Hydro- Québec
Distribution
R-3677-2008 Application
RATE CONTEXT AND STRATEGY
(Chapter 1 and Excerpts of Chapters 2 and 3)
Original : 2007-08-01
HQD-12, Document 1
Page 1 of 67
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Distribution
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TABLE OF CONTENTS
1. CONTEXT OF THE APPLICATION .................................................................4
1.1 Follow-up of Decision D-2008-024 ..............................................................4
1.1.1 Customer Charge for Domestic Rates...............................................4
1.1.2 Analysis of the DT Rate Structure .....................................................5
1.1.3 Analysis of Customer Segmentation for Rates G, M and L ...............5
1.1.4 The “Heure Juste” Ratemaking Project .............................................6
1.1.5 Electricity Rates Applicable to the Schefferville System....................6
1.1.6 Differentiated Rate Increases............................................................7
2. RATE INCREASE AND CROSS-SUBSIDIZATION FOR 2008-2009...............8
2.1 Variances between Revenue Requirements and Projected Revenues for
2009 ..................................................................................................................8
2.2 Proposed Rate Increase and Impact on Cross-Subsidization .....................8
2.3 Domestic Rates .........................................................................................13
2.3.1 Rates and Customer Description ........................................................13
2.3.1.1 Rate D ..........................................................................................13
2.3.1.2 Rate DM .......................................................................................17
2.3.1.3 Rate DT........................................................................................20
2.3.1.4 Rate DH .......................................................................................22
2.3.1.5 Rates DA and DB .........................................................................23
2.3.2 Analyses Requested in Decision D-2008-024.....................................27
2.3.2.1 Rate D Customer Charge.............................................................27
2.3.2.1.1 Decision D-2008-024.................................................................27
2.3.2.1.2 Principles and Orientations .......................................................28
2.3.2.1.3 Contract Costs ..........................................................................29
2.3.2.1.4 Benchmarking ...........................................................................32
2.3.2.1.5 Scenarios Analyzed...................................................................34
2.3.2.1.6 Distributor’s Proposal ................................................................39
2.3.2.2 Analysis of the DT Rate Structure ................................................39
2.3.2.2.1 Profitability of the Structure of Rate DT from the Perspective of
Society and of the Distributor ...................................................................39
2.3.2.2.2 Profitability of the Structure of Rate DT from Customers’
Perspective ..............................................................................................41
2.3.2.2.3 Proposed Rate Strategy on April 1, 2009 ..................................43
2.3.3 Proposed Adjustments to the Rate Structure and Implementation of the
Reform.........................................................................................................47
2.3.3.1 Customer Charge .........................................................................48
2.3.3.2 Energy Rate Adjustment ..............................................................48
2.3.3.2.1 Benchmarking of Rates with Two Progressive Blocks in Canada
.................................................................................................................49
2.3.3.3 Capacity Invoice ...........................................................................52
2.3.3.4 Evolution of Domestic Rates in the Short and Medium Terms .....55
2.3.3.5 Implementation of the Domestic Rate Reform..............................56
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2.4 General Rates ...........................................................................................57
2.4.1 Rates and Customer Description ........................................................57
2.4.1.1 Rate L...........................................................................................57
3. IMPACTS OF THE RATE INCREASE ..........................................................59
3.1 Projected Revenues by Rate class and Component .................................59
3.2 Customer Bills ...........................................................................................60
3.2.1 Domestic Rates ..................................................................................60
3.2.1.1 Distribution of Rate Impacts .........................................................60
3.2.1.2 Impact on Monthly Bills ................................................................60
3.2.1.3 Impact on the Average Customer.................................................61
3.2.1.4 Impact on Typical Home Types ....................................................62
3.2.1.5 Impact on Low-Income Customers...............................................62
3.2.2 General Rates.....................................................................................66
3.2.2.1 Distribution of Impacts..................................................................66
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1. CONTEXT OF THE APPLICATION
Hydro-Quebec Distribution’s current rates are described in the document entitled
Distributor’s Rates and Conditions (hereafter, Rate Handbook) effective April 1,
2008, as approved on March 12, 20081 by the Régie in its decision D-2008-33,
following decision D-2008-0242, as well as in its decision D-2008-0443.
The current application pertains to rates for 2008-2009, as well as the resulting
modifications to the Rate Handbook.
1.1 Follow-up of Decision D-2008-024
1.1.1 Customer Charge for Domestic Rates
The customer charge covers the fixed costs incurred (customer service charges,
metering charges, billing, etc.) to serve each customer. This amount is therefore
independent from energy consumption.
In its R-3644-2007 application, the Distributor proposes to renew the freeze of
the customer charge, effective since April 1, 2005. HQD specifies that customers
should pay for costs incurred to serve them, regardless of energy consumption.
Two intervenors oppose this proposal: they believe that the customer charge is
too high and that it should accurately reflect cost causality.
It its decision D-2008-024, the Régie asks the Distributor to analyze the
composition and the level of customer charge in the context of the current rate
application. This analysis is found in Section 2.3.2.1. This analysis has previously
been the subject of a working group meeting with intervenors and Régie
technical staff that took place on June 25, 2008.
1
Decision on the approval of the Distributor’s rate grid applicable as of April 1, 2007.
Application to set electricity rates for the year 2008-2009.
3
Decision approving the modifications to the Distributor’s Rates and Conditions pursuant to decisions D2008-028 and D-2008-042.
2
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.
1.1.2 Analysis of the DT Rate Structure
The rate reform proposed by the Distributor in its R-3644-2007 application did not
specifically broach the DT rate. In its decision, the Régie asks the Distributor to
provide, in the current rate filing, an analysis of the DT rate structure, taking into
account the current Quebec energy context as it relates to post-heritage supply
costs. This analysis is presented in Section 2.3.2.2.
1.1.3 Analysis of Customer Segmentation for Rates G, M and L
Given the reform of the general rates proposed by the Distributor in the R-36442007 application, the Régie notes that eventually, the biggest Rate G consumers
should naturally migrate to Rate M, which would encompass customers with cost
characteristics more similar to theirs than to those of the small Rate G
customers.
However, the number of Rate M customers will double, going from 12,600 to
approximately 26,300 and will eventually consist of small customers (50 kW) and
very big customers (over 4,000 kW). The Régie is concerned that given this new
rate structure, customers with the same load factor (LF) will be billed at the same
unit cost, independently of their annual energy consumption.
In its decision D-2008-024, the Régie asks the Distributor to present, in the
current rate filing, an analysis of the customer segmentation for the G, M and L
general rates. This analysis should establish the link between the consumption
characteristics of these customers, particularly the LF and the annual
consumption volume, as well as the customers’ cost characteristics, particularly
cost driver factors for capacity, energy, and the customer charge.
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1.1.4 The “Heure Juste” Ratemaking Project
In its R-3644-2007 rate application, the Distributor proposed a time-of-use rate
(TOU) pilot project to the Régie. In its decision D-2008-024, the Régie
authorized the Distributor to complete the TOU project, as presented. The Régie,
however, requests that the Distributor use the alternative version of the DB Rate,
filed in response to a Régie question. The Régie also requests that a sample of
Rate D customers be able to see in real-time, through the use of a display
[translator’s note: presumably on the meter], the impacts of their consumption
choices on their electricity bill.
The follow-up of the pilot project, whose commercial name is heretofore, the
“Heure Juste” (“Right Time”) ratemaking project, is found in Section 6.
1.1.5 Electricity Rates Applicable to the Schefferville System
The decision D-2006-123 authorizes the Distributor to take on the customers of
the Schefferville remote community, situated north of the 53rd parallel.
In order to ensure that the Schefferville electricity rates, which are significantly
lower than those of customers on the Distributor’s main grid, are harmonized
with the main grid without creating a rate shock, the Distributor proposes to
introduce, as of April 1, 2008, a transitional rate, over a period of five years, by
applying a tapering rebate on the rates effective south of the 53rd parallel.
The Distributor also proposes to modify the Rate Handbook to avoid the
application of dissuasive rates, effective north of the 53rd parallel, to Schefferville
system customers. The Distributor proposes to apply the rates and service
conditions applicable south of the 53rd parallel be also applicable to the
Schefferville system.
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In its decision D-2008-024, the Régie accepts the Distributor’s proposal with
respect to the introduction of a transition rate for customers in the remote
community of Schefferville. However, the Régie does not indicate what type of
rate to apply to this system. The Régie asks the Distributor to file, in the current
rate case, a cost study for the Schefferville system in order to examine the
opportunity of introducing a specific rate scheme for the customers of this
system. This study is presented in Section 7.
1.1.6 Differentiated Rate Increases
In its decision D-2007-12, the Régie indicates to the Distributor that as of the
2008 rate application, the Distributor could propose rate adjustments
differentiated by customer class, in which each adjustment reflects the evolution
of the costs attributed to the corresponding customer class.
In setting the Distributor’s rates, the Régie will judge the just and reasonable
nature of the requested rate increases, by taking into account the set of Sections
of the Act, which apply in this case, including the Section pertaining to crosssubsidization of domestic customers.
On December 19, 2007, as permitted in Article 10 of the 1st Paragraph of
Section 49 of the Act, the government adopted Decree 1164-2007 to indicate its
socio-economic concerns to the Régie:
THAT the following economic, social and environmental concern, be
indicated to the Régie de l’énergie, in order to foster a balanced evolution
of the electricity rates among customer classes:
THAT during the setting of the electricity rates, the rate adjustments
among the customer classes should be allocated in such a way as to
ensure stability in the evolution of the rates among customer classes.4
4
Decree 1164-2007 Concerning the economic, social and environmental concerns indicated to the Régie
de l’énergie, in order to foster a balanced evolution of the electricity rates among customer classes, (2008)
140 G. O. II, 347.
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(Unofficial translation of the Decree; translator’s version)
In its decision D-2008-024, the Régie asks the Distributor to apply a uniform
increase to all of the rates. Moreover, it asks the Distributor to file, in the next
rate case, different scenarios of differentiated increases. These scenarios are
found in Section 2.2.
2. RATE INCREASE AND CROSS-SUBSIDIZATION FOR 2008-2009
2.1 Variances between Revenue Requirements and Projected
Revenues for 2009
Taking into account the current rates and the 2009 revenue requirement, the
Distributor is projecting a shortfall of $207 million.
2.2 Proposed Rate Increase and Impact on Cross-Subsidization
The Distributor asks the Régie to approve an overall rate increase of 2.2%
starting April 1, 2009, in accordance with the rates proposed in HQD-12,
Document 2 of this evidence. This increase will allow for $141 million in
additional revenue between April 1 and December 31, 2009 as well as a
regulatory provision of $66 million (see HQD-1, Document 1).
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Figure 1
Evolution of Electricity Rates and of the Consumer Price Index
Figure 1 shows the evolution, between 1998 and 2009, of the Consumer Price
Index and the Distributor’s rates including the proposed increase. The projected
annual inflation rate for 2008 and 2009 is 2.0%, which means that with the
requested 2.2% increase, customers will be subject to an actual increase of
0.2%, on average. In return, over the period, customers will continue to benefit
from an actual gain because the Consumer Price Index will have increased by
27.2%, while the Distributor’s rates will have increased by 19.3%.
