ANEEL
[Agência Nacional de Energia Elétrica]
Superintendência de Regulação Econômica
SGAN 603 / Módulo “I” – 1º andar
70830-030, Brasília, DF
Telephone #: +55-61-2192-8695
Fax #: +55-61-2192-8679
Brazilian Electricity Regulatory Agency - ANEEL
Economic Regulation Superintendence
Technical Note # 352/2012-SRE/ANEEL
Brasilia
st
October 1 , 2012
THIRD TARIFF REVIEW CYCLE OF ENERGY DISTRIBUTION
Bandeirante Energia S.A. – Bandeirante
Cycle 2011 - 2014
FINAL RESULT
1
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
CONTENT
Page
I.
Aim
3
II.
Facts
3
III.
Analysis
5
1. “B” Component
7
1.1. Operational Costs
8
1.2. Sunk Revenue
13
1.3. Capital Remuneration and Regulatory Reintegration Quota
14
1.4. Annual Cost of Personal Property and Real Property Facilities-CAIMI
19
1.5. “B” Component Readjustment due to Investments
21
1.6. “B” Component Readjustment due to Market Index Readjustment
22
2. Other Revenues
23
3. “A” Component
24
3.1. Costs with Electric Energy Purchase
24
3.2. Costs with Connection and Use of Distribution and/or Transmission Systems
30
3.3. Sector Burden
31
4. Verified Revenue
34
5. X-Factor
34
6. Financial Tariff Components
38
7. Tariff Review Summary
44
8. Effects of Tariff Review on Subsequent Readjustments
45
Conclusion
46
IV.
2
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
st
Technical Note # : 352/2012-SRE/ANEEL, October 1 , 2012
Process #: 48500.003391/2011-71
Subject: Tariff Review of Bandeirante concerning the Third Periodic Tariff Review Cycle– “3PTRC” of
Distribution Utilities
I. Aim
Submit to the Board of Directors of ANEEL the results of Bandeirante tariff review related to
the Third Periodic Tariff Review Cycle (3PTRC), consolidated after the analysis of the
contributions brought by the Public Hearing (PH) # 55/2012.
2.
Tariff Regulation Procedure (PRORET) Module 2 establishes the 3PTRC applicable
methodologies, supporting the calculations presented in the Technical Note. See references
below for conceptual review of applicable methodologies1 for a conceptual review of the
applicable methodologies that go beyond the scope of this Technical Note:
3.
Submodule 2.1 and Technical Note 293/2011-SRE/ANEEL: General Procedures;
Submodule 2.2 and Technical Note 294/2011-SRE/ANEEL: Operational Costs;
Submodule 2.3 and Technical Note 296/2011-SRE/ANEEL: Regulatory Remuneration Baseline;
Submodule 2.4 and Technical Note 297/2011-SRE/ANEEL: Cost of Capital;
Submodule 2.5 and Technical Note 295/2011-SRE/ANEEL: X-Factor;
Submodule 2.6 and Technical Note 298/2011-SRE/ANEEL: Energy Loss;
Submodule 2.7 and Technical Note 299&312 /2011-SRE/ANEEL: Other Revenues;
Submodule 2.8 and Technical Note 300/2011-SRE/ANEEL: Generating Own Energy
Section II presents a brief description of the facts related to Bandeirante tariff review.
Section III describes the periodic tariff review calculation, which includes the calculation of the
Verified Revenue, A Component, B Component, Other Revenues, Financial Components and
the X Factor. Section IV presents the conclusions.
II.
4.
Facts
Concession Agreement 202/1998 that regulates public services exploitation of electric
energy distribution in the concession area of Bandeirante, has fixed the 23rd of October 2011
as the date of the third periodic tariff review.
1
Available in the Internet: http://www.aneel.gov.br/cedoc/bren2011457.pdf
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
3
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
5.
The methodologies applicable to the 3PTRC are defined in PRORET Modules 2 and 7,
which deal with the tariff review calculation and with the applicable tariff structure
respectively. Both modules were duly approved in November 2011 by the Resolutions
457/2011 and 464/2011.
6.
Due to extensive discussions concerning 3PTRC methodologies, the time was not
enough to proceed with Bandeirante tariff review at the date of the Concession Agreement.
According to Resolution 433/2011, replaced by Resolution 471/2011, the tariffs effective in
November 22, 2011 were deferred. The consumer, however, did not notice any tariff move at
that time.
7.
Revenue variation due to tariff difference between tariffs effectively applied during
effective term of tariff review, and the tariffs established at the homologation of definite
results, applied on the reference market of the following tariff readjustment shall be
equationed and considered as a financial component in future adjustments. Therefore, tariff
review adjourn was neutral for both utility and customers.
8.
Initial information to calculate tariff review required by official letter 58/2012-SRE-
SFE/ANEEL of April 3, 2012, were sent on May 21, 2012 by Bandeirante (Letter CT-PR-12/12).
9.
In June 19, 2012 the preliminary tariff review proposal of the Distribution Utility was
sent to Bandeirante and to the Customer’s Council of Bandeirante (CONBAND). In June 26,
2012, we received their contributions to the preliminary proposal. After an evaluation, we
incorporated the relevant applicable contributions to the proposal described in the Technical
Note 202/2012-SRE/ANEEL of June 28, 2012.
10.
In July 10, 2012 ANEEL Board of Directors decided to hold the PH 55/2012 to discuss
the tariff review proposal. The period to receive contributions was extended from July 12,
2012 to August 17, 2012. The PH onsite was held in August 16, 2012 in the town of Sao Jose
dos Campos, Sao Paulo.
11.
After assessment of contributions received at the PH 55/2012, the tariff review
consolidated proposal was sent to Bandeirante and to the Consumers’ Council of Bandeirante
(CONBAND) in September 11, 2012, for final considerations. For this purpose meetings were
4
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
held in September 18, 2012 and whenever applicable, they were incorporated to this Technical
Note.
12. An specific meeting held by Bandeirante with the rapporteur-director in September 27,
2012, presented the considerations on the results of their 3rd Periodic Tariff Review.
III. Analysis
13.
The average effect to be noticed by Bandeirante customers due to the tariff review is -
2.25%. Calculated tariff repositioning was -2.22%. To the tariff repositioning financial
components were added2, corresponding to 0.37%. Then, financial components included in the
previous tariff adjustment were detracted, which were equivalent to 0.40% of the revenue.
These combined tariff transactions result in an average effect noticed by the consumers [2.22% + 0.37% - 0.40% = 2.25%].
14.
The table below summarizes the average effect by Group/Subgroup/Tariff Class.
Group/Subgroup/Class
Average Effect for Group A (>2.3 kV)
A1 (≥ 230 kV)
A2 (88kV to 138 kV)
A3a (30 kV to 44 kV)
A4 (2.4 kV to 25 kV)
Average Effect for Group B (≤ 2.3 kV)
B1 (Low Voltage – Residential and Low Income)
B2 (Low Voltage – Rural Area)
B3 (Low voltage – Other Classes)
B4 (Low Voltage – Public Lightning)
CONSUMER AVERAGE EFFECT
15.
Average Effect
-79%
10.94%
1.22%
11.85%
-1.66%
-3.64%
-4.04%
0.96%
-3.36%
0.96%
-2.25%
Tariff repositioning proposed for Bandeirante tariff review is -2.22% calculated as the
equation below.
Where:
RT = Average Tariff Repositioning (%)
RR = Required Revenue
OR = Other Revenues
RV: Verified Revenue
2
The financial components considered to a certain tariff calculation “remain” in the tariffs for one year; therefore,
at each readjustment process there is an “out-put” of a set of financial components and the “input” of other set of
different values.
5
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
16.
Verified Revenue refers to Electric Energy Annual Revenue Supply, Energy Purchase,
Consumption and Use of Distribution Systems, calculated considering the economic tariffs
ratified in the last tariff readjustment, and the Reference Market, disregarding taxes
(PIS/PASEP, COFINS, ICMS) and financial components out of tariff calculation.
17.
Reference Market includes the amount of electric energy, power demand and
distribution system use, billed within Reference Term3, to other distribution utilities and
permissionaires, customers, auto-producers and power generation companies that make use
of the same connection point to import or inject electric energy, as well as by the amount of
power demand hired by other generation companies to be used in the distribution system.
18.
Required Revenue is calculated for the Reference Period, considering the productivity
potential earnings within tariffs effective term set in the review, according to the formula
below:
RR = VPA + VPB (1 – Pm) (1 - mΔX)
(2)
Where:
RR: Required Revenue;
VPA: A Component Value ;
VPB: B Component Value;
Pm: Market Adjustment Factor;
m: See multiplier section III 1.5 for details; and
ΔX: Differential of X, resulting from X-Factor recalculation (2CRTP). For details see section III 1.5.
19.
Considering the Reference Market and the conditions in effect at the date of the
periodic tariff review, the Value of A Component includes the following items:
I. Acquisition cost of purchased electric energy (CE): The amount of energy purchased
to attend the reference market appreciated by pass on price of effective contracts at the date
of periodic tariff review, or by the value of auto-generation. To the amount of purchased
energy, regulatory limits of energy loss in the distribution system defined in the 3PTRC are
added, which are divided into technical loss and non-technical loss. Whenever the case it
includes energy loss regulatory limits in the transportation of Itaipu and in the Basic Grid.
II. Cost with the connection and the use of distribution and/or transmission systems
(CT): Effective values of periodic tariff review date are considered for the connection. For the
3
The Reference Term is the period of twelve months immediately before the month of the Periodic Tariff Review.
6
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
use the amounts of power demand contracted within reference period, valued by respective
economic tariffs effective at the date of the periodic tariff review are considered.
III. Sector Burden (ES): Values effective at the date of the periodic tariff review.
20.
The B Component includes the own costs of the activity of distribution, and the costs
of customers’ commercial management, subjected to the control or the impact of
management practices applied by the utility.
III.1.
21.
B Component
The B Component is the sum of the components below:
VPB = CAOM + CAA
(3)
Where:
VPB: B Component Value;
CAOM: Administration, Operation and Maintenance Cost; and
CAA: Assets Annual Cost
22.
PRORET Submodule 2.2 presents the calculation of Administration, Operation and
Costs of Maintenance (CAOM), which is the sum of the components below:
CAOM = CO3 + RI
(4)
Where:
CAOM: Administration, Operation and Maintenance Costs;
CO3: Operational Costs related to 3PTRC; and
RI: Sunk Revenue
23.
Assets Annual Cost (CAA) is the sum of the components below:
CAA = RC + QRR + CAIMI
(5)
Where:
CAA: Assets Annual Cost;
RC: Capital Remuneration including net remuneration of capital and taxes;
QRR: Regulatory Reintegration Quota (depreciation); and
CAIMI: Annual Cost of Personal Property and Real Property (annuity)
III.1.1. Operational Costs
24.
The approach used for the calculation of regulatory operational costs in the periodic
tariff review aims at defining the efficient level of costs to elaborate commercial processes of
consumer units, operational activities and maintenance of electric installations. It also includes
administration and management according to conditions provided by concession agreements
7
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
and in the regulation, to ensure that assets needed to render the service will remain unaltered
during all useful life.
