This period corresponds to the best assumption for the entry of new investors and the start of a new concession contract. The cash flows were projected in current-day Reais (BRL) (taking into account inflation effects) and discounted at a variable WACC rate according to the calculations previously presented. From the valuation base date (Dec. 31, 2016) to the estimated date for the start of the new concession contract (Mar. 1, 2018), only the Brazilian inflation rate (IPCA) was included in the discount factor. This approach was used in order to assure the business risk would not affect the period prior to the entry of the potential investor.

Operational Assumptions

Market demand

The operational assumptions are based on projected energy consumption as it relates to:· Regulated Market: the amount of energy consumed by the clients of the Residential, Commercial, Industrial, Rural and Other Classes, who pay the distributor both for the consumed energy and the distribution service.

· Free Consumers: the amount of energy consumed by the clients of Commercial and Industrial classes that pay the Distributor only for the distribution service, negotiating the price of the consumed energy directly with other market participants.

· Supplied Distributors: the amount of energy delivered to another energy distribution company that serves consumers outside the concession area of the Distributor.

· Regulatory Allowance for Energy Losses: the amount of energy the Distributor would have as a write-off due to Technical Losses, Non-Technical Losses, and Losses in the High Voltage Network, according to the efficiency limits


·	established Regulatory by Allowance Aneel.	for Contracted Energy:	the amount of energy the

Distributor needs to generate or buy to supply the consumers (Regulatory Market,

Free Consumers, and Supply), considering its Regulatory Allowance for Energy

Losses. Verified Energy Losses: the amount of energy equivalent to the difference between the sum of purchased and self-generated energy and the billed energy (Regulatory Market, Free Consumers, and Supply), considering Technical Losses, Non-Technical Losses, and Losses in the High Voltage Network. This amount can be different from the Regulatory Allowance for Energy Loss. When the difference between the Verified Losses and the Regulatory Allowance for Energy Losses (in terms of amount of energy), is over the tolerance limit established by ANEEL, a

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portion of the losses is not passed on by the Distributor as tariff, which negatively

impacts the value of the Company.

Required Energy Supply: the amount of energy the Distributor needs to

generate or buy to supply the consumers (Regulated Market, Free Consumers, and


·	Excess Supply), considering Contracted its Energy: index of Verified the excess Energy amount Losses. of	energy	the	Distributor

generates or buys in relation to the Required Energy Supply. This variable was projected according to the contracted amounts informed by the Company's Distribution Board. Additionally, the perspectives of adequacy of the Energy Balance with the achievement of an optimum level of 3% of Excess Contracted Energy were considered. Such optimum level is established in order to guarantee a safety margin to the supply of the demand for energy. Considering a scenario where the Regulatory Allowance for Energy Losses and the Verified Energy Losses were equivalent, the Distributor would be paid by the generation and purchase of energy exceeding the demand up to the upper limit of 5% of Excess Contracted Energy calculated on the Regulatory Allowance for Contracted Energy.

· Self-Generation: the amount of energy the Distributor itself generates through power stations and generators. As explained in this report, because Portion A was considered neutral, we did not explicitly consider the volume of self-generated energy in the projections, although its effects are implicit in the Working Capital projections.

· Energy Purchase: the amount of energy bought by the Distributor to supply its consuming market, equivalent to the Required Energy Supply added to the Excess Contracted Energy.

· VPA Volume: the amount of energy distributed to the Regulated Market consumers and the Supplied Distributors, who pay for the cost of the energy they consume.

· VPB Volume: the amount of energy distributed to the Regulated Market consumers, Free Consumers, and Supplied Distributors, who only pay for the cost of the energy distribution services.

Electricity Rate

The Electricity Rate, the sale price of the electric power to the consumers in R$/MWh, is composed of Portions A and B. The former relates to the cost of energy production and other non-management costs, and the latter relates to returns to investment and the operational margin inherent in the electric power distribution service. The Electricity Rate is adjusted or revised on an annual basis by Aneel.

Our analyses considered the net value of the Electricity Rate meaning the taxes are not projected separately.

· Portion A

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Portion A considers five factors in its calculation: Energy Costs, Transportation Costs, Sector Charges, Finance Charges, and Bad Debt.

The calculation method applied for Portion A considers that its components should not have an impact on the business value (neutrality), since eventual gains or losses related to estimates made during the rate adjustment are neutralized in the adjustment the following year.

However, there are two cases where the principle of neutrality of Portion A is not applicable: i- When the Cost of Capital of the Distributor is different from the Adjustment Rate applied on the Finance Charges. In such case, the impact will be the difference between the net present values calculated using the different rates. Considering that the difference between the rates is not relevant, the Finance Charges were not projected. Thus, we consider the costs related to Energy Purchase, Transportation, and Sector Charges (R$/MWh) as they are used in the Electricity Rate calculations. ii- When the amount (MWh) of Required Energy Supply is over the limit of 105% of the Regulatory Allowance for Contracted Energy. In such case, the impact is considered in a portion of the costs related to Energy Purchase and Transportation that is not considered in the Electricity Rate calculation. Such an impact is considered in the valuation, as detailed in this report.

a) Energy Cost

The energy cost is calculated from the Weighted Average Cost of the Energy, in R$/MWh, considering the Energy Purchase Contracts.

Some Energy Purchase Contracts, as is the case for Self-Generation, have a different approach from the Portion A calculation methodology, using costs from the last energy auctions in the regulated market in order to balance the energy costs to consumers from different distributors operating in the Brazilian market.

In these cases, the differences between the effective cost of energy to the Distributor and the cost considered in Portion A is repaid to the Distributor through CCC. Since the projections assume the neutrality of Portion A, such differences were not considered. However, the financial impact related to the period between the payments of Energy Purchase Costs and the CCC repayments is considered in the projections of the Distributor’s Working Capital needs.

The Consortium observed recent cases in the electric power distribution sector where this difference is directly paid to the party responsible for the power generation, and does not impact the distributor’s Working Capital needs and, therefore, does not present a financial impact for the company. This observed trend supports the assumption of neutrality of Portion A considered in the projections, as well as the assumption of normalization of Working Capital levels based on the average financial indicators for the electricity distribution sector, as discussed in next sections.

The costs informed in the last Distributor’s rate adjustment were used to define the

Weighted Average Cost of Energy as of the base date. The referred average cost was projected considering inflation rate assumptions. Since the monetary adjustments are carried out in the following year through the Finance Charges, which were not considered in the valuation, we

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considered the costs used in the calculation of Portion A to be equivalent to the effective Energy Purchase Costs.

Thus, the fraction of Portion A related to the Energy Purchase Cost has a negative financial impact in the cases where the considered Energy Purchase is more than 5% higher than the Regulatory Allowance for Contracted Energy.

b) Transportation Costs

The transportation costs refer to the SIN transmission system. The Transportation Costs are paid by the Distributor in order to receive the purchased energy.

Transportation Costs were projected based on the relation between the Transportation

Cost and the Energy Cost (in R$/MWh) observed in the last Distributor’s rate adjustment. The calculations consider the Distributor´s estimated plans for interconnection.

Thus, the fraction of Portion A related to the Transportation Cost has a negative financial impact in the cases where the Required Energy Supply is more than 5% higher than the Regulatory Allowance for Contracted Energy.

c) Sector Charges

The energy distributors collect the applicable Sector Charges from their consumers and transfer the values to the sector funds.

The Sector Charges were projected based on the values considered in the last available rate adjustment. The base values were adjusted considering the projections for the inflation rate.

Due the assumption of neutrality of Portion A, the Sector Charges do not present financial impact in the valuation. However, the financial impact related to the period between the payment of Sector Charges and the receipt from the consumers is considered in the projections of the Distributor’s Working Capital needs.

d) Finance Charges

As mentioned before, the Finance Charges were not considered in the valuation. e) Bad Debts

Since the projections consider impact of Bad Debts on the cash flows net of the regulatory allowance considered in Portion A, values related to Bad Debts in the calculation of Portion A were not considered.

· Portion B

Portion B compensates the distributor for capital expenditures and operating margin of the electric power distribution service. It is calculated according to the methodology previously explained in this report and divided by the size of the market considered in the rate adjustments/revision to obtain a value expressed in R$/MWh.

Revenues

The projected Net Operating Revenues are composed of four types of revenues:

· Portion A

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Product of the Energy Tariff (R$/MWh) related to Portion A and VPA Volume (MWh).

· Portion B

Product of the Energy Tariff (R$/MWh) related to Portion B and VPB Volume (MWh).

· Sale of the Excess Contracted Energy

The sale of Excess Contracted Energy is considered for the amounts over the regulatory allowance limit (5.0%) in relation to the Required Energy Supply. The energy price considered for the sale of the Excess Contracted Energy is the Difference Liquidation Price (PLD).

The PLD projection considers the average values observed over the last 5 years for the maximum and minimum limits fof PLD as well as the average PLD in the region. The observed values were adjusted considering the inflation rate projections. The projections also considered the historical seasonality of PLD, since the averages were calculated for each month of the year. The value considered in the sale of Excess Contracted Energy is the projected average value between the minimum limit and observed mean of PLD in the region.

· Other Revenues

The other revenues include Chargeable Services and Sharing of Infrastructure, for example. No real growth was projected for those revenues.

All the projections were estimated net of sales tax, such as PIS, COFINS, and ICMS.


Costs
·	Energy Purchase

Product of the Energy Purchase (MWh) and the respective cost (R$/MWh) as projected in Portion A.

· Cost of Own Generation, Fuel and CCC Repayments

As explained before, because of the assumption of neutrality of Portion A, the values related to such items are not considered in this valuation.

· Transportation

Considering the assumption of neutrality of Portion A, the same value in R$/MWh considered in Portion A was considered as transportation costs. The impact on the Company’s valuation refers only to the amount of energy transported that exceeds the Regulatory Allowance for Contracted Energy.

Operating Expenses

In addition to the costs of Energy and Transportation, distributors also presents operational expenses, as described below:

· PMSO

Expenses of Personnel, Materials, Third Parties’ Services, and Other, projected according to the regulatory methodology of Portion B previously explained. The projected PMSO separated into the four components mentioned above is based on the historical average for each type of expense, as observed in the Distributor’s financial statements.

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An additional cost is considered in relation to the eligible PMSO for Portion B, since some distributors’ expenses are not covered by regulatory allowance. This Additional Cost is projected from historical information made available by the Distribution Board and follows an accelerated path of efficiency gain in relation to PMSO. This assumption is adopted because it is expected that the Distributor will concentrate efforts to reduce costs that do not have a regulatory allowance.

· Bad Debts

The bad debt levels were projected as a decreasing percentage of the net revenues. The calculations were made according to the regulatory methodology of Portion B previously explained. As mentioned before, the percentage was calculated net of the regulatory allowance provided as part of Portion A.

Depreciation and Amortization

The projections for depreciation of existing assets (financial, tangible, and fixed) were based on the historical relation between the Depreciation and Amortization Expenses and the the book value of the assets, calculated using the audited Financial Statements of the Distributor.

The average depreciation considered in the calculations of Regulatory Remuneration Base (BRR) was the same used for the new investments.

Financial Result

Since the valuation method used was the Free Cash Flow for the Firm approach, the financial revenues or expenses were not projected.

Direct Taxes

The Income Tax (IR) and the Social Contribution on Net Profit (CSLL) were projected, considering 15% with additional 10% tax rate for the IR and 9% rate for the CSLL.

The deferred tax assets were also considered in the projections. The values reported in the financial due diligence were used as of the base date, and the applicable updates for the projection period were considered.

Investments (Capex)

The projections consider investments in electric and non-electric assets to meet the operational needs of the Distributor, projected as described in item 5.3.7 Long-Term Investment of this report.

Working Capital and Other Adjustments

The Working Capital needs are projected using the value reported in the financial due diligence as of the Base Date, and contains, among other things, the accounts receivable or payable (clients, suppliers, sector charges, and CCC). The observed relation between the initial Working Capital and the Net Operating Revenue of the previous period is considered as the starting point for the Working Capital projections. A linear normalization was proposed, starting in the 25th projected month until the Distributor reaches the benchmark of 1.29% (see the table below) in the 84th projected month.

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7.	References
[1]	“Portal do Brasil,” [Online]. Available: http://www.achetudoeregiao.com.br/ro/historia_de_rondonia.htm.
	[Acesso em 13 04 2017].
[2]	A. Gorayeb, “Opinião de Rondônia,” 21 09 2016. [Online]. Available: http://www.opiniaoderondonia.com/noticia/do-fundo-do-bau-servico-de-abastecimento-de-agua-luz-e- forca-do-territorio/157879. [Acesso em 05 04 2017].
[3]	Eletrobrás, “Eletrobrás Distribuição Rondônia,” Eletrobrás, [Online]. Available: http://www.eletrobrasrondonia.com/empCeronNHistoria.cfm. [Acesso em 05 04 2017].
[4]	“Wikipédia - Rondônia,” [Online]. Available: https://pt.wikipedia.org/wiki/Rond%C3%B4nia. [Acesso em 06
	04 2017].
[5]	E. d. P. Energética, “Plano Nacional de Energia 2030,” Rio de Janeiro, 2007.
[6]	E. D. Rondônia, “Plano Decenal 2015 - 2024,” 2015.
[7]	E. D. Rondônia, “Reunião GT Desestatização EDES,” 2017.
[8]	B. Mundial, “The Regulatory Challange of Asset VAluation: A Case Study from the Brazilian Electricity Distribution Sector. Energy Working Notes. Energy and Mining Sector Board.,” 2004.
[9]	PricewaterhouseCoopers, “Electricity Lines Business – ODV Valuation. Study for Unison Networks Limited,”
	New Zealand, 2005.
[10]	K. F. O. &. R. G. Israel, “Why Does Everyone Use the .05 Level of Significance?, Research Quarterly for Exercise and Sport,” 1987.
[11]	J. M. WOOLDRIDGE, “Econometric analysis of cross section and panel data. MIT Press.,” 2010.

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ANNEX I – Extent of Responsibility

This report (the “Report”) was jointly prepared by PricewaterhouseCoopers Corporate Finance & Recovery Ltda. ("PwC CFR") and Siglasul Consultoria Ltda. (“SSU”) for the use of the Brazilian Development Bank ("BNDES") with the purpose of supporting the privatization process of the Distributors of Eletrobras System (the “Privatization”), in accordance with contract OCS 028/2017 of February 14, 2017 (the “Contract”).

The Report was prepared based on the information and documents provided by the administration of Centrais Elétricas de Rondônia (the “Administration”). The works carried out do not constitute an exam performed according to the audit standards for financial statements; the works of financial valuation are not regulated and do not have specific determined standards and, for this reason, the procedures applied by us were determined in the Official Notice or aligned with BNDES where indicated in this Report.

This analysis considers only one of several methods that may be used to calculate the valuation of a company, with nothing preventing the potential stakeholders from using their own valuation of the projects. Our analysis did not consider eventual synergies, strategic reasons, scale economies, or other benefits or drawbacks that eventual investors could experience in the event of a change of shareholding interests of the Company.

Upon preparing the analysis, we used information and historical and projected data, not audited by the Consortium and provided in writing or orally by the Administration or obtained from the mentioned sources. Additionally, as every prediction is subjective and depends on individual judgment, being subject to uncertainties, we did not present predictions as specific results to be achieved.

Our work considered the contingencies considered in the other reports of diligences prepared by

Consórcio Mais Energia B (the “Consortium”) under the terms of the Contract, that contain more detailed information.

Our work was developed with the purposes described above, therefore, it should not be used for other purposes.

In the event we become aware, at any time, of facts or information that had not been provided to us, we reserve the right to revise the calculations and the numerical results.

We do not take responsibility for the update of our reports outside the terms provided in the Contract with BNDES.

We do not take any responsibility, outside the legal hypotheses or hypotheses provided in the Contract executed with BNDES, for losses caused to BNDES, to Centrais Elétricas de Rondônia, companies connected thereto, their shareholders, officers, or other parties, as a consequence of use of the data and information provided by Centrais Elétricas de Rondônia, or obtained from other sources, or for the improper use of our reports that does not observe the disclaimers of the previous paragraphs.

Finally, the provisions of Contract OCS no. 28/2017 (and its annexes) and the effective legislation were followed in the preparation of this Report, whose copyrights are granted to BNDES under the terms of art. 8 of Law no. 13.303/2016. All information transmitted in this document may be used and disclosed by BNDES, without any restriction.

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Table 85 – Family of Exponential Models

		Seasonal Component
Trend Component		A	M
	N (none)	(additive)	(multiplicative)
N (none)	N,N	N,A	N,M
A (additive)	A,N	A,A	A,M
Ad (smoothed additive)	Ad,N	Ad,A	Ad,M
M (multiplicative)	M,N	M,A	M,M
Md (smoothed multiplicative)	Md,N	Md,A	Md,M

Source: Adapted from http://robjhyndman.com/talks/RevolutionR/6-ETS.pdf.

Such models present some specific names, namely: N,N: Simple exponential smoothing

A,N: Holt’s linear method

Ad,N: Additive damped trend method M,N: Exponential trend method Md,N: Multiplicative damped trend method

A,A: Additive Holt-Winters’ method

A,M: Multiplicative Holt-Winters’ method

The State Space Models also enable the differentiated treatment of the error component, which may be additive or multiplicative, and which increases the variability of options for the projection of time series. The following are some models: A,N,N: Simple exponential smoothing with additive errors

A,A,N: Holt’s linear method with additive errors

A,A,A: Additive Holt-Winters’ method with additive errors

A,Ad,N: Damped trend method with additive errors

M,A,N: Holt’s linear method with multiplicative errors

M,A,M: Multiplicative Holt-Winters’ method with multiplicative errors

c) Dynamic Models

The Dynamic Models of Linear Regression applied in time series, enable combining the use of auxiliary variables, components of trend, seasonality, and self-regressive parameters, to make predictions using Ordinary Least Squares (OLS). The time series yt may be expressed by a constant Ã0 plus a self-regressive part that depends on the dephased value of the series plus a coefficient multiplied by the auxiliary variable and added to the error term.

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APPENDIX C - Selection of Models for Market Projections

The selection of models to perform market projections was made from the selection of models that would present greater strength among the set of models estimated in each distributor and market. It should be noted that the historical series of consumption per class (MWh) presented very strange characteristics, especially due to the economic crisis experienced by Brazil, resulting in greater variability of the sets of data, structural and momentary breaks, modifying the standard and level of the series, diverging from historical standards previously experienced, and increasing the difficult of finding an ideal regression model to perform forecasts.

The models were selected within the set of adjusted models considering: the most adequate methodology to be deployed; the use of transformations in the historical series; the need of use of auxiliary variables; the analysis of the information criteria; the analysis of the residuals; and the value of the need of change in the period of the observed historical series, in order to obtain more robust models.

Statistical tests were used in the analysis of the residuals to check assumptions of non-correlation of errors, heteroscedasticity, and normality, namely: Ljung-Box, Durbin-Watson, Arch, and Jarque Bera tests. Additionally, the residuals of the models were analyzed, through serial autocorrelation graphs and histograms. In the cases of the statistical tests, the greater the p-value, the greater the evidence of non-violated assumptions. To fix a base value, the significance level of 1% was used (0.01).

Considering all aspects presented, the purpose was to find the most robust forecast models within each market and class. Below are the p-value of the statistical tests carried out in each distributor and class of the final models used in the projections, which were elected as most adequate among the possibilities and specificities of each historical series.

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Table 86 – Statistical Indicators


		Self-
Company	Class	relationship	Heterocedasticity	Normality
AME	Residential	0,676	0,669	0,946
	Industrial	0,058	0,735	0,064
	Commercial	0,957	0,986	0,136
	Rural	0,418	0,46	0,001
	Public Entity	0,852	0,086	0,001
	Public Lighting	0,140	0,245	0,001
	Public Service	0,007	0,03	0,000001
	Self consumption	0,34	0,514	0,557
ELETROACRE	Residential	0,748	0,178	0,54
	Industrial	0,929	0,0084	0,6287
	Commercial	0,629	0,268	0,369
	Rural	0,070	0,702	0,314
	Public Entity	0,121	0,911	0,224
	Public Lighting	0,999	0,960	0,0000001
	Public Service	0,921	0,345	0,0001
	Self consumption	0,847	0,978	0,234
CEPISA	Residential	0,050	0,285	0,519
	Industrial	0,386	0,53	0,788
	Commercial	0,908	0,617	0,797
	Rural	0,503	0,667	0,06
	Public Entity	0,109	0,344	0,255
	Public Lighting	0,104	0,144	0,3
	Public Service	0,134	0,577	0,007
	Self consumption	0,268	0,779	0,108
CEAL	Residential	0,307	0,661	0,739
	Industrial	0,002	0,141	0,019
	Commercial	0,977	0,623	0,3388
	Rural	0,735	0,983	0,0032
	Public Entity	0,503	0,548	0,003
	Public Lighting	0,603	0,997	0,0001
	Public Service	0,467	0,686	0,328
	Self consumption	0,547	0,958	0,22
Ceron	Residential	0,987	0,399	0,688
	Industrial	0,815	0,8343	0,010
	Commercial	0,081	0,701	0,646
	Rural	0,278	0,452	0,428
	Public Entity	0,007	0,361	0,386
	Public Lighting	0,607	0,992	0,00003
	Public Service	0,137	0,850	0,803
	Self consumption	0,002	0,407	0,053
BOA VISTA	Residential	0,813	0,634	0,88
	Industrial	0,757	0,856	0,001
	Commercial	0,007	0,814	0,2329
	Rural	0,123	0,732	0,325
	Public Entity	0,289	0,942	0,00001
	Public Lighting	0,819	0,809	0,152
	Public Service	0,289	0,942	0,00002
	Self consumption	0,953	0,998	0,000005
Source: Self prepared.

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ii.

Rolling Forward: this represents the shielding of the initial base, defined from any of the methods previously detailed, and subsequent update of the shielded values until the date of each tariff revision, taking into consideration the monetary indexing, the deduction of the write-offs, the depreciation, and the additions (whose methods may be different from those used for the initial base). This method converts the initial asset into a kind of financial asset. Once incorporated to the BRR, the price of the asset is not reassessed again nor is technological change incorporated.

This method is used by ANEEL in the valuation of the BRR of the electric power distributors in Brazil.

Comparison Value Method

This method is determined from the values associated to the BRR of similar companies with a sample of comparable assets. To its calculation, it is required the establishment of a benchmarking and the gathering of the values defined to the BRR of other companies.

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201

National Bank for Economic and Social Development ("BNDES") Av. República do Chile, 100 Rio de Janeiro - RJ

C/O: Ms. Lidiane Delesderrier Gonçalves - OCS 028/2017 Agreement Manager June 2017 Dear Sirs,

According to our service agreement OCS 028/2017 ("Agreement") executed between BNDES and the Mais Energia B Consortium ("Consortium") on 2/14/2017, we present the result of our work carried out in the context of Privatization of Eletrobrás System Distributors.

The result of our work is detailed in this document "Product 07: CERON Technical-Operational Evaluation Report ("Report"), dated June 2017.

Our work was developed solely for the purpose of advising the BNDES, as those responsible for executing and monitoring the process of privatization of utility companies by Decree 8,893, in CERON's evaluation, in accordance with the Agreement, and was based on information provided by CERON's management and on the premise that this information is true and complete. This information was not subject to testing or verification, except where expressly stated within the scope of our work.

In case the Report is to be accessed by third parties, it must be made available in full, so that the applicable safeguards and limitations are known.

Regards,

Siglasul Consultoria Ltda., as member of the Consortium

___________________________
Luis Fernando Alvarez

______________________________
Leonardo Campos Filho

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This document is a true copy of the original signed version delivered to BNDES and in the possession of Eletrobras.


Summary

1.	Executive summary	5
2.	Company operational characterization and diagnosis	7
2.1.	Characterization of the company's area of activity	8
2.2.	Geoelectric Characterization of the Concession	16
2.3.	Utility's Consumer Market Analysis	21
2.4.	Operating Indicators	26
2.5.	Energy Purchase and Sale Indicators	34
2.6.	Asset Conditions	37
2.7.	Critical points observed during the field visit and challenges for new utilities	39
3.	Five-Year Investment Plan ("PIQ")	41
4.	References	45
APPENDIX A - Socioeconomic Characterization of the Concession Area		46
APPENDIX B- Consumer Market		49
APPENDIX C- Response to Emergencies		50
APPENDIX D- Norte II Agreement		52


Figures
Figure 1 - State of Rondônia (capital highlighted)		9
Figure 2 - Federal and State Highways of Rondônia		12
Figure 3 - Cumulative total precipitation for the Brazilian states.		15
Figure 4 - Average temperatures observed for the Brazilian states		16
Figure 5 - National Interconnected System		18
Figure 6 - Regional representation according to interconnection to the Basic Grid		19
Figure 7 - Map of the state, with the distribution of substations.		20
Figure 8 - Radial system (230 kV) for supplying the states of Rondônia and Acre		38
Figure 9 - Rate Groups and Categories		49


Graphs
Graph 1 - Total Road Density (km/km²)		11
Graph 2 - Percentage of Existing and Planned Roads in 2015		12
Graph 3 - Competitiveness of generation sources		17
Graph 4 - DEC Determined Indicator and Limits		27
Graph 5 - FEC Determined Indicator and Limits		28
Graph 6 - Number of Sets that violated their 2016 limits and UC Representation		28

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Graph 7 - Histogram of Ceron's sets: 2016 DEC	29
Graph 8 - Histogram of Ceron's NUC: 2016 DEC	29
Graph 9 - Histogram of the Ceron sets: 2016 FEC	30
Graph 10 - Histogram of Ceron's NUC: 2016 FEC	30
Graph 11 - Evolution of the product quality indicator (DRCE)	31
Graph 12 - Evolution of the product quality indicator (DRPE)	31
Graph 13 - Regulatory Technical Losses for Injected Energy	33
Graph 14 - Comparison between Non-Technical Real and Regulatory Losses for the BT Market	33

Graph 15 - Evolution of Base Energy, Bilateral and CCEAR and the percentage of Required Energy recognized by the Energy


Rate.	36
Graph 16 - Mean Times of Response to Emergencies	50
Graph 17 - Evolution of the Number of Emergency Events with Electric Power Outage Versus the Total	51


Tables
Table 1 - Five-year investment plan - Base Scenario	7
Table 2 - Five-year investment plan - Alternative Scenario	7
Table 3 - Rondônia Road Indicators	13
Table 4 - Climatic Characteristics of Ceron's Concession Area	14
Table 5 - Evolution of the Number of Consumers by Voltage Level	21
Table 6 - Market Evolution by Voltage Level	22
Table 7 - Evolution of Revenue by Voltage Level	22
Table 8 - NUC Evolution by Rate Class	23
Table 9 - Market Evolution by Rate Class	23
Table 10 - Evolution of the Average Market by Rate Class	24
Table 11 - Revenue Evolution by Rate Class	24
Table 12 - Number of Consumers, Market and Revenue by Voltage Level	25
Table 13 - Number of Consumers and Revenue by Rate Class	25
Table 14 - Compensations for Breach of Quality of Service Indicators	27
Table 15 - Compensations for Breach of Product Quality Indicators	32
Table 16 - Results of Regulated Required Energy (MWh) from 2012 to 2016	35
Table 17 - Results of Contracted Energy (MWh) from 2012 to 2016	35
Table 18 - Investments in progress in the year 2017 by Type of Project	41
Table 19 - Base Scenario: Five-Year Investment Projection	43
Table 20 - SEs with anticipated investments for the drafting of the Five-Year Plan	43
Table 21 - Alternatives Scenario: Five-Year Investment Projection	44
Table 22 - Demographic Information, Level of Education and Unemployment Rates	46
Table 23 - Service Access Information	47

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1. Executive summary

This report aims to fulfill item "4.2.5 -Technical-Operational Evaluation of Eletrobras Group Companies", of the "Invitation to Bid" regarding the "AARH Electronic Bidding #51/2016 - of the National Bank for Economic and Social Development (BNDES)" for Centrais Elétricas de Rondônia S.A. (hereinafter referred to as Ceron for the purposes of this report).

In this document - and in its Appendices - all aspects related to the Invitation to Bid are presented, as described below: (i) operational characterization and diagnosis of the company, identifying the operational challenges in the distributor's concession area, including the current operational indicators; (ii) conditions of assets, services and investments in progress, based on field visits, assessing the most critical points in the concession; and, (iii) investment plan for the next 5 years, with scenarios that envisage the proper operation of the distributor.

Ceron's concession area, with a range of 237,765 km², is located in the state of Rondônia, in the Northern region of Brazil. The state borders the states of Mato Grosso, to the east; Amazonas, to the north; Acre, to the west and has international borders with the Republic of Bolivia, to the west and south. Rondônia's population is one of the most diversified in Brazil, composed of migrants from all regions of the country. With a population of 1.77 million, the state is the third most populous in the Northern Region. In its capital only (Porto Velho), more than 500 thousand people are concentrated [1].

With stable annual temperatures varying between 26 ºC and 28 ºC, the concession is characterized by abundant rain and a high lightning rate. As the total of paved roads represents less than 14% of the state's highways, the combination of climatic and infrastructure factors directly influence the operation of the company both due to the number of disconnections in the overhead transmission and distribution grids caused by lightning, if protection by grounding and logistic surge arrester systems is undersized, and due to the time to respond to emergencies due to bogged cars during the rainy season, since unpaved access roads tend to become even more precarious with the concentration of mud and dirt, affecting even the durability of vehicles.

The consequences of climate and logistics issues can be observed in the high index of violation of DEC and FEC collective continuity indicators¹. About 65% of the company's consumer units are served by electrical sets having indicators above the limits established by the National Electric Energy Agency ("ANEEL") for DEC. For FEC, this number represents 43% of consumer units. The average total time for responding to emergencies is equal to 5 hours.

Regarding the consumer market, Ceron has its market represented by consumers allocated at the High, Medium and Low Voltage levels ("AT", "MT" and "BT", respectively), the latter being more expressive with respect to the number of consumers (99.6%), market (70.4%) and revenue (73.2%), according to 2016 data. Noteworthy is the low growth of the BT segment in the period between 2012 and 2016 (2% p.a.), which mainly includes the Residential class, with participation of 72% of consumers and 42 % of Ceron's revenue, and the Rural class, with 20.2% and 11%, respectively.

¹Equivalent Duration of Downtime per Consumer Unit ("DEC"); Equivalent Frequency of Downtime per Consumer Unit ("FEC")

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Despite the high level of representativeness for BT, the MT level has a good market share, with an average consumption of 789 MWh (27.0% of the market and 24.4% of revenues), according to 2016 data. Noteworthy is the low participation of the captive AT consumers, Free Consumers and Generator in the composition of the Distributor's Revenue, respectively 0.5%, 0.1% and 0.7%.

It should be noted that the level of energy losses in the Ceron system is extremely high, especially with respect to the commercial aspect (Non-Technical Losses, "PNT"). This level is higher than 38% of the Company's low voltage market and is well above the regulatory target for rate recognition, which is 8.33%, related to the year 2016.

Regarding the distributor's electrical system, despite the fact that during the technical visits, assets were observed to be in good conditions, grids have little flexibility in the transfer of loads in situations of operation contingency, and expansion of transforming substations and implementation of new lines is necessary. In addition, equipment was verified to have no automation, and communication systems required improvements. It is also worth noting that, especially in the northern part of the state, many communities are served by isolated systems.

Looking at both commercial and technical aspects, a Five-Year Investment Plan ("PIQ") is an integral part of this report, which prioritizes, for the first five years, ensuring grid expansion for the Programa Luz Para Todos program and interconnection of isolated systems to the National Interconnected System ("SIN"), correction of the quality of supply and the investments related to the fight against losses.

This document has as its main sources of information the "Electricity System Expansion Plan (2017-2026 horizon)", the "Distribution Development Plan ("PDD") for the year 2017", the "Results Plan for Improvement of Management Services" of 2015 and the "Plan for Temporary Rendering of the Electricity Distribution Service" of 2017, all of which were prepared by Ceron. In addition to this information, we used information obtained by the company's planning area, obtained through face-to-face meetings and conference call.

Assumptions and results of the need for investments are described in the PIQ by type of project and voltage level. The PIQ has two investment scenarios (called the "Base Scenario" and the "Alternative Scenario") that differ in the time allocation of certain investments, where the Alternative Scenario occurs in the most opportune time for rate recognition when carrying out the rate revision (2023²), and also foresees investments that are not included in the Base Scenario.

The investments were, in their total amounts, defined as shown in Table 1 (Base Scenario) and Table 2 (Alternative Scenario)³.

²In this case, it was assumed that the company will have its privatization process finalized in 2018, having, therefore, an RTP in the year 2023.

³The financial amounts of projected five-year investments presented in this Report are in real currency at April 2017 prices.

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Table 1 - Five-year investment plan - Base Scenario

						Total
Year	2018	2019	2020	2021	2022
						Period
Total	BRL 579,700,076	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 80,255,600	BRL 1,069,135,500
Total Own
Resources*	BRL 147,965,310	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 80,255,600	BRL 637,400,734

Table 2 - Five-year investment plan - Alternative Scenario

						Total Period
Year	2018	2019	2020	2021	2022

Total	BRL 579,700,076	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 111,183,316	BRL 1,100,063,216
Total Own
Resources*	BRL 147,965,310	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 111,183,316	BRL 668,328,450

*For total Own Resources, we deducted subsidies related to the projects linked to the Programa Luz para Todos ("PLpT") (90%) in the year 2018 and the CCC subrogation for the interconnection of isolated systems in the year 2018, thus better equalizing the initial disbursement to the new utility.