As described in Section 4 of the current document, Quebecers continue to
benefit from the stability of electricity prices, while the prices of heating oil and
natural gas have been subject to significant increases and great volatility. Thus,
between May 1, 1998 and April 1, 2008, the energy for an average oil-heated
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home increased by 246%, whereas the energy bill for a home heated by natural
gas increased by 76%.
The Distributor also proposes a uniform rate increase by customer class. Given
this uniform rate increase, the cross-subsidization indices for 2008 remain
relatively stable before and after the rate increase, as the following table
demonstrates.
TABLE 1
IMPACT OF A UNIFORM INCREASE ON THE CROSS SUBSIDIZATION
INDEX
Revenue
Requirement
2009
($M)
2009
Projected
Revenues
Before
Increase
($M)
CrossSubsidization
Index
Before
Increase
(%)
Projected
Revenues
After
Increase of
Jan. 1, 2009
CrossSubsidization
Index
Following
Increase
(%)
($M)
Domestic
5,312
4,317
81.9
4,412
81.9
Small Power
1,110
1,362
123.7
1,392
123.7
Medium Power
1,466
1,905
131.0
1,947
131.0
Large Power
1,592
1,820
115.3
1,860
115.3
Total – Regular
Rates
9,480
9,405
100.0
9,612
100.0
1,053
1,053
N.A
1,053
N.A
49
1
N.A
1
N.A.
10,582
10,459
N.A
10,666
N.A
Special
Contracts
Consumption
Management
and Back-Up
Energy Source
Rates
Total
Note: Results may not tally due to rounded data.
In its decision D-2007-12, the Régie revisited the principle of maintaining the
cross-subsidization as written in its Act.
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As of the 2008 rate application, the Distributor could propose rate
adjustments differentiated by customer class, in which each adjustment
reflects the evolution of the costs attributed to the corresponding customer
class.5
(Unofficial translation of the decision; translator’s version)
While sharing the concerns articulated by the Régie in its decision, that is the
reflection of true costs, as well as equity among customer classes, the
application of differentiated rate adjustments remains a question of public
interest that is best left to the Régie to arbitrate. The Distributor, however,
submits in Table 2 potential differentiated rate increases by customer class that
could reflect the variation in their cost of service6; the impact on the crosssubsidization levels is also shown.
TABLE 2
IMPACT ON CROSS-SUBSIDIZATION OF A DIFFERENTIATED RATE
INCREASE (VARIATION IN THE COST OF SERVICE)
Cross-Subsidization 2009
2009
Rate increase
Before increase
After increase
(%)
(%)
(%)
Domestic
Small Power
Medium Power
Large Power
3.6
2.6
0.2
0.7
81.9
123.7
131.0
115.3
83.0
124.2
128.4
113.6
Total
2.2
100.0
100.0
An examination of Table 2 reveals that the increases in the domestic and small
power classes are much more important than those of medium and large power
classes.
5
6
D-2007-12, page 94.
See Appendix A for details regarding the calculations.
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In its last decision, the Régie asked the Distributor to file in its next rate
application different scenarios of differentiated increases. First off, the Distributor
specifies that there is no recognized rule or principle in the field. Thus, the
scenarios provided by the Distributor rely on a criterion of maximum deviation
between the increase for each customer class and the average increase
requested for all customers. For example, if the average increase was 5% and
the maximum deviation set with respect to this average increase was 20%, the
maximum increase that could be applied to a customer class would be 6%7; if
the maximum deviation was 30%, the maximum increase would be 6.5%. The
application of a criterion of maximum deviation assumes that in each rate case,
the weight given to the “Cost increase” in the calculation of differentiated
increases could be reduced while increasing the weight of the “Adjustments”,
which are proportional to the revenues forecast before the increase for each
customer class8. This also implies that when a customer class is subject to an
increase which is lower than the increase based on the variation in the cost of
service, then the other classes will be subject to increases that are higher than
those that they would have undergone in a scenario based on the variation of
this same cost.
In return, from year to year, notwithstanding the increase in the revenue
requirement specific to each customer class, the customers from a given class
will be protected from a rate increase that is disproportionately high relative to
the rest of the customers. This ensures stability in the evolution of rates among
customer classes. In so doing, the criterion of maximum deviation could fulfill the
government’s Decree 1164-2007.
The following table presents scenarios of maximum deviation of 20, 30 and 40%
for 2009, as well as their impacts on the cross-subsidization index.
7
That is, 5% + (20% * 5%). If the increase based on the variation of the cost of service is less than 6%, for
example, 5.5%, the latter increase would prevail.
8
According to these scenarios, there would be a transfer of costs from Column e to Column g of Appendix
A.
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TABLE 3
IMPACT ON CROSS-SUBSIDIZATION OF A DIFFERENTIATED RATE
INCREASE (CRITERIA OF MAXIMUM DEVIATION)
Key Column 1:
Domestic
Small Power
Medium Power
Large Power
Total – Regular Rates
Row 1: 20% Scenario; 30% Scenario; 40% Scenario
Row 2: Cross-subsidization before the increase; Rate increase; Crosssubsidization after the increase; Rate increase; Cross-subsidization after the
increase; Rate increase; Cross-subsidization after the increase.
2.3 Domestic Rates
2.3.1 Rates and Customer Description
2.3.1.1 Rate D
Rate D is a rate that applies to a contract, for which the use of electricity is
domestic, that is, exclusively for domestic purposes in a dwelling, apart from the
exceptions described in the Rate Handbook. Electricity delivered to farms for the
purposes of growing crop and animal farming is also subject to Rate D.
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Rate D applies to dwellings for which electricity is metered separately. Therefore,
for buildings with multiple housing units, Rate D is applied when the consumption
for each housing unit is individually metered. This rate also applies since the
termination of Rate DM on April 1, 2008, to apartment buildings or community
residences with dwellings with bulk metering, for which construction began on or
after April 1, 2008.
The structure of Rate D, described in Table 4, consists of a customer charge
(40.64¢/day) and two increasing prices for the energy consumed, that is, a lower
price for the first 30 kWh per day (5.40¢/kWh), while consumption exceeding that
volume is billed at a higher price (7.33¢/kWh). During the winter period, when the
maximum power demand exceeds 50 kW, the excess portion is billed at the
monthly price of $6.21/kW.
TABLE 4
D Rate on April 1, 2008
Customer charge
40.64¢/day
The first 30 kWh/day
5.40¢/kWh
Remaining consumption
7.33¢/kWh
Winter demand charge (exceeding 50 kW)
$6.21/kW
As shown in Table 5, a total of 2,974,730 Rate D contracts were included in the
analysis covering the period between May 1, 2007 and April 30, 2008. The
consumption and revenues associated with these contracts amount to 51.0 TWh
and $3.7 billion, based on rates effective April 1, 2008. Among all contracts
combined, only 2,562 were billed for a winter demand charge.
Over two thirds of residential customers had an all-electric heating (AEH) system;
the other third used a different heating system (non-AEH),9 such as natural gas,
heating oil, wood or mixed. Over 42,800 contracts corresponded to farms whose
activities of animal raising and growing crops made them admissible to Rate D.
TABLE 5
9
Residential customers at the DT dual-energy Rate are discussed in Section 2.3.1.3.
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Description of D Rate Customers
Contracts
Annual
Consumption
GWh
Total Revenues
M$
Residential customers
All electric heating (AEH)
Without capacity invoice
With capacity invoice
2,108,968
2,107,786
1,182
39,593
39,227
366
2,839
2,810
28
Other types of heating
Without capacity invoice
With capacity invoice
822,936
822,589
347
9,755
9,639
115
724
715
9
Total residential customers
2,931,904
46,237
3,563
41,793
1,033
1,354
261
99
20
42,826
1,615
118
2,972,168
2,562
50,220
743
3,624
57
2,974,730
50,963
3,681
Farms
Without capacity invoice
With capacity invoice
Total for farms
All domestic customers
Without capacity invoice
With capacity invoice
Total domestic customers at
the D Rate
Table 6 shows the revenue generated by rate component, derived from the
reference data for Rate D.
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TABLE 6
Rate D: Revenue by Rate Component 2007-2008
Rates in effect April 1, 2008
Price
$M
Rate Components
Customer charge (¢/day)
40.64
443
Energy
1st block (¢/kWh)
2nd block (¢/kWh)
5.40
7.33
1,401
1,834
Demand charge ($/kW)
6.21
3
Total
3 355
Table 7 shows the monthly bills of Rate D customers for the period between May
1, 2007 and April 30, 2008. Over that period, the average annual consumption for
Rate D was 17,056 kWh and the average monthly bill was $103. For a
consumption of 26,484 kWh per year, the average single-family home with an
electric heating system had a monthly bill of $157.
TABLE 7
Average Monthly Bills for Rate D Customers
Rate on April 1, 2008
Average Annual
Consumption
(kWh)
Average Monthly
Bill
($)
All Rate D customers
All electric heating
Not heated with electricity
17,056
18,953
12,576
103
113
78
Average single-family home
heated with electricity (158 m2)
26,484
157
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2.3.1.2 Rate DM
Rate DM is a rate that is similar to Rate D but adapted to bulk metering (see
Table 8). It is reserved to contracts that are subject to Rate DM on March 31,
2008, as well as to an apartment building or community residence with dwellings
with bulk metering, for which construction began prior to April 1, 2008.
The singularity of Rate DM resides in the multiplier applied to the number of
dwellings, in the calculation of the customer charge, and in the level of the first
block.
The multiplier corresponds to the following:

for an apartment building and community residence with dwellings: to the
number of dwellings;

for a community residence with both dwellings and rooms: to the number
of dwellings in the community residence, plus
o 1 for the first 9 rooms or less, plus
o 1 for each additional room.
The prices for the first and second blocks are 5.40¢/kWh and 7.33¢/kWh
respectively. During the winter period, when the maximum power demand
exceeds 50 kW, the excess is billed at the monthly price of $1.53/kW.
TABLE 8
DM Rate on April 1, 2008
Customer charge
40.64¢/day X multiplier
The first 30 kWh/day X multiplier
5.40¢/kWh
Remaining consumption
7.33¢/kWh
Winter demand charge (exceeding 50 kW)
$1.53/kW
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As shown in Table 9, a total of 20,351 Rate DM contracts were included in the
analysis covering the period between May 1, 2007 and April 30, 2008. The
consumption and revenues associated with these contracts amount to 2.3 TWh
and $165 million, based on rates effective April 1, 2008. Among all contracts
combined, only 3,080 were billed for a winter demand charge.
Almost three quarters of residential customers at Rate DM had an all-electric
heating (AEH) system; the other quarter used a different heating system (nonAEH), such as natural gas, heating oil, wood or mixed.
TABLE 9
Description of Rate DM Domestic Customers
(2007-2008)
Contracts
Annual
Consumption GWh
Total Revenues
M$
Residential customers
All electric heating (AEH)
Without capacity invoice
With capacity invoice
14,698
12,033
2,665
1,864
464
1,400
135
33
101
Other types of heating
Without capacity invoice
With capacity invoice
5,307
4,943
364
377
137
241
28
10
17
Total residential customers
20,005
2,242
163
295
51
21
15
1
1
346
36
3
17,271
3,080
622
1,656
45
120
20,351
2,278
165
Farms
Without capacity invoice
With capacity invoice
Total for farms
All domestic customers
Without capacity invoice
With capacity invoice
Total domestic customers at
Rate D
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Table 10 shows the revenue generated by rate component, derived from the
reference data for Rate DM.