25.
Under regulatory operational costs one can see the average productivity earnings
reached by distribution utilities, the efficient level of costs and the characteristics of
concession areas attended.
26.
The definition of regulatory operational costs is done in two steps. On the first step,
operational costs determined by the Reference Company Model methodology (ER) of the 2nd
Periodic Tariff Review Cycle (2PTRC), considers the price variation of the inputs (operational
costs), products increase (network distribution, consumer units and billed market), and
deduces productivity average earning. This means that the average relation between
operational costs variation and products growth reached by distribution utilities.
27.
On the second step, there is a comparative analysis of distribution utilities’ efficiency
to determine expected value interval for operational costs, considering distribution utilities
costs and the characteristics of their concession areas.
28.
The variations between values defined on the first and on the second steps are
considered in the calculation of the T Component of the X-Factor.
III.1.1.1. Step 1: Operational Costs Adjustment by Earnings with Productivity
29.
For tariff repositioning purposes, the value of operational costs to be considered in
3PTRC database, takes into account the cost defined in 2PTRC, the variation of inflation index,
product growth and the average of earnings with productivity during the analysis term, as
equation below shows:
,%
(6)
Where:
CO3: Operational cost to be considered for 3PTRC repositioning purposes;
CO2: Operational cost defined at 2PTRC with adjustments below described, adjusted until the
date of 3PTRC tariff review;
ΔP: Total variation of the products; and
4
n: Number of years between 2PTRC and 3PTRC data base.
30.
The productivity index to be applied for operational costs adjustment in 2PTRC are
based on average earnings of the productivity, associated to the operational costs during the
assessed period to define methodology. The value to be considered is 0.782% per annum and
it is the same for all utilities.
4
2PTRC data base is the date related to consumers units information and networks of the ER; 3PTRC database is the
th
last day of the 6 month before the month of tariff review.
8
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
31.
The value defined through Reference Company Model in 2PTRC for efficient
operational costs must be readjusted, to make adjusting value compatible with other
methodologies proposed for the 3PTRC as follows:
Deduction of costs related to own generation dealt with the A Component; therefore,
they must be excluded from B Component;
Deduction of revenues with taxed services, dealt with in the methodology of “Other
Revenues”;
Exclusion of costs of capital related to annuities (vehicles, computer system, and rent
of administrative personal property and real property), dealt with as Regulatory
Annuity Baseline (BAR) in the methodology definition of Regulatory Remuneration
Base.
Exclusion of additional costs related to the increase of procedure and commercial
activities, and of operation and maintenance. These costs aim at additional expenses
between the time the Reference Company is simulated (database of consumers and
assets data) and the date of the last tariff review. As 2PTRC cost adjustment occurs
from reference date of consumers and assets, the exclusion of such values is
necessary.
32.
Once 2PTRC adjusted operational costs are set, the costs with personnel are adjusted
by the IPCA (Broad Consumer Price Index), while the costs with material and services are
adjusted by the IGP-M (General Market Price Index) between 2PTRC and 3PTRC tariff review
dates.
33.
The calculation of product total variation (ΔP) is as follows:
∆ ∆ ∆ ∆ ∆ ∆
Where:
∆: Total variation of the product
∆ : Low voltage consumption index growth
∆ : Medium voltage consumption index growth
∆ : High voltage consumption index growth
∆: Consumers’ index growth
∆ : Network index growth; and
! : Weight of variable i, where i is equal to low, medium and high voltage consume, consumers
units and distribution networks.
34.
The table below presents a summary of the Operational Cost calculation to be
considered for Tariff repositioning purposes:
9
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 1 – Step 1, Regulatory Operational Costs in 3PTRC Repositioning
Description
Assets and Consumers Database
OPEX Values Database
Number of Consumer Units
Distribution Network Extension (km)
AT Market (MWh)
MT Market (MWh)
BT Market (MWh)
Description
Product Total Variation (?P) – 2PTRC and 3PTRC
Product Annual Variation
OPEX Productivity Index
IPCA Variation
IGPM Variation
Description
OPEX 2PTRC - Original
OPEX 2PTRC - Adjusted
OPEX 2PTRC – Inflation-Adjusted for 3PTRC
OPEX 2PTRC – With Products Growth
OPEX 3PTRC
Consumers’ Council
2PTRC
Values
01/01/2007
10/23/2007
1,364,738
26,814
5,200,850
3,829,263
3,945,103
3PTRC
Values
04/30/2011
10/23/2011
1,514,357
26,857
5,240,334
4,590,353
4,771,949
Variation
%
Weight
%
10.96
0.16
0.76
19.88
20.96
27.96
12.43
7.05
15.60
36.96
Variation
%
13.99
3.07
0.782
24.57
29.55
Total
Personnel
Services &
Materials
247,176,571
225,190,999
284,013,888
323,738,231
313,011,225
154,977,493
193,050,762
220,052,310
212,760,918
70,213,506
90,963,126
103,685,921
100,250,307
94,911
III.1.1.2. Step 2: Operational Costs – Comparative Analysis
35.
Besides the analysis of productivity earnings, there is a second comparative evaluation
of distribution utilities’ efficiency, which presents the results of productivity assessment and
also introduces elements that allow for better characterizing the area of each utility.
36.
The top-down approach was applied in the comparative analysis of the operational
costs. It starts from costs realized by distribution utilities in the years before the definition of
the methodology, with a comparative efficiency analysis to other utilities, upon efficiency
index application.
37.
Efficiency estimation of the utilities is carried out in two steps. The first step defines
efficiency parameters and assesses input/product correlation. Operational costs are
considered the actual inputs of distribution utilities. The products include the number of
consumer units, the extension of the distribution networks and the billed energy consumed
(captive consumer, free consumer and supply) subdivided by voltage level (AT, MT and BT).
10
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Superintendence of Economic Regulation – “SRE/ANEEL”
38.
The second phase assesses the specific characteristics of each concession area that
affect the costs of distribution utilities to define an expected interval of costs that considers
such specificities.
39.
To assess specific characteristics of each concession area that affect operational costs
we apply variables designated “Environmental Variables”. They usually consist of variables
external to the utilities that affect operation and maintenance unitary costs, electric energy
commercialization unitary costs and administrative costs. In the 3PTRC we considered some
environmental variables such as the salary level in different regions; pluvial intensity that
affects network operation and maintenance costs, that is: if the market is concentrated in a
small area, or if network dispersion is high. Once fighting non-technical losses is a complex
issue, it proved to be relevant only for large utilities.
40.
The aim of the second level is to build intervals of values with efficiency percentage
defined on the first level, according to the environmental characteristics of each concession
area. Thus, for the utilities that work in areas where environmental variables justify a higher
average cost, such fact is taken into account to build expected value intervals. The opposite is
valid for utilities where environmental variables justify a lower average cost.
See equations bellow:
"#$
%
· '$! "#$! (
!
!
%
"*$! !
· '$! "*$! (
(8)
(9)
Where:
"#$ : Inferior operational cost limit at 3PTRC database;
"*$ : Superior operational cost limit at 3PTRC database;
%
: 2009 operational accounting cost updated until tariff review date;
!
θi: Efficiency parameter considered at first level;
LS (θi): Superior interval limit on efficiency parameter; and
LI (θi): Inferior interval limit on efficiency parameter
41.
To enable comparison of costs defined at step 1 with the efficient costs of 2009, an
adjustment following the same procedure of equations (6) and (7) should be applied. However,
it should consider operational costs growth and products growth between 2009 and the 3PTRC
tariff review.
The table below summarizes the calculation of step 2 defining regulatory Operational Costs:
11
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 2 – Step 2, Regulatory Operational Costs to Calculate the X-Factor
Description
Assets and Consumers Database
OPEX Values Database
Number of Consumer Units
Distribution Network Extension (km)
AT Market (MWh)
MT Market (MWh)
BT Market (MWh)
2009
Values
07/01/2009
07/01/2009
1,460,661
27,356
4,590,994
4,103,014
4,439,061
Description
Product Total Variation (ΔP) – 2009 to 3PTRC
Product Annual Variation
OPEX Productivity Index
IPCA Variation
IGPM Variation
Variation %
6.42
3.46
0.782
13.07
15.37
Description
3PTRC
Values
04/30/2011
10/23/2011
1,514,357
26,857
5,240,334
4,590,353
4,771,949
Variation
%
Weight
%
3.68
-1.83
14.14
11.88
7.50
27.96
12.43
7.05
15.60
36.96
Total
Personnel
OPEX 2009 – Current Values
OPEX 2009 – Inflation-Adjusted for 3PTRC
OPEX 2009 – With Products Growth
OPEX 2009 – With Productivity Earnings
255,510,381
292,331,916
311,106,879
306,706,195
106,654,163
120,592,066
128,337,069
126,521,709
Services &
Materials
148,856,218
171,739,850
182,769,810
180,184,486
Description
Efficiency
OPEX 3PTRC – 2nd Step (Interval)
Inferior Limit
85.14%
261,129,654
Center
93.51%
286,800,963
Superior Limit
105.14%
322,470,893
42.
As a result of Step 2, expected results intervals are determined for the operational
costs. The variations noticed between values defined in Step 1 and Step 2 are then considered
for the calculation of the T Component of the X-Factor.
43.
The T Component aims at determining a trajectory to define regulatory operational
costs. It refers, basically, to a transition between different methodologies to define efficient
operational costs. Thus, along tariff cycle, the level of operational costs slowly migrates to the
level defined by the comparative analysis.
44.
When value of the operational costs defined in Step 1 is contained in Step 2 of the
efficiency operational costs interval, the T Component shall not be applied, otherwise,
calculation is based on the difference between the value defined in Step 1 and the closest limit
to the interval defined in Step 2, as follows. T Component value is limited to ± 2.0%.
4
013
01
+ ,1 . / 012 5 · 67893 ;
3
:
(10)
Where:
N: Number of readjustments between two successive tariff reviews;
CO3: Operational costs defined in the 2PTRC adjusted considering productivity earnings;
<=>? : The closest limit to CO3 efficient operational costs defined by the benchmarking method;
VPB0: Total of B Component defined in tariff review of 3PTRC.
12
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Superintendence of Economic Regulation – “SRE/ANEEL”
45.
For Bandeirante the T Component of the X-Factor is 0.00%.
III.1.2. Sunk Revenue
46.
The value of sunk revenue to be considered in the tariff review process consists of two
amounts: (1) one related to sector burdens, and (2) another related to other items of
distribution utility’s revenue.
47.
The calculations of the amount of sector burden is made from sunk revenues of the
utility. The aim is to calculate the costs with sector burdens including the amount billed, but
received by the utilities. The level of sunk revenues of each utility are considered provided
they do not exceed the limits fixed by PRORET Submodule 2.2. The equation below shows the
synthesis of the calculus of sunk revenues associated to sector burdens:
A*
@! B#*B#*BC#D* E F∑H E I#! J
(11)
Where:
Vi: Amount of sunk revenues associated to sector burdens;
ES: Value of sector burden to be considered in tariff review;
ρc: Class C consumption participation in total revenue verified in test year; and
RIi: Median of the percentage of sunk revenues, related to class C, verified in the three years previously to
tariff review.