The high volume of investments allocated in 2018 (around 54% of the five-year period) is related to projects to guarantee the interconnection of isolated systems (BRL 251 bn) and compliance with the PLPT (BRL 201 bn), the latter due to the end of the program in the year 2018, according to Decree #8,387 of 12/30/2014.

In the following items (and in its Appendices), all the aspects discussed in the executive summary shall be detailed.

2. Company operational characterization and diagnosis

In this chapter, we will discuss the characterization of Ceron's concession area, as well as make a brief operational diagnosis of the company.

Firstly, we will make a brief description of the company's area of activity (by providing information about its history, socioeconomic, road infrastructure and climate indicators) in order to subsequently carry out the Company's electrical characterization (assessing the level of interconnection to the SIN and constructive standards of the electricity distribution grids).

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Next, we will analyze the company's consumer market by detailing information of both consumption broken down by voltage level and by rate class and of billing according to the type of user. Subsequently, we will cover the main operating indicators regarding: (i) quality of service; (ii) product quality; (iii) response to emergencies; and (iv) power losses, in addition to evaluating energy purchase and sale indicators.

Also in this chapter we will analyze the conditions of the assets observed in the visits made in the field, highlighting critical points and main challenges for a new utility.

2.1.	Characterization of the company's area of activity
2.1.1.	Brief History
	The history of Rondônia began in the early seventeenth century with the arrival of the first

Portuguese settlers in its territory. However, only in the following century, with the discovery of gold in Goiás and Mato Grosso, interest in the region intensified. With the creation of the state of Acre, the construction of the Madeira-Mamoré railroad and the telegraphic connection established by Cândido Rondon at the beginning of the 20^thcentury, the settling of the present state's region experienced a new boost until, in 1943, the region was constituted as the Federal Territory of Guaporé (in 1956 being called Territory of Rondônia), with a capital in Porto Velho, through the dismemberment of areas belonging to the states of Mato Grosso and Amazonas [2].

The first thermoelectric power plant in the present state of Rondônia was opened in 1940 by President Getúlio Vargas. After the creation of the Federal Territory of Guaporé, this plant was renamed SAALFT (Serviço de Abastecimento de Água, Luz e Força do Território), serving only two municipalities: Porto Velho, the Capital and Guajará Mirim. This thermoelectric, diesel generation had an installed power of 2,893 kW.

The accelerated growth of the region only actually occurred from the 60's-70's. The tax incentive policy and intense investments by the federal government, such as directed settlement projects, stimulated migration, largely originating from the Center-South region of the country. With the growth of the region, it was necessary to improve the development of sanitation and electric power infrastructure. Thus, in 1968 SAALFT 's services were divided and the companies CAERD (Companhia de Águas e Esgotos de Rondônia) and Ceron (Centrais Elétricas de Rondônia) were created [3].

In the same year (1968) Federal Law #5,523 of November 4 established Centrais Elétricas de Rondônia S.A. under the abbreviation Ceron, with the purpose of exploiting electricity services and operating in the fields of transmission and distribution within the territory of Rondônia.

After almost 30 years, in 1997, a new landmark was established and Ceron started to experience a shared management among the government of the state of Rondônia (established as a State in 1982) and Eletrobras. The state now holds 51% of the company's shares, while Eletrobras has 48.7% of the shares. Also in 1997, the distributor was federalized, according to State Law #740/97. The State approved the transfer of Ceron's control to Eletrobras. The shareholding structure was distributed as follows: 79.91% - Eletrobras, 20.0% - State Government and 0.09% - other shareholders. [4]

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The analysis of the roads effectively constructed results in the information concentrated in Table 3, which provides data for federal, state and also municipal highways, as well as the paving⁹situation thereof for the state of Rondônia.


	Table 3 - Rondônia Road Indicators

		Extension	Weight/
Type	Roads		Participation
		(km)	(%)
	Federal	1,952.50	8.42%
TOTAL	State	4,889.8	21.09%
	Municipal	16,344.10	70.49%
	Total Roads	23,186.40	100.00%
	Federal	1,839.7	57.11%
	State	1,373.7	42.65%
Paved
	Municipal	7.8	0.24%
	Subtotal Paved	3,221.20	13.89%
	Federal	112.80	0.56%
	State	3,516.1	17.61%
Unpaved
	Municipal	16,336.30	81.82%
	Subtotal Unpaved	19,965.20	86.11%
	Source: DNIT, 2015.

As shown, the state has a road network that totals almost 20,000 km of highways, 70% of which are municipal and unpaved. Federal and state highways, when added, represent 30% of highways, but approximately 50% of them are paved.

These facts directly influence the logistics of operation of the teams to respond to emergencies due to bogged cars during the rainy season, since these roads tend to become even more precarious with the concentration of mud and dirt, affecting even the durability thereof.

Considering all facts exposed in this section, we conclude that Rondônia is a state with low road density in its territory, and has poor road structure.

2.1.5. Climate Characterization

The climatic characterization of the state of Amazonas, comparing it with other regions of the country, is of extreme importance in order to verify the particularities of the region.

The climate in Rondônia is slightly more diversified than the rest of the Northern region of the country, and is able to show up to three different typologies: equatorial, to the north of the state, which has high temperatures throughout the year and great humidity (in the areas bordering the state of Amazonas and the surroundings of Porto Velho); hot and humid with a dry phase duration of up to two months in the central region of the state; and hot and semi-humid, which influences the southwestern part of the state, where the municipalities of Colorado and Cabixi are situated.

Table 4 contains basic information¹⁰for the climatic characterization of Ceron's concession area.

⁹Paving is coating made by materials capable of withstanding constant flow of vehicles, such as asphalt, for example.

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	Table 4 - Climatic Characteristics of Ceron's Concession Area
		Climatic Characteristics for Rondônia and Regions

	Rainfall	Rain	Keraunic	Maximum	Maximum Wind
Region	indexⁱ	Intensity ⁱⁱ	Index ⁱⁱⁱ	Temperature	Speed ^v
	(mm)	(mm/day)	(lightnings/km²)	^iv(°C)	(mps)
Rondônia	170.18	11.41	6.67	32.07	4.79
North	176.60	11.64	5.93	31.76	4.09
Northeast	54.66	5.18	2.48	30.60	5.35
Brazil	109.44	8.82	5.55	29.45	4.69
Source: INMET¹¹and INPE¹²websites.

i	= Annual average precipitation (rain, snow, hail) at a given location during a given period of time.
ii	= Ratio between the Rainfall Index and the number of days with precipitation in a given region.


iii = Amount of lightnings in a given region. v = Average maximum speed recorded.		iv = Maximum average temperature recorded.

Figure 3 illustrates the understanding that the state of Rondônia is located in a region of the country that is not heavily influenced by rainfall, with total precipitation between 1,600 mm and 2,000 mm for the year 2015 and between 1,800 mm and 2,200 mm for the year 2016. Rainfall rates for the state are slightly above the verified rates for the North and Northeast regions, in addition to the national average.

¹⁰The information available for this analysis relates to the year 2012 and is taken from the ABRADEE R&D project entitled Periodic Rate Revision Methodologies of Electric Energy Distributors, held in the year 2013, since there is no publicly available average or accumulated data for the variables under study.

¹¹National Meteorology Institute (INMET).

¹²National Space Research Institute (INPE).

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2.3. Utility's Consumer Market Analysis

This chapter will analyze the consumer market of the company, detailing information on consumption, broken down by voltage level and by rate class, in addition to billing according to the type of user. It should be noted that all the information in this section was obtained from the company's rate activity over the time horizon from 2012 to 2016.

We summarize in Appendix B to this report concepts that facilitate the understanding of the Brazilian rate structure.

In Table 5 we analyze the evolution of the number of consumer units ("NUC") of the company between the years of 2012 to 2016, as well as the growth rates for the whole period - change in the year 2016 versus the year 2013 - and geometric - percentage of average annual increase.


	Table 5 - Evolution of the Number of Consumers by Voltage Level
		NUC by Voltage Level				Rate of Change
						Period %	Geometric
Voltage/Year	2012	2013	2014	2015	2016	(2013/2016)	(p.a.)¹⁴%
A3	-	-	9	2	2	-	-
A3a	-	27	27	26	26	-4%	-1%
A4	-	1,978	2,053	2,146	2,177	10%	3%
BT	-	562,308	573,252	587,033	602,673	7%	2%
TOTAL	538,218	564,313	575,341	589,207	604,878	7%	2%

Source: ANEEL, rate activity approved between 2012 and 2016, processed in November of each year. In general, NUC relates to the month of October of each year.

* There is no public data approved by ANEEL of NUC by voltage level for the year 2012. For this reason, the rates of change were estimated by considering the change observed between 2013 and 2016.

The High Voltage subgroup (A3) showed a path of reduction between the years 2014 and 2015, with a decrease of 7 consumers¹⁵. MT and BT subgroups showed modest annual growth (3% and 2%, respectively).

Table 6 shows the evolution of the billed market (MWh) by voltage level, in addition to the two growth rates (period and geometric). Market information is also presented according to the types: (i) Provision - captive consumers of the distributor; (ii) Supply - distributor supplying another distributor;

(iii)

Other Free Consumers - free consumers of the distributor; and (iv) Distribution.

¹⁴	p.a. = per annum.
¹⁵	The rates of change for the A3 subgroup were not calculated as there are no figures for this subgroup for the year 2013. The
7	clients possibly migrated to the free market.

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Table 6 - Market Evolution by Voltage Level

		Market by Voltage Level (MWh)				Rate of Change
						Period %	Geometric
Voltage/Year	2012	2013	2014	2015	2016	(2012/16)	% (p.a.)
PROVISION	2,633,594	2,778,835	3,001,913	2,966,892	2,900,694	10%	2
A3	24,166	62,324	94,137	39,860	23,268	-4%	-1%
A3a	36,290	36,037	40,917	34,501	29,165	-20%	-5%
A4	792,917	756,062	828,510	812,491	789,327	0%	0%
BT	1,780,222	1,924,412	2,038,350	2,080,041	2,058,933	16%	4%
LOW INCOME	-	139,289	148,569	127,303	107,048	-	-
SUPPLY	-	-	-	-	-	-	-
OTHER FREE
CONSUMERS	28,823	-	35,535	31,472	22,999	-20%	-5%
DISTRIBUTION	-	-	-	-	-	-	-
TOTAL	2,662,418	2,778,835	3,037,448	2,998,364	2,923,693	10%	2%

Source: ANEEL, rate activity approved between 2012 and 2016, processed in November of each year. Market data relates to the period of 12 months, accounted for up to the month before the IRT/RTP. The percentage of Low Income market share is in relation to the BT market.

In general terms, there is a relative stability in the market, which showed a growth trend between 2014 and 2015 and a slowdown in 2016. We see that the consumer market for MT was the one that showed the largest decrease in the period (20%), while the BT market increased energy consumption by 16% for the same period.

Table 7 shows the revenue evolution by voltage level, in addition to the two growth rates under analysis. The highest growth was observed in the BT subgroup, with an average growth of 15% p.a., followed by the MT segment, with an average growth of 10% p.a.

Table 7 - Evolution of Revenue by Voltage Level


		Revenue by Voltage Level (BRL Million)				Rate of Change
						Period %	Geometric
Voltage/Year	2012	2013	2014	2015	2016
						(2012/2016)	% (p.a.)
PROVISION	856	949	866	977	1,422	66%	14%
A3	5	20	17	8	7	33%	7%
A3a	9	9	9	9	12	34%	8%
A4	237	235	202	230	350	48%	10%
BT	604	684	637	729	1,052	74%	15%
SUPPLY	-	-	-	-	-	-	-
OTHER FREE
CONSUMERS	3	-	2	1	2	-33%	-9%
DISTRIBUTION	-	-	-	-	-	-	-
GENERATOR	11	6	6	9	10	-8%	-2%
TOTAL	871	955	875	988	1,435	65%	13%

Source: ANEEL, rate activity approved between 2012 and 2016, processed in November of each year. Revenue is in nominal currency, at the price as of the date of processing the rate activity of each year.

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Table 8 shows the NUC evolution by rate class. There is a higher percentage of NUC growth in the "Street Lighting" class, with an increase of 7% p.a. The "Industrial" and "Other" classes were shrunk, namely, by 3% p.a. and 18% p.a., respectively. The "Public Power" and "Commercial" classes experienced a modest growth of 1% p.a. and 2% p.a., respectively.


Table 8 - NUC Evolution by Rate Class
		NUC by Rate Class (MWh)				Rate of Change
Class/Year	2012	2013	2014	2015	2016	Period%	Geometric%
						(2012/2016)	(p.a.)
Residential	382,548	401,687	411,047	423,053	435,917	14%	3%
Industrial	2,069	1,972	1,974	1,930	1,832	-11%	-3%
Commercial	38,215	38,356	38,663	39,313	39,582	4%	1%
Rural	110,325	117,285	118,478	119,605	122,249	11%	3%
Street Lighting	210	246	257	276	273	30%	7%
Public Power	4,345	4,437	4,595	4,684	4,654	7%	2%
Public Service	208	216	216	225	239	15 %	4%
Other	298	114	111	121	132	-56%	-18%
TOTAL	538,218	564,313	575,341	589,207	604,878	12%	3%

Source: ANEEL, rate activity approved between 2012 and 2016, processed in November of each year. In general, NUC relates to the month of October of each year.

Table 9 shows the evolution of the Ceron Market by rate class. The "Street Lighting" class showed the highest growth in energy consumption in the period considered, namely, 49%, followed by "Rural", with a 25% growth and "Public Power", with a 16% increase. The "Industrial" and "Public Power" classes were shrunk by 2% p.a. and 1% p.a., respectively.


Table 9 - Market Evolution by Rate Class

		Market by Rate Class (MWh)				Rate of Change
Class/Year	2012*	2013	2014	2015	2016	Period%	Geometric%
						(2012/2016)	(p.a.)
Residential	1,007,772	1,089,993	1,147,944	1,165,781	1,154,729	15%	3%
Industrial	458,820	460,222	586,523	482,195	416,479	-9%	-2%
Commercial	585,145	595,936	627,895	643,685	634,418	8%	2%
Rural	246,966	260,545	282,531	300,620	308,486	25%	6%
Street Lighting	88,422	121,322	131,448	130,051	131,880	49%	11%
Public Power	191,647	197,872	208,249	220,823	222,233	16%	4%
Public Service	51,211	49,280	48,924	48,976	49,906	-2%	-1%
Other	5,006	3,665	3,934	6,232	5,561	11%	3%
TOTAL	2,634,989	2,778,835	3,037,448	2,998,364	2,923,693	11%	3%

Source: ANEEL, rate activity approved between 2012 and 2016, processed in November of each year. Market data relates to the period of 12 months, accounted for up to the month before the IRT/RTP.

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*Values for the year 2012 were taken from Technical Note # 405/2012-SRE ANEEL. These are not in agreement with the market by voltage level.

The average monthly consumption information per customer is shown in Table 10. As shown, the "Other" class had the highest increase in average consumption (26% p.a.), while the "Public Service" class showed a 4% p.a. decline.


Table 10 - Evolution of the Average Market by Rate Class

	Average Monthly Consumption by Class (kWh)					Rate of Change
Class/Year	2012	2013	2014	2015	2016	Period%	Geometric%
						(2012/2016)	(p.a.)
Residential	220	226	233	230	221	1%	0%
Industrial	18,480	19,448	24,760	20,820	18,945	3%	1%
Commercial	1,276	1,295	1,353	1,364	1,336	5%	1%
Rural	187	185	199	209	210	13%	3%
Street Lighting	35,088	41,098	42,623	39,267	40,256	15%	3%
Public Power	3,676	3,716	3,777	3,929	3,979	8%	2%
Public Service	20,517	19,012	18,875	18,139	17,401	-15%	-4%
Other	1,400	2,679	2,954	4,292	3,511	151%	26%
TOTAL	408	410	440	424	403	-1%	0%

Source: ANEEL, rate activity approved between 2012 and 2016, processed in November of each year. Market data relates to the period of 12 months, accounted for up to the month before the IRT/RTP.

Table 11 shows the evolution of Ceron's revenue by rate class. It should be noted that there is no public data approved by ANEEL in 2012 regarding revenue related to each rate class, which is why only the total amount for 2012 is presented. The rates of change for this information are calculated by using the period from 2013 to 2016. Note that the "Other" class was the one with the highest revenue growth, which was 15% p.a.


		Table 11 - Revenue Evolution by Rate Class
		Revenue by Class (BRL Million)				Rate of Change
						Period %	Geometric
Class/Year	2012*	2013	2014	2015	2016	(2013/2016)	% (p.a.)
Residential	-	399	370	421	608	52%	11%
Industrial	-	134	126	122	171	28%	6%
Commercial	-	207	183	212	312	51%	11%
Rural	-	94	90	107	161	70%	14%
Street Lighting	-	22	22	24	36	60%	13%
Public Power	-	74	62	73	109	47%	10%
Public Service	-	15	12	14	22	49%	10%
Other	-	7	7	11	13	74%	15%
TOTAL	871	955	875	988	1,435	50%	11%

Source: ANEEL, rate activity approved between 2012 and 2016. There is no public data approved by ANEEL of Revenue by rate class for the year 2012. For this reason, the rates of change were estimated by considering the change observed between 2013 and 2016. Revenue is in nominal currency, at the price as of the date of processing the rate activity of each year.

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Once the market evolution of the distributor has been observed, it is necessary to evaluate it according to the data of the last readjustment of the company (carried out in November 2016, the most recent regulatory information). To that end, Table 12 shows the distribution of users, market and revenue, by voltage level.

Table 12 - Number of Consumers, Market and Revenue by Voltage Level


			Market (MWh)		Revenue (BRL
Ceron	NUC
					million)
A3	2	0.0%	23,268	0.8%	7.3	0.5%
A3a	26	0.0%	29,165	1.0%	12.4	0.8%
A4	2,070	0.4%	789,327	27.0%	350.8	24.4%
BT	602,673	99.6%	2,058,933	70.4%	1,052.2	73.2%
Other Free
Consumers	64	0.0%	22,999	0.8%	2.4	0.1%
Generator	43	0.0%	-	-	10.4	0.7%
Total	604,878	100%	2,923,693	100%	1,435.5	100%
Source: ANEEL, Company's 2016 IRT, November 2016.

As shown, BT has a greater weight of consumers (99.6%), market (70.4%) and also revenue (73.2%) compared to other voltage levels. MT is responsible for about 28% of the market and 25% of revenue. Noteworthy is the low participation of the captive AT consumers, Free Consumers and Generator in the composition of the Distributor's Revenue, respectively 0.5%, 0.1% and 0.7%.

Finally, by analyzing the number of users, the market and income per consumption class (Table 13), we notice that Residential has a greater weight for the company (72%, 39% and 42%, respectively). About 45% of the billing is associated to the Commercial, Industrial and Rural rate classes.


Table 13 - Number of Consumers and Revenue by Rate Class

			Market (MWh)		Revenue (BRL
Class	Consumers
					Million)
Residential	435,917	72.1%	1,154,729	39%	608	42%
Industrial	1,832	0.3%	416,479	14%	171	12%
Commercial	39,582	6.5%	634,418	22%	312	22%
Rural	122,249	20.2%	308,486	11%	162	11%
Street Lighting	273	0.0%	131,880	5%	37	3%
Public Power	4,654	0.8%	222,233	8%	109	8%
Public Service	239	0.0%	49,906	2%	23	2%
Other	132	0.0%	5,561	0%	13	1%
TOTAL	604,878	100%	2,923,693	100%	1,435	100%

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Source: ANEEL, Company's 2016 IRT, November 2016.

In view of the above, the main conclusions of Ceron's consumer market by voltage level are: (i) MT represents 0.4% of consumers, 28% of the market and 25% of the company's revenue in 2016; (ii) BT represents 99.6% of consumers, 70% of the market and 73% of the company's revenue in 2016 and, in the analyzed period from 2012 to 2016, showed annual growth rates of 2%, 4% and of 15% for NUC, the market and the revenue, respectively; (iii) the "Low Income" market associated with the BT voltage level had its highest value in the year 2014, and since then, has shown a downward trend.

From the point of view of the rate classes, for the same information, it can be deduced that: (i) the residential class represents 72% of the NUC and 39% of the company market in 2016, with a 3% annual growth in both; and (ii) in the analyzed period, the residential class grew, on average, by 3% p.a. in terms of market and 11% p.a. in revenue, while the Commercial class had a 2% decline p.a. in the market, but experienced an 11% p.a. growth in revenue.

2.4. Operating Indicators

This chapter aims to analyze the main operating indicators of the company, based on its performance in recent years. To do so, sections 2.4.1 and 2.4.2 address service and product quality indicators, respectively, while section 2.4.3 shows a diagnosis on power losses.

2.4.1. Quality of Service Indicators

The distributor assesses the continuity of the service provided to consumers through individual and collective indicators, which are required by ANEEL and arranged in Module 8 of PRODIST. Individual indicators are divided into indicators of Individual Downtime Duration per Consumer Unit or per Connection Point ("DIC"); or Frequency of Individual Downtime per Consumer Unit or Connection Point ("FIC"); Maximum continuous downtime duration per consumer unit or connection point ("DMIC"); and Duration of individual downtime occurred on a critical day per consumer unit or connection point ("DICRI").

The monitoring of the individual indicators is done by means of limits which are also individual, and are defined for monthly, quarterly and annual periods in relation to the DIC and FIC indicators. The DMIC indicator limit is set for the monthly period, while the DICRI indicator limit is set for each critical-day downtime.

When the limits of the individual continuity indicators are breached, the distributor must compensate the consumer financially automatically with a deduction on their invoice within two months after the indicator is determined.

Table 14 shows the evolution of the compensation paid by Ceron over the period (2012-2016), as well as the evolution of the amount of compensations paid. It is worth noting that the amount of compensations and their respective financial value related to the annual period of assessment of the quality of service indicators are not available on ANEEL's website for the year 2016, which is why the 2016 compensation path reflects a decline.

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The assessed indicators show breaches in all years under analysis (except for 2016, for DRPE). For the DRCE indicator, a path of increasing breaches was observed from 2013 onwards, with a slight drop in 2016, with the highest violation rate (about 10 times over the maximum limit) in 2015. The same is true for the DRPE indicator, which has its highest level of breaches verified in 2012 (about 2 times the maximum limit).

Breaches of limits of the individual indicators also generate compensation to be paid by the Distributor. Table 15 shows the amount paid by Ceron with respect to the breach of individual product quality indicators. As shown, the Distributor shows an increase in the amount paid for the breaches, with a slight drop in 2016, as well as in the quantity of compensations paid.


Table 15 - Compensations for Breach of Product Quality Indicators

Item	2012	2013	2014	2015	2016
Quantity (#)	1,322	2,647	3,415	4,288	3,290
Compensation Amounts (BRL)	153,991	364,569	455,988	758,670	660,476
Installment B (BRL)	196,422,575	258,099,141	276,654,044	307,273,784	321,766,851
%Comp./Installment B	0.07%	0.14%	0.16%	0.25%	0.20%
Source: ANEEL website.

As an example, the company's Installment B deterioration for the year 2015 was 0.25%.

2.4.3. Power Losses

Power losses in a distribution system are also taken as an operational indicator of a Distributor. Losses are divided into the categories of Technical Losses ("PT") and Non-Technical Losses ("PNT").

In the calculation of technical losses carried out by ANEEL, losses in the distribution grids in high, medium and low voltage, substations, distribution transformers, in addition to the connection branches and meters are taken into account. The level of technical losses calculated at the time of the company's RTP, as a percentage of the energy injected, is kept constant in all IRTs until the subsequent revision.

The regulatory framework for non-technical losses is also defined at the time of the RTP, but unlike the PTs, a downward trajectory is defined, with a lower level of PNT being recognized at each rate readjustment until it reaches the regulatory target established by the Agency at the end of the cycle.

Graph 13 shows regulatory technical losses, while Graph 14 illustrates the difference between the Real and Regulatory PNTs, elucidating the Distributor's performance over the analyzed period.

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clandestine connection grids, OPEX's contribution is also essential. These actions would have a positive effect for Ceron to add billable consumption and revenue to the concession.

2.5. Energy Purchase and Sale Indicators

In this chapter, the historical evolution of the Required and Contracted Energy of Ceron will be discussed. The entire analysis is based on the current regulation expressed in Sub-module 3.2 - Energy Acquisition Costs - for Rate Regulation Procedures ("PRORET"), which have a normative nature regarding the rate processes of electric power distribution utilities.

Firstly, the conceptual distinction between Required and Contracted Energy must be defined.

Required Energy is the volume of electric power (MWh) acquired in a given reference period to serve consumers or other utilities and distribution licensees, plus regulatory power losses of the distribution system - subdivided into technical ("PT") and non-technical ("PNT")¹⁸.

Contracted Energy is the volume of electric energy (MWh) acquired by Base contracts, Bilateral contracts and Energy Trading in the Regulated Environment Contracts ("CCEAR"), which shall be briefly explained below.

Base Energy encompasses:

Own Generation: energy generated by the distributor to serve its market, according to Law 9,074 of July 7, 1995, with the wording given by Law 10,848 of 2004, which provides that distributors of the National Interconnected System ("SIN") with a market below 500 GWh/year and those that serve Isolated Systems can carry out electric power generation activities, provided that they are fully intended to serve their own markets.
Angra 1 and 2 Quota: energy marketed by the Angra 1 and Angra 2 generating plants and compulsorily acquired by utilities operating in the SIN, as provided in article 11 of Law #12,111 of 2009.
Renewed Concession Quota: amount resulting from the apportionment of the physical energy and power guarantee of plants whose concessions were extended pursuant to Law # 12,783 of 2013. Allocation of quotas to distributors is established according to ANEEL regulations.
Itaipu Binacional Quota: Energy sold by Itaipu Binacional with the electricity distribution utilities acquiring shares of the production that were made available to Brazil, according to specific ANEEL regulation. Only the distributors located in the South and Southeast/Center- West subsystems are the plant's energy quota holders, which compulsorily acquire the electric energy generated by Itaipu. That is, they do not include distributors located in the North and Northeast subsystems.

¹⁸If the real electrical losses (whether technical or non-technical) are considered instead of regulatory losses, the energy of the system is called Injected Energy.

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Bilateral Contracts are freely negotiated between the agents, signed before the enactment of Law #10,848 of 2004, to serve the Interconnected System. Contracts signed to serve the Isolated System before Provisional Measure #466 of July 29, 2009, and those signed by means of a bidding held in the form of a competition or auction, as set forth by Decree #7,246 of July 28, 2010, also correspond to Bilateral Contracts.

Also classified as Bilateral Contracts are the contracting of Distributed Generation energy resulting from vertical divestiture, as provided by Law #10,848 of 2004. In addition, also classified as such are contracts arising from public bidding carried out by distribution agents with own market lower than 500 GWh/year and contracts signed between a utility with market under 500 GWh/year and its current supply agent.

Finally, Energy Trading in the Regulated Environment Contracts ("CCEAR") are those established for the Auctions of: (i) Existing Energy for existing generation projects - defined based on article 19 of Decree #5,163 of 2004; (ii) New Energy for new generation projects - deriving from auctions defined based on article 19 of Decree #5,163 of 2004 and (iii) Alternative Energy Sources -arising from auctions defined based on article 19 of Decree #5,163 of 2004.

After explaining the concepts, the evolution of the Required Energy (MWh) and Contracted Energy (MWh) for the years 2012 to 2016 of distributor Ceron is shown on Table 16 and Table 17.


Table 16 - Results of Regulated Required Energy (MWh) from 2012 to 2016.

	2012	2013	2014	2015	2016

Required Energy (Provision +
	3,385,524	3,466,037	3,706,753	3,642,317	3,545,813
Supply + Losses)
Provision + Supply	2,633,594	2,778,835	3,001,913	2,966,892	2,900,694
Provision	2,633,594	2,778,835	3,001,913	2,966,892	2,900,694
Supply (TE Market)	0	0	0	0	0
Regulatory Losses	751,930	687,202	704,840	675,426	645,119
Non-Technical Loss	247,985	241,129	226,868	202,388	171,509
Technical Loss	424,920	378,889	409,647	401,670	388,424
Basic Grid Loss on Dist.	79,025	12,256	11,953	12,072	13,783
Basic Grid Loss on Captive market	0	54,929	56,372	59,295	71,402


Table 17 - Results of Contracted Energy (MWh) from 2012 to 2016.

	2012	2013	2014	2015	2016

Contracted Energy (Base + Bilateral +	3,385,525	4,130,537	4,240,008	4,649,359	5,188,014
CCEAR)
Base Energy	1,172,260	424,475	434,263	602,688	739,097
Own Generation	15,458	18,186	18,186	18,186	18,186
Angra I/Angra II Quota	0	116,984	116,984	116,825	114,099
Quotas Law #12783/2013	0	220,524	228,284	394,059	532,413
Itaipu (deducting losses)	0		0	0	0

PROINFA	63,963	68,781	70,809	73,618	74,398
NORTE II AGREEMENT	1,092,839	0	0	0	0
Bilateral	1,138,691	3,223,768	3,189,604	3,192,699	3,530,252

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2.6. Asset Conditions

Between 3/27/2017 and 3/31/2017, a field visit was carried out at Ceron's premises, aiming at the diagnosis and evaluation of the technical and physical conditions of the utility's assets, in particular the main electrical energy distribution equipment and infrastructure, identifying its status, critical points at distribution grids by voltage level, as well as the description and evaluation of services.

The first day of the visit was dedicated to obtaining information from the utility's technical team to define assets to be observed and the construction of the technical-operational situation diagnosis.

The field visit began on the second day, to the municipality of Cacoal, 480 km from Porto Velho, with the inspection of part of the Ji-Paraná/Cacoal transmission line (138 kV) and sections of feeder circuit 03, the most critical which serves the rural area.

On the third day, a visit was made to the Morumbi substation, which was connected the Móvel SE, followed by the Rolim Moura SE, Brasilândia SE, São Miguel SE and the Novo Horizonte Isolated System, their respective MT/BT grids and LTs in some sections.

On the fourth day, returning towards Porto Velho, we visited the Itapuã SE and the isolated Triunfo system, in which we observed the Triunfo SE from the external area, in its final work phase, and Entroncamento Triunfo, which awaits energizing.

On the fifth day, the substations of Porto Velho (owned by Eletronorte), Tiradentes and Areal were visited.

The State of Rondônia is served by the radial transmission system of the 230-kV triple circuit line, 690 km long, between the Vilhena locality in the south of the state (connected to the SIN via Jauru at MT) and to the 230/69 kV, 300 MVA Porto Velho SE. It also has a double circuit connection, 370 km in length, in the stretch between the Porto Velho SE and the border with Acre, with final destination in Rio Branco, Acre.

Along the State, there are other six border points with the basic grid, two of which are at 230/138 kV and 220 MVA (Pimenta Bueno and Abunã SEs), three in 230/69 kV and 270 MVA (Porto Velho, Ariquemes and Vilhena SEs) and one in 230/138/69 kV - 320 MVA (Ji-Paraná SE).

paragraph 10 of article 50 of Resolution #453 of 2011 does not cover all the causes of overcontracting that may be recognized as involuntary, requiring ANEEL to analyze exceptional cases presented by distributors. In such circumstances, as well as in the migration of consumers to ACL, each distributor should have the opportunity to file an involuntary overcontracting recognition petition to ANEEL by proving maximum efforts and detailing its particular case."

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A planning and study are being considered at the ONS for a bidding for the expansion of transmission by EPE of a new supply point from the Coletora SE (Eletronorte), and an interconnection with the Centro SE, removing load from the Porto Velho SE.

Studies coordinated by EPE indicate the implementation of a 230/138 kV, 16.7 MVA single-phase transformer bank in the 230/138/69 kV Jaru substation, for interconnection to the Machadinho d'Oeste sub-region interconnected system.

2.7.	Critical points observed during the field visit and challenges for new utilities
	Below are a series of observations from the field visit, which are related to the PIQ.
2.7.1.	High-voltage distribution system
	Eletrobras Distribuição Rondônia's High Voltage Distribution System derives from seven points

of interconnection throughout the state.

The sections of the 138 kV and 69 kV lines were found to be in good condition. Few stretches accompany roadsides. However, easement strips are free from interferences and without close afforestation.

In the urban area next to the Areal SE we observed a point of invasion of the strip with construction work, which should require regularization actions from the new utility.

Of the 54 substations, 20 are automated and controlled by the COI. No technical reserve of 138/13.8 kV power transformers was observed. The average age of power transformers of the substations visited is 10.4 years, and 8 years for circuit breakers.

Automation and remote-control items were incorporated into the improvements item from the PIQ investment plan, as presented in this report.

Regarding transformer load, according to information from Ceron's operations center, the substation having values close to the limit is the Ji Paraná I SE (information obtained during visits, since there was no access to load reports).

As critical points, it was observed that the 69 kV Ji Paraná/Ouro Preto LT has its conductor worn by annealing, which causes frequent downtimes. The construction of a second circuit in progress, which is already identified in the PIQ, will reflect positively in the DEC of the Ouro Preto set.