TABLE 10
Rate DM : Revenue by Rate Component 2007-2008
Rates in effect April 1, 2008
Price
$M
Rate Components
Customer charge (¢/day)
40.64
28
Energy
1st block (¢/kWh)
2nd block (¢/kWh)
5.40
7.33
89
46
Demand charge ($/kW)
1.53
2
Total
165
Table 11 shows the monthly bills of Rate DM customers for the period between
May 1, 2007 and April 30, 2008. Over that period, the average annual
consumption for Rate DM was 111,920 kWh and the average monthly bill was
$676. For a consumption of 124,160 kWh per year, the average single-family
home with an electric heating system had a monthly bill of $730.
TABLE 11
Average Monthly Bills for Rate DM Customers
Rate on April 1, 2008
Average Annual
Consumption
(kWh)
Average Monthly
Bill
($)
All Rate DM customers
All electric heating
Not heated with electricity
111,920
126,456
72,463
676
762
445
Average single-family home
heated with electricity (158 m2)
124,160
730
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2.3.1.3 Rate DT
Rate DT is an optional rate that applies to all electricity consumption for any
customer eligible for Rates D or DM, who uses a dual energy system, mainly for
domestic purposes. A dual energy system is a system that is used for spaceheating or for space-heating and water heating, which has been designed such
that electricity can be used as the main energy source with a fuel source as an
auxiliary source. To be eligible for Rate DT, the dual energy system’s capability
in both fuel mode and electricity mode must be sufficient to provide all the
heating necessary for the designated space.
Moreover, the heating energy
sources should not be used simultaneously. The dual energy system should also
be equipped with a switch, linked to a thermal sensor, which enables the rateswitching function on the meter and also provides for the automatic transfer from
one source of energy to the other10.
The goal of Rate DT is to reduce the heating costs at the peak period, as well as
to shift consumption from the peak to the off-peak period. In contrast to the CII
dual energy rate which was abrogated in 2006, the residential dual energy rate
was never conceived as an option to encourage dumping of surplus energy.
Rather, this option allows the Distributor to offer an alternative to acquisition of an
all-electric heating system to customers using fuel as a heating source. The
Distributor thus ensures that the heating load of the new DT Rate customers will
not be present at the peak.
In addition to the customer charge of 40.64¢/day, Rate DT is composed of two
energy rates that vary according to exterior temperature: 4.33¢/kWh when the
exterior temperature is equal to or above -12°C or -15°C, depending on the
climatic zone, and 17.55¢/kWh when the temperature is below -12°C or -15°C
(see Table 12 for the price structure and Table 13 for the zones, in which the
10
The customers can also use a manual switch to manage the transfer themselves from one source of
energy to the other.
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transfer temperature is -15°C). During the winter period, when maximum power
demand exceeds 50 kW, the excess is billed at the monthly rate of $1.53/kW
when bulk metering11 is applicable and $6.21/ kW in all other cases.
TABLE 12
Rate DT on April 1, 2008
Customer charge
Off-peak energy price
Peak energy price
Winter demand charge (exceeding 50 kW)
Building with bulk metering
All other cases
40.64¢/day
4.33¢/kWh
17.55¢/kWh
$1.53/kW
$6.21/kW
TABLE 13
Zones in which the Rate DT Transfer Temperature is -15°C
Noroît (Rouyn-Noranda, Val-d'Or, LG-2/Nemiscau)
North of the de Lanaudière Region
High-Laurentians
Haute-Mauricie
From St-Féréol-des-Neiges to the Saguenay River
Saguenay
Côte-Nord
Îles-de-la-Madeleine
Lower St-Laurent and Gaspésie1
Note 1) Except municipalities bordering (direct access) the River or the Baie des
Chaleurs, between St-Fabien and Cascapédia River.
Rate DT includes approximately 121,000 contracts, that is, approximately 4% of
the residential market. Of these some 121,000 contracts, 103,284 were selected
for the period between May 1, 2007 and April 30, 2008. These contracts
generated sales of 2.4 TWh and revenues of $133 million. Rate DT also allowed
the Distributor to shave 810 MW from the system’s peak.
11
Because the DM Rate is closed to new contracts since April 1, 2008, only dual energy customers
considered eligible to the DM Rate are billed according to the payment methods associated with bulk
metering.
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The number of Rate DT customers has been relatively stable since the end of the
subsidization programs in the 1990s. In fact, Distributor notes a slight net annual
increase of approximately 500 contracts for Rate DT. In comparison, conversions
to all-electric systems have risen to an average of 10,000 per year. These
conversions are mainly comprised of customers who need to replace their
heating systems. The high prices of heating oil could however encourage owners
to change their heating systems earlier than planned.
TABLE 14
Rate DT: Revenue by Rate Component 2007-2008
Rate Components
Rates in effect April 1, 2008
Price
$M
Customer charge (¢/day)
40.64
16
Energy
Off-peak (¢/kWh)
Peak (¢/kWh)
4.33
17.55
101
16
Energy
Off-peak (¢/kWh)
Peak (¢/kWh)
6.21
1.53
0.4
0.0
Total
133
2.3.1.4 Rate DH
The Rate DH is an experimental rate that is differentiated in time and which
applies only to contracts eligible for Rate D.
At the beginning of the 1990s, some intervenors expressed the desire for HydroQuébec to offer a time-of-use (TOU) rate to allow customers to reduce their
energy bill by modifying their consumption habits at the opportune time.
In
return, this rate would allow Hydro- Québec to avoid costs in the peak period and
to transfer the greater part of these savings to customers.
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With this orientation, Hydro-Québec undertook a TOU pilot project in 1993, Rate
DH.
As indicated in Table 15, besides the customer charge of 40.64¢/day, Rate DH
comprises two prices for energy consumed and these prices vary according to
the period of consumption. The price for energy consumed off-peak is 4.38¢/kWh
and the on-peak energy price is 14.64¢/kWh (in the winter period between 6 am
and 11 am and between 3 pm and 10 pm, from Monday to Friday inclusively).
TABLE 15
Rate DH on April 1, 2008
Customer charge
Off-peak energy price
Peak energy price
40.64¢/day
4.38¢/kWh
14.64¢/kWh
Rate DH currently includes 155 customers, who generate $0.22 million in
revenue on sales of 3 GWh.
Rate DH was calibrated in 1993 in the context of integrated utility. Its current
structure no longer reflects the avoided cost structure, as is the case for Rates
DA and DB which are the subject of the following Section.
In light of the results of the “Heure Juste” (“Right Time”) rate project, the
Distributor will evaluate the possibility of gradually transferring current
subscribers to a new dynamic rate or even of abrogating Rate DH while offering
subscribers a transition period to mitigate the rate impacts. Given this
perspective, the proposed increases will be more concentrated on off-peak
energy prices than on-peak prices.
2.3.1.5 Rates DA and DB
The DA and DB Rates are experimental rates that are differentiated according to
time-of-use. They apply to any Rate D contract selected by the Distributor,
subject to the customer’s acceptance of the invitation and subscription to the
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Rate within the established deadlines. Rates DA and DB are applicable for a
limited time, that is, until March 31, 2010 at the latest or until cessation of the
customer’s commitment.
Rate DA is presented in the following table. It comprises peak and off-peak
prices, which each include a 1st block of 15 kWh, and, which vary in winter and
summer periods. Moreover, the DA Rate includes a price for critical hours, that
is, for 100 hours divided in blocks of four hours, which can be selected by the
Distributor between 7 am and 11 am and between 5 pm and 9 pm, without taking
into account of:

Saturday and Sunday;

December 24, 25, 26 and 31, January 1 and 2; as well as Good Friday
and Easter Monday, when these days occur during the winter period.
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TABLE 16
Rate DA on April 1, 2008
Customer charge
Energy price for the first 15 kWh consumed during the
summer period
40.64¢/day
4.60¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
Energy price for the balance of the energy consumed
during the summer period
6.56¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
Energy price for the first 15 kWh consumed during the
winter period
3.55¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
December 25 and January 1
Energy price for the balance of the energy consumed
during the winter period
5.50¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
December 25 and January 1
Energy price for the first 15 kWh consumed
6.10¢/kWh
Between 6am and 10pm, Monday – Friday
Energy price for the balance of the energy consumed
8.06¢/kWh
Between 6am and 10pm, Monday – Friday
Energy price for the critical hours
18.06¢/kWh
Notice regarding the critical hours is sent to customers by email or by any other
means determined by the Distributor on the evening prior to their occurrence.
Rate DB is presented in Table 17. It comprises peak and off-peak prices, which
each include a first block of 15 kWh, and, which vary in winter and summer
periods.
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TABLE 17
DB Rate on April 1, 2008
Customer charge
Energy price for the first 15 kWh consumed during the
summer period
40.64¢/day
4.60¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
Energy price for the balance of the energy consumed
during the summer period
6.56¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
Energy price for the first 15 kWh consumed during the
winter period
4.29¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
December 25 and January 1
Energy price for the balance of the energy consumed
during the winter period
6.27¢/kWh
Between 10pm and 6am, Monday – Friday
Saturday and Sunday
December 25 and January 1
Energy price for the first 15 kWh consumed during the
summer period
6.10¢/kWh
Between 6am and 10pm, Monday – Friday
Energy price for the balance of the energy consumed
during the summer period
8.06¢/kWh
Between 6am and 10pm, Monday – Friday
Energy price for the first 15 kWh consumed during the
winter period
6.52¢/kWh
Between 6am and 10pm, Monday – Friday
Energy price for the balance of the energy consumed
during the winter period
8.50¢/kWh
Between 6am and 10pm, Monday – Friday
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Rates DA and DB are the subject of a pilot project which is explored in more
detail in Section 6.
2.3.2 Analyses Requested in Decision D-2008-024
2.3.2.1 Rate D Customer Charge
The customer charge is the fixed component of the domestic rates. This charge
partly covers the costs that the Distributor incurs to establish a commercial
relationship, specific to each contract, that is, the customer service costs (meter
reading, billing, cash receipts, collections, electricity theft, telephone response,
complaints and claims, community relations) and metering costs (acquisition,
installation and maintenance of metering equipment). These costs are linked first
and foremost to the number of customers served and are independent of energy
consumption.
The establishment of the level of the customer charge is carried out in the overall
context of the Distributor’s rate strategy for the domestic rate. During previous
rate applications, the Distributor’s objective was to improve the price signal and
to reflect the marginal costs in the energy prices. Given this orientation, the
adopted rate strategy was to increase the price of the second block more than
the price of the first block and to freeze the customer charge. Moreover, given
that the revenue requirement for the customer service and the metering of
domestic customers was slightly under the customer charge, the freeze was also
justified on a cost basis.
2.3.2.1.1 Decision D-2008-024
In its decision D-2008-024, the Régie notes that two intervenors oppose the
Distributor’s strategy concerning the customer charge; they believe that the
customer charge is too high and that it should accurately reflect cost causality.