48.
For the amount of sunk revenues related to other items of revenue, regulatory
percentages by consume class and by company groups are defined. Regulatory percentage is
based on the development of distribution utilities of each of the groups. The value of sunk
revenues of this revenue amount is then defined by the following equation:
II K @ B%#*B%#*BC#D* E L∑'H E I# (M
(12)
Where:
Vse: Amount of sunk revenues associated to revenue, except for sector burdens;
RR no burdens: Net required revenue with no burdens, that is, subtracting sector burdens;
ρc: Participation of class C consumption in total revenue verified in test year;
R1c: Class C percentage of regulatory sunk revenues of the group the company belongs.
49.
The table below shows a summary of the calculation of the value of sunk revenues to
be considered in tariff review procedure, split into two amounts: one related to sector burdens
and another related to remaining revenue.
13
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 3 – Sunk Revenues
Description
Sector Burdens
Remaining Revenue
Total
Base Revenue (R$)
734,336,706
3,034,915,781
3,769,252,488
RI
1.03%
0.49%
0.59%
RI (R$)
7,593,080
14,818,392
22,411,472
III.1.3. Capital Remuneration and Regulatory Reintegration Quota
50.
Capital Remuneration (RC) corresponds to the remuneration of investments done by
the utility and depends fundamentally on Regulatory Remuneration Baseline and on the
capital cost as follows:
I NIIO . IPI · QRS IPI · IPI.......... (13)
Where:
RC: Capital Remuneration;
BRRI: Net Regulatory Remuneration Baseline;
RGR: RGR debit balance
QRS : Weighted average cost of real capital before taxes, and
IPI : Cost of capital of RGR weighted by destination (PLpT and not PLpT)
51.
The Regulatory Reintegration Quota (QRR) corresponds to the amount that considers
the depreciation and amortization of investments, which aims at maintaining the assets of
service rendering along their useful life.
52.
The Regulatory Reintegration Quota (QRR) depends basically on Regulatory
Remuneration Baseline and on facilities average depreciation index, as follows:
QRR = BRRb δ
(14)
Where:
QRR: Regulatory Reintegration Quota;
BRRb: Gross Regulatory Remuneration Baseline; and
δ: Facilities average depreciation index
53.
To calculate the average index of facilities depreciation, annual depreciation indexes of
Table XVI, attached to the MCPSE (Cost of Implementation of Electric Sector Proprietary
Control Guideline) approved by ANEEL Resolution 367 of June 2, 2009 should be applied.
14
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Superintendence of Economic Regulation – “SRE/ANEEL”
54.
Relevant to mention that due to the approval of new depreciation rates provided by
Resolution 474/2012 of February 7, 2012, the new average rate should be considered as from
January 2012, applying the previous index for the period between review date and December
2011.
III.1.3.1. Cost of Capital
55.
To calculate the return rate the methodology of Weighted Average Cost of Capital –
WACC, including the effect of the taxes on income, as follows:
TUV00 W8⁄7 ·YZ [⁄7 ·Y\ ·WB]
W^
-1
(15)
Where:
r WACC : Weighted average cost of capital after taxes, in real terms;
rp: Nominal cost of own capital;
rD: Nominal cost of debt
P: Own Capital
D: Third parties capital or debt;
V: Sum of own capital and third party capital
T: Marginal effective tax rates; and
π: USA Average Inflation
56.
The structure of the capital refers to sources applied by an investor in a specific
investment. There are two sources: own capital and third party’s capital.
57.
To determine optimal capital structure to be applied in the 3PTRC, empirical data was
collected from Brazilian electric energy distribution utilities between 2006 and the year of
tariff revision of 2PTRC, which resulted in the participation percentage of third parties’ capital
(D/V) of 55%.
58.
The risk/return method of Capital Asset Pricing Model (CAPM) was adopted to
determine own cost of capital. This model was built to calculate assets remuneration of
electric energy distribution in Brazil, resulting in the following equation:
rp = rf + β (rm – rf) + rB
(16)
Where:
rp: Nominal cost of own capital;
rf: Return rate of risk free asset;
β: Beta of regulated sector;
rm-rf: Reference market risk premium; and
rB: Country Risk Premium
15
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
59.
For third parties’ capital cost a similar approach of the own capital is applied.
Additional required risk premiums are added to the free rate in order to have resources lent to
a distribution utility in Brazil. Third parties’ cost of capital is calculated by the CAPM method of
debt as follows:
rd = rf + rc + rB
(17)
Where:
rf: Return risk free asset rate;
rC: Credit Risk Premium
rB: Country Risk Premium
60.
The table below presents the weighted average cost of capital for a utility with tax rate
of 34% for the Corporate Income Tax (IRPJ) and for the Social Contribution on Net Income
(CSLL).
Table 4: Result of the Weighted Average Cost of Capital – WACC
COST OF CAPITAL
Capital Structure
Own Capital Rate
45%
Third Parties’ Rate
55%
Cost of Own Capital
Risk Free Rate
4.87%
Market Risk Premium
5.82%
Levered Average Beta
0.740
Business Risk Premium
4.31%
Country Risk Premium
4.25%
Nominal Own Capital Cost
13.43%
Third Parties’ Cost of Capital
Credit Risk Premium
2.14%
Nominal Cost of Debt
11.26%
WEIGHTED AVERAGE COST
Nominal WACC after Taxes*
10.13%
Real WACC after Taxes*
7.50%
(*) For companies with 34% IRPJ/CSLL tax rate
61.
To apply the tariff, actual WACC is considered after tax benefits with subsequent
inclusion of taxes to be paid. Therefore, the previous equation shall be applied to consumers’
tariff as follows:
TUV00Z_` 62.
W8⁄7·YZ [⁄7·Ya ·WB]
W^
. 1/1 . +
(18)
Considering IRPJ and CSLL tax rates are subject to a differentiated legal analysis
according to distribution utilities’ specificities that may result in final tax rates below 34%.
16
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Superintendence of Economic Regulation – “SRE/ANEEL”
Tax rates to be considered are as follows:
a) For cooperative utilities and municipal agencies, IRPJ and CSSL tax rates are 0.00%; however,
an equitable tax rate may be considered for the cooperative according to effective tax rate;
b) For the utilities within SUDENE/SUDAM area, IRPJ and CLSS tax rates are 15.25%;
c) Utilities with regulatory remuneration below R$240,000.00, IRPJ and CLSS tax rates are 24%;
d) For other cases, tax rates are of 25% and 9% are considered, totalizing 34%.
63.
To apply tariff, the WACC is considered as in table below:
Table 5: WACC before Taxes
WACC
a
Actual WACC before taxes
b
Actual WACC before taxes
c
Actual WACC before taxes
d
Actual WACC before taxes
IRPJ & CSLL Tax Rate (%)
Exempt
15.25%
24%
34%
Tax (%) (rWACC-pre)
9.55%
10.19%
10.66%
11.36%
a) Utilities exempt from Income Tax;
b) Utilities within SUDENE/SUDAM area;
c) Utilities with regulatory earnings below R$ 240,000; and
d) All others
64.
In the 3PTRC the total funds of the debit balance shall be deducted from utility net
remuneration of the RGR at Eletrobras of the month related to appraisal report database of
utility Remuneration Basis. Thus, fixed assets from RGR funds will be remunerated on specific
rate, and other assets of the company at regulatory cost of capital (WACC).
65.
Balance of investments made from financing with RGR funds will be remunerated by
the cost of loans in actual terms, considering that tariff readjustment includes B Component
inflation adjustment, as well as investments made during tariff cycle that are inflation adjusted
at the time of their incorporation to regulatory remuneration baseline.
66.
RGR funds destined to the Program entitled “Light for All” (PLpT) are remunerated by
the effective cost of loans in actual terms of 1.35% p.a., and RGR funds not destined to the
PLpT will be remunerated at the cost of the lowest fund raising of third parties available at
electric power distribution utilities, of 3.62% p.a.in actual terms.
17
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
III.1.3.2.
67.
Regulatory Remuneration Baseline
To assess utilities’ assets bound to the public service concession of electric energy
distribution to define 3PTRC remuneration baseline, follow the guidelines below:
a) Remuneration baseline approved in the second cycle of tariff review (2PTRC) should be
“shielded”. Shielded Baseline refer to values approved by adjusted assess reports including
transactions (inclusion, write-off, depreciation) and respective adjustments;
nd
rd
b) Inclusions between 2 and 3 tariff review cycles database, provided still in operation, are
part of the Incremental Baseline, and are assessed in 3PTRC tariff review process.
c) Final assessment values are obtained by adding adjusted values of shielded remuneration
nd
baseline (item a) with inclusions that took place between 2
and 3
rd
tariff review cycles
database – incremental baseline (item b);
th
d) The last day of the 6 month before the month of the 3PTRC tariff review is the assessment
report database.
e) Remuneration baseline is to be adjusted by the IGPM variation between assessment report
database and the tariff review date.
68.
Assets bound to the public service concession of electric energy distribution are
eligible to compose the Regulatory Remuneration Baseline only when effectively used in the
public service of electric energy distribution. Regulatory Annuity Baseline (BAR) assets are
neglected in remuneration base.
69.
The table below summarizes Regulatory Remuneration Baseline calculation as well as
remuneration and amount of reintegration quota.
Table 6: Capital Remuneration and Quota Reintegration
18
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 6: Capital Remuneration and Quota Reintegration
Description
Amount
(1) Fixed Asset in Service (New Reposition Value)
(2) Integral Asset Capacity Utilization Index
(3) Gross Special Liabilities
(4) Totally Depreciated Assets
(5) Gross Remuneration Base = (1) – (2) – (3) – (4)
(6) Accumulated Depreciation
(7) Net AIS (Market Value in Service)
(8) Depreciated Asset Capacity Utilization Index
(9) Remuneration Baseline Value (VBR)
(10) Storeroom in Operation
(11) Deferred Charges
(12) Net Special Liabilities
(13) Land and Servitudes
(14) Total Net Remuneration Base= (1)-(6)-(8)+(10)+(11)-(12)+(13)
(15) Balance RGR PLPT
(16) RGR Balance Other Investments
(17) Depreciation Index
(18) Regulatory Reintegration Quota = (5) * (17)
(19) Actual WACC before taxes
(20) RGR PLPT Rate
(21) Other Investments RGR Rate
(22) Capital Remuneration (15)*(20)+(16)*(21)+[(14)-(15)-(16)]*(19)
4,121,241,476
1,933,059
354,212,533
764,864,274
3,000,231,610
2,365,744,873
1,755,496,603
856,055
1,754,640,548
1,539,812
306,450,376
94,799,616
1,544,529,600
8,146,627
3.91%
117,396,563
11.36%
1.35%
3.62%
174,643,085
70. The value of Regulatory Remuneration Base was informed by the SFF (Superintendence of
Economic and Financial Supervision), through the Memo # 1315/2012-SFF/ANEEL of
September 3, 2012.
III.1.4. Annual Cost of Personal and Real Property Facilities - CAIMI
71.
The Annual Cost of Personal and Real Property, also designated Annuities, refer to
short term reorganization investments, such as those done with hardware, software, vehicles,
and investments with administrative facilities, and buildings infrastructure.
