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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		2 Impairment/onerous contract

The Company has been ascertaining recurring losses (R$ 321.5 million in 2016		The concessions of the Eletrobras distribution companies
and R$ 252.5 million in 2015), reaching an accumulated loss of R$ 1,252.8		expired in 2015. Although Decree no. 8461, of June 2, 2015,
million as of Dec-16 and a net shareholders' equity of R$ 573.7 million.		provides for the extension of the electric energy distribution
In addition, we identified an adjusted net indebtedness (after our adjustments		concessions, on June 22, 2016, the 165th Extraordinary General
and reclassifications) as of Dec-16 of R$ 1,695.5 million and negative adjusted		Shareholders’ Meeting of Eletrobras decided not to extend the
EBITDA for 2016 of R$ 196.6 million.		concessions of its controlled companies of power distribution.
According to the management, the main reasons for the Company’s current
financial situation are:		Accordingly, the Company started to operate as a public utility
		Company, on a temporary basis, until the earlier of the
-	Significant value of assets in service not yet included in the “armored” basis	assumption by a new concessionaire or December 31, 2017.
	[base blindada], resulting in a tariff below the one necessary to cover the
	operating costs;	As a consequence, considering that the Company also has power
-	Delay in the receipt of subsidies (CDE, CVA, among others);	purchase agreements in force for periods going beyond
-	High level of client default and technical and operating losses;	December 31, 2017, a provision for impairment of the fixed
		assets was registered in 2016, in the amount of R$ 32.4 million,
-	Late payment to suppliers and other liabilities (as a consequence of the	as well as an additional provision for onerous contract in the
	items above), generating cash unbalance and increase in expenses with	amount of R$ 7.8 million.
	financial charges and arrears penalties.
We should stress that the Company’s current financial position, associated		In the management’s view, after conclusion of the privatization
with the tariff gap (e.g., significant volume of assets in service not yet included		process, associated with a program to bring back the company’s
in the “armored” basis), with the investment level during the period of		financial health, those provisions may be reversed, not
provision of the services, among other factors, may result in additional risks		necessarily generating a future cash expenditure.
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 make a comparison
between the historical periods.


Privatization of the Eletrobras System Distribution Companies		10 agosto 2017
PwC		3


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


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.

3 Lawsuit against all distribution

companies	4 Risk due to the loss of exclusivity of

A public civil action was filed by the National Consumers Association –	the client Braskem
ANDECO against all Electric Energy Concessionaires in the country with	According to the management, in 2017 the Company lost exclusivity in
respect to prevention and remediation of collective damages against	the supply of electricity to the client Braskem. Accordingly, there may
consumers, with a request for preliminary injunction in order for the	be reductions in the volume of power distribution in relation to the
companies to refrain from charging the claimed losses from the	historical volume, as well as in the receivables from clients.
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	It is not possible to estimate, now, the possible impacts on the
period from 2010 to 2014. ANDECO also pursues the annulment of all	Company’s EBITDA and working capital, but, according to the
ANEEL Resolutions that allow the collection and inclusion in the bills of	management, the gross revenue from power distribution to Braskem
sums related to non-technical and technical losses. The value of the	was approximately R$ 4 million per month.
matter is R$ 27 billion, but the amount charged from Companhia	We suggest that such impact be discussed together with the Economic
Energética de Alagoas is R$ 3.8 billion.	Valuation area.
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,	5 Tax and labor exposures
therefore, the distribution companies must indemnify the regular
consumers in twice as much (double indemnification provided for in the	It is important to stress that, during our works, we identified several
law) the amounts charged in the period from 2010 to 2014, according to	procedures adopted by the Company that may result in questioning and
their respective balance sheets. It also pursues the annulment of all	assessments by the labor and social security and the federal, state, and
ANEEL Resolutions that allow the collection and inclusion in the bills of	municipal tax authorities. In what respects such procedures, the
sums related to non-technical and technical losses.	respective value of the contingencies that may potentially emerge if
	they are identified and questioned corresponds to R$ 642.1 million.
This lawsuit was classified by the Company’s lawyer as with risk of	Please note that there are other non-quantified adjustments.
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.

Privatization of the Eletrobras System Distribution Companies	10 agosto 2017
PwC	4


*Exhibit I* – *Adjusted EBITDA (1/6)*

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.
Quality of earnings – CEAL				The table on the left displays the Company’s quality of earnings (EBITDA)
		FY15	FY16	analysis for the fiscal years ended on December 31, 2015 (FY15) and
In R$ thousand		(Audited)	(Audited)	December 31, 2016 (FY16).
Net revenue		1,363,076	1,211,766
Net profit (loss)		(252,585)	(321,539)	The adjustments suggested were calculated based on the information
				provided by the Company's management. Those adjustments were
Add-backs (reversions)		132,177	149,119
Financial results		104,539	118,906	made as a result of our analysis, according to financial and
Depreciation/amortization		27,637	30,213	management information prepared by the Company’s management.
IR and CSLL		-	-	The EBITDA corresponds to the net profit subtracted of certain
Reported EBITDA		(120,409)	(172,420)	reclassification items, such as net financial results, taxes and social
% on net revenue		(9%)	(14%)	contributions on the earned income (Income Tax (IRPJ) and Social
Reclassifications		(25,843)	34,731	Contribution on Net Profit (CSLL)), depreciation and amortization.
1	Reclassification of the new replacement value	(25,843)	(5,524)
2	Reclassification of impairment provisions	-	32,446	We should stress that the Company’s current financial position,
3	Reclassification of the provision for onerous liabilities	-	7,809	associated with the tariff gap (e.g., significant volume of assets in
Accounting adjustments		-	-	service not yet included in the “armored” basis), with the investment
Normalization adjustments		32,566	(57,246)	level during the period of provision of the services, among other factors,
4	Normalization of expenses with PCLD	32,566	(57,246)	may result in additional risks for the Company, mainly in the last fiscal
Tax and labor adjustments		(1,571)	(1,631)
5	Tax, labor, and social security impacts	(1,571)	(1,631)	years. We understand that those factors may impair the obtainment of
Adjusted EBITDA		(115,257)	(196,566)	an EBITDA on a recurring and normalized basis, making it more
% on net revenue		(8%)	(16%)	difficult, therefore, to compare the historical periods.
Non-quantified adjustment		NQ	NQ	Comments on the adjustments identified are detailed below and in the
6	Employee insourcing	NQ	NQ	next pages of this summary.
7	Normalization of the revenue from excess demand and excess
	of reactive power	NQ	NQ	Reclassification adjustments
8	Financial impacts due to Braskem loss	NQ	NQ	1. Reclassification of the new replacement value: This is the
Other considerations		(7,283)	(13,295)	monetary restatement of the concession assets basis expected to be
9	Potential normalization of provision for contingencies	(7,283)	(13,295)	paid to the Company after the concession period. Since those sums
10 Potential risk of change in the CVA values		NQ	NQ	are not characterized as operating, and considering the current
11 Costs with new structure/Companies integration		NQ	NQ
12 Undue charges – Angra 3		-	NQ	situation of the distribution Company, we understand that they
13 Other potential adjustments		NQ	NQ	should not be part of the recurring EBITDA analysis for the period.
Source: Audited financial statements and Pw C analysis

Privatization of the Eletrobras System Distribution Companies				10 agosto 2017
PwC				5


*Exhibit I* – *Adjusted EBITDA (2/6)*

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.				2.	Reclassification of impairment provisions: We suggest the
Quality of earnings – CEAL					reversion of the impacts from the recognition and/or reversion of
		FY15	FY16		the provision for recoverability of the intangible assets
In R$ thousand		(Audited)	(Audited)		(impairment), considering that those values are purely accounting
Net revenue		1,363,076	1,211,766		entries which do not directly impact the Company’s cash flow
Net profit (loss)		(252,585)	(321,539)		generation.
Add-backs (reversions)		132,177	149,119
Financial results		104,539	118,906	3.	Reclassification of the provision for onerous liabilities:
Depreciation/amortization		27,637	30,213		We identified that, in 2016, the Company recognized a provision
IR and CSLL		-	-		for onerous contracts in the total amount of R$ 7.8m during the
Reported EBITDA		(120,409)	(172,420)		evaluation of the recoverability of its concession/intangible assets.
% on net revenue		(9%)	(14%)
					Since those sums are purely accounting entries, which do not
Reclassifications		(25,843)	34,731
1	Reclassification of the new replacement value	(25,843)	(5,524)		directly impact the Company’s cash generation, we suggest that
2	Reclassification of impairment provisions	-	32,446		they be excluded for purposes of analysis of normalized EBITDA.
3	Reclassification of the provision for onerous liabilities	-	7,809
Accounting adjustments		-	-	Normalization adjustments
Normalization adjustments		32,566	(57,246)	4.	Normalization of expenses with Provision for Doubtfully
4	Normalization of expenses with PCLD	32,566	(57,246)		Accounts (PCLD): We note that the PCLD is automatically and
Tax and labor adjustments		(1,571)	(1,631)		systemically calculated, following the criteria established by
5	Tax, labor, and social security impacts	(1,571)	(1,631)		Eletrobras, and that such criteria tends to be more conservative
Adjusted EBITDA		(115,257)	(196,566)		than those established by ANEEL. Since those provisions are not of
% on net revenue		(8%)	(16%)		a financial nature and their variations are not historically constant,
Non-quantified adjustment		NQ	NQ
6	Employee insourcing	NQ	NQ		we understand that, for purposes of normalized EBITDA, it must
7	Normalization of the revenue from excess demand and excess				be considered only the impacts from losses resulting from
	of reactive power	NQ	NQ		payments from clients that effectively materialized in the period;
8	Financial impacts due to Braskem loss	NQ	NQ		accordingly, we suggest the reversion of the PCLD in the period.
Other considerations		(7,283)	(13,295)		In R$ thousand	FY15	FY16
9	Potential normalization of provision for contingencies	(7,283)	(13,295)
10 Potential risk of change in the CVA values		NQ	NQ		Net revenue	1,363,076	1,211,766
11 Costs with new structure/Companies integration		NQ	NQ		PCLD / Losses result	(98,489)	(1,947)
12 Undue charges – Angra 3		-	NQ		Proposed adjustment	32,566	(57,246)
13 Other potential adjustments		NQ	NQ		Losses in the period	(65,923)	(59,193)
Source: Audited financial statements and Pw C analysis					% of losses on net revenue	5%	5%

Privatization of the Eletrobras System Distribution Companies							10 agosto 2017
PwC							6


*Exhibit I* – *Adjusted EBITDA (3/6)*

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.
Quality of earnings – CEAL
				Tax and labor adjustments
		FY15	FY16
In R$ thousand		(Audited)	(Audited)	5.	Tax, labor, and social security impacts: refer to potential
Net revenue		1,363,076	1,211,766		additional impacts resulting from the issues described in this
Net profit (loss)		(252,585)	(321,539)		summary, both quantified and non-quantified, classified as
Add-backs (reversions)		132,177	149,119		probable loss by the Company’s legal advisors.
Financial results		104,539	118,906
Depreciation/amortization		27,637	30,213	#	Description	31-Dec-15	31-Dec-16
IR and CSLL		-	-
				4	CVA	-	-
Reported EBITDA		(120,409)	(172,420)	Total tax exposures		-	-
% on net revenue		(9%)	(14%)	3	Irregularities related to work days	1,571	1,631
Reclassifications		(25,843)	34,731	Total labor exposures		1,571	1,631
1	Reclassification of the new replacement value	(25,843)	(5,524)	Total tax and labor exposures + NQ		1,571	1,631
2	Reclassification of impairment provisions	-	32,446
3	Reclassification of the provision for onerous liabilities	-	7,809
Accounting adjustments		-	-	Non-quantified adjustments
Normalization adjustments		32,566	(57,246)
4	Normalization of expenses with PCLD	32,566	(57,246)	6.	Employee insourcing: The management understands that, as
Tax and labor adjustments		(1,571)	(1,631)		determined by law, the Company needs to insource employees of
5	Tax, labor, and social security impacts	(1,571)	(1,631)		its operations (consumption measurement and like
Adjusted EBITDA		(115,257)	(196,566)		professionals), which will increase the costs, due to issues of
% on net revenue		(8%)	(16%)		inefficiency and equivalence of labor benefits. We understand
Non-quantified adjustment		NQ	NQ		that those impacts may influence the Company’s future results.
6	Employee insourcing	NQ	NQ
7	Normalization of the revenue from excess demand and excess	NQ	NQ
	of reactive power
8	Financial impacts due to Braskem loss	NQ	NQ
Other considerations		(7,283)	(13,295)
9	Potential normalization of provision for contingencies	(7,283)	(13,295)
10 Potential risk of change in the CVA values		NQ	NQ
11 Costs with new structure/Companies integration		NQ	NQ
12 Undue charges – Angra 3		-	NQ
13 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis

Privatization of the Eletrobras System Distribution Companies							10 agosto 2017
PwC							7


*Exhibit I* – *Adjusted EBITDA (4/6)*

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.
Quality of earnings – CEAL				7.	Normalization of the revenue from excess demand and
		FY15	FY16		excess of reactive power: The revenues earned with excess
In R$ thousand		(Audited)	(Audited)		demand and excess of reactive power must be accounted for as
Net revenue		1,363,076	1,211,766		“Obligations Related to the Electric Power Utility Service,” which
Net profit (loss)		(252,585)	(321,539)		will be amortized starting on the next cycle of tariff review, after its
Add-backs (reversions)		132,177	149,119		recognition. However, the Company recognized those sums as
Financial results		104,539	118,906		revenues in the fiscal years of 2013-2016 and later, in FY16,
Depreciation/amortization		27,637	30,213		reversed 100% of the sums recognized as liabilities until the next
IR and CSLL		-	-
Reported EBITDA		(120,409)	(172,420)		cycle of tariff review. Due to the unavailability of information
% on net revenue		(9%)	(14%)		related to the period of those sums, it was not possible to quantify
Reclassifications		(25,843)	34,731		the impacts for normalization of the Company’s recurring
1	Reclassification of the new replacement value	(25,843)	(5,524)		EBITDA.
2	Reclassification of impairment provisions	-	32,446	8.	Financial impacts due to Braskem loss: As mentioned, in
3	Reclassification of the provision for onerous liabilities	-	7,809		2017 the Company lost exclusivity in the supply of electricity to the
Accounting adjustments		-	-
Normalization adjustments		32,566	(57,246)		client Braskem. It is not possible to estimate, now, the possible
4	Normalization of expenses with PCLD	32,566	(57,246)		impact on the Company’s EBITDA, but, according to the
Tax and labor adjustments		(1,571)	(1,631)		management, the gross revenue from power distribution to
5	Tax, labor, and social security impacts	(1,571)	(1,631)		Braskem was approximately R$ 4 million per month. We suggest
Adjusted EBITDA		(115,257)	(196,566)		that such impact be discussed with the area in charge of Economic
% on net revenue		(8%)	(16%)		Valuation.
Non-quantified adjustment		NQ	NQ
6	Employee insourcing	NQ	NQ	Other considerations
7	Normalization of the revenue from excess demand and excess			9.	Potential normalization of provision for contingencies:
		NQ	NQ
	of reactive power				We verified that the Company’s EBITDA is being impacted by
8	Financial impacts due to Braskem loss	NQ	NQ		provisions for contingencies that are not characterized as financial
Other considerations		(7,283)	(13,295)		and/or operating for the business. We understand that, for
9	Potential normalization of provision for contingencies	(7,283)	(13,295)		purposes of analysis of recurring and operational EBITDA, it must
10 Potential risk of change in the CVA values		NQ	NQ
11 Costs with new structure/Companies integration		NQ	NQ		be considered only the sums duly paid between the periods, to
12 Undue charges – Angra 3		-	NQ		which we did not have access because the Company did not supply
13 Other potential adjustments		NQ	NQ		its controls.
Source: Audited financial statements and Pw C analysis

Privatization of the Eletrobras System Distribution Companies					10 agosto 2017
PwC					8


*Exhibit I* – *Adjusted EBITDA (5/6)*

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.
Quality of earnings – CEAL				10. Potential risk of change in the CVA values: The Account for
		FY15	FY16	Compensation of “Portion A” Variations (CVA) records the difference
In R$ thousand		(Audited)	(Audited)	between the costs estimated in the tariff (Portion A) and the costs
Net revenue		1,363,076	1,211,766	effectively incurred, creating a payable or receivable balance (and,
Net profit (loss)		(252,585)	(321,539)	consequently, an expense or a revenue) for the Company. Such
Add-backs (reversions)		132,177	149,119	amounts to be paid/received are ratified each year by ANEEL. We
Financial results		104,539	118,906	found that, historically, the amounts ascertained by the Company may
Depreciation/amortization		27,637	30,213
IR and CSLL		-	-	significantly differ from those ratified by ANEEL, mainly with respect
Reported EBITDA		(120,409)	(172,420)	to the financial items, which are not controlled by the Company.
% on net revenue		(9%)	(14%)	Considering that the ratification process happens close to the end of the
Reclassifications		(25,843)	34,731	fiscal year (between September and October), we understand that there
1	Reclassification of the new replacement value	(25,843)	(5,524)	are no material discrepancies for the balances accounted for in Dec-15
2	Reclassification of impairment provisions	-	32,446	and Dec-16. On the other hand, those differences may become
3	Reclassification of the provision for onerous liabilities	-	7,809	significant over the months.
Accounting adjustments		-	-
Normalization adjustments		32,566	(57,246)	11. Costs with new structure/Companies integration: We note that,
4	Normalization of expenses with PCLD	32,566	(57,246)	depending on the changes in the Company’s current structure that are
Tax and labor adjustments		(1,571)	(1,631)	made after the conclusion of the privatization process, as well as on the
5	Tax, labor, and social security impacts	(1,571)	(1,631)
				measures required for the potential integration with an investor, the
Adjusted EBITDA		(115,257)	(196,566)
% on net revenue		(8%)	(16%)	Company’s EBITDA may change significantly. In addition, possible
Non-quantified adjustment		NQ	NQ	changes in the compensation of the new management must be
6	Employee insourcing	NQ	NQ	considered in the Company’s result. We recommend that this issue be
7	Normalization of the revenue from excess demand and excess			discussed with the “Economic and Legal Assessment” area.
	of reactive power	NQ	NQ
8	Financial impacts due to Braskem loss	NQ	NQ	12. Undue charges – Angra 3: According to ANEEL’s information, the
Other considerations		(7,283)	(13,295)	power distribution companies that belong to the interconnected system
9	Potential normalization of provision for contingencies	(7,283)	(13,295)	unduly charged from their consumers in 2016 certain amounts related
10 Potential risk of change in the CVA values		NQ	NQ	to the estimated costs of the nuclear power plant Angra 3. We have not
11 Costs with new structure/Companies integration		NQ	NQ	had access to the sums to be reimbursed to the Company’s consumers,
12 Undue charges – Angra 3		-	NQ	but we were informed that such reimbursement would be made by
13 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis				means of discount (of approximately 7.66%) in the April 2017 bill.

Privatization of the Eletrobras System Distribution Companies				10 agosto 2017
PwC				9


*Exhibit I* – *Adjusted EBITDA (6/6)*


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.

Quality of earnings – CEAL				13. Other potential adjustments: Considering the defined scope of
		FY15	FY16	our works; the limitations in the information provided; the tax,
In R$ thousand		(Audited)	(Audited)	labor, and social security exposures that could not be quantified;
Net revenue		1,363,076	1,211,766
				and possible non-recoverable assets adjustments (e.g., inventory
Net profit (loss)		(252,585)	(321,539)	with low recoverability expectation); other potential adjustments
Add-backs (reversions)		132,177	149,119
Financial results		104,539	118,906	may be necessary, in order to better reflect the Company’s
Depreciation/amortization		27,637	30,213	normalized and recurring EBITDA. In addition, we recommend
IR and CSLL		-	-	that this summary be read jointly with the reports of the other due
Reported EBITDA		(120,409)	(172,420)	diligence areas (operational, legal, HR, insurance, and
% on net revenue		(9%)	(14%)	environmental).
Reclassifications		(25,843)	34,731
1	Reclassification of the new replacement value	(25,843)	(5,524)
2	Reclassification of impairment provisions	-	32,446
3	Reclassification of the provision for onerous liabilities	-	7,809
Accounting adjustments		-	-
Normalization adjustments		32,566	(57,246)
4	Normalization of expenses with PCLD	32,566	(57,246)
Tax and labor adjustments		(1,571)	(1,631)
5	Tax, labor, and social security impacts	(1,571)	(1,631)
Adjusted EBITDA		(115,257)	(196,566)
% on net revenue		(8%)	(16%)
Non-quantified adjustment		NQ	NQ
6	Employee insourcing	NQ	NQ
7	Normalization of the revenue from excess demand and excess	NQ	NQ
	of reactive power
8	Financial impacts due to Braskem loss	NQ	NQ
Other considerations		(7,283)	(13,295)
9	Potential normalization of provision for contingencies	(7,283)	(13,295)
10 Potential risk of change in the CVA values		NQ	NQ
11 Costs with new structure/Companies integration		NQ	NQ
12 Undue charges – Angra 3		-	NQ
13 Other potential adjustments		NQ	NQ
Source: Audited financial statements and Pw C analysis

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


*Exhibit II* – *Net indebtedness (1/5)*

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.

Net indebtedness				The table on the left displays the Company’s net indebtedness, based
In R$ thousand		Dec-15	Dec-16	on the audited financial statements for the years ended on December
Cash and cash equivalents		22,801	21,804	31, 2015 (Dec-16) and December 31, 2016 (Dec-16).
Securities - TVM		19,337	14,709
Loans – short term		(310,110)	(34,794)	We note that the concept of Net Indebtedness is not contemplated in
Loans – long term		(864,330)	(1,427,343)	the accounting practices adopted in Brazil, being it rather a
Net financial indebtedness		(1,132,302)	(1,425,624)	contractual definition. For the purpose of our analysis, we
Collaterals and deposits in court - long term		41,845	60,119	considered, in addition to the net financial indebtedness, other items
Post-employment benefit – short term		(6,402)	(2,389)	and transactions with financing features.
Payable taxes		(48,492)	(87,794)
Industry charges – long term		(21,434)	(17,870)	The adjustments suggested and reported were prepared based on
Post-employment benefit – long term		(32,504)	(41,219)	management information and reports, accounting trial balances, and
Provisions for lawsuits		(95,993)	(109,288)	enquiries made to the Company’s management. We note that, due to
Indemnification obligations - long term		(2,775)	-	limited information and scope, there may be adjustments that could
Other liabilities – long term		(31,892)	(33,603)	not be quantified/identified during our analysis.
Other debt items		(197,647)	(232,044)
Reported net indebtedness		(1,329,949)	(1,657,668)	*Reclassifications between working capital*
Reclassification between working capital and net				*and net indebtedness*
indebtedness		(88,818)	(37,852)
1	Rights to unpaid indemnification from previous periods	-	3,564	1.	Rights to unpaid indemnification from previous
2	Return of sums related to the Light for All program	(38,779)	(11,754)		periods: We suggest the reclassification from net working
3	Suppliers with past due credits	(40,692)	(13,382)		capital to indebtedness of the Energy Development Account
4	Installment payment of taxes – short term	(2,834)	(11,722)		(CDE) receivable balances (recorded in the Indemnification
5	Reclassification of related parties	281	263		Right account – CP) generated more 12 months ago.
6	Other liabilities – short term	(6,794)	(4,821)		Accordingly, the proposed adjustment considers the CDE
Subtotal		(88,818)	(37,852)
					amounts related to fiscal year 2015.
Adjustments proposed by the due diligence		NQ	(29)
7	Restricted cash balance	NQ	(29)	2.	*Return of sums related to the Light for All [Luz para***
Subtotal		NQ	(29)		**Todos] program:** Sums received and not used for the Light for
Adjusted net indebtedness		(1,418,767)	(1,695,549)		All program, which must be returned to Eletrobras.
Other considerations		997,819	1,214,898
Source: Audited trial balances and Pw C analysis

Privatization of the Eletrobras System Distribution Companies					10 agosto 2017
PwC					11


*Exhibit II* – *Net indebtedness (2/5)*

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.
Net indebtedness
				3.	Suppliers with past due credits: We suggest the
In R$ thousand		Dec-15	Dec-16		reclassification as net indebtedness of 100% of the suppliers’
Cash and cash equivalents		22,801	21,804		past due payable balances, due to their nature of financing.
Securities - TVM		19,337	14,709
Loans – short term		(310,110)	(34,794)	4.	Installment payment of taxes – short term: We are
Loans – long term		(864,330)	(1,427,343)		suggesting the reclassification as net indebtedness of 100% of the
Net financial indebtedness		(1,132,302)	(1,425,624)		taxes payable in installments, classified in the current liabilities,
Collaterals and deposits in court - long term		41,845	60,119		due to their nature of financing. The outstanding balance of
Post-employment benefit – short term		(6,402)	(2,389)		installment payments of taxes classified in the non-current
Payable taxes		(48,492)	(87,794)		liabilities is already included in the reported net indebtedness.
Industry charges – long term		(21,434)	(17,870)
Post-employment benefit – long term		(32,504)	(41,219)	5.	Reclassification of related parties: It refers to balances
Provisions for lawsuits		(95,993)	(109,288)		receivable from related parties for employee loans (assigned)
Indemnification obligations - long term		(2,775)	-		repaid by the Company. In view of their nature, we suggest their
Other liabilities – long term		(31,892)	(33,603)		reclassification as Company’s indebtedness.
Other debt items		(197,647)	(232,044)
Reported net indebtedness		(1,329,949)	(1,657,668)	6.	Other liabilities – short term: We identified certain
Reclassification between working capital and net					liabilities classified in the Company’s current liabilities which, in
indebtedness		(88,818)	(37,852)		our view, are not characterized as operating working capital, as
1	Rights to unpaid indemnification from previous periods	-	3,564		detailed below:
2	Return of sums related to the Light for All program	(38,779)	(11,754)
3	Suppliers with past due credits	(40,692)	(13,382)
4	Installment payment of taxes – short term	(2,834)	(11,722)		In R$ thousand	Dec-15	Dec-16
5	Reclassification of related parties	281	263		Relates to regulatory and punitive fines, which are not	6,794	4,821
6	Other liabilities – short term	(6,794)	(4,821)		characterized as working capital
Subtotal		(88,818)	(37,852)		Adjustment for reclassification as debt	6,794	4,821
Adjustments proposed by the due diligence		NQ	(29)		Source: Pw C analysis and discussions w ith management
7	Restricted cash balance	NQ	(29)
Subtotal		NQ	(29)
Adjusted net indebtedness		(1,418,767)	(1,695,549)
Other considerations		997,819	1,214,898
Source: Audited trial balances and Pw C analysis

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


*Exhibit II* – *Net indebtedness (3/5)*

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.

Net indebtedness				Adjustments proposed by the due diligence
In R$ thousand		Dec-15	Dec-16
				7. Restricted cash balance: We were informed that certain
Cash and cash equivalents		22,801	21,804	sums maintained in the cash and cash equivalents account (cash
Securities - TVM		19,337	14,709
Loans – short term		(310,110)	(34,794)	deposits, financial investments, etc.) are not immediately
Loans – long term		(864,330)	(1,427,343)	available. Accordingly, we are excluding those sums from the
Net financial indebtedness		(1,132,302)	(1,425,624)	position as Company net indebtedness.
Collaterals and deposits in court - long term		41,845	60,119
Post-employment benefit – short term		(6,402)	(2,389)	Other considerations:
Payable taxes		(48,492)	(87,794)	i.	Tax, labor, and social security impacts: We are
Industry charges – long term		(21,434)	(17,870)		considering, for purposes of analysis of the Company’s net
Post-employment benefit – long term		(32,504)	(41,219)		indebtedness, the tax, labor, and social security exposures
Provisions for lawsuits		(95,993)	(109,288)
Indemnification obligations - long term		(2,775)	-		classified as with risk of probable loss (see specific exhibit in
Other liabilities – long term		(31,892)	(33,603)		this summary). We note that the amount presented here already
Other debt items		(197,647)	(232,044)		considers possible fines and interest to be added upon an
Reported net indebtedness		(1,329,949)	(1,657,668)		assessment by the tax authorities.
Reclassification between working capital and net				#	Description	31-Dec-15 31-Dec-16
indebtedness		(88,818)	(37,852)	4	CVA	11,590	13,808
Adjustments proposed by the due diligence		NQ	(29)	Total tax exposures		11,590	13,808
7	Restricted cash balance	NQ	(29)	3	Irregularities related to work days	7,154	8,862
Subtotal		NQ	(29)	Total labor exposures		7,154	8,862
Adjusted net indebtedness		(1,418,767)	(1,695,549)	Total tax and labor exposures + NQ		18,744	22,670
Other considerations		997,819	1,214,898
i	Tax, labor, and social security impacts	(18,744)	(22,670)	ii.	Financial asset – public utility concessions: It refers to
ii	Financial asset – public utility concessions	732,843	845,035		the financial asset indemnifiable in the end of the
iii	Clients with past due and installment payments	283,720	392,533		concession/service period. Depending on how the Company’s
iv	Collaterals and deposits in court - long term	NQ	NQ		sale is structured, the indemnifiable balance may be converted
v	Provision for contingencies	NQ	NQ		into cash, thus reducing the level of net indebtedness.
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

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


*Exhibit II* – *Net indebtedness (4/5)*

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.

Net indebtedness				Other considerations:

In R$ thousand		Dec-15	Dec-16	iii.	Clients with past due and installment payments: We
Cash and cash equivalents		22,801	21,804		identified outstanding balances of clients’ past due and
Securities - TVM		19,337	14,709
Loans – short term		(310,110)	(34,794)		installment payments, classified in the current and non-current
Loans – long term		(864,330)	(1,427,343)		assets. Although they do not represent a cash item with
Net financial indebtedness		(1,132,302)	(1,425,624)		immediate liquidity, we understand that they are a receivable of
Collaterals and deposits in court - long term		41,845	60,119		the Company, which, therefore, must be included in possible
Post-employment benefit – short term		(6,402)	(2,389)		cash flow projections.
Payable taxes		(48,492)	(87,794)
Industry charges – long term		(21,434)	(17,870)		In R$ thousand	Dec-15	Dec-16
Post-employment benefit – long term		(32,504)	(41,219)		Clients – current assets	71,631	78,586
Provisions for lawsuits		(95,993)	(109,288)		Clients – non-current assets	212,089	313,947
Indemnification obligations - long term		(2,775)	-		Total	283,720	392,533
Other liabilities – long term		(31,892)	(33,603)
Other debt items		(197,647)	(232,044)	iv.	Long term collaterals and deposits in court: We note that
Reported net indebtedness		(1,329,949)	(1,657,668)		the deposits in court directly related to a provision for
Reclassification between working capital and net					contingency must impact the indebtedness balances in the
indebtedness		(88,818)	(37,852)		period. However, since the Company did not provide the
Adjustments proposed by the due diligence		NQ	(29)		ancillary controls, it was not possible to determine if the full
7	Restricted cash balance	NQ	(29)
Subtotal		NQ	(29)		amount of the reported balances must be included in the
Adjusted net indebtedness		(1,418,767)	(1,695,549)		analysis of the Company’s net indebtedness.
Other considerations		997,819	1,214,898	v.	Provision for contingencies: We note that this summary
i	Tax, labor, and social security impacts	(18,744)	(22,670)		does not consider possible changes in the projection of loss of
ii	Financial asset – public utility concessions	732,843	845,035		the Company’s lawsuits, resulting from the legal due diligence
iii	Clients with past due and installment payments	283,720	392,533		works.
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

Privatization of the Eletrobras System Distribution Companies							10 agosto 2017
PwC							14


*Exhibit II* – *Net indebtedness (5/5)*

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.

Net indebtedness				Other considerations:
In R$ thousand		Dec-15	Dec-16	vi. CAPEX investments: As mentioned before, the Company has
Cash and cash equivalents		22,801	21,804	been operating as a public utility Company, which has resulted
Securities - TVM		19,337	14,709
Loans – short term		(310,110)	(34,794)	in a reduction in CAPEX investments, maintaining only those
Loans – long term		(864,330)	(1,427,343)	that are essentially necessary to continue with the operational
Net financial indebtedness		(1,132,302)	(1,425,624)	activities and the levels of quality required by the regulatory
Collaterals and deposits in court - long term		41,845	60,119	agencies. We recommend that the you consider the impacts
Post-employment benefit – short term		(6,402)	(2,389)	estimated by the result of the technical and operational due
Payable taxes		(48,492)	(87,794)	diligence.
Industry charges – long term		(21,434)	(17,870)
Post-employment benefit – long term		(32,504)	(41,219)	vii. Undue charges – Angra 3: According to ANEEL’s
Provisions for lawsuits		(95,993)	(109,288)	information, the power distribution companies that belong to
Indemnification obligations - long term		(2,775)	-	the interconnected system unduly charged from their
Other liabilities – long term		(31,892)	(33,603)	consumers in 2016 certain amounts related to the estimated
Other debt items		(197,647)	(232,044)	costs of the nuclear power plant Angra 3. We have not had
Reported net indebtedness		(1,329,949)	(1,657,668)	access to the sums to be reimbursed to the Company’s
Reclassification between working capital and net				consumers, but we were informed that such reimbursement
indebtedness		(88,818)	(37,852)	would be made by means of discount (of approximately 7.66%)
Adjustments proposed by the due diligence		NQ	(29)
7	Restricted cash balance	NQ	(29)	in the April 2017 bill.
Subtotal		NQ	(29)	viii. Other potential adjustments: Considering the defined
Adjusted net indebtedness		(1,418,767)	(1,695,549)	scope of our works; the limitations in the information provided;
Other considerations		997,819	1,214,898	the tax, labor, and social security exposures that could not be
i	Tax, labor, and social security impacts	(18,744)	(22,670)	quantified; and possible non-recoverable assets adjustments
ii	Financial asset – public utility concessions	732,843	845,035	(e.g., inventory with low recoverability expectation); other
iii	Clients with past due and installment payments	283,720	392,533	potential adjustments may be necessary, in order to better
iv	Collaterals and deposits in court - long term	NQ	NQ
v	Provision for contingencies	NQ	NQ	reflect the Company’s net and recurring indebtedness. In
vi	CAPEX investments	NQ	NQ	addition, we recommend that this summary be read jointly with
vii Undue charges – Angra 3		-	NQ	the reports of the other due diligence areas (operational, legal,
viii Other potential adjustments		NQ	NQ	HR, insurance, and environmental).
Source: Audited trial balances and Pw C analysis

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


*Exhibit III* – *Net working capital (1/3)*

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.
Net working capital
			We present in the chart on the left the Company’s net working
In R$ thousand	Dec-15	Dec-16	capital as of December 31, 2015 (Dec-15) and 2016 (Dec-16),
Clients – short term	344,668	313,949	prepared based on the audited financial statements.
Taxes and social contributions – short term	11,686	12,625
Indemnification right – short term	25,136	73,126	The adjustments suggested and reported were prepared based on
Inventory	6,099	8,822	management information and reports, audited accounting trial
Regulatory assets - short term	212,888	65,585	balances, and enquiries made to the Company’s management. We
Other assets – short term	31,870	29,302	note that, due to limited information and scope, there may be

Taxes Suppliers Regulatory and - contributions assets short term - long term	(106,414) (239,745) 38,252	(164,322) (76,785) 22,130	analysis. adjustments that could not be quantified/identified during our

Labor Regulatory Indemnification obligations liabilities obligations - short - term short term	(124,005) (17,267) (77,153)	(115,289) (18,392) (45,373)	indebtedness Reclassifications between working capital and net
Industry charges - short term	(24,103)	^(30,955)	•	For further details, see the preceding exhibit of this summary,
Other liabilities – short term	(22,571)	(20,272)		“net indebtedness.”
Regulatory liabilities - long term	(16,380)	(6,801)
Reported net working capital	42,961	47,350	Adjustments proposed by the due diligence
Reclassification between working capital and net indebtedness	88,818	37,852
Rights to unpaid indemnification from previous periods	-	_(3,564)	1.	Inventory with low recoverability expectation: Items
Return of sums related to the Light for All program	38,779	11,754		destined to sale (scraps) and lent materials, which are not
Suppliers with past due credits	40,692	13,382		classified as operating working capital.
Installment payment of taxes – short term	2,834	11,722
Reclassification of related parties	(281)	(263)	2.	Clients with past due and installment payments: We
Other liabilities – short term	6,794	4,821		identified outstanding balances of clients’ past due and
Subtotal	88,818	37,852		installment payments, classified in the current assets, which we
Adjustments proposed by the due diligence				suggest be excluded for purposes of analysis of the Company’s
1 Inventory with low recoverability expectation	(1,319)	(1,225)		working capital. As mentioned before, although they do not
2 Clients with past due and installment payments	(71,631)	(78,586)
3 Other assets – short term	(4,399)	(5,816)		represent a cash item with immediate liquidity, we understand
Subtotal	(77,350)	(85,627)		that they are a receivable of the Company, which, therefore, must
Adjusted net working capital	54,429	(425)		be included in possible cash flow projections.
Other considerations
Source: Audited trial balances and Pw C analysis
Privatization of the Eletrobras System Distribution Companies				10 agosto 2017
PwC				16


*Exhibit III* – *Net working capital (2/3)*

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.

Net working capital				Adjustments proposed by the due diligence

In R$ thousand		Dec-15	Dec-16	3. Other assets – short term: We identified certain assets
Clients – short term		344,668	313,949	classified in the Company’s current assets which, in our view, are
Taxes and social contributions – short term		11,686	12,625	not characterized as operating working capital, as detailed
Indemnification right – short term		25,136	73,126	below:
Inventory		6,099	8,822
Regulatory assets - short term		212,888	65,585	In R$ thousand	Dec-15	Dec-16
Other assets – short term		31,870	29,302	Balance paid re. Decision no. 029211142, which
Regulatory assets - long term		38,252	22,130	awaits decision	(452)	(452)
Suppliers - short term		(239,745)	(164,322)	Goods to be written-off or scrapped	(846)	(1,343)
Taxes and contributions		(106,414)	(76,785)	Scraps available for sale	(150)	(986)
Indemnification obligations - short term		(77,153)	(45,373)
				Re. balances questioned and not paid by the collection
Regulatory liabilities - short term		(124,005)	(115,289)		(1,482)	(1,762)
Labor obligations		(17,267)	(18,392)	agents of electricity bills, e.g., Banco do Brasil.
Industry charges - short term		(24,103)	(30,955)	This adjustment aims to complete the PCLD balance,
Other liabilities – short term		(22,571)	(20,272)	considering the time and the total outstanding value of	(1,285)	(1,088)
Regulatory liabilities - long term		(16,380)	(6,801)	client receivables due to use of structure.
Reported net working capital		42,961	47,350	Write-off of ICMS paid in excess longtime outstanding	(184)	(184)
Reclassification between working capital and net				Adjustment for CG write-off	(4,399)	(5,816)
indebtedness		88,818	37,852	Source: Pw C analysis and discussions w ith management
Adjustments proposed by the due diligence
1 Inventory with low recoverability expectation		(1,319)	(1,225)	Other considerations
2 Clients with past due and installment payments		(71,631)	(78,586)
3 Other assets – short term		(4,399)	(5,816)	i. Risk due to the loss of exclusivity of the client
Subtotal		(77,350)	(85,627)	Braskem: As mentioned above, in 2017 the Company lost
Adjusted net working capital		54,429	(425)	exclusivity in the supply of electricity to the client Braskem. It is
Other considerations				not possible to estimate, now, the possible impact on the
i	Risk due to the loss of exclusivity of the client Braskem	NQ	NQ	Company’s net working capital, but, according to the
ii	Potential risk of change in the CVA values	NQ	NQ	management, the gross revenue from power distribution to
iii Tax, labor, and social security exposures		NQ	NQ	Braskem was approximately R$ 4 million per month. We
iv Other potential adjustments		NQ	NQ	suggest that such impact be discussed with the area in charge of
Source: Audited trial balances and Pw C analysis				Economic Valuation.

Privatization of the Eletrobras System Distribution Companies					10 agosto 2017
PwC						17


*Exhibit III* – *Net working capital (3/3)*

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.

Net working capital				Other considerations

In R$ thousand		Dec-15	Dec-16	ii.	Potential risk of change in the CVA values: The Account
Clients – short term		344,668	313,949		for Compensation of “Portion A” Variations (CVA) records the
Taxes and social contributions – short term		11,686	12,625		difference between the costs estimated in the tariff (Portion A)
Indemnification right – short term		25,136	73,126		and the costs effectively incurred, creating a payable or
Inventory		6,099	8,822		receivable balance (and, consequently, an expense or a revenue)
Regulatory assets - short term		212,888	65,585		for the Company. Such amounts to be paid/received are ratified
Other assets – short term		31,870	29,302		each year by ANEEL. We found that, historically, the amounts
Regulatory assets - long term		38,252	22,130
Suppliers - short term		(239,745)	(164,322)		ascertained by the Company may significantly differ from those
Taxes and contributions		(106,414)	(76,785)		ratified by ANEEL, mainly with respect to the financial items,
Indemnification obligations - short term		(77,153)	(45,373)		which are not controlled by the Company. Considering that the
Regulatory liabilities - short term		(124,005)	(115,289)		ratification process happens close to the end of the fiscal year
Labor obligations		(17,267)	(18,392)		(between September and October), we understand that there
Industry charges - short term		(24,103)	(30,955)		are no material discrepancies for the balances accounted for in
Other liabilities – short term		(22,571)	(20,272)
Regulatory liabilities - long term		(16,380)	(6,801)		Dec-15 and Dec-16. On the other hand, those differences may
Reported net working capital		42,961	47,350		become significant over the months.

Reclassification between working capital and net				iii.	Tax, labor, and social security exposures: It refers to the
indebtedness		88,818	37,852		impact on the net working capital of adjustment #5 presented in
Adjustments proposed by the due diligence
1 Inventory with low recoverability expectation		(1,319)	(1,225)		the quality of the results. We understand that any changes in
2 Clients with past due and installment payments		(71,631)	(78,586)		the tax, labor, and social security procedures may also impact
3 Other assets – short term		(4,399)	(5,816)		the Companies’ net working capital.
Subtotal		(77,350)	(85,627)
Adjusted net working capital		54,429	(425)	iv.	Other potential adjustments: See adjustment viii of the
Other considerations					preceding exhibit.
i	Risk due to the loss of exclusivity of the client Braskem	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

Privatization of the Eletrobras System Distribution Companies					10 agosto 2017
PwC					18


*Exhibit IV* – *Balance Sheet*




Assets			Liabilities
	Dec-15	Dec-16		Dec-15	Dec-16
In R$ thousand	(Audited)	(Audited)	In R$ thousand	(Audited)	(Audited)
Cash and cash equivalents	22,801	21,804	Suppliers - short term	239,745	164,322
Securities - TVM	19,337	14,709	Loans – short term	310,110	34,794
Clients – short term	344,668	313,949	Taxes and contributions	106,414	76,785
Taxes and social contributions – short term	11,686	12,625	Indemnification obligations - short term	77,153	45,373
Indemnification right – short term	25,136	73,126	Post-employment benefit – short term	6,402	2,389
Inventory	6,099	8,822	Regulatory liabilities - short term	124,005	115,289
Ongoing services	11,152	6,421	Labor obligations	17,267	18,392
Regulatory assets - short term	212,888	65,585	Industry charges - short term	24,103	30,955
Other assets – short term	31,870	29,302	Onerous Concession - short term	-	7,808
Current assets	685,637	546,343	Other liabilities – short term	22,571	20,272
Clients – long term	212,089	313,947	Current liabilities	927,770	516,379
Taxes and social contributions – long term	5,019	4,264	Loans – long term	864,330	1,427,343
Collaterals and deposits in court - long term	41,845	60,119	Payable taxes	48,492	87,794
Financial asset – public utility concessions	732,843	845,035	Regulatory liabilities - long term	16,380	6,801
Regulatory assets - long term	38,252	22,130	Industry charges – long term	21,434	17,870
Other assets – long term	564	564	Advance for future capital increase (AFAC)	8,307	159,155
Investments	168	168	Post-employment benefit – long term	32,504	41,219
Intangible assets	54,047	4,984	Provisions for lawsuits	95,993	109,288
Fixed assets	31,757	28,127	Indemnification obligations - long term	2,775	-
Non-current assets	1,116,584	1,279,338	Other liabilities – long term	31,892	33,603
Total assets	1,802,221	1,825,681	Non-current liabilities	1,122,107	1,883,073
			Capital stock	726,447	734,754
			Other comprehensive results	(42,808)	(55,691)
			Accumulated losses	(931,295)	(1,252,834)
			Net equity	(247,656)	(573,771)
			Total liabilities	1,802,221	1,825,681
			Source: Audited trial balances


Privatization of the Eletrobras System Distribution Companies					10 agosto 2017
PwC					19


*Exhibit V* – *Income Statement*




Income Statement

In R$ thousand	FY15	FY16
Net revenue	1,364,461	1,211,766
Operating Cost	(1,276,152)	(1,230,563)
Cost of Electricity	(984,186)	(914,247)
Electricity bought for resale	(894,482)	(839,907)
Charges for use of transmission grid	(89,705)	(74,340)
Operations Cost	(191,313)	(194,349)
Labor, materials, and third parties services	(146,162)	(150,488)
Depreciation and amortization	(27,637)	(30,212)
Other	(17,513)	(13,649)
Construction Cost	(100,652)	(121,967)
Gross Profit	88,309	(18,796)
Operating Expenses/Revenues	(236,355)	(183,836)
Income from Electricity Service	(148,046)	(202,633)
Financial revenue	98,868	126,496
Financial expenses	(203,407)	(245,402)
Financial results	(104,539)	(118,906)
Income before equity stakes	(252,585)	(321,539)
Net profit (loss)	(252,585)	(321,539)
Source: Audited trial balances and audited financial statements




Privatization of the Eletrobras System Distribution Companies			10 agosto 2017
PwC			20


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

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.