The Rolim de Moura SE, through one of its 13.8 kV feeders, supplies power to the 13.8/34.5 kV (step-up) power transformer. Expansion through a new 69 kV to 34.5 kV transformer, with on-load switching, would free the load of the 69/13.8 kV transformers from critical load situations, short-circuit levels, and voltage regulation.

An alternative scenario was included in the PIQ, the expansion of the Rolim de Moura SE, anticipating its execution from 2025 to 2023.

The substation maintenance team is reduced and outsourced, working more on corrective maintenance, rather than preventive maintenance.

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2.7.2. Medium-voltage distribution system, grids and substations

The utility's medium voltage grid is 52,870.74 km long, with stretches of compact grid observed only in urban areas, and it does not feature recloser automation. With extensive branches, an expressive part of which being in single-phase grids, they cause imbalance between phases. In Porto Velho alone, there is a project for automating 85 reclosers.

During the visit, we were informed of the need to build an express distribution line from the Rolim Moura SE to the Santa Luzia SE at 34.5 kV thus avoiding the downtime caused by branches and client transformers installed along the current distribution line. The project, already included under the PIQ expansion item, can positively impact the performance of the Rolim Moura set's indicators.

As reported in 2.1.5 - Climate Characterization, there is a high incidence of atmospheric discharges in the State, one of the main causes of downtime. A project for improvement of the protection system is covered under item "MT grid improvements" of the PIQ.

The practice of "self-repair" of circuits is common among rural consumers, posing a safety risk and damaging the distributor's system, which can lead to a drop in supply in a large number of consumer units in the event of occurrences in the grid. Therefore, implementation of a fuse revision plan is recommended.

The digitalization of the VHF communication system, a need identified in the critical points of section 2.5.4 also increasing the number of repeaters, according to ANATEL's decision, would bring a significant improvement to the operation.

Automation and remote-control items were incorporated into the improvements item from the PIQ investment plan, as presented in this report. The communication system is planned for 2017.

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2.7.3. BT Distribution System

The low voltage grids are leveled and, for the most part, made up of bare cables. Few segments of multiplexed cables were observed in the urban area.

3. Five-Year Investment Plan ("PIQ")

The objective of the PIQ is to present, based on technical and economic evaluations, a five-year investment plan - 2018-2022 horizon - for Ceron's electric energy distribution concession area, with reference to the projects planned as necessary in the concession area, thus ensuring expansion of the grid interconnected to the National Interconnected System ("SIN"), meeting the demand for new connections in the scope of the vegetative growth and the Programa Luz para Todos ("PLpT") program, improvement of the performance indicators of service continuity, voltage levels and electrical losses, as well as adjustments and implementations of computerized systems for support in commercial management and distribution.

The following summarizes the main points of the adopted methodology, the contracted investments in progress and the summary of the consolidated amounts of projected annual investments.

In order to verify the investment needs, the information provided in the Data Room by Ceron was used, namely: "Electrical System Expansion Plan (2017-2026 horizon)", "Distribution Development Plan ("PDD") for the year 2017", "Results Plan for the Improvement of Distribution Services, 2015" and "Plan for Temporary Rendering of Electricity Distribution Service, 2017". In addition to this information, we used information obtained by the company's planning area, obtained through face-to-face meetings and conference call.

Also considered were investments in execution in 2017, as shown in Table 18²¹.

Table 18 - Investments in progress in the year 2017 by Type of Project


Type of Project	Total
AT Expansion	BRL 14,279,056
MT Expansion*	BRL 68,209,699
Improvement	BRL 14,250,000
Renewal	BRL 24,200,000
"Luz para Todos"	BRL 48,360,000
Total	BRL 169,298,755

The works contained in the PIQ were defined based on the information provided and analysis of the investments in progress. Firstly, we drafted a Base Scenario, starting with the 2017 PDD by setting, for the years with no initial investment forecast, the following assumptions by type of investment and voltage level:

²¹The amounts set forth in this section relate to projects in progress or which are in the process of signing a contract. That is, the figures shown are estimated: therefore, they may change during the year.

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"AT Expansion": application of a reduction factor on the 2017 was considered, resulting from the comparison of the company's costs to the average benchmark of other comparable distributors, based on the Eletrobras group price bank. For these projects, we adopted a 1.24% price reduction level;
"MT Expansion": the amounts presented in the 2017 PDD were considered, since they were already established by considering prices practiced in the market.
"Improvement": as there was no investment in the 2017 PDD projected for the 2018-2022 five- year period, the amounts indicated in the 2017-2026 Ten-Year Expansion Plan prepared for Ceron were considered, with equipment and material prices as quoted on the market, without need for adjustments.
"Renewal": as there were no investments projected for the 2018-2022 five-year period, the amount corresponding to the portion related to the "Regulatory Reintegration Quota" ("QRR") established by ANEEL for Ceron in the last rate revision was considered, corrected by the IPCA until 2017.
"PLpT": investments already incorporated in the 2017 PDD were considered, with equipment and material prices as quoted in the market, without need for adjustments, which are necessary for the accomplishment of the goals of conventional connections and through photovoltaic systems within the program that ends in the year 2018, according to Decree #8,387 of 12/30/2014.
In addition to what was obtained via the PDD or Ten-Year Plan, visits to the utility identified

demands, as follows:

"Computerized Systems": implementation of a new Commercial System, ERP System and update to the Distribution Management System ("SGD") was considered.
"Other Investments": investments required for remote control of SEs, telemetry in MT/LT and automation of reclosers of distribution networks were considered, as mentioned in the Notice of Visit to Ceron from 3/29 to 3/31/17.
This plan resulted in the Base Scenario set forth in Table 19, which requires BRL 1.069 billion

in investments within the next five (5) years, with a noticeable need for the year 2018, which concentrates BRL 579.7 million²².

²²The financial amounts presented in this section are in real currency at April 2017 prices.

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Table 19 - Base Scenario: Five-Year Investment Projection

Type of Projects/
	2018	2019	2020	2021	2022	Total
Systems
AT Expansion	BRL 200,512,486	BRL 88,774,958	BRL 17,816,766	BRL 4,429,051	BRL 11,074,813	BRL 322,608,074
MT Expansion	BRL 67,344,148	BRL 60,690,974	BRL 38,018,864	BRL 44,902,845	BRL 10,583,335	BRL 221,540,166
Improvement	BRL 46,291,440	BRL 20,708,630	BRL 16,021,360	BRL 17,160,370	BRL 25,045,450	BRL 125,227,250
Renewal	BRL 33,552,002	BRL 33,552,002	BRL 33,552,002	BRL 33,552,002	BRL 33,552,002	BRL 167,760,010
"Luz para Todos" BRL 201,000,000		-	-	-	-	BRL 201,000,000
Commercial
System	BRL 20,000,000	-	-	-	-	BRL 20,000,000
ERP System	BRL 10,000,000	-	-	-	-	BRL 10,000,000
SGD System
Correction	BRL 1,000,000	-	-	-	-	BRL 1,000,000
Total	BRL 579,700,076	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 80,255,600	BRL 1,069,135,500
Total
Own	BRL 147,965,310	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 80,255,600	BRL 637,400,734
Resources

The high volume of investments allocated in 2018 (around 54% of the five-year period) is related to 28 projects to guarantee the interconnection of isolated systems (BRL 251 bn) and compliance with the PLPT (BRL 201 bn), since the program ends in the year 2018, according to Decree #8,387 of 12/30/2014.

Of the total amount, those coming from Own Resources were highlighted, as certain investments are made with resources from sectoral funds: there are subsidies of 90% of investments related to the works for the Programa Luz Para Todos ("PLpT") program and 100% related to the subrogation of benefits of the Fuel Consumption Account ("CCC").

The Alternative Scenario considers the anticipation of SE constructions/expansions and construction of LDs from 2023-2026 to the year 2022 to the amount of BRL 30.9 million, in order to provide an increase in assets in the Regulatory Remuneration Base ("BRR") in the RTP designed for the year 2023²³.

Table 20 - SEs with anticipated investments for the drafting of the Five-Year Plan


Project Description	Year 2017 PDD	Investment
34.5 kV JI-PARANÁ III SE/RONDOMINAS SE LD (45 km)		BRL 2,475,000
	2023
34.5 kV/13.8 kV - 1x5/6.25 MVA PRIMAVERA DE RONDÔNIA SE		BRL 1,868,894
34.5 kV/13.8 kV - 1x5/6.25 MVA RIO CRESPO SE		BRL 3,392,515
34.5 kV ARIQUEMES I SE/RIO CRESPO SE LD (42 km)	2024	BRL 2,310,000
34.5 kV/13.8 kV - 1x5/6.25 MVA CAUCALÂNDIA SE		BRL 3,392,515
138/34.5 kV – 1x10/12.5 MVA ROLIM DE MOURA SE (Expansion)		BRL 3,161,458
	2025

²³In this case, it was assumed that the company will have its privatization process finalized in 2018, having, therefore, an RTP in the year 2023.

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34.5 kV/13.8 kV - 1x5/6.25 MVA JARDINÓPLOIS SE		BRL 3,392,515
Project Description	Year 2017 PDD	Investment
138/13.8 kV – 1x10/12.5 MVA NOVA MAMORÉ SE	2026	BRL 10,934,819
Total Investments		BRL 30,927,716

Table 21 shows the projection of the Five-Year Plan investment figures by type of project and voltage level and computerized systems for the Alternative Scenario.


Table 21 - Alternatives Scenario: Five-Year Investment Projection

Type of
Projects/	2018	2019	2020	2021	2022	Total
Systems
AT Expansion	BRL 200,512,486	BRL 88,774,958	BRL 17,816,766	BRL 4,429,051	BRL 25,171,090	BRL 336,704,351
MT Expansion	BRL 67,344,148	BRL 60,690,974	BRL 38,018,864	BRL 44,902,845	BRL 27,414,774	BRL 238,371,605
Improvement	BRL 46,291,440	BRL 20,708,630	BRL 16,021,360	BRL 17,160,370	BRL 25,045,450	BRL 125,227,250
Renewal	BRL 33,552,002	BRL 33,552,002	BRL 33,552,002	BRL 33,552,002	BRL 33,552,002	BRL 167,760,010
"Luz para Todos"	BRL 201,000,000	-	-	-	-	BRL 201,000,000
Commercial
System	BRL 20,000,000	-	-	-	-	BRL 20,000,000
ERP System	BRL 10,000,000	-	-	-	-	BRL 10,000,000
SGD System
Correction	BRL 1,000,000	-	-	-	-	BRL 1,000,000
Total	BRL 579,700,076	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 111,183,316	BRL 1,100,063,216
Total
Own	BRL 147,965,310	BRL 203,726,564	BRL 105,408,992	BRL 100,044,268	BRL 111,183,316	BRL 668,328,450
Resources

It should be noted that the Base Scenario shall be used for the Company's economic-financial evaluation.

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APPENDIX A - Socioeconomic Characterization of the Concession Area

In order to better characterize the area of activity of the Distributor, socioeconomic information was collected and grouped into four data sets: (a) Demographic, Education and Employment; (b) Access to Services; (c) Income and (d) Violence. In the following items, comparative analysis was performed for each information collected from the company in relation to the data observed in the North and Northeast regions and Brazil's average. This comparison allows to evaluate the degree of similarity/divergence of the socioeconomic indicators of the company in relation to the regions where the companies of the Eletrobras group operate, as well as to compare with the national average.

a)	Demographic Information, Level of Education and Unemployment Rate
	Table 22 shows, in order, the number of municipalities, area, population, number of households,

percentage of population living in rural areas, percentage of illiterate population and unemployment rate in the Distributor's area, as well as average data for Brazil and the North and Northeast Regions.


Table 22 - Demographic Information, Level of Education and Unemployment Rates

		Area	Population	Density	#	%
Region	#				Households	Rural	% Illiterate	Unemployment
	Municipalities	(km²)	(Thousand)	(Inhabitants/km²)	(thousand)	Popul.	Popul.	Rate
RONDÔNIA	52	238,526	1,773	7.46	591	24%	9%	5%
BRAZIL	5,567	8,497,584	204,860	24.11	68,037	15%	9%	8%
NORTH	449	3,848,855	17,525	4.55	5,093	25%	11%	9%
NORTHEAST	1,794	1,554,291	56,639	36.44	17,836	27%	17%	9%

Sources: Data on the population were taken from the 2015 PNAD. Number of municipalities and areas were obtained from INPE.

Unemployment rate was obtained at IPEA/PNAD for the year 2014.

Rondônia is the state with the highest population density in the Northern Region (7.46 inhabitants/km²), with the capital (Porto Velho) being the most populous municipality in the state and the seventh most populous in the Northern Region. Its population is mainly concentrated in urban centers (76% of the population), but has a considerable percentage of inhabitants in rural areas (24%).

b)	Access to services
	A table on information regarding access to services shows (for Ceron, Brazil and

North and Northeast Region average data) the percentages of households (i) without garbage collection; (ii) without garbage collection for urban areas; (iii) without water supply through networks; (iv) without water supply for urban areas; (v) without sanitary sewage by networks or septic tank; (vi) without sanitary sewage by networks or septic tank for urban areas; and (vi) without electric lighting located in rural areas.

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Table 23 - Service Access Information



			% HH	% Urb. HH	% HH	% Urb. HH
	% HH	% Urb. HH					% Rural HH
			without	without	without	without
	without	without					without
Region			Water	Water	Sewage	Sewage
	Garbage	Garbage					electrical
			Network	Network	Networks/Septic Networks/Septic
	Collection	Collection					lighting
			Supply	Supply	Tank	Tank

RONDÔNIA	21%	2%	52%	41%	54%	45%	1%


BRAZIL	10%	1%	15%	6%	19%	12%	2%


NORTH	21%	3%	40%	28%	38%	29%	7%


NORTHEAST	21%	3%	20%	7%	35%	23%	1%

Source: 2015 PNAD.

In Rondônia, 21% of the households do not have garbage collection, while 52% do not have water supply through networks and 54% do not have access to a proper sewage network. Percentages of urban households without basic infrastructure services are high and above the regional and national averages (45% and 41%, respectively, for the state).

c)	Income
	Income information show (i) the percentage of households with income of up to 2 Minimum

Wages ("S.M."); (ii) the percentage of people living in households with per capita income below the poverty line²⁴; (iii) average household income per capita and (v) GDP (Gross Domestic Product) per capita.


Table 24 - Income Information

	% HH w/	% Pop. Below	Average	GDP per capita
Region	Income Up to 2	Poverty	Residential	(BRL)
	SM	Line	Income per capita
			(BRL)
RONDÔNIA	43%	13%	950.16	17,991
BRAZIL	39%	13%	1,152.24	26,446
NORTH	51%	22%	782.76	17,213
NORTHEAST	58%	20%	730.24	12,955

Sources: Households with income up to 2 S.M. ’ 2015 PNAD. % Pop. Below Poverty Line and Average Household Income per capita ’ 2014 IPEA/PNAD; GDP per capita ’ 2013 Datasus/IBGE.

As shown, the state shows a percentage of population below the poverty line higher than the comparative averages, despite having a per capita household income and GDP per capita higher than the North and Northeast regional averages.

²⁴Equivalent to twice the extreme poverty line. The Poverty Line is based on an estimate of the value of a food basket having the minimum calories needed to adequately supply a person, based on World Health Organization (WHO) recommendations.

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d) Violence

Table 25 - Information on Violence shows the number of deaths per aggression for every 100 thousand inhabitants registered in the year 2014. As shown, the state of Rondônia is slightly above the national average, but lower than the North and Northeast regional averages.

Table 25 - Information on Violence

Region

Deaths by
Aggression


RONDÔNIA	32.6
BRAZIL	29.4
NORTH	34.3
NORTHEAST	41.6

Source: 2014 Datasus/IBGE.

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APPENDIX D- Norte II Agreement

The facts set out in this Appendix are organized chronologically.

1. On 5/12/2000, Eletronorte and Termonorte entered into an agreement to purchase and sell electricity from the Termonorte II thermoelectric power plant. On 12/22/2008, Eletronorte submitted for approval to ANEEL an assignment agreement, under which its contractual position as purchaser in the aforementioned agreement is assigned to Ceron.

2. Based on Technical Notes #233/2009-SFF/ANEEL and 12/2009- SEM/ANEEL, ANEEL's Financial Inspection Superintendency issued Order #1,900, of 5/25/2009, in which it did not consent to the assignment of the agreement for the purchase of electric power of thermal origin to Ceron under the conditions presented, which was originally executed between Eletronorte and Termonorte (seller).

3. Against this Order, Eletronorte filed an appeal.

4. Based on Technical Note #72/2009-SEM/ANEEL and on the argument that "there is no discernible benefit to the Distributor in terms of the modality of rate, and neither does this contracting comply with the mandatory system for energy acquisition by Distributors within the scope of the SIN, in the manner in which it was submitted," the SFF maintained the decision embodied in SFF Order #1,900/2009, according to Order #2,719 of 7/23/2009.

5. On 10/15/2009, Eletronorte forwarded a copy of the First Addendum to the Assignment of the Termonorte II Agreement to Ceron, which would be the result of a meeting held on 10/1/2009 with the Executive Secretary of the MME, ANEEL representatives and agents involved in the transfer in question.

6. At the 34^thOrdinary Public Meeting of 2010, ANEEL's Board partially approved the appeal filed by Eletronorte to maintain the refused approval of the assignment of the agreement for the purchase of electric energy from the Termonorte II plant; to declare that, in order to approve the assignment of the agreement for the purchase of electric energy from Termonorte II, it is necessary that the respective instrument provides that, as from 2012, the annual cost of energy acquisition by Ceron, considered as the sum of the energy prices set in the agreement with the average PLD to which the distributor was exposed throughout the year due to the aforementioned agreement, may not exceed the annual cost corresponding to the acquisition of the electric energy sold in the 5^thNew Energy Auction. This decision was substantiated by Order #2,673 of 9/8/2010. According to the vote of ANEEL's rapporteur who provided the foundations of said Order, prior to the interconnection of the Acre-Rondônia system, there was no obligation for Ceron to acquire energy in auctions, but there was always an obligation to purchase energy at the lowest effective cost, as determined in its Concession Agreement. In order to assess compliance with the obligation to acquire at the lowest effective cost, it was stipulated that "contracting alternatives that cumulatively fulfill the following characteristics should be used as parameters: a. Those that have been discarded by the distributor; and

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b. Those that have a duration and volume compatible with that of the contracting made to their detriment". To that end, the A-5 Auction was adopted as a parameter, which was held on 10/16/2007, with supply commencing on 1/1/2012, a contracting alternative that was cumulatively discarded by Ceron and proved to be compatible in terms of duration and volume of energy traded with the assignments in question. Although the interconnection of the Acre-Rondônia system was expected for December 2008 since 4/20/2007, Ceron discarded its participation in the 2007 A-5 Auction and, in Dec/2008, signed the assignment agreement related to energy from the Termonorte I and II plants. Thus, by failing to acquire energy in said auction and electing to acquire it through the assignments in question, Ceron would have incurred an acquisition cost higher than that of the Auction.

Therefore, based on the concession agreement, an attempt was made to create conditions for the purchase of energy at the lowest cost for consumers and to pass lower costs on to the CCC. Accordingly, in order to achieve approval of the assignment in question, Order #2,673/2010 determined that "the annual cost of acquisition of energy by Ceron, considered as the sum of energy prices set in the agreement with the average PLD to which the distributor was exposed (...), may not exceed the annual cost corresponding to the acquisition of energy in the 5^thNew Energy Auction." Thus, the transfer to consumers of the cost of this contracting would be limited to the value of the annual cost corresponding to the acquisition of the energy marketed in the 5^thNew Energy Auction held in Oct/2007.

7. On 10/26/2010, Eletrobras, Eletronorte and Ceron filed a request for annulment of Order 2,673/2010.

8. On 7/26/2011, in the 2011 27^thOrdinary Public Meeting, the Executive Board dismissed the annulment request, pursuant to Order #3,067/2011.

9. On 12/20/2012, Eletronorte submitted the 2^ndAmendment to the Assignment of the Electric Energy Supply Agreement to ANEEL for approval. The ANEEL Market Studies Superintendency ("SEM"), through Memorandum #240/2012-SEM/ANEEL, analyzed the document submitted, which did not comply with the premises of Order #2,673/2010.

10. Ceron and Eletronorte have argued in many correspondences and meetings that such a condition would impose enormous uncertainty and hence volatility in energy acquisition costs, which would vary strongly with the PLD, while the purpose of a long-term agreement is the exact opposite.

11. On 1/15/2013, the proceeding was again filed at ANEEL and after several interactions between the parties and ANEEL, on 7/1/2013, Eletronorte submitted to ANEEL for approval a new proposal for a Second Amendment to the Assignment of the Supply Agreement in question.

12. On 7/9/2013, by means of order 2180/2013 and considering what is stated in Case #48500.000247/2009-68, ANEEL approved the Second Amendment to the Assignment of Electric Energy Supply Agreement, from Centrais Elétricas do Norte do Brasil S.A. (Eletronorte) to Centrais Elétricas de Rondônia S.A. (Ceron), related to the Termonorte II Thermoelectric Plant, under the following conditions: a. Ceron shall monthly pay Termo Norte Energia Ltda. the amount established in the agreement originally entered into between the latter and Eletronorte;

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b.	Ceron shall be responsible towards CCEE for the results of the accounting, including losses of the basic grid, for exposures to the market, including reduction of Physical Guarantee which it is responsible for due to financial settlement and penalties;
c.	The Termonorte II UTE shall be responsible for its physical guarantee, according to the availability clause set forth in the agreement originally executed between the latter and Eletronorte;
d.	The rate pass-through to Ceron's customers shall be limited to the average cost of power and energy sold in the Regulated Contracting Environment ("ACR"), as defined by the SRE, observing subsection "e" below;
e.	The distributor's shareholder shall cover the difference between the fixed revenue of the agreement (value of the ensured energy plus the value of the supplementary energy) in addition to the Transmission System Use Rate ("TUST") and the fixed revenue to which it would have been exposed had it participated in Auction A-5 of 2007, calculated as the difference between the value related to the price of the 5^thnew energy auction of October 2007 and the average of the minimum values between the CVU of the plant used in the drafting of the Electroenergetic Monthly Operation Program ("PMO") for the month of November 2009, and the average monthly PLD of the Southeast submarket, recorded between January 2002 and October 2007, both adjusted by the IGP-DI;
f.	The difference shall be covered by the Fossil Fuel Consumption Account ("CCC");
g.	Such transfer limitations shall be applied as of January 2012; and
h.	The table contained in Paragraph Five of Clause Two of the agreement shall be excluded or corrected in order to portray the conditions imposed above. Consequently, it determined that the CCEE would carry out a reassessment, from the date of the interconnection of the Acre-Rondônia subsystem to the SIN, in order to consider the registration of the contracted amounts from the Termonorte II UTE, previously in the name of Eletronorte, to Ceron.

13. On 11/27/2013, the CCEE (CT - CCEE Letter -3015/2013) proposed a correction to the aforementioned decision of ANEEL's Board to reconsider the reassessment determination, arising from the registration of the Second Amendment to the Assignment of the Electric Energy Supply Agreement, from Centrais Elétricas do Norte do Brasil S.A. (Eletronorte) to Centrais Elétricas de Rondônia S.A. (Ceron), related to the Termonorte II Thermoelectric Plant, for the period from October to July 2013. This proposal was made at the request of the signatory parties, which propose, instead of the reassessment, that the financial correction be allowed (between Ceron and ELETRONORTE), which would avoid the need to provide resources for both. Accordingly, the CCEE required authorization to carry out, in a future accounting, a financial correction, calculated through an ancillary calculation mechanism ("MAC"), in order to transfer from ELETRONORTE to Ceron the charges for system services owed due to energy security or violation of CAR, paid in December 2012, January 2013 and April to July 2013. Accordingly, CCEE shall assess, through MAC, the energy penalties for Ceron and TERMONORTE, considering the registration of the agreement approved by ANEEL as effected in the SCI.

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14. On 12/2/2013, the SEM (Memorandum #358/2013-SEM/ANEEL) presented its understanding on CCEE's proposal and forwarded the case for my analysis, since I was the rapporteur of the case in question, recommending fulfillment of the aforementioned CCEE proposals, and forwarded the case for decision by the Board, which decided through Order #4,191, published in the DOU on December 18, 2013: a. Change the content of item (ii) of Order #2,180 of 7.9.2013, to the following: (ii) authorize CCEE to carry out, in a future accounting to be carried out until February 2014, a financial correction calculated through an ancillary calculation mechanism ("MAC"), in order to transfer from ELETRONORTE to Ceron the charges for system services paid due to energy security or violation of CAR, paid in December 2012, January 2013, and April to July 2013; b. Determine that CCEE reassess via MAC the energy penalties for Ceron and TERMONORTE, considering the registration of the agreement approved by ANEEL as effected in the Accounting and Settlement System.

15. According to ANEEL PROCEEDING: 48500.002937/2014-19, the 2014 Annual Rate Adjustment of Centrais Elétricas de Rondônia S.A. (Ceron), effective as of November 30, 2014, incorporated the provisions of Order 2,180/13 and the supply agreement with Termonorte II was incorporated into Ceron's portfolio of contracts with retroactive effects from interconnection to the SIN

(invoices as of November 2009), according to the quote from the conductor vote in the aforementioned order, which provided, among the conditions for approval, that the distributor's shareholder should bear a restraint. Due to these effects of Order 2,180/2013, it was necessary to recalculate the CVA energy considered in the rate processes of 2010, 2011, 2012 and 2013, according to what was already established in the vote of the rapporteur who approved the utility's rate revision in 2013. Therefore, the total amount of one hundred and seven million, five hundred and fifty-three thousand Reais and seventy-four cents (BRL 107,553,000.74) is being considered in this rate adjustment, already updated by the SELIC. The retroactive effects of Order 2,180/13 required not only recalculation of the CVA energy, but also of overcontracting in calendar years 2009 (as of November), 2010, 2011 and 2012. The aforementioned Order authorized CCEE to carry out the financial correction through an ancillary calculation mechanism ("MAC") in a future accounting. Such recalculations were made according to REN #255/2007, with the wording as modified by the REN #305/2008 and #609/2014. According to Article 22 of Decree #7,246, the cost of overcontracting in the three years following the respective interconnection (Oct/2009 in the case of Ceron) shall be considered in the total cost of electric generation in the Isolated Systems, and compensated via the Energy Development Account ("CDE"). Thus, the full amount of this recalculation corresponding to the period from Nov/2009 to Dec/2012, totaling one hundred and thirty million, two hundred and ninety-four thousand, four hundred and forty-five reais and forty-seven cents (BRL 130,294,445.47), will not be passed on to the rate, but rather considered in the total cost of generating electric power in the Isolated Systems, as foreseen in article 22 of Decree #7,246 of July 28, 2010.

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16.

According to Ceron's "2016 MANAGEMENT REPORT AND FINANCIAL STATEMENTS", related to the financing of the Eletronorte/Termonorte II bilateral agreement, the Company has reclassified in the long term the amount of BRL 1,770,081 (thousand) corresponding to receivables of rights constituted due to the recognition of the agreement with Termonorte II, in accordance with Order #2,180 of July 22, 2013, which transferred the agreement from Eletronorte to the Company. Thus, the costs that exceeded the average ACR for each year were assessed by considering all costs in the Termonorte II operation from November 2009 to August 2015 with energy and power, cost of PLD settlement and cost of transmission involved, and the Company awaits ANEEL approval to begin receiving funds from the CCC fund to pay the corresponding debt installments to Eletronorte.

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National Bank for Economic and Social Development ("BNDES")

Av. República do Chile, 100 Rio de Janeiro/RJ

September 18, 2017 Dear Sirs,

As requested by BNDES and in compliance the with terms and conditions of Electronic Tender AARH No. 51/2016, of OCS Contract No. 28/2017 (the “Contract”) dated February 14, 2017, and the provisions of section 80 of Law No.

13,303/2016, we have prepared this summary containing a presentation of key issues identified by us during the environmental assessment work carried out in Companhia Energética de Rondônia (“CERON”).

The scope of our services was limited to the procedures described in item 4.2.7 of Annex I to the Contract. This summary does not include all the issues identified and presented in the Environmental Assessment Report dated May 5, 2017, and should thus be reviewed together with the remainder of the report for a comprehensive understanding of the issues identified.

Our work involved review of documents made available in databases, interviews with managers in charge of the environmental activities of the company and on-site visits to six substation facilities.

The information used in our work was provided by the company's management and reviewed on the premise that it is true and complete. Except as expressly stated in the scope of our work, this information was not subject to testing or verification.

The work carried out does not constitute an examination performed in accordance with financial statement auditing standards. Due diligence works are unregulated and not subject to specific standards; for this reason, the procedures applied in our work were those determined in the Final Tender Protocol, and PwC is not responsible for any inadequacies of such procedures in achieving the goals determined by BNDES. Other matters could have been detected and reported if PwC had been asked to perform additional procedures.

Yours faithfully,

PricewaterhouseCoopers Corporate Finance & Recovery Ltda. acting as consortium leader

/s./ Rogério Roberto Gollo

/s./ Luciano Jorge Moreira Sampaio Junior

This document is a true copy of the original signed version delivered to BNDES and in the possession of Eletrobras.

Summary of key issues identified

Below is a summary of key issues identified during the environmental assessment work. As such, it does not include all of the issues identified and discussed in the Environmental Assessment Report and should thus be read in conjunction with the rest of the report for a comprehensive understanding of the issues identified.

1 Purpose and limitations of the work

Our work involved review of documents made available in databases, interviews with managers in charge of the environmental activities of the company and on-site visits to three substation facilities.

The purpose of the work was to evaluate key environmental and social issues of CERON in light of the applicable laws and regulations, review how such issues are managed from environmental and social standpoints, and identify potential deficiencies and situations that may result in significant risks and costs to the company.

The following topics were reviewed: solid wastes, PCB/ascarel, noise, atmospheric emissions, wastewaters, water resources, permanent preservation areas, plant suppression, service providers, environmental accidents, environmental liabilities, easement trespassing, conflicts with indigenous populations, engagement practices and interaction with surrounding populations, as well as assessments, fines and consent agreements.

The scope of the work did not include generation of additional data through collection and analysis of soil and water, atmospheric emission and wastewater samples, nor was any evaluation performed for the purpose of checking compliance with laws related to workers' health and safety.

2 Summary of key issues identified:

• Facilities operate without the required environmental operation license and other licenses such as the Fire Brigade Inspection Service Certificate (FBISC) and the IBAMA Federal Technical Registration (IFTR)

Noncompliance with the terms and conditions of operating licenses
Substation noise levels not monitored
Lack of documents such as Solid Waste Management Plans (SWMPs) and Solid Waste Inventories (SWIs)
Incorrect storage of hazardous solid wastes
Unlicensed use of artesian wells (drinkability not monitored also)
Substations lack appropriate containment systems and oil-water separator boxes
Oil stains resulting from transformers lacking appropriate containment basin structures
Facilities have a history of water and soil contamination incidents
Old, pre-1980 transformers in use and untested for PCB/ascarel
No management system in place for easement strips
No enforcement of contractual standards and environmental requirements implemented by distributor in its procurement processes


Eletrobras System Distributor
Privatization PwC	3

Summary of key issues identified

3 Estimate of costs to remedy issues identified

An estimated amount between R$ 16 million and R$ 63 million, approximately, is required in order to remedy and mitigate some of the previously highlighted issues, as shown in the chart below.

Cost estimates do not include the expense with fines incurred by the company due to noncompliance with any applicable laws and regulations. Fines and assessments provided for in the applicable environmental laws and regulations vary substantially in amount; for this reason, the exact amounts of fines are contingent, among other considerations, upon evaluation by the competent environmental authorities. Furthermore, amounts reported do not include the cost of mitigating issues that depend on non-measurable variables at the time of writing, such as disposal of hazardous wastes and disposal of any equipment containing PCBs.

At present, it is not the intention of PwC to state that these figures are accurate and that they reflect the amounts effectively required to implement each of the proposed actions. In any case, the figures presented in this summary serve as a reference in connection with the privatization process.

In addition to the estimated expenditures, resolution alternatives for each identified issue as well as the potential violation or infringement, if any, that the company is subject to under the applicable environmental laws and regulations, were presented. This information is included in the Environmental Assessment Report dated May 5, 2017.


Eletrobras System Distributor Privatization PwC
	4

Annex I - Issue and estimated cost summary chart


				Cost (in R$)*
Issue #	Topic	Issue Identified
			Minimum	Middle	Maximum



		Deficiencies identified in
		the storage of Class I
1	Waste		R$8,086,364	R$20,215,977	R$32,345,590
		(hazardous) solid wastes at
		substations.


		No Solid Waste
		Management Plan
2	Waste		R$5,000	R$10,000	R$15,000
		(SWMP) implemented at
		CERON.


		There is no updated and
		complete Solid Waste
3	Waste		R$5,000	R$10,000	R$15,000
		Inventory implemented at
		CERON.

Eletrobras System Distributor Privatization
PwC

Annex I - Issue and estimated cost summary chart (cont.)


Issue #	Topic	Issue Identified		Cost (in R$)*
			Minimum	Middle	Maximum


		No evidence of any
		specific PCB identification
		test for transformers and
4	PCB/ascarel		R$75,040	R$112,560	R$150,080
		other oil-containing
		equipment in use at
		company facilities.