72.
The assets comprised within Regulatory Annuity Baseline (BAR) are neglected in the
Fixed Asset in Service (AIS) that will constitute the remuneration base. These assets are
defined as a relation of the AIS. A BAR is determined by the following formula:
BAR = 4.4956 (AIS - IA) -0.21+1 (IGPM1/IGPM0) 0.21
(19)
Where:
BAR: Amount of regulatory remuneration base related to investments in non-electric assets
(real and personal property);
AIS: Fixed Asset in Service approved in the 3PTRC;
IA: Asset Capacity Utilization Index base on AIS approved in the 3PTRC;
IGPM1: IGPM (Market Price Index) at tariff review date; and
st
IGPM0: IGPM (Market Price Index) in January 1 2011.
19
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
73.
Once regulatory annuity base is defined, to calculate the annuity it is necessary to have
it split in 3 groups of assets as follows:
Table 7: Segregation of Regulatory Annuity Base in Groups of Assets
Group of Assets
BAR %
Rent (BARA)
Vehicles (BARV)
Systems (BARI)
74.
25%
25%
50%
Once segregated, the Annuities are as follows:
CAIMI = CAL + CAV + CAI
(20)
Where:
CAIMI: Annual Cost of Personal and Real Property (Annuities);
CAL: Annual Cost of Rent;
CAV: Annual Cost of Vehicles;
CAI: Annual Cost of Computer System
75.
Annuities will be calculated in regimen with linear depreciation in useful life and with
remuneration on 50% of the investment.
R"⁄@⁄# NRIR⁄@⁄# · c@d R⁄@⁄#
QR
S
e
(21)
Where:
CA (L/V/I): Annual Cost of: A: Rent; V: Vehicles; I: Computer System
BARA/V/I: Amount of regulatory annuity base concerning investments in A: Administrative Real
Property; V: Vehicles; I: Computer System; and
VUA/V/I: Useful Life. Value defined in Table XVI of the annex of the MCPSE Guidelines: A: 85% of
the TUC (Type of File Unit); “Edification-Others” and 15% of the TUC “General Equipment” / V:
referring to TUC “Vehicles” / I: referring to TUC “Computer General Equipment”.
76.
The table below summarizes the CAIMI values.
Table 8: Annual Cost of Personal and Real Property – CAIMI
Description
(1) Regulatory Annuity Base (BAR)
(2) Annuity Base – Administrative Personal and Real Property (BARA)
(3) Annuity Base – Vehicles (BARV)
(4) Annuity Base – Computer System (BARI)
(5) Annuity – Infrastructure of Personal and Real Property (CAL)
(6) Annuity – Vehicles (CAV)
(7) Annuity – Computer System (CAI)
(8) CAIMI = (5) + (6) + (7)
Values (R$)
178,732,978
44,683,244
44,683,244
88,366,489
4,158,251
9,037,389
21,702,340
34,897,980
20
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
III.1.5. B Component Adjustment due to Investments
77.
As provided by ANEEL Resolution 234 of October 31, 2006, the mechanism that
compares estimated investments in the X-Factor calculation to investments effectively made
by distribution utilities was defined in 2PTRC.
78.
In the 3PTRC, at the tariff review of each utility, investments effectively made by the
distribution utility between 2PTRC and 3PTRC are assessed and calculated based on
distribution utility’s accounting records, monthly deflated by the IGPM for previous tariff
review database.
79.
In case investments effectively made are inferior to those considered in the calculation
of 2PTRC X-Factor, this item is recalculated, replacing prognosis investment amounts by actual
investments made. Other parameters remain unaltered.
80.
The recalculation of the X-Factor results in a differential of X(ΔX), according to previous
conditions:
ΔX = X1 – X0
(22)
Where:
X0: X defined in previous review (2PTRC); and
X1: Recalculated X
81.
ΔX is applied as a B Component reducer, calculated in 3PTRC tariff review as follows:
VPB’ = VPB (1 - mΔX)
(23)
Where:
VPB’: Final value of B Component in 3PTRC
VPB: Total of B Component calculated in 3PTRC; and
m: Multiplier
82.
The value of the multiplier (m) is 1.13 for utilities that have tariff reviews every 3 years;
1.76 for reviews every 4 years and 2.43 for reviews every 5 years.
83.
According to Memo # 1469/2012-SFF/ANEEL of October 1st, 2012, the investments
validated by the SFF-ANEEL (Superintendence of Financial and Economic Supervision) for
2PTRC were of R$ 396.057,15; thus, for the third tariff review of Bandeirante, the value of (1mΔX) resulted in 0.98.
21
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Superintendence of Economic Regulation – “SRE/ANEEL”
III.1.6. B Component Adjustment to Market Adjustment Index
84.
To the Final Value of B Component, an adjustment index called the Market Adjustment
Factor is applied, to consider potential productivity earnings between the year before
tariff review, the reference period, and the period where tariffs set in the review are
effective; that is, twelve months after the review.
85.
The value of Market Adjustment Factor (Pm) to be applied in the periodic tariff review
of each utility in B Component Value readjustment will be defined from average
productivity of the distribution sector and of the average growth of billed market, and
on the number of consumer units of the utility between 2PTRC and 3PTRC tariff
reviews as follows:
Pm(i): = 1.11% + 0.313 X (VarMWh(i) – 4.25%) – 0.260 X (VarUC(i) – 3.58%)
(24)
Where:
Pm(i): Market Adjustment Factor of the utility I;
VarMWh(i): Market Average Annual Variation of the utility I, between 2PTRC and 3PTRC
reviews; and
VarUC(i): Average annual variation of the number of consumer units of the utility I, 2PTRC and
3PTRC reviews; and
86.
The table below presents the summary of the calculation of Bandeirante tariff review
of B Component.
Table 9: Adjusted B Component Calculation
Description
Administration, Operation and Maintenance Cost (CAOM)
Operational Costs (CO3)
Sunk Revenues – Sector Charges (Vi)
Other Sunk Revenues (Vse)
Assets Annual Cost (CAA)
Capital Remuneration (RC)
Regulatory Reintegration Quota (QRR)
Annual Cost of Personal and Real Facilities (CAIMI)
B Component (VPB)
Adjustments bound to investments made
X Differential (ΔX)
Multiplier (m)
B Component with 2PTRC Adjustment (VPB’)
Productivity Rate of B Component
B Component with market adjustment
Values (R$)
335,517,607
313,106,136
7,593,080
14,818,392
326,937,628
174,643,085
117,396,563
34,897,980
662,455,235
-11,975,998
1.03%
1.76
650,479,238
1.08%
643,436,207
22
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
III.2. Other Revenues
87.
Other revenues can be classified into two categories according to their nature:
“revenues inherent to electric energy distribution service”, and “revenues of other
entrepreneurial activities”.
88.
Revenues inherent to the electric energy distribution service are additional revenues
to the energy supply, an essential part of the concession of electric energy distribution,
for which the expenses incurred are already in the regulated revenue service.
Revenues obtained with connection charges and chargeable services.
89.
The revenues of other entrepreneurial activities are any activities developed by the
utility that are not directly related to a final purpose of the concession. They are
subdivided into two groups:
a) Complementary Activities: Expenses of activities not clearly identified, already
covered by the revenue from the regulated activity. Contracts of infrastructure and
communications systems (PLC) commonality (sharing basis) are in this subgroup.
b) Atypical Activities: Activities under administration and management criteria that
allow for a very distinct record keeping of costs and results. Within this category are
the revenues from services rendered to third parties (operation and maintenance,
consultancy, communication and engineering) and charges for insurance and services
billed in energy invoices.
90.
For each type of revenue there is a percentage to be reverted to tariff modicity as
provided by the PRORET (Tariff Regulation Procedure) Submodule 2.7.
The table that follows synthesizes the calculation of “Other Revenues”.
Table 10: Other Revenues
23
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 10: Other Revenues
Description
Chargeable
Services
Connection
Charges
Infrastructure
Sharing
Communication
Systems
Consultancy
Services
O&M Services
Communication
Services
Engineering
Services
Insurance
&
Services
TOTAL
III.3.
91.
Gross
Revenue
7,718,212
ICMS/PIS
COFINS/ISS
287,903
Net
Revenue
7,430,308
Expenses
-
IRPJ
CSLL
2,526,305
Net
Profit
4,904,004
Other
Revenues
4,904,004
-
-
-
-
-
-
-
20,136,854
751,142
19,385,712
15,508,570
1,318,228
2,558,914
16,788,027
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,545,169
-
134,896
-
1,410,273
-
1,128,218
-
95,899
-
186,156
-
93,078
-
-
-
-
-
-
-
-
1,538,183
134,286
1,403,897
280,779
381,860
741,257
370,629
30,938,418
1,308,227
29,630,190
16,917,567
4,322,292
8,390,331
22,155,737
The A Component
The value of A Component is calculated considering the Reference Market and the
conditions in effect at the date of periodic tariff review. It includes the costs with
electric energy purchase (CE), costs related to connection and use of distribution
and/or transmission systems (CT) and the costs with Sector Charges (ES).
III.3.1. Costs with Electric Energy Purchase (CE)
III.3.1.1. Types of Agreement and Pricing Rules
92.
Law # 10848 of March 15 2004 on the commerce of power changed the rules of
purchase and sale of electric energy, especially concerning the distribution utilities. It
provides differentiated rules considering utility size, that is, those with their own
market ≥ 500 GWh/year, and those that attend consumption below this amount.
93.
The model set by law # 10848/2004 establishes two environments for contracting:
Regulated Contracting Environment (ACR) and Free Contracting Environment (ACL),
where utilities should ensure the distribution of the electric energy to their whole
market, upon the execution of regulated contract (within ACR).
24
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
94.
Concerning energy purchase by distribution agents with their own market ≤500
GWh/year, the regulation allows business within the Regulated Contracting
Environment with the following options: (i) Auctions of purchase in ACR; (ii)
Generators distributed, as provided by decree #5163, articles 14 and 15 of July 30
2004; (iii) With regulated tariff of current supplier agent; or (iv) Upon public licitation
process carried out by distribution agents. The general conditions to hire power supply
for these utilities were provided by means of Normative Resolution #206 of December
22, 2005.
95.
Current agreements are classified in the following modalities:
Bilateral Agreements (CB): Contracts executed from a free negotiation between the
agents previous to law #10848/2004. Energy Contracts of Distributed Generation by
means of public call after this law are also classified as Bilateral Agreements, as well as
those from licitations carried out by the utilities with a market ≤500 GWh/year.
Normative Resolution #167 of October 10, 2005, sets forth the conditions to market the
energy originating from Distributed Generation.
Bid Agreement (CL): Contracts of energy purchase and energy sale previous to Decree
#5163/2004 resulting from public bids of amounts of energy, carried out within the
former Energy Wholesaler Market (MAE), currently The Chamber of Electric Energy
Commercialization.
Itaipu Agreement (IT): Energy commercialized by “Itaipu Binacional” with distribution
utilities that acquired product quotas made available to Brazil set forth in Normative
Resolution #218 of April 11.