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Therefore, the Régie “judges it to be an opportune to review the costs included in
the customer charge, in order to ensure that the amount attributed to this charge
accurately reflects the fixed costs actually incurred to serve each customer”12.
The Régie therefore requests that the Distributor analyze the components of the
customer charge and present the results before hand to the Régie in a working
group session13.
2.3.2.1.2 Principles and Orientations
The establishment of the level of the customer charge is done through two
different, but complementary exercises, cost allocation and rate strategy.
The customer charge is therefore an element of the Distributor’s rate strategy
and the exercise to set this charge takes into account several factors, including:

the components and the level of contract costs;

the stabilization of revenue;

the rate structure;

the price signal.
The Components and the Level of the Contract Costs
Cost causality guides the Distributor in its choice of cost components to be
recovered via the customer charge. Certain costs are independent from
consumption and are therefore associated with the fixed part of the rate. The
energy prices, for their part, serve to recover costs related directly to
consumption.
The Distributor generally relies on the user pays principle. The customers
generate costs before even having started to consume and these costs should
be recovered in the fixed component of the rates. A departure from this
orientation, in which the costs generated by certain customers would be borne by
12
13
D-2008-024, page 81 (unofficial translation; translator’s version).
This working group session took place on June 25, 2008.
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other customers, is not a winning solution in the long-term, even if such a
solution relies on a principle of social equity.
The customer charge should
therefore be used to recover specific costs incurred by customers that are not a
function of their own consumption.
Stabilization of Revenue
For domestic rates, the level of the customer charge plays an important role in
the stability of revenue because the revenue associated with this charge is not
subject to as much volatility as the revenue from energy consumption.
The Rate Structure and the Price Signal
Consideration must also be given to the fact that the customer charge
component is part of a whole and that each of the rate components must be set
according to the costs, but also as a function of an overall vision of the rate and
rate-setting principles.
As an example, the Distributor pursues the objective to improve the price signal
associated with energy consumption by reflecting the marginal cost signal in the
energy price for the domestic rate. From this point of view, the freeze of the
customer charge since 2005 has allowed the Distributor to improve this price
signal by applying more of the rate increase to the price of the second block.
Finally, it must be noted that the establishment of the customer charge is not a
one-dimensional exercise, and that there is no absolute rule on this subject. The
Distributor should make choices by considering the different elements.
2.3.2.1.3 Contract Costs
The contract costs that are normally considered in the calculation of the customer
charge are those that are considered in cost allocation and those that are
independent of energy consumption (see the following table).
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TABLE 18
Contract Costs Used in the Calculation of the Customer Charge
Costs Considered
Customer service: meter reading, billing,
cash receipts, collections, electricity theft,
telephone response, complaints and
claims, community relations
Costs Excluded
Supply
Transmission
Distribution
Metering costs: acquisition, installation
and maintenance of metering equipment
Others (PGEÉ (i.e. Energy Efficiency
Plan), cash balance)
Connection
Minimum system
The Distributor’s position, as expressed during the rate cases at the Régie since
2004, is to exclude connection and minimum system costs and to ensure that the
customer charge covers the customer service and metering costs.
The following table presents a detailed breakdown of the revenue requirement
that is not related to either capacity or energy consumption and that can be taken
into consideration in the establishment of the customer charge14. When the
overall revenue requirement is considered, the contract cost per day is 64.37¢.
This amount is relatively high because it includes all the connection and
minimum system costs.
14
This is an updated version of the table that was presented during the working group session of June 25,
2008.
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TABLE 19
Detailed Breakdown of the Revenue Requirement
Contract costs for
domestic rates
(R-3677-2008)
Overall revenue requirements
(millions$)
(¢/day)
references
Current level
of the
customer
charge
Alternative
scenario
Customer service
431.9
33.43
33.43
19.52
Meter reading
Billing
Cash receipts
Collections
Electricity theft
Telephone response
Complaints and claims
Community relations
Remote communities –
Others
Revenue (fees for
admin and opening file)
Sales and marketing
84.1
98.7
8.8
120.6
5.9
127.3
10.3
4.1
4.5
6.51
7.64
0.68
9.33
0.46
9.85
0.80
0.32
0.35
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
X
X
X
X
X
X
X
X
X
X
X
X
X*
X*
X*
X
X
X
-48.5
-3.75
(10)
X
X
16.1
1.24
X
70.8
329.0
5.48
25.46
(11)
(12)
X
Metering
System (Contract)
5.48
5.48
Connection
Minimum System
44.2
284.8
3.42
22.04
Total
831.6
64.37
(13)
(14)
1.73
40.64
25.00
* Partial amount.
References: R-3677-2008, Exhibit HQD-11, Document 3
1) (Table 14B, column 2, rows 5 and 20) + [(Table 13B, column 2, rows 5 and 20) X (Table 1,
column 3, row 20)]
2) (Table 14B, column 3, rows 5 and 20) + [(Table 13B, column 3, rows 5 and 20) X (Table 1,
column 3, row 20)]
3) (Table 14B, column 4, rows 5 and 20) + [(Table 13B, column 4, rows 5 and 20) X (Table 1,
column 3, row 20)]
4) (Table 14B, column 5, rows 5 and 20) + [(Table 13B, column 5, rows 5 and 20) X (Table 1,
column 3, row 20)]
5) (Table 14B, column 6, rows 5 and 20) + [(Table 13B, column 6, rows 5 and 20) X (Table 1,
column 3, row 20)]
6) (Table 14B, column 7, rows 5 and 20) + [(Table 13B, column 7, rows 5 and 20) X (Table 1,
column 3, row 20)]
7) (Table 14B, column 8, rows 5 and 20) + [(Table 13B, column 8, rows 5 and 20) X (Table 1,
column 3, row 20)]
8) (Table 14B, column 9, rows 5 and 20) + [(Table 13B, column 9, rows 5 and 20) X (Table 1,
column 3, row 20)]
9) (Table 33, column 12, row 9) + [(Table 33, column 12, row 2) X (Table 1, column 3, row 20)]
10) (Table 27B, column 3, rows 5 and 20) + (Table 27B, column 4, rows 5 and 20)
11) (Table 25B, column 7, rows 5 and 20) + [(Table 24B, column 7, rows 5 and 20) X (Table 1,
column 3, row 20)] + (Table 25B, column 10, rows 5 and 20) + [(Table 24B, column 10, rows 5
and 20) X (Table 1, column 3, row 20)]
12) (Table 7, column 13, row 5) + [(Table 6, column 12, row 5) X (Table 1, column 3, row 20)]
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13) (Table 7, column 9, row 5) + (Table 33, column 9, row 9) + [{(Table 6, column 8, row 5) +
(Table 33, column 9, row 2)} X (Table 1, column 3, row 20)]
14) (Table 7, column 6, row 5) + (Table 33, column 6, row 9) + [{(Table 6, column 5, row 5) +
(Table 33, column 6, row 2)} X (Table 1, column 3, row 20)] + (Table 7, column 8, row 5) + (Table
33, column 8, row 9) + [{(Table 6, column 7, row 5) + (Table 33, column 8, row 2)} X (Table 1,
column 3, row 20)]
During the 2008-2009 rate case, as reported by the Régie in decision D-2008024, an expert indicated that the level of the customer charge was too high. He
proposed a reduction of this charge to 25¢/day in order to further increase the
price of the second energy block. The Distributor therefore presents in Table 19
an alternative scenario proposed by the RNCREQ expert in the 2008-2009 rate
filing, which excludes a portion of the costs associated with telephone response,
collections and electricity theft, in addition to the exclusion of connection and
minimum system costs15
2.3.2.1.4 Benchmarking
It is interesting, at this point, to compare the customer charge applied by the
Distributor with those of other electricity distributors in North America. For the
purposes of comparison, Table 20 shows the level of customer charge for
residential customers applied in April 2007 in selected North American cities.
15
R-3644, Document C-9-13, Expert report of Mr. Lazar (amended version).
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TABLE 20
Customer Charge for 30 Days on April 1, 2007
Residential Customers (1,000 kWh per Month)
Cities
Customer charge
(¢/day)
or Cdn$/month1
Canadian cities
Montreal
40.64
12.19
Charlottetown, PE
Edmonton, AB
Halifax, NS
Moncton, NB
Ottawa, ON
Regina, SK
St. John's, NL
Toronto, ON
Vancouver, BC
Winnipeg, MB
74.23
51.73
36.10
63.87
26.27
51.03
51.97
41.43
12.30
20.80
22.27
15.52
10.83
19.16
7.88
15.31
15.59
12.43
3.69
6.24
Canadian average
42.76
12.83
American cities
Boston, MA
Chicago, IL
Detroit, MI
Houston, TX
Miami, FL
Nashville, TN
New York, NY
Portland, OR
San Francisco, CA
Seattle, WA
24.78
34.22
24.28
0.00
19.92
32.33
45.40
28.90
17.09
11.25
7.43
10.27
7.28
0.00
5.98
9.70
13.62
8.67
5.13
3.38
American average
23.82
7.15
Average
33.74
10.12
Note 1: The exchange rate used is $0.8650 on April 1, 2007.
Even if the Distributor’s customer charge was in the average range, the customer
charge amounts differ widely and reflect differences with respect to the retained
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cost components, with respect to the retained level of these costs , as well as
with respect to the adopted rate strategy. In light of these differences, it is
possible to conclude that there is no absolute rule with respect to the
establishment of the customer charge. Moreover, the customer charge of a good
number of Canadian distributors does not cover the totality of the contract costs.
It is therefore clear that the customer charge is an element of the rate strategy
and that factors other than costs are considered in setting this charge.
2.3.2.1.5 Scenarios Analyzed
Notwithstanding the debate on what the customer charge should cover, the
Distributor is of the opinion that the establishment of the customer charge rests
more on elements such as the price signal and the overall rate structure, as well
as impacts on customers.
Therefore, in undertaking this analysis, the Distributor evaluated scenarios with
increased and decreased customer charges and their impacts on the customer
base. The increased customer charge scenario considers the overall revenue
requirement retained, whereas the decreased customer charge scenario
corresponds to the alternative scenario presented in Table 19. For each of these
scenarios, the revenue deviation is compensated by a price adjustment, either of
both energy blocks or of only one of the blocks.
Increased Customer Charge Scenario
If all of the fixed costs, including the connection and minimum system costs, were
considered in the establishment of the customer charge, this charge would be in
the order of 64¢/day. The Distributor presents in Table 21 what the domestic rate
structure could look like if the revenue increase associated with the increased
customer charge was compensated by a decrease in both energy prices or only
by a decrease in the price of the first energy block.