Tax exposure

			Risk
Item	Description	Exposure	assessment*
1	Non-technical energy loss - ICMS, PIS, and COFINS	455,161	Possible
2	Write-off of PIS and COFINS credit on tariffs and charges	72,491	Possible/Remote
3	ICMS on CDE program subsidies	42,341	Possible
4	CVA	13,808	Probable
Total of quantified tax exposure		583,801
Source: Pw C analysis
(*) Risk assessment for exposures reported in accordance w ith Loeser e Portela Advogados


Labor and social security exposure

			Risk
Item Description		Exposure	assessment*
1	PLR disqualification	34,540	Possible
2	Medical and dental care	14,900	Possible
3	Irregularities related to work days	8,862	Probable
Total of quantified tax exposure		58,302
Source: Pw C analysis
(*) Risk assessment for exposures reported in accordance w ith Loeser e Portela Advogados




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


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


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.

•	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		834,227	841,442
Total		834,227	841,442
IRPJ 25%		208,557	-
CSL 9%		-	75,730
Total		208,557	75,730
Source: ECF and Calculation Records




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

Belo Horizonte, November 1, 2017.

Gentlemen,

In furtherance of the service provision agreement, this paper is part of the services retained for Eletrobras Distribuição Acre 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 Contracting Party.

Best regards,

_______________________________

Alexandre Moreira Galvão

Legal Representative & Stockholding Director

“tatutoŒÇ LaÁ íî.óôï dated JavuaŒÇ íí, îìíï, AŒti le ô, PaŒagŒaph í A: ^Whev the seŒÀi e pŒoÀideŒ is a legal evtitÇ

diŒe tlÇ oŒ ivdiŒe tlÇ ovt olled Ç the goÀeŒvuevt, the Uviov Áill e evtitled to hold su h iddivg pŒo eduŒe as de

s Œi ed iv the head se tiov of this a ti le, ou ived Áith the seŒÀi e pŒoÀidivg legal evtit ovtŒol tŒavsfeŒ, avd gŒavt

ivg the utilit ovt a t to the veÁ ovt ollivg sha eholdeŒ foŒ a ïì Çea peŒiod._


Ceres )nteligência Financeira	t





TABLE LIST

Table 1 - Other Revenue Sharing (%)	28
Table 2 - Unrecoverable Revenue per Consumption Class	30
Table 3 - Unrecoverable Revenue Limits – Neutrality of Charges	31
Table 4 - Summary of Applicable Methodologies	39
Table 5 - End 2017 Threshold for Operating Management	43
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	61
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 of Investment with Maintenance prior to Rate Review	69
Table 22 - Maintenance	69
Table 23 - Personnel Expenses Forecasting 1 of 3	76
Table 24 - Personnel Expenses Forecasting 2 of 3	77
Table 25 - Personnel Expenses Forecasting 3 of 3	78
Table 26 - Material Expenses Forecasting 1 of 3	79
Table 27 - Material Expenses Forecasting 2 of 3	79
Table 28 - Material Expenses Forecasting 3 of 3	80
Table 29 - Service Expenses Forecasting 1 of 3	81
Table 30 - Service Expenses Forecasting 2 of 3	81
Table 31 - Service Expenses Forecasting 3 of 3	82
Table 32 - Other Expenses Forecasting 1 of 3	82
Table 33 - Other Expenses Forecasting 2 of 3	83
Table 34 - ther Expenses Forecasting 3 of 3	83
Table 35 - PMSO Expense (BRL ‘000) and Network Extension (Km) of Evaluated Distributors and Benchmark	84
Table 36 - Estimated Upper and Lower Efficiency Limits - Eletroacre	85
Table 37 - Efficiency Limits of Evaluated and Private Distributors	85
Table 38 - Average of Reference Limits for the Evaluated Distributor Limits Forecasting	85
Table 39 - Payroll Realized Dec /16 (in BRL ‘000)	88
Table 40 - Voluntary Dismissal Plan (PDV) Forecasting	88

Ceres Inteligência Financeira		x


Table 41 - Offsetting History of the Evaluated Distributor and its Benchmarks and Forecasting of the Evaluated
Distributor	93
Table 42 - Offsetting History of the Evaluated Distributor up to the Benchmark Group Average	93
Table 43 - Offsetting Evolution of the Evaluated Distributor and Comparison with the Goal 1 of 3	94
Table 44 - Offsetting Evolution of the Evaluated Distributor and Comparison with the Goal 2 of 3	94
Table 45 – Offsetting Evolution of the Evaluated Distributor and Comparison with the Goal 3 of 3	94
Table 46 – Financings (1 of 5)	95
Table 47 – Financings (2 of 5)	96
Table 48 – Financings (3 of 5)	97
Table 49 – Financings (4 of 5)	98
Table 50 – Financings (5 of 5)	98
Table 51 – RGR fund financing premises	99
Table 52 – RGR Releases	100
Table 53 – Net Debt Balance	101
Table 54 – Due Diligence Contingencies	102
Table 55 – Power Purchase Agreements	104
Table 56 – Definition of Other Revenues	105
Table 57 – Details on Other Revenues in the Trial Balance Sheet (in BRL ‘000)	106
Table 58 – Initial and Final Rate of Fully Depreciated Assets over the VNR	117
Table 59 – Regulatory Remuneration Base 4CRTP (R$ ‘000) – Eletroacre	118
Table 60 – Operation of Assets (BRL ‘000) 3CRTP to 4CRTP – CEAL	119
Table 61 – ANEEL Adjustments 3CRTP – Incremental Base – CEAL	119
Table 62 – ANEEL 3CRTP Adjustments – Incremental Base – Celpe (Benchmark)	120
Table 63 – ANEEL 3CRTP Adjustments - Incremental Base – Energisa Pb (Benchmark)	120
Table 64 – ANEEL 3CRTP Adjustments - Incremental Base – Energisa Se (Benchmark)	121
Table 65 – ANEEL Adjustment Average, Benchmarks Group 3CRTP - Incremental Base	121
Table 66 – ANEEL 3CRTP Adjustments - Armored Base – CEAL	122
Table 67 – ANEEL 3CRTP Adjustments - Armored Base – Cepisa	122
Table 68 – ANEEL Adjustment Average, Group Evaluated Distributors 3CRTP - Armored Base	122
Table 69 – Balance of the CEAL Fixed Assets in Progress in Jun/17	124
Table 70 – Indemnification Forecasting	125
Table 71 – Tax Loss Balances and CSL Negative Base	126
Table 72 – Special Obligations Forecasting (in BRL ‘000)	128
Table 73 – History of Special Obligations and Recurrence (in BRL ‘000)	128
Table 74 – Weight Values of Indicators of Quality of Concession Holders with more than 60 thousand
Consumption Units	130
Table 75 –DEC and FEC Global Limits from 2018 to 2022, including	133
Table 76 – DEC Indicator - Realized/Forecasted x ANEEL Limits 1 of 3	134
Table 77 – DEC Indicator - Realized/Forecasted x ANEEL Limits 2 of 3	134
Table 78 – DEC Indicator - Realized/Forecasted x ANEEL Limits 3 of 3	134
Table 79 – Indicator of Forecasted/Realized DEC X ANEEL Limit 2015-2047	135
Table 80 – Realized DEC Variation Rate and Potential per Period	135
Table 81 – Benchmark Evaluation Premises	135
Table 82 – DEC Benchmark Curve	136
Table 83 - FEC Indicator - Realized/Forecasted x ANEEL Limits 1 of 3	136

Ceres Inteligência Financeira		y


Table 84 - FEC Indicator - Realized/Forecasted x ANEEL Limits 2 of 3	136
Table 85 - FEC Indicator - Realized/Forecasted x ANEEL Limits 3 of 3	136
Table 86 - Indicator of Forecasted/Realized FEC X ANEEL Limit 2015-2047	137
Table 87 - Realized and Potential FEC Variation Rate per Period	137
Table 88 – Benchmark Evaluation Premises	138
Table 89 - FEC Benchmark Curve	138
Table 90 – FER Indicator - Realized/Forecasted x ANEEL Limit 1 of 3	140
Table 91 - FER Indicator - Realized/Forecasted x ANEEL Limit 2 of 3	140
Table 92 - FER Indicator - Realized/Forecasted x ANEEL Limit 3 of 3	140
Table 93 - FER Indicator - Forecasted/Realized X ANEEL Limit 2015-2047	141
Table 94 – Realized and Potential FER Variation Rate per Period	141
Table 95 - FER Realized Benchmark	141
Table 96 - FER Realized Benchmark Group	142
Table 97 - IASC Indicator – Realized/Forecasted x Goal 1 of 3	143
Table 98 - IASC Indicator – Realized/Forecasted x Goal 2 of 3	143
Table 99 - IASC Indicator – Realized/Forecasted x Goal 3 of 3	143
Table 100 - IASC Indicator - Forecasted/Realized X ANEEL Limit 2015-2047	144
Table 101 – Realized and Potential IASC Variation Rate per Period	144
Table 102 - IASC Realized Benchmark	144
Table 103 - IASC Realized Benchmark Group	145
Table 104 - INS Indicator Realized and Projected x Meta 1 of 3	145
Table 105 - INS Indicator Realized and Projected x Target 2 of 3	146
Table 106 - INS Indicator Realized and Projected x Target 3 de 3	146
Table 107 - INS Indicator Projected/Realized X ANEEL Limit 2015-2047	146
Table 108 – Realized and Potential Variation Rate of INS per Period	147
Table 109 - INS Realized Benchmark	147
Table 110 – Group of Benchmark of INS Realized	147
Table 111 - IAb Indicator – Realized/Projected x Goal 1 of 3	148
Table 112 - IAb Indicator – Realized/Projected x Goal 2 of 3	148
Table 113 - IAb Indicator – Realized/Projected x Goal 3 of 3	149
Table 114 - IAb Indicator - Projected/Realized X ANEEL Limit 2015-2047	149
Table 115 – Realized and Potential Variation Rate of IAb per Period	149
Table 116 – Benchmark of IAb Realized	150
Table 117 – Group of Benchmark of IAb Realized	150
Table 118 - ICO Indicator – Realized/Projected x Goal 1 of 3	152
Table 119 - ICO Indicator – Realized/Projected x Goal 2 of 3	152
Table 120 - ICO Indicator – Realized/Projected x Goal 3 of 3	152
Table 121 - ICO Indicator - Projected/Realized X ANEEL Limit 2015-2047	153
Table 122 –Realized and Potential ICO Variation Rate per Period	153
Table 123 – Benchmark of ICO Realized	153
Table 124 – Group of Benchmark of ICO Realized	154
Table 125 – Evolution and Impact of the X Factor Components	157
Table 126 – Calculation of Regulatory WACC	158
Table 127 – Calculation of the Cost of equity (Ke)	159
Table 128 – Financial Structure of the Companies	160

Ceres Inteligência Financeira		z


Table 129 - Enterprise Value and Company Debt	161
Table 130 – Weighted Cost of Debt used for the composition of Kd	161
Table 131 - CDI Bradesco Forecast	161
Table 132 – Calculation of Kd Cost	161
Table 133 – Calculation of the Weighted Average Cost of Capital (WACC)	162
Table 134 – Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2016-2027 (%)	164
Table 135 - Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2028-2037 (%)	164
Table 136 - Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2038-2047 (%)	165
Table 137- Curve of Irrecoverable Revenues per Consumption Class of the Distributor 2048-2052 (%)	165
Table 138– Distribution of Total Invoicing and Not Received (in R$ '000)	165
Table 139 - Targets ANEEL per Regulatory Cycle	166
Table 140 – Level of Technical Loss and Loss in the Basic Grid.	168
Table 141 – Projected Regulatory Losses 1 of 3	170
Table 142 – Projected Regulatory losses 2 of 3	170
Table 143 – Projected Regulatory losses 3 of 3	170
Table 144 – Annual Loss Decrease Rate Definition: Benchmark Company CEMAR	171
Table 145 – Starting Point and Goal of Non-Technical Losses	171
Table 146 – Projected Actual Losses 1 of 3	171
Table 147 – Projected Actual Losses 2 of 3	171
Table 148 – Projected Actual Losses 3 of 3	172
Table 149 – Initial Balances of the Working Capital	173
Table 150 – Parameters of projected NCG	174
Table 151 – Benchmark operating due dates Northern Region	174
Table 152 – Balances with special treatment	175
Table 153 – Settlement of Long-Term Balances	175
Table 154 - Sectorial Charges	176
Table 155 - Transmission Costs	177
Table 156 - Benchmark Revenue and Annual Revenue	177
Table 157 - CVA	178
Table 158 – Solvency Indicator	179
Table 159 – Evolved Gross Income	180
Table 160 – Default	181
Table 161 - Operating Costs and Expenses	182
Table 162 – Costs versus EBITDA	182
Table 163 – PMSO Expenses	184
Table 164 – Analysis of Net Revenue, Costs and Gross Margin	187
Table 165 – Evolved EBITDA, Gross Profit and Expenses	188
Table 166 – Summary Financial Indicators 2017 to 2026 (1 of 3)	189
Table 167 – Summary Financial Indicators 2027 to 2036 (2 of 3)	189
Table 168 – Summary Financial Indicators 2037 to 2047 (3 of 3)	189
Table 169 – Projected DRE Eletrobras Distribuição Alagoas	190
Table 170– Projected Indirect Cash Flow Eletrobras Distribuição Alagoas	191
Table 171 – Projected Cash Flow to Firm Eletrobras Distribuição Alagoas	192
Table 172 - Results from Appraisal Eletrobras Distribuição Acre	193
Table 173 – Valuation Components	193

Ceres Inteligência Financeira		{


Table 174 – Adjusted Enterprise Value	194
Table 175 – Projected Cash and Gross Debt Balance	194
Table 176 - WACC and BRRL Sensitivity – Enterprise Value	195
Table 177 - WACC and BRRL Sensitivity – Valuation	195
Table 178 – Data from Eletrobras Distribuição Acre for appraisal by multiples (R$’000)	196
Table 179 - Multiples Companies Privatized from 1997 to 2000	199
Table 180 - Enterprise Value from the Multiples of Companies Privatized from 1997 to 2000 (R$’000)	199
Table 181 - Multiples Publicly Held Companies	201
Table 182 - Enterprise Value from the Multiples of Publicly Held Companies (R$’000)	201
Table 183 - Multiples CELGD	203
Table 184 - Enterprise Value from Multiples of CELG D (R$’000)	203
Table 185 - Multiples from Share Transfer	206
Table 186 - Enterprise Value of Multiples from Share Transfer (R$’000)	206
Table 187 - Date of Privatization of Comparable Companies	207
Table 188 - Multiples Privatizations from 1997 to 2000	208
Table 189 - Multiples Foreign Transactions	210
Table 190 - Enterprise Value Foreign Transactions	210
Table 191 – Median of Multiples (1 of 2)	211
Table 192 - Median of Multiples (2 of 2)	211
Table 193 - Enterprise Value from the Median of Multiples (R$’000)	212
Table 194 – Market Discount Rates	214
Table 195 – VMU/VNR Ratio 2022 - Machinery and Equipment	215
Table 196 – Grouped Personnel (PMSO) and Realized Accounts 2012-2016 1 of 2	218
Table 197 – Grouped Personnel (PMSO) and Realized Accounts 2012-2016 2 of 2	219
Table 198 – Grouped Materials (PMSO) and Realized Accounts 2012-2016	220
Table 199 – Grouped Service (PMSO) and Realized Accounts 2012-2016 1 of 2	221
Table 200 – Grouped Service (PMSO) and Realized Accounts 2012-2016 2 of 2	222
Table 201 – Grouped Others (PMSO) and Realized Accounts 2012-2016	223
Table 202 – Re-rating of Asset Balances	224



Table 203 - Re-rating of Liabilities ^BalancesFIGURE LIST	225

Figure 1 – Owners’ Equity Cost (Ke) Breakdown	36
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 – 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
Figure 10 – Offsetting Evolution of the Evaluated Distributor and Comparison with the Goal	94
Figure 11 – Composition and Evolution of the X Factor Components	157


Ceres Inteligência Financeira		sr

Introduction

Purpose

The purpose of this paper is to issue a Financial & Economic Evaluation Report on Eletrobras Dis-tribuição Acre 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 Acre 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 Inteligência Financeira	12

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 actual 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 Inteligência Financeira	13

General Rules

Revenues deemed a reference to reach tariff moderateness shall correspond to the average revenue invoiced plus taxes, in the 36 months preceding the 6^thmonth before the review date, updated at IGP-M³thru the review date, multiplied by 12, as defined in Chapter 3 “Other Revenue Methodology” of Sub-module 2.7 in PRORET.

In the event the activity was started within a period shorter than 36 months, then we consid- ered the average revenue invoiced thru the 6^thmonth before the review date, updated at IGP- M, multiplied by 12.


³Value updating calculation: A * updating at IGP-M thru review date * 12.
Wherein, for updating in:
2015 and 2016: A = average revenue invoiced in the last 12 months, as of the 2^ndmonth before the tariff review date;
2017: A = average revenue invoiced in the last 24 months, as of the 6^thmonth before the tariff review date;
2018 on: A = average revenue invoiced in the last 36 months, as of the 6^thmonth before the tariff review date.


Ceres Inteligência Financeira	29

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 open capital 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.


Ceres Inteligência Financeira	33

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 country risk premium, regarding the credit risk in the Brazilian Economy against the global market, and the exchange risk, showing the uncertainties about the BRL 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 Exchange FRC, 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, Exchange FRC, 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 less 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:


Ceres Inteligência Financeira	34

Risk Free Rate

The owners’ equity cost calculation is primarily based on the business risk analysis, added by the economy’s risk-free yield rate. As the US economy has more diversity in its indexes and is still considered as an international standard of a risk-free economy, at least so far, the rates practiced by the US Treasury are generally used as a parameter, such as the Treasury Bonds (T-Bonds) as the initial standard.

The rate was constructed using the interest rate curve, a practice that must be respected due to the impossibility of short-term flows being remunerated at long-term rates, since they will be subject to a marked-to-market interest rate curve in the redemptions of these investments.

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

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


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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 FRC and T-Bonds, which more directly reflect the country risk present in the interest curve.

Exchange Risk

To estimate the foreign exchange risk premium, the forward premium was obtained by the breakdown of domestic interest rates and the FRC, which already includes the country risk. The foreign exchange coupon and FRC 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 Contract (FRC) 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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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.


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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.

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.


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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 January 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 goals 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 Temporary Distribution Service Provision Plan, duly executed by the same signatories hereto, detailing the actions to be taken by the management, with a view to abide by the terms and conditions set forth by ANEEL during the assignment period granted by the Contract-Letting Branch of Government.”


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The evaluation model treated such special norm, containing goals and specific budget for 2017. The treatment is due to the need to estimate the start balances for the valuation at the beginning of 2018.

For subsequent years, we considered the private Concession Contract and performance trajectories of distributors according to this new reality. In its turn, the statutory goals were adjusted consistently with the reality and the complexity of the service provision in those regions. More to the point, we considered the terms and conditions contained in the draft template for the Electric Power Distribution Concession Contract, as per resolution issued by the Board of ANEEL during the 15^thOrdinary Public Meeting held on May 2, 2017.

Likewise, the tariff review expected for those distributors was suspended. The new draft contract allows the possibility of accelerated tariff review in the new agreement⁶, a premise taken into account for the Base Scenario 2019.

Those distributors’ compensation bases appear to be outdated, and the unitizing process is underway, in many of them, it may valorize their compensation bases. As a final point, different compensation bases were simulated, given the expected results that may be obtained by Eletrobras, supported by such reports.

Related Parties

The distributors have debt agreements with Eletrobras. Those agreements were priced separately, so as to allow possible debt restructuring with the shareholder.

Outstanding CCC Values and other Industry-Related Charges

There are debt balances for industry-related default. Normative Resolution No. 748/2016 resets post-assignment commitments and provides for loans with RGR funds for cash closing. CCC/other debt flows were treated separately, and the amounts of receivables and payables were reconciled.


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

We forecasted the amounts payable and receivable by means of CDE funds for Program ‘Light to Everyone’ (PLPT) thru expiration scheduled for December 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 September 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.

General Comments on the Report

This report contains the assumptions, analyses and forecasts carried out for the valuation of the distribution companies for the privatization process. The analysis period is from 01-Mar-18 to 28-Feb-2048, which period is used to calculate the evaluation results.

Illustratively, tables and charts are shown in annual values thru 31-Dec-47, seeing as the year 2048 covers only two months of evaluation, thus avoiding a distorted perception of the value over the series.


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Summary of Business and Existing Structures

Features of the Business

Eletrobras Distribution Alagoas, corporate name Companhia Energética de Alagoas (CEAL), was created in 1983 under State Law No. 4.450 dated July 05, 1983 from Companhia de Eletricidade de Ala-goas (CEAL), constituted by State Law No. 2.137, dated April 08, 1959, and record of the public deed for constitution on August 17, 1960.

In July 1997, the Federation, upon intermediation by Eletrobras, took over the share control of Com-panhia Energética de Alagoas, when they assumed most shares upon acquisition of 50% of the nominative shares, which were controlled by the State of Alagoas.

In June 2008, the new management model was implemented for the distribution companies of ELETROBRAS, setting a single and integrated direction, aiming to unify procedures, put employees of different cultures closer, and reinforce confidence of customers served in the different territories of operation. As a holding company, ELETROBRAS controls great part of electric power generation and transmission systems in Brazil, and operates in the distribution segment by means of companies Eletrobras Amazonas Energia, Eletrobras Distribuição Acre, Eletrobras Distribuição Roraima, Eletrobras Distribuição Rondônia, Eletrobras Distribuição Piauí, and Eletrobras Distribuição Alagoas.

Currently, by means of Ordinance of the Ministry of Mines and Energy (MME) No. 424, dated August 03, 2016, Eletrobras was designated as responsible for the provision of public power distribution service in the 102 municipals in Alagoas until December 31, 2017, due to non-renewal of its Concession Contract No. 07/2001.


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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 Residential and Commercial segments have presented a greater growth, higher than 6% p.a, while the Industrial and Other classes presented numbers higher than 4% p.a., except for the rural industry, which had growth below the others, of 0.23% 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. In 2007, the residential sector was responsible for 35.03% of the total consumption, against 39.27% in 2016, with the commercial sector having 20.42% in 2007 against 22.00% in 2016, and the other sectors remaining basically constant.


¹⁹Source: Distributor’s statement of invoicing
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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 “Programa Luz para Todos” (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 projected investments to each distributor.

Three groups have been segregated: (i) low and medium voltage, (ii) high voltage, and (iii) “Programa Luz Para Todos”. 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 projected 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 projected for the high voltage Market served as an input to obtain the network expansion of that class.

Regarding “Programa Luz Para Todos” (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 Programa Luz para Todos in included in the 2001-2006 history, in low and medium
voltage


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Investment Forecasting

Deployment and Renewal

The CEAL 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 CEAL”, annex II, in addition to indications of CEAL’s technical team, obtained in the meetings organized by CERES, were used to define CEAL’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 CEAL”, annex II, were considered as a whole and added to the expenses with Renewal (Maintenance) in 2017 of the Provisional Plan.

Only 30% of the expenses with program Luz para Todos were considered for years 2017 and 2018, since the other 70% were subsidized with CDE resources and have been allocated as Special Obligations. In addition, approximately BRL 65.8 million of the investments with High Voltage Expansion in 2018 were also considered as Special Obligations. There was no sub-rogation of investments for CEAL.

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 2020 and 2026.

Medium Voltage/Low Voltage Expansion: As of 2019, the amount is equivalent to the average of amounts expended between 2018 and 2022 on the base date of December 2016, considered as fixed until the end of the forecasting.

Improvement: Based on information supplied by CEAL’s technical team, it has been defined that, in 2023, the amount corresponds to the average of the amounts spent between 2019 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


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

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 projected, are calculated as the average of expenses in the sampling period, excepting outliers.

Variable accounts, when projected, 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 projected 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 BRL/Parameter, multiplied by the forecasting⁴⁰of Network Extension (Km) or MWh Extension.

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

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.


⁴⁰Detailed in the chapter on Consumption and Demand Forecasting
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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 goal 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 BRL/Consumption unit indicator of the cycle goal, 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 goals 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 BRL 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.

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


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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Nordeste: Ceal, Cepisa, Celpe, Cemar, Coelba, Coelce, Cosern, Energisa Paraíba e Energisa Sergi-pe;

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.


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 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.

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 Decem-ber 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.


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 compensa-
tion. 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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1 – Normative Resolution no. 748, dated November 29, 2016⁵⁹, 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, procedure: 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 Distribution⁶⁰.

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 Obli- gations 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 previous calendar year, such difference shall be invested doubled in the concession


⁵⁹ANEEL
⁶⁰As resolved by ANEEL Management in the 15^thOrdinary Public Meeting, held on May 2, 2017


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Agreements for the Purchase and Sale of Power

Summary of Agreements for the Purchase and Sale of Power

The data contained in the contracts were collected to define the characteristics of the agreements of purchase and sale of power in the Regulated Contracting Environment (ACR). Such data were validated with spreadsheets of internal control assigned by the distributor and with the spreadsheet updated in March 2017, of Consolidated Result of Electric Power Auctions per Contract, obtained on the website of the Electric Power Trading Chamber.

After gathering information on the contracts, the SPARTA system, 2016 readjustment, calculated if the power purchase volume was the same found in the contracts and spreadsheets of internal control. From the validation, the necessary volumes were added in order to obtain values and volumes compatible with the SPARTA.

With the data on quantity of power, price, beginning of effectiveness, end of effectiveness, base date of price, month of readjustment, and index rate of the readjustment of each contract, it was possible to group them based on the beginning and end of the contractual effectiveness, and to readjust the prices in order to update them. Thus, the contracts have been synthesized as shown in the table below. Such data were used as the basis for the demand of power to compose Installment A.


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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;


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(20) RGR PLPT Rate;

(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 Adjustments⁶².

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 Acre: SETAPE – Report: “EDAC Executive Summary – Complete Base –Evaluation of the Electricity Assets of Acre – Eletrobras Distribuição Acre”, 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 Ener-gia – 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;


⁶²Performed by ANEEL inspection
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Eletrobras Distribuição Roraima: Levin – Complete Evaluation Report: “Eletrobras Distribuição Rorai-ma 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 CRTPs⁶³.

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 includes⁶⁴from 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 4CRTP⁶⁵.

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.


⁶³To 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
⁶⁴These same lines are also included for the Asset Evaluation Report that reviews the Incremental Base
⁶⁵Item 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 Base⁶⁶between 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 4CRTP⁶⁷, 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 Base⁶⁸, Northern companies were attributed a disallowance of 5.73% and Northeastern companies had disallowance of 5.01%.

From 2018 to 2048⁶⁹, the average adjustment of the benchmark private distributors⁷⁰is 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


⁶⁶In the specific cases in which they are reviewed and presented again, as occurring to the Evaluated Distributors
⁶⁷Provided by the investment evaluators between 3CRTP and 4CRTP
⁶⁸Armored Base of the Complete Report less Armored Base of the Incremental Report
⁶⁹From the period of a new concession
⁷⁰Benchmark 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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in the average that their asset disallowances are reduced when compared to the period prior to the private concession holder.

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 adjusted⁷¹by the IPCA⁷²: (1) Fixed Assets in Use (New Replacement Value); (3) Special Gross Obligations; (10) Stockroom in Operation; (11) Deferred Asset;


⁷¹The IPCA is applied directly to the value observed from the Initial Base, also considering their increments and write-off
throughout the evaluation period
⁷²National Price Index to the Broad Consumer Amplo – 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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(13) Real Properties and Easements;

(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)⁷³by 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)⁷⁴by the ratio between the Accumulated Fully Depreciated Assets over the Accumulated VNR, both items of the ratio are in the same monetary date.


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 Rate⁷⁵by 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 Obligations⁷⁶is 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
⁷⁶Monetarily 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 agency⁷⁷, 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;

(16) RGR Balance Other Investments.


⁷⁷ANEEL PRORET Submodule 2.3, V2.0, of Normative Resolution no. 686/2015, dated 11/23/2015
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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)⁷⁸of 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.


⁷⁸Monetarily 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 Alagoas, the Complete Assessment Report “Companhia Energética de Alagoas – CEAL project No. 2715-17745” made by Levin is highlighted, 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. Program “Luz para Todos” (PLPT)⁸⁵is 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.


⁸⁵Tratado com maior detalhe no capítulo de investimentos
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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 goals 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 goals established by ANEEL. The levels of coverage or not of each distributor are compared with the results obtained by the distributors of a same group⁸⁶. A distributor may be between the 25% best or worst companies to whether achieve or not the goal, 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 goals 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:


⁸⁶Groups are defined by size of company, as per Submodule 2.5 V2.0 of ANEEL’s PRORET
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“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 previous 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 analyses⁹⁰may 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 2016⁹¹and adjusted according to ANEEL’s goal of reduction for 2017⁹²of DECi and FECi⁹³. 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 benchmark⁹⁴. 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.


⁹⁰DEC and FEC Analyses are carried out in separate but have common constructive logical structure
⁹¹Annual DEC and FEC of the ase of collective indicators of continuity of ANEEL
⁹²Procedure 48500.004245/2016-77, Vote, Table 1 – Limit for the end of 2017 for operational management. Variation % be-
tween the Determined DECi and its Limit for 2017 and the Determined FECi and its Limit for 2017
⁹³Internal DEC and Internal FEC, indicators that accompany the interruptions occurred in the distribution system of internal
origin
⁹⁴Companies with geographic proximity to the evaluated distributors


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late the simple average of the indicator of each established group¹⁰⁴. The joint geometric mean per group is applied between years 2012 and 2016¹⁰⁵, having (2017 Indicator)*(1+Rate of Variation of 2013-2016 Benchmark Group) and so successively until the indicator achieves the FER goals defined by ANEEL of the evaluated distributions to the years starting in 2017.

The FER goal used is the limit to year 2017 and after that, defined¹⁰⁶by ANEEL to each distributor. When achieving the goals in the period, distributors stabilize their efforts to improve the indicator. In the long term, companies tend to have indicators equal to the goals estimated to ANEEL. This makes companies tend to achieve the other 75% of the distributors that achieve the FER goals.


¹⁰⁴Benchmark distributors of the Northern region: Celpa and Celtins (Energisa TO) and benchmark distributors of Northeastern
region: Celpe, Cemar, Energisa Paraíba and Energisa Sergipe
¹⁰⁵2012 is the year in which the FER indicators of the groups of private companies are more similar to te average of the indica-
tors of the evaluated distributors. From such common point, we evaluate how the indicator of non-state owned is developed and
apply its variation rate to the FER of the evaluated companies
¹⁰⁶Normative Resolution no. 574, dated August 20, 2013


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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 2016¹¹⁴. The average is calculated by excluding the missing data¹¹⁵from 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 distributors¹¹⁶. 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 2016¹¹⁷, 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 adjusted¹¹⁸to reach the target established by ANEEL¹¹⁹for 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%¹²⁰from 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.


¹¹⁴ICO base of Distribution Indicators of ANEEL
¹¹⁵The year of 2016 and other points along the historical series present missing data, reason which the average reference
checked in the period was used
¹¹⁶Companies geographically located near the distributors evaluated
¹¹⁷The interval with longer historic period was used, without missing data among the benchmark outsourced
¹¹⁸Speed near that checked by the outsourced companies will be presente din the specific analysis for each distributor

¹¹⁹Estimated by Ceres as it will be addressed below
¹²⁰PRORET 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/ANEEL¹²²in its “Clause Nineteenth – Transitory Provisions”, Subclause Three, the value of Pd component will be defined as zero¹²³between the agreement execution ate and the first subsequent ordinary tariff revision.

Q Factor

The Q Component of the X Factor composed 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 Sep 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 zero¹²⁴, as provided in the Technical Note no. 88/2017-SEM/SGT/SRD/ANEEL¹²⁵.


¹²²On May 3, 2017, case 48510.000502/2017-00
¹²³Also provided in the Technical Note 149/2017-SEM/SGT/SRD/SFF/ANEEL on Sep 8, 2017, case 48500.002667/2017-99
¹²⁴Also provided in the Technical Note 149/2017-SEM/SGT/SRD/SFF/ANEEL on Sep 8, 2017, case 48500.002667/2017-99
¹²⁵On May 24, 2017, case 48500.002667/2017-99


Ceres Inteligência Financeira	156

Irrecoverable Revenues

Analyses Common to the Distributors

The irrecoverable revenues evaluated are the value invoiced that had not been received up to certain set date. Irrecoverable revenue is that deemed the indicator average: (value invoiced not received in the period t)/(total value invoiced in the period t), from the 49th to the 60th month prior to the base date.

The analysis can be divided into three main parts: an estimate for 2017, a variation rate of the indicators along the concession period and the target established.

To assess the indicator level in 2017, the medium value of the indicator was calculated for the base date of Dec/16. For each consumption class, the total value invoiced in the 60 prior months¹²⁶was assessed as well as the total value not received of such respective months in relation to the base date of Dec/16¹²⁷.

The medium value was calculated between the value invoiced not received over the total value invoiced between the months of Dec/11 and Nov/12 inclusive, reaching the value of irrecoverable revenues on the base date of Dec/16.

The percentage of annual variation proposed by ANEEL in the indicator between 3CRTP and 2CRTP was applied to the value of Dec/16, reaching the value estimated for Dec/17. Thus, it was concluded that the company reached the variation forecast by the regulating body.

In relation to the variation rate after 2017, between 2017 and 2020, it was concluded that the variation rate proposed by ANEEL between 3CRTP and 2CRTP carries on being reached, completing a period of four years in this variation rate, according to initial forecast of ANEEL.

From 2021, the variation rate considered is that proposed in the variation from 4CRTP to 3CRTP. Such order of variations is chosen based on the difference of the rates initially proposed by the regulating body. The variation from 3CRTP to 2CRTP in average is softer than that proposed from 4CRTP to 3CRTP. It is agreed that the default levels need time to be deeply changed and, therefore, a less accelerated rate was used in the 3 first years of concession and a more accelerated rate was applied in the subsequent years.


¹²⁶Data obtained from the distributors also made available for ANEEL. Period prior to the base date considered from Dec/11 to
Nov/16
¹²⁷Considering Dec/16, when what was invoiced, e.g.; in Jan/15, has not yet been received by the distributor


Ceres Inteligência Financeira	163

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 projections 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.


Ceres Inteligência Financeira	167

Final Considerations

The fair value of the business for the Enterprise Value indicates R$ 1,994,373,551.48 to Eletrobras Distribuição Alagoas and granting of new Concession Agreement. However, the debts, liabilities with suppliers and contingencies cause the company’s Valuation to be negative at R$ 1,116,190,768.34.

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 X Factor and more strongly the Non-Recoverable Revenues of CEAL generate current amounts which decrease the business value. However, the reduction possibility of PMSO adds value to the future shareholder. Although there is great conditions 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 CEAL.

Analysis by multiples showed that the appraised company has an indicated amount greater than that suggested by the metrics of the compared private companies. In spite of the regional specificities, the increased indebtedness level, the companies’ status and specific risk premiums, regulatory adjustments and proposals added value to the company. In addition, taxes to be recovered of about R$ 284,286,530.00, arising out of aggregate losses throughout the years, are being considered.


Ceres Inteligência Financeira	213

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

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

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 Eletrobrás 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 Companhia Energética De Alagoas.

As contemplated under the Contract, the sole purpose of the Report is to provide a valuation of Companhia Energética De Alagoas 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.


Summary
1.	Introduction		9
1.1.	Context		9
1.2.	Purpose		9
1.3.	Summary of the Assumptions		9
1.4.	Valuation		11
2.	History and Characteristics of the Concession		12
2.1.	Brief History		12
2.2.	Description of the Operating Area		12
2.3.	Socioeconomics		13
2.4.	Transportation Infrastructure		14
2.5.	Climate		17
2.6.	Geoelectric Characteristics		19
3.	Market and Consumption Unit Forecasts		23
3.1.	Market and Consumption Units (CU) History		23
3.2.	Market Forecast Methodology		25
3.3.	Market Forecast Results		32
3.4.	Consumption Unit Forecast Methodology		38
3.5.	CU Forecast Results		40
4.	Methodologies, Premises, Results from Readjustment and Reviews		42
4.1.	Overview		42
4.1.1.	Regulation by incentives		42
4.1.2.	Recent changes to the contractual and tariff rules of the electric power distribution.		46
4.2.	Methodologies, Premises and Results for the Definition of Part A		65
4.2.1.	Purchase of Power and Tariff Flags		65
4.2.2.	Charges		66
4.2.3.	Transport Costs		67
4.2.4.	Financial		68
4.2.5.	Technical Losses (“PT”)		69
4.2.6.	Non-Technical Losses (“PNT”)		77
4.2.7.	Default		95
4.3.	Methodology for definition of Part B		97
4.3.1.	Regulatory WACC		98
4.3.2.	Operational costs and Factor Xt		101
4.3.3.	Factor Xpd and Xq		115
4.3.4.	Demand Surplus, Reactive Excess and Other Revenues		120
4.3.5.	DEC and FEC Indicators		122
4.3.6.	Compensations		134
4.3.7.	Long-Term Investment		137
4.3.8.	Remuneration Base		143

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4.3.9.	Tariff Transactions	159
5.	Analysis of the Distributor	162
5.1.	Historical Financial Statements	163
6.	Valuation	169
6.1.	Methodology	169
6.2.	Discount Rate	169
6.3.	Assumptions	171
6.4.	Valuation by Multiples	179
6.5.	Valuation results	183
6.6.	Sensitivity	190
7.	References	192
ANNEX I – Extent of Responsibility		193
APPENDIX A – Socioeconomic Characterization of the Ceal Concession Area		194
APPENDIX B – Methodologies of Market Projection		197
APPENDIX C - Selection of Models for Market Projections		201
APPENDIX D – Alternative Models Not Selected		203
APPENDIX E – Models of the Assessed DEC and FEC Indicators		207
APÊNDICE F – Concepts and Methods of BRR Valuation		208
APPENDIX G – Company’s Debt Overview		211



Figures

Figure 1 – Macroeconomic assumptions		10
Figure 2 – State of Alagoas (capital in highlight)		13
Figure 3 – Federal and State Highways of Alagoas		17
Figure 5 – Average temperatures observed for the Brazilian states		19
Figure 6 – National Interconnected System		20
Figure 7 - Basic Network of the state of Alagoas		20
Figure 8 - Electric regionals in the state of Alagoas		21
Figure 9 – Map of the status of the transmission and distribution system of the state of Alagoas.		22
Figure 10 – GDP real growth forecasts (% p.a.) of external sources		29
Figure 11 – Schematic drawing for the total forecast of CU		39
Figure 12 – Price cap functioning		43
Figure 13 – Yardstick Competition Functioning		44
Figure 14– Example of Periodicity of Periodical Tariff Reviews and Tariff Readjustments		44
Figure 15 – Time line with changes to the PRORET.		48
Figure 16– Time line with recent rulings related to the renewal of the concessions.		51
Figure 17 - Trajectory of reduction		84
Figure 18 - Periodicity of Forecast of Regulatory Non-Technical Loss Targets		89
Figure 19 - Dynamics of the Regulatory PNT target forecast		91
Figure 20 – Example of a model for calculation of components X Factor quality indicator		119
Figure 21 – Historical Financial Indicators		163
Figure 22 – Summarized Income Statements		164
Figure 23 – Summarized Balance Sheet		164
Figure 24 - Balance Sheet		165
Figure 25 – Income Statements		165
Figure 26 – Quality of earnings		166
Figure 27 – Working Capital		167


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Figure 28 – Net Debt	168
Figure 29 – Due Diligence Financial Indicators	168
Figure 30 - Rolling WACC	171
Figure 31 – Working Capital	178
Figure 32 - EV / Net Revenues Multiples	180
Figure 33 - EV / EBITDA Multiples	181
Figure 34 - EV / BRR Multiples	181
Figure 35 - EV / Consumer Units Multiples (R$ thousand / Number of Clients)	182
Figure 36 - EV / Distributed Energy Multiples (R$ thousand/MWh)	182


Graphs

Graph 1- Density of Total Highways (km/km²)	15
Graph 2 - Percentage of Existing and Planned Highways in 2015	15
Graph 3 - Voltage level share in the total market (%) - Ceal Forecasts	27
Graph 4 – Share of the state GDP in the Brazil GDP (%) - Forecast for Ceal	31
Graph 5 – Forecasted Market of Ceal in each Decade per Class of Consumption.	38
Graph 6 – Forecasted Market of Ceal until 2046 per Class of Consumption	38
Graph 7 – Ceal CU’s Forecasts	41
Graph 8 – Average Loss per Segment of Ceal and Comparable	73
Graph 9 – Forecast of regulatory technical losses of Ceal	77
Graph 10 – Comparison between Real and Regulatory Non-Technical Losses on the Low Voltage Market	78
Graph 11 – Forecast of Verified and Regulatory PNT Ceal (Invoiced)	92
Graph 12 – Example of heterogeneity curve	108
Graph 13 – Ceal efficiency curve	112
Graph14 – Forecast of Other Regulatory Revenues – CEAL (R$ Million)	121
Graph 15 – Forecast of Annual Demand Surplus and Reactive Excess Revenues – CEAL (R$ Million)	122
Graph 16 – Verified Indicator and Limits of DEC for Ceal	124
Graph 17 – Verified Indicator and Limits of FEC for Ceal	124
Graph 18 – History of Compensations for Violation of the Individual Indicators of Ceal	125
Graph 19 – DEC Forecast for Ceal	132
Graph 20 – DEC Forecast for Ceal	133
Graph 21 – Forecasted Compensations for Ceal	137
Graph 22 - Forecast of electric and non-electric investments of Ceal	142
Graph 23 - Long-Term Investments Plan of Ceal per Type of Works/Systems/Vehicles	142
Graph 24 – Tariff Transactions (%)	162
Graph 25 – Industrial Class Ceal: growth rate accumulated in 12 months	204


Tables

Table 1 – Valuation	11
Table 2 – Highway Indicators for the state of Alagoas	16
Table 3 – Climactic Characteristic of the state of Alagoas	18
Table 4 – Evolution of the Number of Consumers per Voltage Level	23
Table 5 – Market Evolution per Voltage Level	24
Table 6 – Mid-Market Evolution per Voltage Level	24
Table 7 – Evolution of the Average Consumption per Tariff Class	25
Table8 – Variables used in the market forecasts per class	28
Table9 – State GDP share in Brazil’s GDP (%)	30
Table 10 – GDP average growth rates (%)	31
Table 11 – Forecasted Market of Ceal in each Decade per Class of Consumption.	37
Table 12 – Summary of the CU Forecast for Ceal	41
Table 13- Values Factor T and Xpd	57
Table 14 - Values of Regulatory Losses	57
Table 15 - DEC and FEC Global Limits	59
Table 16 - Variation of the amounts destined to PMSO per Distributor	62