		Risk of existing PCB and	Not measurable - The cost to dispose of ascarel waste is contingent, among
5	PCB/ascarel	cross-contamination in	other considerations, on the number of affected pieces of equipment, the
		other equipment.	treatment performed, and location of company facilities.




		Lack of noise monitoring
6	Noise	at the substations.	R$207,700	R$207,700	R$207,700

Eletrobras System Distributor Privatization PwC

Annex I - Point summary table and cost estimate (cont.)


Issue #	Topic	Issue Identified		Cost (in R$)*
			Minimum	Middle	Maximum

		Potential water and soil
		contamination resulting from oil-
		contaminated materials currently
		improperly stored at substation
		facilities. Oil leakages in
		transformers of inspected
14	Miscellaneous		R$850,000	R$6,120,000	R$11,390,000
		substation facilities. TPPs
		operating under free lease
		arrangements with IPPs. Old TPP
		facilities with a history of
		contamination of soil and water
		resources.


	Easement	No management and monitoring
15			R$180,000	R$180,000	R$180,000
	Strips	system in place for easement strips

		Lack of a system to address
		enforcement of contractual
	Procurement	standards and environmental
16				N/A
	Processes	requirements implemented by
		distributor in its procurement
		processes.

			R$16,731,217.75	R$38,717,204.75	R$63,924,284.75

*Costs are estimated based on the assumptions detailed in the Environmental Assessment Report dated May 5, 2017.

Eletrobras System Distributor Privatization PwC

National Bank for Economic and Social Development ("BNDES") Av. República do Chile n° 100 Rio de Janeiro - RJ

C/O: Ms. Lidiane Delesderrier Gonçalves — Manager of Agreement OCS 028/2017 May, 2017 Dear Sirs,

The result of our work is detailed in this document "Product 08: CERON Human Resources Evaluation Report ("Report"), dated May 2017.

Our work was developed solely for the purpose of advising the BNDES, as those responsible for executing and monitoring the process of privatization of utility companies by Decree 8.893, in CERON's evaluation, in accordance with the Agreement, and was based on information provided by CERON's management and on the premise that this information is true and complete. This information was not subject to testing or verification, except where expressly stated within the scope of our work.

In case the Report is to be accessed by third parties, it must be made available in full, so that the applicable safeguards and limitations are known.

Regards,

PricewaterhouseCoopers Corporate Finance & Recovery Ltda., as leader of the Consortium


[Signed]		[Signed]
Regério Roberto Gollo		Marcio José Soares Lutterbach

_____________________________________________________________________________________ PwC | Loeser e Portela Advogados | Siglasul 1

This document is a true copy of the original signed version delivered to BNDES and in the possession of Eletrobras.

1. Executive Summary

This report consists of the first part of the Human Resources Evaluation for Distributor Ceron, within the scope of the project "Eletrobras System Distributors' Privatization Process Evaluation" contracted by BNDES, through "AARH Electronic Trading Floor # 51/2016" invitation to bid with the Mais Energia B Consortium composed of PwC (consortium leader), Siglasul and Loeser e Portela Advogados.

The documents prepared by Ceron between February and April 2017 were used to prepare the following analysis and indicators.

In this report, we show information related to Ceron's staff considering the cut-off date of December 31, 2016. Some assumptions were made for the generation and analysis of indicators with respect to staff:

Considered:

Employees

Board members Commissioned positions Employees on secondment

Not considered:

Interns

Young Apprentices Pensioners Retirees on disability

Employees laid off through PID Employees laid off in December/2016 Deceased in December 2016 Transposed to the Federal government's staff Assigned Employees

PwC's 2016 Benchmarking was used to compare the indicators. Indicators were compared with data from the Electrical Sector Panel composed of 18 companies in the sector. If data from this Panel were not available, indicators were compared with the General Market.

When evaluating the generated indicators, we verified:

• Considering the base date of December 31, 2016, the Distributor's workforce has 702 active employees. This group is composed mainly of men (80%), with an average of 46 years of age.

• Employees spent an average of 18 years in the company, and approximately 50% spent over 20 years in the company.

• Employees are distributed into four broad positions: middle-school level professional (1%), high-school level operational professional (33%), high-school level support professional (51%) and higher-education level professional (15%). Professionals with training under and beyond what is required in the public competition exist. The most common level is high-school degree (49%), followed by 36% of employees with a higher-education degree.

• The average turnover of the last 5 years was 3.10%, which is lower than that of the electric power market (approximately 7.00%). This indicator was impacted by layoffs resulting from the voluntary resignation programs in the years of 2013 and 2014 and by the hiring resulting from the process of insourcing of activities in 2015. The percentage of hours not worked due to leave in 2016 for Ceron was 2.73%, in line with the industry average (2.51%). Regarding the percentage of performed

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overtime, we observe that this indicator is better than the average of the general market: while in the last 5 years the Distributor has shown an average of 4.7%, the general market shows 5.3%.

• The Distributor's leadership is comprised of 41% professionals occupying higher-education level positions and 50% possessing up to 10 years in the company. The breadth of command (indicates number of employees per leader) is 6.8. This index is lower than that what is observed among electric power companies (13), representing an opportunity to optimize organizational structures.

• With regard to professional training, there was investment of approximately 22 hours/year and BRL 456.93 (average) per employee for dedication to training in 2016.

• Regarding personnel cost, we observed that the fixed remuneration of Ceron's employees contributes to the weight of the Total Cost, representing 65%. The total cost per capita for the Distributor is 20% lower than that shown by the electric power market.

• Regarding people management practices, the Distributor operates in an integrated manner with the other companies of the Eletrobras System. Consistent policies and practices are in place for performance appraisal, training, and compensation.

The benefits practiced by Ceron are, in their totality, established in a collective agreement. It should be noted that the package offered is superior to that usually practiced in the private market and there is no differentiation between the benefits offered to managers and employees of the administration and operation.

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fundamental management guidelines, as well as the Company's upper management, by monitoring compliance with the guidelines established by it, monitoring enforcement of approved programs and checking the obtained results.

Supervisory Board: Collegial body responsible for overseeing the acts of company managers and verifying compliance with the Company's legal and statutory duties, examining its financial statements, as well as other roles set forth in specific legislation.

Executive Board: Ensuring regular functioning of the Company and, to this end, vested with powers of administration and management of corporate business, is able to deliberate on any matters related to the corporate purpose, except those that, due to their nature or under the Bylaws, are attributed to the General Meeting or the Board of Directors.

Upper management bodies: office of the CEO and boards

Bodies responsible for the planning, coordination and control of their specific activities as defined in the Bylaws and in the Company Organization Handbook.

Office of the CEO: The Office of the CEO is responsible, through the actions of the Chief Executive Officer, for the political-administrative orientation and representation of the Company.

Regulatory and Special Projects Board: Planning, guiding, supervising, coordinating and controlling activities related to technical, commercial and economic-financial regulation, as well as those related to projects related to research and development, energy efficiency, ombudsman, special projects, in accordance with what is established in the concession agreement and current legislation.

Planning and Expansion Board: The Planning and Expansion Board is responsible for planning, guiding, supervising, coordinating and controlling the activities related to the planning and implementation of the expansion of the electric distribution and subtransmission systems, in order to ensure fulfillment of the demand from the energy consumer market within the concession area, as well as activities related to environmental management and monitoring of the Company's activities.

Commercial Board: The Commercial Department is responsible for planning, guiding, supervising, coordinating, deliberating and controlling activities related to commercial relations with consumers and activities related to statistics and market and energy purchasing projections, in accordance with the provisions of the Company's Bylaws, the Concession Agreement and Legislation.

Financial Board: The Financial Board is responsible for planning, guiding, supervising, coordinating and controlling the activities related to general and cost accounting, accounts payable and receivable, budget, treasury, tax management, equity control, insurance, fundraising and investments.

Management Board: The Management Board is responsible for planning, guiding, supervising, coordinating and controlling activities related to people management, training and development, occupational safety and medicine, labor and union relations, supplies and material management, information technology, organization and management methodologies.

On December 31, 2016, Ceron's workforce was composed as follows:

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	Category	Amount
a.	Employees in permanent positions	690
b.	Employees on secondment from other bodies and spheres	3
c.	Officials without ties to the public administration (Commissioned)	2
d.	Board members	7
e.	Assigned employees	28
Total (a+b+c+d-e)		702

In addition to the professionals above, Ceron's workforce include interns and young apprentices:


	Category	Amount
a.	Young Apprentice	28
b.	Interns	49
Total		77

2.3.	Profile of Positions and roles:

Following what has been established in the Eletrobras System's Position and Compensation Plan ("PCR"), Ceron employees are distributed into four broad positions:


	Levels of
Broad position		Role
	complexity

		§	Administrative Assistant
Middle-school Level			Assistant Electrician
	I, II	§
Professional ("PF")			Driver


		§	Electrician-Driver,
High-school Level Support	I, II, III and IV	§	Administrative Support
Professional ("PMS")		§	Telecommunications Accounting Technician Technician

		§	Electrical Technician,
High-school Level Operational	I, II, III and IV	§	Work Safety Technician
Professional ("PMO")		§	Electronics Technician.

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		§	Lawyer Administrator
		§	Social Communication Analyst
		§	Information Technology and

		§	Archivist Communications Analyst
Higher-education Level		§	Social Worker
Professional ("PS")	I, II, III and IV	§	Accountant
		§	Economist
		§	Civil Engineer
		§	Electrical Engineer
		§	Work Safety Engineer
		§	Work Physician
		§	Organizational Psychologist

Note: The PCR also defines the position of Professional Researcher, but this was not adopted by the Distributors.

2.4. Profile of gratified roles and positions in commission:

Gratified roles are carried out by permanent employees who act in positions of leadership and advisory positions:


Category	Amount
Board Assistant	5
Director	3
Area Manager	51
Department Manager	21
Project Manager	3
Location Leader	8
COI Leader	3
Auctioneer	2
	96

In addition to gratified roles, Ceron has employees with no ties to the public administration, acting in a commissioned position (this contracting model is established in Article 37 subsection II of the Constitution).


	Category	Amount
Assistant to the CEO		1
Director		1
		2

In total, Ceron's staff has 98 employees in gratified roles and commissioned positions.

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2.5.	Relevant changes to the Organizational Structure:
2.5.1.	Incentivized Resignation Program ("PID")

In 2013 and 2014 all distributors of the Eletrobras System implemented the Incentivized Resignation Program ("PID"). The following were considered eligible: employees who had a 20-year effective employment relationship with the distributor, considered in the month of termination and retired by the INSS regardless of the time of employment with the distributor. Membership was voluntary and depended on the initiative of the request for resignation by the employees.

87 employees were laid off, distributed into two stages:

Terminations were carried out in two stages:

Stage 1 (July 2013 to December 2013): 81 terminations
Stage 2 (January 2014 to November 2014): 6 terminations

Those terminated through the PID received the maintenance of the benefit of medical assistance for a determined period of time, according to the step in which they were laid off:

Stage 1 - 60 months of medical care maintenance and
Stage 2 - 12 months of medical care maintenance.

2.5.2. Approval of the new 2017 organizational structure

On October 25, 2016, a change in the organizational structure of Ceron was approved. The new organization chart is as illustrated below.

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3.3.6. Absence rate:

The absence rate takes into account absence of the employee due to delay or unjustified absences and is shown as a percentage of the potential work hours that were not actually fulfilled.

At Ceron, the average absence rate of the last 5 years analyzed was around 2.99%. When comparing this percentage with that of other companies in the Electric Power sector, we observe that it is in line with the average of this market.


	Ceron absence rate (as a percentage)

2016	2015	2014	2013	2012	Energy Panel Comparison
2.73%	3.17%	2.66%	3.37%	2.04%	Average absence
					2.51 %

3.3.7. Employees on leave:

In 2016, Ceron reported 4 work accidents. The leave periods were: 2 days, 2 days, 10 days and 90 days. No reasons for the leaves were reported in previous years.

3.3.8. Overtime:

The average overtime rate per capita for the past 5 years analyzed year was approximately 70 hours per year.

The collective agreement of the category provides for the payment of worked overtime hours under current legislation. The Distributor uses an hour bank, but did not prove that it is approved by the workers' union.


Overtime per capita (in hours)

2016	2015	2014	2013	2012
76.98h	72.20h	68.97h	59.46h	72.95h

The average percentage of overtime in the past 5 years, which considers the number of overtime hours worked over the number of potential overtime hours has been maintained at an average of 4.7%. It should be noted that this overtime index is below what is measured in the general market (5.3%).


	Overtime (as a percentage)
					General Market
2016	2015	2014	2013	2012	Comparison

5.2%	4.9%	4.6%	4.0%	4.9%	Overtime
					5.3 %

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3.3.9. Stability:

Currently, the Distributor has 97 employees on Stability as provided for by the legislation or established in a collective agreement:

CIPA members (Considering the 2015/2016 and 2016/2017 terms): 38 employees
Workers' union directors: 52 employees
Employees on leave in general: 7 employees

3.4.	Workforce Development
3.4.1.	Performance appraisal

Ceron annually performs performance appraisal on its employees. The appraisal process covers Skills Appraisal and Targets Appraisal. The former consists of an Individual Appraisal of skills performed by the manager on the employee under his/her subordination. The latter relates to the results of the Business Goal as stipulated by the CMDE (Business Performance Targets Agreement) and Team Targets monitored through the Management in Sight ("Gestão à Vista") program. Skills and targets are assessed through the following concepts:

Skills
AE - Above Expectations
A - Meets
AP - Partially meets
NA - Dos not meet

Targets
S - Exceeds
A - Meets
AP - Partially meets
NA - Dos not meet

The result is a combination of the results of skills appraisal and targets appraisal and is expressed as a number ranging from 1 to 16. This number reveals the employee's position in a 16-quadrant matrix. According to his/her position, the employee receives appropriate training actions and is eligible for promotion or salary raise by merit.

Source: Eletrobras System Performance Management System

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Employees on leave during the appraisal cycle, commissioned employees, members of the Board of Directors and directors do not perform this performance appraisal model, and thus, only 671 employees participated in the 2016 cycle.

By analyzing the results of the evaluations, we observe that almost 56% of the employees are appraised as at least "Meets" regarding targets. Targets are appraised as "Dos not meet," "Meets," or "Exceeds."


Skills		Targets
AE - Above Expectations	44%	S - Exceeds	18%
A - Meets	55%	A - Meets	29%
AP - Partially meets	1%	AP - Partially meets	53%
NA - Dos not meet	0%	NA - Dos not meet	0%

Good market practices indicate that, on average, 70% of appraised employees receive a "Meets" grade, the rest being distributed between "Does not meet", "Partially meets" and "Exceeds" (the latter is generally limited to 5% of those appraised).

3.4.2. Training hours

In 2016, Ceron accounted for 15,464 hours of training, representing an investment of 22.03 hours per year per capita (approximately 3 days) for dedication to training at a cost of BRL 320,764.14 (BRL 456.93 per capita).

According to the Management Report, in 2015 the company invested BRL 600,000.00 in the education of its employees, performing 119 educational actions in person and remotely.

It is possible to increase this volume of hours with the construction of a training and development plan by department and position, aiming at better qualification of the workforce and professional stimulation.

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Fixed pay:

Salary - established according to the Position and Role Plan, according to positions and complexity. The current salary table is available in item 1.1, Part II.
Compensation received for holidays, maternity wages, supplement for sickness aid or 13^thsalary (paid based on salary)
Fees - paid to employees who exercise the role of Directors or Board members who do not receive a salary.
Incorporated bonus - bonuses that have been incorporated into the salary and the employee does not fail to receive
Bonus for service time - bonus incorporated into the salary paid according to the specific terms of the Distributor's collective agreement
Variable pay:
Considers the payment of Profit Sharing. The rules for this payment are described in Part II item 2.
Benefits:
Benefits paid in December 2016 include:


Health and Welfare Support		Education Support	Family Support

Continuous-use	medication	Educational aid	Babysitting aid
reimbursement
Eyewear and contact lens		Graduation reimbursement	Childcare aid
reimbursement
Gym aid		Graduate refund	Aid for children with special
			needs/disabilities
Healthcare		School material aid	Funeral aid
Food aid*

Transportation aid

*Food aid amounts were estimated according to collective agreement.

The rules established for payment of the above benefits are specified in section 6 of this report.

Bonuses:

Unhealthiness pay
Hazard pay
Hardship pay
Night-time bonus
Gratified role bonus
Special board/council bonus

Other items (representing sporadic payments):

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• Overtime

• On-call

• Reimbursement of expenses

4.2. Cost with active employees

The total personnel cost, considering active employees, for the month of December 2016, is BRL 7,261,426.40. In this amount, amounts related to the payment of 13^thsalary are not considered. We did not consider charges nor deductions:

Dec. 2016

Total personnel cost(BRL)*

*considers gross compensation, without deductions and charges. In this amount, the following items are considered:

BRL 7,261,426.40

By analyzing the cost structure, we observe that 65% is equal to fixed pay, 1% is Variable Pay, 15% are benefits, 13% are bonuses and 6% are equivalent to other items.


	Personnel cost composition

		Other items
		Bonuses
		Benefits
		Variable pay
		Fixed pay




	Total Personnel Cost
Compensation Type	Total	Per capita
Fixed pay	BRL 4,714,262.53	BRL 6,753.96
Variable pay	BRL 69,757.20	BRL 99.94
Benefits	BRL 1,072,396.68	BRL 1,536.38
Bonuses	BRL 974,263.15	BRL 1,395.79
Other items	BRL 430,746.84	BRL 617.12

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5. Collective agreements

The collective agreement is nation-wide and its clauses cover all six Distributors analyzed. There are other documents supplementary to the collective agreement. Over the years, the definitions established in previous years have been maintained.

Document

2016 - 2018 Collective agreement Nation-wide commitment agreement

2016 -2018 Specific collective agreement Specific commitment agreement

Specific clauses of the Collective Agreement by distributor Specific commitment agreement

Scope

Its clauses cover all Distributors

Ceron-specific clauses

5.1. Salary readjustment

With respect to salary raises, in the current agreement the readjustment was of 9.28%. It is common to set the 5% downpayment on the base date of the category (May), and the difference between the downpayment and the percentage increase negotiated in the agreement is paid retroactively.


	Collective Agreement	Salary readjustment percentages
	2012-2013	6.60%
	2013-2015	7.90%
	2015-2016	8.18%
	2016-2018	9.28%


5.2.	Benefits


	Collective Agreement	Salary readjustment percentages
	2012-2013	6.60%
	2013-2015	7.90%
	2015-2016	8.18%
	2016-2018	9.28%

5.3.	Payment of other bonuses

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In addition to the benefits, the collective agreement and its respective specific agreements establish clauses regarding payment of bonuses. The following are the main aspects:


Clause Hardship pay		Agreement description Payment of 7.5% on base salary, plus Bonus for service time, for employees in continuous rotating shifts.

Unhealthiness pay		Basis of calculation will be the lowest salary of Eletrobras' salary matrix. It is limited to the 40%, 20% and 10% percentages according to the degree of unhealthiness classified according to maximum, medium and minimum levels.
Night-time bonus		Payment of bonus for employees' extended hours, provided that they fully fulfilled their shift in the night period.
Hazard pay		Indicates the adoption of the payment criterion set forth in Law 12.740/2012 for employees admitted before 12/8/2012.
Overtime Substitution gratification		Calculated according to the percentages applied in the relevant legislation. Non-cumulative grant of Gratification for role to formal substitutes of an official gratified management position for a period of more than 10 days, to the amount valid in the payment month.
13^thsalary		50% advance payment may be requested on the annual holiday schedule and should be received together with the holiday payment.
Bonus for service
time ("ATS")		It will pay employees a bonus per year of uninterrupted service rendered.


Electrician/driver gratification ("GEM")		Driver gratification to electricians in the usual exercise of the Electrician/Driver role.
		1/3 of the normal hour for employees on-call under applicable legislation.
On-call

Holiday gratification		Holiday gratification payment of 75%

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6. Outsourcing

Historically, the Distributors have practiced labor outsourcing to perform certain roles. This outsourcing is contracted and managed by the contracting department, by the contract manager. Accordingly, there is no characterization of an employment relationship with outsourced professionals.

In 2013, legal decisions were made to replace outsourced labor (legal decisions and decisions from judgments 2132/2010 - TCU-Plenary Sitting - and 2303/2012 - TCU-Plenary Sitting). Ceron has designed a project to prioritize such labor.

Currently, Ceron has a total of 1,715 outsourced workers, has hired 109 for the position of grid electrician to meet the demand for insourcing and there is a proposal to perform insourcing on 1,142 positions in the following positions:


Positions		To be Hired
PF-ASSISTANT ELECTRICIAN		335
PF-METER READER (TO BE PHASED		195
OUT)
PMS-ELECTRICIAN DRIVER		435
PMS-ADMINISTRATIVE ASSISTANT		48
PMS-ADMINISTRATIVE	ASSISTANT	105
(CONSUMER SERVICE)
PMO-ELECTRICAL TECHNICIAN		16
PMO-SAFETY TECHNICIAN		4
PS - ELECTRICAL ENGINEER		4

It is important to note that Law 13.249/2017, which regulates outsourcing in companies, is being discussed and has not yet been promulgated, so the exercise of activities by outsourced professionals may represent a labor exposure and the need for insourcing should be considered.

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7. Aspects related to health and safety

In addition to specific clauses on health and safety defined in a collective agreement, Ceron has policies and standards aimed at preserving the health and safety of its employees. The main aspects related to the topic are shown below.

7.1. Verification of existence of health and safety policies and procedures

Ceron follows the health and safety policies and procedures established by the Eletrobras System, which are an integral part of the PPRA and PCMSO.

7.2. PCMSO Analysis

Ceron submitted the document for the preparation and implementation of a valid Occupational Health Medical Control Program ("PCMSO"), which was prepared in October 2016.

The document covers both employees of the capital and those of the rural areas and classifies the activity of the Distributor as risk degree 3. The following are the main aspects analyzed in the document:


Aspects analyzed				Classification
Clear goals
Risk degree
Describes actions to promote health
Describes tests to be performed
Recognition of environmental risks
Procedure in case of accident
Responsibilities
Has descriptions for positions and roles
Has performance indicators
Schedule of actions
Expected to disclose results
Key: showed evidence		ï insufficient information	× did not show evidence

7.3.	PPRA Analysis

Ceron submitted the document for the preparation and implementation of a valid Environmental Risk Prevention Program ("PPRA"), which was prepared in November 2016. The Distributor has a single PPR that covers all of its Units.

Aspects analyzed

Clear goals

Roles and responsibilities Has performance/goal indicators Schedule of actions

Classification

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Expected to disclose results
Description of risk recognition, monitoring and control
Describes physical, chemical, biological, ergonomic and accident risks
Assesses chemical risks
Assesses biological risks
Assesses ergonomic risks
Assesses risk of accidents
Assesses environmental noise risks
Assesses environmental lighting risks
Has descriptions for positions and roles
Describes PPE used
Describes prevention measures
Key: showed evidence		ï insufficient information	× did not show evidence

7.4.	Verification of completion of occupational medical examinations

Aspects analyzed			Classification
Annual periodic examinations
Admission examination
Termination examination
Key: showed evidence		ï insufficient information	× did not show evidence

7.5.	Internal Committee on Accident Prevention ("CIPA")

Ceron has an active CIPA, as established in NR-5. A CIPA is established for each of the different locations of the distributor. Currently, 21 elected employees are fulfilling their term.

According to the documents provided, CIPA meetings take place periodically and have minutes recording the decisions.

7.6. Survey of work accidents (with/without leave) and opening of CAT (Work accident communication)

The Distributor has evidence of being in compliance with the need to open a "CAT" (Work accident communication) when work accidents occur. In 2016, 4 work accidents were reported, with opening of CAT. The leave periods were: 2 days, 2 days, 10 days and 90 days.

7.7. PPE Delivery Verification

Ceron showed evidence that it performs PPE delivery control for employees who need this type of equipment and perform the following roles: • Assistant electrician

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Electrician driver
Electrical engineer
COI Leader
Location leader
Distribution system operator
Electrical technician
Work safety technician
Electromechanical technician
Electricity technologist.
Assistants and administrative managers who work in an environment of exposure to risk.

7.8. Occupational Safety Technician Performance

Ceron has in its staff eight professionals who act as work safety technicians.

7.9. Mandatory training

Mandatory health and safety training depends on the activities performed by the employees, which can expose them to different risk situations.

Ceron offers its employees the following training sessions, according to the activities carried out: Regulatory Standard 10 (NR10), Regulatory Standard 35 (NR35). The mentioned training must be performed every two years.

NR10 - Training performed by employees who perform activities related to the electrical system.
NR35 - Training performed by employees who perform activities in high altitude.

In 2016, 330 employees underwent safety training, including NR10 and NR35.

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High-school Level Operational Professional ("PMO") Higher-education Level Professional ("PS") Professional Researcher ("PP")

I, II, III and IV
I, II, III and IV
I, II, III and IV

Broad positions shall be unfolded in occupational spaces with the purpose of giving flexibility to the professionals to assume different roles in the Organization and, thus, to allow greater alignment between the performance of the professional and the expectations and needs of the person himself/herself and the Organization by respecting the specific requirements of each training.

Occupational spaces define specific assignments, skill and training requirements, given the characteristics of organizational processes and professional regulations.

1.1. Compensation Structure

Each of the five broad positions defined in the Career and Compensation Plan of the Eletrobras System has its respective salary scale. The salary scale consists of "ranges" that are divided into steps: Ranges: Reflect each of the complexity levels established for the positions.

Steps: The number of steps per range varies due to the established wage spread (guided by internal and external market information) and adherence to the methodology present in the requirements for accessing the complexity levels of each position.

1.2. Growth Rules:

Employees can undergo horizontal growth (advancing through steps) or vertical growth (advancing through ranges).

Horizontal growth: The salary evolution of the employee within the same complexity level which the professional is currently in. This change is conditioned to the result of the Performance Appraisal and the availability of funds. Horizontal growth can be done over one (1) to three (3) wage steps.

Vertical growth: The rise of the employee to the complexity level immediately above that of his/her current level. Vertical growth may occur during the twelve (12) months subsequent to the Performance Appraisal, subject to the defined access requirements for seniority promotion and availability of funds and vacancy for this purpose.

Employees shall be ensured at least one (1) and at most four (4) salary growth steps.

Promotion due to Seniority: An automatic advance corresponding to a ½ salary step advance. The level advance will correspond to a lateral (from column A to B) or diagonal (from column B to A) growth in the salary scale and will occur after the employee stays for 24 months at the same salary step. That is, if he/she does not advance due to other criteria.

After the employee stays for 24 months in the last step (column B) of the complexity level to which he/she belongs, the employee shall be entitled to a diagonal level advance. Level growth will only occur in the following cases: _ From Level I to Level II.

_ From Level II to Level III.

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Below is an illustration of advancing within the salary scales of the positions, to be executed according to professional ascension criteria for the career:

Vertical Growth

Complexity Levels / Value
Addition

Horizontal Growth

1.3. Access requirements:

Each complexity level of broad positions has specific access requirements.


Level of Complexity I		Access requirement Access by public competition, without experience requirement.
II		Time spent in the previous complexity
		Result of performance appraisals in the last 3 years.
III		Time spent in the previous complexity
		Result of performance appraisals in the last 3 years
IV		Board Approval Existence of vacancy.

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2. Variable pay

The Eletrobras system defined a policy for sharing the company's profits with employees ("PLR"). The maximum amount to be distributed is up to two salary payrolls of the relevant year for each company that signed the system.

This payment of profit sharing is carried out in accordance with two stages.


			Impact on the amount to
Stage		Targets
			be distributed

	Holding company's net income target		25%
STAGE 1

PROFITABILITY	EBITDA target per company		25%

	Business Performance Target
	Agreement:
STAGE 2	-	Availability and Generation
	-	Availability of transmission lines
OPERATIONAL			50%
	-	Deducted Variable Portion on
TARGETS	transmission
	-	Score obtained at ISE Bovespa

Achievement of targets can be proportional, with specific criteria for each.

Once the assessment of all targets linked to PLR payment have been made, this will be paid 50% in a linear manner and 50% distributed in proportion to the pay of each employee. Permanent employees will be entitled as long as they have been in the company since January 1 of the year related to the PLR, as well as employees on secondment and assigned employees, provided that they do not receive PLR from their original/assignee companies. If any of these employees mentioned above has interrupted their employment contract throughout the reference year, they will not receive the PLR. If they work partially during the year due to their date of admission, retirement, dismissal without just cause, termination or leave, they will receive the PLR in a proportional way.

Hours worked by the employee versus the total hours required by his/her position, by deducting holidays, maternity leave and occupational sick leave or work-related accidents shall be equal to or greater than 95% for him/her to be entitled to receive his/her PLR.

Note 1: Scales having the levels of compliance with the holding company's net profit targets, EBITDA per company and operational targets are included in the PLR normative documents.

Note 2: There are points that are still diverging between the companies and workers' unions to be later checked.

3. Benefits

As informed in Part I session 4, Personnel Costs, Ceron provides its employees with a series of benefits, part of which is established in a collective agreement, and part is offered at the company's discretion.

Practices generally adopted by the market were not identified, such as differentiation of benefits for management positions.

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Benefits established in a collective agreement (whether in the nation-wide agreement, in the nationwide commitment agreement, in the specific agreement of the Distributors or in Ceron's specific agreement.


Benefit Food/Meal Aid		Current amount 13 to 16 booklets/year with 29 units having a value of BRL 37.82. Reimbursement of up to BRL 449.29/month per dependent, for dependents up to 17 years of age, not cumulative with childcare aid, in protection of the academic period (middle-school, high-school and/or technical school).
Educational Aid		Reimbursement for expenses with school uniforms and supplies for full scholarship recipients (limited to the amount of two monthly tuition installments)

Holiday gratification Childcare/ Preschool/ Babysitting Aid		Holiday gratification payment of 75% Reimbursement of BRL 599.05/month per dependent for dependents aged 6 months to 6 years (limited to the amount of two monthly tuition installments). Compensation supplement, including thirteenth salary, to an amount
Work sickness/accident aid		corresponding to the difference between monthly compensation and the benefit received by social security as work sickness/accident aid.

		Reimbursement of proven expenses with PCD dependents up to a limit of BRL
PCD		843.65.
		Reimbursement of funeral expenses up to the limit of BRL 4,921.28 and
Funeral Aid		BRL 9,842.57 for death due to work accident.
School material reimbursement Leave for victims of domestic violence Patient companion leave Leave due to death of step-father or step- mother		Up to the limit amount of two monthly tuition installments for the educational aid or childcare aid. Paid leave of 3 to 5 days to workers. Medical companionship for relatives or healthcare plan dependents: from 1 to 30 days subject to submission of medical certificate or medical report. Up to 5 days.

		1/3 of the normal hour for employees on-call under applicable legislation.
On-call

Annual Supplementary Bonus		1% on base salary for each completed work year. (Employees admitted as of 5.1.2004 will be granted the five-year supplementary bonus on the base salary for every 5 worked years, limited to 7 five-year periods.

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University course incentive		Partial reimbursement of expenses with undergraduate education for employees who do not yet have this education level. 90% reimbursement up to the limit of BRL 605.85.

Physical activity incentive		Reimbursement up to the limit of BRL 94,58. Medical aid, hospital aid, laboratory aid and dental care plan to all employees and dependents. (5 times the wage floor 6% deduction, 5 to 7 times the wage
Healthcare		floor 18%, 7 to 9 times the wage floor 27%, 9 to 10 times the wage floor 36%, above 10 times the wage floor 45%). In the year 2016, the Healthcare Plan (PPRS) had an annual cost of BRL 13,919,784.00. For chronic conditions such as diabetes and heart diseases such as
Continuous-use medication reimbursement		hypertension, arrhythmia, congestive heart failure, medicine for an child with special needs, for a total of BRL 301.28. As a premium when an employment contract is terminated, to an amount
Incentive to retirement		equivalent to 1 time their base salary received in the month of retirement for each year of service in the company, limited to the payment of 10 salaries. 11.62 times the base salary of each employee up to the limit amount of BRL 54,085.00 per natural death or total permanent disability due to illness and to the amount of 23.24 times the base salary of each employee up to the limit of
Group life insurance		BRL 108,170.00 for accidental death of any nature or permanent disability resulting from an accident. (The company will pay 50% to 60% of the cost of group life insurance and the employee will pay the 40% to 50% difference).

		The Distributor will provide it to those who opt for it, observing the legal and
Transportation		regulatory standards that govern said system.

		Full refund of expenses incurred with medicines in the case of work
Medication reimbursement		accidents, occupational diseases and cancer when said medication is for the treatment of the disease.
		It shall be granted to employees subject to continuous rotating shifts at the
Snack Voucher		unit value of 50% of the meal voucher.

Hospital Medical Treatment		The Distributor shall pay for medical and hospital treatment expenses not covered by the healthcare plan for victims of work accidents and occupational illness.
Medication for injured employees		The Distributor shall pay for 100% of the amount of medication for work accident victims. Expenses with glasses (lens and frame) or contact lenses for active employees, within the established limits, are reimbursed: Frame - reimbursement of up to BRL 110,52
Eyewear and contact lens reimbursement*		Single-vision lenses - Refund of up to BRL 95,49 Multifocal lenses - reimbursement of BRL 181.25 Contact lenses - reimbursement of up to BRL 149.21

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Other incentives offered:

Private Pension Plan - Eletrobras CERON, through the CERON CD PLAN, offers its employees the Supplementary Pension Plan for Predefined Contribution ("CD"). Monthly contributions from employees, together with the company's participation, will create a savings account, enabling the employee to receive a supplementation to his/her retirement when retiring. In 2016, no standard contributions were made by the company for constituting mathematical reserves of the private pension plan.