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TABLE 21
Example of the Rate Structure for Rates D and DM and
Dispersion of Rate Impacts
Using Hypothesis of Constant Revenues
-
Rates D and DM
Increase of the Customer Charge to 64 ¢/day -
Customer
charge
(¢/day)
Rate Structure
st
nd
1 block
2 block
Ratio
¢/kWh
2 /1
nd
st
Dispersion of Rate Impacts
Decrease
Increase
(Min ; Max)
( Min ; Max)
April 1, 2008
40.64
5.40
7.33
1.36
Increase of the customer
charge and equivalent
decrease of the 2 blocks
Increase of the customer
charge and equivalent
decrease of the 1st block
64.37
4.97
6.74
1.36
41% of customers
59% of customers
58.4%
-8.0%
-8.0%
0.00
(-8% ; 0%)
(0% ; 58%)
64.37
4.40
7.33
1.67
63% of customers
37% of customers
58.4%
-18.5%
0.0%
0.00
(-3% ; 0%)
(0% ; 58%)
In the first example, the customers affected by rate increases are the smaller
customers and those with very low consumption levels. 59% of customers would
be subject to bill increases of up to 58%. The impact on the annual bill for
customers that do not have any consumption would be almost $87.16
In the second example, rate increases are mildly mitigated for small customers
through a greater rate decrease for the 1st consumption block. However, the $87
annual increase for customers who do not have any consumption would remain
the same under this scenario.
In order to show the impacts of modifications associated with an increase of the
customer charge, a simulation was carried out for a series of case study
studies(see Table 22). The impacts are in line with those presented above. The
scenario that includes an increase of the customer charge and an equivalent
rate decrease of both energy rates has an upward impact on small customers.
16
365 days* ($0.6437 - $0.4064) = $86.60
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Apartments and customers in the first consumption block have respective
increases of 4% and 5%, that is $33 and $39 annually.
TABLE 22
Rate Impact by Case study
Using Hypothesis of Constant Revenues
- Increase of the Customer Charge to 64 ¢/day Average
Rate D
Customer
17 056 kWh
Apartment
April 1, 2007
$1,232
$817
$1,448
Increase of customer
charge and
equivalent decrease
of both blocks
$0
$33
0.0%
4.1%
Increase of customer
charge and
equivalent decrease
of 1st block
$0
-$7
-$18
-$22
-$23
-$23
-$23
-$23
-$23
-$117
0.0%
-0.8%
-1.3%
-1.2%
-1.0%
-0.7%
-0.5%
-0.1%
-3.1%
-1.3%
Rates D and DM
Small
Home
Large
Home
electricity32 054 kWh
Very
Large
Home
42 818
kWh
Imposing
Home
62 840
kWh
Large
Customer
100 kW
411 700
kWh
$1,879
$ 2,287
$3,076
$4,543
-$17
-$52
-$84
-$148
-1.2%
-2.8%
-3.7%
-4.8%
11 590kWh 20 494 kWh
Average
Home
-Heated with
26 484 kWh
Customer
st
1 Block
Apartment
Building
10 950 kWh
124 160 kWh
$31,367
$740
$8,759
-$265
-$2 311
$39
-$110
-5.8%
-7.4%
5.3%
-1.3%
Beyond the significant dispersion of rate impacts, an increase of the customer
charge and a corresponding decrease of energy rates would lead to a
deterioration of the price signal. In fact, from the moment in which a significant
portion of the electricity bill is unduly fixed, customers have less interest in
reducing their consumption or in making the right energy choices.
Scenarios with a Reduction of the Customer Charge
The alternative scenario that was examined involves a reduction of the customer
charge to 25¢/day and an increase of the second consumption block to
compensate the decrease in revenues. The objective of the RNCREQ expert was
to arrive at the marginal price signal more quickly than the approach proposed by
the Distributor.
A reduction of the customer charge to 25¢/day would have an impact on the bill
of all residential customers. In order to provide a concrete example of the impact
resulting from these modifications, the Distributor shows, in Table 23, the
structure of the domestic rate if the decrease in revenues associated with a
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reduction of the customer charge were compensated by an increase in both
energy rates or only by an increase in the rate of the second consumption block.
When both energy rates are increased to compensate for the loss of revenue
associated with a reduction of the customer charge, 41% of customers are
subject to bill increases of up to 5%. When only the rate for the second
consumption block is increased, the rate increases for larger customers are more
significant (maximum 9%).
TABLE 23
Example of the Rate Structure for Rates D and DM and
Dispersion of Rate Impacts
Using Hypothesis of Constant Revenues
-
Rates D and DM
Reduction of the Customer Charge to 25 ¢/day -
Customer
charge
(¢/day)
Rate Structure
st
nd
1 block
2 block
Ratio
¢/kWh
2 /1
nd
st
Dispersion of Rate Impacts
Decrease
Increase
(min ; max)
( Min ; Max)
April 1, 2008
40.64
5.40
7.33
1.36
Increase of the customer
charge and equivalent
decrease of the 2 blocks
Increase of the customer
charge and equivalent
decrease of the 1st block
25.00
5.68
7.72
1.36
59% of customers
41% of customers
-38.5%
5.3%
5.3%
0.00
(-38% ; 0%)
(0% ; 5%)
25.00
5.40
8.01
1.48
62% of customers
38% of customers
-38.5%
0.0%
9.3%
0.00
(-38% ; 0%)
(0% ; 9%)
In order to show the impacts of modifications associated with a decrease of the
customer charge, a simulation was carried out for a series of case studies (see
Table 24). The impacts of the scenario proposed by the expert Mr. Lazar are
more dispersed, with respective bill decreases of up to 5% and 8% for
apartments and customers in the first consumption block, while the increase for
the average home would be 3% and the one for larger customers would range
between 5% and 9%. It should be noted that customers who benefit from bill
reductions have not made any effort to curtail their consumption. Moreover,
these reductions could be perceived as weakening the price signal.
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TABLE 24
Rate Impact by Case study
Using Hypothesis of Constant Revenues
- Decrease of the Customer Charge to 25 ¢/day Average
Rate D
Customer
17 056 kWh
Apartment
April 1, 2007
$1,232
$817
Increase of customer
charge and
equivalent decrease
of both blocks
$0
-$22
$11
$34
0.0%
-2.7%
0.8%
1.8%
$0
-$42
$11
$49
0.0%
-5.1%
0.8%
2.6%
Rates D and DM
Increase of customer
charge and
equivalent decrease
of 1st block
Small
Home
11 590kWh 20 494 kWh
$1,448
Average
Home
-Heated with
26 484 kWh
$1,879
Large
Home
electricity32 054 kWh
Very
Large
Home
42 818
kWh
Imposing
Home
62 840
kWh
Large
Customer
100 kW
411 700
kWh
Customer
st
1 Block
Apartment
Building
10 950 kWh
124 160 kWh
$ 2,287
$3,076
$4,543
$31,367
$740
$8,759
$56
$97
$175
2.4%
3.2%
3.8%
$1,523
-$26
$72
4.9%
-3.5%
0.8%
$87
160
$297
$2,674
-$57
$69
3.8%
5.2%
6.5%
8.5%
-7.7%
The Distributor believes that it is not justified to decrease the customer charge as
a way to accelerate the process of improving the price signal because the current
strategy of increasing the rate of the second consumption block twice as much as
the first, coupled with a freeze of the customer charge already contributes to
improving the progressivity of the rates17 and, as a result, the price signal. The
rate of the second consumption block went from 5.97¢/kWh at the end of the rate
freeze in 2003 to 7.33¢/kWh on April 1, 2008 and it comes closer to with longterm marginal costs. The Distributor proposes to maintain the current strategy
rather than modifying the structure too quickly by reducing the customer charge
to emphasize the price signal. This approach makes it possible to reach the
marginal costs signal all the while minimizing the impacts on customers.
In addition, reducing the customer charge would be unduly favourable to
customers whose consumption is not regular throughout the year, particularly the
200,000 customers who have a cottage or those who spend part of the winter
outside of Quebec. These contracts generate fixed costs associated with
customer service and metering which would then be assumed by other
customers. It would also be favourable to customers who use a different energy
17
The graph shown in Appendix B shows that the Distributor’s strategy for rate D, applied since 2005, has
made the rate more progressive since April 2006.
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source for space-heating as well as condominium owners since they rarely
consume electricity in the second block.
It must also be noted that, while not reducing customers’ bills as such, the freeze
of the customer charge, which has been authorized by the Régie since 2004,
corresponds to an actual decrease of 11.8%.
2.3.2.1.6 Distributor’s Proposal
At its current level of 40.64¢/day, the customer charge remains slightly higher
than
customer
service
and
metering
costs
for
2008
which
total
38.91¢/contract/day. However, if we add service loop charges to this amount, the
total cost increases to 42.33¢/contract/day. The Distributor therefore proposes to
renew the freeze of the customer charge since it is possible to recover all the
metering and customer service costs as well as a portion of the service loop
charges. This rate freeze plays an important role in the residential rate strategy
for domestic rates.
2.3.2.2 Analysis of the DT Rate Structure
In decision D-2008-024, the Régie requested from the Distributor, in its next rate
application, an analysis of the Rate DT structure which takes into account the
Quebec’s current energy context in terms of post-heritage supply costs. This
Section responds to that request.
2.3.2.2.1 Profitability of the Structure of Rate DT from the Perspective of Society
and of the Distributor
Because of a reduction in the heating load of 810 MW on the system’s peak,18
Rate DT is included in HQD’s supply plan as a consumption management tool.
The analysis that follows makes it possible to evaluate the profitability of Rate
DT.
18
R-3648-2007, HQD-1, document 2, Appendix 2A, page 63.
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If Rate DT were abrogated, there would be a transfer of dual energy customers
to Rate D. The transfer to all–electricity-heating (AEH) would lead to additional
annual consumption of 500 GWh and would increase the heating load on the
system by 810 MW.19
The magnitude of this additional load as well as its
characteristics (high load factor during winter hours) would greatly increase and
pre-empt the Distributor’s additional long-term winter capacity requirements. The
avoided costs for this additional capacity are approximately $40.80/Winter-kW
(increasing annuity, $2009).20 In addition to added capacity costs, the customer
transfer would generate significant costs associated with supply, transmission,
and distribution. On the basis of the avoided costs shown in table 25, the
additional costs to the Distributor are approximately $115 million.
Conversely, abolishing Rate DT would make it possible to reduce residential
consumption of fuel oil. In addition to the avoided costs for fuel oil which total $53
million, abolishing Rate DT would reduce greenhouse gas emissions associated
with residential furnaces, assuming the fuel oil is replaced by electricity
generated by an emission-free energy source. Assuming CO2 credits are
purchased at a price of $15/ton these avoided costs would total $2 million.
Therefore, the total cost of abolishing Rate DT would be approximately $60
million. Therefore, it is not economically justified to abolish this rate from a
societal perspective.
19
Considering current energy prices the Distributor assumes that dual energy customers would convert to
electricity if Rate DT were abolished.
20
See HQD-14, document 1, Appendix D.
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TABLE 25
Evaluation of Abolishing Rate DT
Abolishing Rate DT
(+500 GWh and 800 MW)
$M
Profitability from the perspective of society
HQD costs
1
114.8
Supply – Transmission Guaranteed Energy (7.1¢/kWh)
35.5
Supply – Transmission ($40.80/kW)
33.0
Transmission- Native Load ($41.90/kW)
33.9
Distribution ($15.16/kW)
12.3
Other costs
Fuel Oil (average price 2007-2008 85.56¢/l)
-52.9
GHG emissions ($15/ton)
Residential Heating
-2.0
Emission-Free Electricity Production
0.0
Total Cost
59.9
Profitability from the Distributor’s perspective
HQD costs
HQD Revenues (D vs DT)
114.8
2
HQD Net Costs (HQD Costs – HQD Revenues)
1
86.5
28.3
These are the costs for 2009 as shown in HQD-14, appendix D.