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Table 17 - Variation of the DEC limits per Distributor	64
Table 18 - Variation of the FEC limits per Distributor	64
Table 19 - Amount of Losses in the Ceal Distribution System	70
Table 20 - Amount of Technical Losses per Segment of Transformation and Grid	71
Table 21 - Technical Loss Target per Voltage Segment	75
Table22 - Amount of Technical Losses per Segment of Transformation and grid	76
Table 23 – Socioeconomic Variables for the Composition of the Complexity Factor to Fight Non-Technical Losses 79
Table 24 - Models Selected for the Composition of the Complexity Factor to Fight Non-Technical Losses	80
Table 25 - Result of the Complexity Indexes of each Econometric Model for the Companies from Grupo Eletrobras
	82
Table 26 - Average Complexity Index	82
Table 27 - Summary of Definition of the Starting Point	86
Table 28 - Example of Forecast of the Regulatory Non-Technical Losses	88
Table 29 - Comparison of Real Invoiced Loss with Regulatory Invoiced Loss	90
Table 30 - Complexity Index of Fighting Non-Technical Losses of the most Complex Distributors from Group 1	90
Table 31 - Forecast Regulatory PNT 2023 to 2027	93
Table 32 - Forecast Regulatory PNT 2028 to 2032	93
Table 33 - Forecast Regulatory PNT 2033 to 2037	94
Table 34 – Forecast Regulatory PNT 2038 to 2042	94
Table 35 – Forecast Regulatory PNT 2043 to 2047	95
Table 36 – Operational Costs Efficiency Parameters in 4CRTP	102
Table 37 – Confidence intervals of the efficiency estimations	103
Table 38 – Cluster Composition	109
Table 39 – Composition of the clusters and efficiency	111
Table 40 – Forecast of Regulatory PMSO Ceal	112
Table 41 – Grid forecast modeling results	114
Table 42 – Operational Costs and Component T Ceal	115
Table 43 – Technical and commercial indicators of component Q of Factor X	117
Table 44 – Commercial indicators in 2016 - Ceal	120
Table 45 – Results for Factor X and its components Ceal	120
Table 46 – Verified/ Forecasted Verified and Approved/ Verified Limit of DEC for Ceal	133
Table 47 – Verified/ Forecasted Verified and Approved/ Verified Limit of FEC for Ceal	134
Table 48 – Compensation Regression Table	136
Table 49- Forecast of Quinquennial Investments 2018-2022	138
Table 50 - Investments in HV Expansion works 2018-2022	139
Table 51 - Mean, Standard deviation and Limits for HV Expansion works	139
Table 52 - Investments in HV Expansion work (outliers excluded)	140
Table 53 - Investments in HV Expansion works 2023-2027	140
Table 54 - Forecast of Investments for the Quinquennium of Ceal	141
Table 55 – Proportions of the Groups of Assets in BAR	146
Table 56 - Calculation of the AIS Considered in the BRR Model in Feb/17	148
Table 57 – Difference between the Initial and the Final Additional AIS (VOC) of the 3rd RTP	149
Table 58 – Values of BRR Considered Starting Point in the Frozen Asset BRR in Feb/17	151
Table 59 –Investments between 2018 and December 2022 per Registration Unit: Impact on the Average
depreciation rate of the Assets	155
Table 60 – Assumptions for Index and Rate Forecast	156
Table 61 – TJLP Forecast	156
Table 62 – Forecast of Regulatory Reintegration Quota in RTPs	157
Table 63 – Forecast for Equity Remuneration without Special obligations in RTPs	157
Table 64 – Forecast for Equity Remuneration of the Special obligations in RTPs	159
Table 65 – Forecast of the Annual Fixed or Portable Facilities Cost in RTPs	159
Table 66 – Estimations for Required Revenues, VPA and VPB for Ceal (rated R$ million)	161
Table 67 - Unlevered Beta of comparable companies	170
Table 68 - Transaction Multiples	179
Table 69 – Distributed energy projections	183
Table 70 – Net revenues projections	183
Table 71 – Operating costs projections	185
Table 72 – Gross profit projections	185


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Table 73 – Operating expenses projections	186
Table 74 – EBITDA projections	187
Table 75 – Net income projections	188
Table 76 – Cash flow projections	188
Table 77 – Terminal Value	189
Table 78 – Valuation Results	189
Table 79 – Financial Covenants	190
Table 80 – Sensitivity Analysis	190
Table 81 – Demographic Information, Education Level and Unemployment Rates	194
Table 82 – Information about Access to Services	195
Table 83 – Information about Income	195
Table 84 – Information about Violence	196
Table 85 – Family of Exponential Models	199
Table 86 – Statistical Indicators	202
Table 87 – Residential Class: Ceal	203
Table 88 – Industrial Class: Ceal	204
Table 89 – Commercial Class: Ceal	205
Table 90 – Rural Class: Ceal	205
Table 91 – Public Entities Class: Ceal	206
Table 92 – Utility Class: Ceal	206




Charts

Chart 1 – Socioeconomic characteristics of the state of Alagoas	14
Chart 2 – Summary with the forecast model for Residential Consumption Ceal	32
Chart 3 – Summary with the forecast model for Industrial Consumption Ceal	33
Chart 4 – Summary with the forecast model for Commercial Consumption Ceal	33
Chart 5 – Summary with the forecast model for Rural Consumption Ceal	34
Chart 6 – Summary of the forecast model for the Consumption of Public Service Ceal	35
Chart 7 – Summary of the forecast model for the Consumption of Public Lighting Ceal	35
Chart 8 – Summary of the forecast model for the Consumption of Public Service Ceal	36
Chart 9 – Summary with the forecast model for Own Consumption Ceal	37
Chart 10 – Example of the need of investments in HV Expansion for the period between 2023-2027	139


Equations
Equation 1 - Box Cox Transformation	26
Equation 2 - Domiciliary Density Calculation	39
Equation 3 - Kt Coverage	39
Equation 4 - Residential CU’s Forecast	40
Equation 5 - Average Consumption Series	40
Equation 6 - CU’s Forecast	40
Equation 7 - Formula for the Maximum Cap Price and Periodical Readjustment	42
Equation 8 - Formulation for Tariff Readjustment Rate	45
Equation 9 - Formulation for the Complexity Factor of Fight Non-Technical Loss of Company A	80
Equation 10 - Calculation of Target of Non-Technical Losses	83
Equation 11 - Global Target	83
Equation 12 – Value of Non-recoverable revenues for companies, which have not undergone 4CRTP yet	96
Equation 13 – Value of Non-recoverable revenues for companies that have undergone 4CRTP	96
Equation 14 – Calculation of Part B in adjustment processes	98
Equation 15 – Calculation of Part B in review processes	98
Equation 16 – Operational Cost Tariff Coverage	104
Equation 17 – Value of the Efficient operational costs	104


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Equation 18 – Annual Variation of the Regulatory Operational Costs	105
Equation 19 – Target of Efficient operational costs	105
Equation 20 – Target of shared Efficient operational costs	105
Equation 21 – Standardization of variables	105
Equation 22 – Euclidean Distance	106
Equation 23 – Efficiency Indicator	110
Equation 24 – Value of the Efficient operational costs	112
Equation 25 – Update Factor	113
Equation 26 – Operational Cost in Tariff review	115
Equation 27 – Component T of Factor X	115
Equation 28 – Component Pd of Factor X	116
Equation 29 – Component Q of Factor X	118
Equation 30 - Determination of Heterogeneity	126
Equation 31 - Limit Equation	127
Equation 32 – Simplified Limit Equation	127
Equation 33 – Linear Regression Equations for DEC	129
Equation 34 – Linear Regression Equations for FEC	129
Equation 35 - Calculation of the average EUSD	135
Equation 36 - Calculation of the Compensation in Force	135
Equation 37 - Forecasted Compensation	136
Equation 38 – Regulatory Reintegration Quota	143
Equation 39 – Gross BRR	144
Equation 40 – Capital Remuneration	144
Equation 41 – Net Regulatory Remuneration Base	145
Equation 42 – Special Obligations Capital Remuneration	145
Equation 43 – Regulatory Annuity Base (BAR)	146
Equation 44 – Annual Rental Cost (CAL)	147
Equation 45 – Annual vehicle Cost (CAV)	147
Equation 46 – Annual Cost of Information Systems (CAI)	147
Equation 47 - Stationary Series	197
Equation 48 - Seasonal Series	197
Equation 49 - Box & Jenkins Methodology Models	198
Equation 50 – ETS Model	198
Equation 51 - Dynamic Model	200


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1. Introduction
	1.1. Context
	Companhia Energética De Alagoas – CEAL (“CEAL”, “Distributor”, or “Company”) is a
quasi-public company headquartered in Maceió, the capital of the State of Alagoas. The Company
is currently controlled by Centrais Elétricas Brasileiras S.A. - Eletrobras, who holds 100% of its
shares. It is a federal utility concession holder responsible for the sale and distribution of
electricity in the State of Alagoas.

	According to Article 2 of Decree 8.893, the Brazilian 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

·	Field Company; visits;
·	financial statements projections (Income Statements and Cash Flow Statements) based on

·	Financial information valuation provided based by the on Company, Discounted market Cash Flow analyses, methodology; and due diligence studies;
·	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

·	Calculation flows; and projection of regulatory WACC.

	1.3. Summary of the Assumptions
	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).


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2. History and Characteristics of the Concession

This chapter will detail relevant characteristics of Ceal, 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

The history of electricity in Alagoas started in the capital, Maceió, which was a pioneer among the Brazilian capitals in terms of electric power, with service started in 1897. The Empresa Luz Elétrica de Alagoas was responsible for the supply of electricity, using a steam engine with three 755 horsepower boilers [1].

In 1913, Nova Empresa de Luz Elétrica (NELE), owned by commander Teixeira Bastos, assumed responsibility for the supply of electric energy, and later became Companhia Força e Luz de Maceió. The name changed once again in 1931, when Amford purchased the company and adopted the name of Companhia Força e Luz do Brasil – Maceió [1].

In 1959, under the government of Muniz Falcão, Alagoas took the first steps towards implementing planning policies. The Electrification Plan for Alagoas was developed for the energy segment. The government of Alagoas set up a joint capital company, Companhia de Eletricidade de Alagoas – Ceal to execute this Plan. The company was linked to the Department of Waters and Energy.

In 1983, due to Law No. 4.450, Companhia de Eletricidade de Alagoas changed names to Companhia Energética de Alagoas, but maintaining the abbreviation Ceal. Under this law, it was allowed to produce and distribute energy in Alagoas.

Ceal was under State control until June 1997, when the federalization process started, with purchase of 50% of the shares by Centrais Elétricas Brasileiras S.A – Eletrobras, which obtained a controlling interest in the company.

Currently, the Eletrobras holding owns 100% of the shares of Ceal on behalf of the Federal Government. On October 2010, the new brand of Eletrobras was standardized for all companies in the System, including the former Ceal, which came to be known as Eletrobras Distribuição Alagoas.

Finally, in July 2016, the Eletrobras group decided not to renew the contracts of electric power suppliers in the North and Northeast regions, including AmE. On August 3, 2016, through Ordinance No. 424/2016, the MME designated AmE as responsible for providing the public electricity distribution service with the intention ensuring continuity of the service until December 31, 2017 or until the assumption of a new electricity provider, whichever occurs first.

2.2. Description of the Operating Area

Ceal operates throughout the state of Alagoas, covering an area of 27.848 km². Alagoas is the second smallest state in Brazil (after Sergipe) and borders three other states: Pernambuco, to the North, Sergipe, to the South and Bahia, to the Southeast.


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Table 2 – Highway Indicators for the state of Alagoas

Type	Roads	Extension	Weight/
		(km)	Participation (%)
	Federal	822.0	6.26%
Total	State	2,409.5	18.35%
Existent	Municipal	9,896.6	75.38%
	Total Roads	13,128.1	100.0%
	Federal	768.6	32.24%
	State	1,565.7	65.68%
Paved
	Municipal	49.2	2.06%
	Subtotal Pav.	2,383.5	21.62%
	Federal	53.4	0.49%
Not	State	843.8	7.85%
paved	Municipal	9,847.4	91.95%
	Subtotal Not Pav.	10,744.6	81.84%

	Self prepared based on DNIT data, 2015


Alagoas has a total of 13.128 km of roads. The federal highways are the least representative
(only 6% of the total), while state roads constitute 18% of the highways in the state. Of the total
roads present in Alagoas, 82% are unpaved (9.847.4 km). As a consequence, the amount of total
paved roads is low in relation to the total roads (just 21% or 2.383 km).
Almost all the 9.800 km of municipal roads are unpaved, representing 92% of the existing
total municipal roads. This fact directly influences the movement between the central area of the
municipality and its surrounding areas, since these roads tend to become dangerous in case of
rains, because the dirt roads generate mud and can bog down the emergency services vehicles.
Among the paved roads, most are under federal administration (over 1.500 km or 65% of
the total paved roads). The majority of federal roads are paved (768 km of a total of 822 km).
Figure 3 shows the federal roads (in red) and state roads (in blue) for the state of Alagoas⁶.
Analysis of the road grid leads to the conclusion that there is a greater concentration of federal
roads in the areas closer to the capital, Maceió. In relation to the state highways, these have good
distribution throughout the territory of the state of Alagoas, without concentration in any specific
area.




⁶DNIT made only available the updated files of 2016 for federal roads, being the most recent information of the State roads of
the year of 2013

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3. Market and Consumption Unit Forecasts

The sections below present: (a) a history of the market and consumption units, with information subdivided as per voltage level and class of consumption; (b) market forecast methodology per class of consumption, as well as auxiliary data and variables used in the forecasts; (c) Results of market forecasts until 2048; (d) consumption units forecast methodology; and (e) results of the consumer forecasts until 2048.

3.1.Market and Consumption Units (CU) History

In Table 4 we have analyzed the evolution of the number of consumption units (“NCU”) of the company from 2013 to 2016, as well as the variation rates in the entire period – variation of 2016 in relation to 2013 – and geometric – Compound Annual Growth Rate (CAGR)¹⁰.


	Table 4 – Evolution of the Number of Consumers per Voltage Level
		NUC per voltage Level			Variation Rate
Voltage / Year	2013	2014	2015	2016	Period	Geometric
					(2013/2016)	(p.a.)
A3	16	15	17	17	6%	2%
A4	2,086	2,101	2,113	2,102	1%	0%
BT	950,753	996,650	1,033,434	1,099,791	16%	5%
TOTAL	952,855	998,766	1,035,564	1,101,910	16%	5%

Source: Periodical Tariff Review (RTP) 2013 and the Tariff Adjustment Indexes (IRT) of the Company from 2014
to 2016. Remark: NCU usually refers to July of each year.


High voltage subgroup A3 presents increase of 1 user only in four years. Similar conclusion
can be noted in subgroup A4, verifying increase of 1% of clients only in the analyzed period. The
LV Low Voltage subgroup was the one to present highest growth, at annual rate of 5% and 16% in
the period.
Table 2 demonstrates the evolution of the invoiced market (MWh) per voltage level, in
addition to the two growth rates: period and geometric. The information about the market are
also presented in accordance with the types: (i) Supply – captive consumers of the Distributor;
(ii) Supply – Distributor supplying another Distributor; (iii) Other Free – free consumers of the
Distributor; and (iv) Distribution.
In general terms, relative stability of the invoiced market is noted, at average growth of 2%
p.a. In relation to the opening per voltage level, it can be verified that the LV consumption market
was the one to present highest growth in the period, at rate of 10% in the period. The HV market
presented decrease in consumption, at average rate of 3% p.a., while the MV consumers presented
null average growth rate.



¹⁰CAGR – Compound Annual Growth Rate.

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	Table 5 – Market Evolution per Voltage Level
		Market by Voltage Level (MWh)			Variation Rate
Voltage / Year	2013	2014	2015	2016	Period	Geometric
					(2013/2016)	(%) p.a.
SUPPLY CAP.	3,144,209	3,283,014	3,389,576	3,299,290	5%	2%
A3	458,531	409,962	409,026	417,090	-9%	-3%
A4	880,332	895,395	906,768	888,530	1%	0%
BT	1,805,345	1,977,657	2,073,782	1,993,670	10%	3%
LOW INCOME	261,853	309,028	311,097	227,525	-13%	-5%
SUPPLY DIST.	-	-	-	-	-	-
OTHERS FREE	148,363	195,982	195,132	159,001	7%	2%
DISTRIBUTION	18,942	19,317	20,233	20,221	7%	2%
TOTAL	3,311,514	3,498,314	3,604,942	3,478,512	5%	2%

Source: Periodical Tariff Review (RTP) 2013 and the Tariff Adjustment Indexes (IRT) of the Company from 2014
to 2016. The market data refers to the 12-month period, starting from the month before IRT. The Low Income
market is accounted in the LV market

Table 6 contains the evolutions of the mid-market per voltage level, in addition to the two growth rates: period and geometric. Mid-market means the average consumption value of a customer in accordance with the voltage of service.


Table 6 – Mid-Market Evolution per Voltage Level

	Average Market per UC per Voltage Level (MWh)				Variation Rate
Voltage / Year	2013	2014	2015	2016	Period	Geometric
					(2013/2016)	(%) p.a.
A3	2,388	2,278	2,005	2,045	-14%	-5%
A4	35	36	36	35	0%	0%
BT	0.16	0.17	0.17	0.15	-5%	-2%
TOTAL	0.29	0.29	0.29	0.26	-9%	-3%
Source: Periodical Tariff Review (RTP) 2013 and the Tariff Adjustment Indexes (IRT) of the Company from 2014
to 2016. The market data refers to the 12-month period, starting from the month before IRT/ RTP

As the annual market, the mid-market also decreased for the HV consumers, namely 14% in the period and 5% p.a. The MV users presented average consumption with slight oscillations, remaining stable in the years from 2013 to 2016. The LV consumers had the average power consumption reduced by 2% p.a., i.e., the company´s market has not presented any expansion in the last years.

The information about average monthly consumption per client may also be presented per category (rating of users according to the final destination of the electric power), as per Table 7. Consumption classes Public Lighting and Industrial were the ones to present highest representativeness in the composition of the total part of consumption per class. The Rural class was the one to present highest decrease (16% every year and 40% in the period) among all classes with negative growth rate.

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Table 7 – Evolution of the Average Consumption per Tariff Class


	Average Monthly Consumption per Class (kWh)				Variation Rate
Class / Year	2013	2014	2015	2016	Period	Geometric
					(2013/2016)	(%) p.a.
Residential	111	116	119	106	-4%	-1%
Industrial	22,455	23,873	24,713	22,011	-2%	-1%
Commercial	967	1,031	1,039	947	-2%	-1%
Rural	1,918	1,499	1,173	1,153	-40%	-16%
Public Lighting	74,535	85,914	81,803	85,984	15%	5%
Public Entities	1,435	1,428	1,517	1,525	6%	2%
Public Service	13,832	12,916	13,056	12,766	-8%	-3%
Other	21,388	16,992	19,442	16,995	-21%	-7%
TOTAL	290	292	290	263	-9%	-3%

Source: RTP 2013 and IRTs from 2014 to 2016 of the Company

Remark: There might be divergence in relation to the total mean presented in Table 6, which uses the market accumulated in 12 months, while here, the data reflects the reference month of extraction of the number of consumption units (normally, one or two months before RTP).

3.2. Market Forecast Methodology

In order to subsidize the several tariff calculations and the economic-financial cash flow, market forecasts are necessary, separated by: (i) class of consumption (Residential, Commercial, Industrial, Rural, Public Service, Public Lighting, Public Service, Own Consumption); (ii) voltage level (High Voltage - A1, A2 and A3 -, Mid Voltage - A3a and A4 – and Low Voltage - LV -); and (iii) type of consumer (free and captive).

Regarding the market forecast per class of consumption, the main time series methodologies used for the forecasts are known with Box & Jenkins (BOX; JENKINS, 1976) and the methods of exponential smoothening, especially the State Space models (HYNDMAN, et al. 2002). These methodologies allow the forecasting of future values of series based on present and past values, using univariate and multivariate. Univariate series are based on the very own structure of the historical series, and the multivariate series allow using auxiliary variables, which have association with the modeled historical series. In addition to these more consecrated methodologies, another possibility is the Dynamic Models, which consist of the multiple regression models estimated from the Ordinary Least Squares (OLS). In Appendix B, there is a brief explanation of each of the methodologies mentioned and used for the Ceal market forecast.

Software R (version 3.2.3) and EViews 8 were used for the modeling. For the case of software R, specific packages have been used: Forecast v8.0 (HYDMAN, et al. 2017) for models Box & Jenkins, ETS and Dynamic Models; and Dyn v0.2-9 (GRONTHENDIECK, 2012), dynlm v0.3-3 (ZEILEIS, 2014) for Dynamic models. In the case of Dynamic models, software EViews has also been used.

For the analysis of the adequateness of the estimated models, transformations have been used to the historical series. Transformations are applied with the purpose of stabilizing the


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Auxiliary Data and Variables

The models may be different in each class of consumption, depending on the Distributor. After several tests, the auxiliary variables used in the models per consumption classes are presented below. The adjustments of the models followed the hierarchical logics, prioritizing variables showing first in column “Tested” of Table8.


Table8 – Variables used in the market forecasts per class

	Variables

Class	Tested	Used
Residential	Population or UC Residential	Population
Industrial	GDP	GDP
Commercial	GDP and one between: Population and UC Commercial	GDP and Rural
Rural	GDP, Rural Population or Consumer Unit, Univariate	Univariate
Public Entities	Population and/or GDP	Population
Public Lighting	Univariate	-
Public Service	Population	Population
Proper Consumption	Univariate	-

	Source: Self prepared.

In addition to the correlated variables (auxiliary), due to the strong volatility of several series, dummy variables have been used to capture momentary changes or structural breaks¹¹in the historical series.

The data of Population Total were obtained from the Brazilian Institute for Geography and Statistics (“IBGE”). IBGE provides the forecasted monthly population of the State until 2030.

After this period, the growth rate month by month was used for the forecast in each Federative Unit, until 2048. The monthly growth rates were constant from 2030 to 2048 and corresponded to: Rondônia 0.05%, Acre 0.08%, Amazonas 0.07%, Boa Vista 0.10%; Piauí 0.01% and Alagoas 0.02%.

The forecast of the monthly population for the Federal Units, carried out by IBGE, was obtained from the Method of Demographic Components, which incorporates information on the dynamics of demographic growth (mortality, fecundity, and migration). The monthly estimation is obtained by using a third-degree polynomial from the annual population forecasted by the Method of Demographic Components¹².

In the case of the historical series of Rural Population, its forecast was made from the series of Total Population. The share (%) of the total population for transformation into rural population was made based on information from the National Household Sample Survey – PNAD (2000\2015) and Demographic Censuses (2000 and 2010), with decennial forecast until 2050 and linear interpolation between the annual periods.

The forecast of the historical series of Consumption Units was made based on the State space model (ETS) that captures the error, trend, and seasonality. This, the forecast is univariate,

¹¹It is understood that there is a structural break, when there is non-typical dispersion and/or inclination in the levels of the historical series.

¹²For more information, access <http://www.ibge.gov.br/apps/populacao/projecao/notatecnica.html> date of access: June 2^nd, 2017.


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based on the structure of the very own data series. The data have been obtained by the Distributors.

In the case of Total GDP, we have used the monthly series of the national GDP, provided by the Banco Central (BCB-Depec), at current values, including the period from January/2003 to

December/2017. The series was transformed into real values of 2000, based on the GDP’s implicit deflator, of the same, prior source. The series was forecasted until 2020, based on the GDP growth rate per year, available in the Central Bank of Brazil’s Market Expectations System, on March 3,

2017. After this year, a constant GDP growth rate of 3% p.a. was used, following the long term forecasts of Banco BRADESCO until Dec/2048. This decision was made because BRADESCO presented a greater forecasting horizon than that of the Central Bank of Brazil.

The growth of the forecasted GDP indicates a recovery of Brazilian economy from 2017, with an expansion above 2% p.a. already in 2018. After 2021, the country will enter a phase of sustained growth at a moderate rate of 3% p.a. If compared to forecasts of the Brazilian GDP, the forecasted scenario is that of moderate bias. In the long term, it considers an expansion smaller than that brought in the Decennial Energy Plan (BRAZIL, 2015), disclosed by the Energetic

Planning Company (“Empresa de Planejamento Energético”), indicating growth of 4.5% p.a. in the period from 2019 to 2024, while our scenario indicates an evolution of 2.8% p.a. In the short terms, the scenario is more optimistic than the World Bank estimates, which forecast a slower recovery, with GDP having growth below 2% p.a. in 2018.

Figure 9 illustrates the GDP growth forecasts (% p.a.) from the external sources mentioned above.

To obtain the Total GDP for the Federative Units, the market share of the Total GDP of the Federative Unit in relation to the Total GDP of the country. Since this value is annual, the 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


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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.

Table9 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.


Table9 – 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	-
Rondônia	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	019	0.2	019	0.2	021	022	021	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	1.5	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
Pará	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
Amapá	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
Maranhão	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
Piauí	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
Ceará	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
Paraíba	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	0.65	-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	8.3	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
Espírito 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
São 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
Paraná	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
Goiás	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


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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 Part A, component of the revenue of the concessionaire of distribution that includes costs and sectorial 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 Part 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 Part A, technical and non-technical 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 model¹³, 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 valid¹⁴.

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 Approval Resolution no. 2.184/2016¹⁵.

Figure 14 presents a time line 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.

¹³In the terms of the Reporting Judge´s Vote announced in the 30th Ordinary Public Meeting in 2016. ¹⁴Sub-modules 2.1A, 2.2A, 2.5A, 2.7A, 3.1A, 3.2A, 3.3A, 3.4A, 4.2A and 4.4A.

¹⁵Both 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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registered in specific account of special obligations until the date of execution of
contractual amendment, will be subtracted from Part 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 Part 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 Part 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 Part 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 Part B and to transfer them to Part 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 Part A to Part B.

ii. In the tariff readjustments, Part B shall be effectively calculated and not only obtained
as a residue of the calculation of Required Revenue.

iii. The value of Part 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
Part 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 Part
B.


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In Module 4, the neutralities are calculated to all components of Part 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 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 changes¹⁶. 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 Part 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 time line with recent rulings related to the renewal of the concessions of the distributors of Grupo Eletrobras.

¹⁶In 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 modeling of the items composing Part A in the financial model is detailed in section 3.2.

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quarter, and annual values of 2016; (iv) flexibilization of the references of regulatory losses to
Amazonas Energia, Boa Vista Energia, CEA, and CERR.

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 Paragraph 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.


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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.

“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.


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It has been observed in Technical Note no. 182/2017 that the designated companies needed
high investments in the first years of the concession in order to restore the levels of quality of the
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.

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“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 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 equal monthly 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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Table 13- Values Factor T and Xpd

Company	Pd (%)	T (%)
Amazonas Energia	2.02	0
Boa Vista	1.39	0
Ceai	1.91	0
Cepisa	2.15	0
Ceron	2.02	0
Eletroacre	1.42	0
Source: TN No. 088/2017, ANEEL

Regarding the values of regulatory losses, for Distributors Amazonas Energia, CEA, and Boa Vista, the systematic of transfer was defined by Article 4-A of Act no. 13.299/2016 and homologated until 2025 by Homologation Resolution no. 2.184, of 2016. To the others, the values in force should be adopted, which must remain in force until the first tariff review after the execution of the new concession agreement. In case the Concession Agreement foresees the flexibilization of the regulatory referential of non-technical losses, the value set forth in the agreement shall prevail. Table 14 summarizes the foregoing.

Table 14 - Values of Regulatory Losses

Source: Technical Note no. 088/2017, ANEEL

In relation to the global limits of DEC and FEC, the proposal is to maintain the limits of 2017 until the year of the first tariff review after the assumption of the new controllers of these companies. The limits to the indicators will be established by means of specific resolution to each Distributor, attached to the Technical Note. The sets of consumption units of concessionaire CERR shall integrate the area of concession of Boa Vista Energia.


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Table 15 - DEC and FEC Global Limits


Company	DEC	FEC	# Consumer Units
Amazonas Energia	45.58	43.44	940,962
Boa Vista	36.87	28.92	159,118
Ceai	13.73	10.38	1,123,164
Cepisa	19.17	12.44	1,233,677
Ceron	20.57	15.89	561,360
Eletroacre	27.58	23.36	256,297

Source: Technical Note no. 088/2017, ANEEL

This Report adopted the proposals of regulatory indicators as per Technical Note no. 088/2017, establishing the regulatory parameters for the tariff procedures of the Designated distributors and limits to the DEC and FEC collective indicators of continuity. Such parameters shall remain in force until the first tariff review after the execution of the new concession agreement of the companies.

e) Technical Note no. 351/2017

In July 2017, ANEEL disclosed Technical Note no. 351/2017, in attention to the request by the Ministry of Mines and Energy to evaluate the conditions of equilibrium of the concessions in analysis and the technical feasibility of reequilibrium prior to its sale/bidding procedure.

Technical Note no. 351/2017 identifies that new concessionaires would find a scenario of grave instability when assuming the new concession, especially in relation to operational costs and non-technical losses. As a solution, ANEEL considers the possibility of acknowledgment of a part exceeding the regulatory part to non-technical losses and operational costs in the tariff. This exceeding part would correspond to the average between the regulatory values and realized to such indicators.

After the publication of Technical Note no. 351/2017, the Agency, by means of mailing to BNDES, presented answers to doubts and gave its clarifications, being worth noting: (i) that tariff additions in relation to non-technical losses and operational costs would be maintained until the first ordinary tariff review (2023); (ii) these additions would be applied to the annual tariff procedures of 2017; (iii) the additional review forecasted to occur in the first cycle, before 2023, shall not change the flexibilization indicated and will deal specifically with the tariff acknowledgment of the reevaluated base of assets.

In view of the identification of non-feasibility of payment, by the new concessionaire, of the loans of RGR (REN no. 748/2016) in the established conditions, and by means of remuneration over the invested capital, the impacts of flexibilization of the payment conditions of the loans were also evaluated in Technical Note no. 351/2017, as well as the possibility of transfer in the tariffs of the distributors.


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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 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 Part 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

Part 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, Paragraph 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: 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


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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 Part 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 Part 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, Paragraph 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 – The 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 proposal of the Agency generated substantial changes in a few parameters that have been


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determined in Technical Note no. 351/2017, especially in terms of operational costs and indicators of quality.

The amounts destined to the flexibilized, regulatory PMSO (costs with personnel, material, services, and other) were subject to inflation adjustments by the IPCA between July 2015 and the date of the tariff procedure in 2016. In addition, in the case of Boa Vista, there was an increase to its degree of flexibilization, since ANEEL suggested that “the inefficiency considered to Boa Vista Energia, measured by the ratio between the Effective PMSO and the Regulatory PMSO, should be the highest considering the other designated distributors, which is CEA (268%)”. Table 16 illustrates the variation observed in the PMSO flexibilized between Technical Note no. 149/17 and Technical Note no. 351/17.


Table 16 - Variation of the amounts destined to PMSO per Distributor

			Difference	% Percent
Distributor	NT 88/17	NT 149/17
			(NT 88/17 - NT 351/17) Variation/NT 88
AME	606,907,016	627,198,364	20,291,348	3.3%
Boa Vista	53,885,287	69,062,498	15,177,211	28.2%
CEAL	328,345,672	336,655,364	8,309,692	2.5%
CEPISA	409,859,796	420,070,979	10,211,183	2.5%
CERON	273,006,426	279,853,142	6,846,716	2.5%
ELETROACRE	125,242,240	128,543,635	3,301,395	2.6%
Source: Own Elaboration

In addition, Technical Note no. 149/2017 brought a proposal of flexibilization of the goals DEC and FEC collective indicators (which was not set forth in Technical Note no. 351/17). Among the contributions made, the principal are listed below: (i) Proposal of relaxation of the goals due to the supply, with stronger impact to the distributors of the Northern region in Brazil; (ii) Proposal that the starting point should be the average between the calculated value (mobile average from July 2016 to June 2017) and the limit in force in 2017 to distributors Ceal, Cepisa, Ceron, and Eletroacre; (iii) Proposal that these limits should remain unchanged until the fifth calendar year after the execution of the new agreements, so that the limits for the following year are established in the first ordinary tariff review of the new agreement.


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Table 17 - Variation of the DEC limits per Distributor

		Difference		% Percent
Distributor	NT 88/17	NT 149/17
		(NT 88/17 - NT 351/17) Variation/NT 88
AME	45.58	48.53	2.95	6.5%
Boa Vista	36.87	48.67	11.80	32.0%
CEAL	13.73	15.58	1.85	13.5%
CEPISA	19.17	20.67	1.50	7.8%
CERON	20.57	27.54	6.97	33.9%
ELETROACRE	27.58	44.17	16.59	60.2%
Source: Own Elaboration


Table 18 - Variation of the FEC limits per Distributor

		difference		% Percent
Distributor	NT 88/17	NT 149/17
		(NT 88/17 - NT 351/17) Variation/NT 88
AME	43.44	45.69	2.25	5.2%
Boa Vista	28.92	58.43	29.51	102.0%
CEAL	10.38	13.06	2.68	25.8%
CEPISA	12.44	13.99	1.55	12.5%
CERON	15.89	18.90	3.01	18.9%
ELETROACRE	23.36	35.31	11.95	51.2%
Source: Own Elaboration

It should be noted that the flexibilizations proposed by Technical Note NT 149/2017 were already incorporated to the models of forecast of the indicators present in this report.

Technical Note no. 149/2017 did not present changes to the parameters of flexibilized PNT and components Pd, T and Q of Factor X when compared to the provisions of Technical Note no. 351/17. Finally, Technical Note no. 149/2017 presented reductions to the amounts destined to the loans of RGR, between 15% and 39%, depending on the distributor.

h) Final Considerations

Considering the elements presented above, and assuming the assumption of a new controller in the first quarter of 2018, the proposed regulatory chronology, considering as unchanged the date of anniversary of the old agreements – November to AME, Boa Vista, Ceron, and Eletroacre, and September to Ceal and Cepisa – is the following:· An adjustment (IRT) will occur in 2017 on the date of anniversary of the old agreements (not renewed) of the designated companies. An additional acknowledgment of non-technical losses and operational cost will occur upon such adjustment (IRT), as per Technical Note no. 351/2017;· The new agreements will be signed in 2018, whose date was estimated to 03/01/2018. An adjustment (IRT) will occur in this year, on the date of anniversary


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of the old agreements;
· An extraordinary review¹⁷will 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 Part A

Part 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 over-contracting.

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, non-
technical, 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.

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 whether

¹⁷In this extraordinary review, the closed base will be opened.


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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”)

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.


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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 Part A is that of pass-through, i.e., costs with sectorial charges, one of the components of Part 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.

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:


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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.

As mentioned above, the effect of Part A is that of pass-through, i.e., costs with sectorial
charges, one of the components of Part 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.

4.2.4.Financial

Part 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 Part A, may be higher or lower than the
effective costs of Part A, and the differences verified will be accounted in entry CVA
(“Compensation of Variation of Values of Items of Part 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
next year to compensate the surplus, thus charging against the consumer less than the economic
tariff.

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


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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 of Technical Losses 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. 0180/2013-SRD/ANEEL dated July 25, 2013, process No.: 48500.000550/2013-47, “Analysis of the contributions of Public Hearing no. 051/2013, related to the evaluation of the losses in the distribution system, associated with the 3rd Cycle of Periodical Tariff Review of Eletrobras Distribuição Alagoas – EDAL” (Companhia Energética de Alagoas – Ceal). The results from the verification are presented in

Table 19 and


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Table 20 - Amount of Technical Losses per Segment of Transformation and Grid

		Technical Losses of the Segments
	Passing Power
	(EP)	Upstream	% Passing	% of the Total
		(PTS)	Power (IPTS)	Injected Power
	MWh	MWh	%	%
Power
Transformers	3,561,772.445	22,330.088	0.627%	0.516%
A2-A4
Tafros A4-B	2,221,362.058	78,590.507	3.538%	1.817%
Net A3	4,279,825.000	159,557.876	3.728%	3.689%
Net A4	3,585,130.357	149,558.013	4.172%	3.458%
Net B	1,755,538.721	25,447.755	1.450%	0.588%
Meters	1,659,068.743	8,311.382	0.501%	0.192%
Services Wires	1,659,068.743	3,626.935	0.219%	0.084%
	TOTAL			10.344%
Source: Technical Note no. 0180/2013-SRD/ANEEL

Thus, ANEEL adopted, for the entire tariff cycle (2013-2017), the amount of Technical Loss
of 10.34 % over the Total Injected Power in the system of the distributor.

b) Methodology and Premises of Technical Losses Forecasting

The forecast methodology for technical losses consists of: (i) evaluating the technical losses
indexes of the voltage of supply segments (IPTS) of Ceal in relation to the average indexes of
comparable companies identified in 4.3.2; and (ii) seeking the lowest value between the
segmented loss of the company and the verified average for the comparable companies, which will
be the base for the trajectory. Below, we present the step-by-step of the applied methodology:

i. The indexes of the technical loss per supply voltage segment - grid and
transformation level (IPTS) were used as a primary source for the calculation of the
loss. In order to preserve the confidentiality of the information, the methodology is
based on the adoption of information from public sources, namely, Technical Note
No. 0180/2013-SRD/ANEEL dated July 25, 2013, process No.:
48500.000550/2013-47, “Analysis of the contributions of Public Hearing no.
051/2013, related to the evaluation of the losses in the distribution system,
associated with the 3rd Cycle of Periodical Tariff Review of Eletrobras Distribuição
Alagoas – EDAL”. With the Technical Note, ANEEL provides the losses per voltage
segment, with unequivocal application and best representation of the verified
historical information.

ii. The losses obtained in each voltage segment of the distributor were object of
comparison with the companies having greater similarity to the concession are in
evaluation, considering their specific characteristics. For Ceal, the selected
comparable companies were:
· Empresa de Distribuição de Energia Vale Paranapanema S.A. – EDEVP;
· AMPLA Energia e Serviços S/A – AMPLA;


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· Companhia Energética do Ceará – COELCE;

· Companhia Estadual de Distribuição de Energia Elétrica – CEEE-D;· Celg Distribuição S.A. – Celg-D;· Energisa Tocantins - ETO;· Companhia Energética de Pernambuco – CELPE;· Bandeirante Energia S.A - Bandeirante. iii. From the comparison with the similar companies, the average IPTS’s obtained considered the weighted losses of each Distributor in relation to the inject power in each voltage segment. The forecasted goal for 2047 consider, by segment, the maintenance of the rates of the company when below the weighted average; or the values observed in the weighted average of comparable companies when the results demonstrate level below that currently achieved by the company. iv. Based on the obtained results of losses per segment, forecasted for 2047, a simple interpolation was used to define the intermediate values. v. With the annual IPTS values obtained, such values were applied over the volumes of injected power per supply voltage segment, resulting the technical losses per segment, estimated to the entire period of Concession. For the consolidation of the total value of loss of the company, the same proportion of injected power as the one adopted in ANEEL Technical Note No. 0229/2013-SRD/ANEEL was used.

It shall be pointed out that ANEEL, by means of Technical Note no. 88/2017, dated May 24, 2017, defined the Ceal PT at 10.34% of the injected power until the first complete tariff review after the signature of the Concession Contracts pursuant to the bidding process. That is, the methodology described in this section applies as of the first RTP we simulated, with forecast for 2023.

c) Results

Graph 8 presents the average losses per voltage segment of the comparable companies and Ceal.


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Table 21 - Technical Loss Target per Voltage Segment

Voltage segment	Avg	Comp	Final
	IPTS	IPTS	goal
A1-A2	0.000%	0.000%	0.000%
A1-A3	0.000%	0.000%	0.000%
A1-A3a	0.000%	0.000%	0.000%
A1-A4	0.000%	0.000%	0.000%
A2-A2	0.000%	0.000%	0.000%
A2-A3	0.328%	0.000%	0.000%
A2-A3a	0.484%	0.000%	0.000%
A2-A4	0.514%	0.000%	0.000%
A3-A2	1.283%	0.000%	0.000%
A3-A3a	0.575%	0.000%	0.000%
A3-A4	0.450%	0.627%	0.450%
A3a-A2	0.000%	0.000%	0.000%
A3a-A4	0.780%	0.000%	0.000%
A3a-B	9.040%	0.000%	0.000%
A4-A3	0.420%	0.000%	0.000%
A4-A3a	0.644%	0.000%	0.000%
A4-B	3.164%	3.538%	3.164%
B-A4	0.000%	0.000%	0.000%
A1 (< 230 kV)	0.107%	0.000%	0.000%
A2 (88 a 138 kV)	1.683%	0.000%	0.000%
A3 (69 kV)	2.919%	3.728%	2.919%
A3a (30 a 44 kV)	4.179%	0.000%	0.000%
A4 (2,3 a 25 kV)	2.083%	4.172%	2.083%
B (< 2,3 kV)	1.927%	1.656%	1.656%
Meters	0.492%	0.501%	0.492%
Services Wires *	0.000%	0.000%	0.000%
* Incorporated in “B (<2.3 kV)”

Source: Own Elaboration

Based on the IPTS forecasts, the forecasted loss is established. The forecasts for annual

IPTS´s and consolidated technical losses are demonstrated in line “Forecast of the Technical Loss %” and “Forecast of Regulatory Technical Loss %” from Table22.


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Table 25 presents the index of complexity and deviations resulting from the regression models built from the three selected econometric models (C, G and K) for the 6 designated companies.

In Table 26, the complexity indexes verified for each of the companies is calculated. It is possible to note that, for the purposes of comparison, Technical Note no. 106/2015 divided the companies into two groups, being considered as large size (Group 1) those having market greater than 1,000 GWh/year and serving more than 50 thousand consumption units or with more than 15,000 km of electric network. The other companies are considered of Group 2. Small companies tend to present greater facility to combat non-technical losses than large companies.


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Table 25 - Result of the Complexity Indexes of each Econometric Model for the Companies from
Grupo Eletrobras


COMPANY	INDEX DEVIATION INDEX DEVIATION INDEX DEVIATION
	C	C	G	G	K	K
Amazonas	0.37	0.04	0.34	0.05	0.39	0.04
Ceal	0.27	0.02	0.24	0.02	0.29	0.03
Cepisa	0.26	0.02	0.25	0.03	0.25	0.02
Eletroacre	0.25	0.02	0.24	0.02	0.24	0.02
Ceron	0.19	0.02	0.19	0.02	0.19	0.02
Boa Vista
(Capital)	0.07	0.03	0.06	0.03	0.09	0.03
	Source: Technical Note no. 106/2015, ANEEL


Table 26 - Average Complexity Index

COMPANY	IC	Ranking	Size
Amazonas	0.364	4	Large (Group 1)
Ceal	0.266	8	Large (Group 1)
Cepisa	0.257	10	Large (Group 1)
Eletroacre	0.243	12	Large (Group 1)
Ceron	0.191	18	Large (Group 1)
Boa Vista (Capital)	0.074	44	Small (Group 2)
Source: Technical Note no. 106/2015, ANEEL

i. Analysis of the Potential of Reduction of Non-Technical Losses

Once the positions of the concessionaires are defined in each ranking of socio-economic complexity, it is possible to conclude that companies with small non-technical losses and in areas of concession identified as having greater or equal socio-economic complexity are more efficient, and, therefore, reference to the others.

Initially, the goal of reduction of losses of a certain company, once the comparable benchmark is identified, would correspond to the very own load of the benchmark. However, as per ANEEL’s methodology, a differentiated treatment is given as a form of making the calculation procedure more robust, treating the uncertainty regarding the position of the companies in the ranking, as a combination of the value of losses adopted by the benchmark with the probability of having the benchmark in fact in a more complex area of concession. With this purpose, a table of probabilities of a given concessionaire being above or below the benchmark was built. The table of probability allows the calculation of the reference weight to all potential benchmarks of each concessionaire and will then determines goal of the company, as per Equation 10.


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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 to the equations of items (iii.a) and (iii.b), however without trajectory of reduction.


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Table 28 exemplifies the estimate procedure of the regulatory Non-Technical Losses of Distributor Escelsa, in the period from 2016 to 2018, according to the data of Technical Note no. 243/2016-SGT/ANEEL. The methodology of estimate begins with the calculation of the Starting Point, before evaluating the possibility of inclusion in the cases of exceptions. Following that, the calculation of the goal of the company is made based on the losses of the benchmarks found in the table of goals. Then the analysis of flexibilization of the starting point is carried out, followed by the determination of the regulatory goal based on the criteria of trajectory and speed of reduction of the non-technical losses, as explained in the sub-items above. The calculation of the goal is made considering the measured market of the concessionaire while its application must cover the invoiced market. To meet this condition, at the end of the determination procedure a percentage is subtracted from its value, which represents the different of invoiced and measured market.


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The percentage of regulatory non-recoverable revenues is obtained using the methodology in TN No. 107/2015 and presented in sub-module 2.2A of PRORET, and are also kept constant over the period of analysis: 1.44% for residential; 1.05% for industrial; 0.72% for commercial; 1.18% for rural; 0.23% for public authority; 0.05% for public lighting; 0.06% for public services.

In addition to the regulatory calculation, the values of the observed default to be used in the calculation of the cash flow have also been estimated. The average revenues not invoiced in the period from 49 to 60 months until the end of 2016 were adopted as starting point, as informed by the distributor. The values obtained and applied in the calculation for 2017 were: 2.95% for residential; 5.88% for industrial; 2.92% for commercial; 6.21% for rural; 2.,95% for public authority; 1.74% for public lighting; 0.78% for public services. It was assumed that these values will be converted into the regulatory percentage within 10 years.

4.3. Methodology for definition of Part B

The definitions used to calculate Part B are presented in Official Document No. 113/2017-DR/ANEEL with the draft concession contract - as well as the definitions for Part A and tariff transactions. In addition to some particularities, the definitions follow the methodologies presented in versions “A” of PRORET, as presented hereunder. It shall be noted that the elements discussed hereunder are regulatory and refer to the concession of public service.

The calculation of the value of Part 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 Part 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 Part 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)¹⁸and revenues from com Demand Surplus (UD) and Reactive Excess (ER)¹⁹, are excluded. The following formula summarizes the exposed above.