CCEAR: Contracts of power commercialization within a regulated environment,
resulting from bidding process set forth by Decree 5163/2004.
96.
The calculation of economic values for energy purchase in tariff review shall follow the
criteria below as in Concession Agreement:
(i) Energy purchase by means of contracts executed before Law #10848/2004: The
pass-through of the price of each effective agreement at the date of tariff review shall
be applied to the amount of energy of each contract, within the reference period,
limited to the amount of energy that can be attended by the same contract in the
twelve subsequent months;
25
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
(ii) For the electric energy purchased by means of contracts executed after Law #
10848/2004: The pass-through average price of power purchase contracts set forth in
Decree #5163/2004, article 36, authorized by the ANEEL until tariff review date,
weighted by respective contracted volumes to be delivered in the twelve subsequent
months, applied to the amount of purchased power with the deduction of amounts
hereinabove.
97.
In December 2, 2011 the Superintendence of Market Studies (SEM) informed the
prices of Bandeirante bilateral agreements to be considered for tariff calculation (Memo
#393/2011-SEM/ANEEL).
III. 3.1.2. Demanded Energy
98.
Besides the necessary energy to attend your customers, one should consider that not
all generated energy is delivered to the final consumer. The loss of energy is inherent to the
process of power transformation, transmission and distribution.
ANEEL is in charge of defining a regulatory loss referential at each tariff review, taking into
account the utility performance in the segments of loss with larger management.
99.
Energy losses can be divided into Loss at Basic Grid (outside utility distribution system,
with technical origin) and Loss at the Distribution, which can be of technical or non-technical
nature.
100.
The technical losses refer to the amount of loss at the distribution, inherent to
transportation process, voltage transformation and energy measurement at the utility
network. Non-technical loss represent all other losses connected to distribution, such as
energy theft, measurement errors, billing errors, consumer units with no measurement
equipment and others, which are measured by the difference between Distribution Loss and
Technical Loss.
101.
Losses in Basic Grid are calculated based on the percentage of average loss within the
segment of “Consumption”, notified by The Chamber of Electric Energy Commercialization –
CCEE, and assessed twelve months before tariff review.
26
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
102.
Technical losses are calculated taking into consideration utility distribution system
characteristics, such as: grid injection and consumption points of electric power, conductors
gauge, type of transformers and others. Losses in high, medium and low voltage at distribution
networks, substations, distribution transformers and other energy meters and service lines are
calculated. Module 7 of PRODIST (Distribution Procedures) details the methodology applied to
calculate the technical loss. The level of calculated technical loss as the percentage of injected
energy is kept constant at all tariff procedures until the subsequent review.
103.
Regulatory referential for Non Technical Loss is redefined at each tariff review, which
can be given either as a declining trajectory acknowledging a lower level of non-technical loss
at each tariff review, or as a fixed target, where non-technical losses on low voltage market is
kept constant along the tariff cycle.
104.
ANEEL’s approach to define the limits of non-technical loss compares distribution
utilities’ development that is similar within concession areas. Such comparison happens from
building up a complexity ranking to fight non-technical losses that aim at objectively measuring
the level of difficulty faced by each distribution utility, to reduce energy thefts and frauds.
105.
The ranking formula allows us to say that distribution utilities in areas considered as
more complex areas, with lower levels of non-technical loss are a reference of efficiency. This
can be used to define trajectories of reduction of non-technical loss by other distribution
utilities. Relevant to mention that besides distribution utilities’ comparative efficiency analysis,
the assessment also considers the past performance of the distribution utility itself to be used
as a regulatory reference when non-technical levels of loss have increased. The table below
shows non-technical loss calculation:
27
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 11: Regulatory Losses
1- Starting Point Calculation (Tariff Review)
Description
Non-Technical Loss
(BT %)
1. Goal of Cycle 2
16.12
2. Minimum amount in History
20.74
3. UC Adjust with no Measurement
0.09
4.Starting Point [minimum amount (1&2)-3]
16.03
2- Calculation of Goal (End of Tariff Period)
Description
Model A
Benchmark Company
COELCE
PNT/BT Benchmark
7.11%
PNT/BT COELCE
22.63%
Comparison Probability
99.98%
PNT/BT Target based on each Benchmark
7.11%
PNT/BT Benchmark Target Average (measured)
PNT/BT Difference between measured & Billed - COELCE
PNT/BT Benchmark Target Average (billing adjusted)
PNT/BT Starting Point (billed)
PNT/BT Target
Description
Starting
2011
2012
Point
%
%
PN/BT Trajectory (starting point until target)
16.03
13.62
11.20
Speed of Reduction (pa)
-2.42
-2.42
Limit of Reduction (pa)
-1.40
-1.40
PNT/BT Regulatory Referential
16.03
14.63
13.23
PNT/Einj Regulatory Referential
4.90
4.90
4.90
106.
Model B
COELCE
7.11%
22.63%
99.99%
7.11%
7.11%
0.74%
6.37%
16.03%
6.37%
2013
%
8.79
-2.42
-1.40
11.83
4.90
Model C
COELCE
7.11%
22.63%
99.96%
7.11%
2014
%
6.37
-2.42
-1.40
10.43
4.90
The starting point for the regulatory referential of non-technical loss is usually
determined by the smallest value between defined target of the 2PTRC and the minimum
amount in history reached by the distribution utility. The goal for the end of the cycle
considers the performance of distribution utilities in areas with the same complexity (or more
complex areas), concerning the fight against non-technical losses, with better performance.
The average level of non-technical loss of benchmark companies is then the referential to set
the goal, which must observe the potential speed of the reduction.
107.
Finally, the Energy Sold represents all energy billed by the utility for their captive
market, own consumption and the energy supplied to other distribution utilities. The table
below presents the calculation of demanded energy considered in the tariff review procedure:
Table 12: Demanded Energy
Description
Loss in Basic Grid
Loss in Distribution
Technical Loss
Non-Technical Loss
Sold Energy
Demanded Energy
Energy (MWh)
242.651
1,485.380
787.097
688.282
9,302,801
11,030,832
28
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
III.3.1.3. Valuation of Energy Purchase
108.
Utility Energetic Balance was prepared to calculate the expenses with the electric
power purchased to be resold, assessing surplus or deficits of the electric energy within
reference period.
109.
The surplus or deficits are calculated from the difference between the total contracted
energy and the total demanded energy, both related to the reference period. The contracted
energy available is equal to the sum of the own generation, of the CCEAR, of energy purchase
from bilateral agreements and of Itaipu and Proinfa energy quotas.
The table below presents a summary of the cost with energy purchase.
Table 13: Cost with Energy Purchase
Description
Expenses
(R$)
1,389,047,675.97
Tariff
(R$/MWh)
118.08
Energy
(MWh)
12,044,514.87
1st Existing 2005-2008
1st Existing 2006-2008
1st Existing 2007-2008
2nd Existing 2008-2008
MCSD 1st Existing 2005-2008
MCSD 2nd Existing 2006-2008
MCSD 1st Existing 2007-2008
MCSD 2nd Existing 2008-2008
MCSD 4th Existing 2009-2008
MCSD 5th Existing 2007-2008
10th Adjustment Auction P10M-SE
1st Alternative A-3 2010-15 OF
1st Alternative A-3 2010-30 H
1st New A-3 2008-15 T
1st New A-3 2008-30 H
1st New A-4 2009-15 T
1st New A-4 2009-30 H
1st New A-5 2010-15 T
1st New A-5 2010-30 H
2nd New A-3 2009-15 T
2nd New A-3 2009-30 H
3rd New A-5 2011-15 T
3rd New A-5 2011-30 H
4th New A-3 2010-15 T
5th New A-5 2012-15 T
5th New A-5 2012-30 H
6th New A-3 2011-15 T
BILATERAL AGREEMENTS
EDP LAJEADO
ENERPEIXE
ENERPEIXE CEMAT
INVESTCO
FAFEN
ITAIPU
PROINFA
Own Generation
71,182,419.93
134,933,006.82
18,399,156.88
35,768,832.03
23,377,175.37
26,866,836.20
1,554,589.58
3,450,886.92
8,425,845.52
152,748.27
2,762,126.29
24,452,968.51
10,493,302.60
2,794,193.42
539,885.48
14,326,344.84
1,695,135.32
41,636,261.28
48,232,338.85
9,087,875.98
25,719,117.57
26,513,280.64
31,434,285.69
105,250,610.08
38,036,207.42
26,989,55.92
17,510,998.33
80.43
94.16
105.53
113.22
78.63
92.01
102.66
111.27
125.28
131.21
110.92
170.44
170.13
103.59
141.52
100.15
151.22
135.52
152.22
113.65
165.20
140.19
156.28
107.97
101.20
160.39
103.57
885,058.63
1,433,019.97
174,350.73
315,911.62
297,310.89
291,997.47
15,143.00
67,254.53
67,254.53
1,164.11
24,901.97
143,469.66
61,678.55
26,973.58
3,814.99
143,048.88
11,209.96
307,233.33
316,856.65
79,963.71
155,686.92
189,123.91
201,143.00
974,813.47
375,851.85
168,274.31
169,074.04
14,432,815.41
165,435,578.40
60,286,714.20
1,516,703.91
143,480,040.00
252,309,838.30
-
126.85
173.26
169.30
122.75
163.79
97.58
-
113,778.60
954,840.00
356,094.00
12,356.04
876,000.00
2,585,659.28
280,443.02
-
Surplus (+) / Exposition (-)
110,973,307.36
109.48
1,013,682.98
1,278,074,368.61
115.86
11,030,831.89
CONTRACTED ENERGY
CCEAR – REGULATED ENVIRONMENT
TOTAL COST OF ENERGY PURCHASE
29
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
III.3.2. Costs with Connection and Use of Distribution and/or Transmission Systems
110.
The costs with power transmission from the plant to the utilities’ distribution networks
include: the Basic Grid (Nodal and Border), Connection/DIT, Transport from Itaipu and Use of
Distribution Systems. The table below presents power transmission costs related to be
considered in this tariff review:
Table 14: Cost of Connection and Use of Distribution/Transmission Systems (CT)
Description
Transport from Itaipu
Initial Contracts Basic Grid
Basic Grid
Border Basic Grid
ONS Basic Grid (A2)
Export Basic Grid (A2)
Itaipu MUST
Connection
Use of Distribution System
Total
111.
Cost (R$)
22,344,524
253,502,063
53,704,644
211,970
19,389,504
19,056,934
368,209,638
Basic Grid Cost: It refers to the amounts paid by Distribution Utilities to Transmission
Companies as provided by the CUST (Contract of Use of Transmission System) executed by the
ONS to access the transmission network of interconnected system. These amounts are
calculated by the ONS based on power demand values multiplied by the tariff determined by
the ANEEL. This tariff depends on the annual revenue allowed to Transmission Companies
(RAP) to cover the costs of transmission activities. ANEEL fixes the TUST (Tariff for the Use of
Transmission System) in the format of TUSTRB related to the use of Basic Grid installations and
TSTFR concerning the use of Power Transformers on Basic Grid Borders. Itaipu quotaholders
distribution utilities also pay the amount attributed to Itaipu Binational generation plant for
the Use of Basic Grid (Itaipu MUST), proportionally to their shares.