2
Rate DT revenues total $160 million (2,865 GWh at 5.58¢/kWh) whereas if rate DT were
abolished revenues for rate DT would be $246 million (3 365 GWh at 7.32¢/kWh).
For the Distributor, abolishing Rate DT is also not justified since the additional
ensuing costs if the rate is abolished ($115 million), cannot be compensated by
additional revenues that would result from a transfer of customers from Rate DT
to Rate D ($86 million).
2.3.2.2.2 Profitability of the Structure of Rate DT from Customers’ Perspective
Rate DT is calibrated to be neutral relative to Rate D for an average single-family
home located in Montreal that consumes 26,484 kWh before load reduction, that
is, for customers who only use electricity to meet heating requirements.
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Therefore, any consumption management efforts made by customers translate
as bill savings relative to Rate D. The savings on the electricity bill correspond to
a credit equivalent to the peak price for every kWh that is shed when the exterior
temperature is below the applicable transfer level.
On the one hand, the off-peak rate is relatively low to provide an annual saving to
customers using the dual energy mode and so customers may have an interest
in using electricity during off-peak periods. On the other hand, the peak rate must
be sufficiently dissuasive to encourage customers to use an alternative energy
source for heating and to shift certain basic loads. At present, it is in the interest
of dual energy customers to use electricity during off-peak periods as long as the
off-peak price of fuel oil exceeds 35¢/litre, and to function with fuel oil during onpeak periods if the price of fuel oil is below $1.42/litre.
Nonetheless, the annual savings achieved by Rate DT customers who use dual
energy must also take into account fuel purchases and the difference in
maintenance costs of a dual energy system relative to an electrical system. This
total savings ultimately finances a portion of the differential cost of acquisition of
a dual energy system relative to an electrical system.
Since Rate DT energy rates are calibrated to be neutral relative to Rate D and
since maintenance costs are stable from year to year, the total savings achieved
mainly depend on the price of fuel oil paid in a year to function in dual energy
mode. Under normal exterior temperature, Rate DT can result in savings to rate
DT customers that range between 5% and 15% compared to Rate D, depending
on the extent of their consumption management efforts and fuel oil prices.
However, savings for Rate DT customers increase further if they consume more
during off-peak periods by adding, for example, summer usages such as air
conditioning and a pool-heater. Also, it is likely that climate warming increases
savings for Rate DT customers by shifting a portion of the customers’
consumption from on-peak to off-peak period.
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The recent increase in fuel oil prices has nonetheless decreased annual savings
for Rate DT customers who use dual energy systems. It is estimated that with
current Rate DT energy prices, a customer who lives in an average single-family
home would no longer have any annual savings if the average price paid for the
fuel-oil consumed in a year reaches 1.27$/litre.21 For example, as the following
table shows, the price of fuel oil reached 1.06$/litre last April for savings of $81.
TABLE 26
Annual Savings for Rate DT Customers
According to Different Fuel Oil Prices
Price of fuel oil
DT Savings
50¢/litre
301$
15%
73¢/litre
211$
10%
90¢/litre
143$
7%
106¢/litre
81$
4%
127¢/litre
0$
0%
Although it would not be profitable for society nor for the Distributor to abolish
Rate DT, it is ultimately the profitability for customers who adhere to this option
which determines the peak load reduction associated with this rate. Yet the
prices of fuel oil are such that customers get very little out of it and they could
stop using the dual energy mode and ultimately leave Rate DT. Consequently, it
is primarily this aspect which will determine the rate strategy proposed for April 1,
2009.
2.3.2.2.3 Proposed Rate Strategy on April 1, 2009
Rate Neutrality
21
As mentioned earlier, it is always in the interest of a dual energy customer to use fuel oil during peak
periods when the price is below 1.42$/litre.
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The Distributor proposes to continue calibrating Rate DT to Rate D in order to
preserve neutrality between rates. The objective of calibrating is that the
electricity bill before load reduction for a customer living in an average singlefamily home heated with a dual energy system should be the same as an AEH
customer living in the same type of home.
This neutrality is essential because if the bill at Rate DT before load reduction
were lower than for Rate D, customers would achieve savings even before
switching to fuel mode during peak periods. This situation would translate as a
loss in revenue for the Distributor without a return on the cost of service,
Conversely, if Rate DT bills are higher than Rate D bills prior to load reduction,
customers risk paying more in dual energy mode even if they were to eliminate
heating loads completely. The components of Rate DT will therefore continue to
be set so as to ensure this neutrality.
Customer Charge
Despite the higher cost of double-register meters used to meter the consumption
of dual energy customers, the customer charge has historically been set to the
level of Rate D to reward all management efforts by customers. In fact, the
Distributor does not wish to increase the customer charge for Rate DT to recover
the cost differential because, to do so, it would have to sacrifice rate neutrality
relative to Rate D. If rate neutrality had to be maintained while increasing the
customer charge of Rate DT, it would be impossible to recover a greater portion
of costs because additional revenue recovered from a higher customer charge
would have to be compensated by a smaller increase in energy rates. The price
signal
for
these
customers
would
therefore
deteriorate.
Given
these
circumstances, it is therefore proposed to keep the customer charge at the same
level as for Rate D.
Price of Energy
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In rate applications R-3579-2005 and R-3610-2006, the Distributor proposed to
increase the off-peak rate more than the on-peak rate. This strategy was in line
with the strategy followed for Rates D and DM and it sought to improve the price
signal for all uses while preserving the annual savings of customers and without
decreasing their interest to use fuel during cold weather.
The rate strategy proposed by the Distributor in application R-3644-2007 was
adapted to better reflect the new energy supply context. In a context where all
kWh consumed cost approximately 10¢/kWh, it was necessary to improve the
price signal further in order to avoid that the off-peak rate stimulate additional
consumption. For this reason, the Distributor proposed to apply the entire rate
increase to the off-peak rate. Compared to the fuel oil prices in effect at the time,
the on-peak rate of 7.55¢/kWh was sufficiently dissuasive22 to encourage
customers to use an alternative energy source for heating and to shift certain
basic loads. This strategy did not compromise neutrality between Rate DT and
Rate D, nor did it reduce actual savings following load reduction.
In the current rate application, the evolution of fuel oil prices have compelled the
Distributor to revise its short-term rate strategy. At the current peak rate of
17.55¢/kWh, customers have an incentive to use fuel oil if its price is below
$1.42/litre. Yet, in April 2008, the price of fuel oil reached $1.06/litre. The
Distributor’s margin to freeze peak rates on April 1, 2008 was practically nonexistent. Consequently, given the uncertain evolution of fuel oil prices on the
short-term, the Distributor considers it prudent to increase only the on-peak
energy rate for Rate DT. By including the proposed rate increase of 2.2%, the
energy rate would therefore increase to 18.59¢/kWh, or the equivalent of
$1.50/litre. This proposal also makes it possible to increase the savings of Rate
DT customers living in an average single-family home from $81 to $115.
Since Rate DT is an important consumption management tool for the Distributor,
on the one hand it is necessary to preserve customers’ interest in using fuel oil
22
Equivalent to a fuel oil price of $1.42/litre while the fuel oil rate was approximately 70¢/litre for the
2006-2007 heating season.
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during on-peak periods in order to ensure a reduction in the heating load. On the
other hand, it is equally important to preserve a certain degree of savings for
Rate DT customers without which it would be in their interest to convert their
systems to electricity sooner or later.
For these reasons, the Distributor will be sure to monitor the evolution of fuel oil
prices and the dual energy market and it may, as required, revise its strategy
within the year. Therefore, if fuel oil prices continue to rise, the Distributor could
consider a reduction of off-peak rates in order to increase the on-peak rate
further. For example, every decrease of 0.1¢/kWh in the off-peak rate makes it
possible to increase the on-peak rate by 0.5¢/kWh (or 4¢/litre equivalent) and to
increase savings by $16.
Moreover, in the current context of high fuel prices, any modification to the
structure of Rate DT could make the existing dual energy option more fragile and
it could imperil its current contribution to the Distributor’s supply plan. Therefore,
the Distributor asks the Régie to delay any major reform to the structure of Rate
DT.
Billing the Demand Charge
Until very recently, no demand charge was applied to Rate DT. The absence of a
demand charge that applied beyond 50 kW during the winter period made it
impossible to ensure that this rate was adequately calibrated or to ensure an
equitable treatment of Rate DT customers relative to Rate D and DM customers
with similar consumption profiles. The Distributor therefore proposed to introduce
an equivalent demand charge to the one applied to Rates D and DM.
Given that the demand charges that are currently applied to Rate DT customers
whose metering is respectively metered in bulk or individually are already
equivalent to the demand charge for Rates D and DM, the Distributor proposes to
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apply the same elements of the demand charge billing reform as Rates D and
DM.
2.3.3 Proposed Adjustments to the Rate Structure and Implementation of
the Reform
In the 2008 rate application, the Distributor met the Régie’s demands set forth in
decision D-2007-12 to present a proposal for the reform of domestic rates. This
reform takes into account the importance of long-term marginal costs, the
Régie’s orientations, and the implementation of the Government’s energy
strategy.23 The Distributor proposes to begin this reform on April 1, 2009.
In decision D-2008-024, “the Régie finds that the proposals for the reform of rate
structures adequately meet the objectives set out in previous decisions and in the
Energy Strategy 2006-2015 of the Government of Quebec. Over time, these
reforms will lead to an improved price signal.”24 The Régie is satisfied with the
way the rate reform has evolved for Rates D and DM. This rate reform provides a
gradual and prudent incentive to the Distributor’s customers to optimize their
electricity consumption due to an improved price signal and it progressively
makes domestic rates more reflective of long-term marginal costs so electricity
customers may have a greater interest in energy efficiency.25
The Distributor thereby initiates on April 1, 2009 the rate reform proposed in the
2008 rate application and approved by the Régie in decision D-2008-024. We
note that this rate reform is in line with the rate strategy that was initiated in the
2005 rate application, recognized by the Régie in decisions D-2005-34, D-200634 and D-2007-12. The current section reiterates each element of the domestic
rate reform approved by the Régie, as well as the Distributor’s proposals
23
D-2007-12, page 84.
D-2008-024, page 4. The above is an unofficial translation, translator’s version.
25
D-2008-024, page 90.
24
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following the analyses requested in decision D-2008-024 regarding the customer
charge and Rate DT.
2.3.3.1 Customer Charge
For the reasons already expressed in section 2.3.2.1, the Distributor proposes to
renew the freeze of the customer charge.
2.3.3.2 Energy Rate Adjustment
In the analysis it submitted in 2007, the Distributor proposed to pursue its rate
strategy and to increase the rate of the second consumption block twice as much
as the first. This proposal seeks to improve the price signal and to promote
energy efficiency in a context of high supply costs.