¹⁸It 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%).

¹⁹Such 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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Parameters:	Base Date
Rf	5.64%
CR	2.62%
Beta	0.70
PMR	7.56%
rUSD	2.41%
Ke	10.90%
A	48.76%
RC	3.37%
T	34.00%
Kd	5.14%
Regulatory WACC (Pre-Tax)	12.26%
Regulatory WACC (Post-Tax)	8.09%

For the regulatory WACC forecast, update of the historical series from January 2018 using the ANEEL calculation methodology in force (base 2015) was considered. Once there is forecast for review of the methodology in 2021, a factor which causes significant uncertainty, we assumed that the rate calculated for January 2018 will remain the same along the forecast period.

We present the parameters of the adjusted regulatory WACC in January 2018 below:


Parameters:	2018
Rf	4.89%
CR	2.53%
Beta	0.70
PMR	6.90%
rUSD	2.11%
Ke	9.95%

A	48.76%
RC	3.37%
T	34.00%
Kd	4.90%

Regulatory WACC (Pre-Tax)	11.34%
Regulatory WACC (Post-Tax)	7.49%

Risk free: Update and forecast of Risk Free based on the average from the last 5 years of the 10-year T-bond (Source: Bloomberg)
CR= Country Risk: update based on JP Morgan index EMBI - Emerging Market Bond Index from the last 5 years (source: Bloomberg);


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· r = USA inflation rate: Average of the 10-year forecast of the North-American

usd

inflation rate on Base-Date 03/31/2017 (source: US Congressional Budget Office);

RC = Credit risk: Average historical spread of the Credit risk compared to SELIC applied on the SELIC forecast along the forecast (source: Bacen)

4.3.2. Operational costs and Factor Xt

The Efficient Operational Costs are one of the main components to estimate the Value of Part B in the Tariff Review processes (CAOM component in the formula for VPB calculation). The methodology used to calculate the efficient operational costs is presented in Official Document No. 113/2017-DR/ANEEL, clause six, and in general, follows the exposed in sub-module 2.2A of PRORET. Some particularities of the Official Document are described along the methodology.

Under regulatory point of view, such costs refer to the figures for Personnel, Material, Outsourced Services, Other Operational costs, Taxes and Insurance related to the Electric Power Distribution and Sale activity (PMSO). According to specifications in TN No. 66/2015, PMSO shall be adjusted in some points, particularly for Personnel and Other costs. In the Personnel data, the values of actuarial deficits and surpluses and the retirement and/or voluntary dismissal programs are excluded, while in Others, only the following are considered: indemnities for loss and damage, proper power consumption, expenses for trainees and job initiation program, expenses for consumer advising, expenses for internal communication and reprography, collection fee, bank fees and judicial labor sentences. Such adjustments are applied by ANEEL for 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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Graph 12 shows that companies close to the origin (0%) are more comparable to the analyzed concessionaire, while heterogeneity increases a lot, when considering the companies situated to the left, at longer distance from the origin. From the analysis of heterogeneity curves as these ones, clusters containing 8 companies closer to each designated company, were selected.

Table 38 – Cluster Composition

* The companies were excluded from the sample of the cluster that subsidies the

operational cost analysis as these are designated companies.

Source: Own Elaboration

Once the cluster is built, the following step consists in estimating the PMSO trajectory of each analyzed concessionaire. The following methodology was adopted: I. An efficiency indicator was estimated for each company from the cluster. This indicator was based on the efficiency calculation methodology of 4CRTP, which compares the operational costs at a product weighted average. The weights are obtained by applying the non-parametric method DEA, as used in 4CRTP and whose calculation methodology is described in TN No. 66/2015. The formula for the calculation of the efficiency indicator is presented below. The products selected to compose the efficiency analysis are similar to those in 4CRTP, with some simplifications, namely: market²², number of consumers, extension of the grid²³, adjusted non-technical losses (difference in relation to the target in MWh) and CHI (interrupted consumer hour, based on the difference between the verified DEC and DEC V8). The indicator was calculated based on the information from the efficiency calculation in 4CRTP, considering the period from 2011 to 2013.

²²The 4CRTP methodology uses a weighted average of the markets by voltage level. For simplification, the total market was used, with no breakdown.

²³Likewise, for simplification, the total grid was used, with no breakdown in airborne HV, airborne and underground.


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Table 39 – Composition of the clusters and efficiency

Source: Own Elaboration

Note that positive variation in the last column of the table, which compares the efficiency indicator between 2011 and 2013, indicates efficiency gains. The indicator for Ceal shows that to offer each product unit (weighted combination of market, grid, consumer, PNT and CHI), the concessionaire needed 1.87 PMSO units in 2011. In 2013, this need was 1.58 PMSO units – i.e., the concessionaire became more efficient in the period.

The median of the efficiency indicator of the group was 0.77. The convergence speed for the first period was based on the verified mean of the efficiency gain of the concessionaires from the cluster, equal to 3.5%, to avoid abrupt variations in efficiency.

Thus, the efficiency curve for Ceal is presented in Graph 13.


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For the handling of the heterogeneous groups, an index – Score ANI – is calculated, which determines whether the heterogeneous group has, average, attributes with higher complexity (when positive) or lower complexity (when negative), when compared to the other groups from its cluster. Score ANI may change the percentile used to define the regulatory target of the heterogeneous group and consequently, change the trajectory of the limits for the analyzed tariff cycle.

For handling of the groups with high share of supply in the indicators (in case, the limit defined at 9% for DEC and 15% for FEC is exceeded), the trajectory of the limits of the group is attenuated diluting the difference between the calculated value of the external indicator and the average of the grouped values of the external indicator of the similar groups in 4 years.

The last treatment given is in relation to the groups with very intensive limit-reduction trajectory, defining maximum annual reduction values of 8 hours for DEC and 5 interruptions for FEC. Thus, the reduction trajectory is restricted, if there are differences higher than these limits in successive years.

c) Assumptions for Forecast of the Verified (or real) DEC and FEC

Indicators

The forecasts for the calculated (or verified) service quality indicators – DEC and FEC –follow three particular moments of the new concession. The first moment is characterized with the adoption of Temporary Provision regimen in force in 2017 and possibly, in the beginning of 2018, assuming that the calculated indicators remain equal to the values verified in 2016. The second moment of the forecasts is comprehended between 2019 and 2025, where it is expected not only the new administration to set off, but also the beginning of the results collected by means of the investment and operational efficiency measurements taken as of 2018.

For forecast of the indicator performance in this new phase, benchmarking approach was adopted for identification of comparable companies (the same methodology presented in section 3.3.2 - operational costs). Thus, eight companies comparable to Ceal were used: Coelce, CEEE, Celg, Celtins, Celpe, Vale Paranapanema and Bandeirante.

From the calculated global values of DEC and FEC of these 8 companies for the history from 2003 to 2016, a database was created containing the annual indicator and the reduction value of this indicator in relation to the value in the following year, provided that there is reduction in the following year, considering it null when the indicator increases from one year to the other. This, linear regressions were used in this database (excluding their critical outliers³⁰and the null values), trying to find the equation, which enables relating the annual indicators to the annual reduction capacity, reflecting the decreasing yield of the service quality improvement efforts. In context of high service discontinuity, it is possible to verify considerable decreases in a few years, while in low discontinuity situations, the permanent and considerable reduction requires time and certainly, more resources.

Within this vision, two regression models were defined, considering one for DEC and another one for the FEC indicator. The first model presents DEC explanatory variable, and the

³⁰Value that exceeds the average plus three times the standard deviation of the observations.


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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 088/2017 SRD-ANEEL.

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

Based on the used assumptions and methodologies, the results for the forecasts of the calculated indicators and the regulatory service quality limits of the distributor – DEC and FEC –until 2048 are presented. Graph 19 and Graph 20 present the forecasts for DEC and FEC and their values are in


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Table 47 – Verified/ Forecasted Verified and Approved/ Verified Limit of FEC for Ceal

			FEC
	VERIFIED/	THRESHOLD		VERIFIED/	THRES
YEAR	PROJECTED	LIMIT/PROJECTED	YEAR	PROJECTED	HOLD
	VERIFIED	LIMIT		VERIFIED	LIMIT/PROJECTED
					LIMIT
2014	22.82	13.82	2032	5.97	7.69
2015	20.70	12.59	2033	5.94	7.17
2016	16.82	11.39	2034	5.91	7.17
2017	16.82	10.38	2035	5.87	7.17
2018	16.82	13.06	2036	5.84	7.03
2019	14.52	13.06	2037	5.81	7.03
2020	12.55	13.06	2038	5.77	6.19
2021	10.86	13.06	2039	5.74	6.19
2022	9.41	13.06	2040	5.71	6.19
2023	8.17	13.06	2041	5.68	6.19
2024	7.11	12.23	2042	5.64	6.19
2025	6.20	11.45	2043	5.61	6.05
2026	6.17	10.55	2044	5.58	6.05
2027	6.14	9.71	2045	5.55	6.05
2028	6.10	8.81	2046	5.51	6.05
2029	6.07	8.72	2047	5.48	6.05
2030	6.04	8.27	2048	5.48	6.05
2031	6.00	7.74

		Source: Own Elaboration

Analyzing the forecasts for both DEC and FEC, there is a more accelerated decrease between 2018 and 2025, with softer reduction trajectory between 2025 and 2047.

4.3.6.Compensations

The calculation method used by ANEEL for the definition of the individual limits comprehends the following 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.³².

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.

³²Technical Note No. 092/2009, ANEEL presents the details of this method.


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It shall be pointed out that no resources have been forecasted for PLpT because the program will be closed in 2018.

b) Assumptions for Forecast of Non-Electric Investments

In addition to the forecasts of investments for Expansion, Improvement, Renewal of the different voltage levels of the Distributor, it is also necessary to forecast the amounts related to the investments in Systems and Vehicles. For this purpose, the adopted the assumption that at every five years, it is required to invest 50% of the provision in the first quinquennium (2018-2022).

c) Results

Table 54 presents the results for the forecasts for each investment segment of the Distributor by quinquennium. To make comparison easy, we present the forecasted values in real currency (April 2017). It can be noted that the investments from the 1st quinquennium (R$796.9 million) are 30% of the total for the 30 years (R$ 2.634 billion).


Table 54 - Forecast of Investments for the Quinquennium of Ceal


Type of Work/	1^stFive Year	2^ndFive Year	3^rdFive Year	4^thFive Year	5^thFive Year	6^thFive Year
Systems	Period (2018-	Period (2023-	Period (2028-	Period (2033-	Period (2038-	Period (2043-
Vehicles
	2022)	2027)	2032)	2037)	2042)	2047)
Expansion AT R$290,068,170		R$71,240,328	R$142,480,655	R$71,240,328	R$142,480,655	R$71,240,328
Expansion
MT/BT	R$99,657,389	R$62,827,418	R$62,827,418	R$62,827,418	R$62,827,418	R$62,827,418
Enhancement
AT	R$75,100,000	R$42,243,750	R$42,243,750	R$42,243,750	R$42,243,750	R$42,243,750
Enhancement
MT/BT	R$36,641,270	R$30,917,975	R$30,917,975	R$30,917,975	R$30,917,975	R$30,917,975
Renovation	R$277,240,975 R$112,670,024		R$150,673,050 R$112,670,024 R$150,673,050			R$112,670,024
Energy for All	R$10,285,390	R$0	R$0	R$0	R$0	R$0
ERP system
Adequacy	R$1,000,000	R$500,000	R$500,000	R$500,000	R$500,000	R$500,000
Integration of
SGO/SGTD	R$1,000,000	R$500,000	R$500,000	R$500,000	R$500,000	R$500,000
Systems
Vehicles	R$5,962,653	R$2,981,327	R$2,981,327	R$2,981,327	R$2,981,327	R$2,981,327
Total
Investments*	R$796,955,847 R$323,880,821 R$433,124,175 R$323,880,821 R$433,124,175 R$323,880,821
Total of Proper
Resources	R$786,670,457 R$323,880,821 R$433,124,175 R$323,880,821 R$433,124,175 R$323,880,821
*Values in real currency, at prices from April 2017.
Source: Own Elaboration

Graph 22 illustrates the behavior of the electric and the non-electric investments over the years. It can be initially noted that the investments in 2018 and 2019 are actually very high, given the historical blocking of investments in the concession. Furthermore, the investments are growing during the 30 years, with peaks in the two years before RTP (given the concentration of


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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 and 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 closed 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 Part 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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Gross BRR is calculated by Equation 39.

Equation 39 – Gross BRR

BRRb AIS IA OE BTD

Where:

BRRb: gross BRR.

AIS: Fixed assets in Service. IA : Use Index.

OE: Special Obligations.

BTD: 100% depreciated assets.

The special obligations (OE) correspond to the resources of the consumer´s financial share and the budget subsidies from the Federation, federal, state or municipal funds. These are non-onerous liabilities and are not shareholder credits. They are updated upon the same criteria and indexes as those used to correct the assets entered in AIS. The depreciation of the assets acquired with funds from the special obligations is not computed in the calculation of the concessionaire´s required revenues. They are amortized in the accounting at the same depreciation rates, using an average rate defined from the tariff review.

The use index corresponds to the percentage of use of the asset in the regulated service. It is calculated for land, buildings, facilities, machines and equipment.

The Capital Remuneration is calculated by Equation 40.

Equation 40 – Capital Remuneration

RC (BRRl – RGR). r RGR . r

WACCpré RGR

Where:

RC: Capital remuneration BRRl: Net BRR.

RGR: RGR debt balance. rWACCpre: Weighted average verified capital cost before taxes. rRGR: RGR capital cost.

The Global Reversal Reserve (RGR) is a sector fund created by Decree No. 41.019/1957. This fund is used to finance the Program Luz Para Todos (PLpT), in addition to energetic efficiency projects within the National Program for Electric Power Preservation (Procel). The RGR cash to capital are also aimed at the system electric improvement and expansion works in the power generation, transmission and distribution areas.


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BARI: Amount of the regulatory annuity base related to the investments in information systems; VU: Service life 5.3 years. The value defined in Table XVI of the annex to the Electric Sector Asset Control Manual– MCPSE is considered, namely 70% related to TUC “535 – Software”; and 30% related to TUC “235 – General Information Equipment”.

b) Methodology for Forecast of BRR and Assumptions

Below, we will demonstrate how we forecasted the Regulatory Remuneration Base (BRR) of the Company. The forecast model used the data in the following asset evaluation reports as initial source:· Evaluation report prepared by Levin (delivered on 7/31/2017), which considered reopening of the base of assets unified by the base date of the 3rd RTP and the evaluation of the base of assets unified between the 3rd RTP and Feb/17.

· Evaluation report prepared by Levin (delivered on 4/29/2017), which considered the base of assets by the 3rd RTP in a closed way and the evaluation of the base of assets unified between the 3rd RTP and Feb/17.

In the model, different forecast criteria were considered for the base of assets unified by Feb/17 (called Closed BRR in the model) and for the unification done after Feb/17 and new investments (called Additional BRR in the model). The closed BRR is coming from the information presented in the evaluation reports, while the additional BRR is determined based in the information about the new investments forecasted for the 30 years of concession.

The Frozen Asset Base starts from the values considered in the Evaluation report (delivered on 7/31/2017), defining the deduction of the difference between AIS of the full BRR available in this Evaluation report at 9.2%, R$ 2.203 billion, and AIS of the Frozen Asset BRR of the Evaluation report prepared by Levin before (delivered on 4/29/2017), R$ 2.105 billion in the AIS, resulting in AIS of R$ 2.194 billion as shown in Table 56.


Table 56 - Calculation of the AIS Considered in the BRR Model in Feb/17

Integral AIS BRR - Current Report (I)	2,203,637,253
Protected AIS BRR in the 3rd RTP - Previous Report (II)	2,105,652,307
Portion of AIS to be glossed (III) = (I) - (II)	97,984,946
% gloss (IV)	9.2%
AIS Considered in the Model on Feb/17 (V) = (II) + (III) x [1-(IV)]	2,194,613,090
Source: Own Elaboration

The deductions were calculated from the ratio between the final AIS (VOC) and the initial AIS (VOC) (without deductions) of the Additional BRR of the 3rd RTP of the distributors from the Eletrobras group, as presented in Table 57.


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Table 57 – Difference between the Initial and the Final Additional AIS (VOC) of the 3rd RTP

	AIS VOC Incremental AIS VOC Incremental		%
Companies	(final)	(initial)	Disallowances
Cepisa	835,842,143	897,473,190	6.9%
Ceal	385,189,982	393,695,579	2.2%
Eletroacre	179,823,621	199,479,273	9.9%
Ceron	547,631,119	585,776,597	6.5%
Boa Vista	64,853,943	71,850,393	9.7%
AME	899,942,442	1,126,729,159	20.1%
Average			9.2%
Minimum			2.2%
Maximum			20.1%
Source: Own Elaboration

This deduction percentage reflects possible imperfections of the asset and unification controls, which in the recent past, have produced reduction of the regulatory BRR values. As it is about full BRR evaluation of the concessionaire, there is a risk of higher deduction than those verified in a normal process of evaluation of additional BRR. A full evaluation involves assets, which have been unified far in the past, beyond the additional period from 2013 to 2017, which makes survey of information and physical-accounting conciliation difficult. The scope of the reevaluation work is bigger, covering a high number of assets and records, and increases the evaluator´s efforts. Furthermore, full evaluation of BRR is not normal, once since the 2nd cycle, ANEEL adopts additional evaluation of the assets, which intensifies care in a complete process inspection.

Considering these factors, which increase the risk of deduction, we adopted the following criterion to establish this deduction percentage:· For companies with deductions under the average, the average percentage of deductions (9.2%) was considered.

· When the company had percentage of deductions above the average, the average between the company´s percentage and the maximum percentage of deductions (20.1%) was used.

Ceal fits the first case, obtaining deduction at 9.2%.

The values considered as starting point in the frozen asset BRR in Feb/17 are presented in


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Table 58 – Values of BRR Considered Starting Point in the Frozen Asset BRR in Feb/17

	Technical
Description
	Report
	Feb/17
(1) Fixed Asset in Service (Value of New Replacement)	2,194,613,090
(2) Integral Use Index	714,858
(3) Special Obligations	550,309,151
(4) Totally Depreciated Goods	334,567,614
(5) Gross Remuneration Base = (1)-(2)-(3)-(4)	1,309,021,467
(6) Accumulated Depreciation	1,098,712,153
(7) Net AIS (Market Value in Use)	1,095,900,937
(8) Depreciated Use Index	345,848
(9) Value of Remuneration Base (VBR)	1,095,555,090
(10) Operating Warehouse	6,284,089
(11) Deferred Asset	0
(12) Net Special Obligations	414,380,377
(13) Land and Easements	7,529,896
(14) Total Net Remuneration Base = (1)-(6)-(8)-(12)+(10)+(11)+(13)	694,988,698
(15) Balance RGR PLPT	56,682,080
(16) Balance RGR Other Investments	175,929,846
(17) Depreciation Rate	3.68%
*The values in blue (RGR balance and depreciation rate) were estimated, because they
were not stated in the evaluation report prepared by Levin (delivered on 7/31/2017).
Source: Own Elaboration

From the values considered in


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Table 58, he monthly transactions of the Closed BRR is determined by financial update by IPCA and the deduction of depreciation and write-off related to the assets, which entered in operation by Feb/17. The forecast of the Closed BRR account was made as described below:· AIS: evolves upon deduction of write-off of assets and update by IPCA.

· Write-off of assets: the average rate of Write-offs/AIS verified from the information in the Evaluation report prepared by Levin (delivered on 4/29/2017) in the period between the 3rd RTP and Feb/17 was applied to AIS every month.

· Full Use Index (R$): evolves with IPCA.

· Gross Special obligations: evolve upon deduction of write-off of special obligations (OEs) and update by IPCA. Write-off of special obligations was forecasted by applying, to AIS of each month, the average rate of write-offs of OEs available in the Evaluation report prepared by Levin (delivered on 4/29/2017) on AIS in the period between the 3rd RTP and Feb/17.

· 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 in Feb/17 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 Levin (delivered on 4/29/2017) on the value of write-offs in the forecasted month.

· Average Depreciation Rate: the depreciation rate drops from the average level determined 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 Levin (delivered on 7/31/2017) was considered, resulting in 3.15%. o After Feb/17, the rate drops from the average level of 3.15%, 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 Dec/16 again, forecasting 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, 2.47%, was obtained, we interpolated the values between Feb/17 and Dec/2048.


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· Operation warehouse: proportion of the Operation warehouse account in the relation of the gross BRR from the Report 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. 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) 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 previous 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 previous month by IPCA and depreciation of the result.

The transaction of 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 if the 3rd RTP.

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.


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	o	Between Mar/27 and Feb/32: 1/3 multiplied by the Write-off/AIS ratio of the Closed BRR.
	o	Between Mar/32 and Feb/42: 2/3 multiplied by the Write-off/AIS ratio of the Closed BRR.
	o	From Mar/42 on: full ratio of Write-off/AIS of the Closed BRR.
	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 Levin (delivered on 7/31/2017).
	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 3.15% 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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Table 59 –Investments between 2018 and December 2022 per Registration Unit: Impact on
the Average depreciation rate of the Assets
			Dep. ate
Register Unity	AIS*	AIS Weight
Bus	R$84,500,962	11%	2.50%
Conductor / Post and Tower	R$287,678,312	37%	2.70%
Power Transformer	R$36,862,784	5%	2.86%
Swift/ Building / Transformer
Measure/Auxiliary Services Transformer/ Urbanization			3.33%
and Betterments	R$57,341,646	7%
Conductor / Pole and Tower / Panel, Command Table and
Cubicle / Unit Substation	R$253,434,815	32%	3.57%
Distribution Transformer	R$41,253,457	5%	3.70%
Conduct and Channel/Road for
Access/Indicator/Reset/Supply System for
Water/Drainage System/Sewage System			4.00%
Sanitary/Lighting and Power System/Transformer for
Distribution	R$4,484,326	1%
Voltage Regulator/Measurement Transformer	R$7,432,150	1%	4.35%
Capacitor Bank / Communication and Protection System	R$7,423,715	1%	5.00%
Bank for Capacitors/Switch/Optic Fiber/Communication	R$7,385,623	1%	6.67%
System/Protection, Measurement and Automation System
Meter	R$51,427	0%	7.69%
Total	R$787,849,216	100.0%	3.15%
* Estimated AIS (Fixed Assets in Service) related to the investments provided in PIQ (Jan/18 and Dec/22).
Investments are in real currency at prices from April 2017. These do not include assets from the vehicles, general
information equipment and systems groups.
Source: Own Elaboration

· Net special obligations: update of the net OE from the previous month, addition of OE and depreciation of the result. The compensation amounts for indicator violations occurred 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.

· RGR Balance (PLpT): update of the balance of the previous month by IPCA, addition of assets with RGR funds and depreciation of the result.

· RGR Balance (Other Investments): update of the balance of the previous month by IPCA, addition of assets with RGR funds and depreciation of the result.

For each forecasted RTP, the values determined for the total Base, composed of the sum of the Closed BRR and the Additional BRR in the RTP baseline month (6 months before RTP), are used. Specifically for Operation warehouse, the average balance from the 12 months before the base line are used. From the month, when the Closed BRR is extinct, there are only the Additional BRR accounts (except for the Land and Easement account).


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In the forecast for special obligation remuneration, the values of the other items of Part B of each forecasted RTP were considered, as well as those of the parameters of the rates risk-free rate, rated equity cost and equity share, according to the forecasted regulatory WACC, which was presented in section 4.3.1.

c) Results

The results for the Regulatory Reintegration Quota forecast for the subsequent RTPs until 2043 can be seen in Table 62.


Table 62 – Forecast of Regulatory Reintegration Quota in RTPs


	3rd RTP	Technical	4th RTP	5ªRTP	6th RTP	7th RTP	8th RTP	9th RTP
Description
	Aug/13	Report	Sept/19	Sept/23	Sept/28	Sept/33	Sept/38	Sept/43
		Feb/17
(1) Fixed Asset in Service (Value of New Replacement)	1,697,879,202	2,194,613,090	2,814,879,919	3,745,794,856	5,084,960,408	7,186,878,875	5,161,136,362	7,887,800,095
(2) Integral Use Index	5,612,748	714,858	934,490	1,281,124	1,790,187	2,574,089	1,681,153	2,569,318
(3) Special Obligations	432,468,042	550,309,151	601,887,195	696,828,239	817,182,855	955,538,417	31,725,567	39,027,711
(4) Totally Depreciated Goods	173,382,336	334,567,614	437,116,309	700,601,091	1,264,449,215	2,445,467,743	479,233,829	1,098,624,521
(5) Gross Remuneration Base = (1)-(2)-(3)-(4)	1,086,416,076	1,309,021,467	1,774,941,925	2,347,084,401	3,001,538,151	3,783,298,626	4,648,495,813	6,747,578,545
(17) Depreciation Rate	3.97%	3.68%	3.48%	3.30%	3.17%	3.13%	3.15%	3.15%
*(18) Regulatory Reintegration Installment = (17) (5)**	43,130,718	NA	61,814,199	77,358,887	95,074,314	118,417,260	146,255,181	212,298,421

Source: Own Elaboration

The results for the Equity Remuneration forecast for the subsequent RTPs until 2043 can be seen in Table 63.


Table 63 – Forecast for Equity Remuneration without Special obligations in RTPs

	3rd RTP	Technical	4th RTP	5ªRTP	6th RTP	7th RTP	8th RTP	9th RTP
Description
	Aug/13	Report	Sept/19	Sept/23	Sept/28	Sept/33	Sept/38	Sept/43
Feb/17

(1) Fixed Asset in Service (Value of New Replacement)	1,697,879,202	2,194,613,090	2,814,879,919	3,745,794,856	5,084,960,408	7,186,878,875	5,161,136,362	7,887,800,095
(6) Accumulated Depreciation	891,195,249	1,098,712,153	1,303,161,601	1,752,085,391	2,491,835,139	3,496,233,034	1,810,657,230	3,210,633,652
(7) Net AIS (Market Value in Use)	806,683,954	1,095,900,937	1,511,718,317	1,993,709,465	2,593,125,269	3,690,645,841	3,350,479,133	4,677,166,443
(8) Depreciated Use Index	1,483,400	345,848	901,577	1,238,317	1,733,184	2,495,037	1,628,259	2,488,480
(9) Value of Remuneration Base (VBR)	805,200,554	1,095,555,090	1,510,816,741	1,992,471,149	2,591,392,085	3,688,150,804	3,348,850,873	4,674,677,963
(10) Operating Warehouse	6,005,536	6,284,089	9,150,681	12,672,743	16,225,990	20,532,799	24,788,354	36,037,098
(11) Deferred Asset	0	0	0	0	0	0	0	0
(12) Net Special Obligations	371,911,952	414,380,377	416,227,382	414,168,811	394,827,141	369,617,016	18,758,890	19,713,343
(13) Land and Easements	4,542,664	7,529,896	8,410,556	9,938,236	12,225,679	15,039,613	18,501,220	22,759,570
(14) Total Net Remuneration Base = (1)-(6)-(8)-	443,836,802	694,988,698	1,112,150,595	1,600,913,316	2,225,016,613	3,354,106,201	3,373,381,557	4,713,761,288
(12)+(10)+(11)+(13)
(15) Balance RGR PLPT	51,641,207	56,682,080	58,691,776	60,289,237	62,854,013	66,188,611	70,360,044	75,459,364
(16) Balance RGR Other Investments	160,283,984	175,929,846	182,167,542	187,125,741	195,086,293	205,436,220	218,383,514	234,210,783
(19) Real WACC before taxes	11.36%	NA	11.34%	11.34%	11.34%	11.34%	11.34%	11.34%
(20) Real RGR/PLPT rate	1.35%	NA	0.00%	1.13%	2.10%	2.10%	2.10%	2.10%
(21) RGR Rate Other Investments	3.62%	NA	2.00%	4.44%	4.40%	4.38%	4.38%	4.38%
(22) Capital Remuneration without Special Obligations	32,844,596	NA	102,477,424	162,515,089	233,036,807	360,041,025	360,940,975	511,406,372
(RCsOE)

Source: Own Elaboration

The results for the forecast of the Equity Remuneration of the Special obligations for subsequent RTPs until 2043 can be seen in


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Table 64 – Forecast for Equity Remuneration of the Special obligations in RTPs

	3rd RTP	Technical	4th RTP	5ªRTP	6th RTP	7th RTP	8th RTP	9th RTP
Description
	Aug/13	Report	Sept/19	Sept/23	Sept/28	Sept/33	Sept/38	Sept/43
		Feb/17
(3) Special Obligations	432,468,042	550,309,151	601,887,195	696,828,239	817,182,855	955,538,417	31,725,567	39,027,711
(23 ) Cost of Own Capital nominal (rp)	NA	NA	12.27%	12.27%	12.27%	12.27%	12.27%	12.27%
(24) Risk Free nominal Rate (Rf)	NA	NA	4.89%	4.89%	4.89%	4.89%	4.89%	4.89%
(25) Taxes and Contributions on Income (t)	NA	NA	34.00%	34.00%	34.00%	34.00%	34.00%	34.00%
(26) Equity Share	NA	NA	51.24%	51.24%	51.24%	51.24%	51.24%	51.24%
(27) CAOM / (CAOM+QRR+RCsOE+CAIMI)	NA	NA	58.58%	54.42%	51.28%	45.64%	50.58%	47.74%
(28) Remuneration of Special Obligations	NA	NA	10,102,153	10,863,716	12,006,295	12,494,266	459,748	533,800

Source: Own Elaboration

The results of the forecast of the Annual Fixed or Portable Facilities Cost for subsequent RTPs until 2043 can be seen in Table 65.


Table 65 – Forecast of the Annual Fixed or Portable Facilities Cost in RTPs


Description	Aug/13	Feb/17	Sept/19	Sept/23	Sept/28	Sept/33	Sept/38	Sept/43
(1) Regulatory Annuity Base (BAR)	90,467,401	NA	208,042,769	271,403,842	362,419,621	500,488,344	393,231,601	579,588,482
(2) Annuity Base - Real estate and administrative furniture infrastructure (BARA)	22,616,850	NA	93,619,246	122,131,729	163,088,829	225,219,755	176,954,221	260,814,817
(3) Annuity Base - Vehicles (BARV)	22,616,850	NA	24,965,132	32,568,461	43,490,355	60,058,601	47,187,792	69,550,618
(4) Annuity Base - Computer Systems (BARI)	45,233,701	NA	89,458,391	116,703,652	155,840,437	215,209,988	169,089,589	249,223,047
(5) - Annuity - Real estate and administrative furniture infrastructure (CAL)	2,095,277	NA	8,665,099	11,304,124	15,094,982	20,845,623	16,378,319	24,140,188
(6) Annuity - Vehicles (CAV)	4,515,616	NA	4,982,333	6,499,742	8,679,442	11,985,995	9,417,346	13,880,332
(7) Annuity - Computer Systems (CAI)	11,103,935	NA	21,952,531	28,638,349	38,242,272	52,811,189	41,493,531	61,157,782
(8) CAIMI = (5)+(6)+(7)	17,714,827	NA	35,599,963	46,442,214	62,016,696	85,642,807	67,289,196	99,178,303

Source: Own Elaboration

4.3.9.Tariff Transactions

From the composition of the items identified above, the values for Part A and Part B are forecasted and thus, the Required Revenues for each tariff year are determined.

There are some particularities in the tariff transactions between 2017 a 2019.

In 2017, as stated in TN No. 149/2017 and TN No. 247/2017, the difference between the flexible regulatory level of the operational costs and that recognized in the tariff process from 2016 (difference calculated in TN No. 149/2017), updated by IPCA between the tariff process date from 2016 and the tariff process date from 2017, shall be added to Part B. For 2018, first year of the new concession, it is assumed that the operational costs will be equal to those from 2017, updated by IPCA (this value will be reduced according to the bidding criterion).

In this context, the following was done:

(a) the value of the difference between the flexible regulatory of operational costs and that recognized in the tariff from 2016 was updated by accumulated IPCA and added to VPB in 2017; (b) the tariff coverage of Operational costs in Part B in 2017 was estimated, according to PRORET 2.2A, formula (1) of paragraph 13, section 3.1, presented above in this report in Equation 16; (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 VPB0 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.


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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 Ceal (rated R$ million)
		RA1	VPA	VPB
Regulatory Year	Reference Period	Required Income	Value of Portion A	Value of Portion B
2017	Sept/10 to Aug/17	R$1,422.58	R$982.36	R$440.22
2018	Sept/17 to Aug/18	R$1,526.51	R$1,039.90	R$486.61
2019	Sept/18 to Aug/19	R$1,704.03	R$1,117.84	R$586.18
2020	Sept/19 to Aug/20	R$1,836.07	R$1,197.33	R$638.74
2021	Sept/20 to Aug/21	R$1,970.46	R$1,279.76	R$690.70
2022	Sept/21 to Aug/22	R$2,112.58	R$1,366.05	R$746.53
2023	Sept/22 to Aug/23	R$2,150.42	R$1,384.01	R$766.40
2024	Sept/23 to Aug/24	R$2,256.51	R$1,468.01	R$788.50
2025	Sept/24 to Aug/25	R$2,371.02	R$1,560.48	R$810.54
2026	Sept/25 to Aug/26	R$2,490.10	R$1,657.48	R$832.62
2027	Sept/26 to Aug/27	R$2,607.73	R$1,759.11	R$848.62
2028	Sept/27 to Aug/28	R$2,699.60	R$1,852.39	R$847.21
2029	Sept/28 to Aug/29	R$2,836.40	R$1,956.75	R$879.66
2030	Sept/29 to Aug/30	R$2,978.18	R$2,065.73	R$912.45
2031	Sept/30 to Aug/31	R$3,123.76	R$2,178.51	R$945.24
2032	Sept/31 to Aug/32	R$3,276.42	R$2,297.30	R$979.11
2033	Sept/32 to Aug/33	R$3,462.10	R$2,417.67	R$1,044.44
2034	Sept/33 to Aug/34	R$3,647.37	R$2,554.65	R$1,092.72
2035	Sept/34 to Aug/35	R$3,844.22	R$2,700.74	R$1,143.47
2036	Sept/35 to Aug/36	R$4,052.84	R$2,855.99	R$1,196.84
2037	Sept/36 to Aug/37	R$4,274.06	R$3,021.06	R$1,253.00
2038	Sept/37 to Aug/38	R$4,298.16	R$3,185.00	R$1,113.16
2049	Sept/38 to Aug/39	R$4,548.69	R$3,375.21	R$1,173.48
2040	Sept/39 to Aug/40	R$4,816.33	R$3,578.92	R$1,237.41
2041	Sept/40 to Aug/41	R$5,101.59	R$3,796.39	R$1,305.20
2042	Sept/41 to Aug/42	R$5,405.83	R$4,028.70	R$1,377.13
2043	Sept/42 to Aug/43	R$5,745.84	R$4,259.52	R$1,486.32
2044	Sept/43 to Aug/44	R$6,096.75	R$4,522.84	R$1,573.91
2045	Sept/44 to Aug/45	R$6,473.15	R$4,805.87	R$1,667.28
2046	Sept/45 to Aug/46	R$6,876.07	R$5,109.19	R$1,766.88
2047	Sept/46 to Aug/47	R$7,307.78	R$5,434.57	R$1,873.21
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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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 by Aneel.
· Regulatory Allowance 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
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
Supply), considering its index of Verified Energy Losses.


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· Excess Contracted Energy: the excess amount 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.

Energy 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

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.


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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$/MWh) as they are used in the Electricity Rate calculation. ii - When the amount (MWh) of Required Energy Supply is over the limit of 105% of the Regulatory Allowance for Contracted Energy. In such case, the impact is considered in a portion of the costs related to Energy Purchase and Transportation that is not considered in the Electricty Rate calculation. Such an impact is considered in the valuation, as detailed in this report. a) Energy Cost The energy cost is calculated from the Weighted Average Cost of the Energy, in R$/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 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


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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 schedule of interconnections estimated for the Distributor.

Thus, the fraction of Portion A related to the Transportation Cost has a negative economic 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) Financial Charges

As mentioned before, the Financial 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

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


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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 for 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 between the Energy Purchase (MWh) and the respective cost (R$/MWh), as projected in Portion A.

· Cost of Self-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.

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


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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 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 Results

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


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6.5.	Valuation results

The valuation results are presented in the following tables.

Table 69 – Distributed energy projections


Energy (000 MWh)			2017	2018	2019	2020	2021	2022
Regulated market			3,033	3,104	3,221	3,330	3,439	3,545
Free market			454	530	548	566	584	601
Supply			-	-	-	-	-	-
Regulatory allowance for energy losses			1,373	1,425	1,458	1,443	1,423	1,397
Excess contracted Energy			796	365	140	379	146	148
Total energy			5,656	5,424	5,368	5,718	5,591	5,691
Energy (000 MWh)			2023	2024	2025	2026	2027	2028
Regulated market			3,649	3,751	3,850	3,948	4,044	4,139
Free market			618	634	650	666	682	698
Supply			-	-	-	-	-	-
Regulatory allowance for energy losses			1,359	1,308	1,267	1,222	1,172	1,108
Excess contracted Energy			150	152	154	155	156	157
Total energy			5,775	5,845	5,922	5,992	6,055	6,102
Energy (000 MWh)			2029	2030	2031	2032	2033	2034
Regulated market			4,231	4,320	4,407	4,495	4,587	4,682
Free market			713	728	742	757	772	787
Supply			-	-	-	-	-	-
Regulatory allowance for energy losses			1,054	1,064	1,073	1,081	1,080	1,068
Excess contracted Energy			159	162	164	167	170	172
Total energy			6,158	6,274	6,386	6,501	6,608	6,709
Energy (000 MWh)			2035	2036	2037	2038	2039	2040
Regulated market			4,780	4,881	4,986	5,095	5,209	5,327
Free market			802	818	835	851	869	886
Supply			-	-	-	-	-	-
Regulatory allowance for energy losses			1,077	1,086	1,095	1,093	1,080	1,090
Excess contracted Energy			176	179	182	186	189	192
Total energy			6,834	6,964	7,098	7,225	7,346	7,495
Energy (000 MWh)		2041	2042	2043	2044	2045	2046	2047
Regulated market		5,449	5,577	5,710	5,849	5,995	6,147	6,307
Free market		905	923	943	963	983	1,005	1,027
Supply		-	-	-	-	-	-	-
Regulatory allowance for energy losses		1,099	1,110	1,108	1,094	1,104	1,115	1,126
Excess contracted Energy		196	201	205	208	213	218	223
Total energy		7,650	7,811	7,965	8,114	8,295	8,485	8,683


Table 70 – Net revenues projections


Net Revenues (000 R$)			2017	2018	2019	2020	2021	2022
Portion A distributed energy (000 MWh)			3,033	3,104	3,221	3,330	3,439	3,545
Portion A tariff (R$/MWh)			316	340	352	365	377	391
Portion A			958,082	1,056,287	1,134,126	1,214,008	1,297,817	1,385,132
Portion B distributed energy (MWh)			3,487	3,634	3,769	3,896	4,023	4,146
Portion B tariff (R$/MWh)			117	130	142	159	167	175
Portion B			409,647	472,698	536,336	620,638	673,309	726,751
Other revenues			15,522	16,257	17,012	17,787	18,583	19,413
Sale of excess contracted energy			143,924	78,721	31,604	88,896	29,554	13,732
Sectorial Charges			(244,011)	(257,445)	(268,734)	(280,302)	(292,392)	(304,794)
Total net operating revenues			1,283,163	1,366,518	1,450,344	1,661,028	1,726,870	1,840,234


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Net Revenues (000 R$)		2023	2024	2025	2026	2027	2028
Portion A distributed energy (000 MWh)		3,649	3,751	3,850	3,948	4,044	4,139
Portion A tariff (R$/MWh)		397	396	410	425	440	454
Portion A		1,449,094	1,486,269	1,580,309	1,678,966	1,781,560	1,878,278
Portion B distributed energy (MWh)		4,267	4,385	4,501	4,615	4,727	4,837
Portion B tariff (R$/MWh)		181	180	180	181	180	178
Portion B		770,468	790,482	812,036	833,599	853,141	862,663
Other revenues		20,281	21,188	22,135	23,124	24,158	25,238
Sale of excess contracted energy		16,391	42,063	42,882	34,414	13,428	-
Sectorial Charges		(317,678)	(331,111)	(345,113)	(359,709)	(374,923)	(390,780)
Total net operating revenues		1,938,557	2,008,891	2,112,249	2,210,394	2,297,364	2,375,399
Net Revenues (000 R$)		2029	2030	2031	2032	2033	2034
Portion A distributed energy (000 MWh)		4,231	4,320	4,407	4,495	4,587	4,682
Portion A tariff (R$/MWh)		466	482	500	518	536	553
Portion A		1,969,850	2,083,260	2,201,604	2,327,049	2,456,639	2,590,655
Portion B distributed energy (MWh)		4,945	5,048	5,149	5,252	5,358	5,468
Portion B tariff (R$/MWh)		176	179	182	185	189	197
Portion B		871,948	903,866	936,127	969,728	1,014,953	1,075,663
Other revenues		26,366	27,544	28,775	30,062	31,405	32,809
Sale of excess contracted energy		-	-	-	-	-	-
Sectorial Charges		(407,340)	(424,536)	(442,444)	(461,157)	(480,661)	(500,991)
Total net operating revenues		2,460,824	2,590,133	2,724,061	2,865,682	3,022,336	3,198,136
Net Revenues (000 R$)		2035	2036	2037	2038	2039	2040
Portion A distributed energy (000 MWh)		4,780	4,881	4,986	5,095	5,209	5,327
Portion A tariff (R$/MWh)		573	594	616	637	658	682
Portion A		2,740,638	2,900,146	3,069,883	3,245,752	3,428,177	3,632,741
Portion B distributed energy (MWh)		5,582	5,699	5,821	5,947	6,077	6,213
Portion B tariff (R$/MWh)		202	207	212	206	189	195
Portion B		1,125,753	1,178,441	1,233,892	1,224,770	1,151,072	1,213,966
Other revenues		34,276	35,808	37,409	39,081	40,828	42,653
Sale of excess contracted energy		-	-	-	-	-	-
Sectorial Charges		(522,180)	(544,266)	(567,286)	(591,279)	(616,287)	(642,353)
Total net operating revenues		3,378,487	3,570,129	3,773,898	3,918,323	4,003,790	4,247,007
Net Revenues (000 R$)	2041	2042	2043	2044	2045	2046	2047
Portion A distributed energy (000 MWh)	5,449	5,577	5,710	5,849	5,995	6,147	6,307
Portion A tariff (R$/MWh)	707	732	758	783	811	840	871
Portion A	3,850,972	4,083,948	4,326,193	4,578,290	4,861,696	5,165,234	5,490,645
Portion B distributed energy (MWh)	6,354	6,500	6,653	6,812	6,978	7,152	7,334
Portion B tariff (R$/MWh)	202	208	216	226	234	242	250
Portion B	1,280,680	1,351,492	1,437,847	1,542,227	1,634,049	1,732,038	1,836,694
Other revenues	44,559	46,551	48,632	50,806	53,077	55,449	57,928
Sale of excess contracted energy	-	-	-	-	-	-	-
Sectorial Charges	(669,520)	(697,837)	(727,351)	(758,114)	(790,177)	(823,595)	(858,426)
Total net operating revenues	4,506,691	4,784,153	5,085,321	5,413,209	5,758,645	6,129,126	6,526,840


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Table 71 – Operating costs projections