112.
Connection Cost: It refers to distribution utilities’ exclusive use, by Distributors, of
“Other Transmission Installations” (DIT) that do not belong to basic grid but to transmissions
companies for connection to transmission basic grid installations. This cost is fixed the ANEEL
with an annual readjustment that matches readjustment date of electric power distribution
utilities supply tariffs.
113.
Electric Power Transport from Itaipu Binational Plant: Cost of the transmission of
electric power share acquired by the utility from that generation plant. The cost with transport
30
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
from Itaipu is the result of amount of power demand (MW) acquired times by the tariff of
Itaipu transport fixed by the ANEEL in Reais (R$/MW).
114.
Cost related to the Distribution Systems Use : The amounts paid by distribution
utilities to other distribution companies as provided by the CUSS (Contract for Use of the
Distribution System) agreed by and between the parties, to access their distribution network.
The cost is calculated based on the amounts of hired power demand multiplied by the tariff
determined by the ANEEL.
III.3.3. Sector Burden
115.
Sector burdens are determined by their own legislation; they have a specific
destination that is the result of governmental policies for the national electric sector. ANEEL
does not have jurisdiction create or extinguish sector burdens. The sector burdens do not
represent revenue earnings for the utility that collects and passes on due amounts to resource
managers. Table 15 shows sector burden amounts as follows:
Table 15: Sector Burdens
Description
Reversal Global Reserve (RGR)
Fuel Consumption Account (CCC)
Energy Services Inspection Tax (TFSEE)
Energy Development Account (CDE)
Financial Compensation (CFURH)
Charge on System Service (ESS) and on Reserve Energy (EER)
PROINFA
R&D, Energy Efficiency and ICMS Return of Isolated Systems
ONS
Total Tariff Burden
116.
Amount (R$)
30,424,548
212,991,359
6,291,616
143,423,740
57,826,689
66,654,568
31,035,829
107,892
548,666,240
Reversal Global Reserve (RGR): Created by Decree #41019 (26/Feb/1957) to provide
resources for reversion, take over, expansion and improvement of electric energy public
services, to finance alternative energy sources, for inventory / feasibility studies of potential
hydraulic use and for the development and implementation of programs with projects to
prevent waste, and the efficient use of electric power. RGR annual shares set forth in
Resolution # 023/1999 are defined based on 2.5% of the “pro rata tempore” investment with
the limit of 3.0% of the revenue of each utility provided in the Accounting Manual for the
Electric Power Public Service, under the accounts of “Energy Purchase”, “Energy Supply”,
“Revenue from Electric Network Use” and “Charged Service”.
31
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
117.
Consumption Account of Fossil Combustibles (CCC): Created by Decree # 73102
(7/Nov/1973), it aims at pro rata distribution of costs related to fuel consumption to generate
thermoelectric energy in isolated systems. These costs are distributed all over the country
depending on the market of each utility. CCC values are based on ELETROBRAS Combustible
Annual Plan (PAC), prepared by Eletrobras, with prognosis based on forecast hydraulicity, on
expected consumption growth for the current year, and on effective fuel price applied on the
need of thermal generation.
118.
Energy Development Account (CDE): Created by Law # 10438/2002 regulated by
Decree # 4541/2002 to provide resources for: (i) Energy development of the states; (ii) Wind
energy generation competitiveness, small hydroelectric power plants, biomass, natural gas and
mineral coal within the areas attended by interconnected electric systems; (iii) promote the
universalization of electric energy services in the whole country. CDE shares were originally
defined based on CCC values of 2001 Interconnected Systems with charges readjusted annually
from 2002 according to market growth ratio of each agent and in 2004 by the IPCA (Broad
Consumer Price Index). CDE shares for the coming year are based on the share set for the
previous year, incorporating market growth between September/Year-1 and August/Year-2,
adjusted by the IPCA of the same period.
119. Financial Compensation for the Use of Hydro Resources (CFURH): Created by Law # 7990
(28/Dec/1989). The calculation of the CFURH is based on the effective generation of
hydroelectric power plants according to the formula: CFURH = TAR X GH X 6.75%, where TAR
refers to Reference Adjusted Tariff annually fixed by the ANEEL (in R$/MWh) and GH is the
amount (in MWh) of hydroelectric power plant monthly generation set forth in ANEEL
Resolution 67/2001.
120. Energy Services Inspection Tax (TFSEE): Created by Law 9427 (26/Dec/1996), and it is
equivalent to 0.5% of the annual economic benefit of the utility provided by Decree #
2410/1997. The annual amount of the TFSEE is set the ANEEL and destined to cover the costs
of their activities.
121. Program of Incentives for Alternative Electricity Sources (PROINFA) – Law #10438 of
April 26, 2002. The aim of this program is to increase the participation of renewable
alternative sources in the production of electric energy (wind energy, biomass and small power
32
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
plants). PROINFA costing is determined by the PAP (PROINFA Annual Plan), provided by Decree
# 5025/2004, Article 12 of ELETROBRAS. The shares are set according to captive consumers’
market, free consumers’ market and self-producers’ market (ANEEL Normative Resolution #
127/2004).
122.
System Service Charge (ESS) – Decree # 5163 (July 30/2004): A charge destined to
cover the costs of system services, including ancillary services rendered to the users of the SIN
(National Interconnected System), which includes: (i) generation costs from energy dispatched
independently from priority due to transmission restrictions within each submarket; (ii)
operating power reserve in MW, made available by generation plants for system frequency
regulation and their autonomous starting capacity; (iii) Capacity reserve in MVAr made
available by generation companies, above the reference values defined for each generation
company in Network Procedures of the ONS necessary to operate the transmission system;
and (iv) operation of generators as synchronous compensators, the voltage regulation and the
generation cut and load relief plan.
123. Reserve Energy Charge (EER) – Decree # 6353 of January 16, 2008. It represents all costs
for contracting reserve energy. The reserve energy is the energy destined to increase electric
energy supply safety in the SIN (National Interconnected System) from power plants specially
contracted upon public bids for this purpose, including administrative costs, financial costs and
charges prorated among final SIN electric power users.
124.
The burden of R&D-Research and Development-Law 9991, July 24, 2000 determined
that utilities and public distribution permissionaires have to apply the minimum amount of
0.75% of their net operational revenue in research and development of the electric sector; and
the minimum of 0.25% in energy efficiency programs as in ANEEL Resolution # 271/2000 and
Normative Resolution #316/2008.
125.
Distribution Utilities pay monthly amounts to the System National Operator (ONS)
activities costing, which coordinates and controls the operation of interconnected electric
systems and the administration and coordination of electric power transmission services.
III. 4. Verified Revenue
33
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
126.
The Verified Revenue is the Annual Supply Revenue, the Energy Purchase, the
Consumption of Electric Energy and the Use of Distribution Systems, calculated based on
homologous economic tariffs of the latest tariff readjustment and on the Reference Market,
disregarding PIS/PASEP, COFINS, ICMS and the exogenous financial components of tariff
calculus.
127. The Reference Market includes the amounts of electric energy, power demand and the
distribution system use billed within Reference Period5 to other utilities and to distribution
permissionaires, consumers, auto-producers and power generation plants that make use of
the same connection point to import, or inject electric power. The amounts of power demand
contracted by other generation companies to be used in the distribution system are also
included.
128.
Relevant to mention that as from 3PTRC review, the tariffs applied consider the
applicable discounts that result from subsidies granted to certain consumption classes. Thus,
tariff subsidies are then compensated in the own tariff structure with no need to consider
subsidy forecast as a financial component for the next 12 months. The table below presents a
summary of the Verified Revenue calculation.
Table 16: Verified Revenue
Description
Supply
A1 (≥ 230 kV)
A2 (from 88 kV to 138 kV)
A3 (69 kV)
A3a (from 30 kV to 44 kV)
A4 (2.3 kV to 25 kV)
AS
BT (≤ 2.3 kV)
SUPPLY
FREE CONSUMERS A1
FREE CONSUMERS (others)
DISTRIBUTION CONSUMER
GENERATION CONSUMER
CED Low Income
TOTAL
129.
Market
(MWh)
9,260,559
428,988
4,059,621
4,771,949
42,242
227,947
4,828,394
243,494
14,602,636
Revenue
(R$)
2,542,357,594.81
84,317,370
979,269,266
1,478,770,959
2,536,463
8,035,056
306,900,161
17,942,655
1,776,790
627,608.20
2,880,176,328
The SAMP ANEEL System (Market Data Monitoring System) contains market
information, and additionally, utilities are requested in the 3PTRC the billing system open by
5
Reference period corresponds to twelve months immediately before the month of the Periodic Tariff Review.
34
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Consumer Unit. Therefore, the market currently considered may change due to validations
that are being made from breakdown data.
III.5. The X-Factor
130. The X-Factor aims at ensuring that balance between revenues and efficient expenses
determined at tariff review date is kept along the tariff cycle. Tariff calculation is applied in
annual readjustments whenever B Component value is IGPM-adjusted deducing the X-Factor.
Thus, the bigger the X-Factor, the smaller the annual tariff readjustment is.
131. ANEEL’s approach to calculate the X-Factor in the periodic tariff review aims at defining it
from productivity potential earnings, compatible with market growth level, with the number of
consumer units, and quality of the service, also propitiating a transition of efficient operational
costs.
132.
To reach this goal the X-Factor includes 3 components as follows:
X-Factor = Pd + Q + T
(25)
Where:
Pd = Productivity earnings of distribution activity;
Q = Quality of the Service; and
T = Operational costs trajectory
133. Pd and T Component are defined as “ex-ante”, that is, at the time of tariff review. The Q
Component, shall be specified as “ex-post”, that is, in each tariff readjustment after 3PTRC
tariff review; however the methodology for its calculation is already known.
III.5.1. Component of Distribution Productivity Earnings - Pd
134.
Pd Component of the X-Factor includes potential productivity earnings associated to
the electric energy distribution, estimated from the relation between billed market growth and
operational costs and the capital linked to electric power distribution.
35
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
135.
Pd component to be applied in tariff readjustments of each utility is defined from
average productivity of the distribution sector and the average growth of billed market and the
number of consumer units of the utility between 2PTRC and 3PTRC tariff reviews, as follows:
Pd(i) = PTF + o.313 X (VarMWh(i) – VarMedMWh) – 0.260 X (VarUC(i) – VarMedUC)
(26)
Where:
PTF: Average Productivity of the Distribution Sector of 1.11% p.a.;
VarMWh(i): Annual market average variation of utility “i” between 2PTRC and 3PTRC tariff
reviews;
VarMedMWh: Annual market average variation of all distributors within 3PTRC simulation
period of 4.25% p.a.;
VarUC(i): Annual average variation of the number of billed consumer units of utility “I”,
between 2PTRC and 3PTRC tariff reviews;
VarMedUC: Annual average variation of the number of billed consumer units of all distribution
utilities within the period of 3PTRC simulations, of 3.58% p.a.
136.
1.08% is the Pd component value for Bandeirante subsequent readjustments.
III.5.2. Efficiency Trajectory for T Operational Costs
137.