In decision D-2008-024, the Régie found that this proposal respected the rate
strategy that was initiated in the rate application R-3541-2004 and approved by
the Régie in decisions D-2005-34, D-2006-34 and D-2007-12. Like the
Distributor, the Régie noted that the increase in supply costs affects all
consumption and, therefore, part of the rate increase must be applied to the first
consumption block. The Régie approved the Distributor’s proposal to pursue the
application of the strategy by which the rate of the second consumption block
increases twice as much as the rate of the first.26
To favour energy efficiency and align the structure of domestic rates in the longterm, the second block rate must at least reflect the marginal cost of supply
(supply and transmission) for heating. This cost is estimated at 10.97¢/kWh27
(constant annuity over 10 years). By 2018, the marginal cost for heating will
increase to 13.80 ¢/kWh. These costs are relatively higher than the current rate
of the second block.
26
27
D-2008-024, pages 82-83.
See HQD-15, Document 1
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In a context where the second block rate has not yet reached the long-term
marginal cost, the Distributor believes that pursuing this strategy remains
relevant. First, the rate of the second consumption block remains the Distributor’s
most important lever to promote efficient behaviour from its domestic customers.
However, it remains equally important to increase the rate of the first block given
that the increase in supply costs affects all consumption. Finally, the Distributor
reiterates that it is prudent to increase the rate of the second block gradually both
because of the context in which marginal costs continue to evolve and to avoid
rate impacts that are too significant for customers.
Regarding Rate DT, the Distributor proposes to apply the entire rate increase on
the peak energy rate for the reasons provided in section 2.3.2.2. As for Rate DH,
the Distributor proposes, as noted in section 2.3.1.4, a greater rate increase on
the off-peak rate than the on-peak rate
Finally, in regards to Rates DA and DB, the Distributor upholds the principle of
rate neutrality relative to Rate D. Moreover, based on the updated avoided costs,
it proposes to preserve the variance between on-peak rates and off-peak rates at
1.5¢/kWh and to maintain an avoided cost for capacity of $10/winter-kW.
2.3.3.2.1 Benchmarking of Rates with Two Progressive Blocks in Canada
Recently, progressive two-block rates were either proposed or introduced in
other Canadian jurisdictions. In Ontario, the progressive structure of the
residential rates for supply has been in place since April 2004. The variance
between the rates of both blocks for the supply portion only is 18%. The rate for
supply is set at 5.0 ¢/kWh for the kilowatt-hours consumed in the first block and
5.9¢/kWh for the rest.28 The level of the first block varies according to the
season: it is set at 1,000 kWh per month during the winter period and is reduced
to 600 kWh during the summer period.
28
The rate is revised on May 1, every year and re-adjusted six months later if required.
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In Manitoba, the Public Utilities Board, in a decision rendered on June 30, 2008,
approved the introduction on July 1, 2008 of a two-block rate that is slightly
progressive for Manitoba Hydro’s residential customers.29 The level of the first
block is set at 900 kWh per month and the variance between both energy rates is
almost 1%. The rate is set at 6.08¢/kWh for the kilowatt-hours consumed in the
first block and 6.123 ¢/kWh for the rest.
In an application submitted by the BCUC last February, BC Hydro proposed a
two-block progressive rate for its residential customers with the aim of improving
the price signal and, consequently, encouraging energy savings. The current one
block rate of 6.55¢/kWh30 would be divided into two blocks with a consumption
level of 1,600 KWh per two-month period. The variance between both energy
rates is 11%, The rates proposed using constant revenues are 6.28¢/kWh for
kilowatt-hours consumed in the first block and 6.98¢/kWh for the rest.31 BC Hydro
proposes to increase the customer charge and the rate for the first energy block
at the projected inflation rate and to set the rate of the second block so as to
meet the revenue requirement. 32
The table that follows shows BC Hydro’s residential rate as applicable at the time
of the proposal, the one for April 1, 2008 including an increase of 6.56%, as well
as the progressive rate proposed considering, respectively, a rate increase of
8.21% on April 1, 2009,33 a hypothetical 5% increase on April 1, 2010 and
excluding any correction for cross-subsidization.
29
Manitoba PUB, Order 90/08, June 30 2008, page 2.
At the time the proposal was submitted, the analysis was based on the rate applicable on March 31, 2008.
31
http://bchydro.com/policies/rates/rates55221.html
32
For additional information : http://bchydro.com/rx_files/info/info55226.pdf
33
BC Hydro F09/F10 RRA.
30
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TABLE 27
BC Hydro
Progressive Rate Proposed
Customer
Charge
1st Energy
Block
(¢/day)
(¢/kWh)
Block
(¢/kWh)
Variance
between the 1st
and 2nd block
On March 31, 2008
12.13
6.15
6.15
0%
On April 1, 2008
12.93
6.55
6.55
0%
Year 1
12.38
6.28
6.98
11%
Year 2
12.64
6.41
8.53
33%
Year 3
12.91
6.55
9.35
43%
Residential Rates
2nd Energy
The following table summarizes the Distributor’s rate structure as well as those of
the companies mentioned previously.
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Table 28
Progressive Residential Rates in Canada
HQD
Toronto
Hydro1
Winter: 1000
Manitoba
Hydro
BC Hydro2
900
800
Level of 1st Energy
Block (kWh per month)
900
Rate for kWh in the 2nd
Energy Block
5.40¢
9.38¢
6.08¢
6.28¢
Rate for kWh in the 2nd
Energy Block
7.33¢
10.28¢
6.123¢
6.98¢
Variance between rates
36%
10%
0.7%
11%
Summer: 600
1) Only the supply component is progressive, all other components of the rate are applied
uniformly, independently of the consumption level.
2) Constant revenues scenario proposed for October 1, 2008.
2.3.3.3 Capacity Invoice
Since the demand charge plays the role of a third consumption block and is a
component upon which the customer can act, the Distributor has chosen to
emphasize the use of the demand charge since 2005. The rate strategy adopted
at the time thereby consisted of increasing the demand charge by 75¢ per
kilowatt for individually metered domestic customers and 18¢ per kilowatt for
those who are collectively metered.
The rate reform that was proposed in application R-3644-2007 continued to seek
a better price signal, first, by compensating for the absence of an incentive for
domestic customers whose consumption exceeds 50 kW to manage their
capacity requirements in the summer period as there was only a very small
variance between long-term marginal costs for summer and winter and, second,
by compensating for the absence of an incentive to install capacitors to improve
their power factors. The Distributor believes that these gaps create an upward
pressure on costs which all of the Distributor’s customers ultimately have to
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assume. To compensate for these gaps the Distributor therefore proposes a
reform, starting April 1, 2009, which deals with many aspects of the capacity
invoice.
With the aim of improving the price signal to ensure better management of
capacity requirements, the Distributor proposes to bill for capacity that exceeds
50 kW annually. This modification will then make it possible for the demand
charge to fulfill its role throughout the year.
To limit rate impacts, it is proposed to introduce a demand charge of 63¢/kW34
that would apply during the summer period starting April 1, 2009, and to increase
this demand charge every year until it reaches the level of the winter demand
charge. The projected annual increase is currently 63¢/kW; however, the
Distributor does not exclude the possibility of accelerating this reform in
accordance with customers’ consumption management efforts.
In order for the summer demand charge to reach the level of the winter demand
charge, the Distributor proposes to freeze the winter demand charge at the
applicable rate on April 1, 2008. However, this freeze does not mean that the
Distributor has renounced increases in the price signal of the winter demand
charge. Rather, the Distributor prefers that this objective be achieved via the
introduction of an automatic mechanism to set a minimum billing demand, equal
to 65% of the maximum power demand that falls wholly in the winter period.
When the summer demand charge reaches the level of the winter demand
charge, it will be $6.21/kW throughout the year, which is equivalent to paying
1.84¢/kWh35 more for consumption that exceeds the second energy block. Billing
for capacity on an annual basis therefore makes it possible to more rapidly
improve the price signal of customers whose consumption exceeds 50 kW. For
example, a demand charge applicable only during the winter period would have
34
10% of the winter demand charge applicable on March 31, 2009 under the condition that the result is
divisible by 30.
35
Using a 47% load factor applicable to consumption exceeding 50 kW.
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to be $18.73/kW to obtain an equivalent price signal. However, even at that level
the demand charge would not provide any incentive to customers to manage
their summer consumption.
With the aim of eliminating the injustice created by the fact that, contrary to
general rates, only actual power demand is billed under rate D, the Distributor
recommends the introduction, starting April 1, 2009, of billing apparent power
demand to customers whose power factor is below 90%.
The Distributor also proposes that the capacity invoice for Rate DM be equivalent
to the capacity invoice for Rate D. Therefore, the Distributor proposes to set the
demand charge for Rate DM on April 1, 2009 to the level of the demand charge
for Rate D and to apply the elements of the capacity reform proposed for Rate
D.36 In addition to harmonizing the capacity invoices of Rates D and DM, the
proposed reform also makes it possible to improve the price signal for capacity
which will provide an incentive to apartment buildings to better manage their
capacity.
However, to limit the rate impacts resulting from an increase of the demand
charge for customers billed at Rate DM, the Distributor proposes the introduction
of a new level to the capacity invoice per dwelling. The demand charge for Rate
DM would thereby apply when the maximum power demand exceeds the higher
of the following values: 50 kW, or the product of the level per dwelling and the
multiplier. The Distributor sets this level at 4 kW per dwelling to ensure the
neutrality of revenues for capacity. In fact, the current demand charge for Rate
DM applied to the portion exceeding 50 kW generates the same revenues for
capacity as an equivalent demand charge for Rate D applied on the portion
exceeding the higher of: 50 KW and the product of 4 kW and the number of
dwellings.
36
Annual capacity invoice, introduction of an automatic mechanism to set minimum billing demand and
billing apparent power demand.
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In decision D-2008-024, the Régie found that an annual demand charge provides
a better price signal because it adequately reflects the avoided costs for capacity
and it gives customers more incentive to improve their power demand at all
times. It also found that the rate impacts associated with such a reform were
acceptable. The Régie selected the Distributor’s proposal for the reform of the
capacity invoice. The Régie also selected the capacity reform proposal for Rate
DM and it agreed to apply the elements of the capacity reform proposed for Rate
D to Rate DM.
Since the demand charges that apply to Rate DT for customers who are,
respectively, metered individually or collectively are already equivalent to those
of Rates D and DM, the Distributor proposes that the elements for the reform of
the capacity invoice also be extended to Rate DT.
2.3.3.4 Evolution of Domestic Rates in the Short and Medium Terms
The following tables show Rates D, DM and DT respectively on April 1, 2009 and
they include a 2.2% increase as well as all the other elements of the domestic
rate reform. The Distributor also shows the evolution of rates D and DM using the
hypothesis of a 2% increase in 2010 and 2011.