Employee Profit Sharing (PLR) - Eletrobras grants PLR to its permanent employees after the end of each financial year, provided that the goals established in the Agreement Instrument are reached. Guidelines for the distribution of profit sharing are negotiated with the entity representing the employees, and comply with the provisions of the Resolution of the Board for Coordination and Control of State Enterprises ("CCE") # 10/1995 and Law # 10.101/2000.

Quality of Life Program - In order to improve and ensure quality of life to its employees, the company annually signs an agreement with SESI/AC regarding a quality of life and active leisure program, with the creation of interest groups related to dance, sports, culture, and other branches of entertainment, where employees can exchange experiences and perform on festive occasions.

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4. Performance Management

The Performance Management System is a standard in all Eletrobras System companies. This process is composed of two concurrent programs which are the "Skill Assessment and Development Program" ("PADC") and the "Results Evaluation and Improvement Program" ("PAMR").

Distributors are in the fifth evaluation cycle but there still are aspects of the model that have not been fully implemented.

Through the PADC, skills classified as "Organizational Skills" are evaluated. Specific skills have not been defined and, therefore, are not evaluated. In addition to undergoing evaluation by their direct leader, employees perform their self-assessment (without any weight on the final result). The 360^oevaluation model was not implemented.

Through the PAMR, organizational results are monitored on a corporate and team level. These results are measured by targets defined at the beginning of the evaluation cycle. Throughout the cycle, they are monitored with regard to their achievement. Currently the business targets represent 30% of the evaluation and team goals represent 70%.

The evaluation cycle is annual. The result of the evaluation is expressed through a grade and can be visualized in the Performance Classification Matrix.


In Skills

Grade	Description	Scale
Does not	The employee shows performance in skills well below the	0
meet	defined standard
Partially	The employee shows performance in skills approaching the	1
meets	defined standard
Meets	The employee shows performance in skills in accordance	2
	with expectations regarding the defined standard
Meets above	The employee shows performance in skills above	3
expectations	expectations regarding the defined standard


In Results

Grade	Description	Scale
Does not	The employee shows performance in results well below the	0
meet	defined standard
Partially	The employee shows performance in results approaching	1
meets	the defined standard
Achieves	The employee shows performance in results in accordance	2
	with expectations regarding the defined standard
Exceeds	The employee shows performance in results above	3
	expectations regarding the defined standard

4.1. Performance Matrix:

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5. Training and Development

The educational model of Eletrobras distributors for planning and executing educational actions is formally described in its standards (Corporate Education - Planning and Execution and Development and Training of People) and in the Corporate Education Plan of UNISE ("Universidade das empresas da Eletrobras").

The management of educational actions has a hierarchical structure defined both at Eletrobras' corporate level and in local development structures in the distributors. The general guidelines of the educational model are defined by corporate and deployed locally, maintaining strategic alignment among the different companies, while specific demands of the distributors are met by the local corporate education unit.

Eletrobras' educational model is structured based on management by skills. In the process of preparing the educational plan, priority skills for the organization are defined based on the business strategy. The educational model is also integrated with other people management practices such as performance management, job and salary plan, and leadership development by promoting strategic alignment among human resources actions.

The corporate education of Eletrobras companies is organized into two organizational structures that act in a complementary way:

UNISE (Universidade das empresas da Eletrobras): concentrates the role of conducting educational actions that are common to the group companies. The planning of educational actions of UNISE is described in the Corporate Education Plan, as well as guidelines for the enforcement of educational actions.
Corporate Education Unit of each member company: is responsible for meeting the demands of developing the specific skills of each company, aligned with its strategy and UNISE guidelines. This fulfillment is performed through the drafting of a local Corporate Education Plan, which is built from the individual development plans of each employee and according to the guidelines of the Business and Management Plan of each company.

Educational actions can be categorized as internal when performed at the company's premises and with in-house instructors; external, when performed by an external provider and can be performed inside or outside Eletrobras facilities; introductory educational action, which aims to integrate new employees into the organization; and educational contractual training actions resulting from contracts with equipment or software suppliers who demand training of employees. Distributors also feature brief distance education courses offered by Corporate TV (LUME).

To monitor the quality of training and contribute to continuous improvement, reaction assessments and impact assessment should be applied to each training. And at the managerial level, educational actions are accompanied by monthly reports and quarterly reports directed to the Executive Board.

Criteria for employee participation and certification are clearly defined in the standards and standardized forms procedures. The justifications accepted in case of withdrawal are also listed in the standards, as well as penalties in case of abandonment, failure or termination from the company. Formalization of the process ensures greater transparency and equality to employees, aiming to ensure equal opportunity of participation and development to employees.

Analysis of the documentation provided by the Distributors regarding training and development shows that Eletrobras' corporate university offers consistent programs for developing leadership skills, as well as management, strategy and some aspects related to the operation, among other topics.

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Training offered by the Distributors, due to budget constraints, is more focused on operational aspects and compliance with mandatory training. We observed that for these development actions the Distributors frequently use the agreement with S. System institutions.

6. Organizational Climate

The Organizational climate survey aims to monitor the employees' satisfaction and commitment to the company, as well as to identify training needs, personal/managerial development and to seek alignment of the culture with the actions carried out by the company.

All Eletrobras System Distributors conduct the survey every two years by evaluating the following aspects:


	People	Philosophy of	Work
Motivation
	Management	Management	Environment


	Corporative	Organizational
Identity	education	Clarity
			Work Conditions
Leadership	Career and	Communication
	Remuneration		Occupational
Interpersonal		Institutional	Safety
relationship	Benefits	Image	and Health

	Recognition	Sustainability

The result of the survey is expressed through the Favorability Index, which is the result of the average obtained in the four evaluated dimensions.

In the last edition of the survey, conducted in 2015, Ceron's favorability index was 69.15%, which is in line with the Eletrobras system average.

During an interview with human resource leaders, it was reported that, currently, climate-related attention points are the lack of motivation in view of the insourcing prospect and the overload of the workforce (due to a reduction in the number of employees).

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National Bank for Economic and Social Development ("BNDES") Av. República do Chile, 100 Rio de Janeiro - RJ

C/O: Ms. Lidiane Delesderrier Gonçalves — Manager of Agreement OCS 028/2017 May 2017

Dear Sirs,

According to our service agreement OCS 028/2017 ("Agreement") executed between BNDES and Mais Energia B Consortium ("Consortium") on 2/14/2017, we present the result of our work carried out in the context of Privatization of Eletrobrás System Distributors.

The summary of the outcome of our work "Product 04: Legal Due Diligence Report" for CERON ("Report"), dated May 2017, is detailed in this document.

In case this Report is to be accessed by third parties, it must be made available in full, so that the applicable safeguards and limitations are known.

Regards,

Loeser e Portela Advogados, as member of the Consortium


[Signed]		[Signed]
Fernando Loeser		José Augusto Sollero Figueira

This document is a true copy of the original signed version delivered to BNDES and in the possession of Eletrobras.


Legal Auditing Executive Report Introduction INTRODUCTION		CERON Page 4/15

1. This Executive Report ("Report") was carried out as part of the structuring of the privatization operation for Centrais Elétricas de Rondônia S.A. ("CERON" or "Company" or "enterprise"), in accordance with the Invitation to Bid corresponding to AARH ELECTRONIC TRADING FLOOR #51/2016 - BNDES - ITEM 1 - "SERVICE B" (economic and financial assessment and legal, accounting, technical-operational and other specialized professional services).

2. In this context, the NATIONAL BANK FOR ECONOMIC AND SOCIAL

DEVELOPMENT (BNDES), through its Bidding Department, pursuant to the provisions of Law #10,520 of 7/17/2002; Decree #5,450 of 5/31/2005; Supplementary Law #123 of 12/14/2006; Decree #8,538 of 10/6/2015; Law #13,303 of 7/1/2016; and DIR Resolution #3.063/2016 (BNDES System Bidding Regulation) provided for the hiring of a company to provide the specialized services described above.

3. Loeser and Portela Advogados, an integral part of the Mais Energia Consortium, together with PricewaterhouseCoopers Corporate Finance & Recovery Ltda., PricewaterhouseCoopers Serviços Profissionais Ltda. and Siglasul Consultoria Ltda., pursuant to OCS Agreement #028/2017, executed on February 14, 2017, was contracted to advise BNDES on the structuring of CERON privatization operation ("Operation"), specifically with respect to (i) legal aspects related to the structuring and implementation of the Operation; as well as (ii) carrying out limited legal due diligence work through sampling with respect to the Company, which is contemplated in this Executive Report.

4. This Legal Due Diligence resulted in the preparation of this Report, and includes the analysis and assessment of information and documents to identify any issues that may significantly alter the accounting position and/or market value of CERON with respect to the following aspects:

(i)	corporate, civil and regulatory matters. Tax, labor, social security and environmental aspects (compliance) were carried out by the advisors responsible for the analysis in these departments, and are reflected in their respective reports;
(ii)	existing litigation within the administrative and/or legal spheres that affects, or may affect or is in any way related to CERON, and the description must contain the details on the litigation, its probable outcome and the amounts involved;


Legal Auditing Executive Report Introduction		CERON Page 5/15

(iii)	status of the assignment and ownership of real estate and equipment registered or likely to be registered in CERON's property, plant and equipment, and the regularity of the respective documentation, including before public records, pointing out any existing liens or encumbrances; and
(iv)	gathering public information needed to carry out this service.

5. Lastly, this Report was prepared at the request of BNDES and is addressed only to our client (BNDES), and no other person or entity other than BNDES should rely on it; reference to this Report is also prohibited in any other document, as well as its registration or submission to third parties without our prior and explicit authorization and consent. Notwithstanding the foregoing, and provided that the client-attorney relationship (and related rights and obligations) is limited exclusively to BNDES and our firm, (a) BNDES and its advisors may use this Report for analyzing the legal feasibility of the Operation, for its economic and financial structuring and related purposes; and (b) this Report may be sent or disclosed to third parties, at BNDES' sole discretion and liability, which logically includes full disclosure to potential stakeholders in the Operation and their respective advisors.

6. The legal audit, carried out in the period from March 6 to May 12, 2017, was based on documents and information provided by CERON related to the Company.

7. The date of 12.31.2016 was set as the base date for issuance of the respective report of the legal audit performed ("Base Date"). It should be noted, however, that some of the information contained in this Report, as expressly indicated therein, may refer to events occurring after the Base Date.

8. The content of this Report is limited to information obtained through the procedures described below, subject to the restrictions listed.

9.	The legal audit was conducted according to the following methodology:
	(a)	submission of initial request for documents and information to representatives of CERON designated to attend the audit process;
	(b)	submission of requests for additional documents and information, based on information obtained during the investigation process;
	(c)	interviews, meetings and contacts with CERON employees working in the various sectors and units of the company, especially those related to the legal and accounting departments;


Legal Auditing Executive Report Introduction		CERON Page 6/15

(d)	obtaining data extracted from CERON's process control system;
(e)	analysis of the documents and information made available.

10. It is assumed that (i) all copies made available by CERON match the originals; (ii) such documents, except when explicitly stated in this report, are complete and authentic; and (iii) the signatures therein belong to persons empowered to represent the respective parties.

11. In some cases, as usual in all legal proceedings, the level of detail in this Report was compromised by the (partial or total) absence of CERON's information and documents, especially related to Civil, Tax and Labor Litigation.

12. This Report is not intended to cover all legal aspects related to CERON, but mainly those that have a significant impact on the economic-financial analysis for the purpose of recommending the minimum sale price of the Company's shares.

* * *


Legal Auditing Executive Report Introduction EXECUTIVE REPORT		CERON Page 7/15

A.	REGULATORY ASPECTS
1.	CERON acts as a designated distributor responsible for providing public electricity

distribution services in the areas of municipalities of the state of Rondônia listed in MME

Ordinance #422/2016, with a view to ensuring continuity of service, pursuant to paragraph 1 of article 9 of Law #12,783/2013, and subject to provide such services in accordance with the terms and conditions established in MME Ordinance 388/2016, until assumption by a new utility or until 12.31.2017, whichever occurs first.

2. Centrais Elétricas Brasileiras S.A. ("ELETROBRAS"), the controlling shareholder of CERON, agreed to designate its subsidiaries, including CERON, as providers of energy distribution services on a temporary basis, provided that, among other conditions: (i) ELETROBRAS does not undertake to guarantee any new obligations that may be assumed by the distributors, in any way, including obligations arising from the provision of temporary services; and (ii) measures be taken to ensure that the transfer of shareholding controls of the distributors occurs by 12.31.2017, in order to avoid liquidation of the distributors and the return of the respective concessions.

3. CERON held the concession for operation of public electricity distribution services under the terms of Concession Agreement #05/2001, signed on 2.12.2001, effective until 7.7.2015, and requested extension of its validity within deadline and under the conditions laid down in that agreement. Nevertheless, ELETROBRAS, as controlling shareholder of CERON, at its 165^thExtraordinary General Meeting, resolved for: (i) reject the extension of CERON's concession; and (ii) approve the assignment of ownership control of the distributor by 12.31.2017, provided that, until the assignment of the distributor to a new controller, the distributor receives directly from the federal government or through a rate all resources and income necessary to operate, maintain and make investments that are related to the public services of the respective distributor.

4. Considering the interest of the Ministry of Mines and Energy ("MME") in promoting the bidding associated with the assignment of control of the legal entity providing energy distribution services with the corresponding granting of a contract to the new controller for a term of 30 years, the National Electric Energy Agency ("ANEEL"), at the MME's request, prepared and submitted to public hearing (Public Hearing #094/2016) the draft of the concession agreement prepared in accordance with guidelines established by the MME with the purpose of increasing competitiveness of bidding processes for assignment of corporate control related with new concession grants.


Legal Auditing Executive Report Introduction		CERON Page 8/15

5. The assignment of CERON's ownership control shall be submitted to ANEEL's prior consent, in line with the provisions of article 27 of Law #8,987/1995, article 4 (XI) of Attachment I to Decree #2,335/1997, as well as the provisions of ANEEL Normative Resolution #484/2012.

6. On the Base Date, the Distributor had 5 administrative proceedings of regulatory nature, to a total contingency amount of BRL 9,025,720.35. Of these 5 administrative proceedings, 4 have been provisioned in the financial statements of the Distributor, to the amount of BRL 2,476,000.00. The difference between the total contingency amount and the amount provisioned in the Distributor's financial statements is BRL 6,549,720.35 as a result of the administrative fine. According to the information sent by the Distributor, such fine was duly paid in the same financial year of 2016, which is why it did not include ANEEL's provisions for fines in the financial statements ended 12.31.2016.

7. In addition, on the Base Date, the Distributor had 21 legal proceedings contesting regulatory-related Notices of Infraction. Of these 21 legal proceedings, contingencies were provisioned for 14 of them, to the total amount of BRL 76,243,000.00. Legal proceedings that fall within the criterion of materiality were analyzed in Section 8 (Civil, Equity and Criminal Litigation).

8. According to the audited financial statements of the Distributor on 12.31.2016, the Distributor provisioned BRL 78,719,000.00 for contingencies resulting from regulatory claims with ANEEL, of which BRL 2,476,000.00 were in administrative proceedings and BRL 76,243,000.00 in legal proceedings

9. Furthermore, CERON is in default of its intrinsic obligations, which makes it impossible for ANEEL to issue a Certificate of Performance. The Distributor submitted the Verification of Default regarding Obligations of the Electricity Sector, which contains a list of outstanding debt issued by ANEEL, which as of 3.23.2017 amounted of BRL

459,049,767.59, of which BRL 105,067.16 has already been booked and sent to registration as active debt.


Legal Auditing Executive Report Introduction		CERON Page 9/15

B.	CORPORATE ASPECTS
1.	According to article 9 of the current Bylaws¹of CERON, the sale in whole or in part

of its capital stock, as well as an increase in the share capital by subscription of new shares, requires approval of the shareholders through a general meeting specially called for this purpose, noting that CERON is a wholly owned subsidiary of ELETROBRAS.

2. In the case of a public offer for the disposal of shares owned by ELETROBRAS, registration with the CVM is waived, pursuant to article 5 of CVM Instruction #400/2003²combined with CVM Normative Instruction #286/1998³.

3. Article 253 of Law #6,404/76⁴("Corporation Law" or "LSA") provides for the right of first refusal of minority shareholders in the event of admission of shareholders to a wholly-owned subsidiary.

4. This legal provision would not be applicable in the event of the sale of CERON's shares to the extent that this Company became a wholly-owned subsidiary of ELETROBRAS through the acquisition of shares, pursuant to article 251 paragraph 2 (1^stpart) of the LSA⁵. Based on the most recent decisions of the Brazilian Securities and Exchange Commission ("CVM")⁶, and based on the specific response of this body in a consultation formulated by ELETROBRAS, the right of first refusal provided for in this legal provision is only applicable to wholly-owned subsidiaries thus converted through merger of shares.

C.	FINANCIAL AGREEMENTS
1.	Related Party Agreements. Financing agreements entered into with ELETROBRAS

do not contain provisions regarding the possibility and/or procedures for assignment and/or

¹Article 9: The General Meeting shall be called to specifically deliberate on: I - conveyance, in whole or in part, of shares of its capital stock; opening and increase of share capital by subscription of new shares or sale of these securities, if in treasury; sale of debentures which it holds, of companies in which it has a stake, and issuance of debentures convertible into shares.

²Provides for public offerings for distribution of securities in primary or secondary markets.

³Provides for the conveyance of shares owned by legal entities governed by public law and entities directly or indirectly controlled by the Public Authorities and exempts the records referred to in articles 19 and 21 of Law #6,385/76.

⁴Article 253. In proportion to the shares held in the company's capital stock, shareholders shall have the right of first refusal to: I - acquire shares in the capital of the wholly-owned subsidiary, if the company decides to convey them in whole or in part; and II - subscribe a capital increase of the wholly-owned subsidiary, if the company decides to admit other shareholders.

⁵Article 251. The company can be established by means of a public deed, having a Brazilian company as sole shareholder. Paragraph 2. The company may be converted into a wholly-owned subsidiary upon acquisition, by a Brazilian company, of all its shares, or as per article 252.

⁶Such understanding may be observed in CVM Administrative Proceeding #RJ2010/13425, in which it alleges that for companies converted into a wholly-owned subsidiary upon acquisition by a Brazilian company of all its shares, pursuant to article 251 paragraph 2 (1^stpart), the provisions of article 253 do not apply.


Legal Auditing Executive Report Introduction		CERON Page 10/15

transfer of the respective rights and obligations, nor do they expressly establish restrictions on the conveyance of control and/or the corporate restructuring of CERON.

2. Debt Confession Agreements. The purpose of the agreement is to recognize CERON's debt towards Petrobrás Distribuidora S.A. to the total amount of BRL 961,061,034.55 related to debt arising from fuel supply from November 1, 2014 to June 30, 2015. The debt confession agreement entered into between CERON and Petrobrás Distribuidora S.A. provides for anticipated maturity in the event of change of corporate control of CERON, succession of CERON, or any type of corporate reorganization that would result in a change in the shareholding control of ELETROBRAS or CERON, without the prior consent of Petrobrás Distribuidora S.A. There is a personal security of the federal government, a Pledge Agreement as Collateral regarding credit that CERON holds with the CDE; and the amount of BRL 349,045,658.94 will be guaranteed by ELETROBRAS as joint debtor.

D.	OPERATING AGREEMENTS AND OBLIGATIONS
1.	Operating agreements were submitted in a partial manner. Until the closure of this

Report, based on the analysis of the documents provided, no information was identified indicating risks or recommendations in the privatization process.

E.	INTELLECTUAL PROPERTY
1.	Intellectual Property. According to information provided in the data room, and by

consulting the website of the National Intellectual Property Institute ("INPI"), no trademark related to the name of, or distinctive sign related to, "CERON" was identified as of the completion of this Report. However, it should be noted that the term and symbols may be protected under business name protection.

F.	INSURANCE
1.	Mandatory insurance policies. Until the closing of this Report, the following insurance

policies were not available: (i) Insurance against property damage; (ii) Life and personal accident insurance for interns and watchmen, where there are interns and watchmen; (iii) Insurance against damage to land vehicles ("DPVAT"), if there are vehicles; and (iv) Insurance for civil liability of the builder, if works are in progress.


Legal Auditing Executive Report Introduction		CERON Page 15/15

Company's revenues corresponding to the last twelve months prior to the writing of the Infraction Notice.

3. Real Estate Permitting. The data room does not contain copies of the Operating Permits and Inspection Permits from the Fire Department for CERON's properties. The lack of real estate licensing may result in the imposition of administrative sanctions and penalties (warnings, fines, etc.), the amount of which may vary as the case may be, and may even result in suspension of activities at the respective facility.

4. Built-up Area. According to information analyzed in the data room and also in consultation with representatives of CERON, it is possible to conclude that no occupancy permits were issued for CERON's properties. Possible irregularities in the built-up area of real estate may prevent (i) issuance of certain permits, such as the Operating Permit and Inspection Permit from the Fire Department; (ii) registration/endorsement of any lease agreements; as well as generating (iii) imposition of administrative sanctions and penalties (warnings, fines, closure of the establishment, etc.).

5. Acquisition/Lease Restrictions (Foreign Nationals). Considering that some of CERON's own properties are located in a rural area, it is worth mentioning that currently there are restrictions applicable to the acquisition or lease of land by foreign nationals or Brazilian companies controlled by foreign nationals, which include the need for prior authorization from the National Colonization and Agrarian Reform Institute ("INCRA") or the National Congress, as applicable. In addition, it is worth noting that said restrictions also apply to corporate transactions resulting in the assignment of rural properties to foreign legal entities, such as mergers, acquisitions, consolidations and changes in control. Acquisition and/or lease of rural property by foreign nationals or by Brazilian companies controlled by foreign nationals in violation of applicable legislation (Laws #5,709/71 and 8,629/93) may be considered null for all legal purposes.

To the

National Bank for Economic and Social Development ("BNDES")

Av. República do Chile n° 100 Rio de Janeiro – RJ.

C/o: Mrs. Lidiane Delesderrier Gonçalves - Manager of OCS Contract No. 028/2017 May 2017 Dear Madam,

Pursuant to our OCS Service Contract No. 028/2017 (“Contract”) signed February 14, 2017, between BNDES and the Mais Energia B Consortium (“Consortium"), please find enclosed our deliverable for the work performed in connection with the Eletrobrás System Distributor Privatization Program.

Our findings are detailed in this document, which is entitled Deliverable # 6: Status Report on the CERON

Employee Complementary Pension Fund and Health Care Plan (“Report”) for CERON, dated May 2017. The work carried out does not constitute an examination performed in accordance with financial statement auditing standards. In performing our review, we used unaudited historical information and data provided by the Consortium’s management either orally or in writing, or obtained from mentioned sources.

Our work was developed solely for the purpose of advising BNDES in connection with the evaluation of CERON as required by the Contract. As established by Decree 8.893, BNDES is the entity tasked in with implementing and monitoring the utility privatization process.

In case disclosed to third parties, the Report should be made available in full so that any applicable waivers and qualifications can be acknowledged by all recipient parties.

Yours faithfully,

PricewaterhouseCoopers Finance & Recovery Ltda. acting as consortium leader


/s./		/s./
Rogério Roberto Gollo		Carlos Eduardo Silva Teixeira

This document is a true copy of the original signed version delivered to BNDES and in the possession of Eletrobras.

1. Executive summary

This report contains our analysis and findings regarding the review of actuarial assumptions and calculations of mathematical provisions recorded in the balance sheet of Centrais Elétricas de

Rondônia S.A. (“CERON”) for the fiscal year ended 12/31/2016.

Our analysis aims to provide a better understanding of the risks and opportunities associated with the business in view of commitments related to the post-employment benefits payable by the company.

The post-employment benefits referred to above include a temporary health care plan. Key features of these post-employment benefits will be described below.

Actuarial commitments were measured by an independent actuarial firm, Mercer Gama Consultoria, based on the CPC 33 rules established by the Accounting Standards Board, whereas our analyses were based on actuarial reports, registration databases, regulations and other technical documents made available by the actuary and CERON.

2. Plan type

Severance Incentive Plan (SIP): This includes a temporary 5-year health care plan introduced in 2013 for employees who at that time had over 20 years of employment with CERON and were retired by the INSS. This plan is fully funded by the company.

3. Plan statistics

Below are participant statistics for the plan as measured for fiscal year 2016.


	SIP
Active participants		-
Beneficiaries		81
Average age		59.80
Average cost		2,020.66

4.	Analysis of assumptions and recommendations
4.1.	Discount rate

The discount rate must be determined based on high-performing corporate securities or bonds.

Where the foregoing are unavailable, market returns on National Treasury bonds should be used instead. The currency and term of these financial instruments must be consistent with the expected currency and term of post-employment benefit obligations.

We point out that, for purposes of calculating the present value of actuarial liabilities, the rate adopted is net of inflation. The effect of inflation impacts exclusively on the projected expense for the subsequent fiscal year.

The rate used for calculating the actuarial commitments of CERON was 11.40% p.a. (considering an actual rate of 6.13% and inflation of 4.97% p.a.).

We understand that the rate applied is adequate to the calculations since it is consistent with the average rate of public bonds (NTN-B), which as of 12/30/2016 varied between 5.7% and 5.9% p.a. above inflation, as obtained from ANBIMA. The rate applied is therefore adequate to discount the long-term liability. We believe that a positive or negative 0.25 p.p. variation in the range is acceptable.

4.2. Wage growth projection

Not applicable.

4.3.	Biometric tables
	Biometric tables are statistical studies that rely on the occurrence of events observed in a population in order to estimate the incidence of such occurrences in the future.
	Such events can be classified as mortality, disability onset, turnover, among others categories and have a direct impact on post-employment benefits.
4.3.1.	General mortality
	According to CNPC Resolution No. 9 dated November 29, 2012, which amends CGPC Resolution No. 18, the suitability of a biometric table used for longevity projections should be determined by means of a specific study, the results of which confirm adherence, in the last three fiscal years, between the demographic behavior of the mass of participants and beneficiaries within the plan and the respective biometric table used.
	The general mortality table adopted for the SIP was a Basic AT-2000 Basic, segregated by sex. According to the independent actuary's report, the table was adopted based on technical studies that confirmed its adherence to the profile of the population in the plan and therefore its suitability to discount the actuarial liability.
4.3.2.	Disability onset
	Not applicable.
4.3.3.	Disabled mortality
	Not applicable.
4.4.	Turnover

Not applicable.

4.5. Age of retirement

Not applicable.

4.6. Family composition

Not applicable.

4.7.	Health care cost growth rate (HCCTR)
A	rate of 3.00% above inflation was assumed to reflect the growth of health care costs due to sector-

specific inflation. We understand that this rate is in line with general practices of the market, where rates fluctuate in the range between 1% and 4.5%, according to data developed by the post-employment benefits committee of the Brazilian Institute of Actuaries (IBA).


5. Independent actuarial calculations

SIP

Reconciliation (in R$)	12/31/2016
Present value of actuarial liabilities (PVL)	(4,054,901.20)
Fair value of plan assets	-
Surplus/(Deficit)	(4,054,901.20)
Non-recoverable surplus (effect of asset limit)	-
Total (liabilities)/net assets to be recognized	(4,054,901.20)

Actuarial obligations were determined according to the principles and standards established by the regulatory body, namely the National Health Agency (ANS), and are accounted for in accordance with the rules laid out by the Accounting Standards Board. (CPC-33 of the Brazilian Securities and Exchange Commission - CVM 695.)

6. Independent review of actuarial commitment

The actuarial commitment was calculated by an independent actuary. We recalculated the installments of Implemented Benefits as shown below, and believe that the calculation methodology and process are adequate.


CD Plan

Present Value of Obligations (in R$)	Actuary	PwC
Implemented	-	-
Vested	-	-
Total	-	-
Difference (R$)	-	-
Difference (%)	-	-

The CD plan does not have any liability/asset to be accounted for due to its defined contribution structure.


SIP
Present Value of Obligations (in R$)	Actuary	PwC
Implemented	4,054,901.20	4,005,318.10
Vested	-	-
Total	4,054,901.20	4,005,318.10
Difference (R$)	49,583.10
Difference (%)		-1.22%

Considering the inherent subjectivity of actuarial calculations of mathematical provisions related to benefit plans, we understand that the difference identified indicates the reasonableness of the calculations.

Such subjectivity results, for instance, from the manner by which ages are considered for the purpose of finding the probability of death (whether full or fractional or rounded); the method of rounding flow figures (number of decimal places considered – taking into account that the probability of death considered in our calculations has 6 decimal places, for example); whether income payments are accelerated or in arrears (i.e. made at the beginning or end of the period); asset family composition assumptions in retirement, among other instances where small choices can produce relatively small effects however with potential large absolute values.

Therefore, we understand that the difference presented is acceptable from an actuarial technical point of view, and we understand that the liability recorded is properly calculated.

7. Conclusion

Our examinations were based on information provided by both the actuaries responsible for managing the plan and the company, and we considered this information to be appropriate for the preparation of this report.

Only SIP liabilities are covered in this report. In addition to this plan, Ceron also has a defined contribution plan which by its own characteristics does not generate any risk to, or adopts any assumptions in respect of the company as plan obligations are limited to individual account balances established on the date of each evaluation. It should be noted that according to the documentation provided to us, the workers’ union has been sending letters to request that Ceron would make contributions to the defined contribution plan to cover the period in which the company did not have any pension plan in place for its employees. Such contributions are entitled

‘past service contributions’.

According to studies elaborated by ELETROS in September/2016, the aggregate amount of the aforementioned past service contributions is R$ 69,810,133.20 and can be amortized in monthly installments over a period of 5, 10 or 15 years.

It should be pointed out, however, that implementation of the aforementioned contribution is contingent on the approvals of both the competent private pension regulatory body, National Superintendency of Complementary Pension (Previc), and the State Enterprise Governance and Coordination Department (DEST), none of which has been granted so far. Thus, the so-called ‘past service contributions’ to the defined contribution plan do not generate any actuarial impact in view of the plan's characteristics.

Our numbers were calculated according to practices that we deem most appropriate when applicable, and should be taken into account together with the considerations below.

The post-employment benefit obligations recorded in the balance sheet, even where figures are presented with incidental differences which in our opinion relate to the methodology or assumptions adopted, would not, if altered, pose any insolvency risk to the plan.

The Severance Incentive Plan (SIP), which affords only health care for a fixed term of 5 years, has a liability of R$ 4,054,901.20 as of 2013. This liability is expected to decrease in view that this is a fixed-term plan with only two years remaining and new registrations are not allowed. The plan has an inherent deficit resulting from the fact that it does not have an asset to cover benefits and is funded by the flow of contributions.

We understand that employing a capacity factor to measure health care liabilities is not the best practice in the situation. Medical costs increase according to specific sector rules. For this reason, we understand that there is no loss of benefit value over time due to inflation and therefore the use of a capacity factor is not appropriate.

From a legal perspective, we understand that legal compliance is secured in that contributions are made according to the general rules applicable to the SIP.

Product 11 –Privatization Modeling Proposal

To the

Banco Nacional de Desenvolvimento Econômico e Social (“BNDES” - Brazilian National Bank for Economic and Social Development) Av. República do Chile nº 100 Rio de Janeiro - RJ

Attention: Ms. Lidiane Delesderrier Gonçalves - Contract Manager OCS 028/2017 October 2017 Dear All,

In accordance with our service contract OCS 028/2017 (“Contract”), executed between the BNDES and the Consórcio Mais Energia B (“Consortium”) on 02/14/2017, we present the result of our work made in the context of Privatization of the Distributors of the Eletrobras System.

The result of our work is detailed in this document “Product 11: Privatization Modeling Proposal” (“Report”) of Ceron, dated October 2017.

Our work was developed aiming solely at the objective to assist the BNDES, in the quality as responsible for the performance and follow-up of the privatization of concessionaire companies as per Decree 8.893, in the evaluation of Ceron, in accordance with the Contract and it was carried out on the basis of information provided by the administration of Ceron and on the premises that this information is true and complete. This information has not been subject to tests or verifications, except when expressly defined in the scope of our works.

In the case of access to the Report by third parties, it must be made available in full, provided that the applicable safeguard and limitations are known.

Sincerely,

PricewaterhouseCoopers Corporate Finance & Recovery Ltda., as leader of the Consortium.