T Component of the Factor X aims at setting a trajectory to define regulatory
operational costs. It deals with the transition between different methodologies to define
efficient operational costs. The methodology of operational costs calculation and the
calculation of the T Component are herein described in item III.1.1. T Component value to be
considered in subsequent readjustments of Bandeirante, calculated according to equation (10)
is 0.00%.
III.5.3. Q Component of Service Quality
138.
The Q Component of the X-Factor aims at encouraging the improvement of the quality
of the service rendered by distribution utilities along the tariff cycle, changing the tariffs
according to the behavior of quality index.
139.
In the assessment of the quality level of the service rendered, the DEC index
(Equivalent Interruption Duration) and the FEC index (Equivalent Interruption Frequency) are
considered. The mechanism aims at a continuous improvement of the indexes, also aware of
the relative performance of distribution utilities.
36
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
140.
The Q component value depends on the relative performance of the distribution
utilities. To determine the Index of the Service Quality of each distribution utility, the FEC and
the DEC are compared to the limits defined by the ANEEL, every civil year, as the follows:
W
[p0qZr_q\s t
fgh. jklmn o · 6
[p0uvwvx` t
yp0qZr_q\s t
yp0uvwvx` t
;
(28)
Where:
Ind.Qual: Service quality index for tariff purposes;
DECapurado: DEC assessment for the latest available civil year;
FECapurado: FEC assessment for the latest available civil year;
DEClimit: DEC defined for the civil year when index was assessed;
FEClimit: FEC defined for the civil year when index was assessed;
141.
For comparison purposes of relative performance, distribution utilities will be divided
into two groups according to their size. Distribution companies with billed market ≥ 1
TWh/year in the year of index assessment are called “large” and the others called “small”.
142.
Once service quality index of each utility is defined, the ones considered to have the
best performance are those whose index is below the first quartile of individual index of the
utilities within the group. Contrariwise, the utilities with the worst performance are those
whose index exceeds the third quartile. The quartiles are calculated as soon as DEC and FEC of
distribution utilities are available.
143. The Q Component is specified at each tariff readjustment according to the variation of the
FEC and DEC indexes assessed, already suppressing causes that are external to distribution
utilities, taking into consideration distribution utility performance concerning the quality of the
service rendered as follows:
37
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 17: Q Component of the X-Factor
FECI/DECI Var
(%)
> 20%
17% to20%
14% to 17%
11% to 14%
8% to 11%
5% to 8%
-5% to-5%
-8% to-5%
-11% to -8%
-14% to -11%
-17% to 14%
-20% to -17%
< -20%
144.
General
Rule (%)
1.00%
0.95%
0.79%
0.64%
0.49%
0.33%
0.00%
-0.33%
-0.49%
-0.64%
-0.79%
-0.95%
-1.00%
Best
Performances (%)
0.50%
0.47%
0.40%
0.32%
0.24%
0.17%
0.00%
-0.33%
-0.49%
-0.64%
-0.79%
-0.95%
-1.00%
Worst
Performances (%)
1.00%
0.95%
0.79%
0.64%
0.49%
0.33%
0.00%
-0.17%
-0.24%
-0.32%
-0.40%
-0.47%
-0.50%
The annual variation of DEC and FEC index is calculated according to the following
equation, and considers the indexes suppressing interruptions due to causes external to the
utility distribution system.
W
[p0x t
zlT{|<} †~|<} n o €[p0
x‚ƒ t
yp0x t
. 1„ €yp0
x‚ƒ t
. 1„…
(29)
Where:
VarDECI/FECI(i):Annual average variation of utility (i) FEC and DEC having distribution system
external causes suppressed;
DECI(t): DEC assessed, available for the last civil year, having external causes to utility
suppressed. DECip and DECind sum defined in PRODIST;
DECI(t-1): Same as above, but assed in the previous year;
FECI(t): FEC of the past civil year available, having external causes to distribution utility
suppressed. FECip and FECind sum defined in PRODIST; and
FECI(t-1): Same definition as above, but assessed in the previous year.
145.
The Q component will be applied as from 2013 tariff readjustments.
III.6. Financial Tariff Components
146.
The value of power energy supply tariff includes a concept of economic cost. However,
several financial tariff components have been created in the legislation that are not part of the
basic tariff; that is, they are not an integrant part of the economic tariff because they refer to
amounts to be paid by consumers in each period of 12 months subsequent to readjustments
or to tariff reviews.
38
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
147.
The financial components considered herein are as follows:
(i) A Component Items Variation Compensation Account – CVA: to compensate for
the financial effects that take place between readjustments/reviews dates of A
Component, as provided by the Administrative Rule # 025 of January 24, 2002 of the
Ministry of Mines and Energy and Treasury.
148.
The values of the Variation Compensation Account (CVA) - Items of A Component -
under processing were sent by the SFF (Superintendence of Financial and Economic
Supervision).
149.
Concerning the values of the CVAenergy informed by the SFF, it is relevant to mention
that the SRE was dealt with considering contracted amounts to attend 100% of the regulatory
market, in compliance with the cut order provided by Resolution 255 (6/Mar/2007), amended
by Resolution 305 (18/Mar/2008), which determined the criteria of costs transfer for
oversourcing up to 103% of regulatory market.
150.
Other procedures adopted by the SRE concerning the CVAenergy inspected by the SFF
were: (i) Inclusion of invoices related to the amounts of PROINFA (MWh) energy, so as to
ensure the neutrality in power costs of acquisition transfer, considering PROINFA (MWh)
energy is an integrant part of the utility energetic balance and part of calculation of the
average tariff of purchased energy assessed in tariff readjustments; (ii) Considering the tariffs
validated by the SEM (Superintendence of Market Studies) in relation to bilateral agreements;
(iii) Fixing the limit of tariff transfer at the purchase of power of Power Plants in Delay as
provided by the REN 165 of 19/Sept/2005. The table below shows CVA values in process:
Table 18: CVA Assessed Values
CVA DESCRIPTION
Delta
CVA CCC
CVA CDE
CVA Basic Grid
CVA Energy Purchase
CVA CFURH
CVA Itaipu Transportation
CVA Proinfa
CVA ESS/EER
TOTAL
3,058,338
11,496,646
2,545,161
(7,726,718)
408,887
(75,936)
6,952,189
16,658,566
th
30 previous
day
3,388,995
11,959,472
2,388,864
(5,261,087)
432,843
(79,575)
7,717,009
20,546,520
th
5 working
day
3,411,752
12,039,780
2,404,905
(5,296,416)
435,749
(80,110)
7,768,829
20,684,490
12 months
3,600,039
12,704,228
2,537,626
(5,588,713)
459,797
(84,531)
8,197,573
21,826,020
39
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
(ii) CVA (previous year) Offset Balance: As provided by Administrative Rule #25/2002
MF/MME §4, Art. 3, it was checked if the CVA balance in Process considered in the previous
tariff process was effectively compensated, taking into consideration the variations that took
place between the electric power market considered at that time and the actual market
effectively realized within the 12 months of compensation, as well as the difference between
projected interest rate and SELIC interest rate. The CVA assessed a setoff balance of the
previous year in the amount of R$ 1,868,395.77;
(iii) Neutrality of Sectors Burdens: According to the terms set forth in by sub-clause 18
of the Concession Agreement, there was a calculation of the monthly differences assessed
between the values of each item of billed sector burden within reference period and the
respective values given in the previous readjustment. The total of the differences, adjusted by
SELIC for October 2011 came to the negative total amount of R$(16,042,520.62);
(iv) Energy over-sourcing transfer: Article 38 of Decree 5163/04 establishes that the
transfer of electric power acquisition costs provided in articles 36 and 37 of final consumers’
tariff, ANEEL shall consider up to 103% of the total amount of contracted energy in relation to
the annual supply load of the distribution agent. Thus, in compliance with the methodology
approved in Resolutions 255 (6/Mar/2007) and 305 (18/Mar/2008), for the current tariff
process the negative amount is of R$ (14,879,665.82) for energy over-sourcing of the civil year
of 2010; however, due to the negative calculus, there is no prognosis for the next 12 months.
The reversion was not considered due to lack of a prognosis in the previous tariff calculation.
(v) Exposition by Price Differences between Submarkets: Article 28 of Decree
5163/04, paragraphs 2 and 3, provides that commercialization rules set forth specific
mechanisms for pro rata distribution of financial risks resulting from price differences between
the sub-markets, occasionally imposed to distribution agents that execute Agreements of
Electric Energy Commercialization within Regulated Environment (CCEAR) in the modality of
energy amount. The SRE assessed a negative net exposition of R$ (2,318,597.05), already
adjusted by the IPCA, referring to the accountings performed between January and December
2010.
(vi) Component of Basic Grid Readjustment – Border: The Readjustment Component
(PA) of the Border Basic Grid informed by the SRT is R$ 25,343.15. The amount of Border PA
40
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
should be considered in the calculation of the Basic Grid Average Tariff for the assessment of
Basic Grid CVA in the next tariff readjustment.
(vii) Component of Adjustment of the Connection/DIT: It refers to the financial impact
that results from transmission companies review and of other adjustments associated to
connection installations of exclusive use, also informed by the SRT in the total amount of
R$3,703.21. This amount is IGPM-adjusted by the variation of the IGP-M (General Market Price
Index).
(viii) Subsidy, Reversion and Prognosis: Irrigation and Aquaculture: As provided by
Normative Resolution #207, Article 6 (Jan/9/2006) special discounts are granted on the tariff of
power supply related to the electric energy used for irrigation and aquaculture. The amounts
supervised and validated by the SFF (Superintendence of Economic and Financial Supervision),
duly adjusted for the period between September 2010 and August 2011 was R$3.882. The
reversion granted in previous tariff calculation, IGPM-adjusted of –R$1.308 was also
considered. As from 3PTRC tariff review, tariff subsidies started being compensated in the own
tariff structure, with no possibility of considering as a financial component the subsidy forecast
for the next twelve months.
(ix) Subsidy, Reversion and Prognosis – TUSD (Incentivized Sources) As provided by
Normative Resolution #77, Article 7 (18/Aug/2004), the amounts related to the loss of
distribution revenue from discounts granted in the TUSD (Tariff paid for the use of the
distribution system), applicable to hydroelectric plants with power ≤ 1MW, and to generation
plants with power ≤ 30MW (PCH and Incentivized Sources) destined to independent
production and for the self-production, on production and on commercialized energy
consumption and on the energy acquired by free consumers. The amounts supervised and
validated by the SFF -Superintendence of Economic and Financial Supervision, (for free
customers and generation companies) for the period between August 2010 and July 2011,
IGPM-adjusted resulted in the total of R$14,607,875. The reversion of the prognosis granted in
previous tariff calculation, IGPM-adjusted reached the amount of -R$12,021,321. As from the
3PTRC tariff review, tariff subsidies started being compensated at the own tariff structure, with
no possibility of considering as a financial component the subsidy forecast for the next twelve
months.