Operating costs (000 R$)		2017	2018	2019	2020	2021	2022
Energy acquisiton (000 MWh)		5,202	4,894	4,819	5,152	5,008	5,090
Average cost (R$/MWh)		165	172	179	187	195	203
Energy cost		855,893	840,819	864,299	963,959	976,936	1,035,069
Transportation costs		42,162	45,258	48,804	51,944	55,164	58,447
% Energy cost		4.9%	5.4%	5.6%	5.4%	5.6%	5.6%
Total costs		898,056	886,077	913,103	1,015,903	1,032,100	1,093,516
% Net Operating revenues		70.0%	64.8%	63.0%	61.2%	59.8%	59.4%
Operating costs (000 R$)		2023	2024	2025	2026	2027	2028
Energy acquisiton (000 MWh)		5,158	5,210	5,271	5,325	5,373	5,404
Average cost (R$/MWh)		212	221	230	240	250	261
Energy cost		1,093,132	1,151,018	1,213,718	1,278,056	1,344,033	1,409,021
Transportation costs		61,725	64,994	68,535	72,168	75,893	79,563
% Energy cost		5.6%	5.6%	5.6%	5.6%	5.6%	5.6%
Total costs		1,154,858	1,216,012	1,282,252	1,350,224	1,419,926	1,488,583
% Net Operating revenues		59.6%	60.5%	60.7%	61.1%	61.8%	62.7%
Operating costs (000 R$)		2029	2030	2031	2032	2033	2034
Energy acquisiton (000 MWh)		5,444	5,546	5,644	5,744	5,837	5,922
Average cost (R$/MWh)		272	283	295	308	321	334
Energy cost		1,479,588	1,570,907	1,666,252	1,767,590	1,872,058	1,979,808
Transportation costs		83,547	88,704	94,088	99,810	105,709	111,793
% Energy cost		5.6%	5.6%	5.6%	5.6%	5.6%	5.6%
Total costs		1,563,135	1,659,611	1,760,340	1,867,399	1,977,767	2,091,601
% Net Operating revenues		63.5%	64.1%	64.6%	65.2%	65.4%	65.4%
Operating costs (000 R$)		2035	2036	2037	2038	2039	2040
Energy acquisiton (000 MWh)		6,032	6,146	6,264	6,374	6,478	6,609
Average cost (R$/MWh)		348	363	379	395	411	429
Energy cost		2,101,876	2,232,125	2,371,186	2,515,066	2,664,035	2,832,954
Transportation costs		118,686	126,041	133,893	142,017	150,429	159,967
% Energy cost		5.6%	5.6%	5.6%	5.6%	5.6%	5.6%
Total costs		2,220,561	2,358,165	2,505,079	2,657,083	2,814,464	2,992,922
% Net Operating revenues		65.7%	66.1%	66.4%	67.8%	70.3%	70.5%
Operating costs (000 R$)	2041	2042	2043	2044	2045	2046	2047
Energy acquisiton (000 MWh)	6,745	6,887	7,022	7,151	7,312	7,480	7,656
Average cost (R$/MWh)	447	466	485	506	527	550	573
Energy cost	3,013,752	3,207,402	3,408,673	3,618,070	3,855,857	4,111,390	4,386,259
Transportation costs	170,176	181,111	192,476	204,300	217,727	232,156	247,677
% Energy cost	5.6%	5.6%	5.6%	5.6%	5.6%	5.6%	5.6%
Total costs	3,183,929	3,388,513	3,601,149	3,822,370	4,073,584	4,343,546	4,633,936
% Net Operating revenues	70.6%	70.8%	70.8%	70.6%	70.7%	70.9%	71.0%


Table 72 – Gross profit projections


Gross profit (000 R$)		2017	2018	2019	2020	2021	2022
Net Revenues		1,283,163	1,366,518	1,450,344	1,661,028	1,726,870	1,840,234
Total costs		(898,056)	(886,077)	(913,103)	(1,015,903)	(1,032,100)	(1,093,516)
Gross profit		385,107	480,441	537,241	645,124	694,770	746,718
% Gross margin		30.0%	35.2%	37.0%	38.8%	40.2%	40.6%


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Gross profit (000 R$)		2023	2024	2025	2026	2027	2028
Net Revenues		1,938,557	2,008,891	2,112,249	2,210,394	2,297,364	2,375,399
Total costs		(1,154,858)	(1,216,012)	(1,282,252)	(1,350,224)	(1,419,926)	(1,488,583)
Gross profit		783,699	792,878	829,997	860,170	877,438	886,816
% Gross margin		40.4%	39.5%	39.3%	38.9%	38.2%	37.3%

Gross profit (000 R$)		2029	2030	2031	2032	2033	2034
Net Revenues		2,460,824	2,590,133	2,724,061	2,865,682	3,022,336	3,198,136
Total costs		(1,563,135)	(1,659,611)	(1,760,340)	(1,867,399)	(1,977,767)	(2,091,601)
Gross profit		897,689	930,522	963,722	998,283	1,044,569	1,106,535
% Gross margin		36.5%	35.9%	35.4%	34.8%	34.6%	34.6%

Gross profit (000 R$)		2035	2036	2037	2038	2039	2040
Net Revenues		3,378,487	3,570,129	3,773,898	3,918,323	4,003,790	4,247,007
Total costs		(2,220,561)	(2,358,165)	(2,505,079)	(2,657,083)	(2,814,464)	(2,992,922)
Gross profit		1,157,925	1,211,964	1,268,818	1,261,240	1,189,325	1,254,085
% Gross margin		34.3%	33.9%	33.6%	32.2%	29.7%	29.5%

Gross profit (000 R$)	2041	2042	2043	2044	2045	2046	2047
Net Revenues	4,506,691	4,784,153	5,085,321	5,413,209	5,758,645	6,129,126	6,526,840
Total costs	(3,183,929)	(3,388,513)	(3,601,149)	(3,822,370)	(4,073,584)	(4,343,546)	(4,633,936)
Gross profit	1,322,763	1,395,640	1,484,172	1,590,839	1,685,062	1,785,580	1,892,904
% Gross margin	29.4%	29.2%	29.2%	29.4%	29.3%	29.1%	29.0%


Table 73 – Operating expenses projections


Operating Expenses (000 R$)		2017	2018	2019	2020	2021	2022
Personal		165,486	175,076	176,079	176,060	176,773	177,902
Materials		1,899	2,009	2,021	2,020	2,029	2,042
Services		100,228	106,036	106,643	106,632	107,064	107,747
Others		29,074	30,759	30,936	30,932	31,058	31,256
Total PMSO		296,687	313,881	315,678	315,645	316,923	318,946
% Net Revenues		23.1%	23.0%	21.8%	19.0%	18.4%	17.3%
% Verified PMSO / Regulatory allowance for PMSO		112.5%	112.5%	111.4%	109.6%	108.1%	106.8%
Default*		34,393	31,530	27,895	24,624	20,773	17,218
% Net revenues		2.7%	2.3%	1.9%	1.5%	1.2%	0.9%
* Net of considered default in Portion A
Total Operating expenses		331,080	345,411	343,573	340,269	337,696	336,164
% Net revenues		25.8%	25.3%	23.7%	20.5%	19.6%	18.3%

Operating Expenses (000 R$)		2023	2024	2025	2026	2027	2028
Personal		179,351	180,886	182,641	184,592	186,718	188,845
Materials		2,058	2,076	2,096	2,118	2,143	2,167
Services		108,625	109,554	110,617	111,799	113,087	114,375
Others		31,510	31,780	32,088	32,431	32,805	33,178
Total PMSO		321,545	324,296	327,442	330,940	334,752	338,566
% Net Revenues		16.6%	16.1%	15.5%	15.0%	14.6%	14.3%
% Verified PMSO / Regulatory allowance for PMSO		105.8%	104.9%	104.1%	103.4%	102.9%	102.4%
Default*		13,690	9,438	5,790	2,287	0	-
% Net revenues		0.7%	0.5%	0.3%	0.1%	0.0%	0.0%
* Net of considered default in Portion A
Total Operating expenses		335,235	333,734	333,232	333,228	334,752	338,566
% Net revenues		17.3%	16.6%	15.8%	15.1%	14.6%	14.3%


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Operating Expenses (000 R$)		2029	2030	2031	2032	2033	2034
Personal		191,105	193,463	195,736	199,375	207,971	217,085
Materials		2,193	2,220	2,246	2,288	2,387	2,491
Services		115,744	117,172	118,549	120,753	125,959	131,479
Others		33,576	33,990	34,389	35,028	36,539	38,140
Total PMSO		342,618	346,845	350,920	357,444	372,856	389,195
% Net Revenues		13.9%	13.4%	12.9%	12.5%	12.3%	12.2%
% Verified PMSO / Regulatory allowance for PMSO		102.1%	101.7%	101.5%	101.3%	101.2%	101.1%
Default*		-	-	-	-	-	-
% Net revenues		0.0%	0.0%	0.0%	0.0%	0.0%	0.0%
* Net of considered default in Portion A
Total Operating expenses		342,618	346,845	350,920	357,444	372,856	389,195
% Net revenues		13.9%	13.4%	12.9%	12.5%	12.3%	12.2%

Operating Expenses (000 R$)		2035	2036	2037	2038	2039	2040
Personal		226,608	236,560	246,962	257,930	269,404	281,407
Materials		2,600	2,715	2,834	2,960	3,092	3,229
Services		137,247	143,274	149,574	156,217	163,166	170,436
Others		39,813	41,562	43,389	45,316	47,332	49,441
Total PMSO		406,268	424,111	442,758	462,423	482,993	504,512
% Net Revenues		12.0%	11.9%	11.7%	11.8%	12.1%	11.9%
% Verified PMSO / Regulatory allowance for PMSO		101.1%	101.1%	101.1%	101.0%	101.0%	101.0%
Default*		-	-	-	-	-	-
% Net revenues		0.0%	0.0%	0.0%	0.0%	0.0%	0.0%
* Net of considered default in Portion A
Total Operating expenses		406,268	424,111	442,758	462,423	482,993	504,512
% Net revenues		12.0%	11.9%	11.7%	11.8%	12.1%	11.9%

Operating Expenses (000 R$)	2041	2042	2043	2044	2045	2046	2047
Personal	293,966	307,108	320,859	335,253	350,324	366,105	382,634
Materials	3,373	3,524	3,682	3,847	4,020	4,201	4,391
Services	178,042	186,002	194,330	203,048	212,176	221,734	231,744
Others	51,647	53,956	56,372	58,901	61,549	64,321	67,225
Total PMSO	527,028	550,590	575,243	601,050	628,068	656,361	685,995
% Net Revenues	11.7%	11.5%	11.3%	11.1%	10.9%	10.7%	10.5%
% Verified PMSO / Regulatory allowance for PMSO	101.0%	100.9%	100.9%	100.9%	100.9%	100.8%	100.8%
Default*	-	-	-	-	-	-	-
% Net revenues	0.0%	0.0%	0.0%	0.0%	0.0%	0.0%	0.0%
* Net of considered default in Portion A
Total Operating expenses	527,028	550,590	575,243	601,050	628,068	656,361	685,995
% Net revenues	11.7%	11.5%	11.3%	11.1%	10.9%	10.7%	10.5%


Table 74 – EBITDA projections


EBITDA (000 R$)		2017	2018	2019	2020	2021	2022
Gross profit		385,107	480,441	537,241	645,124	694,770	746,718
Total Operating expenses		(331,080)	(345,411)	(343,573)	(340,269)	(337,696)	(336,164)
EBITDA		54,027	135,030	193,668	304,855	357,074	410,554
% EBITDA margin		4.2%	9.9%	13.4%	18.4%	20.7%	22.3%

EBITDA (000 R$)		2023	2024	2025	2026	2027	2028
Gross profit		783,699	792,878	829,997	860,170	877,438	886,816
Total Operating expenses		(335,235)	(333,734)	(333,232)	(333,228)	(334,752)	(338,566)
EBITDA		448,464	459,145	496,765	526,942	542,686	548,250
% EBITDA margin		23.1%	22.9%	23.5%	23.8%	23.6%	23.1%

EBITDA (000 R$)		2029	2030	2031	2032	2033	2034
Gross profit		897,689	930,522	963,722	998,283	1,044,569	1,106,535
Total Operating expenses		(342,618)	(346,845)	(350,920)	(357,444)	(372,856)	(389,195)
EBITDA		555,071	583,677	612,802	640,839	671,714	717,340
% EBITDA margin		22.6%	22.5%	22.5%	22.4%	22.2%	22.4%


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EBITDA (000 R$)		2035	2036	2037	2038	2039	2040
Gross profit		1,157,925	1,211,964	1,268,818	1,261,240	1,189,325	1,254,085
Total Operating expenses		(406,268)	(424,111)	(442,758)	(462,423)	(482,993)	(504,512)
EBITDA		751,657	787,853	826,060	798,817	706,332	749,573
% EBITDA margin		22.2%	22.1%	21.9%	20.4%	17.6%	17.6%
EBITDA (000 R$)	2041	2042	2043	2044	2045	2046	2047
Gross profit	1,322,763	1,395,640	1,484,172	1,590,839	1,685,062	1,785,580	1,892,904
Total Operating expenses	(527,028)	(550,590)	(575,243)	(601,050)	(628,068)	(656,361)	(685,995)
EBITDA	795,735	845,050	908,929	989,790	1,056,993	1,129,219	1,206,909
% EBITDA margin	17.7%	17.7%	17.9%	18.3%	18.4%	18.4%	18.5%


Table 75 – Net income projections


Net income (000 R$)		2017	2018	2019	2020	2021	2022
EBITDA		54,027	135,030	193,668	304,855	357,074	410,554
Depreciation		(61,273)	(62,974)	(70,380)	(73,425)	(71,474)	(75,510)
Income tax		(8,771)	(17,125)	(29,318)	(55,056)	(67,949)	(79,716)
Net income		(16,018)	54,930	93,969	176,374	217,651	255,327
% Net margin		-1.2%	4.0%	6.5%	10.6%	12.6%	13.9%
Net income (000 R$)		2023	2024	2025	2026	2027	2028
EBITDA		448,464	459,145	496,765	526,942	542,686	548,250
Depreciation		(78,763)	(81,259)	(84,422)	(89,002)	(94,376)	(99,198)
Income tax		(87,965)	(89,377)	(97,671)	(103,733)	(125,349)	(151,887)
Net income		281,736	288,509	314,672	334,207	322,961	297,165
% Net margin		14.5%	14.4%	14.9%	15.1%	14.1%	12.5%
Net income (000 R$)		2029	2030	2031	2032	2033	2034
EBITDA		555,071	583,677	612,802	640,839	671,714	717,340
Depreciation		(103,390)	(109,095)	(90,135)	(80,081)	(87,061)	(90,838)
Income tax		(152,732)	(160,467)	(176,763)	(189,658)	(197,723)	(211,889)
Net income		298,950	314,115	345,903	371,100	386,930	414,614
% Net margin		12.1%	12.1%	12.7%	12.9%	12.8%	13.0%
Net income (000 R$)		2035	2036	2037	2038	2039	2040
EBITDA		751,657	787,853	826,060	798,817	706,332	749,573
Depreciation		(95,624)	(102,556)	(110,688)	(117,984)	(124,328)	(132,962)
Income tax		(221,861)	(231,739)	(241,887)	(230,061)	(196,371)	(208,043)
Net income		434,172	453,559	473,485	450,772	385,633	408,568
% Net margin		12.9%	12.7%	12.5%	11.5%	9.6%	9.6%
Net income (000 R$)	2041	2042	2043	2044	2045	2046	2047
EBITDA	795,735	845,050	908,929	989,790	1,056,993	1,129,219	1,206,909
Depreciation	(146,195)	(161,965)	(172,528)	(178,244)	(185,486)	(195,976)	(208,284)
Income tax	(219,138)	(230,435)	(248,446)	(273,871)	(294,124)	(314,970)	(337,045)
Net income	430,402	452,650	487,955	537,675	577,383	618,273	661,581
% Net margin	9.6%	9.5%	9.6%	9.9%	10.0%	10.1%	10.1%


Table 76 – Cash flow projections


Cash Flow (000 R$)		2017	2018	2019	2020	2021	2022
EBITDA		54,027	135,030	193,668	304,855	357,074	410,554
Income Tax		(8,771)	(17,125)	(29,318)	(55,056)	(67,949)	(79,716)
Working capital needs		25	29	(4,396)	(5,637)	(5,648)	(6,613)
Other adjustments		(23,800)	143,040	224,276	60,435	-	-
CAPEX		(45,113)	(354,079)	(134,946)	(137,083)	(127,704)	(128,753)
Free Cash Flow for the Firm		(23,633)	(93,106)	249,283	167,514	155,774	195,471


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Cash Flow (000 R$)		2023	2024	2025	2026	2027	2028
EBITDA		448,464	459,145	496,765	526,942	542,686	548,250
Income Tax		(87,965)	(89,377)	(97,671)	(103,733)	(125,349)	(151,887)
Working capital needs		(7,081)	(1,048)	(1,541)	(1,463)	(1,296)	(1,163)
Other adjustments		-	-	-	-	-	-
CAPEX		(81,924)	(77,138)	(120,303)	(166,982)	(174,045)	(135,630)
Free Cash Flow for the Firm		271,495	291,581	277,250	254,765	241,996	259,570
Cash Flow (000 R$)		2029	2030	2031	2032	2033	2034
EBITDA		555,071	583,677	612,802	640,839	671,714	717,340
Income Tax		(152,732)	(160,467)	(176,763)	(189,658)	(197,723)	(211,889)
Working capital needs		(1,273)	(1,928)	(1,996)	(2,111)	(2,335)	(2,621)
Other adjustments		-	-	-	-	-	-
CAPEX		(131,217)	(223,714)	(323,802)	(337,499)	(123,976)	(116,734)
Free Cash Flow for the Firm		269,849	197,568	110,240	111,571	347,679	386,097
Cash Flow (000 R$)		2035	2036	2037	2038	2039	2040
EBITDA		751,657	787,853	826,060	798,817	706,332	749,573
Income Tax		(221,861)	(231,739)	(241,887)	(230,061)	(196,371)	(208,043)
Working capital needs		(2,688)	(2,857)	(3,037)	(2,153)	(1,274)	(3,625)
Other adjustments		-	-	-	-	-	-
CAPEX		(182,056)	(252,695)	(263,384)	(205,250)	(198,572)	(338,549)
Free Cash Flow for the Firm		345,052	300,563	317,752	361,353	310,115	199,355
Cash Flow (000 R$)	2041	2042	2043	2044	2045	2046	2047
EBITDA	795,735	845,050	908,929	989,790	1,056,993	1,129,219	1,206,909
Income Tax	(219,138)	(230,435)	(248,446)	(273,871)	(294,124)	(314,970)	(337,045)
Working capital needs	(3,871)	(4,136)	(4,489)	(4,888)	(5,149)	(5,522)	(5,928)
Other adjustments	-	-	-	-	-	-	-
CAPEX	(490,012)	(510,740)	(187,614)	(176,655)	(275,507)	(382,405)	(398,581)
Free Cash Flow for the Firm	82,714	99,740	468,379	534,376	482,214	426,321	465,355

Table 77 – Terminal Value

Indemnity (000 R$)					Feb/48
Indemnity					5,243,243
Income tax					(402,435)
Net Compensation					4,840,808
Remaining Value - Portion B					41,457
Terminal Value					4,882,265

Table 78 – Valuation Results

Conclusion					Dec/16
NPV FCFF				2,153,270,399.68
NPV Terminal Value				293,291,900.79
Enterprise Value				2,446,562,300.47
(-) Net Debt				(1,695,548,352.59)
(-) Contingencies				(1,385,433,988.08)
(-) Environmental Adequacies				(29,581,979.15)
Equity Value				(664,002,019.35)



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Additionally, the projections meet the Efficiency Criteria in relation to Financial
Management considering the period of contractual obligations. In the following table, the
indication “No” indicates the noncompliance with the criteria established under the terms of the
new concession contract.


Table 79 – Financial Covenants


Covenants						2017	2018	2019	2020	2021	2022
EBITDA >= 0						OK	OK	OK	OK	OK	OK
EBITDA - QRR >= 0						OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (0,8 * SELIC)						NO	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (1,1 * SELIC)						NO	OK	OK	OK	OK	OK

Covenants						2023	2024	2025	2026	2027	2028
EBITDA >= 0						OK	OK	OK	OK	OK	OK
EBITDA - QRR >= 0						OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (0,8 * SELIC)						OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (1,1 * SELIC)						OK	OK	OK	OK	OK	OK

Covenants						2029	2030	2031	2032	2033	2034
EBITDA >= 0						OK	OK	OK	OK	OK	OK
EBITDA - QRR >= 0						OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (0,8 * SELIC)						OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (1,1 * SELIC)						OK	OK	OK	OK	OK	OK

Covenants						2035	2036	2037	2038	2039	2040
EBITDA >= 0						OK	OK	OK	OK	OK	OK
EBITDA - QRR >= 0						OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (0,8 * SELIC)						OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (1,1 * SELIC)						OK	OK	OK	OK	OK	OK

Covenants					2041	2042	2043	2044	2045	2046	2047
EBITDA >= 0					OK	OK	OK	OK	OK	OK	OK
EBITDA - QRR >= 0					OK	OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (0,8 * SELIC)					OK	OK	OK	OK	OK	OK	OK
Net Debt / (EBITDA - QRR) <= 1 / (1,1 * SELIC)					OK	OK	OK	OK	OK	OK	OK


6.6.	Sensitivity


The table below presents the results of the sensitivity analysis for the main assumptions.


Table 80 – Sensitivity Analysis


		Demand	PMSO	Losses	CAPEX	WACC	WACC	CAPEX	Losses	PMSO	Demand
		+1 SD	- 5%	- 5%	+ 5%	- 0,5%	+ 0,5%	- 5%	+ 5%	+ 5%	- 1 SD
Demand	+1 SD	2.2%	18.2%	3.4%	2.7%	8.7%	-3.6%	1.8%	-7.3%	-35.7%	0.0%
PMSO	- 5%	18.2%	15.8%	16.9%	16.2%	22.8%	9.4%	15.3%	6.7%	0.0%	13.5%
Losses	- 5%	3.4%	16.9%	1.2%	1.6%	7.6%	-4.7%	0.7%	0.0%	-37.1%	-0.8%
CAPEX	+ 5%	2.7%	16.2%	1.6%	0.4%	6.9%	-5.5%	0.0%	-8.7%	-37.7%	-1.7%
WACC	- 0,5%	8.7%	22.8%	7.6%	6.9%	6.4%	0.0%	5.8%	-3.2%	-34.1%	4.2%
WACC	+ 0,5%	-3.6%	9.4%	-4.7%	-5.5%	0.0%	-5.8%	-6.1%	-14.6%	-41.9%	-7.8%
CAPEX	- 5%	1.8%	15.3%	0.7%	0.0%	5.8%	-6.1%	-0.4%	-9.6%	-38.8%	-2.5%
Losses	+ 5%	-7.3%	6.7%	0.0%	-8.7%	-3.2%	-14.6%	-9.6%	-9.2%	-47.4%	-11.0%
PMSO	+ 5%	-35.7%	0.0%	-37.1%	-37.7%	-34.1%	-41.9%	-38.8%	-47.4%	-38.2%	-40.7%
Demand	- 1 SD	0.0%	13.5%	-0.8%	-1.7%	4.2%	-7.8%	-2.5%	-11.0%	-40.7%	-2.1%

The table shows the variation of the Enterprise Value as follows: (i) when the projected

demand growth increases or decreases by one standard deviation; (ii) when the operational costs
increase or decrease by 5%; (iii) when the energy losses increase or decrease by 5%; (iv) when



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investment (CAPEX) increases or decreases by 5%; and (v) when the discount rate increases or decreases by 0.5%. Except for sensitivity (v), the other assumption changes were considered only in the 10 first years of the new contract. It is important to note that the effects presented above are individually observed and also combined two by two in the sensitivity matrix.

As presented in the sensitivity matrix, the valuation is mainly impacted by the variation of operating costs (“PMSO”) reduction projected for the first concession years, especially in the worst-case scenario.

Variations in the estimated energy losses reduction and in the discount rate also presented significant impact on the result, with quite symmetric effect for discount rate best-case and worst-case scenario, but not symmetric for energy losses reduction, with higher impact in the worst-case scenario.

Market demand and investment (CAPEX) variations presented lower impact on the valuation.


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7. References

[1] “História de Alagoas,” 07 01 2016. [Online]. Available: http://www.historiadealagoas.com.br/historia-da- ceal.html. [Access on 04 05 2017].

[2] Wikipédoa, “Wikipédia - Alagoas,” [Online]. Available: https://pt.wikipedia.org/wiki/Alagoas. [Access on 04 06 2017].

[3] E. D. Alagoas, “Plano Decenal 2016-2025,” 2015.

[4] E. D. Alagoas, “Desestatização das Distribuidoras,” 2016.

[5] K. F. O. &. R. G. Israel, “Why Does Everyone Use the .05 Level of Significance?, Research Quarterly for Exercise and Sport,” 1987.

[6] J. M. WOOLDRIDGE, “Econometric analysis of cross section and panel data. MIT Press.,” 2010.

[7] 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.

[8] PricewaterhouseCoopers, “Electricity Lines Business – ODV Valuation. Study for Unison Networks Limited,” New Zealand, 2005.


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ANNEX I – Extent of Responsibility

This report (the “Report”) was jointly prepared by PricewaterhouseCoopers Corporate Finane & 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 Companhia de Eletricidade de Alagoas (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 Companhia de Eletricidade de Alagoas, companies connected thereto, their shareholders, officers, or other parties, as a consequence of use of the data and information provided by Companhia de Eletricidade de Alagoas, 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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APPENDIX A – Socioeconomic Characterization of the Ceal Concession Area

In order to better characterize the area of activity of Ceal, 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 items that follow, we perform comparative analyses for each information collected from the company in relation to data observed in the North, Northeast regions and the Brazilian 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, Education Level and Unemployment Rates

Table 81 shows, 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 concession area of the distribution company as well as average data for Brazil and the North and Northeast Regions.


	Table 81 – Demographic Information, Education Level and Unemployment Rates
	# of	Area	Population	Density	Nº	%	% Popul. Unemployment
Region	Municipalities				Households Popul. Illiterate			Rate
		(km²)	(Thousand) (Inhab/km²)		(thou)	Rural
ALAGOAS	102	27,882	3,345	120.12	1,051	26%	20%	13%
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 was taken from the PNAD 2015. Number of municipalities and areas were obtained from INPE.
The unemployment rate was obtained in the IPEA / PNAD for the year 2014.

Alagoas is the state with highest population density of the Northeast Region (120.12 inhabitants per km2), with the capital Maceió being the most populous of the state. Its population is mainly concentrated in urban centers (74% of the population), but the state has a considerable percentage of inhabitants in rural areas (26%). Its population suffers from illiteracy, wherein 20% of the total population lacks basic knowledge of reading and writing. In addition, the state of Alagoas leads the ranking of Brazilian states with the highest unemployment rate (13%).

b) Access to Services

Table 82 presents for Ceal, as well as average data for Brazil and the North and Northeast Regions, the percentages of households (i) without garbage collection; (ii) same for point "i" for urban areas; (iii) without water supply through networks; (iv) same for point "iii” for urban areas;


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(v)	without sanitary sewage by networks or septic tank; (vi) same to point "v" for urban areas; and
(vii)	without electricity located in rural areas.


		Table 82 – Information about Access to Services

				% Urb.	%
	%		%	Housesh		% Urban	% Rur.
		% Urb.			Households
Region	Househo	Households	Household	olds		Households
	lds		s Without	without	without	without	Households
	without	without	Supply	Supply	Sewage	Sewage	without
	Col.	Gar. Col.	Water Grids	Water	Networks/Se Networks/Septic		Electricity
	Junk			Networks	ptic Tanks	Tanks
ALAGOAS	16%	1%	25%	18%	45%	36%	0%
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: PNAD 2015.

In Alagoas 16% of the households do not have garbage collection, 25% do not have water supply through networks and 45% do not have access to the sewage network/septic tanks. The percentages of urban households without access to the sewage/septic tanks and without water supply through network are relatively high and higher than the regional and national averages (36% and 18%, respectively for the state). c) Income

Table 83 presents the (i) percentage of households with incomes of up to 2 Minimum Wages (M.W.); (ii) percentage of people living in households with a per capita income below the poverty line⁴³; (iii) average household income per capita and (iv) GDP (Gross Domestic Product) per capita.


		Table 83 – Information about Income
			Average Households
		% Pop. Below
Região	% Households w/ Income		Income per capita	GDP *per*
		Poverty Line
	Up to 2 MW		(R$)	*capita* (R$)
ALAGOAS	64%	31%	592.98	11,277
BRASIL	39%	13%	1,152.24	26,446
NORTH	51%	22%	782.76	17,213
NORTHEAST	58%	20%	730.24	12,955
Sources: Domiciles with income up to 2 M.W. . à PNAD 2015. % Pop. Below Poverty Line and
Average Household Income per capitaàIPEA / PNAD 2014; GDP per capitaàDatasus / IBGE 2013.

Notice that the state presents the highest percentage of population with income below the poverty line in Brazil; as well as the lowest level of income and GDP; below the regional and national averages.

⁴³Equivalent to two times the line of extreme poverty. The Line of Poverty is based on an estimate of the value of a food basket with the minimum calories needed to adequately supply a person based on World Health Organization (WHO) recommendations.


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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 erros

A,A,A: Additive Holt-Winters’ method with additive erros

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 outdated 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, heteroskedasticity, 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

Distributor	Class	Autocorrelation	Heteroscedasticity	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 Entities	0.852	0.086	0.001
	Public Lighting	0.140	0.245	0.001
	Public Service	0.007	0.03	0.000001
	Proper	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 Entities	0.121	0.911	0.224
	Public Lighting	0.999	0.960	0.0000001
	Public Service	0.921	0.345	0.0001
	Proper	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 Entities	0.109	0.344	0.255
	Public Lighting	0.104	0.144	0.3
	Public Service	0.134	0.577	0.007
	Proper	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 Entities	0.503	0.548	0.003
	Public Lighting	0.603	0.997	0.0001
	Public Service	0.467	0.686	0.328
	Proper	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 Entities	0.007	0.361	0.386
	Public Lighting	0.607	0.992	0.00003
	Public Service	0.137	0.850	0.803
	Proper	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 Entities	0.289	0.942	0.00001
	Public Lighting	0.819	0.809	0.152
	Public Service	0.289	0.942	0.00002
	Proper	0.953	0.998	0.000005

		Source: Self prepared.


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Table 91 – Public Entities Class: Ceal


Public Entities		Box & Jenkins			Box & Jenkins
	A R1	0 . 0 6 0 8	0 . 6 2 7	MA 1	-0 . 8 9 0 7	0 . 0 0 0 0
	MA 1	-1	<0 . 0 0 1	SA R1	0 . 5 3 1 2	0 . 0 0 0 0
	SA R1	0 . 9 9 8 8	<0 . 0 0 1	Ju l/1 4	-5 3 9 6 . 0 9 6 3	0 . 0 0 0 0
	SMA 1	-0 . 9 4 9 6	<0 . 0 0 1	ln (GDP)	4 8 5 3 . 9 2 1 7	0 . 2 9 6 4
	Ju l/1 4	-5 3 4 2 . 6 2	<0 . 0 0 1
	ln (Population)	0 . 0 2 7 5	<0 . 0 0 1
	MA PE	4 . 1 6 %		MA PE	-	-
	A u t ocor	Het er oc	Norm	A u t ocor	Het er oc	Norm
	0 . 5 0 3	0 . 5 4 8	0 . 0 0 3	-	-	-

Source: Self Prepared.


Table 92 – Utility Class: Ceal


Public Service		Box & Jenkins
	Constant	-7 6 7 . 6 2 1	<0 . 0 0 1
	A R1	0 . 9 2 0 1	<0 . 0 0 1
	MA 1	-0 . 7 9 0 4	<0 . 0 0 1
	SMA 1	0 . 2 1 7	0 . 0 2 3
	Feb /1 2	2 . 9 6 8 7	<0 . 0 0 1
	Dec/1 3	0 . 1 1 9 8	0 . 7 0 0
	ln (Population)	5 4 . 2 8 0 3	<0 . 0 0 1
	MA PE	3 . 1 0 %
	A u t oc or	H et er oc	Norm
	0 . 4 6 7	0 . 6 8 6	0 . 3 2 8

Source: Self Prepared.

It should be noted that the markets for Public Lighting and Own Consumption classes were projected by univariate models. Therefore, there was no use of auxiliary variables.


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APÊNDICE F – Concepts and Methods of BRR Valuation

In relation to the methods of BRR valuation, there are four main approaches used by the regulators in Brazil and in other countries: (i) the economic or market value; (ii) the replacement cost; (iii) the combination between the economic and replacement methods, resulting in a hybrid approach; and (iv) valuation based on comparison of BRR with similar companies.

Methods Based on the Economic or Market Value

The methods based on the economic value, also called market value, aim at determining the price the investors would be willing to pay for the company or, in other words, the capacity of the company’s assets to generate wealth.

The economic value of the assets may be estimated from three methodologies:

i. Auction Bid: corresponds to the minimum bid value of the sale auction or to the winning bid. Only applicable in the cases where there is a bidding process of sale of the assets, as in the case of privatizations. Its value shall coincide with the net present value of the expected cash flow from the point of view of the winner of the auction or the minimum bidder. This method was used by ARSESP (Regulatory Agency of Sanitation and Energy of the State of São Paulo) in the definition of the value of BRR of COMGÁS (Companhia de Gás de São Paulo) [7]. ii. Net Present Value (VPL): defined as the sum of the present values of the estimated flows of expenses, taxes, investments, and revenues of the company, calculated with a discount rate (Weighted Average Cost of Capital - WACC). Its preparation requires several assumptions to the projections of the different components of costs and expenses of the regulated company. iii. Share Value: it consists of the value estimated by the quotation of the company’s shares negotiated on a stock exchange. Although it is a simple parameter, it only represents part of the company’s value: the business value under the point of view of the shareholder. Therefore, it excludes the debt value, which is added in separately. This method was used by the electric power and channeled gas and sanitation Regulators of the United Kingdom, OFGEM (Office of Gas and Electricity Markets) and OFWAT (Water Services Regulation Authority), respectively.

Methods Based on the Replacement Cost

The replacement cost method is focused on the physical, taking into account the valuation of existing assets or the design of the optimum configuration of the infrastructure. Therefore, these methods are different from the economic value, which focuses on the value itself.

There are four main methodologies to estimate the replacement cost:

i. Historical Corrected Costs (Current Cost Valuation - CCV): it involves the adoption of the original acquisition price (from the accounting records), depreciated based on the service life and updated by monetary indicator (sector or general). The


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updating of the book value is required when, as occurs in Brazil, the accounting standards do not allow the indexation of the acquisition value of fixed assets. This method is adopted in the regulation of sanitation in Colombia and of Melbourne Water in Australia. It is also used in the regulation of the services of electric power distribution and transmission in Norway and The Netherlands. In the Netherlands, this method is also applied to the regulation of natural gas. ii. Depreciated Replacement Cost (DRC): consists of the cost of replacing each asset with a new one that performs the same services and that has the same capacity as the existing asset, replacing it in identical conditions—that is, without considering technological innovations. Additionally, the depreciation is discounted, representing a deduction for the physical deterioration of the asset and its obsolescence. This method is used in the regulation of some sanitation companies of Australia such as the South East Queensland Water and Hobart Water. iii. Depreciated Optimized Replacement Cost (DORC): this measures the current cost of replacing each asset, taking into account the remaining service life and the best technological and economical options existing. It involves the adaptation of the assets to the demand (such as, for example, using use indexes), the revaluation of the assets to the price of new and the consideration of their accumulated depreciation according to the service life elapsed. Such method is used by ARSESP in the regulation of sanitation to SABESP (Companhia de Saneamento Básico do Estado de São Paulo) and by ANEEL in the electric power distribution [7]. iv. New Replacement Cost - VNR (Gross Optimized Replacement Cost -GORC): this is the result of an optimization process of bottom-up engineering and economic parameters. It does not take into consideration the age of the assets, but simulates the assets that would be operated by a new hypothetical and efficient provider, with current costs and technologies. This method, also called Reference Company, is applied in Chile, either in the regulation of electric power distribution or sanitation. It was also applied by ADASA (Agência Reguladora de Águas, Energia e Saneamento do Distrito Federal - Regulatory Agency of Water, Energy, and Sanitation of Distrito Federal) in the regulation of the sanitation services provided by CAESB (Companhia de Saneamento Ambiental do Distrito Federal). In the case of CAESB, the Regulator aimed at respecting the technological history of the investments made [7].

Hybrid Methods

The hybrid methods correspond to combinations between the methods of economic value and replacement cost. Their use has combined pros and cons of both methods. There are two main approaches: i. Optimized Deprival Value (ODV): this consists of the lowest value between the economic value and the replacement cost. Such method is used by the Commerce Commission in regulation of the services of electric power distribution and transmission in New Zealand [8].


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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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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: CEAL 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 CEAL's evaluation, in accordance with the Agreement, and was based on information provided by CEAL'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		19
2.4.	Operating Indicators		25
2.5.	Energy Purchase and Sale Indicators		34
2.6.	Asset Conditions		38
2.7.	Critical points observed during the field visit and challenges for new utilities		38
2.7.1.	High-voltage distribution system and substations		38
2.7.2.	Medium and low voltage distribution system		39
3. Five-Year Investment Plan ("PIQ")			39
4. References			43
APPENDIX A - Socioeconomic Characterization of the Concession Area			44
APPENDIX B - Consumer Market			48
APPENDIX C - Response to Emergencies			49



Figures
Figure 1 - State of Alagoas (capital highlighted)			9
Figure 2 - Federal and State Highways of Alagoas			12
Figure 3 - Cumulative total precipitation for the Brazilian states.			15
Figure 4 - Average temperatures observed for the Brazilian states			15
Figure 5 - National Interconnected System			17
Figure 6 - Basic Grid of the state of Alagoas			17
Figure 7 - Electrical regions of the state of Alagoas			18
Figure 8 - Map of Alagoas' Transmission and Distribution system.			19
Figure 9 - Rate Groups and Categories			48

Graphs
Graph 1 - Total Road Density (km/km²)			11
Graph 2 - Percentage of Existing and Planned Roads in 2015			12
Graph 3 - DEC Determined Indicator and Limits			27
Graph 4 - FEC Determined Indicator and Limits			27
Graph 5 - Number of Sets that violated their 2016 limits and UC Representation			28
Graph 6 - Histogram of Ceal's sets: 2016 DEC			28

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Graph 7 - Histogram of Ceal's NUC: 2016 DEC		29
Graph 8 - Histogram of Ceal's sets: 2016 FEC		29
Graph 9 - Histogram of Ceal's NUC: 2016 FEC		29
Graph 10 - Evolution of the product quality indicator (DRCE)		30
Graph 11 - Evolution of the product quality indicator (DRPE)		31
Graph 12 - Regulatory Technical Losses for Injected Energy		33
Graph 13 - Comparison between Non-Technical Real and Regulatory Losses for the BT Market		34
Graph 14 - Evolution of Base Energy, Bilateral and CCEAR and the percentage of Required Energy recognized by the Energy
Rate		37
Graph 15 - Mean Times of Response to Emergencies		49
Graph 16 - Evolution of the Number of Emergency Events with Electric Power Outage Versus the Total		50



Tables
Table 1 - Five-year Investment Plan - Base Scenario		7
Table 2 - Five-year Investment Plan - Alternative Scenario		7
Table 3 - Alagoas Road Indicators		13
Table 4 - Climatic Characteristics of Ceal's Concession Area		14
Table 5 - Evolution of the Number of Consumers by Voltage Level		20
Table 6 - Market Evolution by Voltage Level		21
Table 7 - Evolution of Revenue by Voltage Level		21
Table 8 - Evolution of NUC by Rate Class		22
Table 9 - Market Evolution by Rate Class		22
Table 10 - Evolution of the Average Market by Rate Class		23
Table 11 - Revenue Evolution by Rate Class		23
Table 12 - Number of Consumers, Market and Revenue by Voltage Level		24
Table 13 - Number of Consumers and Revenue by Rate Class		24
Table 14 - Compensations for Breach of Quality of Service Indicators		26
Table 15 - Compensations for Breach of Product Quality Indicators		31
Table 16 - Results of Regulated Required Energy (MWh) from 2012 to 2016.		36
Table 17 - Results of Contracted Energy (MWh) from 2012 to 2016		36
Table 18 - Investments in progress in the year 2017 by Type of Project		40
Table 19 - Base Scenario: PIQ (Detailed Resources by Type of Project)		41
Table 20 - List of SEs and LDs with investments anticipated from 2025/2024/2023 to 2022 for the Five-Year Plan		42
Table 21 - Alternative Scenario: PIQ (Detailed Resources by Type of Project)		42
Table 22 - Demographic Information, Level of Education and Unemployment Rates		44
Table 23 - Service Access Information		45
Table 24 - Income Information		45

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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 Companhia de Eletricidade do Alagoas" (hereinafter referred to as Ceal 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.

Ceal's concession area, located in the state of Alagoas, in the northeastern region of Brazil, has 27,848 km², making it the second smallest federal unit in Brazil. It borders three federative units, namely: Pernambuco to the north, Sergipe to the south, and Bahia to the southwest. The state has about 3.3 million inhabitants, with a third of the population in the capital Maceió. Alagoas is the state with the lowest human development index in the country, and the highest illiteracy rate. 36% of its urban households have no access to the sewage network and 18% have no access to water by networks. It also features the highest number of deaths due to aggression for every 100 thousand inhabitants of Brazil.

The dominant climates of the region are the semi-arid and tropical humid, due to its position between the tropics and proximity to the sea. While at the Alagoas's East rains are more regular, in the backlands the rainfall index is low, making the region very dry. The average temperature range of Alagoas is around 6 ºC with temperatures between 21 ºC and 27 ºC.

The total of paved roads represents only 18% of the state's highways roads, although Alagoas shows the second largest density of roads in the Northeast of Brazil, with 540 meters of road per square kilometer. About 99% of municipal roads are unpaved, making it difficult to commute within municipal boundaries and between cities.

Regarding the consumer market, Ceal has its market represented by consumers allocated at the High, Medium and Low Voltage levels, the latter being more expressive with respect to the number of consumers (99.8%), market (57.3%) and revenue (65.4%), according to 2016 data. The MT market represents about ¾ of the distributor's consumption and revenue. AT's share is around 10% of the Company's market and revenue. The other types of users are not very representative, both in terms of market and revenue.

By evaluating operational indicators of service delivery, we identified that the company presented a violation of the regulatory limits for the collective indicators of continuity ("DEC" and "FEC") in the period between 2012 and 2016, despite the fact that DEC showed an improvement trend. The indicators assessed in 2016 surpassed the year target by a little less than 50%. We consider the average total time of fulfillment of emergencies to be reasonably high, at around 3.8 hours.


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Regarding losses, the level observed at Ceal is considered high, especially with respect to the commercial aspect of losses. The level of real Non-Technical Losses ("PNT") is well above the regulatory target, higher than 41% of what is billed from the Company's entire low voltage grid.

Regarding the distributor's electrical system, we observed 69 kV lines and towers in good condition, but located on sugarcane fields and susceptible to fires. The situation of substations, in spite of being automated, is critical regarding the state of preservation and maintenance of the assets, requiring investments in circuit breakers and SE retrofitting. In general, medium and low voltage grids have good structural and preservation conditions.

For correcting Ceal's operating conditions, while observing 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, investments related to the expansion and strengthening of the company's distribution system, as well as resources needed to complete the Programa Luz Para Todos ("PLPT") program.

The main sources of information for the PIQ are the "Electricity System Expansion Plan (2016-2025 horizon)", the "Distribution Development Plan ("PDD") for the year 2017" (although provisional¹), the "2015 Results Plan for Improvement of the Distribution Services" and the "2017 Plan for Temporary Rendering of the Electricity Distribution Service", all of which were prepared by Ceal, among other bibliographic references listed in Chapter 3 - Five-Year Investment Plan ("PIQ").

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 in 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. BRL 796.96 million in investments are needed in the next five (5) years (according to the Base Scenario) or BRL 825.92 million (according to the Alternative Scenario), and the need for the year 2018 is significant, which concentrates BRL 343.67 million.

¹At the time of drafting this report, the 2017 PDD had not yet been delivered to ANEEL.

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 343,674,065	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 103,499,109	BRL 796,955,847

Total
Own	BRL 336,474,292	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 103,499,109	BRL 789,756,074
Resources*


Table 2 - Five-year Investment Plan - Alternative Scenario


						Total Period
Year	2018	2019	2020	2021	2022

Total	BRL 343,674,065	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 132,461,970	BRL 825,918,708

Total
Own	BRL 336,474,292	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 132,461,970	BRL 818,718,935
Resources*
** For the total Own Resources, the subsidies related to the works linked to the Programa Luz para Todos ("PLpT") program (70%) were
deducted from the total investments.

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 Ceal'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).

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.


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2.1. Characterization of the company's area of activity

2.1.1. Brief History

The history of electricity in Alagoas began in its capital, Maceió. This Capital was the pioneer among the Brazilian capitals to receive electricity, and services begun in 1897. The responsibility for energy supply was on Empresa Luz Elétrica de Alagoas, which used a steam engine with three boilers of 75 horsepower each [1].

In 1913, Nova Empresa de Luz Elétrica (“NELE”) took over the electric power supply in the capital, owned by Commander Teixeira Bastos, which later became Companhia Força e Luz de Maceió.

There was a new name change in 1931, when "Amford" acquired the company and adopted the name Companhia Força e Luz do Brasil - Maceió [1].

In 1959, under the government of Muniz Falcão, Alagoas took the first steps in its planning policies. For the energy sector, the Alagoas Electrification Plan began. To make the execution of this Plan feasible, the Alagoas government created a mixed economy company, Companhia de Eletricidade de Alagoas (Ceal), linked to the Department of Water and Energy.

In 1983, by virtue of Law #4,450, Companhia de Eletricidade de Alagoas was renamed Companhia Energética de Alagoas, maintaining the acronym Ceal. The same law allowed the company to produce and distribute energy in Alagoas.

Ceal remained under the control of the state until June 1997, when the federalization process began with the purchase of 50% of the shares by Centrais Elétricas Brasileiras S.A. (Eletrobras), which became the controlling shareholder of the company.