Rogério Roberto Gollo

Marcio Jose Soares Lutterbach

** This document is a true copy of the original signed version delivered to BNDES and in the possession of Eletrobras.


		Product 11 –Privatization Modeling Proposal


*Summary*

Introduction			6
Section I - Privatization context			7
1.	Approach		7
2.	Context		9
2.1	Overview		9
2.2	Institutional and Management Model of the Brazilian Electric Industry		10
2.3	Financial assessment and sales modeling conjuncture		12
3.	Relevant aspects of the Privatization Process		14
3.1	CCC		14
3.1.1		Context	14
3.1.2		Negotiations	14
3.1.3		Negotiation operationalization	15
3.2	Other critical points, necessary adjustments and recommendations		15
3.3	Consent need in Financing Contracts		16
3.4	Deposit of Shares Owned by Eletrobras at FND		17
3.5	Remaining aspects to be considered		17
3.6	Payment methods		17
4.	Purpose of the Auction		19
4.1	Purpose of sale		19
4.2	Assessment of sale feasibility		19
5.	Relevant Aspects of Valuation		20
5.1	Relaxation of regulatory parameters		20
5.2	Debts		20
5.3	Total liabilities		22
5.4	Risks and Contingencies		22
5.4.1		Types of contingencies	22
5.4.2		Current status of contingencies	23
5.4.3		Negotiations to deal with contingencies	24
6.	Assessment of Synergies		25
7.	Adjustments on the Privatization model		30
7.1	Context		30
7.2	Base amount of valuation – Average between valuations of Services A & B		30
7.3	Relevant adjustments for privatization of Ceron		31
7.3.1		Adjustment to comprise updated balance sheet until June 2017	31

Product 11 –Privatization Modeling Proposal

7.3.2Adjustment related to Advance Payments for Future Capital Increases (AFACs)


7.3.3		Tax adjustments –Tax Losses and Negative Base	34
7.3.4		Adjustment of the relaxation of regulatory parameters	34
8.	Capital and Corporate Structuring		36
8.1	Proposed capital and corporate structuring – Overview		36
8.2	Minimum adjustment of the capital structure – “Stage 1”		38
8.2.1		Symbolic value of shares sale (privatization)	38
8.2.2		Capitalization alternatives	39
8.3	Investor capitalization – “Stage 2”		39
8.4	Eletrobras corporate stake option		41
8.4.1		Justification	41
8.4.2		Eletrobras corporate interest threshold	41
8.4.3		Participation of Eletrobras in the governance of the company	42
8.4.4		Procedure for Eletrobras to increase its shareholding interest	42
8.5	Classes of shares		43
9.	Shares offering to active and retired employees		44
9.1	Mechanism		44
9.2	Definition of active and retired employees		44
9.3	Offer General Conditions		44
9.3.1		Offer take and differentiated conditions	45
9.3.2		Offsetting differentiated conditions to Eletrobras	45
9.3.3		Offer Procedure and Purchase Limits	46
9.3.4		Follow-up by minority stakeholders of investor underwriting	46
9.3.5		New controller shares repurchase obligation	46
9.4	Shares not acquired by active and retired employees		47
Section II - Privatization proposal			48
10.	Summary of Ceron’s privatization proposal		48
10.1	Ceron’s Corporate Structure		48
10.2	Ceron’s Sales Price Definition		48
10.2.1		Result of economic-financial evaluations	48
10.2.2 Balance update adjustment			49
10.2.3		Regulatory parameters relaxation adjustment	51
10.3	Sale vs. Liquidation Evaluation and consequent “pure” concession granting		51
10.4	Potentially convertible liabilities		52
10.5	Eletrobras capitalization value – “Stage 1”		52
10.6	Shares offering to active and retired employees		53

Product 11 –Privatization Modeling Proposal

Introduction

This document refers to the report of Ceron Privatization Model Proposal, produced by the Consórcio Mais Energia B. In it, proposals are included regarding the distributor’s privatization modeling, including conceptual models, technical recommendations and calculated values.

The report is divided into three sections, presented below:· Section I - Privatization Context· Section II - Privatization Proposal· Section III - Auction Model Proposal

In Section I - Privatization Context, among other topics, the approach used to structure the modeling, the parameters that were used as guidelines to the analyses developed and conceptual aspects of the modeling are explained, including its main proposals, rationale and legal basis.

In Section II - Privatization Proposal, the technical and quantitative specifications of proposals made in the previous section are presented. The corporate structure is set out thereof as well as the results of the valuation, the calculated values of adjustments in the capital structure and Ceron's shares, in addition to the share offer conditions to employees, investors’ obligations and expected privatization schedule.

In Section III - Auction Model Proposal, procedural aspects of the auction of the distributor are detailed. In this section, recommendations are made concerning the model and sequence of auctions, auction variables, base of values for investors’ offers and classification criteria and the definition of the winner.

Finally, it should be noted that this document has been developed based on Ceron’s other privatization processes documentation. Among other items, there served as input for this Privatization Modeling Report, the result of the economical and financial evaluations conducted by Services A and B, as well as the legal, tax, accounting-equity, technical-operational, actuarial, human and environmental resources diligences developed by Service B.

Product 11 –Privatization Modeling Proposal

Fiscal and tax aspects: relevant fiscal and tax aspects were considered, as well as tax required adjustments, for the definition of the value and the process of privatization and sale of companies
Risk mitigation: as part of the process of definition of the selling price, it was necessary to evaluate the impact and value of not yet provisioned contingencies, as well as possible alternatives to mitigate them, considering the prospects of Eletrobras and the investor in order to reduce risks related to the sale transaction
Stakeholders and investors: to enable and optimize the process of privatization and sales modeling, the study considered the perspective of several Stakeholders (such as, regulating entities, government agencies and consumers), as well as investors, who had their interest in acquiring distributors and their points of view analyzed through market sounding studies
Evaluation of synergies: the possible synergies between the companies were also evaluated and considered in modeling, analyzing the opportunities for synergies of their operations to find possible levers of value
Groupings of grants: likewise, possible groupings for sale of companies were analyzed in order to enable and leverage the value of the sale of the six distributors that are part of this process of privatization
Process and sequencing of the auction: auction models and their procedural aspects, as well as the sale of sequencing alternatives of the distributors were reviewed to increase the possibilities of sale of the distributors and also to create value
Use of tariff lever: in modeling, alternatives were included regarding regulatory levers which provided a review of the level of balance of the grants relating to companies in privatization process, eventually correcting potential lags

When evaluating the nine perspectives addressed, the study made for the modeling of Ceron sale, along with other distributors, sought to be comprehensive and evaluating all relevant aspects to the process of privatization of the companies, identifying alternatives of the sales process optimization.

Product 11 –Privatization Modeling Proposal

2. Context

2.1 Overview

The process of privatization of Eletrobras’ Distributors was started in the 90’s and resumed in 2016 through Decree 8.893/2016, which qualified as priorities within the framework of the Partnership Program in Investment (PPI) the privatization of the distribution companies and designated the BNDES responsible for the implementation and monitoring of the process of privatization.

In this context, the BNDES hired Consórcio Mais Energia B to assist it in Privatization, involving from economic and financial valuation until the full diligence of current operations. Having completed the basic elements that allow attributing the value resulting from the distribution grants of electric energy, it remains to define how the privatization will actually take place. Such modeling combines corporate aspects, the form of capitalization, sales process, in order to increase the chance of success in attracting investors, as well as offering maximum competitiveness to obtain better conditions of offer to be received.

The guidelines emanated by the sectorial and macroeconomic policy makers, regulators and planning entities, establish the need to offer a quality service in the respective grant areas. One believes that the attraction of an operator from the private sector will have full conditions to raise the efficiency level and to remunerate the necessary investments to the full compliance with the market.

From the regulatory point of view, as a result of Public Hearings 094/2016 and 032/2017 of ANEEL [Brazilian National Electricity Agency] and Public Consultation MME 37/2017, several softening measures were introduced into the regulatory parameters, with the tariff model allowing conditions to bring back to balance the grant. It is unanimously manifested, both the discomfort with the precarious situation of the assignment condition, and the support to the efforts undertaken, so that one is successful with the privatization.

A process of evaluation of market interest (Market Sounding) allowed identifying the existence of companies with recognized competence in the industry - particularly in social economic, geographic realities and similar environmental realities - with capacity to execute the reorganizations required for this process, confirm the reasoning of attractiveness of the privatized companies for potential investors and understand the major elements of concerns. One may also establish a rather specific map of the different level of interest of the market among the several grants.

In this line, the vision of the sector investors could be obtained as to issues such as the grouping of the grants, the process of sale, sensitivity to different corporate models, the structure of capital to face the program of investments, the economic impact of the incorporation of investments to tariffs and the very contingencies bequeathed to the future operator, always with a view to optimize the competitiveness in the future auction.

In short, from this context important lines of direction derive for the model that will be sketched as follows:

Product 11 –Privatization Modeling Proposal

Incorporation of new investor who will be focused on the improvement of the service and economic, financial and operational recovery of the company
Prioritization of solutions that allowed the transference of all the grants to the investors - seeking models that minimize risk of auctions without interested shareholders
To make possible alternatives and solutions that allow generating value to the current shareholder without losses to the consumers and the public power, including mechanisms that make possible the capture of value in the medium and long terms in the future operation, since there is the need for capitalization of the distributors to make possible the privatization auction
Search for factors that lead to the increase of the rivalry between the potential interested shareholders, in order to provide greater competition

Such guidelines lead to solutions that are highlighted by the mitigation of failure risks, simplicity and pragmatism in the search for alternatives for privatization. Below, we present how the modeling should be structured so as to maximize the success of the process.

2.2 Institutional and Management Model of the Brazilian Electric Industry

The characteristics and peculiarities of the Brazilian electric industry have been considered in the study developed. Both its institutional model and its legal framework have been analyzed and used as parameter for the analyses proposed.

Recently, new laws sought to address emergent challenges within the national scope (as for example Law 12.783/2013, with provision on grants of generation, transmission and distribution of electric energy, reduction of sectorial encumbrances and affordability). In this context, for this report, as noted in the previous section, Decree 8.893/2016 is of particular importance, which resumed the subject of privatizations of the Distributors, being the BNDES responsible for the execution and follow-up of the process.

In fact, the edition of Law No. 13.360/2016, resulting from the conversion of MP 735/2016, brought a series of changes for the industry, including the supposition by CCEE of the competences attributed before to Eletrobras on the management of the account of Global Reserve of Reversion (“RGR”), as well as the Account of Energy Development (“CDE”) and of the Account of Fuel Consumption (“CCC”) from May 1^st, 2017, at no hard to the performance of Internal or External Control Agencies of the federal public administration on the management of these accounts.

Additionally, Decree No. 9.143/2017, that regulated Law No. 13.360/2017, by bringing provisions on the commercialization of electric energy, tried to provide the incentive to efficiency, to the correct allocation of the risks among the consumers and investors, as well as mitigate the obstacles to attract new investments to the electric energy industry, especially when establishing that the auctions of new energy and existing energy can be carried out fairly ahead of time and more relaxed, in addition to the possibility of the distribution agents to negotiate with free consumers and other agents from the Free Environment Contracting (“ACL”), sale contracts of backed by excess of energy contracted, as per ANEEL regulation.

Product 11 –Privatization Modeling Proposal

Furthermore, it must be highlighted that, by means of the Public Consultation No. 33 (CP

33), of the Ministry of Mines and Energy (“MME”), already closed, on ‘Improvement of the legal landmark of the electric industry’, proposals of legal measures had been discussed that make possible the future of the electric industry, searching sustainability in the long run

In addition, Law No. 13.360/2016 amended Law No. 12.783/2013, with the objective to make possible the bidding of companies under direct or indirect control of the Union, States, Federal District and Municipalities, whose grants had not been extending, foreseeing the possibility of the Union to promote bidding associated with the transference of the shareholding control of the concessionaire, granting a new grant contract for the period of 30 years. This law also establishes the possibility of inversion of the qualification stages and judgment of the auction, so as to guarantee greater speed and efficiency to the bidding process.

It should be stood out that, as far as the bidding of distribution or transmission grant associated to the transfer of control of legal person, provider of public service of electric energy is concerning, dealt with Law No. 12.783/2013, it became necessary to edit a regulatory decree, with the purpose to, among other conditions: i) to establish requirements to be observed by the controller of the responsible legal entity for the provision of the service of distribution of electric energy, for such bid; ii) attributions of the BNDES in the execution and the follow-up of the privatization process; iii) criteria for new concession without control handover (Decree Draft that regulates the bid of distribution grant associated with the utility control handover of legal entity provider of public service of electric energy).

The new grant contract applicable to the mentioned bid associated with the shareholding control handover of the concessionaire, whose draft was elaborated by Aneel at the request of the MME and submitted the public consultation, was object of new public consultation in the period of 08/28/2017 to 09/06/2017, in virtue of adjustments proposed by means of Ordinance MME No. 342/2017, due to the fact that it was noted the existence of unbalance regarding the operational costs, losses of electric energy and loans with resources from RGR, made to assure the continuity of the service provided under the assignment mode and that, by force of provisions of Law No. 12.783/2013, should have been assumed by the new concessionaire, which could make impracticable the intended bid.

Another point to be considered is with regard to the tariff process concerning the provision of public service of electric energy distribution by agency or entity of the federal public administration. It is highlighted that the Ordinance MME No. 388/2016, which approved the terms and conditions for the provision of such services, in accordance with art. 9, Paragraph 1, of Law No. 12.783/2013, was amended by Ordinance MME No. 346/2017, published in the DOU [Federal Official Gazette] on 08/31/2017, to establish that in the tariff process of year 2017, ANEEL should make flexible, in a temporary way, the regulatory parameters relating to the operating costs in order to enable the economic balance of the grant being bid pursuant to art. 8 of Law No. 12.783/2013.

It is further highlighted that the tariff relaxation resulting from ANEEL’s Technical Notes 351/2017, of 07/24/2017, and 149/2017, of 09/08/2017, which restores levels of regulatory parameters – such as DEC/FEC, PMSO and RGR - aiming at the economic-financial balance of the grants of electric energy under analysis.

Finally, it is stood out that, considering the schedule foreseen for conclusion of the privatization process, as one will see below, it is quite probable that Ordinances MME 420 to

Product 11 –Privatization Modeling Proposal

425/2016 that designated the Distributors of Eletrobras (Amazonas, Boa Vista, Ceal, Cepisa, Ceron and Eletroacre) as responsible for the provision of the public service of distribution of electric energy until the supposition of a new concessionaire or up to December 31^st, 2017, whichever occurs first, deserve to be amended to extend such service provision deadline for a period that suffices to the conclusion of the privatization process.

2.3 Financial assessment and sales modeling conjuncture

As it shall be shown below, in Item 5 – Relevant Aspects of Valuation, in the course of the due diligence and financial evaluation of Eletrobras’ distributors, relevant issues were identified affecting significantly the value of the shareholder of the companies.

Initially, it was assessed that these organizations have amounts of debts of high values. These debts were accumulated by Eletrobras’ distributors over the years, both with the Holding Company (with loans of various types) and with suppliers. Such debts, in turn, often continue to be rolled over or have increasing cost in relation to the non-payment of the principal or even of interests.

It was also identified that the distributors of Eletrobras have contingencies – additional to those provided on the balance sheets – of significant value. These contingencies, from judicial and administrative proceedings and tax aspects, fiscal and labor not yet materialized, among others, also contribute to the reduction of the value of the equity of the companies.

Additionally, it has found in financial and operational evaluation that these companies demand high values of investments in the early years of the new grant. These investments are required, both to facilitate the improvement of financial performance expected and to meet regulatory metrics of service level.

Thus, even in a valuation in which there is the expectation of bold operational and financial performance optimization of the six distributors of Eletrobras in the privatization process, the factors listed overlapped to improvements, resulting often in a negative value to the shareholder.

It should be emphasized that the financial evaluation has already considered the new draft of the grant contract, resulted from contributions in the Public Hearing No. 094/2016 and the Technical Note No. 182/2017 of ANEEL. The regulatory body also reviewed and identified that these grants are unbalanced, granting regulatory parameter relaxation (Technical Notes No.

351/2017 and No. 149/2017, this last part of the Public Hearing No. 032/2017) to bring the grants back in balance, which will result in increased tariff revenues and reduction of loan value of RGR. Consequently, the financial evaluation conducted by the Consortium considered the relaxation made by ANEEL.

It is also highlighted that, in accordance with the Decree Draft that regulates the grant bid of distribution associated with the transfer of control of legal entity service provider of electric energy, dealt with by Law No. 12.783, of January 11^th, 2013, the distributors of Eletrobras to be privatized that are in areas of grant benefited by the relaxation of regulatory parameters, deriving from the Technical Note No. 351/2017 must have specific treatment. If the value to the shareholders of these companies is positive in light of regulatory flexibilizations granted, the relaxed parameters must be readjusted so that the value to the shareholders of these companies is equal to zero. Thus, the possibility that the consumers of the areas of the grant in question are

Product 11 –Privatization Modeling Proposal

3.	Relevant aspects of the Privatization Process
3.1	CCC
3.1.1	Context

It should also be noted that in this model, it is possible that Ceron has values related to CCC, previously provided as amounts receivable in the balance sheet, reverted to accounts payable in view of technical decisions of ANEEL. The accounting difference in question has relevant value:


VALUES REGARDING CERON CCC

A) Credits¹(asset) on the balance of Jun/17	R$ 3,830,608,000.00
B) Payables estimate²(liabilities)	R$ (733,256,890.57)

C = B-A) Accounting difference estimate between credits and payables R$ (4,563,864,890.57)

Note: Reference values, subject to diligence and auditors’ and regulators’ assessment

1)	Source: Distributor’s financial statement from June 2017
2)	Estimate value, not under diligence

We understand that this issue is still under discussion between the interested parties and, therefore, ANEEL's unfavorable decisions to Ceron can be reversed. However, the potential reversal of an unfavorable decision should not occur in a timely manner for the completion of this document or even within the timeline of privatization planned for the distribution company.

It is likely that the attractiveness of the auction to investors be compromised without definitions relating to CCC. The possible loss of credit rights – and the need for return of values – would remove any economic return of the business. The values under discussion are quite significant and relevant when compared to the economic value of the distributor. Thus, it is possible that the risk of loss relating to CCC does not justify the potential gains with the acquisition of the company by the investor.

In this regard, the proposed model for privatization seeks to neutralize potential effects on the appraisal resulting from the uncertainty in the amount effectively recognized of the accounting difference of CCC's credits. This proposal increases the assertiveness of the value for the privatization of Ceron, as it enables Eletrobras to enjoy any upsides arising from the reduction of this potential loss amount.

3.1.2 Negotiations

Given the relevance of the value discussed for the valuation of the Ceron and the unpredictability of the deadline for a final decision regarding this topic, it is recommended that the responsibility – including possible benefits and burdens – concerning the current discussion about the CCC credits be transferred from Ceron to the holding company of Eletrobras. Thus, the effect of the current questioning would be neutral in the financial evaluation of the distribution company and in its sales model.

Product 11 –Privatization Modeling Proposal

To this end, it is proposed that a transfer of the receivables concerning CCC equivalent to value in dispute be made – and burdens in equal amount. This transfer would occur through the assign of current rights relating to CCC credits and financial obligations (for example, payables to CCC, other debts etc.) equivalent from the subsidiary to the holding company.

As a result, in the case of an unfavorable decision, Eletrobras would be charged with the burden of loss, which would occur if the issue were priced on the sale model for the process of privatization of the distributor. In the case of a favorable decision, Eletrobras would reverse this potential loss, receiving the CCC credits and bearing obligations of equivalent value.

It stands out, also, that the transfer of credits and obligations related to the CCC must have the consent of the regulators and come accompanied by considerations of external auditors of the company, following the approval of the level of governance in charge.

Thus, with the absorption of these credits by Eletrobras, the impact on the values in question is considered neutral, without interference in the shareholder value of the company or to the privatization process.

In the case of Eletrobras cannot absorb the credits as per the recommended proposal – or that of any financial, technical or legal limitation occurs - that impedes the transfer of obligations in an amount equivalent to the credits, it is suggested that the holding company considers the possibility to capitalize the distributor. Such capitalization may occur at the discretion of Eletrobras, according to the best alternatives for the state-owned company.

3.1.3 Negotiation operationalization

In order to facilitate negotiations, Eletrobras should, among other things that may be needed:

i)	Define the value and availability of CCC rights and obligations in an amount equivalent to the subsidiary transfer to the holding
ii)	Analyze financial and accounting specific effects, among other aspects relevant to the company
iii)	Analyze corporate and legal specific requirements to follow, as well as realize them in case one proceeds with the recommendation
iv)	Seek the consent of regulators for the operation

3.2 Other critical points, necessary adjustments and recommendations

For Ceron, there are no critical points to impede its privatization process.

During the process of Legal Due Diligence of Ceron some critical points were described in the Report and displayed in its Executive Summary. Although not inhibitory to the process of privatization of this distributor, the new investor should be aware of them so that he can make applicable arrangements.

Among the important issues, but not deterrent, to be considered, are highlighted the contracts of financial nature, whose prior consent of the creditor is recommended in order to avoid the prepayment of the debt.

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3.3 Consent need in Financing Contracts

Some financing contracts signed by the distributors may have the need to obtain prior and express consent from the creditor in the event of a change of control of Ceron.

Otherwise, according to the terms of each contract, there may be legal and/or financial implications to Ceron, Eletrobras, investor and, eventually, to the privatization process, depending on the possible prepayment of debt if the commitment to payment is not assumed by the new investor.

Thereby, the financing agreement with the need for consent from the creditor are listed below, and must have their applications addressed by Ceron and Eletrobras:


N°	Nome do Documento		Credora	Data de Assinatura
	Private Debt
1		Petrobras Distribuidora S.A.		12/31/2014
	Acknowledgement Instrument

Contract

Creditor:		Petrobras Distribuidora S.A.
Intervenor:		Eletrobras
Object:		Recognition of a debt at the total amount of R$ 961,061,034.55 related to the
		debt pursuant to supply of fuel in the period from November 1^st, 2014 to June
		30^th, 2015
Amount:		R$ 961,061,034.55
Interest:		The update of each installment will be made based on the SELIC reference rate
Grace period:		Not applicable
Principal payment:		18 monthly installments
Guarantees:		Fidejussory guarantee of the Federation, Guarantee Pledge Contract related to
		the credits CERON holds at CDE; and the amount of R$ 349,045,658.94 will be
		guaranteed by Eletrobras, as several debtor
Relevant obligations:		CERON is forbidden to grant the contract rights and obligations without prior
		and expressed consent by Eletrobras
Anticipated maturity:		The contract will be terminated in advance in case of:
		(i) non-payment of 3 consecutive or alternate installments, provided that the
		default is not solved by CERON within 5 business days from the due date of the
		last delayed installment;
		(ii) liquidation, request for judicial or extrajudicial recovery, claim,
pronouncement or homologation of bankruptcy;
		(iii) protest of payment slips issued by CERON or obligation over R$
		500,000,000.00 with a bond by the Federation or if any other judicial or
		extrajudicial measures is proposed against CERON, which might provenly affect
		the debt payment capacity;
		(iv) succession of CERON, or any kind of corporate reorganization, which leads
to change in the share control of Eletrobras or
		CERON, without prior consent by BR Distribuidora;
		(v) anticipated termination of any other contract of financial nature signed by
		CERON; and,
		(vi) inclusion of provisions, which lead to restrictions or loss of capacity for
		payment of the financial obligations pursuant to the contract in a corporate
		agreement or corporate bylaws of CERON
Other important clauses:		Not applicable

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3.4 Deposit of Shares Owned by Eletrobras at FND

The Nominative Share Record Book of all Distributors mentioned blockage of all shares owned by Eletrobras to the benefit of the National Privatization Fund – FND, administered by BNDES, in compliance with the Law no. 9.491/1997.

3.5 Remaining aspects to be considered

Remaining aspects shall be considered, the measures of which are within and outside the scope of Distributors are vital for the privatization process, as per the chart below:

ACTIONS ON DISTRIBUTOR’S SCOPE

Obtaining authorization from Executive Board, Supervisory Board, Board of Directors to perform capital increases on the Distributor

Performance of General Meeting specially convened to approve the Distributors’ capital stock, as well as an increase of capital stock by underwriting of new shares

ACTIONS ON ELETROBRAS’ SCOPE

Obtaining authorization from Executive Board and the Board of Directors to perform the privatization of Distributor Performance of General Meeting convened to approve the privatization of Distributor Performance of the necessary procedures to fulfill CVM [Brazilian Securities and Exchange Commission], NYSE, and Latibex

ACTIONS OUTSIDE THE DISTRIBUTOR’S AND ELETROBRAS’ SCOPE

Obtaining prior approval from CADE provided on articles 88 and 90 of the Law 12.529/2011 and CADE Resolution no. 02/2012 Obtaining prior consent from ANEEL for share control transference (Art. 27 of the Law 8.987/95 Art 4, XI, of Annex I of the Decree 2.335/97, in addition to the provisions of ANEEL Normative Resolution 484/2012) Obtaining approval from the Board of the Investment Partnership Program (CPPI - Conselho do Programa de Parcerias de Investimentos) regarding operational modality, conditions and adjustments to be applied to the privatization (Law 9.491/97) Follow-up, surveillance, and evaluation of the privatization process by the Federal Court of Auditors (TCU - Tribunal de Contas da União) (IN TCU 27/1998)

3.6 Payment methods

Under the Law No. 9.491/97, the payment methods in a privatization process shall be recommended by the National Privatization Council (CND), now replaced with the Board of the Investment Partnership Program of the Presidency of the Republic (CPPI), for approval by the President of the Republic. The latter may authorize remaining payment methods within the scope of the National Privatization Program, as recommended by the CPPI.

The Law also requires disclosure of selected items on the conditions for disposal of the concerned company’s shareholding control, through publication at the Brazilian Federal Official

Gazette and in nationally recognized newspapers. In particular, the following shall be disclosed:

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As Ceron met the requirements of these four perspectives, it was concluded that it would be possible to sell the company in a tender associated with granting the concession.

5.	Relevant Aspects of Valuation
5.1	Relaxation of regulatory parameters

It should be taken into consideration that the companies’ valuation already considers, among the flow perspectives, the consequences of the Technical Notes 351/2017 and 149/2017 of ANEEL, the latter being the result of the Open Court 032/2017, providing for loosening of regulatory metrics for financially unbalanced concessions, including Ceron.

Such ANEEL Technical Notes loosened for the company the regulatory values of the PMSO, Non-Technical Loss and RGR metrics of the designation period. As a result, there is increased financial setoff through tariff to the distributors and the resulting decreased volume of RGR loan, increasing the revenues thereof and, accordingly, its cash flow.

Such parameters shall be loosened from the tariff process dated 2017, initiated on November 30 of this year, up to the first regular review of the new utility to be contracted by means of a bid, estimated to be held in 2023.

Such parameters shall be used as auction variables, with their methodology and values being explained in Item 12.6 - Auction Value base for ‘Combined Discount Index in the Regulatory Flexibility and Grant’.

5.2 Debts

The indebtedness levels of Eletrobras distributors are quite high, and the debts may be divided into three major groups: Debts with Eletrobras; Debts with Specific Third Parties and Debts with Other Third Parties. Debts with Eletrobras in turn may be rated according to their origin: Ordinary Resources, RGR, Banco Mundial and Eletrobras related parties.

a)	Debts with Eletrobras: refer to funds with the Holding or through it by means of onlending. Since Eletrobras itself holds the credit rights, the debts may be used by the company as means to optimize the capital structure of its distributors.
	o	World Bank: Eletrobras holds funds obtained with World Bank for the purpose of investing in improved infrastructures, project named by the companies as “Projeto Energia+” [Project Energy+]. Such funds are then lent to distributors as loans and financing.
	o	RGR (Global Reversal Reserve): Refers to amounts raised by Eletrobras for the distributor with the Global Reversal Reserve (RGR). Thus, the sums are due by the distributor to Eletrobras, associated with funds raised from the RGR. The amounts found in the balance sheet, as of the base date of this report (12/31/2016) are mostly from loans obtained prior to the designation period.
		§	RGR pre-PPST (temporary service provision period): Amount of debt arising out of the pre-PPST period, when the funds were aimed at financing investments of the distributors.

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§	RGR PPST (temporary service provision period): Debt amount arising out of the PPST period, initiated in November 2016. Within the scope of the concession agreement termination and beginning of such

period, the RGR onlending changed their purpose to maintaining the companies’ activities ensuring the so-called “Appropriate Remuneration”, as defined in the Technical Note 331 dated September 13, 2016. By the end of this Item, the estimated sums of the debts with RGR are provided until the end of February 2018 (date estimated for entry of the potential investors in the operations), considering the fund-raising operations in the service provision period.

o	Ordinary Resources: Own fund onlending by Eletrobras to the distributors, through loans, usually with low financing cost and for the purpose of covering operating deficits. Therefore, this debt is directly due from the distributor to the Holding, without involving Third Parties.
o	Advance Payment for Future Capital Increase (AFAC): Refers to funds contributed by Eletrobras at the distributors for future capital increases.
	Usually, AFACs are paid-up as capital within up to one year of their composition, but that is not a requirement, and they may be kept in the balance sheet as distributor debt. Currently, only Eletrobras is responsible for contributing AFAC sums in the distributors.
o	Related Parties: Refer to debts contracted with other Eletrobras distributors or companies, except the Holding. Among the major related parties with effective credits we may mention, for instance, Eletronorte, Furnas and Chesf.
	Like in the case of the debts contracted directly with Eletrobras Holding, the company has preference over the funds, and may use the same alternatives as mentioned in the prior item. However, in this group of debts, there are legal and corporate aspects required to be noted vis-à-vis any measure. It should be stressed that variables such as the cash flows, the amount and the own capital structure of the creditor companies may be affected due to an attempted use of such credits.

Debts with Specific Third Parties: Debts of such nature are mostly overdue payment liabilities concerning fuel supply agreements (therefore, rated as debt by the Accounting-Equity Due Diligence), due by some of the distributors which are parties to this privatization process. Among the major creditors, we have Petrobras and Cigás.

Debts with Other Third Parties: refers to debts contracted with other parties than Eletrobras, its distributors, Petrobras or Cigás. The remaining creditors of the distributors and debt instruments are considered in this group, among which there are domestic public banks, such as Caixa Econômica Federal, private financial institutions and other funding agents. The procedures of the Accounting-Equity Due Diligence also included to the balances of Debts with Third Parties the amounts concerning overdue payments with suppliers, including, for example, overdue liabilities with CCC (Fuel Consumption Account).

The RGR PPST accounting balances reported to this Consortium by Ceron in December 2016 and June 2017 are shown below:

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from both the reviewed sums provisioned and from identification of unmapped contingencies and their estimated value.

Contingencies, type of rating and amounts derive from the legal, accounting-capital and environmental audits conducted at Ceron.

There are three types of contingency, according to their probable loss of the concerned sums and, accordingly, incorporation into the valuation process, as listed below:

	Probable:
	o	High risk of losing the sum involved in the judicial and administrative proceedings
	o	Usually priced in valuations, decreasing the equity value
	Possible:
	o	Potential risk of losing the sum involved in the judicial and administrative proceedings
	o	Usually not priced in valuations, being eventually dealt with in specific
	Remote: negotiations between the selling and the purchasing parties
	o	Low risk of losing the sums involved in the judicial and administrative proceedings
	o	Usually not priced in valuations

5.4.2 Current status of contingencies

Find below the amounts and percentages of contingencies for Ceron, according to their risk rating level.

In R$ MM
DETAILING OF CERON CONTINGENCIES


	Likely	Probable	Remote	Total
Litigious	132.84	-	-	132.84
Taxes	260.60	918.58	64.14	1,243.32
Labor	107.10	52.64	-	159.74
Actuarial	-	-	-	-
Total	500.54	971.22	64.14	1,535.90

In %
DETAILING OF CERON CONTINGENCIES

	Likely	Probable	Remote	Total
Litigious	27%	0%	0%	9%
Taxes	52%	95%	100%	81%
Labor	21%	5%	0%	10%
Actuarial	0%	0%	0%	0%
Total	33%	63%	4%	100%

Note: ‘Litigious’ contingencies refer to materialized lawsuits and include actions from different areas (taxes, labor, civil, environmental, and regulatory). The others refer to risks mapped in the respective diligences, which do not have materialized suits.

Product 11 –Privatization Modeling Proposal

Among the contingencies for classification as “Probable”, in Litigation, there are about R$

127 million related to taxation suits. In Taxation, approximately R$ 253 million are related to accessory obligations. In Labor, R$ 104 million are related to outsourcing of target activity.

Among those for classification as “Possible”, Taxation is at approximately R$ 677 million related to PIS [Social Integration Program] and COFINS [Contribution for Social Security Financing] falling upon reimbursement of CCC, R$ 130 million in non-technical loss of power and R$ 109 million to ICMS [Tax on Goods and Services Marketing] on CDE and Low Income subsidies.

In addition to the provided contingencies, there are also contingencies concerning environmental adaptations in the amount of R$ 38,717,204.75 required for distributor. Such values, however, were previously deducted from the equity value in the company’s valuation.

It should be stressed that the base date of the contingencies is 12/31/2016 and that such sums are in addition to those provisioned in the distributor’s balance sheet dated December

2016. The full details of the contingencies are in the audit reports.

5.4.3 Negotiations to deal with contingencies

Dealing with such distributor contingencies is relevant to enable eventual adjustments to the company’s price between the selling and purchasing parties. However, after developing several legal and financial analyses on contingencies, it was concluded that Eletrobras would avoid keeping future liabilities – after privatization – with the purchaser related to contingencies, in addition to eventual legal provisions allowing for the purchaser to question or file actions in the future to Eletrobras.

Thus, the adjustment definition shall occur prior to entering into the share purchase and sale agreement. Therefore, we recommend the distributor privatization to consider prior corporate adjustments between the parties as part of distributor’s sale price definition. As a result, new value adjustments or corrections concerning these items shall not be conducted after the privatization.