41
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
(x) Subsidy, Reversion and Prognosis – Self-Producer (APE) and Independent Energy
Producer (PIE): It refers to utility revenue loss due to the discounts granted at the TUSD CCC,
CED and PROINFA, for the own consumption of energy auto-producer and the independent
producer (Normative Resolution #166, Nov/11/2005). Amendments in public service
concession contracts of electric power distribution introduced a new methodology of energy
annual readjustment tariff, effective from February 2012. They aimed at ensuring neutrality to
A Component costs related to sector burdens and the discounts granted to the APE/PIE were
considered in the present tariff calculation concerning the period between August 2010 and
July 2012, supervised and validated by the SFF (Superintendence of Economic and Financial
Supervision), in the total amount of R$5,371,33 IGPM-Adjusted. The reversion of the
prognostic granted in previous tariff calculation in adjusted values was -R$ 1,555,661. From
3PTRC tariff review, tariff subsidies started being compensated at the own tariff structure.
Subsidy prognosis is no longer considered as a financial component for the next twelve
months.
(xi) Subsidy, Reversion and Prognosis – Rural Electrification Cooperatives: It refers to
revenue compensation due to “full” tariffs, with no discounts concerning rural electrification
cooperatives, so that subsidizing market defined in the tariff structure does not increase to
compensate for such discount. Therefore, the amount of R$ 12,616,136.96 is being considered
as a “Subsidy – Cooperative”, supervised by the SFF/ANEEL for the period between June 2009
and July 2011. The amount of R$ (7,934,846.50) is also being considered for “Reversion of
Subsidy Prognosis” granted in Tariff Readjustment of 2010.
(xii) Subsidy, Reversion and Prognosis – Low Income: Based on information given by
the SRC (Superintendence of Regulation of Energy Commercialization) on the market and
billing of Low Income Residential Subclass consumers, adjusted annual Low Income subsidy
value, referring to the term between October 2010 to September 2011, was assessed in R$
14,952,556. This amount is not covered by the economic subvention provided by the
Normative Resolution 89/2004, transferred to the utility by ELETROBRAS. This amount includes
occasional revenue differences resulting from compliance to Law # 12212/2010 on Electric
Energy Social Tariff, and Article 13 of Law # 12111/2009, which vetoes passing on the
percentage of the Sector Burden of Consumption Account of Fossil Combustibles (CCC) to Low
Income Residential Subclass consumers. For the same period, the reversion of the forecast
42
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
included in the previous tariff calculation, IGPM-adjusted, in the negative total amount of -R$
11,810,225.
151.
Still considering the discounts given to Low Income Residential Subclass consumers,
and according to Memo 342/2012-SRC/ANEEL of 5/Sept/2012, the SRC informed data
approved to low income subsidy of Bandeirante between October 2008 and September 2009,
and October 2009 and September 2010, which had not been considered in the IRT-2010,
waiting for approval at that time. Therefore, this tariff review considered the following setoff
adjustments R$ 2,173,558 and R$ 255,715.
152.
As from 3PTRC tariff review the tariff subsidies started being compensated at the own
tariff structure with subsidy prognosis no longer considered as a financial component for the
next twelve months.
(xiii) Financial Guarantees to participate in Energy Public Bids: Considering Report
295/2010-PGE/ANEEL (Apr22/2010) ANEEL’s Office of Attorney General, this kind of tariff
setoff is restricted to financial guarantees provided in contracts, referring to Article 15
(generation distributed by public call), article 27 (CCEAR of new energy and existing energy
bids), and Article 32 (Adjustment Auctions) of Decree 5163/2004; that is, occasional costs to
compose financial guarantees to participate in public bids should be disregarded. However
required in the bid notice, they are not provided in energy purchase and sale contracts, and
are released after auctions are closed. Relevant to mention that as in Article 12 of Decree
5177/2004, tariff pass through of expenses/reimbursement costs resulting from energy bids is
vetoed. Thus, in the present tariff calculation, payments made, duly supervised and validated
by the SFF (Superintendence of Economic and Financial Supervision), were R$ 325,326 IGPMAdjusted.
(xiv) Cost of Implementation of Electric Sector Proprietary Control Guideline –
MCPSE: Normative Resolution #367 (2/Jun/2009) approved the MCPSE to be applied
by utilities, permissionaires and authorized electric energy companies, whose assets
and installations are liable to reverted to the Union as effective legislation sets forth.
Article 3 of this Resolution determines the costs of the implementation of the
Handbook should be considered as regulatory within periodic tariff review. The
amount of R$ 3,451,820.16 supervised by the SFF was included and is considered a
43
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
provisional form until article 3 of RN 367/2009 is regulated, subject to correction in the
scope of the tariff readjustment procedure immediately after the result of this tariff
review.
Summary of Financial Components
153.
The table below consolidates the amounts considered as financial components:
Table 19: Financial Components
Description
Amount (R$)
CVA under process
CVA Setoff Balance
Sector burdens neutrality
Subsidy – Irrigation and Aquaculture – Res 207/2006 (assessed-previous year reversion)
Subsidy – Free Consumer Incentivized Source TUSD – Res 77/2004
Subsidy TUSDccc, cde, proinfa – APE/PIE – Res. 166/2005
Subsidy – Low Income
Subsidy - Cooperative
Energy Oversourcing REN 255/2007 (Assessed + Prognosis – Reversion)
CCEAR Exposition between Sub-markets
Financial guarantees at energy regulated contracting (CCEAR)
Border RB Adjustment Component
Adjustment Component of DIT/Connection
Implementation Assets Control Guide - MCPSE
Low Income Subsidy Setoff Adjustment 2008/2009
Low Income Subsidy Setoff Adjustment 2009/2010
TOTAL
21,826,020
1,868,396
-16,042,521
2,575
2,586,554
3,815,669
3,142,331
4,681,290
-14,879,666
-2,318,597
325,326
25,343
3,703
3,451,820
2,173,559
255,715
10,917,518
III.7. Tariff Review Summary
154.
Applying the methodologies defined in PRORET Module 2 on tariff review of electric
power distribution utilities, Bandeirante tariff review is summarized in the following table,
with all items of utility required revenue, other revenues, financial components and verified
revenue. The table also shows the contribution of each item to repositioning.
44
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
Table 20: Tariff Review Summary
Description
1. A COMPONENT (1.1+1.2+1.3)
1.1. Sector Burdens
RG
CCC
…..TFSEE
…..CDE
PROINFA
….R&D (Energetic Efficiency)
ONS
ESS
1.2. Transmission
Basic Grid
Basic Border Grid
Itaipu
…..Connection
Others
1.3. Energy Purchase
Existing CCEAR
New CCAR
Bilateral Agreements
Itaipu
2. B COMPONENT
(2.1+2.2+2.3+2.4+2.5)
2.1. Operational Costs + Annuities
2.2. Remuneration
2.3. Depreciation
2.4. Sunk Revenues
2.5. Other Revenues
3. Economic Repositioning
4. Financial Components
5. Financial Repositioning
6. Financial from previous IRT
Last IRT
Revenue
R$
Verified
Revenue
R$
Required
Revenue
R$
Projected
Variation
R$
Impact in
Review
(%)
Part.
Revenue
Review
(%)
2,042,028
488,374
4,187
190,216
6,088
126,435
66,656
31,387
110
63,296
326,919
219,971
50,950
37,993
17,848
157
1,226,735
260,457
364,136
366,509
235,632
772,861
2,109,866
504,598
4,326
196,535
6,290
130,635
68,870
32,430
113
65,399
337,780
227,279
52,643
39,255
18,441
163
1,267,488
269,110
376,233
378,685
243,460
798,536
2,194,950
548,666
30,425
212,991
6,292
143,424
66,565
31,036
108
57,827
368,210
253,502
53,705
41,734
19,057
212
1,278,074
278,610
362,003
385,152
252,310
612,280
4.03
8.73
603.26
8.37
0.03
9.79
-3.35
-4.30
-4.70
-11.58
9.01
11.54
2.02
6.32
3.34
30.38
0.84
3.53
-3.78
1.71
3.64
-22.20
2.93
1.52
0.90
0.57
0.00
0.44
-0.08
-0.05
0.00
-0.26
1.05
0.90
0.04
0.09
0.02
0.00
0.36
0.33
-0.49
0.22
0.30
-6.09
77.94
19.48
1.08
7.56
0.22
5.09
2.36
1.10
0.00
2.05
13.07
9.00
1.91
1.48
0.68
0.01
45.38
9.89
12.85
13.68
8.96
22.06
353,250
261,775
154,090
21,529
-17,783
2,814,888
364,985
270,472
159,209
22,244
-18,374
2,880,176
338,013
169,629
114,026
21,768
-22,156
2,816,231
10,918
-7.39
-37.28
-28.38
-2.14
20.58
-2.22
-0.93
-3.47
-1.55
-0.02
-0.13
-2.22
0.37
-1.85
-0.40
12.00
6.02
4.05
0.77
-0.79
7. Average Effect for Consumer
III.8.
155.
-2.25
Effects of Tariff Review on Subsequent Readjustments
Despite late process, Bandeirante tariff review has been in effect since date provided
in Concession Agreement of October 23, 2011. In order to counterbalance tariff review
adjournment to both distributors and consumers, a financial component shall be assed from
the difference between adjourned tariffs (actually applied) and those fixed at tariff review
(that should have been used), applied on reference market of the next tariff readjustment.
156. The calculation of the financial component should occur as from Annex I tariffs. That is,
considering both the economic items of the revenue and the financial components. As the
effects of the tariff review are not uniform – they vary according to consumers’ tariff modality
- financial bubble is calculated by tariff modality.
45
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”
157.
It is relevant to mention that in June 18, 2012, Technical Note 185/2012-SRE/ANEEL
recommended the change in the Normative Resolution 471/2011. It allowed that revenue
variation due to the difference between tariffs effectively applied within effective term tariff
review, and the ones defined at the homologation of definite results, could be set out and
considered as a financial component in the next tariff readjustment. It also recommended that
in case of financial component deferred balance, it should be remunerated by the WACC
(7.5%) and by the IGP-M (General Market Price Index).
IV. Conclusion
158.
By applying the methodologies defined in PRORET Module 2 of distribution utilities
tariff review, Bandeirante tariff repositioning is of -2.22%, with an average effect perceived by
the consumer of -2,25%.
The table below shows the effect by voltage level.
Table 21: Tariff Impact on Consumer
Group / Sub-Group / Class
Group A Average Effect (>2.3kV)
A1 (≥ 230 kV)
A2 (88 to 138 kV)
A3a (30 to 44 kV)
A4 (2.4 to 25 kV)
Group B Average Effect (≤ 2.3kV)
B1 (Low Voltage – Residential and Low Income)
B2 (Low Voltage – Rural)
B3 (Low Voltage – Other Classes)
B4 (Low Voltage – Public Lighting)
CONSUMERS’ AVERAGE EFFECT
Mr. Lincoln José Silva de Albuquerque Barros
Regulatory Specialist – SRE
Average Effect
%
-0.79
10.94
1.22
11.85
-1.66
-3.64
-4.04
0.96
-3.36
0.96
-2.25
MS. Flávia Lis Pederneiras
Regulatory Specialist – SRE
46
* The Technical Note is a document issued by the Organizational Units, which aims at supporting the decisions of the Agency.
Superintendence of Economic Regulation – “SRE/ANEEL”