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TABLE 29
Example of the Evolution of the Rate Structure for Rates D and DM
Customer
charge
(¢/day)
Rates D and DM
Current- April 1 2008
40.64
st
nd
1 bloc
2
Rate Structure
bloc
Ratio
nd
st
2 /1
¢/kWh
5.40
D Demand
DM Demand
Charge
Charge
$/kW
7.33
1.36
D
6.21
DM
1.53
Winter
Summer
- Proposed
RatesApril 1 2009 2.2%
40.64
0.0%
5.49
1.7%
7.56
3.1%
1.38
6.21
0.0%
0.63
-
April 1 2010 – 2%
40.64
0.0%
5.57
1.5%
7.78
2.9%
1.40
6.21
0.0%
1.26
100.0%
April 1 2011 – 2%
40.64
0.0%
5.65
1.4%
8.00
2.9%
1.42
6.21
0.0%
1.89
50.0%
TABLE 30
Rate DT Proposed for April 1, 2009
Rate Structure
Customer charge
(¢/day)
Peak
Rate DT
Current - April 1,
2008
Proposed Rates
April 1 2009 – 2.2%
Off-Peak
¢/kWh
Ratio
nd st
2 /1
Demand Charge
$/kW
40.64
4.33
17.55
4.05
Individual
Metering
6.21
40.64
4.33
18.59
4.29
Winter
Summer
0.0%
0.0%
5.9%
6.21
0.63
Collective
Metering
1.53
2.3.3.5 Implementation of the Domestic Rate Reform
Contrary to the reform of general rates discussed in the following sections, there
is no element of the domestic rate reform that involves the systematic transfer of
customers from one rate to another. Thus, it is essentially the reform of the
capacity invoice that requires special attention to its implementation.
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As mentioned in rate application R-3644-2007, the Distributor believes that the
impact of changes made to the capacity invoice can be minimized. The
implementation
the
Distributor
proposes
consists
of
using
targeted
communication to advise domestic customers that will potentially be affected of
how they may change their consumption behaviour to minimize the impact of the
reform to the capacity invoice and to inform them that they can benefit from
technical support from the Distributor’s representatives. These behaviours mainly
consist in optimizing their power demand or installing capacitors if required.
2.4 General Rates
2.4.1 Rates and Customer Description
2.4.1.1 Rate L
Rate L, shown in Table 31, applies to large power customers whose minimum
billing demand is 5 000 kW or more. It is expressed in low voltage. Therefore,
credits for supply at medium or high voltage are given to customers so that costs
generated by lower voltage networks are not transferred onto customers using a
higher voltage.
TABLE 31
Rate L on April 1, 2008
Demand charge
Price of energy
Optimization charge (in winter)
Daily
Monthly limit
$12.18/kW
2.91¢/kWh
$7.11/kW
$21.33/kW
From May 1, 2007 to April 30, 2008, 236 contracts were used to analyse Rate L.
Total annual consumption totalled 45.3 TWh, for annual revenues of $2.1 billion.
Table 32 shows a summary description of customers subject to Rate L.
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The latter part of section 2.4.1.1 until the end of section 2.4.3.4 are not
included in the translated version of this document.
Hereafter is a translated version of Chapter 3, sections 3.1 to 3.2.2.1
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3. IMPACTS OF THE RATE INCREASE
3.1 Projected Revenues by Rate class and Component
The proposed 2.2% increase allows for an overall increase of the Distributor’s
revenue of $207 million in 2009 of which $141 million between April 1 and
December 31, 2009. Table 59 shows the details of the $141 million by rate class.
TABLE 59
Revenues by Rate Class in 2009 ($M)1
Without the
increase on
April 1, 2009
Including the
increase on
April 1, 2009
Difference
Domestic
4,317
4,377
60
Small Power
1,362
1,384
21
Medium Power
1,905
1,936
31
Large Power
1,820
1,850
30
9,405
9,546
141
1,053
1,053
N/A
1
1
0
Total – Regular Rates
Special Contracts
Consumption management
and Back-Up Energy Source
Rates
Total
10,459
10,6002
185
Notes:
1) Results may not tally due to rounded data.
2) Excluding the $65.6 million regulatory provision coming for the months of January to March
2009.
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3.2 Customer Bills
3.2.1 Domestic Rates
3.2.1.1 Distribution of Rate Impacts
Table 60 shows a distribution of the rate impacts on domestic customers. Almost
91% of customers are subject to a rate impact that ranges between 1% and 3%.
Moreover, the bill for 52% of customers, represented by small customers, will be
subject to an annual increase of less than 2%. Appendix C shows a more
complete distribution of the impacts on domestic customers.
TABLE 60
Annual Impact of a 2.2 % Rate Increase: Rate D
Variation of the annual bill (%)
Less than 1 (min:0)
From 1 to 2
From 2 to 3
From 3 to 4
From 4 to 5
From 5 to 6
6 and over (max: 9.8)
Total
Customer allocation (%)
9.3
42.7
47.9
0.1
0.0
0.0
0.0
100.0
3.2.1.2 Impact on Monthly Bills
The following table shows the impact of the proposed rate increase on monthly
bills for typical consumption levels. The bill increases observed range between
1.2% and 2.6%. Appendix D shows the impact by typical consumption level and
by rate component.
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TABLE 61
Monthly Impacts Using Typical Consumption Levels – Rate D
Energy
Bill at the
proposed rate
$
Variance
Variance
kWh
Bill at the
current rate
$
$
%
625
750
1 000
2 000
3 000
45.94
52.69
68.12
141.42
214.72
46.50
53.37
69.16
144.76
220.36
0.56
0.68
1.04
3.34
5.64
1.2
1.3
1.5
2.4
2.6
3.2.1.3 Impact on the Average Customer
Table 62 shows the impact of the proposed increase on the electricity bills of
domestic customers. For the average domestic customer, the monthly electricity
bill increases by $2.27.
TABLE 62
Impacts of the Proposed Increase on the Average Monthly Bill
For Domestic Customers (Rate D)
Average Annual
Consumption Based
on 2007-2008
Monthly Bill ($)
Proposed rate incl.
Current rate
2.2% increase
Customer average
(17 056 kWh)
Customer average for
customers heating
with electricity
(18 953 kWh)
Customer average for
customers not heating
with electricity
(12 576 kWh)
Customer living a
single-family home
heated with electricity
(26 484 kWh)
Original : 2007-08-01
Increase
($)
Increase
(%)
102.66
104.93
2.27
2.9
113.27
115.81
2.54
2.2
77.70
79.29
1.59
2.0
156.59
160.39
3.80
2.4
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3.2.1.4 Impact on Typical Home Types
As an example, Table 63 shows the impacts of the rate increase on certain
typical homes.
The table shows that customers that live in an apartment will be subject to an
increase of 1.7% while customers that live in an imposing home will be subject to
an increase of 2.8%.
TABLE 63
Impact of the Proposed Increase on
Typical Domestic Homes
Rates D and DM
Current-April 1, 2008
Proposed rateApril 1, 2009
Average
Rate D
Customer
17 056 kWh
Apartment
$1232
$817
$1,448
$36
$14
2.2%
1.7%
11 590kWh
Small
Home
Average
Home
-Heated with
20 494 kWh 26 484 kWh
Large
Home
electricity32 054 kWh
Very
Large
Home
42 818
kWh
Imposing
Home
62 840
kWh
Large
Customer
100 kW
411 700
kWh
$1,879
$ 2,287
$3,076
$4,543
$32
$46
$58
$83
$129
2.2%
2.4%
2.6%
2.7%
2.8%
Customer
1st Block
Apartment
Building
10 950 kWh
124 160 kWh
$31,367
$740
$8,759
$1,188
$10
$196
3.8%
1.3%
2.2%
3.2.1.5 Impact on Low-Income Customers
As per the Government’s request in its energy strategy, the Distributor shows the
impact of the rate increase on low-income customers.
The Distributor has little data on the income of its residential customers and the
data from surveys that were carried out for other ends is often incomplete and
not valid as far as the respondents’ income is concerned. It is in fact a delicate
question to which respondents are not always inclined to respond.
Moreover, a household’s income is not the sole variable that determines whether
or not a household is in need.
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In order to evaluate the impact of the rate increase on low-income customers, the
Distributor used the latest available data from Statistics Canada pertaining to
household expenses (2006 data). This data provides the annual expense for
several goods and services by income category.
The Distributor asked Statistics Canada to carry out a distribution of electricity
expenses according to the decile of the household’s income. Therefore, if all
households are classified according to their income, from the lowest to the
highest, the first decile includes the 10% of households that have the lowest
income, the second decile includes the next 10% and so on. The following Table
shows the deciles used for 2006 as well as average electricity expenses,
including taxes, for the households that claimed to have electricity expenses.
TABLE 64
Description of the Deciles Used
Annual Household Income $
first decile
second decile
third decile
4th decile
5th decile
6th decile
7th decile
8th decile
9th decile
10th decile
15,180 or less
15,180 – 23,036
23,036 – 29,000
29,000 – 37,134
37,134 – 46,515
46,515 – 57,141
57,141 – 68,600
68,600 – 84,280
84,280 – 113,000
113,000 and over
Average Annual Electricity
Expenses
874
997
1,131
1,162
1,169
1,324
1,477
1,632
1,695
2,038
The Distributor also requested an index of the dispersion of electricity expenses
for each decile. This allows it to evaluate the maximum impact by income level.
The maximum level of expenses shows the upper bound that includes 95% of all
respondents by decile.
From this data, it is possible to draw an annual consumption profile (energy in the
first and second blocks), which will be used to establish the impact of the rate
increase by decile of income.
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The following table very precisely shows the impact of the 2.2% rate increase by
decile of income. The average impact on bills in the first four deciles ranges
between 1.65% and 1.98%. Nevertheless, within each decile we note a variation
in the impacts that reflects the variation in expenses. For example, for certain
households within the first deciles for whom the energy bill is significant, the
impact can exceed the average rate increase of all customers.
The Distributor’s proposal to increase the second block twice as much as the first
energy block means that households that have a large electricity bill – and
thereby consume several kWh in the second block - will be subject to an increase
that exceeds 2.2%. These are primarily households that have higher incomes.
For their part, households that have lower electricity bills – and therefore
consume fewer kWh in the second block – will be subject to a rate increase that
is below 2.2%. It consists mainly of low-income households. On average, the
Distributor’s proposal therefore attenuates the impact of the rate increase on lowincome households.
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TABLE 65
Dispersion of Impacts of the 2009 Rate Increase Based on the Income
Decile
Increase of the Annual Bill 2009 vs. 2008
The strategy of applying a rate increase that is twice as significant for the second
block began on April 1, 2006. The Distributor’s proposal for the 2009 rate year
means that this strategy has been applied for four consecutive years. The
following table shows the impacts for these four years based on 2005
expenses.37 It can be noted that, since 2005, the households in the first four
37
2005 data was used in rate application R-3644-2007 at Exhibit HQD-12, document 1. At the time the
application was submitted, it was the most recent data available.
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deciles have been subject to a cumulative rate increase below 12% while, over
the same period, the households in the last deciles were subject to bill increases
up to 15%.
TABLE 66
Cumulative Dispersion of Impacts of the Rate Strategy Since 2005
Based on the Income Decile
Cumulative Impact of the Rate Increase
3.2.2 General Rates
3.2.2.1 Distribution of Impacts
For 2009, the Distributor proposes a rate increase only for the energy
component. This choice is based on two main elements: the ratemaking reform
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and the level of the requested rate increase. In fact, as per the rate reform, the
elimination of the degressivity of Rates G and M requires a more significant
increase of the rates in the second block starting in April 1, 2009. Because the
level of the increase is relatively low the Distributor proposes an increase only in
the energy component so that it may have enough latitude to apply a
differentiated rate increase between both energy rates.
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