Contingencies whose assessments are Probable Loss, due to the high chance they have to lose the sums involved in the respective proceedings, should be deducted from the shareholder’s value prior to transferring the shareholding control. Likewise, contingencies rated as ‘Possible’ and ‘Remote’ Loss should not have their value deducted from the company’s sale price.

‘Probable’ Contingencies: their amount shall be discounted from the equity price due to decreased chance of success in the proceeding and resulting probable loss of the value involved in the claim;
‘Possible’ and ‘Remote’ Contingencies: their amount shall not be discounted from the equity price considering the chance of success in the proceeding and reduced probable loss of the value involved in the claim.

It should be stressed that several possibilities were analyzed to deal with contingencies, but all of them were proven to be financially unfeasible, with great operating complexity or with legal hindrances and risks.

Product 11 –Privatization Modeling Proposal

purchasing company, being questionable to advance its pricing in the minimum amount

Companies can be privatized at different times – e.g., such as Amazonas, which would not match the different nature groupings
Ungrouped concessions can increase competitiveness between the bidders, increasing competition and resulting into higher final price, but differently from pre-estimated synergies, avoiding the risk of empty offers for a grouping

It should be stressed that grouping can be used for pragmatic aspects, deriving from objective assessment aspects (e.g., grouping to minimize the required capitalization) and the own interest of investors (mitigating risks that a less attractive concession is not successful in the privatization).

In summary, a wide assessment, allied to the discussed context, does not construe as consistent the synergy incorporation to the minimum price and, accordingly, inexistence of returns to the proposed model.

Such recommendation occurs vis-a-vis the instruction that no concession groupings should be conducted since it is construed that an open model shall tend to increase the competition between the shareholders. Thus, there would be not only an increased number of offers –avoiding the chance for auctions without bidders – but also increased prices offered. Such prices, in turn, would be more appropriate to the level of synergy the investors shall have when inserting such companies into their management model.

Product 11 –Privatization Modeling Proposal

7.	Adjustments on the Privatization model
7.1	Context

The privatization model is made from the results of the due diligence reports and economic-financial assessments. However, for the final proposal of capital and corporate structuring of the distributor, it is necessary that additional adjustments are conducted.

The adjustments are carried out for the privatization model to meet the required legal instructions and comprise the latest information available concerning the economic-financial condition of the distributor.

Adjustments made follow the stages provided below:

ADJUSTMENTS FOR PRIVATIZATION MODELING

= Mean of Services A and B

(+/-) Consolidated adjustments
Balance Sheet Adjustments
(+/-) Asset and Liability Adjustments

(+)	RGR PPST Reincorporation
(-)	Reclassification of AFACs as Debt

(-)	Tax Adjustments (Tax Loss and Negative Base)
=	Adjusted Equity Value
(-)	Reduction adjustment of tariff relaxation
=	Final Equity Value

The following topics describe the adjustments made. Their amounts are detailed in Section II

Privatization proposal.
Base amount of valuation – Average between valuations of Services A & B

Under Decree 2.594/98, providing for the National Privatization Program, Ceron sale model shall consider the financial assessments conducted by Services A and B contracted by the State-owned bank, conducted with the base date of December 2016.

Within such context, based on the equity values drafted by Service A reported through the Letter AD/DEADE3 No. 14/2017, it is proposed that the equity value considered as basis for the financial and corporate model of Ceron shall be the simple average of the equity values defined by Service A and Service B. The formula is below:

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Equity value average = (Equity value Service A + Equity value Service B) / 2

As a result, an assessment basis is obtained with reduced chance of distortions since it considers the analysis of two different assessing companies. It is construed that both assessing companies are fully qualified to analyze the companies’ value and that the natural amount differences are due to the inherent subjectivity of interpretations and assumptions of each of them. Thus, any amount adopted among those provided by such companies would be acceptable.

We should also consider that, by using the theoretical concepts and technical tools usually accepted by the experts and the market, definition of assumptions and parameters of a financial assessment has the subjectivity of its developers, which is inherent to valuation of a company.

Thus, the Enterprise Value of a company, representing its projected cash flows, carried at present value by a discount rate, are subject to specific interpretations of their appraisers.

Therefore, it is construed that one-sided selection of only one of the amounts provided by both appraisers could give room to greater assessment distortions vis-à-vis the market value considered by potential investors of such companies. For example, if choosing the lowest between both values, the investor could be benefited. In turn, if choosing the largest between both values, there could be a risk that it would be distant from the market assessment, reducing the auction attractiveness. Finally, choosing an arbitrary amount – other than the average –between both values assessed would not be logical.

In the case of Ceron, the Enterprise Value estimated by the Services A and B are in close inter-values, lower than 20% in difference between them, benefiting the average use.


ENTERPRISE VALUES OF CERON - MEAN OF SERVICES A AND B

Service A	R$	1,524,512,239.58
Service B	R$	1,264,573,655.87
Mean of Services A and B	R$	1,394,542,947.72
Percentage variation¹		17%

1) Variation calculated as the module of lower value divided by the higher value

As a result, using the average of the amounts assessed by Services A and B is the most effective alternative to define the privatization price of Ceron.

7.3	Relevant adjustments for privatization of Ceron
7.3.1	Adjustment to comprise updated balance sheet until June 2017

As means to minimize eventual financial discrepancies between the valuation base date and the latest balance sheet available for Ceron (updated until June 2017 and not audited by the Consortium), updates are being made as to the balance sheet accounts related to indebtedness and working capital, in addition to specific accounting adjustments.

Accounts with their amounts updated are listed below:

Product 11 –Privatization Modeling Proposal


Assets	Liabilities
Current	Current
Cash and cash equivalents	Financing and loans
Securities	Lease
Clients	Debt charges
Taxes to be recovered	Suppliers
Reimbursement rights	Taxes payable
Warehouse	Social and labor obligations
Services in progress	Reimbursement obligations
Regulatory asset	Accounts payable to related parties
Sureties and judicial deposits	Estimated obligations
Financial asset	Sectorial charges
Assets destined to disposal	Post-employment benefits
CDE repayment	Regulatory liabilities
Others	Research and development
	Financial liabilities
	Others

Non-current	Non-current
Clients	Financing and loans
Taxes to be recovered	Lease
Taxes to social contributions	Suppliers
Sureties and related deposits	Taxes payable
Reimbursement rights	Reimbursement obligations
Regulatory asset	Accounts payable to related parties
Others	Provision for unsecured liability in controlled
Investments	Post-employment benefits
	Regulatory liability
	Sectorial charges
	Advance for future capital increase
	Research and development
	Others

The balance sheet accounts listed above refer to those comprised of this Consortium as

Working Capital (e.g., ‘Customers’), Net Debt (e.g., ‘Cash and cash equivalents’) and other capital accounts not considered as Working Capital or Net Debt (e.g., ‘Investments’). The understanding is the same as that made by the Accounting-Capital Diligence and the Economic-Financial Assessment. Such amounts exclude the remaining balance sheet accounts not listed above.

RGR PPST (for the designation period) also received different approach in the privatization model, as well as in the Economic-Financial Assessment conducted. Under the Law No. 12.783 dated 2013, the Technical Notes 351/2017 and 149/2017 of ANEEL and the Draft of Share Purchase and Sale Agreement, loosening was established for regulatory parameters for the distributor, including the RGR PPST. Payments concerning the loans contracted with RGR concerning the designation period shall have tariff recognition as components of Installment A. Since such tariff recognition follows the neutrality concept, the component was not considered when calculating the Installment A, since its consideration was also not considered for the purposes of this report.

Therefore, since the RGR PPST has tariff coverage, not impacting the equity value, its balances – included into the Liabilities in the account of ‘Loans and Financing’ – were positively reincorporated into the amount to the shareholder.

It is also stressed that, for the accounts of ‘Assets’ (property and rights), when there is positive variation, they increase the shareholder’s value. Therefore, being added to the equity value of the distributor. In the case of negative variation in turn, they reduce the amount. For the accounts of ‘Liabilities’ (obligations), the adjustment is inverted in relation to the ‘Assets’.

Product 11 –Privatization Modeling Proposal

For positive variation, the shareholder’s value is reduced, and, for negative variation, such amount is increased.

The adjustments excluded the accounts of ‘Liabilities’ concerning variations in the provisions for contingencies, litigations and civil, tax and labor claims. The reason is the probable overlapping between the new provisions made in the statements (after the valuation base date of December 2016) and the amounts of contingencies made by the Consortium. The amounts made are related to the same topics, in addition to the amounts of provisions of the financial statements and discounted from the shareholder’s value. Thus, the adjustment related to provisions for contingencies is avoided to occur in duplicate, leading Eletrobras to make increased contributions than those actually required.

Detailed amounts and the adjustment balances are provided in Item 10.2.2 - Balance update adjustment refer to the consolidated balance between the amounts of December 2016 and June 2017, which may be positive or negative. Balances of fiscal benefit and negative CSLL [Social Contribution on Net Income] basis were also updated to June 2017.

The resulting amount is used as basis for the adjustment in loosened regulatory parameters. The adjustments were solely applied in the equity value, not being extended to any other income.

7.3.2 Adjustment related to Advance Payments for Future Capital Increases

(AFACs)

Furthermore, if the distributor has AFACs, another adjustment is made, with the amounts concerning AFACs being considered as debt. Until the updating of the balance sheet dated June 2017 – last updated until this report was concluded – no existing AFAC was used to increase the capital.

Thus, we suggest no new capital increase by using the AFACs of distributors by Eletrobras. As an alternative, its amounts shall now be construed as debts in the balance sheet (and may be used as an additional alternative for the capitalization to be conducted by Eletrobras outlined in

‘Stage 1’, as well as the remaining options provided).

Taking into account that, once approved, the CPPI Resolution with definitions of financial and corporate adjustments to be made in the distributor under privatization, it is not advisable that new corporate amendments are made. It means that, if paying-up of the AFACs is after the CPPI publication, there is great chance that the numbers established in such CPPI Resolution will not comply with the distributor’s capital stock after capital increase by using the AFACs.

Thus, conflicts will be avoided concerning the number of shares to be subscribed, as well as their underwriting amount, in addition to eventual legal conflicts or non-compliances.

We should also consider that there are no relevant financial benefits in paying up the AFACs instead of considering them as debt. The effect upon the equity is neutral, since the new indebtedness amount shall be part of the adjustments of the model. Eventual savings of the distributor with debt taxation costs (e.g., IOF) shall be offset with benefits of the reduced basis for collection of the distributor’s income tax and with adjustments for inflation of the AFACs

(e.g., SELIC), which shall be due to Eletrobras.

Product 11 –Privatization Modeling Proposal

It is also stressed that the eventual paying-up of AFACs requires several levels of approvals, including internally at distributor and Eletrobras, as well as externally from the respective governmental agencies (e.g., MME, GCEST and PGFN).

Finally, we note that, until the latest information available for this report, the distributors’

AFACs funds solely derive from Eletrobras. Detailed adjustments and amounts related to the AFACs are found in Section II - Privatization proposal.

7.3.3 Tax adjustments –Tax Losses and Negative Base

In the first semester of 2017, the distributors used part of the Tax Losses (Individual Taxpayer Income Tax – IRPF) and Negative Base (Social Contribution on Net Income – CSLL) to liquidate tax debts. Since the economic-financial analysis of the distributors considers the use of these benefits positively in their cash flow, once used, such benefits must be excluded from the evaluation.

Thus, for the financial modeling, the balances of Tax Loss and Negative Base used between January and June 2017 have been deducted from the tax balances existing in December 2016, base date used in the economic-financial analysis.

7.3.4 Adjustment of the relaxation of regulatory parameters

The adjustment in the relaxation of regulatory parameters aims at complying with ANEEL Technical Note no. 149, dated September 8, 2017, in order to reach the economic equilibrium of the concessions of designated distributors, defined under the terms of Normative Resolution no. 748/2016.

Thus, the Draft of the Decree that will govern the bidding of distribution associated with the transfer of control of legal entity providing the electric power service, as per Law 12.783/2013, establishes that, in case the value to the shareholder of Ceron resulting from the valuation is positive (which also considers the adjustment of the balance update) based on the relaxation of regulatory parameters, the value of relaxed parameters must be registered so that the value to the shareholder is zero. That is, in case Ceron had negative value to the shareholder before the relaxation of regulatory parameters, and such relaxation results in positive value to the shareholder, the value of the relaxed parameters must be reduced to the amount necessary for the value to shareholder to be equal zero.

The relaxed regulatory parameters of Ceron are listed below:

RELAXED PARAMETERS

Non-Technical Losses
PMSO
RGR PPST

The adjustment of the relaxed regulatory parameters is applied to values of equity value (average of services A and B), corrected with the other adjustments specified (balance update, RGR PPST, AFAC, Tax Loss and Negative Base).

In order to zero the value to shareholder, the relaxed values of the relaxed parameters shall be adjusted. The reason is that they have a direct effect to the first years of the concession and

Product 11 –Privatization Modeling Proposal

raise the rate to the consumer in a period in which other exceptional rate adjustments are in force.

As detailed in Section II - Privatization proposal, the relaxed values will be used as variables of the privatization auction, after the eventual adjustment of these parameters to zero the value to shareholder. In addition, the RGR PPST will also be used as an auction variable.

It is also worthwhile noting that in case the value to shareholder of the distributor is negative after the regulatory flexibilization, it will not be necessary to adjust the value of relaxed parameters. In this scenario, the relaxed value shall be fully valid as a base for the bids of investors in the auction.

Product 11 –Privatization Modeling Proposal

This stage, as well as its premises and parameters, is detailed in Item 8.2 - Minimum adjustment of the capital structure – “Stage 1”.

Investor capitalization – “Stage 2”

“Stage 2” is a stage after “Stage 1”, and optional to Eletrobras.

It is important to stress that the capital structure of privatized companies needs to be balanced after the sale. This equilibrium is important to assure that the company will have financial health to honor its obligations – such as investments forecasted for the period of concession – and overcome eventual adverse conditions.

This, the modeling determined that the investor stakeed in acquiring the company, in addition to buying the shares held by Eletrobras at the company of symbolic value, will also invest funds and resources to balance the capital structure of the company.

This stage, as well as its premises and parameters, is detailed in Item 8.3 - Investor capitalization – “Stage 2”.

Eletrobras corporate stake option

In order to allow Eletrobras to have economic and financial benefits in the future with the privatization of its distributors, the modeling foresaw the possibility for the state-owned company to remain as a shareholder of the companies sold, holding only a minimum percentage of corporate stake right after the disposal, being able to increase its corporate stake by up to 30% of the total shares of the distributors within up to six (6) months after the auction.

For such, Eletrobras is entitled to increase its corporate stake up to the limit of 30% of the shares of the capital stock of Ceron, case in which the investor shall assign its right to subscribe such new shares to Eletrobras, so that it may formalize such increase. Considering the financial conditions of the company and the credit amounts of the debt held by Eletrobras with its distributors, Eletrobras may also pay such new shares by exchanging such debts into investment. These rules will be defined in the Shareholders Agreement to be signed by Eletrobras and the investor, and such agreement will be an attachment to the Purchase and Sale Agreement of the distributor.

Finally, it should be stressed that this alternative is not effectively part of the privatization, but an alternative available to Eletrobras, to be evaluated by it. Therefore, the intent is to include in the purchase and sale agreement of the distributor that Eletrobras may manifest its stake in increasing its corporate stake in the distributors after the privatization, within up to six (6) months from the date of the auction.

In order to be eligible to increase its corporate stake in this stage, Eletrobras must hold one (1) share at the end of “Stage 1”. In case Eletrobras chooses not to increase its stake, such remaining share shall be sold to the investor within six (6) months from the date of the auction.

This stage, as well as its premises and parameters, is detailed in Item 8.4 - Eletrobras corporate stake option.

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quantity of active and retired employees eligible to purchase shares; 3) a margin of safety for the number of eligible employees, active and retired; 4) the number of shares of the company; 5) the minimum values to each lot of shares of the company.

The capitalization value also considered the reality of six distributors in privatization procedure by Eletrobras, part of the same initiative. An uniform value was defined to all, considering the similarity of the financial situation in which they are found, as well as the proposed auction model, in which its sales operations interconnect. The definition of a homogeneous sales value of the companies, considering their financial situation, allows for a clearer and greater understanding of the privatization procedure of these companies to investors and to society.

Details on the number of shares and values, among other aspects, are listed in Section II -Privatization proposal and in the Public Notice to the privatization procedure of Ceron.

8.2.2 Capitalization alternatives

It is recommended that the choice on the alternatives to perform the adjustments to the capital structure of Ceron should fall exclusively onto Eletrobras. The choice shall be made according to the most attractive options and to the reality of financial availability and credit of the company at the time of the operation.

Recommendation made, it has been noted that Eletrobras could use three main alternatives to make the capitalization, all resulting in subscribing shares of the distributor: (i) conversion of debt credits by distributor to Eletrobras; (ii) assumption of debts of the distributor with third parties; and/or (iii) cash contribution to the distributor’s capital structure.

Conversion of debt credit of distributor: requires that Eletrobras should waive the right to amortization and interest of the debt credits, which, in part, would be of doubtful liquidation without the privatization. However, no demand is made in terms of cash disbursements by the company;
Assumption of debts of distributor with third parties: requires disbursement of cash for the payment of debts with third parties, according to the negotiation occurred;
Funding of financial resources to the distributor: requires disbursement of capital to allow the contribution to capital.

In order to define the best alternative of capitalization to Eletrobras, a specific analysis shall be carried out by the Holding.

8.3 Investor capitalization – “Stage 2”

Even after the adjustment to the capital structure by Eletrobras to a symbolic value, the recommendation, for the purposes of conclusion of the privatization procedure of Ceron, is to conduct a new capitalization of the company, however this time by the investor, against the underwriting of new shares. This capitalization has the attributions of:

a)	Avoiding the participation of investors effectively committed with the success of the company or without the due financial conditions to make the investments necessary for the organization;

Product 11 –Privatization Modeling Proposal

b)	Optimizing the capital structure of the company. After the “Stage 1”, against a symbolic equity value, the capital structure of Ceron shall consist of approximately 100% of debt.
	Thus, the company is not duly capitalized to make the investments and other demands of cash;
c)	Demonstrating to society and stakeholders that the privatization of Ceron has attracted an investor committed to contributing with resources sufficient to cover the investments in the first five years of the concession, fundamental to lever efficiency and the level of service of the company.

For definition of the capitalization value, two factors were taken into consideration: 1) capital structure of the companies after adjustment in “Stage 1”; and 2) reference leverage for the electric power distributors in Brazil, considering that Eletrobras will remain as minority partner of the companies.

In the first factor, it was considered that the capital structure, which will serve as a base to be adjusted by the investor, is the one after the privatization operation. That is, any debt conversions by Eletrobras to achieve the amount defined for the transfer of the distributor´s shares held by Eletrobras to the investor and consequent privatization of Ceron, have already been considered. At this stage, the company´s leverage is close to the theoretical limit, as there is no significant equity value.

In the second factor, a reference capital structure for the companies from the sector was used, 54% financial leverage. The leverage is calculated as a module of the amount of the net debt divided by the sum of the module of the net debt amount with the company´s equity value, as expressed herein: (|Net Debt| / [|Net Debt | + Equity Value]).

The value of 54% defined for the leverage target after the investor´s capitalization was calculated according to the methodology used by Consórcio Mais Energia B. It considered the current weighted average capital cost (“WACC”) of the companies compared to the most leveraged from the sector. In the calculation of the amount required from the investor, it was also considered that Eletrobras will use the option to achieve the maximum value of corporate share (30%) in Ceron by means of debt conversion after privatization.

In case Eletrobras does not use its option partially or totally, there are no damages to the operation or to the investor. The main reflection is that Ceron will have more leveraged capital structure than the suggested level (54%). However, due to the capitalization done by the investor, the distributor will be more prepared to undertake the relevant investments forecasted for the first years after the privatization. Likewise, the reasons to require the capitalization from the investor remain fulfilled.

It should be noted that, in addition to the capitalization forecasted for the investor, optimizations of the capital structure tend to be made progressively by the future investor. Thus, new contributions of resources may be demanded so that the financial equilibrium of Ceron is continuously achieved or even to face cash demands. Accordingly, in case Eletrobras decides to remain as a shareholder of the distributor and does not accompany the investor in eventual future increases of capital of the distributor, it shall be diluted. The same principle applies to eventual minority stakeholders (including Active and Retired Employees which adhere to the distributor’s Share Offer).

Product 11 –Privatization Modeling Proposal

The capitalization values of the investor are listed in Section II - Privatization proposal.


8.4	Eletrobras corporate stake option
8.4.1	Justification

The privatization modeling considers the possibility of Eletrobras continuing as a minority stakeholder of Ceron after the disposal of the shareholding control of such distributor. When holding a shareholding interest, even if assuming the risks as a shareholder of the company, Eletrobras may recover part of the investments made with the receipt of dividends or future increase of value and subsequent sale of its shareholding interest.

In such case, Eletrobras shall have the right to increase its shareholding interest at Ceron after the privatization of the company, having as an alternative not only the contribution to capital, but also the additional conversion of debts into shares. Thus, the state-owned company will not necessarily need to contribute to the capital of Ceron in case it is willing to exercise the respective option, using the credits of remaining debt eventually held against the privatized company.

The structuring of this alternative to Eletrobras occurs to provide it with an option to generate additional value from the privatization. For such, a financial valuation shall be carried out by Eletrobras, considering, among other aspects, the TIR and VPL of both scenarios.

8.4.2 Eletrobras corporate interest threshold

The corporate interest of Eletrobras should be limited to 30% of the shares of the company. The threshold of 30% was established based on benchmarks and good market practices, in which minority stakeholders have limited participation in the governance and/or management of the company.

The established percentage, in addition to allowing Eletrobras to hold relevant economic interest in the company, will not be equivalent to that of future investor, which will provide the investor with autonomy to act.

The capitalization to be performed by Eletrobras shall also follow the same profile of share categories currently existing at Ceron. Thus, eventual risks of legal inquiries related to specific corporate adjustments to the privatization procedure may be mitigated.

However, the shareholders agreement set forth in Item 8.4.3 –Participation of Eletrobras in the governance of the company shall be observed. Therefore, the degree of attractiveness of Ceron privatization to investors, main resource holders and risk takers, should be kept when assuring autonomy in the management of the company.

Such evaluation was also carried out based on market analyses, which included interviews with market experts and potential investors. In general, investors tend to accept the participation of Eletrobras in the company, however without substantial participation in the management of the company.

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8.4.3 Participation of Eletrobras in the governance of the company

In the presented model, although Eletrobras holds shares of Ceron, the state-owned company should preserve minimum rules in the management and governance of Ceron. Thus, the attractiveness of sale of the distributor would not be reduced duet to the sharing of its management, allowing the highest degree of freedom to the new investor.

For such, it proposes that, regardless of the shareholding organization of Ceron after the privatization, a shareholders agreement with the following parameters shall be established:


MODEL OF PROPOSED AGREEMENT
Participation Option	Eletrobras option to increase the participation in the distributor up to 30%
Conditions for the increase of capital	Accompany or increase the participation via debt conversion
Purchase priority	Valid to investor and to Eletrobras
Tag Along	100%
Effectiveness of the agreement	Regardless of controller succession

The objective of this configuration is to preserve the attractiveness of creation of value of the company, overcoming eventual barriers resulting from the sharing of decisions of the company after the privatization.

It is worthwhile noting that, even though not having a role in the management of the company, Eletrobras shall have its rights as a minority stakeholder duly protected. Privatized, Ceron will become a business corporation, one of the legal requirements for a company engaged in the distribution of electric power. In this case, the rights of the minority stakeholders will be governed by law, as well as the requirement of observance of good corporate governance practices (including the conduction of external audit and the disclosure of financial statements).

In addition, Eletrobras shall have specific aspects set forth in the shareholders agreement and in the obligations of the eventual investor when acquiring Ceron. The rights of Eletrobras are protected by the conditions detailed in the Public Notice to privatization of the company, and the specific conditions of the purchase and sale agreement of the distributor, including the shareholders agreement.

8.4.4 Procedure for Eletrobras to increase its shareholding interest

The purchase and sale agreement of the distributor and the shareholders agreement establish that Eletrobras will have up to six (6) months from the date of the auction to decide on its interest in increasing its shareholding interest by up to 30% of the shares of the capital stock of Ceron. Once the decision is made, Eletrobras shall communicate it to the new controller so that it becomes effective.

In case Eletrobras is interested in increasing its participation, the legal and usual procedures for the capitalization of the company shall be observed, considering the rights of minority stakeholders – including active and retired employees acquiring shares of Ceron. The investor shall not accompany such capitalization, in order to dilute its interest in the distributor and for Eletrobras to achieve the maximum threshold determined for its shareholding interest.

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As mentioned, the capitalization to be made by Eletrobras may also be made using debt credits held by the state-owned company with Ceron. The financial conditions of the capitalization, i.e., the market value per share, shall be the same of Stage 2 and of the auction.

8.5 Classes of shares

During the procedures of increase of capital of the distributor, the assumed premise is that the distributor will observe the legal rules applicable to the matter.

In case the new controller is interested in rearranging the corporate structure of the company, it may issue new classes of shares or create groups. This should occur provided that the legal rights of minority stakeholders are observed, as well as the contractual obligations resulting from the privatization procedure.

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9.	Shares offering to active and retired employees
9.1	Mechanism

According to the applicable legislation, the active and retired employees of the companies directly or indirectly controlled by the Government, included in the National Privatization

Program (“PND”), herein the Investment Partnership Program (“PPI”), are assured the offer of at least ten percent (10%) of the shares representative of its capital.

The offer to active and retired employees is made in parallel with the privatization auction, and its implementation is conditioned to its success, i.e., against the effective transfer of shareholding control.

To take part of the offer, active and retired employees must be qualified according to the criteria established in Item 9.2 – Definition of active and retired employees. After such qualification, active and retired employees shall indicate the number of lots of shares they are willing to reserve, without any purchase obligation.

Each qualified active and retired employee may receive the same number of shares, regardless of title, either at the present or upon retirement.

To negotiate the shares, the active and retired employees must be qualified and must hire a custodian agent, authorized institution accredited with B3, new denomination of BM&FBOVESPA.

9.2 Definition of active and retired employees

For the purposes of the Offer to Active and Retired Employees, active or retired employees of the distributor shall be considered as the following:

1)	Employees with labor links with the distributor on the date of publication of the Public
	Notice	in the Federal Official Gazette;
2)	Retired employees who meet any of the following requirements:
	a)	Hold labor link with the distributor on the date of request of their retirements;
	b)	Have the last contribution to the social security made as an employee of the distributor;
	c)	Have the last contribution to the social security covered by the distributor, as a result of voluntary dismissal plans;
	The	details on the eligibility criteria of active and retired employees for their eligibility to the

auction, including specifications of CNPJ [Corporate Taxpayer ID Number] of companies eventually related, shall be included in the Public Notice to the privatization of Ceron.

9.3 Offer General Conditions

The table below presents the main conditions of the offer of shares to the active and retired employees, with explicative details in the following items.

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General Conditions for Offering Shares to Active and Retired Employees


	Percentage of Eletrobras shares to be offered	10%
Conditions of
the offer	Discount on the Investor’s underwriting value	10%
	Destination of the Remainder	Sale¹to the Investor
Offering	Quantity for offering to Active and Retired Employees	02 Offers
Process	Purchase limit	Depends on the number of entitled people
		Depends on the participation acquired in the
Underwriting	Shares to be subscribed by Active and retired employees	offer
process
	Price per share on underwriting	Same price as Investor
	Lock-up period	No lock-up
	Re-purchase deadline	03 years
	Value per share for re-purchasing purposes	Same value as underwriting
Re-purchasing	Value limit of shares to be re-purchased	R$ 100,000.00
process²	Increase in shares’ value	10%
	Monetary correction index	SELIC
		Assets value (up to R$ 100,000.00) + 10% +
	Final re-purchase value	SELIC
1) Sale by the same offering value to Active and Retired Employees
2) The re-purchasing rights are exclusive for the original purchasers

The shares shall be offered to the active and retired employees in mixed lots, containing ordinary and preferred shares in the same proportion existing at the distributor. The offer in lots is necessary to allow the sale of the shares for the minimum price (R$ 0.01) necessary to perform a transactions in Brazilian Reais. Rounding may also occur to the totals of the number of shares per lot, offered to employees, culminating in a final offered percentage slightly greater than the value defined as a goal (10%). The details are described in Section II – Privatization Proposal.

For the second offer of shares to employees, aiming at the sale of eventual surplus of shares from the first offer, there will be criteria applicable purchases involving employees in case of draw, as duly established in the Public Notice to the auction and the Manual of Shares offering to active and retired employees.

9.3.1 Offer take and differentiated conditions

The active and retired employees of the distributor will be offered 10% of the shares held by Eletrobras. According to Article 30, Paragraph 4 of Decree No. 2.594, of May 1998, the shares to be offered to the active and retired employees may have different prices and conditions in relation to those offered to investors.

Thus, active and retired employees will have the prerogative to acquire shares at a lower price than the price paid by the new controller of the company in the Auction. The price per share for the Offer to Active and Retired Employees shall be defined as the value per share paid by the investor for the purposes of disposal, discounting up to 10%.

9.3.2 Offsetting differentiated conditions to Eletrobras

The discount offered to the active and retired employees must be offset to Eletrobras by the investor, as per Article 30, Paragraph 5 of Decree No. 2.594, of May 1998. Such offset shall occur directly, with the total value being paid in conjunction with the liquidation of the auction.

Product 11 –Privatization Modeling Proposal

After the stage of offer to the active and retired employees, shares that have not been sold shall be purchased by the winner of the auction, for the same price as previously offered, i.e., with the same discount offered, since the investor already is responsible for the costs of such discount.

9.3.3 Offer Procedure and Purchase Limits

A single offer of shares shall be made, extensive to all active and retired employees of each distributor, of 10% of the total amount of shares held by Eletrobras after the adjustment of the capital structure of “Stage 1”.

Based on the value of the shares for the disposal to the Investor, the value of shares for the Offer to Active and Retired Employees shall be calculated with the application of the discount of 10%, as indicated in Item 10.6 - Shares offering to active and retired employees. In order to allow the Offer, the shares will be grouped so that a lot of shares has value equivalent to R$ 0.01 (one centavo), minimum effective unit for money transactions.

After the qualification stage, the maximum limit of lots of shares that each active and retired employee may acquire will be defined (“Purchase Limit”), through the division of the number of lots offered by the number of qualified persons.

9.3.4 Follow-up by minority stakeholders of investor underwriting

As presented in Item 8.3 - Investor capitalization – “Stage 2”, the investor shall increase its interest in the capital stock against the underwriting of new shares following the liquidation of the auction. At that time, the persons who have acquired shares through the Shares offering to active and retired employees already are considered shareholders of the company.

The value per share (or lot of shares) for the eventual follow-up of the capitalization by the active and retired employees shall be equal to the price per share for the investor underwriting.

9.3.5 New controller shares repurchase obligation

The active and retired employees will be entitled to distribute the acquired shares in the following differentiated conditions:

a)	Under the scope of the Offer to the active and retired employees
b)	In the underwriting of capital with the investor

In case the active and retired employees who acquired shares of the Distributor are interested in selling such shares to the new controller, they may make such sale after three years from the date of the liquidation of the auction. The repurchase of these shares shall be made at the price per share acquired, up to the total maximum value of R$ 100,000.00 (one hundred thousand Brazilian Reais) per Active or Retired Employee.

Moreover, for the repurchase, the value of the shares acquired by the active and retired employees shall be added 10%. Following that, such total must be adjusted by the SELIC of the period for the purposes of inflation adjustment of the values. These values are detailed in Section II - Privatization proposal.

Product 11 –Privatization Modeling Proposal

The addition of 10% to the repurchase value is defined as a form of assuring differentiated conditions to the active and retired employees with a substantial value, since the sale of shares for the privatization of the distributor is made with symbolic value. It is a benefit for the participation in the capitalization of the company and also an stimulation for employees to contribute with the financial and operating success of the company.

The price per share (or lot) shall observe eventual adjustments resulting from grouping, split, bonus, and/or additional underwritings of shares or equivalent operations. Details of the values are also presented in Section II - Privatization proposal.

It is worthwhile noting that the active and retired employee are not prohibited from selling shares they acquired from Ceron to third parties. However, in case such sale occurs, the obligation and respective share repurchase conditions are cancelled. Exceptions apply to cases of heritage and eventual legal provisions.

9.4 Shares not acquired by active and retired employees

The shares offered in the Shares offering to active and retired employees, eventually not acquired by active and retired employees, shall be purchased by the investor. The purchase shall occur at the differentiated value (already with the discount), since the investor will already be entitled to offset the discount to Eletrobras.

Product 11 –Privatization Modeling Proposal

Section II - Privatization proposal

10. Summary of Ceron’s privatization proposal

This summary will present the recommendations of Consórcio Mais Energia B in relation to the privatization of Ceron. The evaluations and recommendations are presented in an objective manner, according to the instructions presented in Section I - Privatization context. They are intended to guide the actions to be taken by Eletrobras and entities responsible for the privatization procedure of the company.