In June 2008, a new management model for Eletrobras' Distribution Companies was established, establishing a single, integrated management, seeking to unify procedures, bring employees of different cultures closer together and to strengthen the trust of clients served in different regions. As a holding company, Centrais Elétricas Brasileiras S.A. (Eletrobras) controls a large part of Brazil's electricity generation and transmission systems and operates in the distribution area through the companies Eletrobras Amazonas Energia, Eletrobras Distribuição Acre, Eletrobras Distribuição Roraima, Eletrobras Distribuição Rondônia, Eletrobras Distribuição Piauí and Eletrobras Distribuição Alagoas [2].

Currently, Eletrobras holding holds 100% of shares of the Alagoas utility on behalf of the Federal Government. In October 2010, Eletrobras' new brand was standardized for all companies of the System, including the former Ceal, which became known as Eletrobras Distribuição Alagoas.

Finally, in July 2016, the Eletrobras group decided against renewing the concessions of electric power distributors in the North and Northeast regions under its control, including Ceal. On August 3, 2016, through Ordinance #424/2016, the MME has designated Ceal as responsible for providing the public electricity distribution service with a view to ensuring continuity of service until December 31, 2017 or until the assumption by a new utility, whichever occurs first.


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Table 3 - Alagoas Road Indicators

			Weight/Participation
Type	Roads	Extension (km)	(%)
	Federal	822.0	6.26%
	State	2,409.5	18.35%
Existing Total
	Municipal	9,896.6	75.38%
	Total Roads	13,128.1	100.0%
	Federal	768.6	32.24%
	State	1,565.7	65.68%
Paved
	Municipal	49.2	2.06%
	Subtotal Paved	2,383.5	18.16%
	Federal	53.4	0.49%
	State	843.8	7.85%
Unpaved	Municipal	9,847.4	91.95%
	Subtotal Unpaved	10,744.6	81.84%
Source: DNIT, 2015.

As shown, the state has a total of 13,128 km of roads. Federal highways are the least representative (only 6% of the total), while state highways contribute 18% to the state's highway universe. Of the total number of existing roads in Alagoas, 82% are unpaved (9,847.4 km) and, consequently, the total paved grid extension is not very significant when compared to the total (only 21%, 2,383 km).

Also noteworthy is the fact that that almost 9,800 km of municipal roads are unpaved, accounting for 92% of all municipal roads. This finding directly influences the commute between the seat of the municipality and surrounding areas, since these roads tend to become precarious in case of rains, where dirt roads generate mud and dirt that can bog down the cars of teams that are on duty to respond to emergencies.

It should be noted that, among the paved roads, the majority are under state administration (more than 1,500 km or 65% of the total paved roads). The vast majority of federal roads are paved (768 km out of a total of 822 km).

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 of vehicles.

Considering all facts exposed in this section, we conclude that the state of Alagoas has a high road density, despite the fact that its highways are in a poor situation (only 21% of the total state roads are paved, the majority of which are state roads). Most of the unpaved roads of the state are under municipal administration (92%).


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2.1.5. Climate Characterization

The climatic characterization of the state of Alagoas, comparing it with other regions of the country, is of extreme importance in order to verify the particularities of the region.

The dominant climates are the semi-arid and tropical humid, due to the state's position between the tropics and proximity to the sea. While in Alagoas' East rains are more regular, in the backlands the rainfall index is low, making the region very dry. Because of its location, the average temperature range in Alagoas is around 6 ºC, with temperatures between 21 ºC and 27 ºC.

Table 4 contains basic information¹⁰for the climatic characterization of Ceal's concession area.


		Table 4 - Climatic Characteristics of Ceal's Concession Area
		Climatic Characteristics for Roraima and Regions
		Rainfall		Rain	Keraunic	Maximum	Maximum Wind
	Region	indexⁱ(mm)	Intensity ⁱⁱ		Index ⁱⁱⁱ	Temperature	Speed ^v
			(mm/day)		(lightnings/km²)	^iv(°C)	(mps)
Alagoas		61.58		5.43	0.81	28.46	5.08
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.			iv = Maximum average temperature recorded.
v = Average maximum speed recorded.

The state shows a rainfall index below the national and the North Region averages and slightly above the Northeast Region average. The same is true for rainfall intensity, which is approximately 53% below the national average. The region's winds are slightly below the Northeast Region average. The state is the one that also shows the lowest keraunic index of Brazil.

Figure 3 shows the total accumulated precipitation volume (in millimeters) observed for all states of Brazil in the years 2015 and 2016.

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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Considering all the exposed facts, we identify in Ceal's concession area a low lightning index, low rainfall index and rainfall intensity, and extensive road mileage. Since most of the municipal roads are unpaved, in the event of inclement weather, this issue may compromise the Distributor's DEC and FEC quality indicators ¹³.

2.2. Geoelectric Characterization of the Concession

The state of Alagoas is served by the National Interconnected System (SIN) through hydroelectric power plants owned by CHESF, from the Paulo Afonso complex and Xingó, from which 230 kV and 500 kV transmission lines supply the entire state of Alagoas, as well as other states in the Northeast Region.

This section shall address information about the level of interconnection to the SIN of the state of Alagoas, as well as characteristics of the High (AT), Medium (MT) and Low Voltage (BT) distribution systems.

2.2.1. SIN Interconnection Level

The transmission system in Brazil has an importance and a role that goes beyond the classic function of "just" bringing power from the generating centers to the consumption centers. Due to the characteristics of the Brazilian electrical system - notably the power generation base of a hydroelectric source - and the great territorial extension of the country, the transmission system in Brazil also functions as a "virtual energy source", that is, it is operated in order to allow exploitation of the diversity and use of existing energy sources between the subsystems (North, Northeast, Southeast/Center-West and South), through the SIN.

Figure 5 illustrates the situation in June 2016 of the level of interconnection - current and future -of national transmission lines. As noted on the map, the Distributor's area of activity is already interconnected to the National Interconnected System. The state of Alagoas is served through hydroelectric power plants, owned by CHESF and the Paulo Afonso complex and Xingó, from which 230 kV and 500 kV transmission lines supply the entire state, as well as the entire Northeast Region.

¹³Equivalent Duration of Downtime per Consumer Unit ("DEC"); Equivalent Frequency of Downtime per Consumer Unit ("FEC")


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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 2013 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.)¹⁵
A3	-	16	15	17	17	6%	2%
A4	-	2,086	2,101	2,113	2,102	1%	0%
BT	-	950,753	996,650	1,033,434	1,099,791	16%	5%
TOTAL	928,590	952,855	998,766	1,035,564	1,101,910	16%	5%
Source: ANEEL, rate activity approved between 2012 and 2016, commonly processed in August of each year. In general, NUC relates
to the month of June/July 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.

High Voltage Subgroup A3 shows an increase of only 1 user in four years. A similar conclusion can be observed in the A4 subgroup, with only a 1% increase in customers for the analyzed period. On the other hand, the BT (Low Voltage) subgroup showed the highest growth, with a 16% rate for the period.

Table 2 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.

¹⁵p.a. = per annum.


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Table 6 - Market Evolution by Voltage Level

		Market by Voltage Level (MWh)				Rate of Change
Voltage/Year	2012	2013	2014	2015	2016	Per.%	Geo.%
						(2012/16)	(p.a.)
PROVISION	2,835,550	3,144,209	3,283,014	3,389,576	3,299,290	16%	4%
A3	358,232	458,531	409,962	409,026	417,090	16%	4%
A4	838,255	880,332	895,395	906,768	888,530	6%	1%
BT	1,639,062	1,805,345	1,977,657	2,073,782	1,993,670	22%	5%
LOW INCOME	-	261,853	309,028	311,097	227,525	-	-
SUPPLY	-	-	-	-	-	-	-
OTHER FREE CONSUMERS	99,918	148,363	195,982	195,132	159,001	59%	12%
DISTRIBUTION	17,595	18,942	19,317	20,233	20,221	15%	4%
TOTAL	2,953,063	3,311,514	3,498,314	3,604,942	3,478,512	18%	4%
Source: ANEEL, rate activity approved between 2012 and 2016, commonly processed in August 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 billed market, with an average growth rate of 4% p.a. The class of free consumers was the one with the highest growth in the considered period, namely, 12% p.a, while the MT class was the one with the lowest growth, with an average rate of 1% p.a.

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 subgroup A3, with an average growth of 12% p.a., followed by subgroup A4, with an average growth of 11% p.a. (the same as the Company's revenue as a whole).


Table 7 - Evolution of Revenue by Voltage Level

	Revenue by Voltage Level (BRL Million)					Rate of Change
						Period %	Geo. %
Voltage/Year	2012	2013	2014	2015	2016
						(2012/2016)	(p.a.)
PROVISION	780	765	803	1,060	1,165	49%	11%
A3	66	71	58	83	105	59%	12%
A4	187	174	196	256	287	54%	11%
BT	527	519	548	720	773	47%	10%
SUPPLY	-	-	-	-	-	-	-
OTHER FREE
CONSUMERS	10	10	7	8	8	-16%	-4%
DISTRIBUTION	1	1	0.8	0.8	0.8	-52%	-17%
GENERATOR	3	4	5	6	6	81%	16%
TOTAL	796	782	817	1,076	1,181	48%	10%
Source: ANEEL, rate activity approved between 2012 and 2016, commonly processed in August 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 "Rural" class, with an increase of 6% p.a.. The "Other" class had a 27% p.a drop.


		Table 8 - Evolution of NUC by Rate Class
		NUC by Rate Class				Rate of Change
						Period %	Geometric
Class/Year	2012	2013	2014	2015	2016
						(2012/2016)	% (p.a.)
Residential	851,711	873,756	917,293	950,719	1,012,875	19%	4%
Industrial	2,678	2,667	2,648	2,563	2,658	-1%	0%
Commercial	54,532	56,331	58,268	60,065	63,749	17%	4%
Rural	9,978	10,316	10,438	11,919	12,362	24%	6%
Street Lighting	173	194	197	205	202	17%	4%
Public Power	8,006	8,342	8,644	8,771	8,639	8%	2%
Public Service	1,096	1,092	1,165	1,221	1,310	20%	5%
Other	416	157	113	101	115	-72%	-27%
TOTAL	928,590	952,855	998,766	1,035,564	1,101,910	19%	4%
Source: ANEEL, rate activity approved between 2012 and 2016, commonly processed in August of each year. In general, NUC relates to
the month of June/July of each year.

Table 9 shows the evolution of the Ceal Market by class. The "Rural" class showed the highest growth in energy consumption in the period considered, namely, 263%, followed by "Street Lighting", with a 51% growth and "Industrial", with a 38% increase. Only the "Other" class suffered a reduction in consumption (34% p.a.).


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	1,047,431	1,162,883	1,276,544	1,352,582	1,290,350	23%	5%
Industrial	510,297	718,659	758,597	760,059	702,050	38%	8%
Commercial	587,895	653,809	720,610	748,806	724,366	23%	5%
Rural	47,134	237,414	187,711	167,720	171,114	263%	38%
Street Lighting	138,079	173,518	203,100	201,236	208,426	51%	11%
Public Power	134,783	143,682	148,143	159,674	158,076	17%	4%
Public Service	180,670	181,253	180,568	191,302	200,677	11%	3%
Other	126,361	40,296	23,041	23,564	23,453	-81%	-34%
TOTAL	2,772,650	3,311,514	3,498,314	3,604,942	3,478,512	25%	6%
Source: ANEEL, rate activity approved between 2012 and 2016, commonly processed in August 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.
*Values for the year 2012 were taken from Technical Note #286/2012-SRE ANEEL. These are not in agreement with the market by voltage
level.


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The average monthly consumption information by rate class is shown in Table 10. As shown, the "Rural" class had the highest increase in average consumption (31% p.a.), while the "Public Service" and "Other" classes showed a 2% p.a. and 9% p.a. decline, respectively. Data for the company as a whole are in line with the finding of a certain stagnation in the company's market.


Table 10 - Evolution of the Average Market by Rate Class

	Average Monthly Consumption by Class (kWh)					Rate of Change
						Period %	Geometric
Class/Year	2012	2013	2014	2015	2016
						(2012/2016)	% (p.a.)
Residential	102	111	116	119	106	4%	1%
Industrial	15,879	22,455	23,873	24,713	22,011	39%	9%
Commercial	898	967	1,031	1,039	947	5%	1%
Rural	394	1,918	1,499	1,173	1,153	193%	31%
Street Lighting	66,512	74,535	85,914	81,803	85,984	29%	7%
Public Power	1,403	1,435	1,428	1,517	1,525	9%	2%
Public Service	13,737	13,832	12,916	13,056	12,766	-7%	-2%
Other	25,313	21,388	16,992	19,442	16,995	-33%	-9%
TOTAL	249	290	292	290	263	6%	1%
Source: ANEEL, rate activity approved between 2012 and 2016.

Table 11 shows the evolution of Ceal's revenue by rate class. It should be noted that there is no public data approved by ANEEL for the year 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 "Public Service" class was the one with the highest revenue growth, which was 16% 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	-	352	371	491	525	49%	11%
Industrial	-	114	109	147	164	43%	9%
Commercial	-	165	184	240	263	59%	12%
Rural	-	39	34	41	48	22%	5%
Street Lighting	-	26	31	40	46	74%	15%
Public Power	-	38	39	53	59	56%	12%
Public Service	-	35	38	53	64	83%	16%
Other	-	9	7	8	8	-13%	-3%
TOTAL	796	782	817	1,076	1,181	51%	11%
Source: ANEEL, rate activity approved between 2012 and 2016, commonly processed in August 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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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 September 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
					Revenue (BRL
Ceal	NUC		Market (MWh)
					Million)
A3	17	0.0%	417,090	11.9%	105.0	8.8%
A4	1,853	0.2%	888,530	25.5%	287.4	24.2%
BT	1,099,791	99.8%	1,993,670	57.3%	773.5	65.4%
Other Free
Consumers	34	0.0%	159,001	4.6%	8.7	0.7%
Distribution	72	0.0%	20,221	0.6%	0.85	0.0%
Generator	87	0.0%	-	-	6.2	0.5%
Total	1,101,910	100%	3,478,512	100%	1,181.5	100%
Source: ANEEL, 2016 IRT.

As shown, BT has a greater weight of consumers (99.8%), market (57.3%) and also revenue (65.4%) compared to other voltage levels. The MT market represents about ¾ of the distributor's consumption and revenue. AT's share is around 10% of the Company's market and revenue. The other types of users are not very representative, both in terms of market and revenue.

Analyzing the number of users and the revenue by consumption class (Table 13), we observe that Residential revenues have greater weight for the company in relation to the number of consumers, market and revenue, namely, 92%, 37% and 44%, respectively. The commercial class represents about 22% of the company's market and revenue.


	Table 13 - Number of Consumers and Revenue by Rate Class
Class	Consumers		Market (MWh)		Revenue (BRL million)
Residential	1,012,875	92%	1,290,350	37%	525	44%
Industrial	2,658	0%	702,050	20%	164	14%
Commercial	63,749	6%	724,366	21%	264	22%
Rural	12,362	1%	171,114	5%	49	4%
Street Lighting	202	0%	208,426	6%	47	4%
Public Power	8,639	1%	158,076	5%	59	5%
Public Service	1,310	0%	200,677	6%	65	5%
Other Classes	115	0%	23,453	1%	8	1%
TOTAL	1,101,910	100%	3,478,512	100%	1,182	100%
Source: ANEEL, 2016 IRT.


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In view of the above, the main conclusions of Ceal's consumer market by voltage level are: (i) MT represents 0.19% of consumers, 26% of the market and 24% of the company's revenue in 2016; (ii) BT represents 99.8% of consumers, 57% of the market and 65% of the company's revenue in 2016 and, in the analyzed period from 2012 to 2016, showed annual growth rates of 5%, 5% and of 10% for NUC, the market and the revenue, respectively; (iii) the "Low Income" market associated with the BT voltage level had its highest value verified in 2015, showing an expressive 27% drop in 2016; and (iv) free consumers had the highest percentage increase in consumption in the last five years, namely, 59% in the period (12% p.a.), although they had very little relevance in the distributor's income.

From the point of view of the rate classes, for the same information, it can be deduced that: (i) the residential class represents 92% of the NUC and 37% of the 2016 company market with annual growth of 4% and 5% respectively; and (ii) although the rural and street lighting classes are the ones with the highest percentages of market growth for the analyzed period, on the revenue side we see that the highest percentage growth is in the public service and street lighting classes, 83% and 74%, respectively, in the period from 2013 to 2016.

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 energy 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.


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Table 14 shows the evolution of the compensation paid by Ceal over the period (2012-2016) by violating quality of service indicators, 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.


Table 14 - Compensations for Breach of Quality of Service Indicators

			Ceal
Item	2012	2013	2014	2015	2016
Quantity (#)	2,003,125	2,370,552	3,586,655	3,171,740	1,898,728
Compensation Amounts (BRL)	4,769,920	5,576,104	7,737,666	8,482,580	4,177,455
Installment B (BRL)	248,978,654	301,465,771	339,718,638	374,082,340	390,492,886
%Comp./Installment B	1.91%	1.85%	2.28%	2.27%	0.98%
Source: ANEEL website.

The Distributor has increased compensation levels over the years (except for the year 2016 as previously explained). As an example, the total compensations paid in 2015 corresponded to 2.27% of the company's installment B, according to IRT data for this year.

From the sums of the determined amounts for the individual DIC and FIC indicators, we obtain collective indicators that reflect the continuity of the service provided, both at the level of groups of consumer units and at the company level, namely: DEC (Equivalent Duration of Downtime per Consumer Unit) and FEC (Equivalent Frequency of Downtime per Consumer Unit).

The graphs below (Graph 3 and Graph 4) show, for the Distributor, the evolution of the determined DEC and FEC indicators and the regulatory limits approved for the period 2012 to 2016. In addition, for the year 2017, the limit of internal collective DECi and FECi indicators (which disregard downtime originated outside the distribution system) is demonstrated, as set forth in Normative Resolution #748/16, of November 29, 2016. We identified that the company presented a violation of the regulatory limits for the collective indicators (DEC and FEC) in the period under study, despite the fact that DEC showed an improvement trend. It is worth noting that the indicators assessed in 2016 surpassed the year target by a little less than 50%.


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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)¹⁷.

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 Concessions 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. Holders of quotas of the plant's energy are only distributors located in the South and Southeast/Center-West subsystems, which compulsorily acquire the electricity generated by Itaipu. That is, they do not include distributors located in the North and Northeast subsystems.

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 an utility with market under 500 GWh/year and its current supply agent.

¹⁷If 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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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 Ceal's Required Energy (MWh) and Contracted Energy (MWh) for the years 2012 to 2016 is shown on tables 16 and 17.


Table 16 - Results of Regulated Required Energy (MWh) from 2012 to 2016.


		2012	2013		2014	2015	2016

a T + Required Supply + Energy Losses) (Provision		3,540,046		3,903,972	4,174,513	4,287,428	4,158,457
b
l	Provision + Supply	2,835,550		3,144,209	3,283,014	3,389,576	3,299,290
	Provision			3,144,209	3,283,014	3,389,576	3,299,290
e		2,835,550
	Supply (TE Market)			0	0	0	0
1	Regulatory Losses	704,496		759,764	891,499	897,853	859,167
7	Non-Technical Loss	325,190		338,794	350,639	346,322	312,408
	Technical Loss	301,408		420,970	443,879	455,678	437,186
-	Basic Grid Loss on Dist	77,898		0	18,897	18,340	20,286
	Basic Grid Loss on		0	0	78,084	77,513	89,287
R _Captivemarket
e
sults of Contracted Energy (MWh) from 2012 to 2016.

			2012	2013	2014	2015	2016
	Contracted Energy (Base + Bilateral +		4,798,862	4,951,560	4,828,665	5,309,726	5,236,345
	CCEAR)
	Base Energy		0	1,634,641	1,650,976	1,966,275	1,809,482
	Own Generation		0	0	0	0	0
	Angra I/Angra II Quota		0	128,674	128,674	128,499	125,501
	Quotas Law #12783/2013		0	1,430,313	1,441,550	1,755,906	1,599,948
	Itaipu (deducting losses)		0		0	0	0
	PROINFA		0	75,654	80,752	81,871	84,034
	Bilateral		0	0	0	0	0
	CCEAR		4,798,862	3,316,919	3,177,689	3,343,451	3,426,863
Source: ANEEL.

From the point of view of Required Energy, we observe that the total energy showed a small growth, remaining at a level of 4 TWh/year, as well as Provision, which remained at 3 TWh/year. Regulatory losses showed a slightly increasing trend between 2012 and 2015 (0.15 TWh increase).

Regarding Contracted Energy, its oscillating trajectory is due to CCEAR energies (this contract accumulates a decrease of 1.3 TWh in 5 years), and the increase in the Base Energy (1.8 TWh increase over the period).

Graph 14 presents the evolution for the years 2012 to 2016 of the following information: (i) Contracted energy in TWh subdivided by the Base, Bilateral and CCEAR contracts; (ii) curve with the percentages of coverage by the rate of the energy contracts that the distributor made during the analyzed period; and (iii) difference between Contracted Energy and the regulatory Required Energy in TWh.


PwC \| Loeser e Portela Advogados \| Siglasul	Prepared for BNDES	36

2.6. Asset Conditions

Between 4/3/2017 and 4/7/2017, a field visit was carried out at Ceal'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.

Sixteen 69 kV substations were visited, which belong to 5 of the company's 6 regions, and its respective most critical feeders (MT/BT). In general, we verified an adequate preservation within the boundaries of the traces of MT/BT transmission lines and grids. From the inspected sample, problems of maintenance and preservation of substations were observed, as well as pruning needs at MT/BT grids. There were no problems accessing the observed substations and stretches of MT/BT grids.

2.7. Critical points observed during the field visit and challenges for new utilities

The following is a summary of the main critical points observed during the field visit conducted between 4/3/2017 and 4/7/2017 and the resulting challenges for new utilities from the point of view of the need for specific investments in the Company's distribution system, which should be included in the Five-Year Investment Plan (PIQ), which will be summarized in Chapter 3.

2.7.1. High-voltage distribution system and substations

For the 69 kV lines, towers were observed to be in good condition. However, special attention must be paid to these structures since most of the stretches are on sugarcane fields, which are susceptible to possible fires, and are located fairly far from highways.

Sixteen of a total of 39 of the Distributor's 69/13.8 kV substations were inspected. All SEs are automated. However, only three (3) are in good condition with regard to switchings having clean contacts, transformers without leaks, preserved supporting structures, absence of vegetation in the graveled area and a lack of disjunction at the 69 kV terminals. In the state's rural substations, the maintenance situation is critical.

The average age of the 69/13.8 kV power transformers is 19.9 years, and many were identified having leaks and without an insulating oil collection system.


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As for the loading, 12 power transformers had loads equal to or greater than 100%. This high loading situation is aggravated during the carnival period, when the load at Barra de São Miguel (the main resort city of the state) can reach 200%. Of the 32 power transformers inspected, only 6 were switched under load, and even those had their automatic device deactivated. Four SEs had a voltage regulator bank, evidencing voltage regulation problems throughout their grid.

The average age of the 69 kV and 13.8 kV circuit breakers is 22.82 years, and not all circuit breakers had their ages calculated, since some of the nameplate data was unreadable or there was simply no nameplate. In any case, all showed aspects of old age, which indicates that their average age can be greater than the calculated.

In order to consider investments for the necessary improvements to match what was verified in the field visits to the AT system, the PIQ includes installation of circuit breakers in 15 of the 69 kV SE line terminals and retrofitting in 20 SEs that have already exceeded their service life for the year 2018, plus an additional amount for the years 2019 to 2022.

2.7.2. Medium and low voltage distribution system

The MT grid is 22,755 km long and has, as of 2016, 240 voltage regulator banks, 338 reclosers and 90 capacitor banks. The low voltage grid totals 18,219 km.

In general, in urban areas, we observed a medium and low voltage grid in good preservation conditions and leveled by using grid spacers and with adequate structures near the beach region. Some sections of the 13.8 kV grid are compact and the low voltage grid is, for the most part, bare cable.

Rural medium voltage grids cut through extensive sugarcane fields, which are liable for fires and downtimes due to objects that are foreign to the grid (vegetation from Alagoas' backlands). It should be noted that, for almost three years, Distributor has not satisfactorily carried out tree pruning service, and require better maintenance management (which are funds from operating costs, "OPEX").

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 to 2022 horizon - for Ceal's electric energy distribution concession area, with reference to the projects planned as necessary to meet the demand for new connections (within the scope of the vegetative growth and the Programa Luz para Todos program) improvement of the performance indicators of service continuity, reduction of electrical losses, as well as adjustments and implementations of computerized systems for support in commercial management and distribution.


PwC \| Loeser e Portela Advogados \| Siglasul	Prepared for BNDES	39

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 Ceal was used, namely: "Electrical System Expansion Plan (2016-2025 horizon)", "Distribution Development Plan (PDD) for the year 2017" (although provisional¹⁹), "Results Plan for the Improvement of Distribution Services, 2015" and "Plan for Temporary Rendering of Electricity Distribution Service, 2017". In addition, we used information obtained by the company's planning area, obtained during face-to-face meetings and conference call that were carried out.

Initially, we present in Table 18 a summary, by type of project and voltage level, of the investments in progress reported by Ceal. In total, BRL 62.57 million are intended for projects/investments planned for the year 2017²⁰.


Table 18 - Investments in progress in the year 2017 by Type of Project
Type of Project	Investment
AT/MT EXPANSION	BRL 25,860,730
AT/MT/BT IMPROVEMENT	BRL 11,770,000
PROGRAMA LUZ PARA TODOS ("PlpT")	BRL 24,941,913
Total Investments	BRL 62,572,643

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, adopting the following assumptions by type of investment and voltage level:

• "AT Expansion": we considered the company's projected annual works in the 2017 PDD for the period from 2018 to 2022; however, the amounts submitted by Ceal for these investments were considered slightly inflated in relation to the price bank used by ANEEL. For these works, a 5.50% reduction level on the investment amounts allocated in the PDD was adopted;

• "MT/BT Expansion": the company's projected annual investment amounts in the 2017 PDD for the period from 2018 to 2022 were considered;

• "AT Improvement": as there were no investments in the 2017 PDD projected for the years 2017 to 2026, the need was estimated for the period from 2018 to 2022.

• "MT and BT improvement": as there was no projected investments for the years 2020 and 2022 in the 2017 PDD, the need for these years was estimated as: i) for the year 2020, the average of investments allocated to the years 2018 and 2019; ii) for the year 2022, the average of previous

¹⁹At the time of drafting this Report, the 2017 PDD had not yet been delivered to ANEEL by Ceal.

²⁰The amounts set forth in this section relate to projects in progress or which are in the process of signing a contract. The figures shown are estimated: therefore, they may change during the year.


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years (2018 to 2021), considering the investment amount calculated for the year 2020 in the calculation;

• "Renewal": no investments were projected for the period from 2018 to 2022. For this period, the necessary investment was estimated as the amount corresponding to the portion related to the "Regulatory Reintegration Quota ('QRR')" established by ANEEL to Ceal in the last rate revision occurred in August/2013, adjusted by the IPCA until April 2017;

• "PLpT": considered, in the year 2018, the necessary investments to meet the targets of conventional connections only until the year 2018, which is related to the completion of the program, according to Decree #8,387, of 12/30/2014; In addition to these, necessary investments were made in "Systems" and "Vehicles". For "Systems", in 2018, the necessary investments were considered for correcting the ERP System and integration of the Construction Management System ("SGO") with the Distribution Technical Management System ("SGTD"). Also in 2018, for "Vehicles", we considered investments necessary for the renewal of vehicles of the own fleet having an expired service life.

We present, in Table 19, the Base Scenario PIQ, by type of project and voltage level. BRL 796.9 million of investments are needed in the next five (5) years, and the need for the year 2018 is significant, which concentrates BRL 343.7 million²¹.


Table 19 - Base Scenario: PIQ (Detailed Resources by Type of Project)


Type of
Project/System/	2018	2019	2020	2021	2022	Total
Vehicles
AT Expansion	BRL 176,083,646	BRL 37,123,026	BRL 28,937,221	BRL 23,162,138	BRL 24,762,139	BRL 290,068,170
MT/BT Expansion	BRL 43,810,795	BRL 17,562,526	BRL 17,980,260	BRL 13,730,787	BRL 6,573,021	BRL 99,657,389
AT Improvement	BRL 37,550,000	BRL 9,387,500	BRL 9,387,500	BRL 9,387,500	BRL 9,387,500	BRL 75,100,000
MT/BT	BRL 12,533,386	BRL 3,495,901	BRL 8,014,643	BRL 5,269,086	BRL 7,328,254	BRL 36,641,270
Improvement
Renewal	BRL 55,448,195	BRL 55,448,195	BRL 55,448,195	BRL 55,448,195	BRL 55,448,195	BRL 277,240,975
"Luz para Todos"	BRL 10,285,390	-	-	-	-	BRL 10,285,390
ERP System	BRL 1,000,000	-	-	-	-	BRL 1,000,000
Correction
Integration of	BRL 1,000,000	-	-	-	-	BRL 1,000,000
SGO/SGTD Sys.
Vehicles	BRL 5,962,653	-	-	-	-	BRL 5,962,653
Total Investments	BRL 343,674,065	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 103,499,109	BRL 796,955,847
Total
Own	BRL 336,474,292	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 103,499,109	BRL 789,756,074
Resources

Of the total amount, Own Resources stands out, since there are sector subsidies from the Economic Development Account ("CDE") of 70% of the investments related to the Programa Luz para Todos (PLpT) program.

In addition to the Base Scenario, an Alternative Scenario, which anticipates, for the year 2022 (the year prior to the date of the first Periodic Rate Revision ("1RTP") to be applied in the new concession) investment

²¹The financial amounts presented in this section of this report are in real currency at April 2017 prices.


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related to the construction of SEs and LDs in the years 2025/2024/2023, representing an amount of about BRL

29 million, so as to increase the Regulatory Remuneration Base ("BRR"), as shown in Table 20²².


Table 20 - List of SEs and LDs with investments anticipated from 2025/2024/2023 to 2022 for the Five-Year Plan
	Estimated Year	Estimated
Project Description
	2017 PDD	Amount
VIÇOSA/PALMEIRA DOS ÍNDIOS CS LD (69 kV)	2023	BRL 8,059,399
ANGELIM/UNIÃO DOS PALMARES LD (69 kV)	2024	BRL 5,147,432
OLHO D’ ÁGUA DAS FLORES/PÃO DE AÇUCAR (C2) LD (69 kV)		BRL 7,520,867
EXPANSION OF ARAPIRACA II SE (69 kV/25 MVA)		BRL 1,134,253
DEPLOYMENT OF CAMPO GRANDE SE (69/13.8 kV – 12.5 MVA)	2025	BRL 7,100,910
Total Investments		BRL 28,962,861

Table 21 shows the resulting Alternative Scenario PIQ. Note that the Alternative Scenario surpasses the Base Scenario by approximately BRL 28 million in the total for the five-year period.


Table 21 - Alternative Scenario: PIQ (Detailed Resources by Type of Project)

Type of
Project/System/	2018	2019	2020	2021	2022	Total
Vehicles
AT Expansion	BRL 176,083,646	BRL 37,123,026	BRL 28,937,221	BRL 23,162,138	BRL 53,725,000	BRL 319,031,031
MT/BT Expansion	BRL 43,810,795	BRL 17,562,526	BRL 17,980,260	BRL 13,730,787	BRL 6,573,021	BRL 99,657,389
AT Improvement	BRL 37,550,000	BRL 9,387,500	BRL 9,387,500	BRL 9,387,500	BRL 9,387,500	BRL 75,100,000
MT/BT	BRL 12,533,386	BRL 3,495,901	BRL 8,014,643	BRL 5,269,086	BRL 7,328,254	BRL 36,641,270
Improvement
Renewal	BRL 55,448,195	BRL 55,448,195	BRL 55,448,195	BRL 55,448,195	BRL 55,448,195	BRL 277,240,975
"Luz para Todos"	BRL 10,285,390	-	-	-	-	BRL 10,285,390
ERP System	BRL 1,000,000	-	-	-	-	BRL 1,000,000
Correction
Integration of	BRL 1,000,000	-	-	-	-	BRL 1,000,000
SGO/SGTD Sys.
Vehicles	BRL 5,962,653	-	-	-	-	BRL 5,962,653
Total	BRL 343,674,065	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 132,461,970	BRL 825,918,708
Total
Own	BRL 336,474,292	BRL 123,017,148	BRL 119,767,819	BRL 106,997,706	BRL 132,461,970	BRL 818,718,935
Resources

²²In this case, it was assumed that the company will have its privatization process finalized in 2018, thus being subject to an RTP in the year 2023.


PwC \| Loeser e Portela Advogados \| Siglasul	Prepared for BNDES	42

It should be noted that the Base Scenario shall be used for the Company's economic-financial evaluation.

4. References

[1] “História de Alagoas,” 1 7 2016. [Online]. Available: http://www.historiadealagoas.com.br/historia-daceal.html. [Accessed 4 5 2017].

[2] Eletrobras, “Eletrobras Distribuição Alagoas,” [Online]. Available: http://www.eletrobrasalagoas.com/historia.aspx. [Accessed 4 5 2017].

[3] Wikipedia, “Wikipédia - Alagoas” [Online]. Available: https://pt.wikipedia.org/wiki/Alagoas. [Accessed 4 6 2017]. [4] E. d. P. Energética, “Plano Nacional de Energia 2030,” 2007.

[5] I. Própria, Somatório das áreas dos países, Rio de Janeiro, 2017.


PwC \| Loeser e Portela Advogados \| Siglasul	Prepared for BNDES	43

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, population density per km², 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	Pop.	Density	# HH	%	%
Region	# Munic.	(km²)	(Thousand)	(Inhabitants/km²₎(thousand)		Rural	Illiterate Unemployment
						Popul.	Popul.	Rate
ALAGOAS	102	27,882	3,345	120,12	1,051	26%	20%	13%
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.

Alagoas is the state having the highest population density in the Northeast Region (120.12 inhabitants per km²), with its capital (Maceió) being the most populous municipality in the state. Its population is mainly concentrated in urban centers (74% of the population), but has a high percentage of inhabitants in rural areas (26%). Its population suffers from illiteracy, where 20% of the total population lacks basic reading and writing skills. In addition, the state of Alagoas leads the ranking of Brazilian states with the highest unemployment rate (13%).

b) Access to services

Table 23 shows (for Ceal, and average data from Brazil and the North and Northeast Regions) the percentages of households (i) without garbage collection; (ii) same as point "i", but for urban areas; (iii) without water supply through networks; (iv) same as point "iii", but for urban areas; (v) without


PwC \| Loeser e Portela Advogados \| Siglasul	Prepared for BNDES	44

sanitary sewage by networks or septic tank; (vi) same as point "v", but for urban areas; and (vi) without electric lighting located in rural areas.


Table 23 - Service Access Information

			% HH	% Urb.	% HH without	% Urb. HH
	% HH	% Urb. HH	without	HH	Sewage	without _Sewage% Rural HH
Region	without	without	Water	without	Networks/Septic Networks/Septic		without
	Garbage	Garbage	Network	Water	Tank	Tank	electrical
	Collection	Collection	Supply	Network			lighting
				Supply
ALAGOAS	16%	1%	25%	18%	45%	36%	0%
BRAZIL	10%	1%	15%	6%	19%	12%	2%
NORTH	21%	3%	40%	28%	38%	29%	7%
NORTHEAST	21%	3%	20%	7%	35%	23%	1%
Sources: 2015 PNAD.

In Alagoas, 16% of the households do not have garbage collection, while 25% do not have water supply through networks and 45% do not have access to a sewage network/septic tank. The percentages of urban households without access to the sewage/septic tank and without water supply through network are relatively high and higher than the national average (36% and 18%, respectively, for the state).

c) Income

Table 24 shows (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 line²³; (iii) average household income per capita and (iv) GDP (Gross Domestic Product) per capita. As shown, the state has the highest percentage of population with income below the poverty line in Brazil; as well as the lowest income and GDP level, below regional and national averages.

²³Equivalent 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.


PwC \| Loeser e Portela Advogados \| Siglasul	Prepared for BNDES	45

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 Alagoas (“CEAL”).

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.


1 Purpose and limitations of the work	2 Summary of key issues identified:
Our work involved review of documents made available in databases,	•	Facilities operate without the required environmental operation license and
interviews with managers in charge of the environmental activities of the		other licenses such as the Fire Brigade Inspection Service Certificate
company and on-site visits to six substation facilities.		(FBISC) and the IBAMA Federal Technical Registration (IFTR)
The purpose of the work was to evaluate key environmental and social issues of	•	Noncompliance with the terms and conditions of operating licenses
CEAL in light of the applicable laws and regulations, review how such issues	•	Substation noise levels not monitored
are managed from environmental and social standpoints, and identify
potential deficiencies and situations that may result in significant risks and	•	Lack of documents such as Solid Waste Management Plans (SWMPs) and
costs to the company.		Solid Waste Inventories (SWIs)
The following topics were reviewed: solid wastes, PCB/ascarel, noise,	•	Waste burning
atmospheric emissions, wastewaters, water resources, permanent preservation	•	Incorrect storage and disposal of hazardous solid wastes
areas, plant suppression, service providers, environmental accidents,
environmental liabilities, easement trespassing, conflicts with indigenous	•	Unlicensed use of artesian wells (drinkability not monitored also)
populations, engagement practices and interaction with surrounding	•	Transformer explosion incidents
populations, as well as assessments, fines and consent agreements.
	•	Oil stains found on non-impervious soils
The scope of the work did not include generation of additional data through
collection and analysis of soil and water, atmospheric emission and wastewater	•	Painting activities carried out without environmental controls
samples, nor was any evaluation performed for the purpose of checking	•	Substations and maintenance activities lack appropriate containment
compliance with laws related to workers' health and safety.		systems and oil-water separator boxes
	•	Old, pre-1980 transformers in use and untested for PCB/ascarel

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.


Eletrobras System Distributor
Privatization PwC	3

Summary of key issues identified

Below is a summary of key issues identified during the environmental assessment work. This summary does not include all issues identified and presented in the Environmental Assessment Report. Accordingly, it should be reviewed together with the remainder of the report for a comprehensive understanding of the issues identified.

3 Estimate of costs to remedy issues identified

An estimated amount between R$ 13.1 million and R$ 51 million, approximately, is required in order to remedy and mitigate some of the previously highlighted issues and their respective potential impacts, 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


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.

Issue #	Topic	Issue Identified		Cost (in R$)*
			Minimum	Middle	Maximum




		Deficiencies identified in
		the storage of Class I
1	Waste		R$5,189,756	R$12,974,390	R$20,759,024
		(hazardous) solid wastes at
		substations.




		Incorrect disposal of Class I
2	Waste	solid hazardous wastes (e.g.	Not available - According to information provided by CEAL, the tendering process for
		paint and lamp bulbs).	specialized solid hazardous waste management contractors is underway.




3	Waste	Waste is burned outdoors.		N/A


Eletrobras System Distributor Privatization PwC


Eletrobras System Distributor Privatization PwC
*Annex I - Issue and estimated cost summary chart (cont.)*	7


Issue #	Topic	Issue Identified		Cost (in R$)*
			Minimum	Middle	Maximum

13	IFTR	IFTR absent for all		N/A
		facilities
		Painting activities
		carried out at CEAL
	Atmospher	facilities lack
14	ic		R$33,000	R$148,666	R$245,000
	Emissions	appropriate
		environmental control
		measures.
		Lack of containment
		basins and oil-water
		separator boxes for
		substation transformers
	Wastewate	and/or at locations in
15	rs	which oil-containing	R$4,956,000	R$9,912,000	R$19,824,000
		equipment is serviced.



		Water resources used in
16	Water	substations without	R$1,128.15	R$1,128.15	R$1,128.15
	Resources	appropriate licensing.


						8

Eletrobras System Distributor Privatization PwC

Annex I - Issue and estimated cost summary chart (cont.)


Issue #	Topic	Issue Identified		Cost (in R$)*
			Minimum	Middle	Maximum



		Water drinkability not
	Water
17	Resources tested at facilities using		R$1,980	R$1,980	R$1,980
		artesian wells.




		Existing risk of water and
		soil contamination in
		substations and facilities
		(oil stains detected on the
		soil) resulting from
18	^Miscellaneoleakages due to improper		R$340,000	R$3,825,000	R$7,310,000
	us
		storage of oily wastes or
		accidents such as
		explosions of transformers
		and oil-containing
		equipment.


		TOTAL	R$13,153,249.15	R$29,581,979.15	R$ 50,947,377.15

*Costs are estimated based on the assumptions detailed in the Environmental Assessment Report dated May 5, 2017.

						9

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: CEAL 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 CEAL's evaluation, in accordance with the Agreement, and was based on information provided by CEAL'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


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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 Ceal, 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 Ceal between February and April 2017 were used to prepare the following analysis and indicators.

In this report, we present information related to Ceal's staff considering the cut-off date of December 31, 2016, and adopted the following assumptions for the generation and analysis of personnel indicators.


Considered:	Not considered:
Employees	Interns
Member of the Board of Directors	Young apprentices
Director	Pensioners
Employees on secondment	Assigned Employees
Commissioned positions	Employees laid off in December/2016
	Retirees on Disability

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. In cases where data from this Panel were not available, the Distributor's indicators were compared with General Market data.

• Considering the base date of December 31, 2016, the Distributor's workforce has 1,128 active employees. This group is composed mainly of men (88%), with an average of 42 years of age, who have completed high school (40%).

• Employees spent an average of 14 years in the company, and approximately 32% spent over 20 years in the company.

• Employees are distributed into four broad positions: middle-school level professional (57%), high-school level operational professional (12%), high-school level support professional (17%) and higher-education level professional (10%). Professionals with training beyond what is required in the public competition exist. Despite the preponderance of middle-school level positions, about 18% of employees have higher-education level.

• Among leaderships, 56% of leaders are in higher-education level positions and 66% of positions are held by professionals with up to 10 years in the company. We observe that the breadth of command at the Distributor (number of employees per leader) is 13, which is similar to what is found among companies in the electric power sector.

• The average turnover of the last 5 years was around 5%, which is lower than that of the electric power market (7%). 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.


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• CEAL has consistent Health and Safety policies and the analysis of the number of accidents in the last 5 years shows an opportunity to adopt more effective practices. The Distributor maintained an average of 23 accidents per year. On average, 4.78% of the staff were on leave in recent years.

• With regard to professional training, there was investment of approximately 47.12 hours/year and BRL 405.71 (average) per employee for dedication to training.

• Regarding personnel cost, we observed that the fixed remuneration of Ceal's employees contributes to the weight of the Total Cost, representing 51%. The total cost per capita for the Distributor is 36% 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. Personnel management issues seem poorly organized and supported by poorly automated systems.

The benefits practiced by Ceal 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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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. It is coordinated by the president of the Board of Directors and composed of six (6) official members, with a term of three (3) years, and reelection is allowed. It is formed by the local CEO and five (5) corporate directors. Regular meetings are held weekly, and extraordinary meetings may be held whenever necessary. Members of this Board are elected by the company's 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 Affairs and Special Projects Board: The Regulatory Affairs and Special Projects Board is responsible for 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 and 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 and controlling the activities related to the company's commercial relationship with its consumers, in accordance with the provisions of the concession agreement and current legislation, as well as activities related to market projections and energy purchasing.

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 the activities related to people management, training and development, occupational safety and medicine, labor and union relations, supplies and material management, transportation, information technology, organization and methods, documentation and archiving, and general services.

On December 31, 2016, Ceal's workforce was composed according to the table below.


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	Category	Amount
a.	Employees in permanent positions	1,111
b.	Employees on secondment from other bodies and spheres*	4
Employees without ties to the public administration (commissioned)		6
d.	Board members	7
Assigned employees		11
Total (a+b+c+d-e)		1,128

	In addition to the professionals above, Ceal's workforce include interns and young apprentices.

	Category	Amount
a.	Young apprentice	43
b.	Interns	94
Total (a+b)		137

2.3. Profile of Positions and roles:

Following what has been established in the Eletrobras System's Position and Compensation Plan ("PCR"), Ceal employees are distributed into four broad positions:


	Levels of
Broad position				Role
	complexity

Middle-school Level			§	Assistant Electrician
Professional ("PF")	I, II		§	Administrative Electrician-Driver assistant
		§	Accounting technician
High-school Level Support	I, II, III and IV	§	Administrative Support
Professional ("PMS")

		§	Electrical Technician,
High-school Level Operational		§	Telecommunications Technician
Professional ("PMO")	I, II, III and IV	§	Work Safety Technician
		§	Electronics Technician.
		§	Administrator
		§	Lawyer
		§	Social Communication Analyst
Higher-education Level		§	Information Technology and

Professional ("PS")	I, II, III and IV	§	Archivist Communications Analyst
		§	Social Worker
		§	Accountant


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§	Economist
§	Civil Engineer
§	Electrical Engineer
§	Work Safety Engineer
§	Work Physician
§	Organizational Psychologist

At Ceal, roles that originally in the PCR are classified as high-school level are classified as middle-school level professionals. Namely: Electrician Driver, Administrative Assistant.

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	8
Assistant to the CEO	1
Director	1
Manager	18
Area Manager	48
Advisory Manager	3
COI Leader	3
Location Leader	10
Auctioneer	1
Total	93

In addition to gratified roles, Ceal has employees with no ties to the public administration who act in a commissioned position. This contracting model is set forth in Article 37 item II of the Constitution.


Category	Amount
Board Assistant	2
Advisory Manager	1
Director	3
Total	6

In total, Ceal's staff has 99 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.

73 employees were laid off, distributed into two stages:

• Stage 1 (July 2013 to December 2013): 58 terminations.

• Stage 2 (January 2014 to November 2014): 15 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

Ceal's organizational structure is in the process of being updated, but the new model has not yet been implemented.


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According to his/her position, the employee receives appropriate training actions and is eligible for promotion or salary raise by merit.

Employees on leave during the appraisal cycle, commissioned employees, members of the Board of Directors and directors do not participate in this performance appraisal model, and thus, only 954 employees participated in the 2016 cycle.

By analyzing the results of the appraisals, we observed that the majority of employees have their skills appraised at "Above expectations" (49%) and targets appraised at "Exceeds" (58%). These employees are positioned in quadrant 4. We also verified that about 3% is appraised at "Partially meets" for skills and 8% for targets.


	Appraisal result
Skills		Targets
AE - Above Expectations	49%	S - Exceeds	58%
A - Meets	47%	A - Meets	34%
AP - Partially meets	3%	AP - Partially meets	8%
NA - Dos not meet	1%	NA - Dos not meet	-

Good market practices indicate that, on average, 70% of appraised employees receive a "Meets" grade, and the rest is 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, Ceal accounted for 53,011 hours of training, representing an approximate investment of 47.12 hours per year per capita (approximately 6 days) for dedication to training at a cost of BRL 456,429.02 (BRL 405.70 per capita).

According to the 2015 Management Report, in 2015 the investment in training and development totaled 81,396 hours of training, representing 75.09 hours per year (approximately 9 days). The cost of training was BRL 1,127,711.10 (BRL 1,040.33).

According to information gathered during interviews, the reduction in investment in training was due to budget constraints in 2016. As an opportunity to keep training hours at a low cost, the Distributor can benefit from the partnership with institutions of the S System (inter alia, SENAI, SENAC, SESC).


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4. Personnel Cost

The analysis of Ceal's personnel costs was based on the reports from the December 2016 payroll.

In the documents and reports provided by the Distributor, the following types of employment relationships were identified through the payroll, i.e., with receipt of some type of compensation.


	Category	Amount
	EMPLOYEE	1,115
ACTIVE	COMMISSIONED POSITION	3
	SECONDMENT	4
	TERMINATED EMPLOYEES	35
	TERMINATED INTERNS	21
INACTIVE
	TERMINATED APPRENTICES	1
	RETIREES ON DISABILITY	7
	ASSIGNED EMPLOYEES	11
OTHER	YOUNG APPRENTICE	43
	INTERN	94
	Total	1,334

The analysis of the demographic data included 1,128 active employees, however, Ceal has 3 commissioned employees, 2 directors and 1 member of the Board of Directors who are not on the payroll, and are instead paid directly by the source company. Thus, the personnel cost data shown below considers only 1,122 active employees, 64 inactive employees and 148 other employees.

4.1. Compensation structure

Ceal's compensation structure consists of the following items:

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 vacation, maternity wages and sickness allowance;

• Fees paid to employees who exercise the role of Directors or Board members who do not receive a salary;

• Incorporated bonus, i.e., bonuses that have been incorporated into the salary and the employee does not fail to receive;

• Bonus for service time 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:


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Benefits paid in December 2016 are defined in a collective agreement and include:

Health and Well-being Support	Education Support	Family Support

Medical Aid	Educational reimbursement	Special dependent aid
Dental Care	Graduation reimbursement	Babysitting reimbursement
Continuous-use medication		Childcare reimbursement
reimbursement
Medication reimbursement		Funeral aid
Gym reimbursement
Hospital Medical Treatment

Food aid
Transportation Reimbursement
Transportation aid

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;

Other items (representing sporadic payments):

• Overtime;

• On-call;

• Transfer bonus;

• Travel accommodation.

4.2. Cost with active employees

The total personnel cost, considering active employees, for the month of December 2016, is BRL 10,443,432.14. The costs with payment of 13^thsalary for this period was BRL 8,350,553.85 and was not considered in the calculation of financial indicators. In this calculation, charges and deductions were also not considered:


	Dec. 2016
Total personnel cost*	BRL
	10,443,432.14
*considers gross compensation, without deductions and charges.


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4.3. Interns and apprentices

In addition to employees, interns and apprentices are on the payroll.


Relationship	Amount	Costs
Apprentices	43	BRL 27,231.65
Interns	94	BRL 63,550.40

Internship program includes higher-education and high-school students at several departments of the company. Management of the contract is carried out by CIEE (Centro de Integração Empresa Escola).

The amount for compensation for higher-education interns is BRL 400.00, and for high-school interns is BRL 293.00. The workload is 20 hours per week. All are entitled to a transportation fee of BRL 6.00 and a monthly meal aid. Young apprentices are entitled to a compensation of BRL 413.33.

4.4. Costs with inactive staff

In addition to the cost with employees, the payroll includes inactive staff.

Retirees on disability and terminated employees received in the December 2016 payroll a payment residue related to profit sharing. The total amount paid to inactive staff represents less than 2% of the total payroll.


Category	Costs
Retirees on disability	BRL 5,255.96
Assigned Employees	BRL 280,147.11
Terminated employees	BRL 101,283.31


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5. Collective agreements

The collective bargaining agreement is nation-wide, covers 100% of employees, and its clauses cover all six Distributors analyzed. In addition to this instrument, the company also has a Specific Agreement and Profit Sharing Agreement. Over the years, the definitions established in previous years have been maintained.


Document	Scope
2016 - 2018 Collective agreement
Nation-wide commitment agreement
2016 -2018 Specific collective agreement	Its clauses cover all Distributors
Specific commitment agreement
Specific clauses of the Collective Agreement by
distributor	Ceal-specific clauses
Specific commitment agreement

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

5.3. Payment of other bonuses

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:


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Clause	Agreement description

Hardship pay	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	Calculated according to the percentages applied in the relevant legislation.

Substitution	Non-cumulative grant of Gratification for role to formal substitutes of an
gratification	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	Driver gratification to electricians in the usual exercise of the
gratification	Electrician/Driver role.
("GEM"):
	1/3 of the normal hour for employees on-call under applicable legislation.
On-call

Holiday	Holiday gratification payment of 75%
gratification


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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) with in-house staff.

Ceal has designed a project to prioritize such labor. Services that are the object of insourcing are those of a continuous nature, directly related to the end activity and having roles foreseen in the Career and Compensation Plan ("PCR") and the defined deadline was 5/19/2017.

According to the Insourcing Project, the proposal for Ceal is that out of a total of 414 third-party employees, 19 employees are insourced. A total of 159 employees were hired, considering the years of 2015 and 2016, with the objective of labor insourcing.

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

7.1. Verification of existence of health and safety policies and procedures

In addition to specific clauses on health and safety defined in a collective agreement, Ceal has policies and standards aimed at preserving the health and safety of its employees. The main aspects related to the topic are shown below.

Ceal 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

Ceal submitted the document for the preparation and implementation of a valid Occupational Health Medical Control Program ("PCMSO"), which was prepared in January 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			ï
Describes actions to promote health			ï
Describes tests to be performed
Recognition of environmental risks			ï
Procedure in case of accident
Responsibilities
Has descriptions for positions and roles
Has performance indicators			ï
Schedule of actions
Expected to disclose results			ï

Key: showed evidence	ï insufficient information	× did not show evidence

7.3. PPRA Analysis

Ceal submitted the document for the preparation and implementation of a valid Environmental Risk Prevention Program ("PPRA"), which was prepared in October 2016. The Distributor has a single PPR that covers all of its Units.


Aspects analyzed	Classification
Clear goals
Roles and responsibilities
Has performance/goal indicators	ï


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The Distributor has evidence of being in compliance with the need to open a "CAT" (Work accident communication) when work accidents occur.


Ceal number of accidents	2016	2015	2014	2013	2012
With Leave	10	14	14	11	22
Without Leave	7	8	11	5	2
Commute	0	0	0	8	6
Total number of accidents	17	22	25	24	30


The number of accidents involving outsourced companies, service providers, was also provided by
the Distributor.

Number of accidents with Third	2015	2014	2013	2012
parties
Total number of accidents	19	13	14	7

7.7. PPE Delivery Verification

Ceal showed evidence that it performs PPE delivery control for the following roles, which require this type of equipment: • Electrician serving in COD and Maintenance of electric power distribution lines and grids Electrician driver; • Substation Operator; • Winch Operator; • Electrician for De-energized Grid Maintenance, disconnections and connections of consumer units; • Medium/High Voltage Reader; • Electrical Technician and Safety Technician; • Engineer.

7.8. Occupational Safety Technician Performance

Ceal has in its staff a professional that acts as a work safety technician.

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.

Ceal offers its employees the following training sessions, according to the activities carried out: Regulatory Standard 10 (NR10), Regulatory Standard 35 (NR35), Regulatory Standard 37 (NR37) and Regulatory Standard 33 (NR33). 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.

• NR17 - Training performed by employees who perform activities related to call centers/telemarketing.


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High-school Level Operational Professional ("PMO")	I, II, III and IV
Higher-education Level Professional ("PS")	I, II, III and IV
Professional Researcher ("PP")	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.

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, 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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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, Boa Vista 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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The benefits established in a collective agreement, whether in the nation-wide agreement, in the nation-wide commitment agreement, in the specific agreement of the Distributors or in the specific agreement of the distributor are shown in the table below:


Benefit	Current amount
Food/Meal Aid		13 to 16 booklets/year with 29 units having a value of BRL 37.82.
		It shall be granted to employees subject to continuous rotating shifts
Snack Voucher		at the unit value of 50% of the meal voucher.
Food/meal aid in overtime		It shall be granted to employees when called to work on Saturdays,
schedule		Sundays and holidays.
		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
Educational Aid		and/or technical school).
		Reimbursement for expenses with school uniforms and supplies for
		full scholarship recipients, limited to the amount of two monthly
		tuition installments.
PCD Dependent Aid		Reimbursement of proven expenses with PCD dependents up to a
		limit of BRL 843.65.

_{Childcare/Preschool/Nanny}		Reimbursement of BRL 599.05/month per dependent for
		dependents aged 6 months to 6 years. Note: limited to the amount
Aid		of two monthly tuition installments.
School material		Up to the limit amount of two monthly tuition installments for the
reimbursement		educational aid or childcare aid.
		Partial reimbursement of expenses with higher education for
		employees who have not yet finished college or for courses in fields
Cost aid for college		of knowledge considered to be of interest to the company.
students		Reimbursement of 90% the monthly tuition, limited to BRL
		1,133.83.
		Ceal has an in-house plan for payments, aid and benefits: Health
		Protection and Recovery Plan ("PPRS"), which encompasses the use
		of medical and care services under the Accredited Network, Free
		Choice and Reciprocity Agreement modalities by recipients and
		their dependents. Dependents are: children, stepchildren, spouse,
		companion and parents, under the conditions set forth in the specific
		standard.
		The plan offers comprehensive coverage, including:
Dental care		•	Corrective and/or Orthopedic Apparatuses
		•	Reimbursement of Medication expenses (continuous use only)
		•	Hospital Care, Surgical and Obstetric Interventions
		•	Psychotherapeutic and Speech Therapy Treatments
		•	Treatments for Global Posture Re-education ("RPG")
		•	Out-of-Home Treatment
		The Distributor has a table with the amounts for each procedure.
		Payment is made by the company, which deducts the employee's co-
		pay.


PwC \| Loeser e Portela Advogados \| Siglasul	42


	In the year 2016, the Healthcare Plan had the cost of BRL
	7,409,470.74.
	Reimbursement of funeral expenses up to the limit of BRL 4,921.28
Funeral Aid	and BRL 9,842.57 for death due to work accident.
Physical activity incentive	Reimbursement of expenses with physical activity up to the established
	limit of BRL 94.58.
	The Distributor pays for medical and hospital treatment expenses not
Hospital Medical Treatment	covered by the healthcare plan for victims of work accidents and
	occupational illness.
Medication for injured	The Distributor pays for 100% of the amount of medication for work
employees	accident victims.
Illness/	Compensation supplement, including thirteenth salary, to an amount
work accident aid	corresponding to the difference between monthly compensation and the
	benefit received by social security as work sickness/accident aid.
Out-of-state healthcare	Advance of 2 gross wages to employees who need out-of-state
	treatment due to illness. (Maximum 30% of the employee's
compensation limited to 10 payments.

Airfare	Provision of airfare for out-of-home treatment of illness to employees
	in rural areas of the state.
	Group life insurance for permanent employees, apprentices, interns,
Life insurance	members of the Board of Directors and directors, with predetermined
	amounts.
	Accident insurance will be paid by the company in case of a fatal
Accident insurance	accident at work or in case of an accident at work resulting in
	permanent incapacity for work.
Transportation voucher	Granted to employees, apprentices and interns, according to the law.

Leave for victims of	Paid leave of 3 to 5 days to workers.
domestic violence
Patient companion leave	Medical companionship for relatives or healthcare plan dependents:
	from 1 to 30 days subject to submission of medical certificate or
	medical report.

Leave due to death of step-	Grant of leave of up to 5 days.
father or step-mother
Death or disability	Inclusion in existing group life insurance of coverage for death or
insurance	permanent disability caused by illness, while keeping indemnity
	coverage updated.

Other incentives offered:

Private Pension Plan - Ceal, through PREVINORTE, 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. The foundation also provides personal loans under payroll deduction. In 2016, the


PwC \| Loeser e Portela Advogados \| Siglasul	43

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.

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.


PwC \| Loeser e Portela Advogados \| Siglasul	46

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:

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, Ceal's index was 66.13%.

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 company's sale prospect and the overload of the

workforce (due to a reduction in the number of employees) versus the high demand, which has been

causing leaves due to occupational illness.


PwC \| Loeser e Portela Advogados \| Siglasul	47

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,

The summary of the outcome of our work "Product 04: Legal Due Diligence Report" for CEAL ("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 CEAL

Introduction Page 4/15

INTRODUCTION

1. This Executive Report ("Report") was carried out as part of the structuring of the
privatization operation of Companhia Energética de Alagoas S.A. ("CEAL" 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; in 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 CEAL 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 CEAL 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 CEAL, and the description must contain
the details on the litigation, its probable outcome and the amounts involved;


Legal Auditing Executive Report Introduction		CEAL Page 5/15

(iii)	status of the assignment and ownership of real estate and equipment registered or likely to be registered in CEAL'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 CEAL 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 CEAL 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 CEAL 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		CEAL Page 6/15

(d)	obtaining data extracted from CEAL's process control system;
(e)	analysis of the documents and information made available.

10. It is assumed that (i) all copies made available by CEAL 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 CEAL'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 CEAL, 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		CEAL Page 7/15

A.	REGULATORY ASPECTS
1.	CEAL acts as a designated distributor responsible for providing public electricity

distribution services in the areas of municipalities of the state of Alagoas listed in ANEEL

Resolution #353/1998, in order to ensure the 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. ELETROBRAS agreed to designate its subsidiaries, including CEAL, 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. CEAL held the concession for operation of public electricity distribution services under the terms of Concession Agreement #07/2001, 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, ELETROBRÁS, as controlling shareholder of CEAL, at its 165^thExtraordinary General Meeting, resolved for: (i) reject the extension of CEAL'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		CEAL
Introduction		Page 9/15
4.	This legal provision would not be applicable in the event of the sale of CEAL'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 mergers of shares.

C.	FINANCIAL AGREEMENTS
1.	Related Party Agreements. Financing agreements entered into with ELETROBRAS

do not contain provisions regarding the possibility and procedures for assignment and/or transfer of the respective rights and obligations, nor do they expressly establish restrictions on the conveyance of control and/or the corporate restructuring of CEAL.

2. Debt Confession Agreements. Debt confession agreements signed between CEAL and ELETROBRAS provide for early maturity in the event of: (i) potential expiration or non-renewal of the electric power distribution concession; (ii) change in the corporate control of CEAL.

3. Loan and Financing Agreements. The agreement entered into with Banco IBM S.A. provides for anticipated maturity of the debt in the event of transfer or assignment of the rights and obligations arising from the respective agreements to third parties, without prior and express consent by the creditor, as well as early termination in event of (i) direct or indirect transfer or conveyance of the corporate control of CEAL, without prior consent by the other party; (ii) spin-off, merger, consolidation or reduction of the share capital of CEAL, without prior consent by the other party; and (iii) performance of operations that imply corporate restructuring, transfer of control, sale of assets or reduction of capital, or any other operation that adversely affects the economic and financial condition of CEAL, without prior and express consent by the creditor.

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		CEAL Page 10/15

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 "CEAL" 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.	Information on payment of contracted insurance premiums. As of the completion of

this Report, no documentary evidence of payment of insurance premiums contracted by CEAL has been provided, and it is not possible to assess whether the policies are in force. Failure to pay one of the insurance premium installments would result in suspension of such insurance.

2. Mandatory insurance policies. As of the completion of this Report, no insurance policies against damage to land vehicles ("DPVAT") and civil liability of the builder were provided.

3. Insurance on assets with expired validity. The insurance contract for assets was effective until 4.3.2017, and as of the completion of this Report, no amendment was introduced to extend said date.

G.	LABOR ASPECTS
1.	From the completion of the studies undertaken in CEAL on labor aspects, we

highlight the following points:

(i)	The main and most recurrent themes addressed in the individual actions refer to actions for compensation for accidents at work with claims for material and moral damages, issues involving salary equalization and overtime;
(ii)	There are class actions and public civil actions with probable risk of loss;


Legal Auditing Executive Report							CEAL
Introduction							Page 11/15

2.	The following table summarizes CEAL's estimates of contingent liabilities related to
labor litigation according to the legal audit performed.
Distributor

		Loss risk				Provision
		classification	Number of cases		Loss amount	(BRL)
					estimate (BRL)
	Probable		562		28,926,290.77	29,372,000.00
	Possible		462		33,209,350.43
	Remote		159		17,562,457.70
	Total		1,183		79,698,098.90	29,372,000.00

3.	Specifically with respect to the cases analyzed in the present audit, we have the
following scenario:

		Attorneys			LPA
	Loss risk					Provision	Difference
classification		Number of	Loss amount Number of Amount at risk			(BRL)	(BRL)
		cases	estimate (BRL) cases		(BRL) (A)
	Probable	6	5,199,664.50	8	1,410,427,332.11	5,199,664.50 1,409,320,680.61
	Possible	6	4,527,588.87	4	15,877,588.87	0.00	0.00
	Remote	4	7,874,005.00	4	617,018.00	0.00	0.00
	Total	16	17,601,258.37	16	1,426,921,938.98	5,199,664.50 1,409,320,680.61

4. According to information provided by CEAL, there are court deposits totaling BRL

53,257,000.00. This amount, however, is the sum of deposits for labor, civil and ANEEL proceedings. It was not possible to identify the amount related to labor claims. Statements containing court deposits issued by Caixa Econômica Federal and Banco do Brasil were not provided.

H.	CIVIL, COMMERCIAL AND EQUITY LITIGATION
1.	In this section, the following points are highlighted:
	(i)	CEAL is involved in a total contingency of BRL 633,974,893.02, in respect of which the total amount of BRL 34,963,711.71 was indicated as having a probable loss risk (amounts in financial statements were rounded);
	(ii)	a total of 26 relevant actions were identified according to materiality criteria, in which the Company is listed as a defendant;
	(iii)	it was possible to analyze data on 6 civil public/class actions in which the following matters are mainly discussed: quality of provision of electric power supply services; indemnification to consumers who suffered damages due to the intermittence of the electric power distribution system; adoption of measures to


Legal Auditing Executive Report Introduction		CEAL Page 12/15

	improve energy supply services in order to avoid the occurrence of blackouts and rationing and compensation for undue issuance of notifications to SERASA. There is also an action filed against the Distributor for the refund of amounts to consumers related to an illegal increase in rates at the beginning of the Cruzado Plan received by the Distributor between March and November 1986, having an estimated contingency amount of BRL 12,175,000.00, and the loss risk is possible. There is also a lawsuit related to billing and measurement, claiming the amount of BRL 3,896,212,939.92, with a possible loss risk. The amount mentioned herein is verified in the action, but not in the Distributor's legal action spreadsheet;
(iv)	the Distributor is being sued in 3 proceedings seeking annulment of agreements, indemnification for noncompliance with clauses and contractual obligations and compensation for pain and suffering and material damages, with a total contingency of BRL 36,648,508.08. Of these, 2 proceedings are classified as having a possible loss risk (totaling BRL 28,582,314.40), and the third proceedings is classified as having a probable loss risk to the amount of BRL 8,066,193.68.
(v)	the Distributor is listed as a defendant in all the relevant actions analyzed;
(vi)	there are relevant actions that have had their analysis limited or even impaired due to partial copies of the proceedings or absence of copies.
(vii)	within the analysis performed, the legal audit identified 2 actions that require adjustment to the Distributor's provision to the amounts of BRL 250,000.00 and BRL 25,000.00.

2. The following table summarizes the civil actions involving the Distributor, and estimates for the respective commercial and equity contingent liabilities according to the information provided.


Loss risk classification	Number of Actions	Amount (BRL)
Probable loss	657	34,963,711.71
Possible loss	3,781	274,399,759.59
Remote loss	282	324,611,421.73
TOTAL	4,720	633,974,893.02


Legal Auditing Executive Report Introduction		CEAL Page 13/15

I.	TAX LITIGATION
1.	The following points stand out:
	(i)	It was possible to analyze data on ten (10) administrative and legal proceedings where the Distributor is listed as a defendant, and their amounts are aligned with the cutoff amount threshold (BRL 2,000,000.00).
	(ii)	In the Checking Account reports, we extracted information that one (1) tax note has not been included in the legal action progress report;
	(iii)	CEAL is involved in a total contingency of approximately BRL 58,430,970.47;
	(iv)	There are pending delivery certificates, which is why it is possible that there are contingencies/provisions that may not have been reported by the Distributor;
	(v)	The Distributor did not provide all of the requested copies, which compromised our analysis.
2.	Based on the analysis of the proceedings subject to the legal audit, the following

table shows the conclusions with the respective provision adjustment indicator:


Loss risk	Distributor	LPA		Adjustment of
classification			Provision	provision (BRL)
	Loss amount estimate (BRL)	Amount at risk (BRL)	(BRL) (B)	(A-B)
		(A)
Probable			44,952,000.00	(44,952,000.00)
Possible	322,909,425.04	312,039,561.22
Remote	48,984,963.49	48,984,963.49
Impaired*		7,649,119.19
Total	371,894,388.53	368,673,643.90	44,952,000,00	(44,952,000.00)

*	Threshold related to a proceeding where, due to a lack of a copy or an incomplete copy, it was not possible to analyze the risk of loss.
J.	REAL ESTATE ASPECTS
1.	Absence of Regularization. According to the information available, the control of real

estate assets is irregular and there is difficulty in obtaining documentation, especially with regard to real estate located in the rural part of the state. It was not possible, so far, due to a lack of necessary documentation, to confirm the ownership of the properties.


Legal Auditing Executive Report Introduction		CEAL Page 14/15

2. Goods offered as Collateral. According to information provided by representatives of CEAL, all of CEAL's assets, including real estate, were pledged as collateral in the pleas for stay of execution related to the Bresser Plan. In this context, the existence of certain liens and encumbrances may result in the foreclosure of the property and its subsequent public sale to third parties, thus causing the loss of ownership from the owner. In addition, in the case of properties linked to the concession, ANEEL Normative Resolution #63 of 5.12.2004 establishes that the pledging of assets tied to the concession as collateral without prior and explicit authorization by ANEEL constitutes an infraction subject to the imposition of a fine of up to 1% on the amount of the Company's revenues corresponding to the last twelve months prior to the writing of the Infraction Notice.

3. Real Estate Permitting. According to information analyzed in the data room, and in consultation with representatives of CEAL, it is possible to conclude that no Operating Permits or Inspection Permits were issued from the Fire Department for a large part of CEAL'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 in consultation with representatives of CEAL, it is possible to conclude that no occupancy permits were issued for CEAL'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). According to information provided in the data room, as well as in consultation with representatives of CEAL, we have verified that some properties of CEAL are located in rural areas. In this context, it is worth mentioning that 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

Employee Complementary Pension Fund and Health Care Plan (“Report”) for CEAL, 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 CEAL 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 Corporate 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 Eletrobras Distribuição

Alagoas (“CEAL”) 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 two retirement plan and two health care plans, one of which is temporary. Key features of these post-employment benefits will be described below.

Actuarial commitments were measured by an independent actuarial firm, MercerGama 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 ELETROACRE.

2. Plan types

Defined Contribution Plan (Plan 1): This is a structured, variable-contribution retirement plan covering disability and death risks funded by both CEAL and its employees. Registrations in this plan were open as of September 2008.

Defined Benefit Plan (Plan 2): This is a structured, defined-benefit retirement plan covering risks in both the vesting period and the benefit payout period. The plan is closed to new registrations since June 2008.

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 CEAL and were retired under the INSS. This plan is fully funded by the company.

Health Care Plan: This is a health care plan providing reimbursement for part of a beneficiary participant’s expenditure with health insurance plans, whether the insurance covers outpatient, hospital and/or dental care costs.

3. Plan statistics

Below are plan statistics in accordance with the independent actuary’s report for year 2016.


	Plan 1 (DC)
Active participants		1.036
Average age		42.41
Average salary		6,146.21
Retired participants		239
Average age		62.67
Average benefit		4,504.26

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 rates used in calculating the company's actuarial commitments are:

Plan 1 - 11.16% p.a. (considering an actual rate of 5.90% and inflation of 4.97% p.a.) Plan 2 - 11.14% p.a. (considering an actual rate of 5.88% and inflation of 4.97% p.a.) SIP Plan - 11.40% p.a. (considering an actual rate of 6.13% and inflation of 4.97% p.a.) Health Care Plan: 11.23% p.a. (considering an actual rate of 5.96% and inflation of 4.97% p.a.)

We understand that the rates applied are adequate to the calculations since they are 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 rates applied are 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

This assumption should reflect the expectation of the company regarding the projection of wage growth throughout the participants' career. In general, wages are adjusted for inflation, merit, and promotion.

We noted that actual market rates range from 0.5% p.a. to 3% p.a., according to data developed by the post-employment benefits committee of the Brazilian Actuarial Institute (BAI).

The rate of wage growth adopted in the calculations of liabilities of the plans maintained by CEAL is 7.07% p.a. (considering an actual real rate of 2% and inflation of 4.97% p.a.).

We noted that the rate used is consistent with market practices and we understand that it was adopted based on the expectation of the company regarding the projection of wage growth throughout the participants' career, and that it also reflects the results verified in hypothesis adherence studies developed by an independent actuary.

It should be noted that this premise does not apply to the SIP and HC plans.

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 Plan 1, SIP and HC plans was the Male AT-83 adjusted in 50%. According to the independent actuary's report, the table was adopted based on technical studies that confirmed its adherence to the profile of plan cohort and therefore its suitability to discount the actuarial liability.
	The general mortality table adopted for Plan 2 was the Male AT-2000 relieved in 10%. According to the independent actuary's report, the table was adopted based on technical studies that confirmed its adherence to the profile of plan cohort and therefore its suitability to discount the actuarial liability.
4.3.2.	Disability onset
	The table used for Plan 1 and the HC plan is the Medium Light table adjusted up by 25%. According to the study report prepared by the independent actuary, the mass of participants was not enough to allow for a study confirming that the table was suitable to match the plan population.
	The table used for Plan 2 is the Strong Light table. According to the independent actuary's study report, the table was adopted based on technical studies that confirmed its adherence to the profile of plan cohort and therefore their suitability to discount the actuarial liability.
	Since these tables are customarily employed in the market and their adoption does not
represent	a significant risk to the plan, we believe that they are adequate for the calculations.
It	should be noted that this premise does not apply to SIP.
4.3.3.	Disabled mortality
The	adopted invalid mortality board was AT-83 M&F relieved by 10%. According to the
independent	actuary's study report, the table was adopted based on technical studies that
confirmed	its adherence to the profile of plan cohort and therefore their suitability to
discount	the actuarial liability.
It	should be noted that this premise applies only to Plan 2.

4.4 Turnover

The turnover assumed for the plans was nil, meaning that future participant terminations in the coming years are not expected to bear a significant impact on plan liability.

Considering the plans’ features, we understand that the assumption adopted is adequate for liability calculation purposes.

It should be noted that this premise does not apply to SIP.

4.5. Time of retirement

The time of retirement assumed for the pension plans was the moment in which the benefit vests in full.

The study report provided by the independent actuary provides no information on the source of this assumption. Notwithstanding, this assumption is in line with market benchmarks and is a conservative one given that the commitments will be paid in over the short term.

It should be noted that this premise does not apply to SIP.

4.6. Family composition

The family composition assumption adopted for the pension and HC plans was 95% of married participants, while an age variance of 4 years was assumed for both beneficiaries and active participants.

With regard to active participants, although in line with usual market practices there is no information in the actuary's report on the source of this assumption. Notwithstanding and considering the features of the plans as well as the small impact that may result from its adoption, we understand that the assumption is adequate.

For the beneficiaries, we understand that it is not the best practice because the impact of the premise for the benefits granted can be expressive. We recommend the use of the royal family.

It should be noted that this premise does not apply to SIP.

4.7.	Health care cost growth rate (HCCTR)
A	rate of 2.34% 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 Actuarial Institute (BAI).

The GAMA-EXPERIÊNCIA CEAL table was employed for SIP. This suggests plan experience.

Therefore, we understand that the assumption is appropriate.


5. Independent actuarial calculations

Plan 1

Reconciliation (in R$)	12/31/2016
Present value of actuarial liabilities (PVL)	(5,256,863.00)
Fair value of plan assets	5,093,503.28
Surplus/(Deficit)	(163,359.72)
Non-recoverable surplus (effect of asset limit)	-
Total (liabilities)/net assets to be recognized	(163,359.72)
Total (liabilities)/net assets to be recognized (% of PVL)	(3.11%)

Plan 2

Reconciliation (in R$)	12/31/2016
Present value of actuarial liabilities (PVL)	(108,413,656.00)
Fair to value of plan assets	236,922,000.89
Surplus/(Deficit)	128,508,344.89
Non-recoverable surplus (effect of asset limit)	(128,508,344.89)
Total (liabilities)/net assets to be recognized	-

SIP

Reconciliation (in R$)	12/31/2016
Present value of actuarial liabilities (PVL)	(3,143,772.09)
Fair value of plan assets
Surplus/(Deficit)	(3,143,772.09)
Non-recoverable surplus (effect of asset limit)
Total (liabilities)/net assets to be recognized	(3,143,772.09)

Health Care

Reconciliation (in R$)	12/31/2016
Present value of actuarial liabilities (PVL)	(39,562,208.44)
Fair value of plan assets
Surplus/(Deficit)	(39,562,208.44)
Non-recoverable surplus (effect of asset limit)
Total (liabilities)/net assets to be recognized	(39,562,208.44)

Actuarial obligations were determined according to the principles and standards established by the regulatory bodies, namely the the National Health Agency (NHA) regarding benefits related to health care, and the National Private Pension Bureau (NPPB) regarding retirement and pension benefits, 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 Vested Benefits and Implemented Benefits as shown below, and believe that the calculation methodology and process are adequate.


Plan 1

Present Value of Obligations (in R$)	Actuary	PwC
Implemented	-	-
Vested	5,256,863.00	3,377,170.47
Difference (R$)	(1,879,692.53)
Difference (%)	-35.76%

Plan 2

Present Value of Obligations (in R$)	Actuary	PwC
Implemented	106,083,109.00	103,300,563.81
Vested	2,330,547.00	2,710,691.00
Total	108,413,656.00	106,011,254.81
Difference (R$)	(2,402,401.19)
Difference (%)	-2.22%

SIP

Present Value of Obligations (in R$)	Actuary	PwC
Implemented	3,143,772.09	3,113,884.60
Difference (R$)	(29,887.49)
Difference (%)	-0.95%

Health Care

Present Value of Obligations (in R$)	Actuary	PwC
Implemented	39,562,208.44	39,272,776.00
Difference (R$)	(289,432.44)
Difference (%)	-0.73%

Considering the inherent subjectivity of actuarial calculations of mathematical provisions related to benefit plans, we understand that the differences identified indicate 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 differences presented are acceptable from an actuarial technical point of view, and we understand that the liabilities recorded are properly calculated.

It should be noted that in our determination of the results for Plan 1, a more significant difference was identified in comparison with the results recorded in the balance sheet. According to our analyses, the calculations prepared by Mercer Gama involved an interpolation of individual results from the date in which a participant becomes eligible for normal retirement until the next birthday, which in practice implies postponing the retirement date by up to one year. Given the characteristics of the plan in which the defined-benefit portion is linked to contributions expected to be made during a participant's future employment, an increase in the period during which the participant will remain active implies an increase in liability. We understand that this discrepancy is associated with the parameterization of calculations in the system.

7. Conclusion

Our examinations were based on information provided by both the actuaries responsible for managing the plans and the company, and we considered this information to be appropriate for the preparation of this report.

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.

With regard to the family composition assumption, we understand that the best practice involves the use of the royal family for the beneficiaries. The impact of using an average family can be significant depending on the population of the plan.

The post-employment benefit obligations recorded in the balance sheet, even where figures are presented for some plans with incidental differences which in our opinion relate to the methodology or assumptions adopted, would not, if altered, pose any insolvency risk to the plans.

The variable contribution Plan 1 has an insufficiency of R$163,359.72 that was accounted for as deficit but that do not necessarily represents a financial imbalance, as such insufficiency relates to the volume of future normal contributions expected to be carried into the plan and that will be accounted for in the assets at the time these assets are used to support future plan commitments, thus defeating potential insolvency or liquidity risks.

Plan 2, which is a defined benefit plan, has a technical surplus in the amount of R$128,508,344.89 from excess contributions carried into the plan resulting from the financial performance and actuarial gains accrued over the years. However, such surplus can not be considered an economic benefit for the company, given that the limits enforced by local regulators call for up to 25% of the mathematical provisions to establish a reserve to hedge against plan fluctuations of plan risks. We understand that the plan is not exposed to any insolvency or liquidity risk, since all risks associated with it are supported by the portion of the assets intended as plan coverage. It should be pointed out that part of the plan surplus should inure back to the company on the basis of the rules and time frames established in Resolution CGPC No. 26 dated September 2008. Such amounts will be dimensioned by the actuary in charge of local evaluations over the course of the year corresponding to the third consecutive year in which a determination is made in respect of plan surplus, based on the contribution parity identified in the period.

The HPRP has a liability of R$39,562,208.44. The source of this liability is the difference between the present value of future contributions and the plan cost. This liability may increase or decrease due to reasons such as changes in the profile of the plan cohort, fluctuation of health care costs and adoption of actuarial assumptions that are in keeping with plan features, or an increase the list of medical procedures. Our analyses identified a liability close to that calculated by the actuary. A difference was identified in the amount of R$289,432.43, corresponding to 0.73% indicating that the calculations are correct.

The Severance Incentive Plan (SIP), which affords only health care for a fixed term of 5 years, has a liability of R$3,143,772.09 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, our understanding is that plan benefits have been supported by regular and extraordinary contributions established on the basis of actuarial evaluations prepared by an independent actuary and reviewed by the regulatory body (NPPB) in the case of the pension plans.

With regard to the health care plans, legal compliance is secured in that contributions are made according to the general rules of the plans.

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 November 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 Ceal, dated November 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 Ceal, in accordance with the Contract and it was carried out on the basis of information provided by the administration of Ceal 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	Bresser Plan		14
3.1.1		Context	14
3.1.2		Effects for modeling	14
3.1.3		Scenario 1 – With value adjustment for Bresser Plan	14
3.1.4		Scenario 2 – With no value adjustments for Bresser Plan	14
3.2	Other critical points, necessary adjustments and recommendations		15
3.3	Consent need in Financing Contracts		15
3.4	Deposit of Shares Owned by Eletrobras at FND		18
3.5	Remaining aspects to be considered		18
3.6	Payment methods		18
4.	Purpose of the Auction		20
4.1	Purpose of sale		20
4.2	Assessment of sale feasibility		20
5.	Relevant Aspects of Valuation		21
5.1	Relaxation of regulatory parameters		21
5.2	Debts		21
5.3	Total liabilities		23
5.4	Risks and Contingencies		23
5.4.1		Types of contingencies	23
5.4.2		Current status of contingencies	24
5.4.3		Negotiations to deal with contingencies	25
6.	Assessment of Synergies		26
7.	Adjustments on the Privatization model		31
7.1	Context		31
7.2	Base amount of valuation – Average between valuations of Services A & B		31
7.3	Relevant adjustments for privatization of Ceal		32
7.3.1		Adjustment to comprise updated balance sheet until June 2017	32

Product 11 – Privatization Modeling Proposal

7.3.2

Adjustment related to Advance Payments for Future Capital Increases (AFACs) . 34


7.3.3		Tax adjustments –Tax Losses and Negative Base	35
7.3.4		Adjustment of the relaxation of regulatory parameters	35
8.	Capital and Corporate Structuring		37
8.1	Proposed capital and corporate structuring – Overview		37
8.2	Minimum adjustment of the capital structure – “Stage 1”		39
8.2.1		Symbolic value of shares sale (privatization)	40
8.2.2		Capitalization alternatives	41
8.3	Investor capitalization – “Stage 2”		41
8.4	Eletrobras corporate stake option		43
8.4.1		Justification	43
8.4.2		Eletrobras corporate interest threshold	43
8.4.3		Participation of Eletrobras in the governance of the company	43
8.4.4		Procedure for Eletrobras to increase its shareholding interest	44
8.5	Classes of shares		44
9.	Shares offering to active and retired employees		46
9.1	Mechanism		46
9.2	Definition of active and retired employees		46
9.3	Offer General Conditions		46
9.3.1		Offer take and differentiated conditions	47
9.3.2		Offsetting differentiated conditions to Eletrobras	47
9.3.3		Offer Procedure and Purchase Limits	48
9.3.4		Follow-up by minority stakeholders of investor underwriting	48
9.3.5		New controller shares repurchase obligation	48
9.4	Shares not acquired by active and retired employees		49
Section II - Privatization proposal			50
10.	Summary of Ceal’s privatization proposal		50
10.1	Ceal’s corporate structure		50
10.2	Definition of Ceal's sales value		50
10.2.1		Result of economic and financial evaluations	50
10.2.2 Balance update adjustment			51
10.2.3		Regulatory parameters relaxation adjustment	53
10.3	Sale vs. Liquidation Evaluation and consequent “pure” concession granting		53
10.4	Potentially convertible liabilities		54
10.5	Eletrobras capitalization value - “Stage 1”		54
10.6	Share offer to Active and Retired Employees		55


		Product 11 – Privatization Modeling Proposal

10.7	Investor’s capitalization – “Stage 2”		56
10.8	Ceal's final corporate structure		57
10.9	Investor’s obligations		57
10.9.1		Financial obligations	57
10.9.2		Obligations defined in contract	58
11.	Ceal’s privatization schedule		59
Section III - Privatization Proposal – Without Agreement			60
12.	Summary of Ceal’s privatization proposal		60
12.1	Ceal’s Corporate Structure		60
12.2	Ceal’s Sales Price Definition		60
12.2.1		Result of economic-financial evaluations	60
12.2.2		Balance update adjustment	61
12.2.3		Regulatory parameters relaxation adjustment	63
12.3	Sale vs. Liquidation Evaluation and consequent “pure” concession granting		63
12.4	Potentially convertible liabilities		64
12.5	Eletrobras capitalization value – “Stage 1”		64
12.6	Shares offering to active and retired employees		65
12.7	Investor capitalization – “Stage 2”		67
12.8	Ceal’s final corporate structure		67
12.9	Investors Obligations		68
12.9.1		Financial obligations	68
12.9.2		Obligations defined in the Purchase Agreement	68
13.	Ceal’s privatization schedule		69
Section IV - Auction Model Proposal			70
14.	Model and Procedure of Auctions		70
14.1	Proposed model		70
14.2	Sequence		71
14.3	The right to participate		71
14.4	The right to withdraw bids		72
14.5	Bid procedures and values		72

14.6	Auction Value base for ‘Combined Discount Index in the Regulatory Flexibility and


	Grant’	74
14.7	Auction´s 2nd stage ranking criteria	76
14.8	Auction procedures	78

Product 11 – Privatization Modeling Proposal

Introduction

This document refers to the report of Ceal 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 IV - 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 Ceal's shares, in addition to the share offer conditions to employees, investors’ obligations and expected privatization schedule.

In Section IV - 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 Ceal’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 Ceal 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’s 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 stakeholders
To make possible alternatives and solutions that allow generating value to the current stakeholder 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 stakeholders, 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.

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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 phases 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 and non-technical losses 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, Non-Technical Losses 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

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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’s distributors, relevant issues were identified affecting significantly the value of the stakeholder of the companies.

Initially, it was assessed that these organizations have amounts of debts of high values. These debts were accumulated by Eletrobras’s 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 stakeholder.

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 stakeholders of these companies is positive in light of regulatory flexibilizations granted, the relaxed parameters must be readjusted so that the value to the stakeholders of these companies is equal to zero. Thus, the possibility that the consumers of the areas of the grant in question are burdened with additional exceptional tariffs to those necessary for the companies holders of the grant operate under financial balance is eliminated.

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3.	Relevant aspects of the Privatization Process
3.1	Bresser Plan
3.1.1	Context

It is appropriate to emphasize the collective labor lawsuit brought against Ceal by the Union of Workers of Urban Industries of the State of Alagoas, as a procedural substitute, for the payment of salary differences arising from the economic measures established by Decree 2.335 / 87 (Bresser Plan).

For this lawsuit, a high loss risk (probable loss) was identified and the involved value of approximately R$ 1,409,199,636.60 (updated to December 2016) referring to the so-called Bresser Plan.

The proceeding is currently in the execution phase when payable amounts are to be defined. To guarantee execution, common shares and preferred shares of Ceal, as well as real estate, were offered. There is no formal decision about the assets offered as execution guarantee.

In view of the amount and its loss risk, this lawsuit represents a risk potential and impediment to Ceal privatization process. More details regarding the lawsuit are included in

Ceal’s due diligence legal reports.

3.1.2 Effects for modeling

Due to the uncertainty regarding the values of the action related to the Bresser Plan up to the preparation of this report, two scenarios were considered in the privatization model: i) Scenario 1 - With value adjustment for Bresser Plan; and ii) Scenario 2 – With no value adjustments for Bresser Plan.

The scenarios are presented below:

3.1.3 Scenario 1 – With value adjustment for Bresser Plan

It was considered for all analyses made in this scenario that final costs of the lawsuit brought against Ceal referring to Bresser Plan would be R$ 129,738,947.39, and not its full value. This is the most up-to-date indicator of value made by the competent bodies involved with the action.

Thus, the difference (R$ 1,279,460,689.21) between full value of the lawsuit and its adjusted value was reincorporated into the value equity of the distributor, as in the economic and financial analyses made by Services A and B, the value under discussion was entirely written down.

Values of this scenario resulting from model are show in Section II - Privatization proposal -With Agreement to this report.

3.1.4 Scenario 2 – With no value adjustments for Bresser Plan

It was considered for all analyses made in this scenario that final costs of the lawsuit brought against Ceal referring to Bresser Plan would be their fully value (R$ 1,409,199,636.60). Consequently, there was no change in the results of the distributor's valuation report.

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Values of this scenario resulting from model are show in Section III - Privatization Proposal

Without Agreement to this report
Other critical points, necessary adjustments and recommendations

In Ceal’s case, there are no other critical impediments to its privatization process.

During the process of Legal Due Diligence of Ceal 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.

3.3 Consent need in Financing Contracts

Some financing contracts signed by the distributors have the need to obtain prior and express consent from the creditor in the event of a change of control of Ceal.