10.1 Ceron’s Corporate Structure

The corporate structure on the base date of 12/31/2016 is organized according to the table below:


CURRENT CERON’S CORPORATE STRUCTURE

Total shares		1,212,156,653
Capital stock	R$	1,325,368,848.76
Nominal value of shares	R$	1.09339733

Interest	Shares	(%)
Eletrobras	1,212,156,653	100.00%
Minorities	0	- %

Classes of shares	Shares	(%)
Ordinary	1,212,156,653	100.00%
Preferential	0	- %

10.2	Ceron’s Sales Price Definition
	10.2.1 Result of economic-financial evaluations

The economic value of the shares of the company was determined according to the base date of 12/31/2016. Following on, the values were defined, considering the average of the prices for Services A and B, demonstrated in the table below:


ECONOMIC VALUE OF CERON - MEAN OF SERVICES A AND B

Service A	R$	(1,636,209,285.18)
Service B	R$	(1,896,147,868.89)
Mean of Services A and B	R$	(1,766,178,577.04)

The definition of the economic value of Ceron followed the definitions and instructions of Decree no. 2.594/98, Article 30, Paragraph 3, taking into account several aspects relevant to a valuation:

a)	Improvement of the operational efficiency level of the company, equal to or even higher than the efficiency levels of the market; and
b)	Evaluations of relevant due diligence for asset valuation (Legal Due Diligence, Accounting-Equity Due Diligence, Technical-Operational Due Diligence, Actuarial Due Diligence, Human Resources Due Diligence, and Environmental Evaluation Report).

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The detailing of the relevant information of these reports for the modeling are described in Section I - Privatization context.

10.2.2 Balance update adjustment

As mentioned in Item 7.3.1 – Adjustment to comprise updated balance sheet until June 2017, the entries of the balance of Ceron were updated to reduce the difference of values between the base date of the valuation (December 2016) and the last available publication of results (June 2017).

The balances of the adjusted values are listed below, by entry, and consolidated in a table, including the positive or negative effect they have to the adjustment value:


ASSETS (IN R$ 000) - CERON	Dec/16	Jun/17 Adjustment
Current
Cash and cash equivalents	18,706	37,526	18,820
Securities	2,039	52,580	50,541
Clients	248,349	230,278	(18,071)
Taxes to be recovered	27,665	33,364	5,699
Reimbursement rights	253,308	256,224	2,916
Warehouse	16,864	16,211	(653)
Services in progress	10,621	14,316	3,695
Regulatory asset	-	-	-
Sureties and judicial deposits	-	-	-
Financial asset	54,523	40,371	(14,152)
Assets destined to disposal	-	-	-
CDE repayment	-	-	-
Others	22,210	38,331	16,121
Non-current
Clients	16,829	16,677	(152)
Taxes to be recovered	6,534	5,850	(684)
Taxes to social contributions	-	-	-
Sureties and related deposits	127,064	135,089	8,025
Reimbursement rights	3,488,797	3,591,069	102,272
Regulatory asset	-	-	-
Others	2,447	2,447	-
Investments	1,806	1,806	-
Total asset adjustment			174,377

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LIABILITIES (IN R$ 000) - CERON	Dec/16	Jun/17	Adjustment
Current
Loans and Financing	23,324	147,518	124,194
Lease	-	-	-
Debt charges	6	44	38
Suppliers	1,456,393	1,766,511	310,118
Taxes payable	69,418	63,609	(5,809)
Social and labor obligations	17,167	25,786	8,619
Reimbursement obligations	125,083	13,203	(111,880)
Accounts payable to related parties	-	-	-
Estimated obligations	-	-	-
Sectorial charges	21,459	13,686	(7,773)
Post-employment benefits	6,316	4,620	(1,696)
Regulatory liabilities	-	-	-
Research and development	-	-	-
Financial liabilities	74,898	62,255	(12,643)
Others	46,199	39,880	(6,319)
Non-current
Loans and Financing	940,637	1,031,665	91,028
Lease	-	-	-
Suppliers	3,421,566	3,584,226	162,660
Taxes payable	4,260	15,752	11,492
Reimbursement obligations	152,339	151,353	(986)
Accounts payable to related parties	-	-	-
Provision for unsecured liability in controlled	-	-	-
Post-employment benefits	-	-	-
Regulatory liability	-	-	-
Sector charges	-	-	-
Advance for future capital increase	-	-	n/a
Research and development	-	-	-
Others	47,439	55,548	8,109
Total liabilities adjustment			569,152

CONSOLIDATED VALUE OF ADJUSTMENTS (IN R$ 000) - CERON
(+/-) Asset Adjustment			174,377
(+/-) Liabilities Adjustment			(569,152)
(+) RGR PPST Reincorporation			294,625
(-) Reclassification of AFACs as Debt			-
(-) Tax Adjustments (Tax Loss and Negative Base)			(6,144)
Consolidated value of adjustments			(106,294)

The consolidated value of the balances of the entries for the respective period was used as the adjustment value:


CERON VALUATION ADJUSTMENTS
Mean of Services A and B	R$	(1,766,178,577.04)
Consolidated adjustments	R$	(106,293,886.39)
Adjusted Equity Value	R$	(1,872,472,463.42)

Product 11 –Privatization Modeling Proposal

10.2.3 Regulatory parameters relaxation adjustment

As described in Item 7.3.4 – Adjustment of the relaxation of regulatory parameters, in case the ‘Adjusted Equity Value’ is greater than zero, the relaxation of the regulatory parameters must be reduced to result an equity value equal to zero. In the case of ‘Adjusted Equity Value’ smaller than zero, there will be no reductions to the relaxation of the rate parameters and no adjustment will be made to the equity value.


CERON TARIFF RELAXATION ADJUSTMENTS
Adjusted Equity Value	R$	(1,872,472,463.42)
Reduction adjustment of tariff relaxation	R$	-
Final Equity Value	R$	(1,872,472,463.42)
Reduction percentage of tariff relaxation		- %

10.3 Sale vs. Liquidation Evaluation and consequent “pure” concession granting

One of the relevant alternatives that Eletrobras shareholders have is to evaluate the economic feasibility in selling Ceron associated with the grant of the concession.

In case the state-owned company is willing to sell the company associated with the concession, the respective auction shall be held. Otherwise, or if the proposed adjustments are not accepted and/or made by Eletrobras, the auction shall only be held for the sale of the concession.

Thus, a comparative analysis between the sale price of the distributor associated with the concession and the eventual liquidation price of the company was developed. Thus, it is possible to assess if the sale would be more attractive to the state-owned entity.

Since the sale price considers adjustments to the equity value, the adjustments were also considered in the estimate of the liquidation value. However, exception was made to Tax Adjustments and Negative Base, since these had no impact to the liquidation value, and to AFACs, since they could be paid if the distributor is not sold.

As shown below, in the case of Ceron, the best economic option is to sell the company, considering the value of assets and of the concession. The balance between selling and liquidating is favorable for the first option, according to the table below:

Product 11 –Privatization Modeling Proposal


CONVERSION AND ASSUMPTION OF CERON’S DEBTS

Final Equity Value	R$	(1,872,472,463.42)

Stage 1 - Eletrobras Capitalization	R$	1,872,522,463.42
Debt conversion	R$	1,872,522,463.42
Debt assumption	R$	-
Adjusted Equity Value – Post Stage 1	R$	50,000.00

Price per share for Eletrobras underwriting	R$	1.09339733
Total shares subscribed by Eletrobras		1,712,572,741

The number of new shares subscribed by Eletrobras from these operations is defined pursuant to the price of issuance of the shares.

This is the stage in which the privatization of Ceron occurs in technical terms. After the adjustment of capital, 10% of the shares shall be offered to Active and Retired Employees, 90% of the shares less one shall be sold to the potential investor, and one share must remain as property of Eletrobras. The possession of this one share is necessary in case Eletrobras wishes to increase its corporate interest.

The capitalization values presented consider that the negotiations of the issues related to the CC are duly settled. As indicated in Item 3 – Relevant aspect for the Privatization Procedure, due to the relevance of the CCC value, the solution related to this topic is a critical factor for the success of the auction.

10.6 Shares offering to active and retired employees

As mentioned, the Brazilian legislation requires that, in a federal privatization, part of the shares directly or indirectly owned by the Government should be sold to the active and retired employees in differentiated conditions.

Thus, the shares of the distributor held by Eletrobras shall be offered to its active and retired employees, according to the conditions below:


OFFERING TO ACTIVE AND RETIRED EMPLOYEES FROM CERON

Conditions of differentiated offer
Base value of sale share	R$	0.00001710
Discount over the disposal value for the Investor		10.01%
Share value for differentiated offer	R$	0.00001538

Shares to be offered
Amount of Eletrobras shares		2,924,729,394
Percentage of Eletrobras shares offered		10.00001404%
Total amount offered		292,473,350
Ordinary		292,473,350
Preferential		0
Total valued of shares offered	R$	5,000.01
Value of shares offered with discount	R$	4,499.59
Value of compensation payable by the Investor	R$	500.42


	Product 11 –Privatization Modeling Proposal



Lots of the Shares offering to active and retired employees
Value of the lot of shares with discount	R$	0.01000000
Total quantity of lots in the Offer to Active and Retired Employees		449,959
Amount of shares in the lot		650
Amount of Ordinary shares in the lot		650
Amount of Preferential shares in the lot		0

Re-purchasing process¹by the investor
Lock-up period		No lock-up
Re-purchasing deadline		03 Years
Base value per share for re-purchasing purposes	R$	0.00001710
Base value limit of shares to be re-purchased	R$	100,000.00
Increase on base value of shares		10%
Share value with increase	R$	0.00001881
Correction Index		SELIC
Re-purchasing price per share	R$ 0.00001881 + SELIC

1) In the defined modeling, the repurchase conditions by the investor of the offered shares are exclusive rights of the active and retired employees acquiring them, or by individuals that may acquire them by succession (due to death of the original purchaser). In the case of sale of the shares to third parties, the repurchase benefits will be cancelled.

The investor shall offset Eletrobras for the offer of shares with differentiated conditions to employees (according to Decree 2.594/98), in addition to complying with the obligations included in this report, as indicated in Item 10.9 - Investors Obligations.

Shares eventually not purchased by the active and retired employees must be acquired by the investor at the end of the sale of these shares, at the price including the proposed discount. The acquisition of the remaining shares at the discount price shall occur so that the investor is not encumbered, twice, for the financial offset made to Eletrobras in relation to the sale of the shares to the active and retired employees, since the offset to Eletrobras will be made.

10.7 Investor capitalization – “Stage 2”

In the proposed sales model, for the purposes of liquidation of the auction, the investor willing to purchase Ceron shall make a contribution of capital with the underwriting of new shares at the company. Such capital shall be paid in national currency.


CAPITALIZATION OF INVESTOR ON CERON
Adjusted Equity Value – Post Stage 1	R$	50,000.00
Value to be paid by the Investor	R$	241,099,855.91
Adjusted Equity Value – Post Stage 2	R$	241,149,855.91
Amount of share to subscribe to the Investor		14,103,036,709,553
Price per share subscribed	R$	0.00001710

Product 11 –Privatization Modeling Proposal

10.8 Ceron’s final corporate structure

At the end of the privatization procedure, Ceron shall present the corporate structure described below, considering the full adhesion of the active and retired employees to the offer of shares:


CERON’S FINAL CORPORATE STRUCTURE
Total shares			15,672,967,962,122
Capital stock		R$	3,465,780,082.76
Nominal value of shares		R$		0.00022113

Interest	Ordinary shares	Preferential shares	Total Shares	(%)
Investor	14,105,668,965,596	0	14,105,668,965,596	90.0000%
Eletrobras	1	0	1	0.0000%
Active and Retired
Employees	1,567,298,996,525	0	1,567,298,996,525	10.0000%
Other Minorities	0	0	0	%

Shares per Class			Total Shares	(%)
Ordinary			15,672,967,962,122	100.0000%
Preferential			0	%

Note: assumes the total follow-up by Active and Retired Employees of the capitalization made by the investor. The final corporate structure, however, shall vary in accordance with the degree of adhesion to the offer by the Active and Retired Employees and to the follow-up rate of the capitalization.

The final corporate structure will vary depending on the rate of adhesion of the active and retired employees of Ceron to the offer of shares.

Shares eventually not acquired by the active and retired employees will be purchased from Eletrobras by the investor. The final participation of Eletrobras, however, shall not be changed.

In case Eletrobras chooses not to increase its corporate interest, the remaining share held by it shall be sold at its base price to the investor within six (6) months from the date of the auction.

10.9 Investors Obligations

The purchase Ceron, the interested investor must undertake to the following obligations established in the sale proposal:

10.9.1

Financial obligations

i.	Underwriting and payment of capital at the company
ii.	Pay Eletrobras the offsetting amount related to the differentiated conditions of the Shares offering to active and retired employees of Ceron
iii.	Purchase from Eletrobras the remaining shares of the offer made to the active and retired employees
iv.	Fulfill the requests related to the offer of shares to the active and retired employees in accordance with the differentiated conditions established
	The values of the financial obligations are defined below:


	Product 11 –Privatization Modeling Proposal


INVESTOR OPERATIONS ON CERON

Total paid during disposal of Ceron control	R$	45,500.41
Total value from sale of shares	R$	45,499.99
Amount of sale shares		2,632,256,043
Price per share	R$	0.00001710
Value compensation to Eletrobras for the offer to active and retired employees	R$	500.42

Capitalization - Stage 2
Amount of subscribed shares		14,103,036,709,553
Price per subscribed share	R$	0.00001710
Value to be paid by the Investor	R$	241,099,855.91

Other Obligations
Re-purchase of remainder from the offer to active and retired employees
Re-purchasing price	R$	0.00001538
Re-purchasing amount		Totality of remainder
Maximum value to be re-purchased	R$	4,499.59
Re-purchase of shares from active and retired employees
Re-purchasing deadline		03 Years
Base value per share for re-purchasing purposes	R$	0.00001710
Base value limit of shares to be re-purchased	R$	100,000.00
Increase on base value of shares		10%
Share value with increase	R$	0.00001881
Correction Index		SELIC
Re-purchasing price per share		R$ 0.00001881 + SELIC

10.9.2	Obligations defined in the Purchase Agreement
	Certain additional obligations are recommended, namely:
	i. Comply with the corporate clauses related to active and retired employees, according to the model proposed below:

Contractual obligations proposals

Private Pension Health Insurance

Re-qualification of dismissed

personnel

Maintain current conditions for two years Maintain current conditions for two years

Structure re-qualification program compatible with the best market practices

ii.	Comply with the governance clauses related to the shareholders agreement with Eletrobras, according to the model proposed below:


Proposed Deal Model
Participation Option	Option for Eletrobras to increase participation on the distributor up to
	30%
Conditions for capital increase.	Follow or increase participation via debt conversion
Purchase preference	Mutual for investor and Eletrobras
Tag Along	100%
Deal validity	Independent from controller succession

Product 11 –Privatization Modeling Proposal

11. Ceron’s privatization schedule

A proposal of schedule¹presenting the key stages of the privatization procedure was developed for the privatization of Ceron. The objective is to offer an overview of the procedure, complemented by a detailed schedule in terms of specific reports and legal drafts.

The schedule considers the legal requirements of term and the time necessary to make the corporate and financial adjustments, as well as the observance of contractual and corporate aspects. We have observed that this schedule is preliminary and may be subject to changes and adjustments to meet the requirements of the privatization procedure.

Activity

Publication of Resolution CPPI Data Room Opening

Shareholder’s Meeting of Eletrobras Shareholder’s Meeting of Distributor Conduction of Public Hearing

Publication of the Public Notice to Privatization Auction Auction homologation

Shareholder’s Meetings of the Distributor

Liquidation of the auction and execution of the agreement

Shareholder’s Meeting of the Distributor

Term

D + 0 D + 9 days

D + 50 days D + 63 days D + 70 days¹

D + 92 days D + 145 days²D + 168 days²

D + 177 days

D + 207 days³

Note: Depending on the effective date of the CPI resolution and the internal deadlines for the corporate procedures of Eletrobras (at times considered in business days), the estimated terms may be changed 1) According to Article 39 of Law 8.666/93, 15 business days before the publication of the Public Notice will be necessary. Considering that six public hearings shall occur, two weeks have been estimated. Thus, in case more days are necessary to hold these public hearings, the schedule will be changed 2) Suggestive term, since such terms are stipulated by the Public Notice 3) Suggestive term, however not smaller than 30 days from the date of the last Shareholder’s Meeting of the Distributor

Product 11 –Privatization Modeling Proposal

As established in the regulation above, the regulatory aspects mentioned below have been made flexible for the area of concession of the distributor:

RELAXED PARAMETERS

- Non-Technical Losses

- PMSO

- RGR PPST

As a form of allowing the reduction of the power rate charged against the consumer, the relaxed parameters shall be used as auction variables. They will be reduced by the bids of investors participating in the auction up to the limit of the relaxations performed by the regulator.

Once the relaxed parameters have a limit, the regulation also established the possibility of offer of values of grant by investors, with their resources being destined to the Government. The grant offer is subsequent to the reduction of the relaxed parameters and has no capped value. Thus, there are no procedural limits for the bids placed by the participants of the auction.

To reduce the operating complexity of an auction with several parameters, the proposal is to establish a single variable for the investor offers. This variable is a reference Index, exclusive and of crescent value, the ‘Combined Discount Index in the Regulatory Flexibility and Grant’ –referred to as Index.

In order to meet the regulatory requirements, the Index value will begin with 0.00 (zero) percentage point (p.p.) and shall not have capped value, with up to two decimal points for bids. The Index will also have two combined intervals, the first representing how investors are willing to reduce the tax relaxed, and the second representing how much they are willing the offer as grant value.

The intermediary values of the Index are described below:

	Values from zero (0.00) to one hundred (100.00):
	o	The offers in this interval will be related to the discount percentage in the relaxed regulatory parameters offered by the investor, with the percentage being applied linearly to all relaxed parameters in the area of concession of the distributor;
	o	The values will be used to define the final regulatory parameters of the area of concession of the distributor, according to the Draft of Electric Power Distribution Concession Agreement resulting from Public Hearing 94/2016 of ANEEL and Public Inquiry 037/2017 of the Ministry of Mines and Energy - MME.
	Values above one hundred point zero one (100.01):

o The bids in this interval consider only the values additionally to the initial one hundred (100.00) p.p. and refer to the value of offered grant, with the payment being made to the Government;

Product 11 –Privatization Modeling Proposal

o The value offered by the investor shall be multiplied by a pre-determined reference money value to each one (1.00) percentage point of the Index after 100.01;

For exemplification purposes, we indicate the following cases:

Index equal to zero (0.00): The tariff is not reduced, nor the grant value. The agreement will be signed with the whole Regulatory Flexibility that served as the base of the auction;
Index equal to one hundred (100.00): The investor completely waives to the relaxed, without offering grant value. The concession agreement shall be signed without adjustments resulting from the auction, to be applied over the relaxed factors (as per the Draft of Electric power Distribution Concession Agreement resulting from Public Hearings 94/2016 and 032/2017 of ANEEL);
Index equal to one hundred and ten (110.00): The investor completely waives to the relaxed and offers as grant ten (10) times its reference value for each percentage point.
The concession agreement will be signed without adjustments resulting from the auction, to be applied over the relaxed factors. The reference grant value of each percentage point (for instance, R$ 5 million) will be multiplies by 10, and the resulting grant value (in this case, R$ 50 million) will be destined to the Government.

The Index will be valid both to the first stage (in closed envelope) and in the second stage (live bidding). After opening the envelopes, in case of bidders classified to the 2^ndstage, the bids of investors for the highest Index value continue in live bidding until one of them is declared winner.

12.6 Auction Value base for ‘Combined Discount Index in the Regulatory Flexibility and Grant’

The values of the first interval of the Index (from 0.00 to 100.00 p.p.) refer to the Regulatory Flexibility, in which the offered discount is applied linearly over the values of the relaxed parameters by the regulator.

In this context, the values of the regulatory parameters used as variables of the auction should be fixed. Thus, investors will know the amount in which they bids will be placed and that will base the auction. This recommendation also aims at avoiding legal inquiries prior to or after the auction, which may compromise the privatization of the distributor.

For such, the PMSO value and the RGR PPST to be used as auction variables should be fixed. These values will depend on the future definition of ANEEL to be used in the auction and will be informed upon the publication of the invitation to privatization. The additional RGR values eventually not part of the auction will be fully offset via tariff. The Non-Technical Loss amounts have already been pre-defined according to ANEEL Technical Note 149/2017.

The table below shows the Consortium estimate for the base of values of the auction variables for the auction of the distributor:

Product 11 –Privatization Modeling Proposal


NOTE BASE ESTIMATE VALUES FOR AUCTION		CERON

l	Index (BID)	Auction Result

2	Contract: Sub clause on Tariff Coverage of RGR	Auction Result

3	Relaxation PMSO 2017	47,551,063
4	Regulatory PMSO 2017	281,710,917
5	Pre-Auction Discount	0.0%
6	2017 PMSO Relaxation Post Pre-Auction Discount	47,551,063
7	Contract: Item II Sub Clause 3 Clause 19 of the Contract	Auction Result

8	Regulatory PNT 2016	8.33%
9	PNT Relaxation	14.76%
10	Adjusted Relaxation	14.76%
11	Contract: Item III Sub Clause 3 Clause 19 of the Contract	Auction Result


	EXPLANATORY NOTES
1	Value offered by the auction winner
2	Value to be defined on the Contract Clause that rules the tariff recognition of RGR
	Relaxation base for Operational Costs of 2017 (estimated by the Consortium, according to item 43 of NT 149/2017) -
3	will be informed by Aneel for the Auction
4	Operational Costs considered on the Tariff Process of 2017 (estimated by the Consortium, according to item 43 of
	NT 149/2017) - will be informed by Aneel for the Auction
5	Adjustment to zero Equity Value, as instructed on the Decree Minutes
6	Relaxation base for Operational Costs of 2017, adjusted by Pre-Auction Discount
7	Value to be defined on Item II, Sub-Clause 3, Clause 19 of the Contract
8	Non-Technical Losses considered by the Tariff Process of 2016 (NT 149/2017)
9	Relaxation base of Non-Technical Losses (NT 149/2017)
10	2017 PNT Relaxation adjusted by Post Pre-Auction Discount
11	Value to be defined on Item III, Sub-Clause 3, Clause 19 of the Contract

The values of the second interval of the Index (above 100.01 p.p.) are related to the grant value. As explained, the Index value offered by the investor above 100.00 p.p. shall be multiplied by a reference value to each percentage point related to the grant. The reference value must be monetary, in Real, and defined in the Public Notice to the auction.

The reference value should be based on parameters related to the context of the privatization of the distributor. Thus, the reference value will be established in a logical way and shall maintain a relationship with the other aspects of the auction.

For that, two initial possibilities were identified for the definition of the monetary reference value of each percentage point offered as grant value:

i)	Value with magnitude order near the monetary value estimated to each percentage point of the first interval of the Index (part related to rate relaxed discount);
ii)	Percentage of the Enterprise Value of the distributor.

Product 11 –Privatization Modeling Proposal

The preliminary values estimated by the Consortium to each one of the two presented possibilities are listed below, as a form of support for the definition of the reference value of each percentage point related to the grant:


REFERENCE VALUE ALTERNATIVES FOR EACH P.P. - GRANT FROM CERON

i) Value¹estimated for each Index p.p.	R$ 5.0 Million
ii) Value¹regarding Enterprise Value	R$ 3.2 Million
Enterprise Value	R$ 1,264.6 Million
Percentage Base of Enterprise Value	0.
1) Approximate value

12.7 Auction´s 2nd stage ranking criteria

Bids placed in the 1^ststage will be considered as classified to the 2^ndstage of each auction, in the case· of: Being the bid with the highest Combined Discount Index in the Regulatory Flexibility· and Grant Being a bid in the interval of classification

The interval of classification will be defined upon the publication of the Public Notice and is demonstrated as an example in the table below. The representativeness of the interval of classification was also considered in relation to the Enterprise Value of the distributors.

The interval value suggested was secured in relation to its estimated absolute value and its representativeness in relation to the Enterprise Value of the distributor. Thus, an interval was proposed in which these two aspects could not be extremely high or low, stimulating competitiveness of investors in the auction.

Bids will be considered in the interval of classification if their difference to the offer with the highest Index is smaller than or equal to the specific classification interval of the auction. Since there is no limit for the value offered by the Index, the interval of classification shall observe the best bid placed.


Interval of Classification
Auction	3^rd
Company	Ceron
Interval of Classification	20.00

For example, in case the highest bid is of an Index equal to 75.00 in the auction of the distributor, bids greater than or equal to 55.00 (75.00 less 20.00) will be considered as classified. Similarly to this auction, in case the best bid is equal to 110.00, offers greater than or equal to 90.00 will be classified. The Interval of Classification may also be changed until the final draft of the Public Notice is drawn up.

The monetary values of each percentage point (p.p.) of discount in the Index related to discount in the regulatory flexibilization is not fixed, ranging in accordance with the estimate made. Similarly, the nominal values to the Interval of Classification will range.

Product 11 –Privatization Modeling Proposal

The estimate of the Consortium of the approximate average of the monetary values of each percentage point of variation and of the interval of classification is presented below. These are estimated values of reduction in the Enterprise Value of the company, which, on its turn, reflect the Equity Value (value to shareholder).


CLASSIFICATION INTERVAL FOR CERON AUCTION

Approximated value for one (1) p.p. variation	R$ 5.0 Million
Classification Interval	20 p.p.
Estimated value for Classification Interval	R$ 100.0 Million
Estimated percentage of Enterprise Value	7.9%

The estimate of value for one percentage point of variation is made based on the economic-financial evaluation model of this Consortium. To every percentage point of discount conceded, the relaxation parameters are adjusted, with key reflections to reductions in the value of Installment A. It also includes the discount to be given in RGR PPST, considering the present value of the amount accumulated until June 2017.

It should be noted that this estimate is based on the average of values found by the Consortium for progressive reductions to the Index in relation to discount in the regulatory flexibilization, since the curve of values is not linear. That is, different values will be obtained to different discount levels to the Index.

The investor, on its turn, shall make its own estimate, according to the modeling of valuation of the distributor, so that it may guide its bid in the auction.

12.8 Auction procedures

Prior to the public auction sessions, interested parties must hand the qualification documentation in conjunction with the economic bids, in sealed envelope.

For an investor to have its bid considered valid in one of the auctions, such investor shall deliver envelopes to all auctions of each round, even if without bid or with the indication of non-interest. For instance, even though the investor is exclusively interested in the company of the 4^thauction, it shall hand envelopes to all other auctions of the round.

This procedure aims at mitigating eventual asymmetries of information from investors in relation to which or how many investors are bidding to each company.

The 3^rd, 4^th, and 5^thauctions will allow bidders to exercise their right to participate in the 2^ndstage, if so desired, as demonstrated in the figure below. The right to participate must be delivered duly filled and signed. The validity of the right is conditioned to the prior delivery of a valid economic bid to the auction in screen.

The chart below illustrates the sequence of deliveries of bids and the right to participate in the auctions.

This press release may contain forward-looking statements. These statements are statements that are not historical facts, and are based on management's current view and estimates offuture economic circumstances, industry conditions, company performance and financial results. The words "anticipates", "believes", "estimates", "expects", "plans" and similar expressions, as they relate to the company, are intended to identify forward-looking statements. Statements regarding the declaration or payment of dividends, the implementation of principal operating and financing strategies and capital expenditure plans, the direction of future operations and the factors or trends affecting financial condition, liquidity or results of operations are examples of forward-looking statements. Such statements reflect the current views of management and are subject to a number of risks and uncertainties. There is no guarantee that the expected events, trends or results will actually occur. The statements are based on many assumptions and factors, including general economic and market conditions, industry conditions, and operating factors. Any changes in such assumptions or factors could cause actual results to differ materially from current expectations.


Figure 10 – Offsetting Evolution of the Evaluated Distributor and Comparison with the Target	92
Figure 11 – Composition and Evolution of the X Factor Components	152
Figure 12 – Target Calculation by Benchmark Comparison	164
Figure 13 – Evolution of Non-Technical Losses (%/ Low-Voltage Market)	167
Figure 14 – Evolved Revenue and Growth Rate	175
Figure 15 – Evolved Default	176
Figure 16 – Evolved Operating Costs	177
Figure 17 - Costs versus EBITDA	178
Figure 18 – Evolved PMSO	180
Figure 19 – Forecast Effective and Regulatory PMSO	181
Figure 20 – Evolved Operating Indicators: Gross Margin	182
Figure 21 – Evolved Operating Income: EBITDA Margin	183


		· ·	^%#+$#4_Âmeans means Annual the statutory Cost of annuity Computer base Systems; amount regarding investments in computer systems, as
		·	87 means Submodule the lifespan, 2.3; as defined in Table XVI of the Annex to the Electricity Market Equity
			Control Manual (MCPSE).


Where: ·		^82#82$⁵means means Installment Installment B A in in current current juncture juncture on on DRP; DRP;
·		5


Company	Unlevered Beta
ENERGISA	0.50
EQUATORIAL	0.58
COSERN	0.35
COELBA	0.17
COELCE	0.35
CPFL	0.56
EDP	0.66
ELETROPAULO	0.28
CEMIG	0.62
LIGHT	0.57
COPEL	0.56
CELESC	0.38
Average	0.47


Table 24 - Income Information	47
Table 25 - Information on Violence	48


Charts
Chart 1 - Socioeconomic characterization of the state of Rondônia	10
Chart 2 - Overview of the Brazilian Rate Structure	49


Summary

1. Executive Summary		4
2. Organizational structure		7
2.1.	Organizational Chart:	7
2.2.	Nature and assignments of bodies:	7
2.3.	Profile of Positions and roles:	9
2.4. Profile of gratified roles and positions in commission:		10
2.5.	Relevant changes to the Organizational Structure:	11
3. Staff profile		12
3.1.	General information	12
3.2.	Demographic profile	12
3.3.	Productive profile of the workforce	13
3.4.	Workforce Development	19
3.5.	Leadership profile	21
3.6. Leadership by position		22
3.7.	Leadership education level	23
3.8. Leadership Service Time		23
4. Personnel Cost		24
4.1. Compensation structure		24
4.2. Cost with active employees		26
4.3. Interns and apprentices		27
5. Collective agreements		29
5.1. Salary readjustment		29
5.2.	Benefits	29
5.3.	Payment of other bonuses	29
6. Outsourcing		31
7. Aspects related to health and safety		32
7.1.	Verification of existence of health and safety policies and procedures	32
7.2.	PCMSO Analysis	32
7.3.	PPRA Analysis	32
7.4.	Verification of completion of occupational medical examinations	33
7.5.	Internal Committee on Accident Prevention ("CIPA")	33
7.6.	Survey of work accidents (with/without leave) and opening of CAT (Work accident communication)	33
7.7.	PPE Delivery Verification	33
7.8.	Occupational Safety Technician Performance	34
7.9.	Mandatory training	34
1. Position and Compensation Plan ("PCR")		36
1.1.	Compensation Structure	37


1.2.	Growth Rules:	37
1.3.	Access requirements:	38
2. Variable pay		39
3. Benefits		39
4. Performance Management		43
4.1.	Performance Matrix:	43
5. Training and Development		45
6. Organizational Climate		46


Relationship	Amount	Costs
Apprentices	28	BRL 17,387.92
Interns	49	BRL 68,729.36


TABLE OF CONTENTS
INTRODUCTION		4
EXECUTIVE REPORT		7
A.	REGULATORY ASPECTS	7
B.	CORPORATE ASPECTS	9
C.	FINANCIAL AGREEMENTS	9
D.	OPERATING AGREEMENTS AND OBLIGATIONS	10
E.	INTELLECTUAL PROPERTY	10
F.	INSURANCE	10
G.	LABOR ASPECTS	11
H.	CIVIL, COMMERCIAL, EQUITY AND CRIMINAL LITIGATION	12
I.	TAX LITIGATION	13
J.	REAL ESTATE ASPECTS	14


*Table of contents*
1.	Executive summary		4
2.	Plan types		4
3.	Plan statistics		4
4.	Analysis of assumptions and recommendations		4
	4.1.	Discount rate	4
	4.2.	Wage growth projection	5
	4.3.	Biometric tables	5
	4.4.	Turnover	5
	4.5.	Age of retirement	6
	4.6.	Family composition	6
	4.7.	Health care cost growth rate (HCCTR)	6
5.	Independent calculation of actuarial results		6
6.	Independent review of actuarial commitment		6
7.	Conclusion		7


			Product 11 –Privatization Modeling Proposal

10.7	Investor capitalization – “Stage 2”		54
10.8	Ceron’s final corporate structure		55
10.9	Investors Obligations		55
10.9.1		Financial obligations	55
10.9.2		Obligations defined in the Purchase Agreement	56
11.	Ceron’s privatization schedule		57
Section III - Auction Model Proposal			58
12.	Model and Procedure of Auctions		58
12.1	Proposed model		58
12.2	Sequence		59
12.3	The right to participate		59
12.4	The right to withdraw bids		60
12.5	Bid procedures and values		60


	Grant’	62
12.7	Auction´s 2nd stage ranking criteria	64
12.8	Auction procedures	65

CENTRAIS ELÉTRICAS BRASILEIRAS S.A. - ELETROBRÁS

By:	/S/ Armando Casado de Araujo
	Armando Casado de Araujo Chief Financial and Investor Relation Officer