Otherwise, according to the terms of each contract, there may be legal and/or financial implications to Ceal, 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 agreements with the need for consent from the creditor are listed below, and must have their applications addressed by Ceal and Eletrobras:


No.	Type of document	Lender	Date of Signature

	Private Debt
1		Eletrobras	09/09/2013
Acknowledgement Instrument
	Private Debt
2		Eletrobras	09/15/ 2015
Acknowledgement Instrument
	Private Debt
3		Eletrobras	No date
Acknowledgement Instrument
	Private Debt
4		Eletrobras	No date
Acknowledgement Instrument
	Private Debt
5		Government	12/31/ 1997
Acknowledgement Instrument
	Credit Line Opening
6		Banco IBM S.A.	08/07/2015
	Agreement

Contract No. 1

Creditor:	Eletrobras
Intervenor:	Caixa Econômica Federal
Object:	CEAL’s recognition of a balance due to Eletrobras in the amount of R$
	19,408,802.34, as a result of a long-term loan granted under agreement ECF-
	3055/2013
Amount:	R$ 19,408,802.34
Interests:	Interest rate corresponding to SELIC calculated pro rata temporis over the


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	balance due
Grace Period:	180 days
Principal payment:	24 monthly, equal and successive installments
Guarantees:	Binding own revenue to pay amounts due and not paid
Relevant obligations:	N/A
Anticipated maturity:	Eletrobras may consider the agreement as terminated in advance in the event
	of (i) the eventual expiration or non-renewal of the electric energy distribution
	concession; (ii) change in the corporate control of CEAL
Other important clauses:	Debt backed by the issue of a promissory note
	The Caixa Econômica Federal undertakes to transfer to Eletrobras the
	resources of CEAL's accounts until full satisfaction of the defaulted value

	Contract No. 2
Creditor:	Eletrobras
Intervenor:	Caixa Econômica Federal - CEF
Object:	Recognition of debt in the amount of R$ 15,169,596.08
Amount:	R$ 15,169,596.08
Interests:	Interest corresponding to the variation accrued in the month of payment of the
	SELIC rate, plus a spread of 0.5% per year, calculated pro rata temporis on the
	debit balance
Grace Period:	December 31, 2013
Principal payment:	17 monthly, equal and successive sucessivas
Guarantees:	Binding own revenue to pay amounts due and not paid
Relevant obligations:	N/A
Anticipated maturity:	Eletrobras may consider the agreement as terminated in advance in the event
	of (i) the eventual expiration or non-renewal of the electric energy distribution
	concession; (ii) change in the corporate control of CEAL
Other important clauses:	Debt backed by the issue of a promissory note
	The Caixa Econômica Federal undertakes to transfer to Eletrobras the
	resources of CEAL's accounts until full satisfaction of the defaulted value

	Contract No. 3
Creditor:	Eletrobras
Intervenor:	Caixa Econômica Federal
Object:	CEAL’s recognition of a balance due to Eletrobras in the amount of R$
	6,466,163.26, by virtue of the amounts calculated in the process of termination
	of agreement ECF-250/2009
Amount:	R$ 6,466,163.26
Interests:	Interest rate corresponding to SELIC rate, calculated pro rata temporis on the
	balance due
Grace Period:	4 months
Principal payment:	12 monthly, equal and successive installments
Guarantees:	Binding own revenue to pay amounts due and not paid
Relevant obligations:	N/A
Anticipated maturity:	Eletrobras may consider the agreement as terminated in advance in the event
	of (i) the eventual expiration or non-renewal of the electric energy distribution
	concession; (ii) change in the corporate control of CEAL
Other important clauses:	Debt backed by the issue of a promissory note
	The Caixa Econômica Federal undertakes to transfer to Eletrobras the
	resources of CEAL's accounts until full satisfaction of the defaulted value

	Contract No. 4
Creditor:	Eletrobras
Intervenor:	Caixa Econômica Federal
Object:	CEAL’s recognition of the balance due to Eletrobras in the amount of R$
	16,724,684.67 by virtue of the amounts calculated in the process of termination
	of agreement ECFS-171/2007


	16


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Amount:	R$ 16.724.684,67
Interests:	Interest rate corresponding to SELIC rate, calculated pro rata temporis on the
	balance due
Grace Period:	4 months
Principal payment:	12 monthly, equal and successive installments
Guarantees:	Binding own revenue to pay amounts due and not paid
Relevant obligations:	N/A
Anticipated maturity:	Eletrobras may consider the agreement as terminated in advance in the event
	of (i) the eventual expiration or non-renewal of the electric energy distribution
	concession; (ii) change in the corporate control of CEAL
Other important clauses:	Debt backed by the issue of a promissory note
	The Caixa Econômica Federal undertakes to transfer to Eletrobras the
	resources of CEAL's accounts until full satisfaction of the defaulted value

	Contract No. 5
Creditor:	Federal Government
Guarantor:	Estado de Alagoas
Intervenor:	Banco do Brasil S.A. and Caixa Econômica Federal
Object:	Confession of debt in the amount of R$ 1,110,628.81
Amount:	R$ 1,110,628.81
Interests:	Monetary adjustment according to US dollar variation and interest on daily
	debit balances, variable rate according to the type of bonds
Grace Period:	N/A
Principal payment:	N/A
Guarantees:	Assignment of credits with resource that are made to the deposit account of
	CEAL, before Caixa Econômica Federal, up to the limit sufficient to pay the
	installments and other charges due at each due date
Relevant obligations:	N/A
Anticipated maturity:	N/A
Other important clauses:	N/A

	Contract No. 6
Creditor:	Banco IBM S.A.
Guarantor:	Eletrobras
Object:	Opening of a fixed credit line for acquisition of equipment, software and
	information technology services
Value:	Opening of revolving credit of
	R$ 10,736,342.85
Interest:	In case of payment delay or failure to comply with any obligation, the
	outstanding balance will be subject to moratorium interest of 1% per month
	and a fine of 2% on the amount of the debt
Period of grace:	N/A
Principal value payment:	N/A
Collaterals:	Bank credit note with each disbursement
Relevant obligations:	CEAL undertakes not to carry out operations that imply corporate
	restructuring, transfer of control, sale of assets or reduction of capital, or any
	other operation that adversely affects its economic and financial condition,
without prior and express consent of Banco IBM

Accelerated due date:	CEAL may request the maturity at any time, by means of written notification
	and payment of the balance due
Other importante clauses:	Furthermore, IBM may consider the agreement terminated in the event of (i)
	direct or indirect transfer or disposition of the corporate control of CEAL,
	without prior agreement of IBM; as well as (ii) spin-off, merger, incorporation,
	or reduction of the share capital of CEAL, without prior agreement of Banco
	IBM

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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 Ceal met the requirements from these four perspectives, it is concluded that the company would be able to be sold in an auction associated with the grant of 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 Ceal.

Such ANEEL Technical Notes loosened for the company the regulatory values of the PMSO, Non-Technical Losses 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 September 28 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 14.6 - 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 this nature area mostly overdue obligations for the payment of fuel supply agreements (therefore, rated as debt by the Accounting-Equity Due Diligence) due by a few distributors that are not party to the privatization process.

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 Ceal 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 Ceal.

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 Ceal, according to their risk rating level.


In R$ MM
DETAILING OF CEAL CONTINGENCIES

	Likely	Probable	Remote	Total
Litigious	1,364.64	-	-	1,364.64
Taxes	13.81	553.74	16.25	583.80
Labor	6.25	49.44	-	55.69
Actuarial	(1.88)	-	-	(1.88)
Total	1,382.82	603.18	16.25	2,002.25

In %
DETAILING OF CEAL CONTINGENCIES

	Likely	Probable	Remote	Total
Litigious	99%	0%	0%	68%
Taxes	1%	92%	100%	29%
Labor	0%	8%	0%	3%
Actuarial	0%	0%	0%	0%
Total	69%	30%	1%	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.

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In the balance of contingencies classified as 'Probable', such as Litigation, there is the full amount of approximately R$ 1.4 billion related to the labor lawsuit of the Bresser Plan filed against the distributor, in addition to almost R$ 45 million in tax lawsuits favorable to the distributor (which are deducted against the total amount of contingencies). In the balance classified as 'Possible', in Tax segment, there are approximately R$ 455 million regarding nontechnical energy losses.

In addition to the provided contingencies, there are also contingencies concerning environmental adaptations in the amount of R$ 29,581,979.15 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 stakeholder’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.

In addition, Eletrobras was identified, due to its State nature and current financial condition, to have legal and financial limitations to offer warranties to the investors in relation to such contingencies.

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 stakeholders. 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, Ceal 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 Ceal 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 Ceal, the Enterprise Values 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 CEAL - MEAN OF SERVICES A AND B


Service A	R$	1,994,373,551.48
Service B	R$	2,446,562,300.47
Mean of Services A and B	R$	2,220,467,925.98
Percentage variation¹		18%

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 Ceal.

7.3	Relevant adjustments for privatization of Ceal
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 Ceal (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:


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

Product 11 – Privatization Modeling Proposal

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 on the equity value, its balances – included into the Liabilities in the account of ‘Loans and Financing’ – were positively reincorporated into the amount to the stakeholder.

It is also stressed that, for the accounts of ‘Assets’ (property and rights), when there is positive variation, they increase the stakeholder’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’.

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For positive variation, the stakeholder’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 stakeholder’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 12.2.2 - 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.

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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 stakeholder of Ceal 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 stakeholder is zero. That is, in case Ceal had negative value to the stakeholder before the relaxation of regulatory parameters, and such relaxation results in positive value to the stakeholder, the value of the relaxed parameters must be reduced to the amount necessary for the value to stakeholder to be equal zero.

The relaxed regulatory parameters of Ceal 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 stakeholder, 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 stakeholder. In addition, the RGR PPST will also be used as an auction variable.

It is also worthwhile noting that in case the value to stakeholder 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 stakeholder 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 Ceal, 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 Stakeholders 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.

Product 11 – Privatization Modeling Proposal

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 Ceal.

8.2.2 Capitalization alternatives

It is recommended that the choice on the alternatives to perform the adjustments to the capital structure of Ceal 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 Ceal, 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;
b)	Optimizing the capital structure of the company. After the “Stage 1”, against a symbolic equity value, the capital structure of Ceal shall consist of approximately 100% of debt.
	Thus, the company is not duly capitalized to make the investments and other demands of cash;

Product 11 – Privatization Modeling Proposal

c)	Demonstrating to society and stakeholders that the privatization of Ceal 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.

The definition of the capitalization value took two factors into consideration: 1) capital structure of companies after adjustments in “Stage 1”; and 2) reference leverage for electric power distributors in Brazil considering that Eletrobras remains as a minor partner of the companies.

In the first factor, it was considered that the capital structure that will serve as basis to be adjusted by the investor is that of the post-privatization operation. That is, any possible debt conversions by Eletrobras have already been considered in order to reach the value defined for the disposal of the distributor’s shares held by Eletrobras to the investor and consequent privatization of Ceal. At the moment, the company's leverage is close to the theoretical limit, since there is no significant equity value.

In the second factor, a reference capital structure was used for companies of the industry, with a 54% financial leverage. Leverage is calculated as the modulus of net debt divided by the sum of the net debt value modulus and the company's equity value, as follows: (|Net Debt| / [|Net Debt| + Equity Value]).

The value of 54% defined for the investor's post-capitalization leverage goal was calculated according to the methodology used by Consórcio Mais Energia B. It considers the average of the current weighted average capital cost ("WACC") of the most comparable companies leveraged in the industry. The calculation of the value required from the investor also considered that Eletrobras will exercise the option to reach the maximum value of ownership (30%) in Ceal through debt conversion, after the privatization.

If Eletrobras does not partially or fully exercise its option, there is no damage to the operation or the investor. The main reflex is that Ceal will have a more leveraged capital structure than the suggested level (54%). However, as a function of the capitalization made by the investor, the distributor is already more prepared to face the relevant investments foreseen for the first years after privatization. Likewise, the reasons to require the investor’s capitalization remain to be met.

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 Ceal is continuously achieved or even to face cash demands. Accordingly, in case Eletrobras decides to remain as a stakeholder 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 minor stakeholders (including Active and Retired Employees who join the distributor’s Share Offer).

The capitalization values of the investor are listed in Section II - Privatization proposal.

Product 11 – Privatization Modeling Proposal


8.4	Eletrobras corporate stake option
8.4.1	Justification

The privatization modeling considers the possibility of Eletrobras continuing as a minor stakeholder of Ceal after the disposal of the shareholding control of such distributor. When holding a shareholding interest, even if assuming the risks as a stakeholder 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 Ceal 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 Ceal 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 minor 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 Ceal. Thus, eventual risks of legal inquiries related to specific corporate adjustments to the privatization procedure may be mitigated.

However, the stakeholders 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 Ceal 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.

8.4.3 Participation of Eletrobras in the governance of the company

In the presented model, although Eletrobras holds shares of Ceal, the state-owned company should preserve minimum rules in the management and governance of Ceal. 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.

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For such, it proposes that, regardless of the shareholding organization of Ceal after the privatization, a stakeholders 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 minor stakeholder duly protected. Privatized, Ceal 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 minor 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 stakeholders agreement and in the obligations of the eventual investor when acquiring Ceal. 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 stakeholders agreement.

8.4.4 Procedure for Eletrobras to increase its shareholding interest

The purchase and sale agreement of the distributor and the stakeholders 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 Ceal. 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 minor stakeholders – including active and retired employees acquiring shares of Ceal. 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.

As mentioned, the capitalization to be made by Eletrobras may also be made using debt credits held by the state-owned company with Ceal. 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.

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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 Ceal.

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.

Product 11 – Privatization Modeling Proposal

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 - Share offer to . 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 stakeholders of the company.

The value per share (or lot of shares) for the eventual follow-up of the capitalization by the active and retired employee 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 employees are not prohibited from selling shares they acquired from Ceal 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

Actuarial due diligence, Human Resources due diligence and Environmental Evaluation Report).

Detailing of information of these reports relevant for the model is 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, Ceal's balance sheet accounts have been updated to reduce the value gap between the valuation base date (December 2016) and the latest earnings release available (June 2017).

The balances of the adjusted amounts are listed below, per account, and consolidated in a table, including the positive or negative effect they have on the adjustment value:


ASSETS (IN R$ 000) - CEAL	Dec/16	Jun/17 Adjustment
Current
Cash and cash equivalents	21,804	72,667	50,863
Securities	14,709	3,007	(11,702)
Clients	313,949	337,307	23,358
Taxes to be recovered	12,625	12,962	337
Reimbursement rights	73,126	27,305	(45,821)
Warehouse	8,822	9,737	915
Services in progress	6,421	7,204	783
Regulatory asset	65,585	55,422	(10,163)
Sureties and judicial deposits	-	-	-
Financial asset	-	-	-
Assets destined to disposal	-	-	-
CDE repayment	-	-	-
Others	29,302	31,862	2,560
Non-current
Clients	313,947	307,947	(6,000)
Taxes to be recovered	4,264	4,477	213
Taxes to social contributions	-	-	-
Sureties and related deposits	60,119	73,960	13,841
Reimbursement rights	-	-	-
Regulatory asset	22,130	47,766	25,636
Others	564	564	-
Investments	168	168	-
Total asset adjustment			44,820

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LIABILITIES (IN R$ 000) - CEAL	Dec/16	Jun/17	Adjustment
Current
Loans and Financing	34,794	248,236	213,442
Lease	-	-	-
Debt charges	-	-	-
Suppliers	164,322	142,001	(22,321)
Taxes payable	76,789	79,181	2,392
Social and labor obligations	18,392	23,043	4,651
Reimbursement obligations	45,373	38,764	(6,609)
Accounts payable to related parties	-	-	-
Estimated obligations	-	-	-
Sectorial charges	30,955	27,809	(3,146)
Post-employment benefits	2,389	914	(1,475)
Regulatory liabilities	115,289	31,912	(83,377)
Research and development	-	-	-
Financial liabilities	-	-	-
Others	20,268	23,669	3,401
Non-current
Loans and Financing	1,427,343	1,504,984	77,641
Lease	-	-	-
Suppliers	-	-	-
Taxes payable	87,794	64,933	(22,861)
Reimbursement obligations	-	-	-
Accounts payable to related parties	-	-	-
Provision for unsecured liability in controlled	-	-	-
Post-employment benefits	41,219	41,219	-
Regulatory liability	6,801	25,976	19,175
Sector charges	17,870	24,135	6,265
Advance for future capital increase	159,155	159,155	n/a
Research and development	-	-	-
Others	33,603	34,273	670
Total liabilities adjustment			187,848

CONSOLIDATED VALUE OF ADJUSTMENTS (IN R$ 000) - CEAL

(+/-) Asset Adjustment		44,820
(+/-) Liabilities Adjustment		(187,848)
(+) RGR PPST Reincorporation		336,304
(-) Reclassification of AFACs as Debt		(159,155)
(-) Tax Adjustments (Tax Loss and Negative Base)		(37,684)
Consolidated value of adjustments		(3,563)

The consolidated value of the account balances in the referred to period was used as adjustment value:


CEAL VALUATION ADJUSTMENTS


Mean of Services A and B	R$	(890,096,393.84)
Bresser Plan Reversal	R$	1,279,460,689.21
Consolidated adjustments	R$	(3,563,184.05)
Adjusted Equity Value	R$	385,801,111.32

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, if the

“Adjusted Equity Value” is greater than zero, the relaxed of the regulatory parameters should be reduced to result in an equity value equal to zero. If the “Adjusted Equity Value” is lower than zero, there are no relaxed reductions of the tariff parameters and no adjustment is made to the equity value.


	CEAL TARIFF RELAXATION ADJUSTMENTS
	Adjusted Equity Value	R$	385,801,111.32
	Reduction adjustment of tariff relaxation	R$	(385,801,111.32)
	Final Equity Value	R$	-
	Reduction percentage of tariff relaxation		99,2 %

10.3	Sale vs. Liquidation Evaluation and	consequent “pure” concession
	granting

One of the relevant alternatives that Eletrobras stakeholders have is to check if it is economically interesting to sell Ceal associated with the concession grant.

If the state-owned company wants to sell the company associated with the concession, the auction will be held. Otherwise, or if the proposed adjustments are not acceptable and/or made by Eletrobras, an auction must be held only for sale of the concession.

Thus, a comparative analysis was made between the sale value of the distributor associated with the concession and the liquidation value of the company. So, it is possible to assess if the sale is more attractive for the state-owned company.

Since the sale value considers adjustments to the equity value, the adjustments were also considered in the estimation of the liquidation value. However, there was an exception for the Tax Adjustments and Negative Base, as they do not impact the liquidation value, and for the AFACs, as they can be paid in full in case the distributor is not sold.

As shown below, in CEAL’s case, the best economic option is to sell the company, considering the value of the assets and concession. The balance between selling and liquidating is favorable to the first option, given the following chart:

Product 11 – Privatization Modeling Proposal


CONVERSION AND ASSUMPTION OF CEAL’S DEBTS

Final Equity Value	R$	-

Stage 1 - Eletrobras Capitalization	R$	50,000.00
Debt conversion	R$	50,000.00
Debt assumption	R$	-
Adjusted Equity Value – Post Stage 1	R$	50,000.00

Price per share for Eletrobras underwriting	R$	1.06559514
Total shares subscribed by Eletrobras		46,923

The amount of new shares subscribed by Eletrobras from these operations is defined according to the share issue price:

It is in this stage that Ceal’s privatization technically occurs. After capital adjustment, 10% of the shares must be offered to Active and retired employees, 90% of the shares minus one must be sold to the potential investor and one share must remain Eletrobras property. Owning this share unit is necessary in case Eletrobras wants to increase its ownership interest.

10.6 Share offer to Active and Retired Employees

As mentioned, the Brazilian Legislation requires that, in a federal privatization, part of the shares held either directly or indirectly by the Federal Government be alienated to active and retired employees under different conditions.

Thus, shares of the distributor owned by Eletrobras, must be offered to its active and retired employees, in accordance with the following conditions:

Product 11 – Privatization Modeling Proposal


OFFERING TO ACTIVE AND RETIRED EMPLOYEES FROM CEAL

Conditions of differentiated offer
Base value of sale share	R$	0.00007251
Discount over the disposal value for the Investor		11.02%
Share value for differentiated offer	R$	0.00006452

Shares to be offered
Amount of Eletrobras shares		689,571,307
Percentage of Eletrobras shares offered		10.06494460%
Total amount offered		69,404,970
Ordinary		68,061,648
Preferential		1,343,322
Total valued of shares offered	R$	5,032.47
Value of shares offered with discount	R$	4,477.74
Value of compensation payable by the Investor	R$	554.73

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		447,774
Amount of shares in the lot		155
Amount of Ordinary shares in the lot		152
Amount of Preferential shares in the lot		3

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$	0.00007251
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$	0.00007976
Correction Index		SELIC
Re-purchasing price per share	R$ 0.00007976 + SELIC

1) In the model defined, the conditions for buyback by the investor of the shares offered are exclusive rights of the active and retired employees who acquire them, or individuals who acquire them by succession (due to the death of the original purchaser). In case the shares are sold to third parties the buyback benefits are cancelled.

The investor must compensate Eletrobras for the share offer under conditions other than those offered to the employees (according to Decree 2.594/98), in addition to complying with obligations reported in this report, as indicated in Item 12.9 – Investor’s obligations.

Any shares not eventually purchased by active and retired employees must be acquired by the investor at the end of the sale process of these shares, at the price already including the proposed discount. The acquisition of the remaining shares at the discount price occurs so that the investor is not charged in duplicate for the financial compensation made to Eletrobras regarding the sale of the shares to active and retired employees, since compensation to the state-owned company will be made.

10.7 Investor’s capitalization – “Stage 2”

In the proposed sale model for purposes of auction settlement, the investor willing to purchase Ceal must make a capital contribution by subscribing new shares of the company. This capital will be paid in cash.

Product 11 – Privatization Modeling Proposal


CAPITALIZATION OF INVESTOR ON CEAL
Adjusted Equity Value – Post Stage 1	R$	50,000.00
Value to be paid by the Investor	R$	545,770,485.33
Adjusted Equity Value – Post Stage 2	R$	545,820,485.33
Amount of share to subscribe to the Investor		7,526,953,337,861
Price per share subscribed	R$	0.00007251

10.8 Ceal's final corporate structure

By the end of the privatization process Ceal must submit the following corporate structure considering full adhesion of the active and retired employees to the share offer:


CEAL’S FINAL CORPORATE STRUCTURE

Total shares				8,370,010,415,171
Capital stock			R$	1,341,653,392. 10
Nominal value of shares			R$		0.00016029

Interest	Ordinary shares	Preferential shares		Total Shares	(%)
Investor	7,402,266,527,625	125,306,976,572		7,527,573,504,197	89.9351%
Eletrobras	1	0		1	0.0000%
Active and Retired Employees	826,131,680,439	16,305,230,534		842,436,910,973	10.0649%
Other Minorities	0	0		0	%

Shares per Class				Total Shares	(%)
Ordinary				8,228,398,208,065	98.3081%
Preferential				141,612,207,106	1.6919%

Note: assumes full monitoring by the Active and Retired Employees of the capitalization made by the investor. The final corporate structure, however, varies according to the level of adhesion to the offer to the Active and Retired Employees, and the level of monitoring of the capitalization.

The final corporate structure, however, varies according to the level of adhesion of Ceal’s active and retired employees to the share offer.

Any shares not eventually purchased by active and retired employees will be purchased from Eletrobras by the investor. Eletrobras final equity interest, however, will suffer no change.

If the Eletrobras chooses not to increase its equity interest, the remaining shares it holds must be sold at its base price to the investor within six (6) months from the auction date.

10.9 Investor’s obligations

In order to acquire Ceal, the interested investor must commit to the following obligations established in this sales proposal:

10.9.1	Financial obligations
	i.	Subscribing and paying the company’s capital stock
	ii.	Pay Eletrobras the compensation amount resulting from the different conditions applicable to the share offer to Ceal’s active and retired employees.
	iii.	Buy from Eletrobras the remaining shares of the share offer made to the active and retired employees.

Product 11 – Privatization Modeling Proposal

iv.	Meet requests regarding the share offer to the active and retired employees according to the different conditions established.

The amounts of the financial obligations are defined below:


INVESTOR OPERATIONS ON CEAL

Total paid during disposal of Ceal control	R$	45,522.26
Total value from sale of shares	R$	44,967.53
Amount of sale shares		620,166,336
Price per share	R$	0.00007251
Value compensation to Eletrobras for the offer to active and retired employees	R$	554.73

Capitalization - Stage 2
Amount of subscribed shares		7,526,953,337,861
Price per subscribed share	R$	0.00007251
Value to be paid by the Investor	R$	545,770,485.33

Other Obligations
Re-purchase of remainder from the offer to employees and retired
Re-purchasing price	R$	0.00006452
Re-purchasing amount		Totality of remainder
Maximum value to be re-purchased	R$	4,477.74


Re-purchase of shares from employees and retired
Re-purchasing deadline		03 Years
Base value per share for re-purchasing purposes	R$	0.00007251
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$	0.00007976
Correction Index		SELIC
Re-purchasing price per share		R$ 0.00007976 + SELIC

10.9.2	Obligations defined in contract
	Some additional obligations are recommended as follows:
	i. Meeting the social provisions relating to the active and retired employees according to the sample proposed below:

Contractual obligations proposals

Private Pension Health Insurance

Re-qualification of dismissed

Maintain current conditions for two years Maintain current conditions for two years

Structure re-qualification program compatible with the best market practices

ii.	Meeting the governance provisions relating to Eletrobras stakeholders, according to the sample proposed below:


	Product 11 – Privatization Modeling Proposal

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

11. Ceal’s privatization schedule

In order to achieve Ceal’s privatization, a schedule is proposed¹with the key stages of the privatization process. The objective is to provide an overview of the process complemented by a detailed schedule in specific reports and legal drafts.

The schedule considers the legal terms and time required to carry out the corporate and financial adjustments, as well as the compliance with contractual and corporate aspects. We note that this schedule is preliminary and may adjusted to meet the requirements of the privatization process.


Activity	Term
CPPI Resolution Publication	D + 0
Data Room Opening	D + 9 days
Eletrobras Extraordinary General Meeting	D + 50 days
Distributor Extraordinary General Meeting	D + 63 days
Holding a Public Hearing	D + 70 days¹
Publication of the Privatization Announcement	D + 92 days
Auction	D + 145 days²
Auction homologation	D + 168 days²
Distributor Extraordinary General Meetings	D + 177 days
Auction settlement and contract signing	D + 177 days
Distributor Extraordinary General Meeting	D + 207 days³

Note: Subject to the effective date of the CPPI resolution and Eletrobras internal terms for corporate procedures (sometimes counted in business days), the estimated terms may be changed.

1) According to article 39 of Law 8.666/93, 15 business days are necessary before publishing the Announcement. Since there should be six public hearings, 2 weeks were estimated. Therefore, if more days are required so such public hearings be held, the schedule will be changed accordingly 2) Suggested term once such deadlines are set forth in the Announcement 3) Suggested term but not lower than 30 days counted from the date of the last Extraordinary General Meeting of the Distributor

Product 11 – Privatization Modeling Proposal

Section III - Privatization Proposal – Without Agreement

12. Summary of Ceal’s privatization proposal

This summary shows the recommendations of the Consórcio Mais Energia B relating to Ceal’s privatization. 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.

12.1 Ceal’s Corporate Structure

The corporate structure on the base date of 12/31/2016 is organized according to the table below:


CURRENT CEAL’S CORPORATE STRUCTURE

Total shares		689,524,384
Capital stock	R$	734,753,835.07
Nominal value of shares	R$	1. 06559514

Interest	Shares	(%)
Eletrobras	689,524,384	100.00%
Minorities	0	- %

Classes of shares	Shares	(%)
Ordinary	677,858,321	98.31%
Preferential	11,666,063	1.69%

12.2	Ceal’s Sales Price Definition
	12.2.1 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 CEAL - MEAN OF SERVICES A AND B


Service A	R$	(1,116,190,768.34)
Service B	R$	(664,002,019.35)
Mean of Services A and B	R$	(890,096,393.84)

The definition of the economic value of Ceal followed the definitions and instructions of Decree no. 2.594/98, Article 30, Paragraph 3, taking into account several aspects relevant to a valuation:

c)	Improvement of the operational efficiency level of the company, equal to or even higher than the efficiency levels of the market; and

Product 11 – Privatization Modeling Proposal

d)	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).

The detailing of the relevant information of these reports for the modeling are described in Section I - Privatization context.

12.2.2 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 Ceal 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) - CEAL	Dec/16	Jun/17 Adjustment
Current
Cash and cash equivalents	21,804	72,667	50,863
Securities	14,709	3,007	(11,702)
Clients	313,949	337,307	23,358
Taxes to be recovered	12,625	12,962	337
Reimbursement rights	73,126	27,305	(45,821)
Warehouse	8,822	9,737	915
Services in progress	6,421	7,204	783
Regulatory asset	65,585	55,422	(10,163)
Sureties and judicial deposits	-	-	-
Financial asset	-	-	-
Assets destined to disposal	-	-	-
CDE repayment	-	-	-
Others	29,302	31,862	2,560
Non-current
Clients	313,947	307,947	(6,000)
Taxes to be recovered	4,264	4,477	213
Taxes to social contributions	-	-	-
Sureties and related deposits	60,119	73,960	13,841
Reimbursement rights	-	-	-
Regulatory asset	22,130	47,766	25,636
Others	564	564	-
Investments	168	168	-
Total asset adjustment			44,820

Product 11 – Privatization Modeling Proposal


LIABILITIES (IN R$ 000) - CEAL	Dec/16	Jun/17	Adjustment
Current
Loans and Financing	34,794	248,236	213,442
Lease	-	-	-
Debt charges	-	-	-
Suppliers	164,322	142,001	(22,321)
Taxes payable	76,789	79,181	2,392
Social and labor obligations	18,392	23,043	4,651
Reimbursement obligations	45,373	38,764	(6,609)
Accounts payable to related parties	-	-	-
Estimated obligations	-	-	-
Sectorial charges	30,955	27,809	(3,146)
Post-employment benefits	2,389	914	(1,475)
Regulatory liabilities	115,289	31,912	(83,377)
Research and development	-	-	-
Financial liabilities	-	-	-
Others	20,268	23,669	3,401
Non-current
Loans and Financing	1,427,343	1,504,984	77,641
Lease	-	-	-
Suppliers	-	-	-
Taxes payable	87,794	64,933	(22,861)
Reimbursement obligations	-	-	-
Accounts payable to related parties	-	-	-
Provision for unsecured liability in controlled	-	-	-
Post-employment benefits	41,219	41,219	-
Regulatory liability	6,801	25,976	19,175
Sector charges	17,870	24,135	6,265
Advance for future capital increase	159,155	159,155	n/a
Research and development	-	-	-
Others	33,603	34,273	670
Total liabilities adjustment			187,848

CONSOLIDATED VALUE OF ADJUSTMENTS (IN R$ 000) - CEAL

(+/-) Asset Adjustment			44,820
(+/-) Liabilities Adjustment		(187,848)
(+) RGR PPST Reincorporation		336,304
(-) Reclassification of AFACs as Debt		(159,155)
(-) Tax Adjustments (Tax Loss and Negative Base)		(37,684)
Consolidated value of adjustments			(3,563)

The consolidated value of the balances of the entries for the respective period was used as the adjustment value:

CEAL’S VALUATION ADJUSTMENTS


Mean of Services A and B	R$	(890,096,393.84)
Bresser Plan Reversal	R$	-
Consolidated adjustments	R$	(3,563,184.05)
Adjusted Equity Value	R$	(893,659,577.89)

Product 11 – Privatization Modeling Proposal

12.2.3 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.


	CEAL’S TARIFF RELAXATION ADJUSTMENTS
	Adjusted Equity Value	R$	(893,659,577.89)
	Reduction adjustment of tariff relaxation	R$	-
	Final Equity Value	R$	(893,659,577.89)
	Reduction percentage of tariff relaxation		- %

12.3	Sale vs. Liquidation Evaluation	and consequent “pure” concession
	granting

One of the relevant alternatives that Eletrobras stakeholders have is to evaluate the economic feasibility in selling Ceal 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 Ceal, 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 CEAL’S DEBTS

Final Equity Value	R$	(893,659,577.89)

Stage 1 - Eletrobras Capitalization	R$	893,709,577.89
Debt conversion	R$	893,709,577.89
Debt assumption	R$	-
Adjusted Equity Value – Post Stage 1	R$	50,000.00


Price per share for Eletrobras underwriting	R$	1.06559514
Total shares subscribed by Eletrobras		838,695,243

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 Ceal 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.

12.6 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:

Product 11 – Privatization Modeling Proposal


OFFERING TO ACTIVE AND RETIRED EMPLOYEES FROM CEAL

Conditions of differentiated offer
Base value of sale share	R$	0.00003272
Discount over the disposal value for the Investor		10.37%
Share value for differentiated offer	R$	0.00002933

Shares to be offered
Amount of Eletrobras shares		1,528,219,627
Percentage of Eletrobras shares offered		10.02942603%
Total amount offered		153,271,657
Ordinary		150,574,795
Preferential		2,696,862
Total valued of shares offered	R$	5,014.71
Value of shares offered with discount	R$	4,494.77
Value of compensation payable by the Investor	R$	519.94

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		449,477
Amount of shares in the lot		341
Amount of Ordinary shares in the lot		335
Amount of Preferential shares in the lot		6

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$	0.00003272
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$	0.00003599
Correction Index		SELIC
Re-purchasing price per share	R$ 0.00003599 + SELIC

1) Value show considers full adhesion of Active and retired employees to the offer, which may vary

2) 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 - Investor’s 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 the state-owned company will be made.

Product 11 – Privatization Modeling Proposal

12.7 Investor capitalization – “Stage 2”

In the proposed sales model, for the purposes of liquidation of the auction, the investor willing to purchase Ceal 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 CEAL
Adjusted Equity Value – Post Stage 1	R$	50,000.00
Value to be paid by the Investor	R$	258,115,449.84
Adjusted Equity Value – Post Stage 2	R$	258,165,449.84
Amount of share to subscribe to the Investor		7,889,141,929,446
Price per share subscribed	R$	0.00003272

12.8 Ceal’s final corporate structure

At the end of the privatization procedure, Ceal shall present the corporate structure described below, considering the full adhesion of the active and retired employees to the offer of shares:


CEAL’S FINAL CORPORATE STRUCTURE

Total shares				8,770,108,413,078
Capital stock			R$	1,915,352,157. 18
Nominal value of shares			R$		0.00021840

Interest	Ordinary shares	Preferential shares		Total Shares	(%)
Investor	7,757,612,096,239	132,904,781,176		7,890,516,877,415	89.9706%
Eletrobras	1	0		1	0.0000%
Active and Retired Employees	864,114,851,751	15,476,683,911		879,591,535,662	10.0294%
Other Minorities	0	0		0	%

Shares per Class				Total Shares	(%)
Ordinary				8,621,726,947,991	98.3081%
Preferential				148,381,465,087	1.6919%

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 Ceal 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 the state-owned company 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.

Product 11 – Privatization Modeling Proposal

12.9 Investors Obligations

The purchase Ceal, the interested investor must undertake to the following obligations established in the sale proposal:

12.9.1 Financial obligations

v.	Underwriting and payment of capital at the company
vi.	Pay Eletrobras the offsetting amount related to the differentiated conditions of the Shares offering to active and retired employees of Ceal
vii.	Purchase from Eletrobras the remaining shares of the offer made to the active and retired employees
viii.	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:


INVESTOR OPERATIONS ON CEAL

Total paid during disposal of Ceal control	R$	45,505.23
Total value from sale of shares	R$	44,985.29
Amount of sale shares		1,374,947,969
Price per share	R$	0.00003272
Value compensation to Eletrobras for the offer to active and retired employees	R$	519.94

Capitalization - Stage 2
Amount of subscribed shares		7,889,141,929,446
Price per subscribed share	R$	0.00003272
Value to be paid by the Investor	R$	258,115,449.84

Other Obligations
Re-purchase of remainder from the offer to active and retired employees
Re-purchasing price	R$	0.00002933
Re-purchasing amount		Totality of remainder
Maximum value to be re-purchased	R$	4,494.77
Re-purchase of shares from active and retired employees
Re-purchasing deadline		03 Years
Base value per share for re-purchasing purposes	R$	0.00003272
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$	0.00003599
Correction Index		SELIC
Re-purchasing price per share		R$ 0.00003599 + SELIC

12.9.2	Obligations defined in the Purchase Agreement
	Certain additional obligations are recommended, namely:
	iii. Comply with the corporate clauses related to active and retired employees, according to the model proposed below:

Product 11 – Privatization Modeling Proposal

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

iv.	Comply with the governance clauses related to the stakeholders 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

13. Ceal’s privatization schedule

A proposal of schedule¹presenting the key stages of the privatization procedure was developed for the privatization of Ceal. 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.

14.6 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. Values of Non-Technical Losses are already predefined according to Technical Note 149/2017 of ANEEL.

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


Scenario – With Bresser Plan Agreement

NOTE	BASE ESTIMATE VALUES FOR AUCTION	CEAL – w/ Ag.

1	Index (BID)	Auction Result

2	Contract: Sub clause on Tax Coverage of RGR	Auction Result

3	Relaxation PMSO 2017	67,140,222
4	Regulatory PMSO 2017	328,676,698
5	Pre-Auction Discount	99.2%
6	2017 PMSO Relaxation Post Pre-Auction Discount	568,089
7	Contract: Item II Sub Clause 3 Clause 19 of the Contract	Auction Result

8	Regulatory PNT 2016	15.67%
9	PNT Relaxation	11.51%
10	Adjusted Relaxation	0.10%
11	Contract: Item III Sub Clause 3 Clause 19 of the Contract	Auction Result

Scenario – Without Bresser Plan Agreement

NOTE	BASE ESTIMATE VALUES FOR AUCTION	CEAL – w/o Ag.

1	Index (BID)	Auction Result

2	Contract: Sub clause on Tariff Coverage of RGR	Auction Result

3	Relaxation PMSO 2017	67,140,222
4	Regulatory PMSO 2017	328,676,698
5	Pre-Auction Discount	0.0%
6	2017 PMSO Relaxation Post Pre-Auction Discount	67,140,222
7	Contract: Item II Sub Clause 3 Clause 19 of the Contract	Auction Result

8	Regulatory PNT 2016	15.67%
9	PNT Relaxation	11.51%
10	Adjusted Relaxation	11.51%
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
3	Relaxation base for Operational Costs of 2017 (estimated by the Consortium, according to item 43 of NT 149/2017) -
	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

Product 11 –Privatization Modeling Proposal

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.

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:

Scenario – With Bresser Plan Agreement

REFERENCE VALUE ALTERNATIVES FOR EACH P.P. - GRANT FROM CEAL

i) Value¹estimated for each Index p.p.

ii) Value¹regarding Enterprise Value

Enterprise Value

Percentage Base of Enterprise Value 1) Approximate value

R$ 1,5 Million

R$ 6.1 Million

R$ 2,446.6 Million

0.25%

Scenario – Without Bresser Plan Agreement

REFERENCE VALUE ALTERNATIVES FOR EACH P.P. - GRANT FROM CEAL


i) Value¹estimated for each Index p.p.		R$ 5.0 Million

ii) Value¹regarding Enterprise Value		R$ 6.1 Million
Enterprise Value		R$ 2,446.6 Million
Percentage Base of Enterprise Value		0.25%
1) Approximate value

14.7	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

Being and Grant a bid in the interval of classification

Product 11 –Privatization Modeling Proposal

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	4^th
Company	Ceal
Interval of Classification	30.00

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 45.00 (75.00 less 30.00) 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 80.00 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.

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 stakeholder).

Scenario – With Bresser Plan Agreement

CLASSIFICATION INTERVAL FOR CEAL’S AUCTION

Approximated value for 1 (one) p.p. variation Classification Interval Estimated value for Classification Interval Estimated percentage of Enterprise Value

R$ 1.5 Million 30 p.p. R$ 45.0 Million 1.8%


	Product 11 –Privatization Modeling Proposal


Scenario – Without Bresser Plan Agreement

CLASSIFICATION INTERVAL FOR CEAL’S AUCTION

Approximated value for 1 (one) p.p. variation	R$ 5.0 Million
Classification Interval	30 p.p.
Estimated value for Classification Interval	R$ 150.0 Million
Estimated percentage of Enterprise Value	6.1%

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.

14.8 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 12 – Goal Calculation by Benchmark Comparison	169
Figure 13 – Evolution of Non-Technical Losses (%/ Low-Voltage Market)	172
Figure 14 – Evolved Revenue and Growth Rate	180
Figure 15 – Evolved Default	181
Figure 16 – Evolved Operating Costs	182
Figure 17 - Costs versus EBITDA	183
Figure 18 – Evolved Costs with Power Purchase	183
Figure 19 – Evolved Transmission Costs	184
Figure 20 – Evolved PMSO	185
Figure 21 – Projected Effective and Regulatory PMSO	186
Figure 22 – Evolved Operating Indicators: Gross Margin	187
Figure 23 – Evolved Operating Income: EBITDA Margin	188


Table 20 .

	Table 19 - Amount of Losses in the Ceal Distribution System
	Description	Amounts (MWh/year)	% Injected power
	Injected power (El)	4,325,513.000	100.000%
	Supplied power (EF)	3,102,547.083	71.727%
	Losses in Distribution (PD)	1,222,965.917	28.273%
	Technical Losses (PT)	447,422.556	10.344%
	Non Technical Losses
	(PNT)	775,543.361	17.930%
	Source: Technical Note no. 0180/2013-SRD/ANEEL


Table 84 – Information about Violence
Region	Deaths due to
	Aggression
ALAGOAS	63.0
BRAZIL	29.4
NORTH	34.3
NORHTEAST	41.6

Source: Datasus/IBGE 2014.


Table 25 - Information on Violence	47


Charts
Chart 1 - Socioeconomic characterization of the state of Alagoas	10
Chart 2 - Overview of the Brazilian Rate Structure	48


Table 25 - Information on Violence
Region	Deaths by
	Aggression
ALAGOAS	63.0
BRAZIL	29.4
NORTH	34.3
NORTHEAST	41.6
Source: 2014 Datasus/IBGE.


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		24
4. Personnel Cost		25
4.1. Compensation structure		25
4.2. Cost with active employees		26
4.3. Interns and apprentices		29
4.4. Costs with inactive staff		29
5. Collective agreements		30
5.1. Salary readjustment		30
5.2.	Benefits	30
5.3.	Payment of other bonuses	30
6. Outsourcing		32
7. Aspects related to health and safety		33
7.1.	Verification of existence of health and safety policies and procedures	33
7.2.	PCMSO Analysis	33
7.3.	PPRA Analysis	33
7.4.	Verification of completion of occupational medical examinations	34
7.5.	Internal Committee on Accident Prevention ("CIPA")	34
7.6.	Survey of work accidents (with/without leave) and opening of CAT (Work accident communication)	34
7.7.	PPE Delivery Verification	35
7.8.	Occupational Safety Technician Performance	35
7.9.	Mandatory training	35
1. Position and Compensation Plan ("PCR")		38

PwC \| Loeser e Portela Advogados \| Siglasul		2


1.1.	Compensation Structure	39
Growth Rules:		39
1.2.	Access requirements:	40
2. Variable pay		41
3. Benefits		41
4. Performance Management		44
4.1.	Performance Matrix:	45
5. Training and Development		46
6. Organizational Climate		47


TABLE OF CONTENTS
INTRODUCTION		4
EXECUTIVE REPORT		7
A.	REGULATORY ASPECTS	7
B.	CORPORATE ASPECTS	8
C.	FINANCIAL AGREEMENTS	9
D.	OPERATING AGREEMENTS AND OBLIGATIONS	10
E.	INTELLECTUAL PROPERTY	10
F.	INSURANCE	10
G.	LABOR ASPECTS	10
H.	CIVIL, COMMERCIAL AND EQUITY LITIGATION	11
I.	TAX LITIGATION	13
J.	REAL ESTATE ASPECTS	13

* * *


*Table of contents*
1.	Executive summary		4
2.	Plan types		4
3.	Plan statistics		4
4.	Analysis of assumptions and recommendations		6
	4.1.	Discount rate	6
	4.2.	Wage growth projection	6
	4.3.	Biometric tables	7
	4.4.	Turnover	8
	4.5.	Time of retirement	8
	4.6.	Family composition	8
	4.7.	Health care cost growth rate (HCCTR)	8
5.	Independent calculation of actuarial results		9
6.	Independent review of actuarial commitment		10
7.	Conclusion		11


Pensioners		-
Average benefit		-
Aggregate monthly benefit		1,076,510.97


	Plan 2 (DB)
Active participants		16
Average age		50.41
Average salary		4,152.36
Retired participants (valid)		303
Average age		71
Average benefit		2,026.12
Pensioners		191
Average benefit		675.28
Aggregate monthly benefit		742,892.84


	SIP
Active participants		-
Beneficiaries		159
Average age		61.39
Average cost		815.64


Health Care
Disabled retirees - HC	307
Average age	70.74
Dependents	393
Average age	49.07
Disabled retirees - Dental	461
Average age	67.60
Dependents	857
Average age	41.36
Average monthly per capita cost	372.33
Average per capita monthly coparticipation	37.23
Total participants - HC	700
Total participants - Dental	1,318

CENTRAIS ELÉTRICAS BRASILEIRAS S.A. - ELETROBRÁS

By:	/S/ Armando Casado de Araujo
	Armando Casado de Araujo Chief Financial and Investor Relation Officer